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2007 Annual Report
investing for our future.
investing for our future.
We’re working with customers,
regulators, legislators and others
to invest in a brighter future.
By investing in our infrastructure
and in the communities we serve,
we’re building a stronger company
for a better tomorrow.
Investing to Meet Customer Needs PAGE TWO
Investing in Environmental Stewardship PAGE FOUR
Investing in Infrastructure PAGE SIX
Letter to Shareholders PAGE NINE
Financial Highlights PAGE FOURTEEN
Investing in Returns for Shareholders PAGE FIFTEEN
Ameren Corporation and
Subsidiaries Offi cers and Directors PAGE SIXTEEN
Form 10-K
Investor Information INSIDE BACK COVER
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investing to meet customer needs.
“ We are committed to delivering
electricity and natural gas in a safe,
reliable and effi cient manner while
striving to improve our customer
service and satisfaction. It is essential
that we keep our focus to elevate
performance in all that we do.”
Scott A. Cisel
President and Chief Executive Offi cer
Ameren Illinois Utilities
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customer on computer, tree
trimming visible through window
The Ameren Illinois utilities, like all the Ameren
companies, put top priority on working safely
and elevating customer satisfaction as a
cornerstone of future success. The companies
are also positioning themselves as trusted
advisors in helping customers understand
energy usage and conservation. Since 2004,
the Illinois companies have spent more than
$1 billion on electric and natural gas infrastruc-
ture upgrades and new developments. They plan
to continue making meaningful investments in
their electric and natural gas delivery systems
in the coming years.
child on rope swing,
Sioux Plant visible in
background
In 2007, AmerenUE launched Power On, a
three-year, $1 billion commitment to improve
reliability, upgrade the company’s delivery
system and enhance the environmental
performance of its power plants. AmerenUE
also plans to spend at least $13 million annually
beginning in 2008, increasing to $56 million
annually by 2015, on energy effi ciency
programs in Missouri. That level of investment
should place Missouri among the top 10 states
in the nation in per-capita spending on energy
effi ciency. Finally, AmerenUE committed to add
at least 100 megawatts of wind power to its
generation mix by 2010 and, in 2007, rolled
out Pure Power TM, a voluntary renewable energy
credit program for customers.
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investing in environmental stewardship.
“ Ameren companies have always
been leaders in reducing power
plant emissions and testing emerging
environmental technologies even
before government regulations
required us to do so.”
Thomas R. Voss
President and Chief Executive Offi cer
AmerenUE
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investing in infrastructure.
“ In 2007, our fl eet of non-rate-regulated
power plants contributed more than 40%
of Ameren’s earnings. Our strategy is to
continue optimizing the performance of
those plants—more than 6,000 megawatts
of generating capacity—while keeping
our commitment to be good stewards of
the environment.”
R. Alan Kelley
President and Chief Executive Offi cer
AmerenEnergy Resources
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To be Determined
Ameren’s non-rate-regulated power plants,
most of them in Illinois, will benefi t from more
than $2 billion to be spent over the next
fi ve years to add pollution control equipment
to meet federal requirements for signifi cantly
reducing plant emissions, including mercury.
For example, at AmerenEnergy Generating
Company’s Coffeen Power Station (above),
a new scrubber will remove more than
95 percent of the plant’s sulfur dioxide
emissions by late 2009.
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“ Our company’s values and focus on
our core energy business has served
as a guide as we addressed the challenges
of the past year. Through it all, we have
remained committed to achieving strong
returns for you.”
Gary L. Rainwater
Chairman, Chief Executive Offi cer and President
Ameren Corporation
To My Fellow Shareholders,
2007 was a pivotal year for Ameren Corporation
substantially covered by insurance. The recon-
in the sense that we put in place several
struction of the plant will also serve as an engine
important building blocks for future success.
for economic growth for Southeast Missouri.
■ In Illinois, we reached a comprehensive
■ And for all our customers, in the wake
settlement with key stakeholders that will help
of the severe storms that hit our system in both
our customers’ transition to new electric rates
states, we signifi cantly increased investments
and bring stability to the power procurement
to harden our electrical delivery system in order
process. This settlement provides signifi cantly
to provide industry-leading reliability and service.
greater levels of legislative, regulatory and legal
Our belief is that by investing in infrastruc-
certainty, while enabling a viable, competitive
ture, we can make material improvements in
power supply market to continue to develop
service, which, in turn, will bring meaningful
in Illinois.
improvement in customer satisfaction. As in
■ In Missouri, we settled all state and federal
any business, serving customers well is critical
issues associated with the 2005 Taum Sauk
to achieving solid returns for investors. I believe
plant reservoir breach and began rebuilding this
improved customer service and satisfaction
valuable power facility. The project, scheduled
will enable us to bring our rates of return more
for completion in the fall of 2009, is expected
in line with returns normally allowed by utility
to cost approximately $450 million and to be
regulatory commissions.
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One example of this increased investment
pace. Since our customers’ rates are typically
is Power On, AmerenUE’s three-year, $1 billion
set based on historical cost levels through a
investment to improve the reliability of the
nearly one-year regulatory review, by the time
company’s Missouri electric delivery system
new rates are put in place, they are already
and reduce emissions at its coal-fi red plants.
inadequate to fully recover current costs and
Ameren’s Illinois utilities—AmerenCIPS,
earn a fair return on investment. Of course, rate
AmerenCILCO and AmerenIP—also plan to
increases are not popular among customers,
spend $1 billion on infrastructure improvements
even when rates have been far below the
beween 2008 and 2010.
industry norm for many years. Therefore, in order
These and future investments will contribute
to allow our customers to more easily adjust to
to long-term earnings growth. In the near term,
however, our rates are well below the levels
necessary to recover current costs and to earn
a fair return on investment. Returns in 2007
and expected returns in 2008 in our regulated
Missouri and Illinois businesses are well below
the levels allowed by both state utility commis-
sions in our last rate cases.
higher energy prices, and to allow shareholders
to earn a fair profi t, we must not wait decades
for rate increases, but seek smaller and more
frequent increases. We must also seek auto-
matic cost recovery mechanisms for large dollar
items, like fuel and environmental investments.
Consequently, in late 2007, we fi led with the
Illinois Commerce Commission for an aggre-
A Need to Recover Rising Costs
gate $247 million increase in delivery rates for
For decades, we have been industry leaders
electricity and natural gas. We also requested
in keeping our rates low through disciplined
cost recovery mechanisms for bad debts, electric
cost control and effi cient operations. Even
infrastructure investments and gas decoupling.
after recent rate increases, AmerenUE’s electric
In Missouri, we plan to fi le for an electric rate
rates are still about 40 percent below the
increase in the second quarter of 2008. We will
national average, and rates for our Illinois
also request that a fuel cost recovery mechanism,
utilities approximate the national average.
and potentially an environmental cost recovery
However, today, costs of every element
mechanism, be implemented to recover our costs
of our business are rising at an unprecedented
in a more timely manner.
Since it went online in 1984, AmerenUE’s Callaway Nuclear Plant has achieved
the fourth highest generation record among the 104 nuclear power units operating
in the U.S., having now generated more than 200 million megawatthours.
Callaway’s lifetime generation through 2006 ranks it 20th in the world out of 445
nuclear units operating in 30 countries. Though no decision has been made to
add a second unit at the site, in 2007 AmerenUE took steps to preserve that option.
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The bottom line is that we are now in a rising
Power On sets aside $500 million for environ-
cost environment following many years of
mental improvements, including a scrubber we
declining costs for our customers. As a result,
are installing at AmerenUE’s Sioux Plant.
it is now more important than ever to obtain
We are also installing scrubbers on the
constructive outcomes for our rate cases in
non-rate-regulated generation side of our
Illinois and Missouri. We must recover our
business at the Duck Creek Plant and Coffeen
costs and realize appropriate returns on our
Power Station. These technologies will remove
investments in order to continue investing
at least 95 percent of the plants’ sulfur dioxide
in our energy infrastructure on a timely basis
emissions.
to provide our customers with the safe,
Our environmental plans are discussed in
reliable service they expect.
more detail in our fi rst comprehensive environ-
We will protect our customers’ and
your interests in arguing our case
for a balanced, reasoned approach
to reductions of greenhouse gases.
mental report, “Stewardship: Balancing the
Needs of Our Environment, Our Customers
and Our Economy.” This publication—which
you can view at www.ameren.com/EnvReport
—also states that Ameren would fi rmly support
a mandated reduction in carbon dioxide (CO2)
emissions as long as that requirement effectively
balances the benefi ts to the environment against
cost to consumers and the risk of economic
Planning for a Cleaner Environment
disruption to the economy in the Midwest and
Programs, like Power On, demonstrate that
throughout the nation.
we are responding to our customers’ need
After extensive analysis, we have concluded
for improved reliability—burying lines where
that any federal climate legislation must include
appropriate, increasing our pole and line
reductions for all greenhouse gas sources, set
maintenance programs, stepping up our tree-
compliance timelines consistent with development
trimming and removals and more.
and deployment of advanced technologies, be
However, we also know that our customers
global in approach and recognize the signifi cant
are concerned about the environment.
economic impact reducing CO2 will have on our
With support from the Missouri Department of Natural Resources, the Department
of Conservation, AmerenUE and its contractors, and others, the state of Missouri
reopened Johnson’s Shut-Ins State Park for swimming in 2007. The popular
tourist site was severely damaged by the 2005 breach of AmerenUE’s Taum Sauk
pumped-storage plant’s upper reservoir. The company has now settled all issues
with the state of Missouri, and work is under way to bring this critical plant back
in service by late 2009.
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region’s consumers and businesses. Our current
details how the company expects to supply
analysis shows that under some policy scenarios
safe, reliable electricity in coming years, while
being considered, because of the dependence
protecting the environment.
on coal-fi red generation in the Midwest, house-
hold costs could rise signifi cantly and rates for
electricity could double by 2030.
We will protect our customers’ and your
interests in arguing our case for a balanced,
reasoned approach to reductions of greenhouse
gases, and we look forward to continuing our
active engagement in discussions about this
important issue at both federal and state levels.
I encourage you to also get involved in this
important debate.
Future Generation to Meet
Our Customer Needs
We will study a wide range
of technologies to meet our
customers’ energy needs in the
future, including advanced coal
technologies and nuclear power.
In summary, the plan recommends aggres-
sively pursuing energy effi ciency programs,
expanding the role of renewable energy,
Related to the topic of the environmental
increasing operational effi ciency at existing
report is the question of Ameren’s next
plants, and evaluating a range of options for
addition of baseload generation—the “work-
new baseload generating facilities.
horse” plants that operate virtually year-
We will study a wide range of technologies
round, 24 hours a day, so that Ameren’s
to meet our customers’ energy needs in the
customers have the power they need,
future, including advanced coal technologies
when they need it.
and nuclear power. As a result of the long
In February 2008, AmerenUE fi led an
time required to design, license and build a
integrated resource plan with the Missouri
baseload power plant, this year we expect
Public Service Commission. It was developed
to fi le a construction and operating license
with signifi cant stakeholder input from a
application with the Nuclear Regulatory Commis-
broad spectrum of organizations. This plan
sion for a new nuclear unit at our Callaway site.
Ameren employees are active in their communities. AmerenUE Vice President,
Public Relations Karen Foss (above left) helps Boy Scouts place energy
effi cient, long-lasting compact fl uorescent light bulbs in boxes of food headed
to needy senior citizens. Employees volunteer for countless community
projects across the company’s 64,000-square-mile service territory, from planting
trees (above right) to participating in food and blood drives.
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While this does not mean we have made a fi nal
as well as through improving the returns in
decision to add a second unit at Callaway, it
these businesses as a result of more frequent,
preserves that option for us.
but smaller rate increases. We also expect to
Optimizing Our Power Generation
Business
continue to improve the operation of our non-
rate-regulated generating plants and position
In our non-rate-regulated generation operations,
them for earnings growth should power markets
we continued, in 2007, to invest in our plants
improve in the years ahead.
to improve their productivity, as well as to
effectively market the power they produce.
Looking ahead, we will continue to focus
on optimizing this business by increasing plant
When we put all that together, we see
average earnings growth on the order of
4% to 6% per year through 2010, achieving
earnings of approximately $3.70 per share
availability and plant output. By 2010, we expect
by 2010. By 2011, we believe we will be able
our non-rate-regulated plant output to increase
approximately 10 percent over 2007 levels, to
to achieve $4 per share with continued earnings
growth thereafter. We are committed to realizing
nearly 33 million megawatthours.
And while we currently believe that rising
costs, including fuel, depreciation and fi nancing
costs, will largely offset these productivity gains
in the near-term, we believe our plants will be
well-positioned for earnings growth in the future
should energy and capacity prices improve.
A Bright Future
I believe that in 2007 we laid a solid foundation
for future success. Looking ahead, we expect
to achieve signifi cant earnings growth in our
this goal. We are committed to providing the
strong sustainable dividend we have for the
past century. And we are committed to laying
a solid foundation for future dividend growth.
I thank you for your continued support,
and I hope you can attend this year’s Annual
Shareholders Meeting on April 22 at The
St. Louis Art Museum.
business. That growth is expected to come
Gary L. Rainwater
primarily from our regulated businesses through
Chairman, Chief Executive Offi cer and President
the higher levels of investment I have outlined,
Ameren Corporation
From left, Dick Fleming, chief executive offi cer of the St. Louis Regional
Chamber and Growth Association; the Honorable Francis Slay, mayor of the
City of St. Louis; Tom Voss, AmerenUE president and chief executive offi cer;
Richard Mark, AmerenUE senior vice president, Missouri Energy Delivery; and
Charlie Dooley, St. Louis County Executive, kick off Power On—AmerenUE’s
$1 billion commitment to improving distribution system reliability and enhancing
the environmental performance of its power plants.
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Financial Highlights
Ameren Consolidated
(In millions, except per share amounts and as noted)
RESULTS OF OPERATIONS
Operating revenues
Operating expenses
Operating income
Income before cumulative effect of change in accounting principle
Cumulative effect of change in accounting principle,
net of income tax benefi t
Net income
COMMON STOCK DATA
Earnings per basic and diluted share (a)
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 (KwH)
Native gas sales (thousands of MMBtus)
Total generation output (KwH)
Electric customers
Gas customers
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(a) 2005 excludes charges for the cumulative effect of a change in accounting
principle of $22 million (11 cents per share), net of income tax benefit.
2007
Year Ended December 31,
2005
2006
$7,546
$6,204
$1,342
$618
$ –
$618
$2.98
$2.54
4.7%
$54.21
207.4
$11,294
$32.41
$15,069
$20,728
$5,691
48.2%
1.4%
50.4%
107,486
107,871
81,367
2.4
1.0
$6,880
$5,707
$1,173
$547
$ –
$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
$6,780
$5,496
$1,284
$628
$(22)
$606
$3.13
$2.54
5.0%
$51.24
200.8
$10,489
$31.09
$13,581
$18,171
$5,354
52.5%
1.6%
45.9%
96,059
114,182
77,941
2.4
1.0
investing in returns for shareholders.
“ We are investing our resources
wisely for the benefi t of all of our
stakeholders. We will remain focused
on achieving solid returns on our
investments and producing long-term
earnings growth, as well as continuing
to provide a strong, sustainable dividend.”
Warner L. Baxter
Executive Vice President and Chief Financial Offi cer
Ameren Corporation
TOTAL
GENERATION
OUTPUT
5
8
4
4
,
1
1
8
8
7
6
3
,
1
8
1
4
9
7,
7
CAPITAL
INVESTMENTS
1
8
3
,
1
$
4
8
2
2
,
1
1
$
$
5
3
9
$
)
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(
05
05
06
06
07
07
05
05
06
06
07
07
)
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(
AMEREN’S 2007
SEGMENT EARNINGS
(In millions)
Illinois Regulated $47
Non-Rate-Regulated
Generation $281
Missouri Regulated $281
Other $9
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Ameren Corporation and Subsidiaries Offi cers and Directors
EXECUTIVE
LEADERSHIP TEAM
Gary L. Rainwater
Chairman, President
and Chief Executive Officer
Warner L. Baxter
Executive Vice President
and Chief Financial Officer,
Ameren Services President
and Chief Executive Officer
Thomas R. Voss
Executive Vice President
and Chief Operating Officer,
AmerenUE President and
Chief Executive Officer
Scott A. Cisel *
President and Chief
Executive Officer,
AmerenCILCO, AmerenCIPS
and AmerenIP
R. Alan Kelley *
President and Chief
Executive Officer,
AmerenEnergy Resources
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
Martin J. Lyons
Senior Vice President
and Chief Accounting Officer
Richard J. Mark*
Senior Vice President,
AmerenUE
Michael L. Moehn*
Vice President,
Corporate Planning,
Ameren Services
Charles D. Naslund*
Senior Vice President
and Chief Nuclear Officer,
AmerenUE
Andrew M. Serri *
President,
AmerenEnergy Marketing
OTHER OFFICERS
Lynn M. Barnes*
Vice President Business Planning
and Controller, AmerenUE
Scott A. Glaeser *
Vice President, Gas Supply
and System Control,
AmerenEnergy Fuels
and Services
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,
AmerenEnergy Generating
Ronald K. Evans*
Vice President and
Deputy General Counsel,
Ameren Services
Adam C. Heflin*
Vice President,
Nuclear Operations, AmerenUE
Timothy E. Herrmann*
Vice President, Engineering,
Callaway Nuclear Plant,
AmerenUE
Christopher A. Iselin*
Vice President, Human
Resources, Business Services,
Ameren Services
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
Karen C. Foss*
Vice President, Public Relations,
AmerenUE
Donald M. Mosier *
Vice President,
AmerenEnergy Marketing
Michael G. Mueller *
President, AmerenEnergy
Fuels and Services
Robert K. Neff *
Vice President, Coal Supply
and Transportation,
AmerenEnergy Fuels and Services
Craig D. Nelson*
Vice President, Regulatory Affairs
and Financial Services, Ameren-
CILCO, AmerenCIPS, AmerenIP
Stan E. Ogden*
Vice President, Customer Service
and Public Relations, AmerenCILCO,
AmerenCIPS, AmerenIP
Ronald D. Pate*
Vice President, Regional
Operations, AmerenCILCO,
AmerenCIPS, AmerenIP
Gregory L. Nelson*
Vice President and Tax Counsel,
Ameren Services
Joseph M. Power *
Vice President, Federal
Legislative and Regulatory
Affairs, Ameren Services
Robert L. Powers*
Vice President, Generation
Technical Services,
AmerenEnergy Resources
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, AmerenEnergy
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
BOARD OF DIRECTORS
Stephen F. Brauer 2, 5
Chairman and Chief
Executive Officer, Hunter
Engineering Company
Susan S. Elliott 2, 6
Chairman and
Co-Chief Executive Officer,
Systems Service
Enterprises, Inc.
Walter J. Galvin
Senior Executive Vice
President and Chief
Financial Officer, Emerson
Electric Co.
Dr. Gayle P. W. Jackson 5, 6
President, Energy Global, Inc.
James C. Johnson 4, 5
Vice President and
Assistant General Counsel,
Commercial Airplanes,
The Boeing Company
Richard A. Liddy 1, 2, 3
Retired Chairman,
GenAmerica Financial
Corporation
Gordon R. Lohman 1, 3, 4, 7
Retired Chairman and
Chief Executive Officer,
AMSTED Industries Inc.
Charles W. Mueller 1, 5, 6
Retired Chairman and
Chief Executive Officer,
Ameren Corporation
Jack D. Woodard 5, 6
Retired Executive Vice President
and Chief Nuclear Officer, Southern
Nuclear Operating Company, Inc.
Douglas R. Oberhelman 1, 2, 5
Group President, Caterpillar Inc.
Gary L. Rainwater 1
Chairman, President
and Chief Executive Officer,
Ameren Corporation
Harvey Saligman 1, 3, 4
Partner, Cynwyd Investments
Patrick T. Stokes 3, 5
Chairman, Anheuser-Busch
Companies, Inc.
1 Member of Executive Committee
2 Member of Audit and Risk Committee
3 Member of the Human Resources
Committee
4 Member of the Nominating and
Corporate Governance Committee
5 Member of the Public Policy Committee
6 Member of the Nuclear Oversight
Committee
7 Lead Director
* Officer of an Ameren Corporation subsidiary only
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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, 2007
OR
( )
Transition report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
to
for the transition period from
.
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
Commission
File Number
1-14756
1-2967
1-3672
333-56594
2-95569
1-2732
1-3004
IRS Employer
Identification No.
43-1723446
43-0559760
37-0211380
37-1395586
37-1169387
37-0211050
37-0344645
Securities Registered Pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Each of the following classes or series of securities is registered pursuant to Section 12(b) of the Securities Exchange Act
of 1934 and is listed on the New York Stock Exchange:
Registrant
Ameren Corporation
Title of each class
Common Stock, $0.01 par value per share and Preferred
Share Purchase Rights
Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934:
Registrant
Union Electric Company
Central Illinois Public Service Company
Title of each class
Preferred Stock, cumulative, no par value,
Stated value $100 per share –
$4.50 Series
$4.56 Series
$3.50 Series
$4.00 Series
Preferred Stock, cumulative, $100 par value per share –
4.90% Series
4.25% Series
4.00% Series
Depository Shares, each representing one-fourth of a
6.625% Series
5.16% Series
4.92% Series
share of 6.625% Preferred Stock, cumulative,
$100 par value per share
Central Illinois Light Company
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
( )
( )
(X)
(X)
(X)
(X)
(X)
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)
(X)
( )
(X)
No
No
No
No
No
No
No
(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. Yes (X)
No ( )
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
CILCORP Inc.
Central Illinois Light Company
Illinois Power Company
(X)
(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 “accelerated filer”, “large 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 29, 2007, Ameren Corporation had 207,510,090 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 $10,170,069,511. The shares of common stock of the other registrants were
held by affiliates as of June 29, 2007.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2008, 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: 208,728,929
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
Development Company (parent company of the registrant
and indirect 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 2008 annual
meetings of shareholders are incorporated by reference into Part III of this Form 10-K.
OMISSION OF CERTAIN INFORMATION
Ameren Energy Generating Company and CILCORP Inc. meet the conditions set forth in General Instruction I(1)(a) and
(b) of Form 10-K and are therefore filing this form with the reduced disclosure format allowed under that General Instruction.
This combined Form 10-K is separately filed by Ameren Corporation, Union Electric Company, Central Illinois Public Service
Company, Ameren Energy Generating Company, CILCORP Inc., 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.
Business
General
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rates and Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supply for Electric Power. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas Supply for Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industry Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A.
Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B.
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
Item 4.
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
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 15.
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.
(This page intentionally left blank)
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.
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.
APB – Accounting Principles Board.
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 various
non-rate-regulated subsidiaries.
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.
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.
CUB – Citizens Utility Board.
Development Company – Ameren Energy Development
Company 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.
Dynegy – Dynegy Inc.
EEI – Electric Energy, Inc., an 80%-owned Ameren
Corporation subsidiary (40% owned by UE and 40% owned
by Development Company) that operates non-rate-regulated
electric generation facilities and FERC-regulated transmission
facilities in Illinois. In February 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.
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.
FIN – FASB Interpretation. 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, Texas Generation Company
LP, and Pacific Energy Fuels Company.
1
GAAP – Generally accepted accounting principles in the
United States.
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 the Illinois utility businesses and 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 introduced
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 future 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 gas transmission and
distribution businesses of CIPS, CILCO and IP.
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 is a special-purpose Delaware limited-
liability company.
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. Pursuant to FIN 46R,
IP SPT is a variable-interest entity, as the equity investment
is not sufficient to permit IP SPT to finance its activities
without additional subordinated debt.
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.
Marketing Company – Ameren Energy Marketing Company,
a Resources Company subsidiary that markets power for
Genco, AERG and EEI.
Medina Valley – Ameren Energy Medina Valley Cogen LLC,
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 began
operating on April 1, 2005. It uses market-based pricing,
which incorporates 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 all the operations of UE’s business, except for
non-rate-regulated activities.
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
businesses 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 the Missouri utility business and
operations of UE.
NCF&O – National Congress of Firemen and Oilers, a labor
union.
NERC – North American Electric Reliability Corporation.
Non-rate-regulated Generation – A financial reporting
segment consisting of the operations or activities of Genco,
CILCORP holding company, AERG, EEI, 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 nonnative 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.
2
PJM – PJM Interconnection LLC.
PUHCA 1935 – The Public Utility Holding Company Act of
1935. It was repealed effective February 8, 2006, by the
Energy Policy Act of 2005 that was enacted on August 8,
2005.
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 and rate increase
requests can take up to 11 months to be granted 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.
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 must
designate a portion of cash received from customer billings
to pay the TFNs. The proceeds received by IP are remitted to
IP SPT. The proceeds are restricted for the sole purpose of
making payments of principal and interest on, and paying
other fees and expenses related to, the TFNs. Under the
application of FIN 46R, IP does not consolidate IP SPT.
Therefore, the obligation to IP SPT appears on IP’s balance
sheet.
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:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
regulatory or legislative actions, including changes in
regulatory policies and ratemaking determinations, such
as the outcome of pending CIPS, CILCO and IP rate
proceedings or future legislative actions that seek to
limit or reverse rate increases;
uncertainty as to the effect of implementation of the
Illinois electric settlement agreement on Ameren, the
Ameren Illinois Utilities, Genco and AERG, including
implementation of the new power procurement process
in Illinois beginning in 2008;
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;
the effects of participation in the MISO;
the availability of fuel such as coal, natural gas, and
enriched uranium used to produce electricity; the
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 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;
disruptions of the capital markets or other events that
make the Ameren Companies’ access to necessary
capital more difficult or costly;
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;
the impact of system outages caused by severe weather
conditions or other events;
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;
3
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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;
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
labor disputes, future wage and employee benefits costs,
including changes in returns on benefit plan assets;
the inability of our counterparties and affiliates to meet
their obligations with respect to contracts and financial
instruments;
the cost and availability of transmission capacity for the
energy generated by the Ameren Companies’ facilities or
required to satisfy energy sales made by the Ameren
Companies;
legal and administrative proceedings; and
acts of sabotage, war, terrorism or intentionally
disruptive acts.
Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent
required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements
to reflect new information or future events.
PART I
ITEM 1. BUSINESS.
GENERAL
Ameren, headquartered in St. Louis, Missouri, is a
public utility holding company under PUHCA 2005
administered by FERC. Ameren was formed in 1997 by the
merger of UE and CIPSCO. Ameren acquired CILCORP in
2003 and IP in 2004. Ameren’s primary assets are the
common stock of its subsidiaries, including UE, CIPS,
Genco, CILCORP and IP. Ameren’s subsidiaries, which are
separate, independent legal entities, 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 depend upon distributions made to it by its
subsidiaries.
To streamline its organizational structure, during late
2007, Ameren dissolved, merged or consolidated various of
its subsidiaries that were inactive or had minimal or ancillary
business operations. Among the subsidiaries eliminated was
Ameren Energy, Inc., which previously served as a power
marketing and risk management agent for UE. UE now
performs such functions for itself. To further streamline its
organizational structure, in February 2008, Development
Company was eliminated through merger and Ameren
Energy Resources Company was merged into the newly
created Resources Company. As a part of this internal
reorganization, on February 29, 2008, UE’s 40% ownership
interest and Development Company’s 40% ownership
interest in EEI were transferred to this newly created
Resources Company.
The following table presents our total employees at
December 31, 2007:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,069
3,665
664
561
598
1,165
(a) Total for Ameren includes Ameren registrant and nonregistrant
subsidiaries.
The IBEW, the IUOE, the NCF&O and the Laborers and
Gas Fitters labor unions collectively represent about 61% of
Ameren’s total employees. They represent 72% of the
employees at UE, 81% at CIPS, 72% at Genco, 70% at
CILCORP, 70% at CILCO, and 90% at IP. All collective
bargaining agreements that expired in 2007 have been
renegotiated and ratified, with the exception of the benefits
provisions contained in the agreements between IP and
IBEW locals 51, 309, 702, and 1306. Bargaining over these
benefits provisions continues at this time, with existing
provisions remaining in effect. The majority of the
renegotiated agreements have four- or five-year terms, and
expire in 2011 and 2012. Four collective bargaining
agreements between IP and the Laborers and Gas Fitters
labor unions, covering approximately 127 employees, expire
June 30, 2008.
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.
4
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 16 – 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 the single most 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 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 UE. FERC regulates UE,
CIPS, Genco, CILCO, IP and EEI 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 37% of Ameren’s electric and 13% of its gas
operating revenues were subject to regulation by the MoPSC
in the year ended December 31, 2007. About 41% of
Ameren’s electric and 87% of its gas operating revenues
were subject to regulation by the ICC in the year ended
December 31, 2007. Wholesale revenues for UE, Genco and
AERG are subject to FERC regulation, but not subject to
direct MoPSC or ICC regulation.
Missouri Regulated
About 83% of UE’s electric and 100% of its gas
operating revenues were subject to regulation by the MoPSC
in the year ended December 31, 2007.
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 permits prudently
incurred gas infrastructure replacement costs to be passed
directly to the consumer.
A Missouri law enacted in July 2005 enables the
MoPSC to put in place fuel and purchased power and
environmental cost recovery mechanisms for Missouri’s
electric utilities. The law also includes rate case filing
requirements, a 2.5% annual rate increase cap for the
environmental cost recovery mechanism, and prudency
reviews, among other things. Rules for the fuel and
purchased power cost recovery mechanism were approved
by the MoPSC in September 2006 and became effective that
year. Rules for the environmental cost recovery mechanism
were approved by the MoPSC in February 2008 and will be
effective once published in the Missouri Register. UE will not
be able to utilize the cost recovery mechanisms until the
MoPSC authorizes them as part of a rate case proceeding.
UE was denied use of a fuel and purchased power cost
recovery mechanism in its last electric rate order, in May
2007. UE plans to request use of a fuel and purchased
power cost recovery mechanism and, potentially an
environmental cost recovery mechanism, in its next electric
rate case filing, expected in the second quarter of 2008.
With the expiration of multiyear electric and gas rate
moratoriums, effective July 1, 2006, UE filed requests with
the MoPSC in July 2006 for an electric rate increase and for
a natural gas delivery rate increase. In March 2007, a
stipulation and agreement approved by the MoPSC
authorized an increase in annual natural gas delivery
revenues of $6 million effective April 1, 2007. As part of this
stipulation and agreement, 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. In February 2008, the MoPSC
approved UE’s petition requesting the establishment of an
ISRS to recover annual revenues of $4 million effective
March 29, 2008.
In May 2007, the MoPSC issued an order, which, as
clarified, granted UE an increase in base rates for electric
service, effective June 4, 2007. For further information on
Missouri rate matters, including the Missouri law enabling
fuel and purchased power and environmental cost recovery
mechanisms, 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 13 – 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, 2007:
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO(a) . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100% 100%
58
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.
5
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. As a part of
the order approving Ameren’s acquisition of IP, the ICC also
approved a tariff rider that allows IP 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 and
financed with contributions of $10 million each by Ameren
and Dynegy. At December 31, 2007, the trust fund balance
was $22 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.
New electric rates for CIPS, CILCO and IP went into
effect on January 2, 2007, reflecting delivery service tariffs
approved by the ICC in November 2006 and full cost
recovery of power purchased on behalf of Ameren Illinois
Utilities’ customers in the September 2006 power
procurement auction in accordance with a January 2006 ICC
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 13 – Commitments and Contingencies to our financial
statements under Part II, Item 8, of this report for further
information on rate matters. This material summarizes
actions taken by certain Illinois legislators, the Illinois
governor, the Illinois attorney general, and others regarding
the expiration of the rate freeze at the beginning of 2007,
opposition to the 2006 power procurement auction, and the
Illinois electric settlement agreement and establishment of
the IPA, as well as electric and gas delivery service rate
cases filed by CIPS, CILCO and IP in November 2007.
General Regulatory Matters
UE, CIPS, CILCO and IP must receive FERC approval to
issue short-term debt securities and to conduct certain
acquisitions, mergers and consolidations involving electric
utility holding companies having a value in excess of
$10 million. In addition, these Ameren utilities must receive
authorization from the applicable state public utility
regulatory 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. On
March 30, 2007, FERC granted a new 40-year license for
UE’s Osage hydroelectric plant and approved a settlement
agreement among UE, the U.S. Department of the Interior,
and various state agencies that was submitted in May 2005
in support of the license renewal. The license for UE’s Taum
Sauk plant expires on June 30, 2010. UE intends to file with
FERC an application for license renewal of the Taum Sauk
facility no later than June 30, 2008. The Taum Sauk plant is
currently out of service and 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
open-ended authority granted by an Act of Congress in
1905.
For additional information on regulatory matters, see
Note 2 – Rate and Regulatory Matters and Note 13 –
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,
record keeping, 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 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 13 –
6
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, CILCO, CIPS,
and IP. Ameren also operates two balancing authority areas,
AMMO (which includes UE) and AMIL (which includes
CILCO, CIPS, IP, AERG and Genco). During 2007, the peak
demand in AMMO was 8,606 MW and in AMIL was
9,386 MW. Factors that could cause us 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. 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. See Note 2 – Rate and Regulatory Matters to our
financial statements under Part II, Item 8, of this report for
further information. 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,
a regional electric reliability organization with NERC-
delegated authority for proposing and enforcing reliability
standards. 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.
Missouri Regulated
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.
UE’s electric supply is obtained primarily from its own
generation. 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 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. See Outlook in Management’s
Discussion and Analysis of Financial Condition and Results
of Operations under Part II, Item 7 and Note 13 –
Commitments and Contingencies to our financial statements
under Part II, Item 8, of this report. UE filed in February
2008 an integrated resource plan with the MoPSC. The plan
includes 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.
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 through the Illinois reverse power
procurement auction held in September 2006. CIPS, CILCO
and IP entered into power supply contracts with the winning
bidders, including their affiliate, 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
their customers at an all-inclusive fixed price with one-third
of the supply contracts expiring in each of May 2008, 2009
and 2010. 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 full cost recovery of power purchased on behalf of
Ameren Illinois Utilities’ customers in the September 2006
reverse power procurement auction.
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. As part of the
Illinois electric settlement agreement reached in 2007, the
reverse power procurement auction in Illinois was
discontinued and will be replaced with a new process led by
the IPA, beginning in 2009. In 2008, utilities will contract for
necessary power and energy requirements not already
supplied through the September 2006 auction contracts,
primarily through a request-for-proposal process, subject to
ICC review and approval. Existing supply contracts from the
September 2006 reverse power procurement auction remain
in place. 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 around-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. See Note 2 – Rate and Regulatory Matters and
Note 12 – Related Party Transactions to our financial
7
statements under Part II, Item 8, of this report for a
discussion of the ICC-approved power procurement auction.
Non-rate-regulated Generation
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.
In December 2006, Genco and Marketing Company, and
AERG and Marketing Company, entered into new 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 such amount of
associated energy commencing on January 1, 2007. All of
Genco’s and AERG’s generating capacity now competes for
the sale of energy and capacity in the competitive energy
markets through Marketing Company. See Note 12 – Related
Party Transactions to our financial statements under Part II,
Item 8, of this report for additional information.
On December 31, 2005, EEI’s power supply contract
with its affiliates, including UE, CIPS and IP, expired. EEI
entered into a power supply agreement with Marketing
Company whereby EEI sells 100% of its capacity and energy
to Marketing Company at market-based prices. All of EEI’s
generating capacity now competes for the sale of energy and
capacity in the competitive energy markets through
Marketing Company. See Note 12 – Related Party
Transactions to our financial statements under Part II, Item 8,
of this report for additional information.
The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended
December 31, 2007, 2006 and 2005:
Coal
Nuclear
Natural Gas
Hydroelectric
Oil
Ameren:(a)
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Missouri Regulated:
UE:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-rate-regulated Generation:
Genco:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO (AERG):
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EEI:
84%
85
86
76%
77
80
96%
97
96
99%
99
99
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100%
100
100
Total Non-rate-regulated Generation:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
98%
99
98
12%
13
10
19%
20
16
-%
-
-
-%
-
-
-%
-
-
-%
-
-
2%
1
1
2%
1
1
4%
2
3
1%
1
1
-%
(b)
(b)
2%
1
2
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Less than 1% of total fuel supply.
2%
1
2
3%
2
3
-%
-
-
-%
-
-
-%
-
-
-%
-
-
(b)%
(b)
1
(b)%
(b)
(b)
(b)%
1
1
(b)%
(b)
(b)
-%
-
-
(b)%
(b)
(b)
8
The following table presents the cost of fuels for electric generation for the years ended December 31, 2007, 2006 and
2005.
Cost of Fuels (Dollars per million Btus)
2007
2006
2005
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Ameren:
Coal(a)
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Missouri Regulated:
UE:
Coal(a)
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Non-rate-regulated Generation:
Genco:
Coal(a)
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
CILCO (AERG):
Coal(a)
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1.399
0.490
7.872
1.437
1.284
0.490
7.580
1.271
1.717
8.440
1.939
1.309
1.450
EEI:
Coal(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1.329
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total Non-rate-regulated Generation:
Coal(a)
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1.545
8.440
1.698
$
$
$
$
$
$
$
$
$
$
$
1.271
0.434
8.917
1.256
1.084
0.434
8.625
1.035
1.691
9.391
1.865
1.419
1.466
1.266
1.513
9.385
1.613
$
$
$
$
$
$
$
$
$
$
$
1.153
0.421
9.044
1.184
0.994
0.421
8.825
0.993
1.589
9.395
1.808
1.317
1.396
1.053
1.378
9.384
1.508
(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.
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 40.6 million (UE – 22.4 million,
Genco – 10.1 million, AERG – 3.1 million, EEI – 5.0 million)
tons of coal in 2007. See Part II, Item 7A – Quantitative and
Qualitative Disclosures about Market Risk of this report for
additional information about coal supply contracts.
About 94% of Ameren’s coal (UE – 97%, Genco – 88%,
AERG – 92%, 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. As of December 31, 2007, coal inventories for UE,
Genco, AERG and EEI were adequate and in excess of
historical levels, but below 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
Fuel assemblies for the 2008 fall refueling at UE’s
Callaway nuclear plant will begin manufacture during the
second quarter of 2008. Enriched uranium for such
assemblies is already at the facility. UE also has agreements
or inventories to price-hedge 87% of Callaway’s 2010 and
2011 refueling requirements. There is no refueling scheduled
in 2009 or 2012. UE expects to enter into additional
contracts to purchase nuclear fuel. UE is a member of
Fuelco, which allows UE to join with other member
9
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 May 2007.
Natural Gas Supply for Power Generation
Ameren’s portfolio of natural gas supply resources
includes firm transportation capacity and firm no-notice
storage capacity leased from interstate pipelines to maintain
gas deliveries to our gas-fired generating units throughout
the year, especially during the summer peak demand. 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, 2007, UE had hedged about 25% of its
required gas supply for generation in 2008 and Genco about
90%. As of December 31, 2007, 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, including firm gas supply
under term agreements with producers, interstate and
intrastate firm transportation capacity, firm storage capacity
leased from interstate pipelines, and on-system storage
facilities to maintain gas deliveries to our customers
throughout the year and especially during 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. 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 12 – Related
Party Transactions, Note 13 – Commitments and
Contingencies, and Note 14 – 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:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
political and regulatory resistance to higher rates;
the potential for changes in laws, regulation, and
policies at the state and federal level, including those
resulting from election cycles;
the potential for more intense competition in generation
and supply;
the potential for reregulation in some states, which
could cause electric distribution companies to build
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;
fluctuations in power prices due to the balance of
supply and demand and fuel prices;
the availability of fuel and increases in 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 new 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;
public concerns about nuclear plant operation and
decommissioning and the disposal of nuclear waste;
uncertainty in the credit markets; 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 13 – Commitments and Contingencies to
our financial statements under Part II, Item 8, of this report.
10
OPERATING STATISTICS
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,
2007
2006
2005
Electric Sales – kilowatthours (in millions):
Missouri Regulated:
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Native . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-affiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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
13,859
14,539
8,820
781
37,999
3,549
11,564
53,112
Illinois Regulated:
Residential
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,857
11,476
11,711
Commercial
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-rate-regulated Generation:
Non-affiliate energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate affiliate sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate Illinois Regulated/Non-rate-regulated Generation common customers . . . . . . . . . .
7,232
5,178
1,606
11,199
576
-
37,648
25,196
7,296
32,492
(7,296)
(5,800)
Ameren Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
107,486
11,406
269
10,950
2,349
598
-
37,048
24,921
18,425
43,346
(28,036)
(2,024)
101,015
10,082
204
9,728
3,275
606
2,055
37,661
27,884
17,149
45,033
(30,768)
(8,979)
96,059
Electric Operating Revenues (in millions):
Missouri Regulated:
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Commercial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Native . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-affiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
980
839
390
111
2,320
466
-
$
899
796
392
104
2,191
263
196
937
814
363
109
2,223
253
230
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,786
$
2,650
$
2,706
Illinois Regulated:
Residential
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,055
$
852
$
Commercial
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
666
54
105
24
358
-
784
3
489
2
112
-
868
713
-
449
-
118
36
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,262
$
2,242
$
2,184
11
Electric Operating Statistics – Year Ended December 31,
2007
2006
2005
Non-rate-regulated Generation:
Non-affiliate energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Affiliate native energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate other sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Eliminate affiliate sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,266
495
37
1,798
(579)
Ameren Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
6,267
$
$
$
1,032
662
19
1,713
(1,020)
5,585
$
$
$
1,041
614
18
1,673
(1,131)
5,432
Electric Generation – megawatthours (in millions):
Missouri Regulated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-rate-regulated Generation:
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AERG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EEI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medina Valley. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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
49.6
14.2
6.0
7.9
0.2
28.3
77.9
Price per ton of delivered coal (average) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
25.20
$
22.74
$
21.31
Source of energy supply:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased and interchanged, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
68.7%
1.8
-
9.4
1.6
18.5
65.8%
0.9
0.7
9.7
0.9
22.0
66.0%
1.1
0.8
8.1
1.3
22.7
100.0%
100.0%
100.0%
Gas Operating Statistics – Year Ended December 31,
2007
2006
2005
Gas Sales (millions of Dth)
Missouri Regulated:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Regulated:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7
4
1
12
59
25
10
94
-
-
2
2
7
3
1
11
55
23
13
91
-
-
7
7
Ameren Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
108
109
Natural Gas Operating Revenues (in millions)
Missouri Regulated:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Residential
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
108
47
12
7
174
$
$
101
46
13
(2)
158
$
$
8
4
1
13
59
24
13
96
-
-
5
5
114
111
47
13
11
182
12
Gas Operating Statistics – Year Ended December 31,
2007
2006
2005
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Illinois Regulated:
Residential
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
687
272
103
39
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,101
Other:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Residential
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
-
-
16
-
16
Eliminate affiliate sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(12)
Ameren Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,279
Peak day throughput (thousands of Dth):
UE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
155
250
401
574
$
$
$
$
$
$
$
$
$
$
690
271
82
53
1,096
-
-
60
-
60
(19)
1,295
124
242
356
540
693
273
98
54
1,118
-
-
72
-
72
(27)
1,345
161
250
370
569
Total peak day throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,380
1,262
1,350
AVAILABLE INFORMATION
ITEM 1A. RISK FACTORS
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, nuclear oversight
committee, and public policy committee; the corporate
governance guidelines; a policy regarding communications to
the board of directors; policies and procedures with respect
to related-person transactions; a code of ethics for principal
executive officers 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.
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 our 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 certain Ameren Companies are allowed to
charge for their services are the single most important item
influencing the results of operations, financial position, and
liquidity of the Ameren Companies. The electric and gas
utility industry is highly regulated. The regulation of the rates
that we charge our customers is determined, in large part,
by governmental entities outside of our control, including the
MoPSC, the ICC, and FERC. Decisions made by these
entities could have a material adverse effect on results of
operations, financial position, or liquidity.
Our electric and gas utility rates are typically established
in a regulatory proceeding that takes up to 11 months to
complete. Rates established in those proceedings are
primarily based on historical costs and include an allowed
return on our investments by the regulator.
Our company, and the industry as a whole, is going
through a period of rising costs, including increases in fuel,
purchased power, labor and material costs, coupled with
significant increases in capital, operation and maintenance
and financing costs targeted at enhanced distribution system
reliability and environmental compliance. Due to rising costs
and the fact that our rates are primarily based on historical
costs, UE, CIPS, CILCO and IP are not earning the allowed
return established by their regulators (often referred to as
regulatory lag). As a result, UE, CIPS, CILCO and IP expect
to be entering a period where more frequent rate cases and
13
requests for cost recovery mechanisms will be necessary. A
period of increasing rates to our customers could result in
additional regulatory, legislative, political, economic and
competitive pressures that could have a material adverse
effect on our results of operations, financial position, or
liquidity.
Illinois
Pending Delivery Service Rate Cases
Due to inadequate recovery of costs and low returns on
equity experienced in 2007 and expected in 2008, CIPS,
CILCO and IP filed requests with the ICC in November 2007
to increase their annual revenues for electric delivery service
by $180 million in the aggregate (CIPS – $31 million,
CILCO – $10 million, and IP – $139 million). In addition,
CIPS, CILCO and IP filed requests with the ICC in November
2007 to increase their annual revenues for natural gas
delivery service by $67 million in the aggregate (CIPS –
$15 million increase, CILCO – $4 million decrease and IP –
$56 million increase). The ICC has until the end of
September 2008 to render a decision in these rate cases. It
could materially reduce the amount of the increase
requested, or even reduce rates.
Illinois Electric Settlement Agreement
Due to the magnitude of rate increases that went into
effect following the end of a rate freeze on January 2, 2007
under the Illinois Customer Choice Law, various legislators
supported legislation that would have reduced and frozen the
electric rates of CIPS, CILCO and IP at the level in effect
prior to January 2, 2007, or would have imposed a tax on
electric generation in Illinois to help fund customer
assistance programs. The Illinois governor also supported
rate rollback and freeze legislation. The rate rollback and
freeze legislation would have prevented the Ameren Illinois
Utilities from recovering from retail customers substantial
portions of the cost of electric energy that the Ameren
Illinois Utilities are obligated to purchase under wholesale
contracts, and would also have caused the Ameren Illinois
Utilities to under-recover their delivery service costs until the
ICC could approve higher delivery service rates.
In order to address these concerns, the Illinois electric
settlement agreement was reached in 2007. Ameren, on
behalf of Marketing Company, Genco and AERG, the Ameren
Illinois Utilities, Exelon, on behalf of Exelon Generation
Company LLC, Commonwealth Edison Company, Exelon’s
Illinois electric utility subsidiary, Dynegy Holdings, Inc.,
Midwest Generation, LLC, and MidAmerican Energy Company
agreed to contribute an aggregate of $1 billion over four years
to fund both rate relief programs and a new power
procurement agency, the IPA. Approximately $488 million of
the funding is earmarked as rate relief for customers of the
Ameren Illinois Utilities. The Ameren Illinois Utilities, Genco
and AERG agreed to make aggregate contributions of
$150 million over a four-year period, which commenced in
2007, 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
AERG. The Illinois electric settlement agreement provides that
if legislation freezing or reducing retail electric rates or
imposing or authorizing a new tax, special assessment or fee
on generation of electricity is enacted before August 1, 2011,
then the remaining funding commitments will expire. Any
funds set aside in support of those commitments will be
refunded to the utilities and electric generators. See Note 2 –
Rate and Regulatory Matters to our financial statements under
Part II, Item 8, of this report for additional information on the
Illinois electric settlement agreement.
The following factors resulting from implementation of
the Illinois electric settlement agreement could have a
material adverse effect on the results of operations, financial
position or liquidity of Ameren, the Ameren Illinois Utilities,
Genco or AERG:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
uncertainty as to the implementation of the new power
procurement process in Illinois for 2008 and 2009,
including ICC review and approval requirements, the
role of the IPA, timely procurement of power and
recovery of costs from the Ameren Illinois Utilities’
customers, and the ability of the Ameren Illinois Utilities
or other electric distribution companies to lease or
invest in generation facilities;
the extent to which the IPA may exercise its statutory
authority to build or invest in generation facilities;
the increase in short-term or long-term borrowings by
the Ameren Illinois Utilities, Genco and AERG to fund
contributions under the Illinois electric settlement
agreement or to pay for or collateralize their obligations
under future power purchase agreements;
the failure by the electric generators that are party to
the settlement agreement to perform in a timely manner
under their respective funding agreements, which permit
the Ameren Illinois Utilities to seek reimbursement for a
portion of the rate relief that will be provided to certain
of their electric customers; and
the extent to which Genco and AERG will be successful
in making future sales to meet a portion of Illinois’ total
electric demand through the revised power procurement
mechanism.
If, notwithstanding the Illinois electric settlement
agreement, any decision is made or any action occurs that
impairs the ability of CIPS, CILCO and IP to fully recover
purchased power or distribution costs from their electric
customers in a timely manner, and such decision or action is
not promptly enjoined, it could result in material adverse
consequences to Ameren, CIPS, CILCORP, CILCO and IP.
Missouri
With the expiration of multiyear electric and gas rate
moratoriums, effective July 1, 2006, UE filed requests with
the MoPSC in July 2006 for an electric rate increase of
$361 million and for a natural gas delivery rate increase of
$11 million. In March 2007, a stipulation and agreement
approved by the MoPSC authorized an increase in annual
natural gas delivery revenues of $6 million, effective April 1,
2007. As part of this stipulation and agreement, UE agreed
not to file a natural gas delivery rate case before March 15,
14
2010. This agreement did not prevent UE from filing to
recover infrastructure costs through an ISRS during this
three-year rate moratorium. In February 2008, the MoPSC
approved UE’s petition requesting the establishment of an
ISRS to recover annual revenues of $1 million effective
March 29, 2008.
In May 2007, the MoPSC issued an order authorizing a
$43 million increase in UE’s base rates for electric service
based on a return on equity of 10.2%. Certain aspects of the
MoPSC decision have been appealed by UE, the Office of Public
Counsel and the Missouri attorney general to the Court of
Appeals for the Western District of Missouri. In its order, the
MoPSC denied UE the use of a fuel and purchased power cost
recovery mechanism. UE expects to incur significant increases
in fuel and related transportation costs over the next three
years. Without a rate recovery mechanism, UE may experience
regulatory lag and not fully recover these costs.
Increased federal and state environmental regulation
will cause UE, Genco, CILCO (through AERG) and EEI to
incur large capital expenditures and increased operating
costs. Future limits on greenhouse gas emissions would
likely require UE, Genco, CILCO (through AERG) and EEI to
incur significant additional increases in capital expenditures
and operating costs. Such expenses, if excessive, could
result in the closures of coal-fired generating plants.
About 61% of Ameren’s (UE – 54%, Genco – 60%,
AERG – 95%, EEI – 95%) generating capacity is coal-fired.
About 84% (UE – 76%, Genco – 96%, AERG – 99%, EEI –
100%) of its electric generation was produced by its coal-
fired plants in 2007. The remaining electric generation
comes from nuclear, gas-fired, hydroelectric, and oil-fired
power plants. The EPA has issued final regulations with
respect to SO2, NOx, and mercury emissions from coal-fired
power plants. These regulations require significant additional
reductions in the emissions from UE, Genco, AERG and EEI
power plants in phases, beginning in 2009, and significant
capital expenditures. Missouri has adopted rules that
substantially follow the federal regulations.
Illinois has adopted rules for mercury emissions that
are significantly stricter than the federal regulations. In 2006,
Genco, AERG, EEI, and the Illinois EPA entered into an
agreement that was incorporated into Illinois’ mercury
emission regulations. Under the regulations, Illinois
generators may defer until 2015 the requirement to reduce
mercury emissions by 90% in exchange for accelerated
installation of NOx and SO2 controls. In 2009, Genco, AERG
and EEI will begin putting into service equipment designed
to reduce mercury emissions.
In February 2008, the U.S. Court of Appeals for the
District of Columbia issued a decision that effectively
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 Court’s decision is subject to appeal,
and it is uncertain how the EPA will respond. At this time,
we are unable to determine the impact that this action would
have on our estimated expenditures for compliance with
environmental rules, our results of operations, financial
position, or liquidity.
Ameren’s estimated capital costs based on current
technology to comply with both the federal Clean Air
Interstate Rule and Clean Air Mercury Rule and related state
implementation plans range from $4 billion to $5 billion by
2017 (UE – $1.8 billion to $2.3 billion; Genco – $1.3 billion
to $1.6 billion, AERG – $620 million to $760 million, EEI –
$310 million to $410 million).
Future initiatives regarding greenhouse gas emissions
and global warming are subject to active consideration in the
U.S. Congress. Ameren believes that currently proposed
legislation can be classified as moderate to extreme
depending upon proposed CO2 emission limits, the timing of
implementation of those limits, and the method of allocating
allowances. The moderate scenarios include provisions for 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 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. When
consumed natural gas emits about half the amount of CO2
as coal. As a result, economy-wide shifts favoring natural
gas as a fuel source for electric generation also would affect
the cost of nonelectric transportation, heating for our
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 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. 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.
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 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 made.
In April 2005, Genco received a request from the EPA
for information pursuant to Section 114(a) of the Clean Air
15
Act seeking detailed operating and maintenance history data
with respect to its Meredosia, Hutsonville, Coffeen 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. We are currently in
discussions with the EPA and the state of Illinois regarding
these matters, but we are unable to predict the outcome of
these discussions. Resolution of the matters could have a
material adverse impact on the future results of operations,
financial position, or liquidity of Ameren, Genco, AERG and
EEI. A resolution could result in increased capital
expenditures, increased operations and maintenance
expenses, and fines or penalties. We believe that any
potential resolution would probably require the installation of
emission control technology, some of which has already
been planned for compliance with other regulatory
requirements, such as the Clean Air Interstate Rule and the
Illinois mercury emission rules.
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 and 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 by Genco, AERG or EEI. We are unable
to predict the ultimate impact of these matters on our
results of operations, financial position or liquidity.
The construction of, and capital improvements to,
UE’s, CIPS’, CILCO’s and IP’s electric and gas utility
infrastructure as well as to Genco’s, CILCO’s (through
AERG) and EEI’s non-rate-regulated power generation
facilities involve substantial risks, particularly as the
Ameren Companies expect to incur significant capital
expenditures over the next five years and beyond for
compliance with environmental regulations and to make
significant investments in our utility infrastructure to
improve overall system reliability. Should construction or
capital improvement efforts be unsuccessful, it could have
a material adverse impact on Ameren’s, UE’s, CIPS’,
Genco’s, CILCORP’s, CILCO’s and IP’s results of
operations, financial position, or liquidity.
The Ameren Companies will incur significant capital
expenditures over the next five years for compliance with
environmental regulations and to make significant
investments in their electric and gas utility infrastructure and
their non-rate-regulated power generation facilities. The
Ameren Companies estimate that they will incur up to
$10.6 billion (UE – up to $4.9 billion; CIPS – up to
$505 million; Genco – up to $2.1 billion; CILCO (Illinois
Regulated) – up to $425 million; CILCO (AERG) – up to
$870 million; IP – up to $1.1 billion; EEI – up to $555 million,
Other – up to $205 million) of capital expenditures during
the period from 2008 through 2012, including construction
expenditures, capitalized interest and allowance for funds
used during construction (except for Genco, which has no
allowance for funds used during construction), and
estimated expenditures for 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 continue to escalate.
Investment in Ameren’s regulated operations is
expected to be recoverable from ratepayers. The
recoverability of amounts expended in non-rate-regulated
operations will depend on whether market prices for power
adjust as a result of market conditions reflecting increased
costs generally for generators.
The ability of the Ameren Companies to successfully
complete those facilities currently under construction, and
those projects yet to begin construction within established
estimates is contingent upon many variables and are 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,
and other events beyond our control may occur that may
materially affect the schedule, cost and performance of these
projects. With respect to capital expenditures related to the
installation of pollution control equipment, there is a risk that
such electric generating plants would 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 gas to supply its 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.
Our counterparties may not meet their obligations to us.
We are exposed to the risk that counterparties to
various arrangements who owe us money, energy, coal or
other commodities or services will not be able to perform
their obligations. Should the counterparties to these
arrangements fail to perform, we might be forced to replace
or to sell the underlying commitment at then-current market
prices. In such 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, or other commodities
and 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 such nondefaulting Ameren
entity being unable to meet its obligations to unrelated third
parties. Hedging activities are generally undertaken with a view
16
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. In May 2007, the MoPSC
issued an electric rate order that allows UE to recover through
customer rates pension expense incurred under GAAP.
Ameren expects to fund its pension plans at a level equal to
the pension expense. Based on Ameren’s assumptions at
December 31, 2007, and reflecting this pension funding
policy, Ameren expects to make annual contributions of
$40 million to $65 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 65%, 8%, 11%, 5%, and
11%, respectively. These amounts are estimates. They may
change with actual stock market 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 substantially 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.
UE’s, Genco’s, AERG’s, Medina Valley’s and EEI’s
electric generating facilities are subject to operational
risks that could result in unscheduled plant outages,
unanticipated operation and maintenance expenses,
liability, and increased purchased power costs.
UE, Genco, AERG, Medina Valley, and EEI own and
operate coal-fired, nuclear, gas-fired, hydroelectric, and oil-
fired generating facilities. Operation of electric generating
facilities involves certain risks that can adversely affect
energy output, efficiency levels, operating costs, and
investment levels. Among these risks are:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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;
lack of water for cooling plant operations;
labor disputes;
inability to comply with regulatory or permit
requirements;
disruptions in the delivery of electricity;
(cid:129)
(cid:129)
(cid:129)
increased capital expenditure requirements, including
those due to environmental regulation;
unusual or adverse weather conditions, including
drought; and
catastrophic events such as fires, explosions, floods, or
other similar occurrences affecting electric generating
facilities.
Even though agreements have been reached with
state and federal authorities, 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.
In October 2006, FERC approved a stipulation and
consent agreement between UE and FERC’s Office of
Enforcement that resolves all issues arising from an
investigation by FERC’s Office of Enforcement into alleged
violations of license conditions and FERC regulations by UE,
as the licensee of the Taum Sauk hydroelectric facility, that
may have contributed to the breach of the upper reservoir.
In November 2007, UE entered into a settlement agreement
with the state of Missouri represented by the Missouri
attorney general, the Missouri Conservation Commission and
the Missouri Department of Natural Resources. The
agreement resolved the state of Missouri’s lawsuit and
claims for damages and other relief related to the December
2005 Taum Sauk breach. A business owners’ suit, which was
filed in the Missouri Circuit Court of Reynolds County and
remains pending, seeks damages relating to business losses
and lost profit and unspecified punitive damages.
In February 2007, UE submitted to FERC an
environmental report to rebuild the upper reservoir at Taum
Sauk. UE received approval from FERC in August 2007 and
hired a contractor in November 2007. The estimated cost to
rebuild the upper reservoir is in the range of $450 million.
The Taum Sauk plant is expected to be out of service at
least through the fall of 2009.
As part of the settlement agreement with the state of
Missouri, UE agreed not to attempt to recover from
ratepayers in any future rate increase any in-kind or
monetary payments to the state parties required by the
settlement agreement or any costs incurred in the rebuilding
of the upper reservoir (expressly excluding, however,
enhancements, costs incurred due to circumstances or
conditions that are currently not reasonably foreseeable, and
costs that would have been incurred absent the December
2005 breach of the upper reservoir at the Taum Sauk plant).
If UE needs to purchase power because of the
unavailability of the Taum Sauk facility during the rebuild of the
upper reservoir, UE has committed to not seek these additional
costs from ratepayers. The Taum Sauk incident is expected to
reduce Ameren’s and UE’s 2008 pretax earnings by $15 million
to $20 million. UE expects to face higher-cost sources of
17
power, reduced interchange sales, and increased expenses, net
of insurance reimbursement for replacement power costs.
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. 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.
The Missouri Parks Association and the Missouri
Coalition for the Environment initiated legal proceedings over
FERC’s decision to authorize the rebuilding of the upper
reservoir at Taum Sauk. They seek injunctive and other relief.
If they obtain injunctive relief, it could delay the construction
of the rebuild and could delay the return of the plant to
service.
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.
In December 2006, Genco and Marketing Company, and
AERG and Marketing Company, entered into new 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 such amount of
associated energy commencing on January 1, 2007. All of
Genco’s and AERG’s generating capacity now competes for
the sale of energy and capacity in the competitive energy
markets through Marketing Company.
On December 31, 2005, EEI’s power supply contract
with its affiliates, including UE, CIPS and IP, expired. EEI
entered into a power supply agreement with Marketing
Company whereby EEI sells 100% of its capacity and energy
to Marketing Company. All of EEI’s generating capacity now
competes for the sale of energy and capacity in the
competitive energy markets through Marketing Company.
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 they can
obtain for energy and capacity in Illinois and adjacent
markets. Among the factors that could influence such prices
(all of which are beyond our control to a significant degree)
are:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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 pricing structures developed for
evolving Midwest energy markets and the pace at which
regional markets for energy and capacity develop
outside of bilateral contracts;
changes enacted by the Illinois legislature, the ICC, the
IPA or other government agencies with respect to power
procurement procedures;
the potential for reregulation of generation in some
states;
future pricing for, and availability of, services on
transmission systems, and the effect of RTOs and
export energy transmission constraints, which could
limit our ability to sell energy in our markets;
the growth rate in electricity usage as a result of
population changes, regional economic conditions, and
the implementation of conservation programs;
climate conditions in the Midwest market; and
environmental laws and regulations.
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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 2007 generation. Therefore, UE is subject to the risks
of nuclear generation, which include the following:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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;
increased 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.
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.
18
UE’s Callaway nuclear plant’s next scheduled refueling
and maintenance outage is in the fall of 2008. During an
outage, which occurs approximately every 18 months,
maintenance and purchased power costs increase, and the
amount of excess power available for sale decreases,
compared with non-outage years.
Operating performance at UE’s Callaway nuclear plant
has resulted in unscheduled or extended outages. The
operating performance at UE’s Callaway nuclear plant declined
both in comparison with its past operating performance and
in comparison with the operating performance of other
nuclear plants in the United States. Ameren and UE are
actively working to address the factors that led to the decline
in Callaway’s operating performance. Management and
supervision of operating personnel, equipment reliability,
maintenance worker practices, engineering performance,
training, and overall organizational effectiveness have been
reviewed. Some actions have been taken. However, Ameren
and UE cannot predict whether such efforts will result in an
overall improvement of operations at Callaway. Any additional
actions taken are expected to result in incremental operating
costs at Callaway. Further, additional unscheduled or extended
outages at Callaway could have a material adverse effect on
the results of operations, financial position, or liquidity of
Ameren and UE.
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 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, weather, 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
ITEM 2. PROPERTIES.
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, 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.
We use short-term and long-term capital markets as a
significant source of liquidity and funding for capital
requirements not satisfied by our operating cash flow,
including requirements related to future environmental
compliance. As a result of rising costs and increased capital
and operations and maintenance expenditures, coupled with
near-term regulatory lag, we expect to need more short-term
and long-term debt financing. The inability to raise capital on
favorable terms, 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 recent collapse of the subprime
mortgage market may create uncertainty that could increase
our cost of capital or impair our ability to access the capital
markets. 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. See the Credit
Ratings section in 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 for a discussion of credit rating changes in
response to actions in Illinois with respect to the matter of
power procurement commencing in 2007.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
For information on our principal properties, see the generating facilities table below. See also Liquidity and Capital Resources
and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II,
Item 7, of this report for any planned additions, replacements or transfers. See also Note 5 – Long-term Debt and Equity
Financings, and Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
19
The following table shows what our electric generating facilities and capability are anticipated to be at the time of our
expected 2008 peak summer electrical demand:
Primary Fuel Source
Plant
Location
Net Kilowatt Capability(a)
Missouri Regulated:
UE:
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total coal . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . .
Total hydroelectric . . . . . . . . . . . . . . . . . . . . .
Labadie
Rush Island
Sioux
Meramec
Callaway
Osage
Keokuk
Franklin County, Mo.
Jefferson County, Mo.
St. Charles County, Mo.
St. Louis County, Mo.
Callaway County, Mo.
Lakeside, Mo.
Keokuk, Iowa
Pumped-storage . . . . . . . . . . . . . . . . . . . . . . .
Taum Sauk
Reynolds County, Mo.
Oil (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total oil . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (CTs) . . . . . . . . . . . . . . . . . . . . . .
Total natural gas . . . . . . . . . . . . . . . . . . . . . . .
Total UE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . .
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.
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(h)
Columbia(i)
Grand Tower, Ill.
Elgin, Ill.
Gibson City, Ill.
Joppa, Ill.
Columbia, Mo.
2,406,000
1,181,000
993,000
842,000
5,422,000
1,190,000
234,000
134,000
368,000
(b)
55,000
59,000
55,000
55,000
55,000
43,000
(c)
322,000
188,000
53,000
492,000
25,000
13,000
608,000
438,000
304,000
316,000
216,000
2,653,000
9,955,000
1,000,000
55,000
1,055,000
1,208,000
900,000
290,000
151,000
2,549,000
156,000
3,000
159,000
511,000
460,000
234,000
162,000
140,000
1,507,000
4,215,000
20
Primary Fuel Source
Plant
Location
Net Kilowatt Capability(a)
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 . . . . . . . . . . . . . . . . . . . . . . .
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.
744,000
330,000
1,074,000
30,000
10,000
40,000
9,000
6,000
15,000
1,129,000
44,000
6,443,000
16,398,000
“Net Kilowatt Capability” is the generating capacity available for dispatch from the facility into the electric transmission grid.
(a)
(b) This facility is out of service. It is not operational because of a breach of its upper reservoir in December 2005. Its 2005 peak summer
electrical demand net kilowatt capability was 440,000. For additional information on the Taum Sauk incident, see Note 13 – Commitments
and Contingencies under Part II, Item 8 of this report.
(c) This facility will be out of service in 2008.
(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.
(g) There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts).
(h) These CTs are owned by Genco and were leased to Development Company prior to its elimination in an internal reorganization in February
2008. The operating lease was terminated in February 2008. Genco received rental payments under the lease in fixed monthly amounts that
varied over the term of the lease and ranged from $0.8 million to $1.0 million.
(i) 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.
The following table presents electric and natural gas
utility-related properties for UE, CIPS, CILCO and IP as of
December 31, 2007:
UE
CIPS
CILCO
IP
Circuit miles of electric
transmission lines . . .
2,931
2,306
331
1,853
Circuit miles of electric
distribution lines . . . .
32,489
14,872
8,908
21,538
Percent of circuit miles
of electric distribution
lines underground . . .
Miles of natural gas
transmission and
distribution mains . . .
Number of propane-air
plants . . . . . . . . . . .
Number of underground
gas storage fields . . .
Billion cubic feet of total
working capacity of
underground gas
storage fields . . . . . .
21%
11%
26%
12%
3,145
5,311
3,878
8,722
1
-
-
-
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:
(cid:129)
(cid:129)
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
21
(cid:129)
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 –
Credit Facilities and Liquidity 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, 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
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 13 – 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.
In December 2007, Caterpillar Inc., in conjunction with
other industrial customers as a coalition, intervened in the
2007 rate cases filed by CILCO and IP with the ICC to
modify their electric and natural gas delivery service rates.
Douglas R. Oberhelman is an executive officer of Caterpillar
Inc. and a member of the board of directors of Ameren.
Mr. Oberhelman did not participate in Ameren Corporation’s
board and committee deliberations relating to these matters.
For additional information on legal and administrative
proceedings, see Rates and Regulation under Item 1,
Business, and Item 1A, Risk Factors, above. See also
Liquidity and Capital Resources and Regulatory Matters in
Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7,
and Note 2 – Rate and Regulatory Matters, and Note 13 –
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 2007 with respect to
any of the Ameren Companies.
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of
December 31, 2007, 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.
22
AMEREN CORPORATION:
Age at
12/31/07
61
Positions and Offices Held
Name
Gary L. Rainwater
Chairman, Chief Executive Officer, President, and Director
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. Effective January 1, 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 September 2004, upon Ameren’s acquisition of IP, Rainwater was 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. Effective January 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.
Warner L. Baxter
46
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 October 2003 and of IP in September 2004. He
was elected chairman, chief executive officer, president, and chief financial officer of Ameren Services effective January 1, 2007.
Thomas R. Voss
60
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 October 2003, Voss was elected president of Genco; he
relinquished his presidency of this company in October 2004. He was elected to his present position at Ameren in January
2005. In May 2006, he was elected executive vice president of UE, CIPS, CILCORP, CILCO and IP. Effective January 1, 2007,
Voss was elected chairman, chief executive officer, and president of UE. He relinquished his positions at CIPS, CILCORP, CILCO
and IP in April 2007.
Donna K. Martin
Martin joined Ameren Services in May 2002 as vice president, human resources. In February 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 April
2007.
Senior Vice President and Chief Human Resources Officer
60
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 January 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 October 2003, and at IP in September 2004.
Senior Vice President, General Counsel, and Secretary
47
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 January 2003, and
of IP in September 2004.
Vice President and Treasurer
53
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 January 2003. He was also elected vice president of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and Ameren Services
in February 2003 and vice president and controller of IP in September 2004. In July 2007, his position at UE was changed to
vice president and principal accounting officer. Effective January 1, 2008, Lyons was elected senior vice president and chief
accounting officer of the Ameren Companies and various other Ameren subsidiaries.
Senior Vice President and Chief Accounting Officer
41
23
Name
SUBSIDIARIES:
Scott A. Cisel
Age at
12/31/07
Positions and Offices Held
54
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.
Effective January 1, 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 April 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 January 2003, and at IP in September 2004.
Senior Vice President (CILCO, CIPS, CILCORP, IP and UE)
54
R. Alan Kelley
55
Chairman, Chief Executive Officer, and President (Resources
Company), and President (Genco)
Kelley joined UE in 1974 as an engineer. Kelley was elected senior vice president of Ameren Services in 1999 and of Genco in
2000. He was elected senior vice president of CILCO in January 2003, upon Ameren’s acquisition of that company. In October
2004, Kelley was elected president of Genco, and senior vice president of UE. Effective January 1, 2007, he was elected
chairman, chief executive officer, and president of Ameren Energy Resources Company, and of its successor, Resources
Company, in February 2008. Kelley relinquished his positions at UE, Ameren Services, and CILCO in April 2007.
Richard J. Mark
Mark joined Ameren Services in January 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
January 2005, with responsibility for Missouri energy delivery. In April 2007, Mark relinquished his position at Ameren Services.
Senior Vice President (UE)
52
Michael L. Moehn
Moehn joined Ameren Services as assistant controller in June 2000. He was named director of Ameren Services’ corporate
modeling and transaction support in 2001 and elected vice president of business services for Resources Company in 2002. In
2004, Moehn was elected vice president of corporate planning for Ameren Services and relinquished his position at Resources
Company.
Vice President (Ameren Services)
38
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)
44
Charles D. Naslund
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 September 2004. He relinquished his position at Ameren Services in
2001. Naslund was elected senior vice president and chief nuclear officer at UE in January 2005.
Senior Vice President and Chief Nuclear Officer (UE)
55
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)
46
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. All of
the above-named executive officers have been employed by an Ameren company for more than five years in executive or
management positions.
24
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 27, 2007, 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 74,419 on January 31, 2008. The following table presents the price ranges
and dividends paid per Ameren common share for each quarter during 2007 and 2006.
High
Low
Close
Dividends Paid
AEE 2007 Quarter Ended:
March 31. . . . . . . . . . . . . . . . . . . . . . . . . . . . $
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . .
December 31 . . . . . . . . . . . . . . . . . . . . . . . . .
AEE 2006 Quarter Ended:
March 31. . . . . . . . . . . . . . . . . . . . . . . . . . . . $
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . .
December 31 . . . . . . . . . . . . . . . . . . . . . . . . .
55.00
55.00
53.89
54.74
52.75
51.30
53.77
55.24
$
$
48.56
48.23
47.10
51.81
48.51
47.96
49.80
52.19
$
$
50.30
49.01
52.50
54.21
49.82
50.50
52.79
53.73
631⁄2¢
631⁄2
631⁄2
631⁄2
631⁄2¢
631⁄2
631⁄2
631⁄2
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
2007 and 2006:
2007
Quarter Ended
2006
Quarter Ended
Registrant
December 31
September 30
June 30 March 31
December 31
September 30
June 30 March 31
UE . . . . . . . . . . . .
CIPS . . . . . . . . . .
Genco . . . . . . . . .
CILCORP(a) . . . . . .
IP . . . . . . . . . . . .
Nonregistrants . . . .
$
21
40
-
-
61
10
Ameren . . . . . . . .
$
132
$
$
119
-
-
-
-
13
132
$
$
47
-
74
-
-
11
80
-
39
-
-
12
$
95
-
20
-
-
16
$
70
25
22
-
-
14
$
42
25
49
-
-
14
$
42
-
22
50
-
16
$
132
$
131
$
131
$
131
$
130
$
130
(a) CILCO paid dividends to CILCORP of $50 million in the quarterly period ended March 31, 2006, and $15 million in the quarterly period
ended September 30, 2006.
On February 8, 2008, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 63.5
cents per share. The common share dividend is payable March 31, 2008, to stockholders of record on March 5, 2008.
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.
25
Purchases of Equity Securities
The following table presents Ameren’s purchases of equity securities reportable under Item 703 of Regulation S-K:
Period
October 1 – 31, 2007 . . . . . . . . . .
November 1 – 30, 2007 . . . . . . . . .
December 1 – 31, 2007 . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . .
Total Number
of Shares (or Units)
Purchased(a)
Average Price
Paid per Share
(or Unit)
-
3,350
1,700
5,050
$
$
-
54.11
54.04
54.09
Total Number of Shares
(or Units) Purchased as
Part of Publicly Announced
Plans or Programs
Maximum Number
(or Approximate Dollar Value)
of Shares That May Yet
Be Purchased Under the
Plans or Programs
-
-
-
-
-
-
-
-
(a) Included in December were 1,000 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to
Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligations for Ameren Board of Directors’ compensation
awards. The remaining shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s
obligations upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any
publicly announced equity securities repurchase plans or programs.
None of the other Ameren Companies purchased equity securities reportable under Item 703 of Regulation S-K during the
period October 1 to December 31, 2007.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five fiscal years ended December 31,
2007. 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, 2002, in Ameren common stock and in each of the indices shown, and it assumes that all of the
dividends were reinvested.
$275
$250
$225
$200
$175
$150
$125
$100
$75
$50
2002
2003
2004
2005
2006
2007
AEE
S&P 500
EEI Index
December 31,
2002
2003
2004
2005
2006
2007
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S&P 500 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EEI Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$100.00
100.00
100.00
$117.36
128.69
123.48
$135.10
142.69
151.68
$144.92
149.70
176.03
$159.57
173.33
212.57
$169.05
182.85
247.77
Ameren management cautions that the stock price performance shown in the graph above should not be considered
indicative of potential future stock price performance.
26
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(a)(b) . . . . . . . . . . . . . . . .
– 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 . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . .
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 . . . . . . .
$
$
$
$
$
$
$
$
$
$
$
$
2007
2006
2005
2004
2003
6,880
1,173
547
522
2.66
2.66
2.54
19,635
5,285
17
6,583
2,823
620
343
249
10,290
2,934
3,153
954
69
35
50
1,855
471
543
992
131
49
113
1,850
474
163
563
733
65
19
50
2,250
542
17
671
733
79
45
65
1,650
148
$
$
$
$
$
$
$
$
$
$
$
$
6,780
1,284
606
511
3.02
3.02
2.54
18,171
5,354
19
6,364
2,889
640
346
280
9,277
2,698
3,016
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
$
$
$
$
$
$
$
$
$
$
$
$
5,135
1,078
530
479
2.84
2.84
2.54
17,450
5,021
20
5,800
2,640
673
373
315
8,750
2,059
2,996
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
$
$
$
$
$
$
$
$
$
$
$
$
4,574
1,090
524
410
3.25
3.25
2.54
14,236
4,070
21
4,354
2,616
787
441
288
8,517
1,758
2,923
742
45
26
62
1,742
485
532
785
197
75
36
1,977
698
411
321
926
85
23
27
2,136
669
21
478
839
53
43
62
1,324
138
$
$
$
$
$
$
$
$
$
$
$
$
7,546
1,342
618
527
2.98
2.98
2.54
20,728
5,691
16
6,752
2,961
590
336
267
10,903
3,208
3,601
1,005
49
14
40
1,860
456
517
872
256
125
113
1,968
474
126
648
990
135
47
-
2,459
537
16
715
990
144
74
-
1,862
148
27
For the Years Ended December 31,
(In millions, except per share amounts)
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(d)
. . . . . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . .
$
$
2007
2006
2005
2004
2003
$
$
16
622
1,646
109
24
61
3,319
1,014
2
1,308
$
$
17
535
1,694
141
55
-
3,212
772
92
1,346
$
$
19
562
1,653
202
95
76
3,056
704
184
1,287
$
$
20
437
1,539
216
137
-
3,117
713
278
1,280
21
342
1,568
178
115
-
5,059
1,435
345
1,530
(a) Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for CILCORP since the acquisition date of
January 31, 2003; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) For the years ended December 31, 2005 and 2003, net income included income (loss) from cumulative effect of change in accounting
principle of $(22) million and $18 million or ($(0.11) and $0.11 per share) for Ameren, $(16) million and $18 million for Genco, $(2) million
and $4 million for CILCORP, $(2) million and $24 million for CILCO, and $- and $(2) million for IP.
(c) Includes 2004 combined financial data under ownership by Ameren and IP’s former ultimate parent, Dynegy.
(d) Effective December 31, 2003, IP SPT was deconsolidated from IP’s financial statements in conjunction with the adoption of FIN 46R,
“Variable Interest Entities.” See Note 1 – Summary of Significant Accounting Policies, Variable-interest Entities, to our financial statements
under Part II, Item 8, of this report for further information.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Operations
In 2007, we accomplished some key objectives that we
believe will bring significant long-term benefits to our
customers and shareholders. In Illinois, the Ameren Illinois
Utilities, Genco and AERG reached a comprehensive
settlement that will help Ameren Illinois Utilities customers’
transition to higher electric rates and bring stability to the
power procurement process. Rate rollback and freeze
legislation in response to higher electric rates in Illinois,
driven by deregulation of that market, would have had
severe negative operational and financial consequences for
Ameren, CIPS, CILCORP, CILCO and IP, as well as
significantly impacted the Ameren Illinois Utilities’ ability to
deliver reliable service to their customers. Major
stakeholders involved with this issue, including the Illinois
governor’s office, leaders of the House of Representatives
and Senate in Illinois, and the Illinois attorney general’s
office, agreed to the Illinois electric settlement agreement.
As a result, the Illinois electric settlement agreement
provides significantly greater levels of legislative, regulatory
and legal certainty. It also enables a viable competitive
power supply market to continue to develop in Illinois.
In late 2007, the Ameren Illinois Utilities requested to
increase annual revenues for electric and gas delivery
services by $247 million in the aggregate. The Ameren
Illinois Utilities also requested ICC approval to implement
rate adjustment mechanisms for bad debt expenses, certain
electric infrastructure investments and the decoupling of
natural gas revenues from sales volumes. The ICC has until
the end of September 2008 to render a decision in these
rate cases. UE also expects to file an electric rate increase
request in Missouri in the second quarter of 2008 to
mitigate higher cost and investment levels. Constructive
outcomes for the rate cases in Illinois and Missouri are very
important to UE and the Ameren Illinois Utilities. UE, CIPS,
CILCO and IP need to recover their costs to continue
investing in their energy infrastructure on a timely basis and
provide their customers with safe and reliable service.
In Missouri, we were able to settle all state and federal
issues associated with the December 2005 breach of the
upper reservoir at UE’s Taum Sauk pumped-storage
hydroelectric facility. UE has begun rebuilding the upper
reservoir and expects the plant to be out of service until the
fall of 2009, if not longer. The cost of the rebuild is expected
to be in the range of $450 million. UE believes that
substantially all damages and liabilities (but not fines and
penalties) 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 or replacement power,
up to $8 million annually, will be covered by insurance.
In February 2008, UE filed an integrated resource plan
with the MoPSC. The integrated resource plan outlines
support for energy efficiency measures to reduce demand
growth, expand renewable generation and increase existing
power plant efficiency. Some of UE’s coal-fired power plants
are aging, and an analysis will be completed in 2009 to
determine which units are likely candidates for retirement.
The integrated resource plan concludes that a new baseload
plant is expected to be required in our regulated Missouri
operations in the 2018 to 2020 timeframe. For that reason,
UE is preserving the option to develop additional nuclear
generation, while researching clean coal and carbon
sequestration technologies. UE expects to file in 2008 a
28
construction and operating license application with the NRC
for a new unit at UE’s Callaway nuclear plant site. While this
filing will not represent a final decision, it preserves the
option to build a nuclear unit. UE will not proceed on any
new baseload power plant unless construction costs are
recoverable through rates in Missouri. In addition to
considering a new unit at Callaway, UE also began the
process in 2008 to extend through 2044 the existing unit
license at Callaway, which currently expires in 2024.
In 2007, Ameren’s Non-rate-regulated Generation
business segment continued to execute its plan for investing
in its power plants to improve their future productivity, as
well as to effectively market their generation, consistent with
their risk management framework. Non-rate-regulated
Generation has also begun significant work on some of its
coal-fired plants to begin installing additional environmental
controls.
Earnings
Ameren reported net income of $618 million, or
$2.98 per share, for 2007 compared to net income of
$547 million, or $2.66 per share, in 2006. Earnings in 2007
principally benefited from, among other things, higher-priced
power sales contracts in Ameren’s Non-rate-regulated
Generation business segment, the June 2007 implementation
of a Missouri electric rate order and greater demand for
electricity and natural gas caused by warmer summer and
cooler winter weather than in 2006.
Ameren’s 2007 earnings were reduced by 21 cents per share
for the net cost of the Illinois electric settlement agreement.
Storm-related costs in 2006 reduced net income by 26 cents
per share. The impact of storm restoration efforts was less
in 2007, but still significant. Ameren’s 2007 earnings were
reduced by 9 cents per share as a result of the cost of
restoration efforts associated with a severe ice storm in
January 2007. In addition, a FERC order retroactively
adjusting prior years’ RTO costs reduced 2007 earnings by
6 cents per share. Other items that unfavorably impacted
earnings were, among other things, higher fuel costs and
bad debt expenses, lower emission allowance sales,
increased expenditures to improve reliability in Ameren’s
regulated business segments and higher depreciation and
financing costs due to greater energy infrastructure
investment. In addition, there were fewer sales of noncore
properties in 2007.
Liquidity
Cash flows from operations of $1.1 billion in 2007 at
Ameren, along with other funds, were used to pay dividends
to common shareholders of $527 million and to fund capital
expenditures of $1.4 billion. Financing activities in 2007
primarily consisted of refinancing debt and funding capital
investment with borrowings under credit facilities.
Outlook
Over the next few years, we expect to make significant
investments in our electric and gas infrastructure to improve
the reliability of our distribution systems and to comply with
environmental regulations. These investments are consistent
with our customers’ and regulators’ expectations. We expect
that earnings growth in our rate-regulated businesses will
come from updating existing customer rates to better reflect
these investments and the current levels of costs UE and the
Ameren Illinois Utilities are experiencing. However, in the
near-term, the returns experienced in 2007 and expected to
be experienced in 2008 by UE and the Ameren Illinois
Utilities are below levels allowed by the respective state
utility commissions in their last rate cases. That is due to
the fact that UE’s and the Ameren Illinois Utilities’ current
rates are significantly below the cost and investment levels
they are incurring in their businesses today. In a rising cost
environment, earnings will be negatively impacted due to
regulatory lag until appropriate levels of rate relief are
granted. Our plan to address this shortfall and to achieve
earnings growth is very straightforward: UE and the Ameren
Illinois Utilities will file more frequent rate cases requesting
moderate rate increases, as well as seek appropriate cost
recovery 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.
While we currently believe that rising costs, including fuel,
depreciation and financing costs will largely offset these
productivity gains, we believe our plants will be well
positioned for earnings growth in the future should energy
and capacity prices improve.
The EPA has issued more stringent emission limits on
all coal-fired power plants. Between 2008 and 2017 Ameren
expects that certain Ameren Companies will be required to
invest between $4 billion and $5 billion to retrofit their power
plants with pollution control equipment. Costs for these
types of projects continue to escalate. These investments
will also result in decreased plant availability during
construction and significantly higher ongoing operating
expenses. Approximately 45% of this investment will be in
Ameren’s regulated UE 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. Ameren believes that currently proposed
legislation can be classified as moderate to extreme
depending upon proposed CO2 emission limits, the timing of
implementation of those limits, and the method of allocating
allowances. We support public policy that will result in
substantial reductions in CO2 emission. However, CO2 policy
must take into account the profound economic implications
of moving toward a carbon constrained economy. We believe
any legislation should include the following principles in
order to limit the negative impact on our customers,
economy and company:
(cid:129)
(cid:129)
Recognition of the significant economic impact of
greenhouse gas policies on consumers and businesses
in regions now dependent on coal.
Compliance timelines consistent with development of
advanced technologies.
29
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
Provisions for significant research funding.
Provisions for an effective cap and trade program.
Allowances for greenhouse gas offsets, such as
reforestation.
Removal of potential regulatory and financial barriers to
improvement in existing infrastructure.
Broad-based CO2 regulation across all industries.
A national and global policy approach.
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. The costs to comply with future legislation
or regulations could be so expensive that Ameren and other
similarly situated electric power generators may be forced to
close some coal-fired facilities. 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.
The Ameren Companies will 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. Expenditures not funded with
operating cash flows are expected to be funded primarily
with debt.
General
Ameren, headquartered in St. Louis, Missouri, is a
public utility holding company. 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 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.
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
UE operates a rate-regulated electric generation,
transmission and distribution business, and a rate-
regulated natural gas transmission and distribution
business in Missouri. Before May 2, 2005, UE also
operated those businesses in Illinois.
CIPS operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois.
Genco operates a non-rate-regulated electric generation
business.
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.
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 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 not
currently have a fuel and purchased power cost recovery
mechanism in Missouri for our electric utility business. 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. See Note 2 – Rate and Regulatory
Matters to our financial statements under Part II, Item 8, for
a discussion of pending and recently decided rate cases and
the Illinois electric settlement agreement. Fluctuations in
interest rates 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 $618 million ($2.98 per
share) for 2007, $547 million ($2.66 per share) for 2006,
and $606 million ($3.02 per share) for 2005. In 2005,
Ameren’s net income included a net cumulative effect
aftertax loss of $22 million (11 cents per share) associated
with recording liabilities for conditional AROs as a result of
our adoption of FIN 47, “Accounting for Conditional Asset
Retirement Obligations.” The net cumulative effect aftertax
30
loss of adopting FIN 47 is presented below for the applicable
registrant companies:
(cid:129)
reduced gains on the sale of noncore properties,
including leveraged leases (15 cents per share).
The cents per share information presented above is
based on average shares outstanding in 2006.
Ameren’s net income before cumulative effect of the
adoption of FIN 47 decreased $81 million and earnings per
share decreased 47 cents in 2006 compared with 2005.
Compared with 2005 earnings, 2006 earnings were
negatively affected by:
(cid:129)
costs and lost electric margins associated with outages
caused by severe storms (26 cents per share);
(cid:129) milder weather conditions (estimated at 17 cents per
share);
costs associated with the reservoir breach at UE’s Taum
Sauk plant (20 cents per share);
an unscheduled outage at UE’s Callaway nuclear plant
(7 cents per share);
higher depreciation expense (11 cents per share);
increased taxes other than income taxes (8 cents per
share);
contributions made in association with the Illinois
Customer Elect electric rate increase phase-in plan
(5 cents per share);
increased fuel and purchased power costs; and
higher financing costs.
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
An increase in the number of common shares
outstanding also reduced Ameren’s earnings per share in
2006 compared with 2005.
Compared with 2005, earnings in 2006 were favorably
affected by:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
higher margins on interchange sales (33 cents per
share);
increased net gains on the sale of noncore properties,
including leveraged leases, compared with 2005 (9 cents
per share);
the lack of a refueling and maintenance outage at UE’s
Callaway nuclear plant in 2006 (18 cents per share);
increased sales of emission allowances (5 cents per
share); and
other factors including improved plant operations, lack
of coal conservation efforts, industrial electric
customers switching back to the Ameren Illinois
Utilities, lower bad debt expenses, and organic growth.
The cents per share information presented above is
based on average shares outstanding in 2005.
2005 Net Cumulative
Effect Aftertax Loss
Ameren(a). . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . .
$22
16
2
2
(a) Includes amounts for EEI.
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:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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;
favorable weather conditions (estimated at 14 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);
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); and
decreased costs associated with outages caused by
severe storms (17 cents per share).
Compared with 2006 earnings, 2007 earnings were
negatively affected by:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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) described in Note 2 –
Rate and Regulatory Matters to our financial statements
under Part II, Item 8, of this report;
the combined effect of the elimination of the Ameren
Illinois Utilities’ bundled 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);
higher labor and employee benefit costs (18 cents per
share);
increased depreciation and amortization expense
(13 cents per share);
higher financing costs (17 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);
increases in distribution system reliability expenditures
(15 cents per share);
higher bad debt expenses (8 cents per share);
lower emission allowance sales (16 cents per share); and
31
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, 2007, 2006 and 2005:
Net income:
UE(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
336
14
125
47
24
72
618
$
$
343
35
49
19
55
46
547
$
$
346
41
97
3
95
24
606
2007
2006
2005
(a) Includes earnings from a non-rate-regulated 40% interest in EEI.
(b) Includes net income from non-rate-regulated operations and a 40% interest in EEI held by Development Company, corporate general and
administrative expenses, gains on sales of noncore assets, and intercompany eliminations.
Below is a table of income statement components by segment for the years ended December 31, 2007, 2006 and 2005:
2007
Missouri
Regulated
Illinois
Regulated
Non-rate-
regulated
Generation
Other /
Intersegment
Eliminations
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 . . . . . . . . . . . . . . . . . . .
$ 1,984
70
2
(900)
(333)
(234)
35
(194)
(143)
(6)
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
281
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 . . . . . . . . . . . . . . . . . . .
$ 1,898
60
2
(800)
(335)
(230)
33
(171)
(184)
(6)
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
267
2005
Electric margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . .
Cumulative effect of change in accounting principle . . . . . . . . . . . .
$ 1,889
73
2
(785)
(310)
(229)
17
(116)
(206)
(6)
-
$
$
$
$
$
760
317
3
(550)
(217)
(121)
19
(132)
(25)
(7)
47
824
307
2
(535)
(192)
(137)
13
(95)
(65)
(7)
115
829
315
3
(490)
(190)
(119)
12
(86)
(101)
(7)
-
$ 1,034
-
-
(313)
(105)
(25)
6
(107)
(182)
(27)
$
$
$
$
281
756
-
1
(283)
(106)
(24)
2
(103)
(78)
(27)
138
703
-
2
(255)
(106)
(17)
(1)
(119)
(86)
(3)
(23)
$
$
$
$
$
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
329
$
166
$
95
$
(65)
(8)
(5)
75
(26)
(1)
7
10
20
2
9
(61)
(3)
(5)
62
(28)
-
(2)
19
43
2
27
(45)
-
(3)
43
(26)
-
(11)
20
37
-
1
16
Total
$ 3,713
379
-
(1,688)
(681)
(381)
67
(423)
(330)
(38)
$
618
$ 3,417
364
-
(1,556)
(661)
(391)
46
(350)
(284)
(38)
$
547
$ 3,376
388
4
(1,487)
(632)
(365)
17
(301)
(356)
(16)
(22)
$
606
32
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, 2007, 2006, and 2005. 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.
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 resettlements – March
2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market losses on energy contracts . . .
Illinois rate redesign, generation repricing,
growth and other (estimate) . . . . . . . . . . .
Total electric revenue change . . . . . . . . . . . . . .
$
Fuel and purchased power change:
Fuel:
Generation and other . . . . . . . . . . . . . . . .
Emission allowance 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 . . . . . . . . . . . . . . . . . . . . . . .
Insurance recovery . . . . . . . . . . . . . . . . . . .
FERC-ordered MISO resettlements – March
2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
Storm-related energy costs (estimate) . . . . . . .
Total fuel and purchased power change . . . . . . .
Net change in electric margins . . . . . . . . . . . . .
Net change in gas margins . . . . . . . . . . . . . . .
$
$
$
73
29
10
-
108
252
(73)
17
(21)
287
682
(35)
(38)
23
(98)
-
(90)
(12)
(108)
8
(35)
(1)
(386)
296
15
2006 versus 2005
Ameren(a)
Electric revenue change:
$
Effect of weather on native load (estimate) . . . .
Storm-related outages (estimate) . . . . . . . . . .
Noranda . . . . . . . . . . . . . . . . . . . . . . . . . .
UE Illinois service territory transfer to CIPS . . .
Wholesale contracts . . . . . . . . . . . . . . . . . .
Interchange revenues(b) . . . . . . . . . . . . . . . .
Transmission service and other revenues . . . . .
Growth and other (estimate) . . . . . . . . . . . . .
Total electric revenue change . . . . . . . . . . . . . .
$
(82)
(10)
46
-
(76)
236
(32)
72
154
-
252
-
-
(13)
11
123
(10)
(29)
9
(84)
97
(25)
(12)
-
20
(11)
(2)
(47)
76
10
UE
(39)
(9)
46
(38)
-
(26)
(4)
27
(43)
33
$
$
$
$
$
$
$
$
$
31
29
9
(196)
$
$
$
16
-
3
-
-
-
$
-
-
(3)
(97)
-
-
9
-
-
-
108
-
9
-
-
-
108
-
17
-
1
-
-
-
(11)
(30)
(20)
(20)
(14)
-
-
36
44
12
-
(2)
$
(120)
$
4
-
160
261
$
$
4
-
160
261
21
11
1
(5)
-
(119)
$
22
14
1
(5)
-
(120)
(48)
-
6
(5)
196
101
-
-
2
-
1
-
3
-
34
(76)
(46)
2
40
(43)
-
-
(108)
7
(4)
-
(193)
68
5
$
$
$
(108)
7
(4)
-
(196)
65
5
253
133
-
$
$
$
Genco
CILCORP
CILCO
$
$
(10)
-
-
-
-
8
2
12
(10)
-
-
-
-
8
2
12
$
$
$
$
$
$
$
-
-
-
-
-
(48)
-
-
-
(8)
-
(56)
(12)
2
CIPS
(16)
(3)
-
41
-
(34)
3
27
$
$
$
$
$
$
$
$
$
$
-
-
(49)
(45)
-
-
-
-
-
35
-
-
-
(12)
1
24
(21)
1
(17)
(1)
-
-
-
-
(12)
67
37
IP
$
18
$
$
12
$
12
$
2006 versus 2005
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
Fuel and purchased power change:
Fuel:
Generation and other . . . . . . . . . . . . . . . .
Emission allowances sales (costs) . . . . . . .
Price . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power . . . . . . . . . . . . . . . . . . . .
Storm-related energy costs (estimate) . . . . . . .
Total fuel and purchased power change . . . . . . .
Net change in electric margins . . . . . . . . . . . . .
Net change in gas margins . . . . . . . . . . . . . . .
$
$
$
$
(29)
28
(82)
(31)
1
(113)
41
(24)
$
$
$
$
3
30
(40)
69
2
64
21
(13)
$
$
$
$
-
-
-
(15)
-
(15)
3
1
$
$
$
$
(10)
(21)
(18)
(10)
(1)
(60)
(103)
-
$
$
$
$
(3)
9
(20)
29
-
15
27
(10)
$
$
$
$
-
8
(20)
29
-
17
29
(10)
$
$
$
$
-
-
-
(51)
(1)
(52)
(15)
1
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The effect of storm-related outages increasing interchange revenues is included in the storm-related outages (estimate) line.
2007 versus 2006
Ameren
Ameren’s electric margin increased by $296 million, or
9%, in 2007 compared with 2006. Factors contributing to an
increase in Ameren’s electric margin were as follows:
(cid:129)
(cid:129)
(cid:129)
(cid:129) 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, increased electric
margin by $35 million.
UE’s 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, 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
utilization of higher priced energy sources, increased
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 to those that occurred in 2006, which
negatively impacted 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 13 – Commitments and Contingencies to our
(cid:129)
(cid:129)
(cid:129)
(cid:129)
financial statements under Part II, Item 8, of this report,
for more information.
Factors contributing to a decrease in electric margin for
2007 as compared with 2006 were as follows:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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.
Purchased power costs that were $18 million higher for
the year 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.
Ameren’s gas margin increased by $15 million, or 4%,
in 2007. The primary causes of the increase were favorable
weather conditions, as evidenced by an 8% increase in
heating degree-days, which increased gas margin by an
estimated $10 million, and 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:
(cid:129)
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
34
excess power, 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.
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, which
increased electric margin by $27 million.
Favorable weather conditions, as evidenced by a 19%
increase in cooling degree-days, which increased
electric margin by $22 million.
Replacement power insurance recoveries of $20 million,
including $8 million associated with Taum Sauk. See
Note 13 – Commitments and Contingencies to our
financial statements under Part II, Item 8, of this report,
for more information.
Increased transmission service revenues of $18 million
due to the ancillary service agreement with CIPS,
CILCO, and IP. See Note 12 – Related Party Transactions
to our financial statements under Part II, Item 8, of this
report, for more 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 impacted electric
sales that year and resulted in a net reduction in overall
electric margin of $7 million in 2006.
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
Items that had an unfavorable impact on electric margin
in 2007 as compared with 2006 were as follows:
A 21% increase in fuel prices.
(cid:129)
Decreased emission allowance sales of $29 million.
(cid:129)
(cid:129) MISO purchased power costs that were $11 million
(cid:129)
(cid:129)
higher due to the March 2007 FERC order.
Other MISO purchased power costs, excluding the effect
of the March 2007 FERC order, 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 margins:
(cid:129)
(cid:129)
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 $2 million.
Illinois Regulated
Illinois Regulated’s electric margin decreased by
$64 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:
(cid:129)
(cid:129)
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.
(cid:129) MISO purchased power costs that increased $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:
(cid:129)
(cid:129)
(cid:129)
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 native
load electric margin by $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 . . . . . . . .
$(31)
96
$ 65
2007 versus 2006
(cid:129)
The UE gas rate increase effective in April 2007, which
increased gas margin by $4 million.
CILCO’s (Illinois Regulated) electric margin decreased
by $31 million, or 20%, in 2007 compared with 2006. The
35
following items had an unfavorable impact on electric
margin:
(cid:129)
(cid:129)
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.
(cid:129) MISO purchased power costs that increased $4 million,
because of the March 2007 FERC order.
The following items had a favorable impact on electric
margin in 2007 compared with 2006:
(cid:129)
(cid:129)
Other MISO purchased power costs, excluding the effect
of the March 2007 FERC order, 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 native
load electric margin by $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:
(cid:129)
(cid:129)
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.
(cid:129) MISO purchased power costs that increased $12 million,
because of the March 2007 FERC order.
The following items had a favorable impact on electric
margin in 2007 compared with 2006:
(cid:129)
(cid:129)
(cid:129)
Other MISO purchased power costs, excluding the effect
of the March 2007 FERC order, 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 native
load electric margin by $5 million.
Reduced severe storm-related outages in 2007
compared to those that occurred in 2006, which
negatively impacted 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 $278 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.
Genco
Genco’s electric margin increased by $133 million, or
36%, in 2007 compared with 2006. The following items had
a favorable impact on electric margin:
(cid:129)
(cid:129)
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.
(cid:129) MISO – related revenues that were $12 million higher as
(cid:129)
a result of the March 2007 FERC order.
(cid:129) MISO purchased power costs that were $16 million
(cid:129)
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:
(cid:129)
(cid:129)
(cid:129)
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.
A 4% increase in fuel prices.
CILCO (AERG)
AERG’s electric margin increased by $96 million, or
87%, in 2007 compared with 2006. The following items had
a favorable impact on electric margin:
(cid:129)
(cid:129)
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.
Reduced emission allowance costs of $11 million as
more low-sulfur coal was burned in 2007.
(cid:129) MISO-related revenues that were $4 million higher as a
result of the March 2007 FERC order.
(cid:129) MISO purchased power costs that were $7 million
(cid:129)
lower.
Replacement power insurance recoveries of $7 million
due to plant maintenance.
36
The following items had an unfavorable impact on
electric margin in 2007 compared with 2006:
(cid:129)
(cid:129)
(cid:129)
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.
A 5% increase in fuel prices.
EEI
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:
(cid:129)
(cid:129)
(cid:129)
The lack of emissions allowance sales in 2007, which
increased 2006 electric margin by $30 million.
A 5% increase in fuel prices.
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.
2006 versus 2005
Ameren
Ameren’s electric margin increased by $41 million, or
1%, in 2006 compared with 2005. Factors contributing to an
increase in Ameren’s electric margin were as follows:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
A $162 million, or 67%, increase in margin on
interchange sales. The expiration of EEI’s affiliate cost-
based power supply contract on December 31, 2005,
the expiration of several large Marketing Company
power supply contracts in 2006, and an increase in
plant availability provided Ameren with additional power
to sell in the spot market. The increase in margin on
interchange sales from these items was reduced by
lower power prices, resulting from declining market
prices for natural gas, and the significant impact of
hurricanes and coal delivery disruptions on prices in
2005.
Plant efficiencies, primarily at CILCO (AERG), as
Ameren’s baseload electric generating plants’ average
capacity and equivalent availability factors were
approximately 80% and 88%, respectively, in 2006
compared with 76% and 86%, respectively, in 2005.
The lack of a UE Callaway nuclear plant refueling and
maintenance outage in 2006, which resulted in an
increased electric margin of $25 million.
Capacity upgrades performed during the refueling and
maintenance outage in 2005, which increased Callaway’s
output and electric margin by $22 million.
Organic growth and the movement of industrial
customers back to below-market Illinois tariff rates
(cid:129)
(cid:129)
(cid:129)
because of the expiration of power contracts with
suppliers.
Lower purchased power costs at IP.
Sales to Noranda, which began receiving power on
June 1, 2005, resulting in increased electric margin of
$20 million at UE.
Increased sales of emission allowances, totaling
$17 million, and lower emission allowance costs,
totaling $11 million, in 2006 compared with 2005.
Factors contributing to a decrease in Ameren’s electric
margin were as follows:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
Unfavorable weather conditions, as evidenced by a 9%
decline in cooling degree-days, which reduced the native
load electric margin by $33 million in 2006 compared
with 2005.
Severe storm-related outages in 2006, which reduced
overall electric margin by $9 million as less electricity
was sold for native load. This was partially offset by an
increase in margin on the sales of this power on the
interchange market.
An increase in fuel and purchased power costs for
native load at UE and Genco due to the expiration of a
cost-based power supply contract with EEI.
A 12% increase in coal and transportation prices.
A $25 million reduction in margin because of the
unavailability of UE’s Taum Sauk hydroelectric plant in
2006 compared with 2005.
An $11 million reduction in native load margin from
UE’s other hydroelectric generation in 2006 compared
with 2005.
An unscheduled outage in 2006 at UE’s Callaway nuclear
plant, which reduced electric margin by an estimated
$20 million.
Reduced transmission service revenues, primarily due
to the elimination of interim cost recovery mechanisms
and reduced revenues associated with the MISO Day
Two Energy Market.
Ameren’s gas margin decreased by $24 million, or 6%,
in 2006 compared with 2005, primarily because of the
following factors:
(cid:129)
(cid:129)
Unfavorable weather conditions, as evidenced by a 9%
decrease in heating degree-days, which reduced the gas
margin by $15 million in 2006 from 2005. Weather-
sensitive residential and commercial gas sales volumes
decreased by 8% each, in 2006 compared with 2005.
Unrecoverable purchased gas costs, together with
unfavorable customer sales mix, totaling $19 million.
Factors contributing to an increase in Ameren’s gas
margin were as follows:
(cid:129)
(cid:129)
An IP rate increase effective in May 2005, which added
revenues of $6 million in 2006.
Increased sales to customers, excluding the impact
from weather, of 2%, or $4 million.
37
Missouri Regulated
UE
UE’s total electric margin increased by $21 million in
2006 compared with 2005. UE’s Missouri Regulated electric
margin increased by $9 million in 2006 compared with 2005.
The following items had a favorable impact on UE’s electric
margin:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
Sales to Noranda that increased electric margin by
$20 million and other organic growth.
Increased sales of emission allowances, totaling
$30 million.
The lack of a scheduled Callaway nuclear plant refueling
and maintenance outage in 2006.
Capacity upgrades at the Callaway plant performed
during the refueling and maintenance outage in 2005.
UE’s other electric margin increased by $12 million as a
result of the adoption of Staff Accounting Bulletin 108. See
Note 1 – Summary of Significant Accounting Policies,
Accounting Changes and Other Matters, to our financial
statements under Part II, Item 8, of this report, for further
information.
electric margin (maintenance expenses were covered
under warranty).
(cid:129) MISO Day Two Energy Market costs, which were
(cid:129)
(cid:129)
$6 million higher in 2006, as this market did not begin
operating until the second quarter of 2005.
The expiration of a cost-based power supply contract
with EEI on December 31, 2005.
Reduced transmission service revenues of $13 million,
primarily due to elimination of interim cost recovery
mechanisms and reduced revenues associated with the
MISO Day Two Energy Market.
UE’s gas margin decreased by $13 million, or 18%, in
2006 compared with 2005. The following items had an
unfavorable impact on UE’s gas margin:
(cid:129)
(cid:129) Mild winter weather conditions that reduced gas margin
by $2 million, as evidenced by an 8% decrease in
heating degree-days in 2006 compared with 2005.
The transfer of UE’s Illinois service territory in May
2005 to CIPS, which reduced gas margin by $4 million.
A reduction in gas sales to customers, excluding the
impacts from weather.
Unrecoverable purchased gas costs totaling $4 million.
(cid:129)
(cid:129)
Items that had an unfavorable impact on electric margin
Illinois Regulated
in 2006 as compared to 2005 were as follows:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
Unfavorable weather conditions, which reduced native
load electric margin by $11 million, as evidenced by an
8% decline in cooling degree-days in 2006 compared
with 2005.
Severe storm-related outages in 2006, which reduced
electric native load sales and resulted in an estimated
net reduction in electric margin of $7 million.
Lower margin on nonaffiliated interchange sales in 2006
compared with 2005, which resulted from reduced
power prices. The average realized power prices on UE’s
interchange sales decreased from $48 per megawatt
hour in 2005 to $37 per megawatt hour in 2006.
However, the margin on interchange sales benefited
from the January 10, 2006, amendment of the JDA. The
MoPSC-required and FERC-approved change in the JDA
methodology (to basing the allocation of third-party
short-term power sales of excess generation on
generation output instead of load requirements) resulted
in $23 million in incremental margin on interchange
sales for UE in 2006 compared with 2005.
The transfer of UE’s Illinois service territory in May
2005 to CIPS, which decreased electric margin by an
estimated $22 million in 2006 compared with 2005.
A 9% increase in coal and related transportation prices.
Fees of $4 million levied by FERC in 2006 for prior
years’ generation benefits provided to UE’s Osage
hydroelectric plant.
The unavailability of UE’s Taum Sauk hydroelectric plant.
UE’s other hydroelectric generation was lower due to
drought-like conditions across the central and southern
portions of Missouri.
An unscheduled 20-day outage at UE’s Callaway nuclear
plant in the second quarter of 2006, which reduced
Illinois Regulated’s electric margin decreased by
$5 million, or 1%, and its gas margin decreased by
$8 million, or 3%, in 2006 compared with 2005. See below
for explanations of electric and gas margin variances for the
Illinois Regulated segment.
CIPS
CIPS’ electric margin increased by $3 million, or 1%, in
2006 compared with 2005. The following items had a
favorable impact on electric margin:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
The transfer to CIPS of UE’s Illinois service territory in
May 2005, which increased electric margin by $7 million.
Customers, (primarily industrial), who switched back to
CIPS from Marketing Company in 2006 because tariff
rates were below market rates for power.
A decrease in MISO Day Two Energy Market costs of
$7 million.
Increased miscellaneous revenues of $2 million.
The following items had an unfavorable impact on
electric margin in 2006 as compared to 2005:
(cid:129)
(cid:129)
(cid:129)
Unfavorable weather conditions, as evidenced by a 9%
decrease in cooling degree-days in 2006 compared with
2005, which reduced native load electric margin by
$7 million.
Severe storm-related outages in 2006, which reduced
electric sales and reduced the electric margin by
$3 million.
Reduced transmission service revenues, primarily due
to elimination of interim cost recovery mechanisms, and
reduced revenues associated with the MISO Day Two
Energy Market.
38
Due to the expiration of CIPS’ cost-based power supply
agreement with EEI in December 2005, pursuant to which
CIPS sold its entitlements under the agreement to Marketing
Company, both interchange revenues and purchased power
expenses decreased by $34 million in 2006 compared with
2005.
CIPS’ gas margin increased by $1 million, or 1%, in
2006, compared with 2005, primarily because the transfer to
CIPS of UE’s Illinois service territory in May 2005 added
$4 million to gas margin. CIPS’ increase in gas margin was
reduced by mild winter weather, as evidenced by a 10%
decrease in heating degree-days in 2006 compared with
2005, which reduced gas margin by $3 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 2006 compared with 2005:
CILCO (Illinois Regulated) . . . . . . . . . . .
CILCO (AERG)(a)
. . . . . . . . . . . . . . . . .
Total change in electric margin . . . . . . . .
$ 7
22
$29
2006 versus 2005
(a) See Non-rate-regulated Generation under Results of Operations
for a detailed explanation of CILCO’s (AERG) change in electric
margin in 2006 compared with 2005.
CILCO’s Illinois Regulated electric margin increased by
$7 million, or 5%, in 2006 compared with 2005. The
following items had a favorable impact on electric margin:
(cid:129)
(cid:129)
(cid:129)
Increased native load growth, primarily in the industrial
sector.
Increased miscellaneous revenues totaling $2 million.
A decrease in MISO Day Two Energy Market costs
totaling $2 million.
The following items had an unfavorable impact on
electric margin in 2006 as compared to 2005:
(cid:129)
(cid:129)
Unfavorable weather conditions, as evidenced by an
18% decrease in cooling degree-days in 2006, which
reduced native load electric margin by $7 million.
Reduced transmission service revenues, primarily due
to elimination of interim cost recovery mechanisms and
reduced revenues associated with the MISO Day Two
Energy Market.
CILCO’s (Illinois Regulated) gas margin decreased by
$10 million, or 10%, in 2006 compared with 2005. The
following items had an unfavorable impact on gas margin:
(cid:129) Mild winter weather conditions in CILCO’s service
territory, as evidenced by a 7% decrease in heating
degree-days in 2006, which reduced gas margin by
$3 million.
Lower transportation volumes, together with unfavorable
customer sales mix.
(cid:129)
IP
IP’s electric margin decreased by $15 million, or 4%, in
2006 compared with 2005. The following items had an
unfavorable impact on electric margin:
(cid:129)
(cid:129)
(cid:129)
Unfavorable weather conditions, as evidenced by a 10%
decrease in cooling degree-days in 2006, which reduced
native load electric margin by $9 million.
Severe storm-related outages in 2006, which resulted in
reduced electric sales, decreasing electric margin by
$2 million.
Reduced transmission service revenues of $17 million,
primarily due to the elimination of interim cost recovery
mechanisms and reduced revenues associated with the
MISO Day Two Energy Market.
The following items had a favorable impact on electric
margin in 2006 compared with 2005:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
A net increase in electric margin as a result of
customers, (primarily industrial), who switched back to
IP because tariff rates were below market rates for
power. The increase in revenues more than offset an
increase in purchased power costs.
Lower transmission expenses included in purchased
power costs due, in part, to a $6 million favorable
settlement of disputed ancillary charges with MISO.
Lower MISO Day Two Energy Market costs totaling
$4 million.
Increased rental and miscellaneous revenues totaling
$5 million.
IP’s gas margin increased by $1 million, or 1%, in 2006
compared with 2005. Factors contributing to an increase in
IP’s gas margin were as follows:
(cid:129)
(cid:129)
A rate increase effective in May 2005 that added
revenues of $6 million in 2006.
Organic growth, primarily in the industrial sector.
The increase in gas margin was reduced by mild winter
weather conditions, as evidenced by a 9% decrease in
heating degree-days in 2006 compared with 2005, which
reduced gas margin by $7 million.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin
increased by $53 million, or 8%, in 2006 compared with
2005. See below for explanations of electric margin
variances for the Non-rate-regulated Generation segment.
Genco
Genco’s electric margin decreased by $103 million, or 22%,
in 2006 compared with 2005. The following items had an
unfavorable impact on electric margin:
(cid:129)
A lower wholesale sales margin, as Genco purchased
additional power at higher costs to supply Marketing
Company after the expiration of the cost-based power
supply contract between EEI and its affiliates on
December 31, 2005.
39
(cid:129)
(cid:129)
(cid:129)
(cid:129)
Lower emission allowance sales, because of a
$21 million gain at Genco in the third quarter of 2005,
which resulted from the nonmonetary swap of certain
earlier vintage-year SO2 emission allowances for later
vintage-year allowances.
A 9% increase in coal and transportation prices.
A lower margin on interchange sales in 2006 compared
with 2005, primarily because of lower power prices, and
a $23 million reduction in 2006 due to the January
2006 amendment of the JDA among UE, Genco and
CIPS discussed above. The average realized power
prices on Genco’s interchange sales decreased from
$47 per megawatthour in 2005 to $38 per
megawatthour in 2006.
Higher MISO Day Two Energy Market costs, totaling
$12 million in 2006 compared with 2005. The market
did not begin operating until the second quarter of
2005.
Genco’s decrease in electric margin was reduced by
increased sales to CIPS as a result of the May 2005 transfer
of UE’s Illinois service territory to CIPS.
CILCO (AERG)
AERG’s electric margin increased by $22 million, or
25%, in 2006 compared with 2005. The following items had
a favorable impact on electric margin:
(cid:129)
(cid:129)
(cid:129)
Lower purchased power costs due to improved power
plant availability.
A decrease in emission allowance utilization expenses of
$8 million in 2006.
An increase in margin on interchange sales due to
improved plant availability. AERG’s electric generating
plants’ average capacity and equivalent availability
factors were approximately 69% and 81%, respectively,
in 2006 compared with 61% and 73%, respectively, in
2005.
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 as compared to 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
AERG’s electric margin was reduced by a 31% increase
in coal and transportation prices in 2006 over 2005.
UE
EEI
EEI’s electric margin increased by $194 million in 2006
compared with 2005. The following items had a favorable
impact on electric margin:
(cid:129)
(cid:129)
An increase in margin on interchange sales, which
resulted from the expiration of an affiliate cost-based
power supply agreement on December 31, 2005, and its
replacement with an affiliate market-based power supply
agreement.
Sales of emission allowances.
Other Operations and Maintenance Expenses
2007 versus 2006
Ameren
Ameren’s other operations and maintenance expenses
increased $132 million in 2007 compared with 2006.
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 as
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.
40
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.
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 that occurred 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.
2006 versus 2005
Ameren
Ameren’s other operations and maintenance expenses
increased $69 million in 2006 compared with 2005. We
experienced the most damaging storms in the Ameren
utilities’ history in our service territory during the summer of
2006, resulting in the loss of power to about 950,000
electric customers and expenses of $28 million. Severe ice
storms in the fourth quarter of 2006 resulted in the loss of
power to about 520,000 electric customers and expenses of
$42 million. Additionally, other operations and maintenance
expenses increased because of $25 million in costs related
to the December 2005 reservoir breach at UE’s Taum Sauk
plant and $15 million of contributions to assist residential
customers in association with the Illinois Customer Elect
electric rate increase phase-in plan accepted by the ICC in
December 2006. In addition, there were higher maintenance
expenses at our coal-fired power plants due to the timing of
maintenance outages, and an increase in legal fees for
environmental issues and general litigation. The effect on
other operations and maintenance expenses from
transactions related to noncore properties, including the
impairment of a Delta Air Lines, Inc. lease in 2005, was
comparable between years.
Reducing the unfavorable impact of the above items
were lower labor costs and a decrease in bad debt expense
of $17 million in 2006. An anticipated increase in
uncollectible accounts due to higher natural gas prices was
mitigated by mild winter weather. In 2005, a Callaway
nuclear plant refueling and maintenance outage resulted in
other operations and maintenance expenses of $31 million;
there was no refueling and maintenance outage in 2006.
Variations in other operations and maintenance
expenses for the Ameren, CILCORP and CILCO business
segments and for the Ameren Companies between 2006 and
2005 are discussed below.
Missouri Regulated
UE
Other operations and maintenance expenses increased
in 2006 over 2005, primarily because of storm repair
41
expenditures of $38 million, incremental costs associated
with the Taum Sauk plant incident of $25 million, as noted
above, and higher maintenance expenses at UE’s coal-fired
power plants. Reducing the impact of these unfavorable
items were decreased injury and damage expenses,
decreased bad debt expenses, lower labor and employee
benefit costs, and the lack of a scheduled Callaway refueling
and maintenance outage in 2006, which resulted in other
operations and maintenance expenses of $31 million in
2005. Additionally, other operations and maintenance
expenses decreased $7 million in 2006 as a result of the
transfer of UE’s Illinois service territory to CIPS in May
2005.
Genco
Other operations and maintenance expenses increased
$13 million in 2006 over 2005, primarily because of higher
maintenance expenses resulting from more scheduled power
plant maintenance outages in 2006.
CILCO (AERG)
Other operations and maintenance expenses were
comparable between 2006 and 2005, as decreased
maintenance costs were offset by increased legal and
environmental expenses.
Illinois Regulated
Other operations and maintenance expenses increased
$45 million in 2006 compared with 2005 in the Illinois
Regulated segment, as detailed below.
CILCORP (Parent Company only) & EEI
Other operations and maintenance expenses increased
$8 million at CILCORP (Parent Company only) and $3 million
at EEI in 2006 over 2005, primarily because of increased
employee benefit costs.
CIPS
Other operations and maintenance expenses increased
$13 million in 2006 over 2005, primarily because of storm
repair expenditures of $6 million and the transfer of UE’s
Illinois service territory to CIPS in May 2005, which resulted
in additional other operations and maintenance expenses of
$7 million. Additionally, other operations and maintenance
expenses increased because of contributions of $4 million
associated with the Illinois Customer Elect electric rate
increase phase-in plan in 2006. The negative impact of these
items was reduced by lower bad debt expense.
CILCO (Illinois Regulated)
Other operations and maintenance expenses decreased
$4 million in 2006 from 2005, primarily because of lower
employee benefit costs and reduced bad debt expenses.
Reducing the benefit of these items were $3 million of
contributions associated with the Illinois Customer Elect
electric rate increase phase-in plan and $5 million of storm
repair and tree trimming expenditures in 2006.
IP
Other operations and maintenance expenses increased
$46 million in 2006 over 2005, primarily because of storm
repair expenditures of $24 million and contributions
associated with the Illinois Customer Elect electric rate
increase phase-in plan of $8 million in 2006, along with
higher rental expenses, and higher injury and damage
expenses. The negative effect of these items was reduced by
lower labor costs and employee benefit costs.
Depreciation and Amortization
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 expenses as a result of
a MoPSC electric rate order somewhat mitigated that effect.
The MoPSC order extended the lives of UE’s Callaway
nuclear plant and coal-fired generation plant for purposes of
calculating depreciation expense, beginning in June 2007.
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 noted above.
Illinois Regulated
Depreciation and amortization expenses increased
$25 million in the Illinois Regulated segment in 2007
compared with 2006.
Non-rate-regulated Generation
Other operations and maintenance expenses increased
$28 million in 2006 compared with 2005 in the Non-rate-
regulated Generation segment, as detailed below.
CIPS & CILCO (Illinois Regulated)
Depreciation and amortization expenses were
comparable between 2007 and 2006.
42
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.
2006 versus 2005
Ameren
Ameren’s depreciation and amortization expenses
increased $29 million in 2006 over 2005, primarily because
of capital additions.
Variations in depreciation and amortization expenses for
the Ameren, CILCORP and CILCO business segments and for
the Ameren Companies between 2006 and 2005 were as
follows.
Missouri Regulated
UE
Depreciation and amortization expenses increased
$25 million in 2006 over 2005. The increases were primarily
because of capital additions, which included new steam
generators and turbine rotors installed during the refueling
and maintenance outage at the Callaway nuclear plant in
2005, as well as CTs purchased in the first quarter of 2006.
Additionally, depreciation increased because CTs were
transferred to UE from Genco in May 2005. Reducing
depreciation expense was the property transfer to CIPS as
part of the Illinois service territory transfer in May 2005.
Illinois Regulated
Depreciation and amortization expenses were
comparable in the Illinois Regulated segment, CILCO (Illinois
Regulated), and IP in 2006 and 2005. Depreciation and
amortization expenses increased $3 million at CIPS primarily
because of property transferred from UE to CIPS as part of
the Illinois service territory transfer in May 2005.
Taxes Other Than Income Taxes
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.
Illinois Regulated
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.
2006 versus 2005
Ameren
Ameren’s taxes other than income taxes increased
$26 million in 2006 over 2005, primarily as a result of
higher gross receipts, and higher excise taxes and property
taxes.
Variations in taxes other than income taxes for the
Ameren, CILCORP and CILCO business segments and for the
Ameren Companies between 2006 and 2005 were as follows.
Missouri Regulated
UE
Taxes other than income taxes were comparable in
2006 and 2005.
Illinois Regulated
Non-rate-regulated Generation
Depreciation and amortization expenses were
comparable in 2006 and 2005 in the Non-rate-regulated
Generation segment and for CILCORP (Parent Company
only), Genco, CILCO (AERG), and EEI.
In the Illinois Regulated segment, taxes other than
income taxes increased $18 million in 2006 compared with
2005. Taxes other than income taxes increased $8 million at
CIPS, $5 million at CILCO (Illinois Regulated), and $5 million
at IP in 2006 over 2005, primarily as a result of higher
property taxes and excise taxes.
43
Non-rate-regulated Generation
In the Non-rate-regulated Generation segment, taxes
other than income taxes increased $7 million in 2006
compared with 2005, primarily because of higher property
taxes at Genco. A court decision in the first quarter of 2005
favorably affected taxes that year. Taxes other than income
taxes were comparable in 2006 and 2005 at CILCORP
(Parent Company only), CILCO (AERG), and EEI.
Other Income and Expenses
2007 versus 2006
Ameren
Miscellaneous income increased $27 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
with 2006.
Illinois Regulated
Other income and expenses increased $6 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 periods at
CIPS and CILCO (Illinois Regulated).
Non-rate-regulated Generation
Other income and expenses were comparable between
2007 and 2006 for the Non-rate-regulated Generation
segment and for Genco, CILCORP (Parent Company only),
CILCO (AERG), and EEI.
2006 versus 2005
Ameren
Miscellaneous income increased $21 million in 2006
over 2005, primarily because of $24 million of interest
income on a taxable industrial development revenue bond
acquired by UE in conjunction with its purchase of a CT in
the first quarter of 2006. This amount was offset by an
equivalent amount of interest expense on Ameren’s and UE’s
statements of income. Miscellaneous expense decreased
$8 million, primarily because of decreased donations in 2006
and the write-off of unrecoverable natural gas costs in 2005.
Variations in other income and expenses for the
Ameren, CILCORP and CILCO business segments and for the
Ameren Companies between 2006 and 2005 were as follows.
Missouri Regulated
UE
Miscellaneous income increased $16 million in 2006
over 2005, primarily as a result of interest income on a
taxable industrial development revenue bond acquired by UE
in conjunction with its purchase of a CT as noted above.
This favorable impact was partially offset by lower
capitalization of equity funds used during construction in
2006. In 2005, UE replaced steam generators and turbine
rotors at the Callaway nuclear plant. Miscellaneous expense
was comparable in 2006 and 2005.
Illinois Regulated
Other income and expenses were comparable for
Illinois Regulated, CIPS, CILCO (Illinois Regulated), and IP in
2006 and 2005.
Non-rate-regulated Generation
Other income and expenses were comparable for Non-
rate-regulated Generation, Genco, CILCORP (Parent
Company only), CILCO (AERG), and EEI in 2006 and 2005.
Interest
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 in 2007
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 the Ameren, CILCORP
and CILCO 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
44
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.
Non-rate-regulated Generation
Interest expense increased $4 million in the Non-rate-
regulated Generation segment in 2007 compared with 2006.
CILCORP (Parent Company only) & 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. Partially 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.
2006 versus 2005
Ameren
UE’s capital lease associated with one of these CTs. This
amount was offset by an equivalent amount of interest
income on industrial revenue bonds in Ameren’s and UE’s
statements of income.
Illinois Regulated
In the Illinois Regulated segment, interest expense
increased $9 million in 2006 compared with 2005, primarily
because of the issuance of $75 million of senior secured
notes in June 2006 and increased money pool borrowings at
IP. Interest expense at CIPS and CILCO (Illinois Regulated)
was comparable in 2006 and 2005.
Non-rate-regulated Generation
In the Non-rate-regulated Generation segment, interest
expense decreased $16 million in 2006 compared with 2005.
Interest expense decreased $13 million at Genco resulting
from the maturity of $225 million of its senior notes in
2005. Interest expense at CILCORP (Parent Company only),
CILCO (AERG), and EEI was comparable in 2006 and 2005.
Income Taxes
2007 versus 2006
Ameren
Ameren’s effective tax rate increased between 2007 and
2006.
Variations in effective tax rates for the Ameren,
CILCORP and CILCO business segments and for the Ameren
Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
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, which
reduced the net amortization of property-related regulatory
assets and liabilities in 2007 compared to 2006, decreases
in reserves for uncertain tax positions in 2007 compared to
increases in 2006, and increased production activity
deductions in 2007 compared to 2006.
Ameren’s interest expense increased $49 million in
2006 over 2005, primarily because of items noted below for
the Ameren, CILCORP and CILCO business segments and for
each of the Ameren Companies individually.
Illinois Regulated
The effective tax rate decreased in the Illinois Regulated
segment in 2007 compared with 2006, because of the items
detailed below.
Missouri Regulated
UE
Interest expense increased $55 million in 2006 over
2005. UE issued $300 million of senior secured notes in July
2005 and $260 million of senior secured notes in December
2005. It also increased its short-term borrowings, partly in
connection with the purchase of CTs in the first quarter of
2006. Interest expense of $24 million was recognized on
CIPS
The effective tax rate increased, primarily because of
higher reserves for uncertain tax positions in 2007 compared
to 2006, unfavorable 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
45
miscellaneous items, offset by the increased impact of the
amortization of investment tax credit, and other items on
lower pretax book income.
Variations in effective tax rates for the Ameren,
CILCORP and CILCO business segments and for the Ameren
Companies between 2006 and 2005 were as follows.
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 favorable
net amortization of the property-related regulatory assets
and liabilities, and increased impact of the amortization of
investment tax credit on lower pretax book income.
IP
Missouri Regulated
UE
The effective tax rate increased in 2006 over the prior
year, primarily because of an increase in reserves for
uncertain tax positions in 2006 compared to a decrease in
2005, and lower unfavorable net amortization of property-
related regulatory assets and liabilities in 2006 compared to
2005.
The effective tax rate decreased, primarily because of
Illinois Regulated
favorable 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 items detailed below.
Genco
The effective tax rate increased, primarily because of
lower decreases in reserves for uncertain tax positions in
2007 compared to 2006, and decreased production activity
deductions in 2007 compared to 2006.
CILCO (AERG)
The effective tax rate increased in 2007, primarily
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 production activity deductions in
2007 compared to 2006, and differences between the book
and tax treatment of the sales of noncore properties in 2006.
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.
EEI
The effective tax rate decreased, primarily because of
increased production activity deductions.
2006 versus 2005
Ameren
Ameren’s effective tax rate decreased in 2006 from
2005, primarily because of differences between the book and
tax treatment of the sales of noncore properties, as well as
the items discussed below.
The effective tax rate decreased in 2006 from 2005 at
Illinois Regulated, primarily because of the items detailed
below.
CIPS
The effective tax rate decreased from the prior year,
primarily because of favorable net amortization of property-
related regulatory assets and liabilities and larger decreases
in reserves for uncertain tax positions in 2006 compared to
2005, offset by lower permanent benefits for SFAS No. 106-
2, as it relates to Medicare Part D provisions.
CILCO (Illinois Regulated)
The effective tax rate increased in 2006 over 2005,
primarily because of lower permanent benefits related to
company-owned life insurance and SFAS No. 106-2, as it
relates to Medicare Part D provisions.
IP
The effective tax rate was comparable in 2006 and 2005.
Non-rate-regulated Generation
The effective tax rate decreased in 2006 compared with
2005 at Non-rate-regulated Generation, primarily because of
the items detailed below.
Genco
The effective tax rate decreased in 2006 from 2005,
primarily because of the resolution of uncertain tax positions
in 2006 based on favorable developments with taxing
authorities, and increased production activity deductions.
CILCO (AERG)
The effective tax rate decreased in 2006 from 2005,
primarily because of the resolution of uncertain tax positions
in 2006 based on favorable developments with taxing
authorities compared to an increase in reserves for uncertain
tax positions in 2005, as well as the difference between the
book and tax treatment of the sales of noncore properties in
2006.
46
CILCORP (Parent Company only)
EEI
The effective tax rate decreased from the prior year,
primarily because of a change in the permanent benefit of
SFAS No. 106-2, as it relates to Medicare Part D provisions.
LIQUIDITY AND CAPITAL RESOURCES
The effective tax rate was comparable in 2006 and 2005.
The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated)
and IP) continue to be the 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 principally on power sales to Marketing Company, which sold power to
CIPS, CILCO and IP via the September 2006 Illinois power procurement auction and via financial contracts that were part of 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 or commercial paper 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, 2007,
for Ameren, Genco, CILCORP, and CILCO. 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 will 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. Expenditures not funded with operating cash flows are expected to be funded primarily with debt. 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, which among other things, will change the process for power procurement in Illinois and
affect future cash flows of the Ameren Companies, except UE. The settlement resulted in customer refunds and credits during
2007, and it will result in further credits to customers through 2010. The Ameren Illinois Utilities will receive reimbursement for
most of these refunds and credits from Illinois power generators, including Genco and AERG.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended
December 31, 2007, 2006 and 2005:
Net Cash Provided By
Operating Activities
Net Cash Provided By
(Used In) Investing Activities
Net Cash Provided By
(Used In) Financing Activities
Ameren(a) . . . . . . .
UE . . . . . . . . . . .
CIPS . . . . . . . . . .
Genco . . . . . . . . .
CILCORP . . . . . . . .
CILCO . . . . . . . . .
IP . . . . . . . . . . . .
2007
$ 1,102
588
14
255
33
74
28
2006
$ 1,279
734
118
138
133
153
172
2005
$ 1,251
706
133
213
33
67
148
2007
2006
2005
2007
2006
2005
$
(1,468)
(700)
(42)
(210)
(214)
(212)
(180)
$
(1,266)
(732)
(66)
(110)
(90)
(161)
(180)
$
(961)
(800)
(12)
95
(109)
(114)
9
$
584
296
48
(44)
183
141
158
$
28
(21)
(46)
(27)
(42)
9
8
$
(263)
66
(123)
(309)
72
47
(162)
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Cash Flows from Operating Activities
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. 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
complete 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.
47
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 $60 million, and a decrease in
income tax payments (net of refunds) of $86 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 $31 million,
including $74 million of customer refunds, credits, and
program funding, and related reimbursements from
nonaffiliated Illinois generators of $43 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 $44 million, benefiting cash flows
from operations.
Genco’s cash from operating activities increased in
2007 compared with 2006, primarily because electric
margins were up, as discussed in Results of Operations, and
because cash spent for fuel inventory was down. 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
$27 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
$17 million: $41 million of customer refunds, credits, and
program funding, minus related reimbursements from
nonaffiliated Illinois generators of $24 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 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 $16 million
for CILCORP and $15 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 $40 million:
$96 million of customer refunds, credits, and program
funding, minus related reimbursements from nonaffiliated
Illinois generators of $56 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 $15 million, further
reducing cash flows from operations.
2006 versus 2005
Ameren’s cash from operations increased in 2006,
compared with 2005. As discussed in Results of Operations,
electric margins increased by $41 million, while gas margins
decreased by $24 million. Benefiting operating cash flows in
2006 was an $84 million decrease in pension and
postretirement benefit contributions. IP also collected higher-
than-normal trade receivables in 2006 because of the
especially cold December 2005 weather during the winter
heating season. The cash impact from trade receivables was
more significant in 2006 because we had higher gas prices
and colder December 2005 weather. Negative impacts on
operating cash flow include a $216 million increase in
income tax payments, expenditures of $59 million (including
a $10 million FERC fine) associated with the breach of the
upper reservoir at UE’s Taum Sauk pumped-storage
hydroelectric facility in December 2005, and $37 million of
other operations and maintenance expenses due to severe
storms. Most of the Taum Sauk expenditures were pending
recovery from insurance carriers at the end of 2006. In
addition, there was an increase in cash used during 2006 for
payment of 2005 costs, including $9 million for other
operations and maintenance and $14 million for annual
incentive compensation. These expenses were higher in
2006 than they were in 2005, because of increased 2005
earnings relative to performance targets. The cash benefit
from reduced natural gas inventories as a result of lower
prices was offset by increased volume of coal inventory
purchases, because of the coal supply delivery issues
experienced in 2005. See Note 13 – Commitments and
Contingencies – Pumped-storage Hydroelectric Facility
Breach to our financial statements under Part II, Item 8, of
this report for more information regarding the Taum Sauk
incident.
48
At UE, cash from operating activities increased in 2006.
Pension Funding
Overall margins were higher in 2006 than in 2005. Other
operations and maintenance expenses were comparable with
the previous year’s, despite $59 million (including $10 million
for a FERC fine) spent due to the breach of the upper
reservoir at UE’s Taum Sauk pumped-storage hydroelectric
facility as discussed above for Ameren, and $24 million
spent due to severe storms. Pension and postretirement
benefit contributions were $61 million less than in the prior
year. Income tax payments increased $51 million, and
interest payments increased $40 million because of
increased outstanding debt. Cash used for coal purchases
increased in 2006 to alleviate the coal supply delivery issues
experienced in 2005. Cash used for working capital
increased, largely because of storm-related costs.
At CIPS, cash from operating activities decreased from
the prior year. The negative cash effect of higher other
operations and maintenance expenses was reduced by a
small increase in electric and gas margins, as discussed in
Results of Operations. Income tax payments increased
$55 million in 2006 compared with 2005. Reducing this use
of cash was a decrease in pension and postretirement
benefit contributions of $11 million in 2006 compared with
2005, and an increase in collections of trade receivables as a
result of colder December 2005 weather and higher gas
prices than in the year-ago period.
Genco’s cash from operating activities in 2006
decreased compared with the 2005 period, primarily because
of lower operating margins, as discussed in Results of
Operations, and increases in coal inventory. Income tax
payments decreased by $17 million in 2006, pension and
postretirement benefit payments decreased $9 million, and
interest payments were lower because there was less debt
outstanding.
Cash from operating activities increased for CILCORP
and CILCO in 2006 compared with 2005, primarily because
of higher electric margins, as discussed in Results of
Operations, and an increase in collections of trade
receivables as a result of colder December 2005 weather
and higher gas prices than in 2004. In addition, income tax
payments decreased $25 million for CILCORP and $17 million
for CILCO. An increase in coal deliveries at CILCO’s
subsidiary, AERG, negatively affected cash.
IP’s cash from operations increased in 2006, compared
with 2005. Benefiting 2006 cash flows were the collection of
higher-than-normal trade receivables caused by cold
December 2005 weather, as discussed above for Ameren,
and a $1 million decrease in pension and postretirement
benefit payments. These increases were reduced by lower
electric margins and higher other operations and
maintenance expenses, including $9 million related to severe
storms, net income tax refunds of $13 million in 2006
compared with $22 million in 2005, and cash used in 2006
for payment of 2005 costs, as discussed above for Ameren,
including an increase of $7 million in other operations and
maintenance expenses, and an increase of $3 million in
incentive compensation.
Ameren’s pension plans are funded in compliance with
income tax regulations and federal funding requirements. In
May 2007, the MoPSC issued an electric rate order that
allows UE to recover through customer rates the pension
expense it incurred under GAAP. Consequently, Ameren
expects to fund its pension plans at a level equal to the total
pension expense. Based on Ameren’s assumptions at
December 31, 2007, and reflecting this pension funding
policy, Ameren expects to make annual voluntary
contributions of $40 million to $65 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
65%, 8%, 11%, 5% and 11%, respectively. These amounts
are estimates; the numbers may change with actual stock
market performance, changes in interest rates, any pertinent
changes in government regulations, and any voluntary
contributions. See Note 9 – Retirement Benefits to our
financial statements under Part II, Item 8, of this report for
additional information.
Cash Flows from Investing Activities
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
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
49
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 Resources Company in the amount of
$71 million related to the 2005 transfer of leveraged leases
from CILCORP to Resources Company, contributed to the
increase in cash used in investing activities in 2007. The net
year-over-year reduction of $84 million and $82 million in
money pool advances for CILCO and CILCORP, 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 Note 13 – 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.
2006 versus 2005
Ameren’s increase in cash used in investing activities
was primarily due to UE’s 2006 purchases of a
640-megawatt CT facility from affiliates of NRG Energy Inc.
and 510-megawatt and 340-megawatt CT facilities from
subsidiaries of Aquila Inc., for a total of $292 million;
increased nuclear fuel expenditures of $22 million; and
$96 million of capital expenditures during 2006 related to
the severe storms. The CT purchases were intended to meet
UE’s increased generating capacity needs and to provide UE
with additional flexibility in determining the timing of future
baseload generating capacity additions. Emission allowance
purchases decreased $50 million in 2006 compared with
2005, while emission allowance sales increased $49 million.
The sale of noncore properties in 2006 provided a
$56 million benefit to Ameren’s cash from investing
activities.
UE’s cash used in investing activities decreased in
2006, compared with 2005, principally because of a
decrease in capital expenditures at the Callaway nuclear
plant. This is due to UE spending $221 million for planned
upgrades during a scheduled refueling outage in 2005. In
addition, in 2006 UE received $67 million from CIPS as
repayment of an intercompany note. The cash effect of the
$292 million in CT purchases discussed above was more
than the prior-year effect of the $237 million purchase of
two CTs from Genco and the purchase of CT equipment from
Development Company for $25 million. UE’s capital
expenditures related to the 2006 severe storms were
$47 million. In 2006, UE had a $13 million gain on the sale
of a noncore property, and a $35 million increase in sales of
emission allowances.
CIPS’ cash used in investing activities increased in
2006, compared with 2005. Capital expenditures increased
$18 million. Also negatively affecting CIPS’ investing cash
flow was an $18 million reduction in proceeds from CIPS’
note receivable from Genco in 2006. In addition, CIPS paid
$17 million to repurchase its own outstanding bond. The
bond remains outstanding, and CIPS is currently the holder
and debtor. The increased capital expenditures resulted
partly from CIPS’ expansion of its service territory because
of its acquisition of UE’s Illinois utility operations in May
2005. In addition, $16 million was expended as a result of
storms. CIPS’ remaining capital expenditures were for
projects to improve the reliability of its electric and gas
transmission and distribution systems.
Genco had a net use of cash in investing activities for
2006, compared with a net source of cash for 2005. This
was due primarily to the 2005 sale of two CTs to UE for
$241 million. Purchases of emission allowances were
$45 million less in 2006 than in 2005. Capital expenditures
increased $9 million for 2006 compared with 2005.
CILCORP’s cash used in investing activities decreased,
and CILCO’s increased in 2006, compared with 2005. Capital
expenditures increased $12 million for CILCORP and CILCO,
and net money pool advances decreased for each company
by $42 million. CILCORP’s cash from investing activities
further benefited from the repayment of Resources
Company’s note for $71 million, which originated from the
2005 transfer of leveraged leases from CILCORP to
Resources Company. In addition, a subsidiary of CILCORP
and CILCO generated cash from investing activities of
$11 million in 2006, from the sale of its remaining leveraged
lease investments. Emission allowance purchases were
$9 million less in 2006 than in 2005.
IP had a net use of cash in investing activities for 2006,
compared with a net source of cash for 2005, primarily
because of the absence in 2006 of the 2005 repayments for
advances made to the money pool in prior-periods. In
addition, capital expenditures increased $47 million over the
year-ago period, which included $27 million as a result of
severe storms, and increased expenditures to maintain the
reliability of IP’s electric and gas transmission and
distribution systems.
Intercompany Transfer of Illinois Service Territory
On May 2, 2005, UE completed the transfer of its
Illinois-based electric and natural gas service territory to
CIPS, at a net book value of $133 million. UE transferred
50% of the assets directly to CIPS in consideration for a
CIPS subordinated promissory note in the principal amount
50
of $67 million and 50% of the assets by means of a
dividend in kind to Ameren, followed by a capital
contribution by Ameren to CIPS. The remaining principal
balance of $61 million under the note was repaid in full by
CIPS in June 2006.
Capital Expenditures
The following table presents the capital expenditures by
the Ameren Companies for the years ended December 31,
2007, 2006, and 2005:
Capital Expenditures
Ameren(a) . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . .
CILCO (Illinois Regulated) . . . .
CILCO (AERG) . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . .
2007
2006
2005
$ 1,381
625
79
191
254
64
190
178
$
1,284
782
82
85
119
53
66
179
$
935(b)
775
64
76
107
55
52
132
(a) Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
(b) Includes intercompany eliminations.
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 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 scrubber
projects. The scrubbers are necessary to comply with
environmental regulations. AERG also made expenditures for
a 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 expenditures of
$47 million. CIPS and IP incurred storm damage-related
expenditures of $16 million and $27 million, respectively. At
Genco and AERG there was a cash outlay of $24 million and
$11 million, respectively, for scrubber projects. Genco also
made expenditures for a 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.
Ameren’s 2005 capital expenditures principally
consisted of the following expenditures at its subsidiaries.
UE’s capital expenditures for 2005 principally consisted of
$221 million for steam generators, low pressure rotor
replacements, and other upgrades during the 2005 refueling
and maintenance outage at its Callaway nuclear plant. UE
also incurred expenditures of $65 million for three CTs at its
Venice plant, $60 million for numerous projects at its
generating plants, and $45 million for various upgrades to
51
its transmission and distribution system. In addition, UE
incurred expenditures of $237 million for CTs purchased
from Genco, as discussed above. CILCORP’s and CILCO’s
capital expenditures included $29 million for ongoing
generation plant projects to improve flexibility in future fuel
supply for power generation. In addition, CILCO, CIPS, and
IP incurred expenditures to maintain, upgrade and expand
the reliability of their electric and gas transmission and
distribution systems.
The following table estimates the capital expenditures
that will be incurred by the Ameren Companies from 2008
through 2012, including construction expenditures,
capitalized interest and allowance for funds used during
construction (except for Genco, which has no allowance for
funds used during construction), and estimated expenditures
for compliance with environmental standards:
2008
2009 – 2012
Total
UE . . . . . . . . . $ 1,030
105
CIPS . . . . . . . .
Genco . . . . . . .
405
CILCO (Illinois
95
Regulated) . . .
265
CILCO (AERG) . .
200
IP . . . . . . . . . .
65
EEI . . . . . . . . .
Other . . . . . . . .
70
Ameren(a) . . . . . $ 2,235
$ 2,920 – $3,880
400
1,300 – 1,670
300 –
$ 3,950 – $ 4,910
505
2,075
405 –
1,705 –
250 –
460 –
675 –
365 –
130 –
330
605
890
490
135
345 –
725 –
875 –
430 –
200 –
425
870
1,090
555
205
$ 6,400 – $8,400
$ 8,635 – $10,635
(a) Includes amounts for nonregistrant Ameren 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, 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. Any changes that we
may plan to make for future generating needs could result in
significant capital expenditures or losses being incurred,
which could be material.
Environmental Capital Expenditures
Ameren, UE, Genco, AERG and EEI will incur significant
costs in future years to comply with EPA and state
regulations regarding SO2 and NOx emissions (the Clean Air
Interstate Rule) and mercury emissions (the Clean Air
Mercury Rule) from coal-fired power plants.
In May 2005, the EPA issued final regulations with
respect to SO2 and NOx emissions (the Clean Air Interstate
Rule) and mercury emissions (the Clean Air Mercury Rule)
from coal-fired power plants. The rules require significant
reductions in these emissions from UE, Genco, AERG and
EEI power plants in phases, beginning in 2009. States have
finalized rules to implement the federal Clean Air Interstate
Rule and Clean Air Mercury Rule. Illinois has finalized rules
to implement the federal Clean Air Interstate Rule program
that will reduce the number of NOx allowances automatically
allocated to Genco’s, AERG’s and EEI’s plants. 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 selective catalytic reduction (SCR) systems for NOx
reduction at certain coal-fired plants in Illinois.
Missouri rules, which substantially follow the federal
regulations, became effective in April 2007. As a result of
the Missouri rules, UE will manage allowances and install
pollution control equipment. Current plans include the
installation of scrubbers for SO2 reduction and co-benefit
reduction of mercury and pollution control equipment
designed to reduce mercury emissions at certain coal-fired
plants in Missouri.
Illinois has adopted rules for mercury emissions that
are significantly stricter than the federal regulations. In 2006,
Genco, CILCO, EEI, and the Illinois EPA entered into an
agreement that was incorporated into Illinois’ mercury
emission regulations. Under the regulations, Illinois
generators may defer until 2015 the requirement to reduce
mercury emissions by 90% in exchange for accelerated
installation of NOx and SO2 controls. In 2009, Genco, AERG
and EEI will begin putting into service equipment designed
to reduce mercury emissions.
In February 2008, the U.S. Court of Appeals for the
District of Columbia issued a decision that effectively
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 Court’s decision is subject to appeal
and it is uncertain how the EPA will respond. At this time,
we are unable to determine the impact that this action would
have on our estimated expenditures for compliance with
environmental rules, our results of operations, financial
position, or liquidity.
The table below presents estimated capital costs based
on current technology to comply with both the federal Clean
Air Interstate Rule and Clean Air Mercury Rule through 2017
and related state implementation plans. The estimates
described below could change, depending upon additional
federal or state requirements, 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 the proposed rules,
thereby deferring capital investment.
2008
$255
300
170
30
UE(a)
. . .
Genco . .
AERG . . .
EEI . . . .
2009 – 2012
2013 – 2017
Total
$
215 – $ 295
955 – 1,210
500
380 –
350
260 –
$ 1,300 – $1,700
70
45 –
90
70 –
30
20 –
$ 1,770 – $2,250
1,300 – 1,580
760
410
620 –
310 –
Ameren . .
$755
$ 1,810 – $2,355
$ 1,435 – $1,890
$ 4,000 – $5,000
(a) UE’s expenditures are expected to be recoverable in rates over time.
Illinois and Missouri must also develop attainment
plans to meet the federal eight-hour ozone ambient standard,
the federal fine particulate ambient standard, and the Clean
Air Visibility rule. Both states have filed ozone attainment
plans for the St. Louis area. The state attainment plans for
fine particulate matter must be submitted to the EPA by April
2008. The plans for the Clean Air Visibility rule were
submitted in December 2007. The costs in the table above
assume that emission controls required for the Clean Air
Interstate Rule regulations will be sufficient to meet these
new standards in the St. Louis region. Should Missouri
develop an alternative plan to comply with these standards,
the cost impact could be material to UE, but we expect these
costs to be recoverable from ratepayers. Illinois is planning
to impose additional requirements beyond the Clean Air
Interstate Rule as part of the attainment plans for ozone and
fine particulate matter. At this time, we are unable to
determine the impact that state actions would have on our
results of operations, financial position, or liquidity.
The impact that future initiatives related to greenhouse
gas emissions and global warming may have on us is
unknown and therefore not included in the estimated
environmental expenditures. 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.
See Note 13 – 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
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
52
$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 long-term debt 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 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 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.
2006 versus 2005
Ameren had a net source of cash from financing
activities in 2006, compared with a net use of cash in 2005.
Positive effects on cash included a net increase of
$419 million in net short-term debt proceeds in 2006,
compared with net repayments of $224 million of short-term
debt in 2005, and a $454 million decrease in long-term debt
redemptions, repurchases and maturities. Negative effects
on cash included a $411 million reduction in long-term debt
proceeds from the year-ago period, and a $358 million
reduction in proceeds from the issuance of common stock.
The reduction in common stock proceeds was due to the
issuance of 7.4 million shares in the 2005 period related to
the settlement of a stock purchase obligation in Ameren’s
adjustable conversion-rate equity security units.
UE had a net use of cash for financing activities in
2006, compared with a net source of cash in 2005. The
absence of long-term debt issuances in 2006, compared
with $643 million of long-term debt issuances in 2005, was
the primary reason for the change. This negative effect on
cash flow was reduced by net changes in short-term debt
that resulted in a $154 million positive effect on cash in
2006, compared with a $295 million negative effect on cash
in 2005. In addition, dividend payments decreased
$31 million in the 2006 period from 2005, and net money
pool borrowings increased $79 million. Cash from financing
activities in 2006 was used principally to fund CT
acquisitions.
CIPS’ cash used in financing activities decreased in
2006, compared with 2005, principally because of the
issuance of $61 million of long-term debt that was used with
other available corporate funds to repay CIPS’ outstanding
balance on the intercompany note payable to UE. That note
was originally issued as 50% of the consideration for UE’s
Illinois service territory, which was transferred to CIPS in
2005. Cash was also positively affected by a $64 million net
decrease in money pool repayments and borrowings of
$35 million under the 2006 $500 million credit facility in
2006. A $15 million increase in dividends to Ameren
negatively affected CIPS’ cash from financing activities in
2006.
Genco had a net decrease in cash used in financing
activities for 2006, compared with 2005, principally because
of $200 million of capital contributions received in 2006
from Ameren. These capital contributions were made to
reduce Genco’s money pool borrowings. In 2005, Genco
used the $241 million from the sale of CTs to UE along with
other funds to retire $225 million of maturing debt and to
make principal payments on intercompany notes with CIPS
and Ameren. Reducing these positive effects on cash was a
$25 million increase in dividend payments in 2006.
CILCORP had a net use of cash in 2006, compared with
a net source of cash in 2005. CILCO’s cash provided by
financing activities decreased in 2006. Net money pool
repayments increased $142 million at CILCORP and
$145 million at CILCO. CILCORP’s net repayments of
$113 million on its note payable to Ameren reduced its
53
financing cash flow by $227 million, because 2005 included
net borrowings on this note that provided CILCORP with
cash. Positive effects on cash flow included long-term debt
issuances that generated $96 million in 2006, compared with
no long-term debt issuances in 2005. The proceeds from
this debt were used to redeem $21 million of long-term debt
and to reduce money pool borrowings. In addition, CILCORP
borrowed $215 million and CILCO (and CILCO’s subsidiary
AERG) borrowed $165 million under the 2006 $500 million
credit facility, net of repayments. In 2006, CILCORP used
cash of $33 million for redemptions, repurchases and
maturities of long-term debt, compared with $101 million in
the 2005 period. CILCO’s cash used for redemptions,
repurchases and maturities of long-term debt was
comparable in the two years. These positive effects on cash
in 2006 were partially offset by the absence in 2006 of a
$102 million capital contribution received in 2005 from
Ameren, which was made to reduce CILCO’s short-term
Short-term Borrowings and Liquidity
debt. Also contributing to CILCORP’s and CILCO’s increase
in cash used in financing activities for 2006 were increased
common stock dividends of $20 million at CILCORP and
$45 million at CILCO.
IP had a net source of cash from financing activities in
2006, compared with a net use of cash in 2005. This was
partly because of lower redemptions and repurchases of
long-term debt of $70 million in 2006. More debt was repaid
in 2005 to improve IP’s credit profile. Other positive effects
on cash from financing activities included the absence in
2006 of $76 million of common stock dividend payments
made in 2005, net borrowings of $75 million on the 2006
$500 million credit facility, and the issuance of $75 million
of long-term debt in 2006 compared with no long-term debt
proceeds in 2005. The $75 million was used to reduce
money pool borrowings.
Short-term borrowings typically consist of drawings under committed bank credit facilities and commercial paper
issuances. See Note 4 – Credit Facilities 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, 2007:
Credit Facility
Ameren, UE and Genco:
Expiration
Amount Committed
Amount Available
Multiyear revolving(a)(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 2010
$ 1,150
$
409
CIPS, CILCORP, CILCO, IP and AERG:
2006 Multiyear revolving(c)
2007 Multiyear revolving(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
January 2010
January 2010
500
500
120
60
(a) Ameren Companies may access this credit facility through intercompany borrowing arrangements.
(b) See Note 4 – Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report for discussion of the amendment
of this facility.
(c) The maximum amount available to each borrower at December 31, 2007, including for 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, 2007, CILCO had a
sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility. See Note 4 – Credit Facilities and Liquidity
to our financial statements under Part II, Item 8, of this report for a discussion of this credit facility.
(d) The maximum amount available to each borrower at December 31, 2007, 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.
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
Ameren. The termination date for UE and Genco is July 10,
2008, subject to the annual 364-day renewal provisions of
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-
54
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 money pool agreements. See Note 4 –
Credit Facilities 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,
2007, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP
had $355 million, $185 million, $26 million, $2 million,
$6 million, $6 million and $6 million, respectively, of cash
and cash equivalents.
balances: UE – $1 billion, CIPS – $250 million, and CILCO –
$250 million. The authorization was effective as of April 1,
2006, and terminates on March 31, 2008. An application for
renewal of this authorization through March 31, 2010, is
pending with FERC. IP has unlimited short-term debt
authorization from FERC.
Genco is authorized by a March 2006 FERC order to
have up to $300 million of short-term debt outstanding at
any time. In the application to FERC for renewal
authorization referred to above, Genco has requested to
increase its short-term debt authorization to $500 million.
AERG and EEI have unlimited short-term debt authorization
from FERC.
The issuance of short-term unsecured debt securities
by Ameren and CILCORP is not subject to approval by any
regulatory body.
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 2006, FERC issued an order
authorizing these utility subsidiaries to issue short-term debt
securities subject to the following limits on outstanding
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.
Long-term Debt and Equity
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
2007, 2006 and 2005 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
2007
2006
2005
Issuances(a)
Long-term debt
UE:(b)
5.40% Senior secured notes due 2016 . . . . . . . . . . . . . . . . . . .
5.30% Senior secured notes due 2037 . . . . . . . . . . . . . . . . . . .
5.00% Senior secured notes due 2020 . . . . . . . . . . . . . . . . . . .
6.40% Senior secured notes due 2017 . . . . . . . . . . . . . . . . . . .
CIPS:
6.70% Senior secured notes due 2036 . . . . . . . . . . . . . . . . . . .
CILCO:
6.20% Senior secured notes due 2016 . . . . . . . . . . . . . . . . . . .
6.70% Senior secured notes due 2036 . . . . . . . . . . . . . . . . . . .
IP:
December
July
January
June
June
June
June
6.25% Senior secured notes due 2016 . . . . . . . . . . . . . . . . . . .
6.125% Senior secured notes due 2017 . . . . . . . . . . . . . . . . . .
June
November
Total Ameren long-term debt issuances . . . . . . . . . . . . . . . . . . . . . .
Common stock
Ameren:
7,402,320 Shares at $46.61(c)
. . . . . . . . . . . . . . . . . . . . . . . .
DRPlus and 401(k) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
May
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
February
May
55
$
$
$
$
$
$
$
$
$
$
$
$
-
-
-
424
-
-
-
-
250
674
-
91
91
765
100
250
-
-
-
-
61
54
42
75
-
$
259
299
85
-
-
-
-
-
-
232
$
643
-
96
96
$
$
345
109
454
328
$ 1,097
$
-
-
-
95
Month Issued, Redeemed,
Repurchased or Matured
2007
2006
2005
UE:
City of Bowling Green capital lease (Peno Creek CT) . . . . . . . . . .
Various
CIPS:
7.05% First mortgage bonds due 2006 . . . . . . . . . . . . . . . . . . .
6.49% First mortgage bonds due 2005 . . . . . . . . . . . . . . . . . . .
June
June
Genco:
7.75% Senior notes due 2005 . . . . . . . . . . . . . . . . . . . . . . . .
November
CILCORP:
9.375% Senior bonds due 2029 . . . . . . . . . . . . . . . . . . . . . . .
8.70% Senior notes due 2009 . . . . . . . . . . . . . . . . . . . . . . . .
CILCO:
7.73% First mortgage bonds due 2025 . . . . . . . . . . . . . . . . . . .
7.50% First mortgage bonds due 2007 . . . . . . . . . . . . . . . . . . .
6.13% First mortgage bonds due 2005 . . . . . . . . . . . . . . . . . . .
IP:
EEI:
11.5% First mortgage bonds due 2010 . . . . . . . . . . . . . . . . . . .
6.75% First mortgage bonds due 2005 . . . . . . . . . . . . . . . . . . .
Note payable to IP SPT:
5.65% Series due 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.54% Series due 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.38% Series due 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . .
1994 6.61% Senior medium term notes . . . . . . . . . . . . . . . . . .
1991 8.60% Senior medium term notes . . . . . . . . . . . . . . . . . .
Preferred Stock
CILCO:
Various
Various
July
January
December
December
March
Various
Various
Various
December
December
5.85% Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July
Total Ameren long-term debt and preferred stock redemptions,
repurchases and maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
-
-
-
-
-
-
50
-
-
-
84
-
-
-
-
1
4
20
-
-
12
-
21
-
-
(d)
-
-
107
-
-
-
1
3
-
20
225
-
85
-
-
16
-
70
-
58
31
8
7
1
$
489
$
165
$
619
(a) Amount is net of discount.
(b) Ameren’s and UE’s long-term debt increased $240 million during 2006 as a result of the leasing transaction related to UE’s purchase of a
640-megawatt CT facility located in Audrain County, Missouri. No capital was raised as a result of UE’s assumption of the lease obligations.
(c) Shares issued upon settlement of the stock purchase contracts, which were a component of the adjustable conversion-rate equity security
units issued in March 2002.
(d) Amount is less than $1 million.
The following table presents the authorized amounts
under Form S-3 shelf registration statements filed and
declared effective for certain Ameren Companies as of
December 31, 2007:
Effective
Date
Authorized
Amount
June 2004
Ameren . . . .
UE . . . . . . . October 2005
CIPS. . . . . .
May 2001
$ 2,000
1,000
250
Issued
Available
$
459
685
211
$ 1,541
315
39
In March 2004, the SEC declared effective a Form S-3
registration statement filed by Ameren in February 2004,
authorizing the offering of 6 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.
and its 401(k) plan (including subsidiary plans that are now
merged into the Ameren 401(k) plan), Ameren issued
1.7 million, ($91 million) shares of common stock in 2007,
1.9 million ($96 million) in 2006, and 2.1 million
($109 million) in 2005.
Ameren, UE and CIPS 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 – Credit Facilities and Liquidity to our
financial statements under Part II, Item 8, of this report for a
discussion of the covenants and provisions contained in our
bank credit facilities and applicable cross-default provisions.
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
Also see 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
56
contained in certain of the Ameren Companies’ indenture
agreements and articles of incorporation.
At December 31, 2007, the Ameren Companies were in
compliance with their credit facility, indenture, and articles of
incorporation provisions and covenants.
We consider access to short-term and long-term capital
markets a significant source of funding for capital
requirements not satisfied by our operating cash flows.
Inability to raise capital on favorable terms, particularly
during times of uncertainty in the capital markets, could
negatively affect our ability to maintain and expand our
businesses. After assessing our current operating
performance, liquidity, and credit ratings (see Credit Ratings
below), we believe that we will continue to have access to
the capital markets. However, events beyond our control
may create uncertainty in the capital markets or make
access to the capital markets uncertain or limited. Such
events would increase our cost of capital or adversely affect
our ability to access the capital markets.
Dividends
Ameren paid to its shareholders common stock
dividends totaling $527 million, or $2.54 per share, in 2007,
$522 million, or $2.54 per share, in 2006, and $511 million,
or $2.54 per share, in 2005. This resulted in a payout rate
based on net income of 85% in 2007, 95% in 2006, and
84% in 2005. Dividends paid to common shareholders in
relation to net cash provided by operating activities for the
same periods were 48% in 2007, 41% in 2006 and 41% in
2005.
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, the board considers
various issues, including Ameren’s historical earnings and
cash flow, projected earnings, projected cash flow and
potential cash flow requirements, dividend payout rates at
other utilities, return on investments with similar risk
characteristics, impacts of regulatory orders or legislation
and overall business considerations. On February 8, 2008,
Ameren’s board of directors declared a quarterly common
stock dividend of 63.5 cents per share payable on March 31,
2008, to shareholders of record on March 5, 2008.
Certain of our financial agreements and corporate
organizational documents contain covenants and conditions
that, among other things, restrict the Ameren Companies’
payment of 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 and
amounts to be set aside for any sinking fund retirement of
its 5.85% Series preferred stock. At December 31, 2007,
except as described below with respect to the 2007
$500 million credit facility and the 2006 $500 million credit
facility, none of these conditions existed at the Ameren
Companies, and as a result, they were allowed to pay
dividends. The ICC requires IP to have a dividend policy
comparable to that of Ameren’s other Illinois utilities and
consistent with achieving and maintaining a common equity-
to-total-capitalization ratio between 50% and 60%.
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. On July 26, 2006, Moody’s
downgraded CILCORP’s senior unsecured credit rating to
below investment-grade, causing it to be subject to this
dividend payment limitation. As of December 31, 2007,
AERG was in compliance with the debt-to-operating cash
flow ratio test in the 2007 and 2006 $500 million credit
facilities and therefore able to pay dividends. The other
borrowers thereunder are not currently limited in their
dividend payments by this provision of the 2007 or 2006
$500 million credit facilities.
57
The following table presents 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
$
2007
2006
2005
267
40
113
-
61
46
527
$
$
249
50
113
50
-
60
522
$
$
280
35
88
30
76
2
511
(a) CILCO paid to CILCORP dividends of $- million, $65 million and $20 million for the years ended December 31, 2007, 2006 and 2005,
respectively.
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
Contractual Obligations
which the dividend is payable and the amount to be paid.
See Note 8 – 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.
The following table presents our contractual obligations as of December 31, 2007. See Note 9 – 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.
Ameren:(a)
Long-term debt and capital lease obligations(b)(c)
Short-term debt
Interest payments(d)
Operating leases(e)
Illinois electric settlement agreement
Preferred stock of subsidiary subject to mandatory redemption
Other obligations(f)
Total cash contractual obligations
UE:
Long-term debt and capital lease obligations(c)
Short-term debt
Interest payments(d)
Operating leases(e)
Other obligations(f)
Total cash contractual obligations
CIPS:
Long-term debt(c)
Short-term debt
Interest payments(d)
Operating leases(e)
Illinois electric settlement agreement
Other obligations(f)
Total cash contractual obligations
Total
Less than
1 Year
1-3 Years
3-5 Years
After
5 Years
$
$
5,849
1,472
4,380
423
71
16
5,968
$
221
1,472
337
41
43
16
1,300
$
582
-
603
69
28
-
1,451
333
-
537
57
-
-
669
$
4,713
-
2,903
256
-
-
2,548
$ 18,179
$ 3,430
$
2,733
$
1,596
$ 10,420
$
$
$
$
$
$
3,366
82
2,414
185
2,002
8,049
472
125
353
3
10
418
$
1,381
$
152
82
173
15
557
979
15
125
28
1
6
125
300
$
8
-
338
28
683
$
1,057
$
$
-
-
56
1
4
158
219
$
$
$
$
182
-
335
26
262
805
150
-
40
1
-
70
261
$
$
$
$
3,024
-
1,568
116
500
5,208
307
-
229
-
-
65
601
58
Genco:
Long-term debt(c)
Short-term debt
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)
Interest payments(d)(g)
Operating leases(e)
Illinois electric settlement agreement
Preferred stock of subsidiary subject to mandatory redemption
Other obligations(f)
Total cash contractual obligations
CILCO:
Long-term debt
Short-term debt
Interest payments(d)
Operating leases(e)
Illinois electric settlement agreement
Preferred stock subject to mandatory redemption
Other obligations(f)
Total cash contractual obligations
IP:
Long-term debt(b)(c)
Short-term debt
Interest payments(d)
Operating leases(e)
Illinois electric settlement agreement
Other obligations(f)
Total cash contractual obligations
Total
Less than
1 Year
1-3 Years
3-5 Years
After
5 Years
$
$
$
$
$
$
$
$
475
100
126
54
582
152
29
211
1,729
334
175
450
24
18
16
1,455
2,462
148
345
160
24
18
16
1,445
2,156
1,054
175
421
12
14
1,688
3,364
$
$
$
$
$
$
$
$
-
100
39
54
39
9
17
113
371
-
175
31
2
11
16
193
428
-
345
9
2
11
16
193
576
54
175
57
4
9
214
513
$
$
$
$
$
$
$
$
200
-
87
-
75
17
12
77
468
124
-
48
4
7
-
214
397
-
-
18
4
7
-
214
243
250
-
68
5
5
250
578
$
$
$
$
$
$
$
$
-
-
-
-
44
17
-
13
74
-
-
40
4
-
-
132
176
1
-
18
4
-
-
132
155
-
-
60
2
-
155
217
$
$
$
$
$
$
$
$
275
-
-
-
424
109
-
8
816
210
-
331
14
-
-
906
1,461
147
-
115
14
-
-
906
1,182
750
-
236
1
-
1,069
2,056
(a) Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.
(b) Excludes fair market value adjustments of long-term debt of $55 million for CILCORP and $20 million for IP.
(c) Excludes unamortized discount of $6 million at UE, $1 million at CIPS, $1 million at Genco, and $4 million at IP.
(d) The weighted average variable rate debt has been calculated using the interest rate as of December 31, 2007.
(e) Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The $1 million annual obligation for
these items is included in the Less than 1 Year, 1 – 3 Years, and 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 13 – 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 48,
“Accounting for Uncertainty in Income Taxes” on January 1,
2007. As of December 31, 2007, the amounts of unrecognized
tax benefits under the provisions of FIN 48 were $116 million,
$26 million, $- million, $40 million, $19 million, $19 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 11 – Income Taxes for information regarding the
Ameren Companies’ unrecognized tax benefits and related
liabilities for interest expense.
Off-Balance-Sheet Arrangements
At December 31, 2007, none of the Ameren Companies
had any off-balance-sheet financing arrangements other than
operating leases entered into in the ordinary course of
59
business. None of the Ameren Companies expect to engage in
any significant off-balance-sheet financing arrangements in the
near future.
Credit Ratings
The following table presents the principal credit ratings
of the Ameren Companies by Moody’s, S&P and Fitch
effective on the date of this report:
Moody’s
S&P
Fitch
Ameren:
Issuer/corporate credit rating . .
Senior unsecured debt . . . . .
Commercial paper . . . . . . . .
UE:
Issuer/corporate credit rating . .
Secured debt
. . . . . . . . . . .
Commercial paper . . . . . . . .
CIPS:
Issuer/corporate credit rating . .
. . . . . . . . . . .
Secured 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
Baa2
Baa2
P-2
Baa1
A3
P-2
Ba1
Baa3
-
Baa2
-
Ba2
Ba1
Baa2
Ba1
Baa3
BBB-
BB+
A-3
BBB-
BBB
A-3
BB
BBB
BBB-
BBB-
BB
B+
BB
BBB
BB
BBB-
BBB+
BBB+
F2
A-
A+
F2
BB+
BBB
BBB+
BBB+
BB+
BB+
BB+
BBB
BB+
BBB
During March and April of 2007, Moody’s, S&P, and
Fitch downgraded various credit ratings of certain of the
Ameren Companies. Depending on the specific credit rating
agency action and the specific legal entities affected, the
downgrade of these credit ratings was a result of the actions
of various Illinois state legislators, including consideration of
forms of legislation that would have rolled back and frozen
the electric rates of CIPS, CILCO and IP. In the case of UE,
this downgrade was prompted by higher costs, lower
financial metrics, and a continued challenging regulatory
environment in Missouri.
On June 8, 2007, Fitch changed the rating outlook at
UE to negative due to the combined effect of the receipt of
less than expected rate relief and a sizable capital
expenditure program.
On August 1, 2007, Fitch changed the rating outlook at
Ameren to stable. In addition, Fitch revised the rating watch
on CIPS, CILCORP, CILCO and IP to positive. The positive
watch followed the announcement 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 for further discussion of the Illinois electric
settlement agreement.
On August 29, 2007, S&P issued a research update in
response to the Illinois electric settlement agreement. The
outlook on the ratings of Ameren, UE and Genco was changed
to stable. The outlook on the ratings of CIPS, CILCORP,
CILCO, and IP was upgraded to positive. On September 6,
2007, S&P upgraded its senior secured debt ratings of UE,
CIPS, and CILCO from “BBB-” to “BBB” as a result of changes
in its first mortgage bond rating methodology.
On August 29, 2007, Moody’s changed the rating
outlook at Ameren and Genco to stable. The rating outlook
of CIPS, CILCORP, CILCO, and IP was upgraded to positive.
These actions were prompted by the Illinois electric
settlement agreement. Moody’s stated that “the settlement
significantly reduces the likelihood of a rate freeze being
enacted in Illinois and provides the foundation for a
potentially improving political and regulatory environment for
investor-owned-utilities in the state.”
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.
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 as
of the end of 2007 were $56 million, $5 million, $8 million,
$14 million, $14 million, and $21 million at Ameren, UE,
CIPS, CILCORP, CILCO and IP, respectively, resulting from
our reduced issuer and senior unsecured debt ratings. At
December 31, 2007, a reduction to sub-investment-grade
issuer or senior unsecured debt ratings (lower than “BBB-”
or “Baa3”), 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 $176 million, $65 million, $13 million,
$43 million, $29 million, $29 million, and $12 million,
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respectively. In addition, the cost of borrowing under our
credit facilities can 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 2008 and beyond.
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. With 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, Ameren, UE, CIPS, CILCO
and IP expect to experience regulatory lag until requests
to increase rates to recover such costs are granted by
state regulators. Ameren, UE, CIPS, CILCO and IP
expect to be entering a period where more frequent rate
cases will be necessary. UE expects to file its next
electric rate case in Missouri during the second quarter
of 2008. The Ameren Illinois Utilities filed delivery
service rate cases with the ICC in November 2007 due
to inadequate recovery of costs and low returns on
equity of less than 5% experienced in 2007 and
expected in 2008. CIPS, CILCO and IP requested to
increase their annual revenues for electric delivery
service by $180 million in the aggregate (CIPS –
$31 million, CILCO – $10 million, and IP – $139 million).
The electric rate increase requests were based on an
11% return on equity, a capital structure composed of
51% to 53% equity, an aggregate rate base for the
Ameren Illinois Utilities of $2.1 billion and a test year
ended December 31, 2006, with certain prospective
updates. In addition, CIPS, CILCO and IP filed requests
with the ICC in November 2007 to increase their annual
revenues for natural gas delivery service by $67 million
in the aggregate (CIPS – $15 million increase, CILCO –
$4 million decrease, and IP – $56 million increase). The
natural gas rate change requests were based on an 11%
return on equity, a capital structure composed of 51%
to 53% equity, an aggregate rate base for the Ameren
Illinois Utilities of $0.9 billion and a test year ended
December 31, 2006, with certain prospective updates.
The ICC has until the end of September 2008 to render
a decision in these rate cases.
In current and future rate cases, UE, CIPS, CILCO and
IP will also seek cost recovery mechanisms from their
state regulators to reduce regulatory lag. In their electric
and natural gas delivery service rate cases filed in
November 2007, the Ameren Illinois Utilities requested
ICC approval to implement rate adjustment mechanisms
for bad debt expenses, electric infrastructure
investments, and the decoupling of natural gas revenues
from sales volumes. In July 2005, a law was enacted
that enables the MoPSC to put in place fuel and
purchased power and environmental cost recovery
mechanisms for Missouri’s utilities. Rules for the fuel
and purchased power cost recovery mechanism were
approved by the MoPSC in September 2006. Rules for
the environmental cost recovery mechanism were
approved by the MoPSC in February 2008 and will be
effective once published in the Missouri Register. UE
will not be able to use these cost recovery mechanisms
until authorized by the MoPSC as part of a rate case
proceeding. The MoPSC denied UE the use of a fuel and
purchased power cost recovery mechanism in its 2007
rate order. UE plans to request use of a fuel and
purchased power cost recovery mechanism and,
potentially an environmental cost recovery mechanism,
in its next electric rate case filing.
Average residential electric rates for CIPS, CILCO and IP
increased significantly following the expiration of a rate
freeze at the end of 2006. Electric rates rose because of
the increased cost of power purchased on behalf of the
Ameren Illinois Utilities’ customers and an increase in
electric delivery service rates. Due to the magnitude of
these increases, 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
will come from electric generators in Illinois and certain
Illinois electric utilities. Pursuant to the Illinois electric
settlement agreement, the Ameren Illinois Utilities,
Genco and AERG agreed to fund an aggregate of
$150 million, of which the following contributions
remain to be made as of December 31, 2007:
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CILCO
(Illinois
Regulated)
$3.2
1.9
0.1
$5.2
IP
Genco
$ 8.4
4.9
0.4
$13.7
$17.2
10.9
0.7
$28.8
CILCO
(AERG)
$ 7.7
4.9
0.3
$12.9
Ameren
CIPS
2008(a) . . . .
2009(a) . . . .
2010(a) . . . .
Total
. . . . .
$42.9
26.5
1.7
$71.1
$ 6.4
3.9
0.2
$10.5
(a) Estimated.
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To fund these contributions, the Ameren Illinois Utilities,
Genco and AERG will need to increase their respective
borrowings.
As part of the Illinois electric settlement agreement, the
reverse auction used for power procurement in Illinois
was discontinued. It will be replaced with a new power
procurement process to be led by the IPA, beginning in
2009. In 2008, utilities will contract for necessary power
and energy requirements primarily through a request-
for-proposal process, subject to ICC review and
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approval. The ICC approved the proposed 2008 power
procurement plans of the Ameren Illinois Utilities in
December 2007. Existing supply contracts from the
September 2006 reverse auction remain in place. The
Ameren Illinois Utilities’ power procurement costs are
passed directly to its customers. The impact of the new
procurement process in Illinois is uncertain.
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 around-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.
The MoPSC issued an order, as clarified, granting UE a
$43 million increase in base rates for electric service
with new electric rates effective June 4, 2007. This
order included provisions to extend UE’s Callaway
nuclear plant and fossil generation plant lives and to
change the income tax method associated with the cost
of property removals. Such provisions are expected to
decrease Ameren’s and UE’s expenses by $58 million
annually. The MoPSC also approved a stipulation and
agreement authorizing an increase in UE’s 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.
Volatile power prices in the Midwest affect the amount
of revenues Ameren, UE, Genco, CILCO (through AERG)
and EEI can generate by marketing power into the
wholesale and spot markets and influence the cost of
power purchased in the spot markets.
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 33 million megawatthours of power in 2008
(Genco – 18 million, AERG – 7 million, EEI – 8 million),
31 million megawatthours in 2009 (Genco – 15 million,
AERG – 8 million, EEI – 8 million) and 33 million
megawatthours in 2010 (Genco – 18 million, AERG –
7 million, EEI – 8 million).
All but 5 million megawatthours of Genco and AERG’s
pre-2006 wholesale and retail electric power supply
agreements expired during 2006. In 2007, 1 million
megawatthours of these agreements, which had an
average embedded selling price of $35 per
megawatthour, expired. Another 2 million contracted
megawatthours will expire in late 2008, which have an
average embedded selling price of $33 per
megawatthour. These agreements are being replaced
with market-based sales.
The marketing strategy for Non-rate-regulated
Generation is to optimize generation output in a low risk
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manner to minimize earnings and cash flow volatility,
while capitalizing on its low-cost generation fleet to
provide solid, sustainable returns. Through a mix of
physical and financial sales contracts, including
contracts resulting from the Illinois 2006 power
procurement auction and the Illinois electric settlement
agreement, Marketing Company sold as of December 31,
2007, approximately 86% of Non-rate-regulated
Generation’s expected 2008 generation at an average
price of $50 per megawatthour (fiscal year 2009 – 60%,
at an average price of $52 per megawatthour; fiscal year
2010 – 45%, at an average price of $54 per
megawatthour).
The future 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. In February 2008, FERC conditionally
accepted the ancillary services market tariff proposed by
MISO. We expect Non-rate-regulated Generation’s
ancillary services market revenues to increase to
$15 million in 2008 from $5 million realized in 2007.
Ancillary services market revenues are allocated to
Genco and AERG based on their generation in
accordance with their power supply agreements with
Marketing Company.
(cid:129) We expect MISO will begin development of a capacity
market once its ancillary services market is in place. A
capacity market allows participants to purchase or sell
capacity products that meet reliability requirements.
MISO is currently in the process of developing a
centralized regional wholesale ancillary services market,
which is expected to begin during 2008. We expect
capacity and energy prices to strengthen from current
levels because of improving market liquidity and
decreasing reserve margins in MISO. Non-rate-regulated
Generation’s capacity revenues are expected to increase
to approximately $40 million in 2008 from $25 million
in 2007. EEI receives payment for 100% of its capacity
sales under its power supply agreement with Marketing
Company. Capacity revenues are allocated to Genco and
AERG based on their generation in accordance with their
power supply agreements with Marketing Company.
(cid:129) We expect continued economic growth in our service
territory and market area to benefit energy demand in
2008 and beyond, but higher energy prices could result
in reduced demand from customers, especially in
Illinois. 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
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In 2007, 84% of Ameren’s electric generation (UE –
76%, Genco – 96%, AERG – 99%, EEI – 100%) was
supplied by coal-fired power plants. About 94% of the
coal used by these plants (UE – 97%, Genco – 88%,
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(cid:129)
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AERG – 92%, EEI – 100%) was delivered by railroads
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, 2007, coal inventories
for UE, Genco, AERG and EEI were adequate, and in
excess of historical levels, but below 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.
Ameren’s fuel costs (including transportation) are
expected to increase in 2008 and beyond. Fuel costs for
both Missouri Regulated and Non-rate-regulated
Generation are expected to increase approximately 35%
from 2007 to 2010. As of December 31, 2007,
approximately 94%, 86% and 54% of Missouri
Regulated’s estimated fuel costs for 2008, 2009 and
2010, respectively, were priced-hedged. Approximately
98%, 72% and 16% of Non-rate-regulated Generation’s
estimated fuel costs for 2008, 2009 and 2010,
respectively, were price-hedged. 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 2008 through 2012.
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. In
January 2008, the Circuit Court of Reynolds County,
Missouri, approved UE’s November 2007 settlement
agreement with the state of Missouri resolving the
state’s lawsuit and claims for damages and other relief
related to the breach. In addition, pursuant to the
settlement agreement, UE is required to replace the
breached upper reservoir with a new reservoir, subject
to FERC authorization. UE received approval from FERC
to rebuild the upper reservoir in August 2007 and hired
a contractor in November 2007. The estimated cost to
rebuild the upper reservoir is in the range of
$450 million. UE expects the Taum Sauk pumped-
storage hydroelectric facility to be out of service
through at least the fall of 2009, if not longer. UE
believes that substantially all of the 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. We are unable to predict the
timing, or outcomes of this litigation, or its possible
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effect on UE’s results of operation, financial position or
liquidity. See Note 2 – Rate and Regulatory Matters and
Note 13 – 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’s next scheduled refueling
and maintenance outage in the fall of 2008 is expected
to last 25 to 30 days. During a scheduled outage, which
occurs every 18 months, maintenance and purchased
power costs increase, and the amount of excess power
available for sale decreases, versus non-outage years.
Over the next few years, we expect rising employee
benefit costs as well as higher insurance and security
costs associated with additional measures we have
taken, or may need to take, at UE’s Callaway nuclear
plant and at our other facilities. Insurance premiums
may also increase as a result of the Taum Sauk
incident, among other things.
Bad debts may increase due to rising electric and gas
rates.
As we refinance our short-term and variable-rate debt
into fixed-rate debt, financing costs may increase.
(cid:129) We are currently undertaking cost reduction and control
initiatives associated with the strategic sourcing of
purchases and streamlining of all aspects of our
business.
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Capital Expenditures
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The EPA has issued more stringent emission limits on
all coal-fired power plants. Between 2008 and 2017,
Ameren expects that certain Ameren Companies will be
required to invest between $4 billion and $5 billion to
retrofit their power plants with pollution control
equipment. Costs for these types of projects continue to
escalate. These investments will also result in decreased
plant availability during construction and significantly
higher ongoing operating expenses. Approximately 45%
of this investment will be in Ameren’s regulated UE
operations, and it is therefore expected to be
recoverable from ratepayers. The recoverability of
amounts expended in non-rate-regulated 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. In
December 2007, Ameren issued a report on how it is
responding to the rising regulatory, competitive, and
public pressure to significantly reduce carbon dioxide
and other emissions from current and proposed power
plant operations. The report included Ameren’s climate
change strategy and activities, current greenhouse gas
emissions, and analysis with respect to plausible future
greenhouse gas scenarios; it is available on Ameren’s
63
(cid:129)
(cid:129)
(cid:129)
Web site. Investments to control carbon emissions at
Ameren’s coal-fired 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 2007, UE signed an
agreement with UniStar Nuclear to assist UE in the
preparation of a combined construction and operating
license application (COLA) for filing with the NRC. A
COLA describes how a nuclear plant would be designed,
constructed and operated. In addition, UE has also
signed contracts for certain long lead-time equipment.
Preparing that COLA and entering into these contracts
does not mean a decision has been made to build a
nuclear plant. These are only the first steps in the
regulatory licensing and procurement process. UE and
UniStar Nuclear must submit the COLA to the NRC in
2008 to be eligible for incentives available under
provisions of the 2005 Energy Policy Act. We cannot
predict whether or when the NRC will approve the
COLA.
UE intends to submit a license extension application
with the NRC to extend its Callaway nuclear plant’s
operating license by twenty 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 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. UE announced in July 2007 plans to
spend $300 million over three years for underground
cabling and reliability improvement, $135 million
($45 million per year) for tree-trimming, and $84 million
over three years (approximately $28 million per year)
REGULATORY MATTERS
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(cid:129)
for circuit and device inspection and repair. We would
expect these costs or investments to be ultimately
recovered in rates.
Increased investments for environmental compliance,
reliability improvement, and new baseload capacity will
result in higher depreciation and financing costs.
The Ameren Companies will incur significant capital
expenditures over the next five years for compliance
with environmental regulations and to make significant
investments in their electric and gas utility infrastructure
to improve overall system reliability. Expenditures are
expected to be funded primarily with debt.
Other
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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. This case is
currently pending. UE’s filing noted that there were a
number of uncertainties associated with the cost-benefit
study, including issues associated with the UE-MISO
service agreement. If some of these uncertainties are
ultimately resolved in a manner adverse to UE, it could
call into question whether it is cost-effective for UE to
remain in MISO. UE has advised MISO of its intent to
withdraw from MISO as of December 31, 2008, in order
to preserve the option to withdraw based on the outcome
of the pending MoPSC proceeding. It is uncertain when
or how the MoPSC will rule on UE’s MISO cost-benefit
study or, if UE were to withdraw from MISO, what the
effect of such a withdrawal would be on UE.
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 Policies
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. Our application of these policies involves
judgments regarding many factors which in and of themselves could materially affect the financial statements and disclosures.
We have outlined below the critical accounting policies that we believe are most difficult, subjective or complex. Any change in
64
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.
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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.
Environmental Costs
We accrue for all known environmental
contamination where remediation can be reasonably
estimated, but some of our operations have existed for
over 100 years and previous contamination may be
unknown to us.
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(cid:129)
Extent of contamination
Responsible party determination
Approved methods for cleanup
Present and future legislation and governmental
regulations and standards
Results of ongoing research and development regarding
environmental impacts
Basis for Judgment
We determine the proper amounts to accrue for known environmental contamination by using estimates of cleanup costs in
the context of current remediation standards and available technology. See Note 13 – Commitments and Contingencies to our
financial statements under Part II, Item 8, of this report for disclosure on quantified environmental costs, to the extent
possible.
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 billed.
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Projecting customer energy usage
Estimating impacts of weather and other usage-affecting
factors provided to customers but not yet 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 balance sheets under Part II, Item 8, of
this report for unbilled revenue amounts for each registrant.
Valuation of Goodwill, Long-Lived Assets, and Asset Retirement Obligations
We assess the carrying value of our goodwill 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.
(cid:129) Management’s identification of impairment indicators
(cid:129)
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
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65
Accounting Estimate
Uncertainties Affecting Application
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 assets.
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 9 – Retirement
Benefits to our financial statements under Part II, Item 8,
of this report.
Basis for Judgment
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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 rate
payers
Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension assets is based on
our review of available historical, current, and projected rates, as applicable. See Note 9 – 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.
In UE’s Missouri electric utility jurisdiction, there is
currently no tariff for adjusting rates to accommodate
changes in the cost of fuel for electric generation or the cost
of purchased power. However, in July 2005, a law was
enacted that enables the MoPSC to put in place cost
recovery mechanisms for fuel and purchased power and
for environmental costs at Missouri’s utilities. Rules for the
fuel and purchased power cost recovery mechanism were
approved by the MoPSC in September 2006. Rules for the
environmental cost recovery mechanism were approved by
the MoPSC in February 2008 and will be effective once
published in the Missouri Register. UE will not be able to
use these cost recovery mechanisms until so authorized by
the MoPSC as part of a rate case proceeding. In its rate
case filed in July 2006, UE was denied use of a fuel and
purchased power cost recovery mechanism. UE plans to
request use of a fuel and purchased power cost recovery
mechanism, and potentially an environmental cost recovery
mechanism, in its next electric rate case filing.
Effective January 2, 2007, ICC-approved tariffs in
Illinois allow CIPS, CILCO and IP to recover power supply
costs 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
66
billings to gas customers through PGA clauses. As part of a
stipulation and agreement, effective April 1, 2007, UE has
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. In
February 2008, the MoPSC approved UE’s petition requesting
the establishment of an ISRS, to recover annual revenues of
$1 million effective March 29, 2008.
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, as well as rate-related
recovery mechanisms being sought by the Ameren Illinois
Utilities in their pending rate cases with the ICC.
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:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
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, 2007:
Interest Expense
Net Income(a)
Ameren . . . . . . . . . . . .
UE. . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . .
CILCO . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . .
$ 23
5
2
1
5
4
5
$ (14)
(3)
(1)
(b)
(3)
(2)
(3)
(a) Calculations are based on an effective tax rate of 38%.
(b) Less than $1 million.
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
Our tax-exempt environmental improvement and
pollution control revenue-auction-rate bonds issued for the
benefit of UE, CIPS, CILCO and IP through governmental
authorities are insured by “monoline” bond insurers. 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 the tax-exempt environmental
improvement and pollution control revenue bonds issued for
the benefit of UE, CIPS, CILCO and IP. Monoline bond
insurers guarantee the timely repayment of bond principal
and interest when an issuer defaults; as a result, such
securities typically receive the highest investment-grade
ratings from the credit rating agencies, which reflect the
credit ratings of the monoline bond insurers. UE has an
aggregate of $437 million principal amount of insured tax-
exempt auction-rate bonds ($229 million insured by XL
Capital Ltd., $208 million insured by MBIA Inc.). CIPS has
$35 million principal amount of insured tax-exempt auction-
67
rate bonds insured by XL Capital Ltd. CILCO has $19 million
principal amount of insured tax-exempt auction-rate bonds
insured by Financial Guaranty Insurance Company. IP has an
aggregate of $337 million principal amount of insured tax-
exempt auction-rate bonds ($150 million insured by MBIA
Inc., $187 million insured by Ambac Financial Group, Inc.).
Our insured tax-exempt auction-rate bonds bear interest at
rates determined pursuant to auctions conducted every
seven or 35 days, depending on the particular series of
securities. 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 placed some of the monoline bond insurers on review
for a possible downgrade or have actually downgraded their
credit ratings due to their insuring of such securities. As a
result, since December 2007, the insured tax-exempt bonds
that are guaranteed by the monoline bond insurers have
similarly been placed on review for possible downgrade or
have been downgraded. 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.
As a result of these actions by the credit rating
agencies with respect to monoline bond insurers and a lack
of liquidity in the auction rate market, we believe the interest
rates on certain of our insured tax-exempt auction rate
bonds are higher than they would have been in the absence
of such actions. It is possible that the credit rating agencies
may continue to take steps to further downgrade the credit
ratings of the monoline bond insurers as well as our tax-
exempt bonds insured by such insurers and any such
further negative actions could result in higher interest rates
on our insured tax-exempt auction rate bonds. Downgrades
of the monoline bond insurers also increase the possibility
of a “failed auction,” where there are not sufficient clearing
bids in an auction to set the interest rate. A “failed auction”
would result in the interest rates resetting to maximum
interest rates ranging up to 18%, depending upon the series
of bonds, until the next scheduled auction date at which
time another attempt at a successful auction will be made.
Between February 12 and 20, we experienced “failed
auctions” with respect to a portion of our tax-exempt
auction rate bonds. According to press reports, many other
series of tax-exempt auction rate securities similarly
experienced “failed auctions.”
We are evaluating various options available to us,
including refinancing with other instruments, to mitigate the
effects of the ratings downgrades on the monoline insurers
and the effects of these on the interest rates of our
securities. Certain of these options would require approvals
from state regulators and could result in higher expense.
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. At December 31, 2007, no
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, 2007,
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 (2006 – 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 that 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
leases. We estimate our credit exposure to MISO associated
with the MISO Day Two Energy Market to be $63 million at
December 31, 2007 (2006 – $35 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, which will provide $488 million in rate relief over
a four-year period to certain electric customers of the
Ameren Illinois Utilities. 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, Item 8 of this report for additional information.
Equity Price Risk
Our costs of 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.
68
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 or OCI 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 8.25%.
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, 2007, this fund was
invested primarily in domestic equity securities (63%) and
debt securities (36%) and totaled $307 million (in 2006 –
$285 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
through electric rates its decommissioning costs, which
would include unfavorable investment results.
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
structured risk management programs and policies, which
include structured 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 2008 through 2012:
Net Income(a)
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO (AERG) . . . . . . . . . . . . . . . . . . . . .
EEI . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(22)
(9)
(8)
(3)
(6)
(a) Calculations are based on an effective tax rate of 38%.
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.
Similar techniques are used to manage risks associated
with changing prices of fuel for generation. Most UE, Genco
and AERG fuel supply contracts are physical forward
contracts. UE, Genco and AERG do not have a provision
similar to the PGA clause for electric operations, so UE,
Genco and AERG have entered into long-term contracts with
various suppliers to purchase coal and nuclear fuel 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. We 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. We typically hedge coal
transportation forward to provide supply certainty and to
mitigate transportation price volatility. Natural gas
transportation expenses for Ameren’s gas distribution utility
companies and the gas-fired generation units of UE, Genco,
AERG and EEI are regulated by FERC through approved
tariffs governing the rates, terms and conditions of
transportation and storage services. Certain firm
transportation and storage capacity agreements held by
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.
69
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
2008 through 2012, as of December 31, 2007:
2008
2009
2010 – 2012
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) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100% 92%
100
100
44
76
91
82
100
1
18
76
100% 86%
100
100
25
92
96
100
-
22
CIPS:
Natural gas for distribution(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
84%
91
19%
76
Genco:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO:
Coal (AERG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation (AERG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for distribution(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100% 100%
100
90
99
-
92%
100
71
91
85%
69
17
76
IP:
Natural gas for distribution(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
72%
91
18%
76
EEI:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100% 87%
100
-
34%
17
87
-
10
51
37%
31
87
-
10
11%
51
25%
-
-
26%
-
9
51
10%
51
38%
-
(a) Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2008 represents
January 2008 through March 2008. The year 2009 represents November 2008 through March 2009. This continues each successive year
through March 2012.
(b) Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than 1
megawatt of demand as part of the Illinois power procurement auction held in early September 2006. Excluded from the percent hedged
amount is purchased power for fixed-price large commercial and industrial customers with 1 megawatt of demand or higher. Nearly all of
these customers chose a third-party supplier. Also excluded from the percent hedged amount is purchased power to serve large-service
real-time pricing customers, which is purchased as needed. See Note 2 – Rate and Regulatory Matters and Note 13 – Commitments and
Contingencies to our financial statements under Part II, Item 8, of this report for a discussion of this matter and the new power
procurement process pursuant to the Illinois electric settlement agreement.
70
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 2008 through 2012. 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 by
$0.25/gallon, Ameren’s fuel expense could increase by
$13 million annually (UE – $7 million, Genco – $3 million,
AERG – $1 million and EEI – $2 million). As of December 31,
2007, Ameren has price-hedged approximately 75% of
expected fuel surcharges in 2008.
Coal
Transportation
Fuel
Expense
Net
Income(a)
Fuel
Expense
Net
Income(a)
Ameren(b) . . . .
UE . . . . . . . .
Genco . . . . . .
CILCORP . . . .
CILCO . . . . . .
EEI . . . . . . . .
$17
7
6
3
3
1
$(11)
(4)
(4)
(2)
(2)
(1)
$23
10
6
2
2
5
$(15)
(6)
(3)
(2)
(2)
(4)
(a) Calculations are based on an effective tax rate of 38%.
(b) Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
In the event of a significant change in coal prices, UE,
Genco and CILCO 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 through 2008. There is no fuel reloading scheduled
for 2009. UE has price hedges for 87% of the 2010 to 2012
nuclear fuel requirements.
The nuclear fuel markets have undergone significant
change. What was once a buyer’s market has become a
seller’s market; with increased potential for supply
disruptions. UE has increased its desired inventories of
nuclear fuel (with inherent price hedge) and has increased
its forward contract coverage. 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.
Therefore, nuclear fuel price increases are expected, and
price hedging becomes less available. 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 predicted.
Unlike the electricity and natural gas markets, nuclear fuel
markets have no sophisticated financial instruments available
for price hedging, so most hedging is done through
inventories and forward contracts, if they are available.
With regard to the electric generating operations for UE,
Genco and AERG that are exposed to changes in market
prices for natural gas used to run CTs, the natural gas
procurement strategy is designed to ensure reliable and
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 advent of the MISO Day Two Energy Market.
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 our 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. We use complex grid modeling tools to
determine which FTRs we wish to nominate in the FTR
allocation process. There is a risk that we may incorrectly
model the amount of FTRs we will need, 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 CIPS’, CILCO’s and IP’s power 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 costs. Our strategy is
designed to reduce the effect of market fluctuations for our
regulated customers. We cannot eliminate the effects of
price volatility. 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, natural gas, hydroelectric and oil.
Also see Note 13 – Commitments and Contingencies to our
financial statements under Part II, Item 8, of this report for
further information.
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 and emission allowances.
Price fluctuations in natural gas, fuel, electricity and
emission allowances may cause any of these conditions:
(cid:129)
an unrealized appreciation or depreciation of our
contracted commitments to purchase or sell when
71
purchase or sales prices under the commitments are
compared with current commodity prices;
(cid:129) 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.
(cid:129)
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, 2007. The sources used to determine the fair value of these contracts were active
quotes, other external sources, and other modeling and valuation methods. All of these contracts have maturities of less than
five years.
Ameren(a)
UE
CIPS
Genco
CILCORP/
CILCO
IP
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. . . . . . . . . . . . . . . . . . . . . . . .
$
35
(5)
-
14
(31)
Fair value of contracts outstanding at end of year, net . . . . . .
$
13
$
9
(5)
-
5
(2)
7
$
$
(7)
7
-
40
(2)
38
$
$
2
1
-
(4)
(3)
(4)
$
$
(3)
9
-
18
(3)
21
$
$
(36)
47
-
57
(13)
55
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The following table presents maturities of derivative contracts as of December 31, 2007:
Sources of Fair Value
Ameren:
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices provided by other external sources(a) . . . . . . . . . . . . . . . . . . .
Prices based on models and other valuation methods(b)
. . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE:
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices provided by other external sources(a) . . . . . . . . . . . . . . . . . . .
Prices based on models and other valuation methods(b)
. . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS:
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices provided by other external sources(a) . . . . . . . . . . . . . . . . . . .
Prices based on models and other valuation methods(b)
. . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GENCO:
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices provided by other external sources(a) . . . . . . . . . . . . . . . . . . .
Prices based on models and other valuation methods(b)
. . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO:
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices provided by other external sources(a) . . . . . . . . . . . . . . . . . . .
Prices based on models and other valuation methods(b)
. . . . . . . . . . .
$
$
$
$
$
$
$
$
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
72
Maturity
Less than
1 Year
Maturity
1-3 Years
Maturity
4-5 Years
Maturity in
Excess of
5 Years
Total
Fair Value
8
(10)
14
12
2
-
4
6
-
(1)
1
-
1
-
(5)
(4)
-
-
1
1
$
$
$
$
$
$
$
$
$
$
-
7
(7)
-
-
1
-
1
-
-
15
15
-
-
-
-
-
1
8
9
$
$
$
$
$
$
$
$
$
$
-
1
-
1
-
-
-
-
-
-
23
23
-
-
-
-
-
-
11
11
$
$
$
$
$
$
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
$
$
$
$
$
$
$
$
$
8
(2)
7
13
2
1
4
7
-
(1)
39
38
1
-
(5)
(4)
-
1
20
21
Sources of Fair Value
Maturity
Less than
1 Year
Maturity
1-3 Years
Maturity
4-5 Years
Maturity in
Excess of
5 Years
Total
Fair Value
IP:
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices provided by other external sources(a) . . . . . . . . . . . . . . . . . . .
Prices based on models and other valuation methods(b)
. . . . . . . . . . .
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
(9)
2
(7)
$
$
-
6
22
28
$
$
-
1
33
34
$
$
-
-
-
-
$
$
-
(2)
57
55
(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.
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, 2007 and 2006, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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, 2007, 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 1 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and
postretirement obligations as of December 31, 2006.
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.
73
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
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, 2007 and 2006, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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 1 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and
postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
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, 2007 and 2006, and the results of its
operations and its cash flows for each of the three years in the period ended December 31, 2007 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.
74
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and
postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
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, 2007 and
2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31,
2007 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 1 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and
postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
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, 2007 and 2006, and the results of
their operations and their cash flows for each of the three years in the period ended December 31, 2007 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 1 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and
postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
75
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, 2007 and 2006,
and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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 1 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and
postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
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, 2007 and 2006, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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 1 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and
postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
76
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(In millions, except per share amounts)
Operating Revenues:
Electric
Gas
Other
Total operating revenues
Operating Expenses:
Fuel
Purchased power
Gas purchased for resale
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other income
Interest Charges
Income Before Income Taxes, Minority Interest, Preferred Dividends of
Subsidiaries, and Cumulative Effect of Change in Accounting Principle
Income Taxes
Income Before Minority Interest, Preferred Dividends of Subsidiaries, and
Cumulative Effect of Change in Accounting Principle
Minority Interest and Preferred Dividends of Subsidiaries
Income Before Cumulative Effect of Change in Accounting Principle
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes (Benefit) of $–, $–, and $(15)
Net Income
Earnings per Common Share – Basic and Diluted:
Income before cumulative effect of change in accounting principle
Cumulative effect of change in accounting principle, net of income taxes
Earnings per common share – basic and diluted
Dividends per Common Share
Average Common Shares Outstanding
Year Ended December 31,
2007
2006
2005
$
$
$
$
$
6,267
1,279
-
7,546
1,167
1,387
900
1,688
681
381
6,204
1,342
77
(10)
67
423
986
330
656
38
618
-
$
$ 5,585
1,295
-
6,880
1,018
1,150
931
1,556
661
391
5,707
1,173
50
(4)
46
350
869
284
585
38
547
5,431
1,345
4
6,780
936
1,119
957
1,487
632
365
5,496
1,284
29
(12)
17
301
1,000
356
644
16
628
-
(22)
618
$
547
$
606
2.98
-
2.98
2.54
207.4
$
$
$
2.66
-
2.66
2.54
205.6
$
$
$
3.13
(0.11)
3.02
2.54
200.8
The accompanying notes are an integral part of these consolidated financial statements.
77
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 $22 and $11,
ASSETS
respectively)
Unbilled revenue
Miscellaneous accounts and notes receivable
Materials and supplies
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
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
Accrued 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, 12, 13, and 14)
Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 208.3 and
206.6, 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,
2007
2006
$
355
$
137
570
359
280
735
181
2,480
15,069
418
309
160
647
203
1,874
14,286
307
831
198
1,158
685
3,179
$ 20,728
285
831
217
1,488
654
3,475
$ 19,635
$
221
1,472
687
84
438
2,902
5,691
16
2,046
109
1,240
562
839
354
5,150
195
22
$
456
612
671
58
406
2,203
5,285
17
2,144
118
1,177
549
1,065
283
5,336
195
16
2
4,604
2,110
36
6,752
$ 20,728
2
4,495
2,024
62
6,583
$ 19,635
The accompanying notes are an integral part of these consolidated financial statements.
78
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:
Cumulative effect of change in accounting principle
Gain on sales of emission allowances
Gain on sales 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
Minority interest
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement benefit obligations
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 (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 Periods:
Interest
Income taxes, net
Year Ended December 31,
2007
2005
2006
$
618
$
547
$
606
-
(8)
(3)
735
37
19
(28)
27
12
(320)
(88)
20
21
25
8
27
1,102
(1,381)
-
13
(68)
(142)
128
(24)
5
1
(1,468)
(527)
(4)
860
(21)
(488)
(1)
91
674
584
218
137
355
455
283
$
$
-
(60)
(37)
656
36
15
91
27
13
91
(75)
(85)
(72)
(103)
138
97
1,279
(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
$
$
$
$
22
(22)
(22)
656
28
15
59
3
(3)
(160)
(75)
129
107
(77)
(37)
22
1,251
(935)
-
54
(17)
(111)
99
(92)
22
19
(961)
(511)
(6)
(224)
-
(618)
(1)
454
643
(263)
27
69
96
307
187
The accompanying notes are an integral part of these consolidated financial statements.
79
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
Employee stock awards
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 (loss), end of year
Other:
Beginning of year
Reclassification of unearned compensation
Restricted stock compensation awards
Compensation amortized and mark-to-market adjustments
Other, end of year
Total Stockholders’ Equity
Comprehensive Income, Net of Taxes:
Net income
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes
(benefit) of $(7), $11, and $21, respectively
Reclassification adjustments for derivative (gains) included in net income, net of
income taxes of $22, $3, and $8, respectively
Minimum pension liability adjustment, net of income tax (benefit) of $–, $41, and
$(1), respectively
Adjustment to pension and benefit obligation, net of taxes of $1, $–, and $–,
respectively
Total Comprehensive Income, Net of Taxes
Common stock shares at beginning of period
Shares issued
Common stock shares at end of period
December 31,
2006
2007
2005
$
2
-
2
$
2
-
2
$
2
-
2
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
3,949
-
454
-
2
(6)
4,399
1,904
606
(511)
-
1,999
17
23
40
(62)
(2)
(64)
-
-
-
-
(24)
-
-
-
-
-
$6,752
(12)
12
-
-
-
$6,583
(10)
-
(8)
6
(12)
$6,364
$ 618
$ 547
$ 606
(12)
(39)
-
28
(8)
64
36
(13)
(2)
25
$ 592
206.6
1.7
208.3
-
$ 631
204.7
1.9
206.6
-
$ 627
195.2
9.5
204.7
The accompanying notes are an integral part of these consolidated financial statements.
80
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
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
Year Ended December 31,
2007
2006
2005
$ 2,320
466
174
1
2,961
$
2,204
459
158
2
2,823
$2,223
483
181
2
2,889
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
487
330
108
785
310
229
2,203
2,249
620
640
38
(8)
30
22
(7)
15
171
116
479
184
295
54
349
6
539
193
346
6
352
6
Net Income Available to Common Stockholder
$
336
$
343
$ 346
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
81
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 $6 and $6, respectively)
Unbilled revenue
Miscellaneous accounts and notes receivable
Advances to money pool
Accounts receivable – affiliates
Materials and supplies
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
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
Accrued pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 12, 13 and 14)
Stockholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding
Preferred stock not subject to mandatory redemption
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,
2007
2006
$
185
191
118
213
15
90
301
50
1,163
8,189
$
1
145
120
128
18
33
236
45
726
7,882
307
56
697
491
1,551
$ 10,903
285
58
813
526
1,682
$ 10,290
$
152
82
-
315
212
78
209
1,048
3,208
1,273
85
865
476
297
50
3,046
$
5
234
77
313
185
66
191
1,071
2,934
1,293
89
824
491
374
61
3,132
511
113
1,119
1,855
3
3,601
$ 10,903
511
113
739
1,783
7
3,153
$ 10,290
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
82
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2006
2007
2005
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
342
$
349
$
352
activities:
Gain on sales of emission allowances
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
Assets, other
Liabilities, other
Pension and other postretirement obligations
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
CT acquisitions
Nuclear fuel expenditures
Changes in money pool advances
Proceeds from intercompany note receivable – CIPS
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 money pool borrowings
Intercompany note payable – Ameren, net
Redemptions, repurchases, and maturities:
Long-term debt
Issuance 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 Periods:
Interest
Income taxes, net
(5)
-
333
37
6
1
(6)
(186)
(65)
62
12
40
(1)
18
588
(625)
-
(68)
3
-
-
(142)
128
4
(700)
(267)
(6)
(3)
(152)
-
(77)
(4)
424
380
1
296
184
1
185
218
117
$
$
(34)
(13)
335
36
5
38
(1)
(30)
(37)
27
7
(86)
102
36
734
(490)
(292)
(39)
(18)
67
13
(110)
98
39
(732)
(249)
(6)
-
154
-
77
(4)
-
6
1
(21)
(19)
20
1
144
203
$
$
(4)
-
310
28
5
33
11
(82)
-
75
8
(10)
(4)
(16)
706
(538)
(237)
(17)
-
-
-
(111)
99
4
(800)
(280)
(6)
(5)
(295)
(2)
-
(3)
643
15
(1)
66
(28)
48
20
104
52
$
$
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
83
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Preferred Stock Not Subject to Mandatory Redemption
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends
Dividend-in-kind to Ameren
Adjustment to adopt FIN 48
Other
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
Total accumulated other comprehensive income (loss), end of year
Total Stockholders’ Equity
Comprehensive Income, Net of Taxes:
December 31,
2007
2006
2005
$ 511
113
$ 511
113
$ 511
113
739
380
1,119
1,783
342
(267)
(6)
-
3
-
733
6
739
1,689
349
(249)
(6)
-
-
-
718
15
733
1,688
352
(280)
(6)
(67)
-
2
1,855
1,783
1,689
7
(4)
3
-
-
-
3
5
2
7
(35)
35
-
7
2
3
5
(36)
1
(35)
(30)
$3,601
$3,153
$3,016
Net income
Unrealized net gain on derivative hedging instruments, net of income taxes of $–,
$ 342
$ 349
$ 352
$4, and $2, respectively
Reclassification adjustments for derivative (gains) included in net income, net of
income taxes of $2, $4, and $–, respectively
Minimum pension liability adjustment, net of income taxes of $–, $22, and $1,
respectively
-
(4)
-
9
(7)
35
3
-
1
Total Comprehensive Income, Net of Taxes
$ 338
$ 386
$ 356
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
84
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2007
2006
2005
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
$
$
$
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
$
$
710
222
2
934
456
152
148
60
33
849
85
18
(4)
14
30
69
25
44
3
41
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
85
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
BALANCE SHEET
(In millions)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $5 and $2,
$
26
$
6
December 31,
2007
2006
respectively)
Unbilled revenue
Accounts receivable – affiliates
Current portion of intercompany note receivable – Genco
Current portion of intercompany tax receivable – Genco
Materials and supplies
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
Taxes accrued
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
Accrued pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 12 and 13)
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
Accumulated other comprehensive income
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
62
66
9
39
9
66
35
312
1,174
87
105
113
69
374
1,860
15
125
44
19
8
47
258
456
269
265
67
28
629
55
43
10
37
9
71
47
278
1,155
126
115
154
27
422
$ 1,855
$
-
35
36
81
10
36
198
471
297
216
90
40
643
$
$
-
191
50
276
-
517
1,860
-
190
50
302
1
543
$ 1,855
$
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
86
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
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:
$
17
$
38
$
44
Year Ended December 31,
2007
2006
2005
Depreciation and amortization
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement obligations
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Proceeds from intercompany note receivable – Genco
Bond investment
Changes in money pool advances
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
Redemptions, repurchases, and maturities:
Long-term debt
Intercompany note payable – UE
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 Periods:
Interest
Income taxes, net
66
1
(27)
-
(19)
5
(48)
(2)
21
(3)
3
14
(79)
37
-
-
(42)
(40)
(3)
-
90
-
-
-
-
1
-
48
20
6
26
46
25
$
$
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
69
$
60
1
(15)
1
3
(19)
24
26
1
13
(6)
133
(64)
52
-
-
(12)
(35)
(3)
-
-
(66)
(20)
-
-
-
1
(123)
(2)
2
-
29
14
$
$
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
87
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 – SAB 108 (Note 1)
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 gain (loss) on derivative hedging instruments, net of income
taxes (benefit) of $–, $(3), and $6, respectively
Reclassification adjustments for derivative (gains) included in net income,
net of income taxes of $1, $1, and $4, respectively
Minimum pension liability adjustment, net of income taxes of $–, $4, and
$1, respectively
$
$
December 31,
2007
2006
2005
$
-
$
-
$
-
190
1
191
50
302
-
302
17
(40)
(3)
276
1
(1)
-
-
-
-
-
517
17
-
(1)
-
$
$
189
1
190
50
329
(12)
317
38
(50)
(3)
302
7
(6)
1
(6)
6
-
1
543
38
(5)
(1)
6
38
$
$
$
121
68
189
50
323
-
323
44
(35)
(3)
329
4
3
7
(8)
2
(6)
1
569
44
9
(6)
2
49
Total Comprehensive Income, Net of Taxes
$
16
$
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
88
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
Operating Revenues:
Electric
Other
Total operating revenues
Operating Expenses:
Fuel
Purchased power
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income
Miscellaneous Income
Interest Charges
Income Before Income Taxes
Income Taxes
Income Before Cumulative Effect of Change in Accounting Principle
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes (Benefit) of $–, $–, and $(10)
Year Ended December 31,
2007
2006
2005
$
$
872
-
872
344
21
163
69
19
616
256
2
55
203
78
125
-
992
-
992
298
320
153
72
18
861
131
-
60
71
22
49
-
$
1,035
3
1,038
249
309
140
72
11
781
257
1
73
185
72
113
(16)
Net Income
$
125
$
49
$
97
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
89
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable – affiliates
Accounts receivable – trade
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
Accrued pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 12 and 13)
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,
2007
2006
$
2
93
12
93
4
204
1
96
19
96
5
217
1,683
63
18
1,968
1,539
74
20
$ 1,850
$
100
39
54
61
57
9
15
30
365
474
87
161
7
105
47
32
42
394
-
503
167
(22)
648
-
37
123
52
66
9
22
22
331
474
126
165
9
115
31
34
2
356
-
428
156
(21)
563
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$
1,968
$ 1,850
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
90
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
activities:
Cumulative effect of change in accounting principle
Gain on sales of emission allowances
Depreciation and amortization
Amortization of debt issuance costs and 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 obligations
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Proceeds from asset sale to UE
Purchases of emission allowances
Sales of emission allowances
Net cash provided by (used in) investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Short-term debt, net
Changes in money pool borrowings
Redemptions, repurchases, and maturities:
Intercompany notes payable – CIPS and Ameren
Long-term debt
Capital contribution from parent
Net cash 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 Periods:
Interest
Income taxes, net
Year Ended December 31,
2007
2006
2005
$ 125
$ 49
$ 97
-
(2)
101
-
30
1
10
3
(4)
(7)
1
(8)
5
255
(191)
-
(20)
1
(210)
(113)
100
(69)
(37)
-
75
(44)
1
1
2
$
-
(1)
104
-
25
(1)
16
(23)
3
(15)
(24)
(1)
6
138
(85)
-
(26)
1
(110)
(113)
-
(80)
(34)
-
200
(27)
1
-
1
$
$ 48
52
$ 39
25
16
(1)
104
1
20
(21)
(35)
(7)
46
2
4
(16)
3
213
(76)
241
(71)
1
95
(88)
-
87
(86)
(225)
3
(309)
(1)
1
$
-
$ 56
42
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
91
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:
December 31,
2007
$
-
2006
$
-
2005
$
-
428
75
503
156
125
(113)
(1)
167
3
(4)
(1)
-
-
-
(24)
-
3
(21)
(22)
228
200
428
220
49
(113)
-
156
2
1
3
(6)
6
-
-
(24)
-
(24)
(21)
225
3
228
211
97
(88)
-
220
3
(1)
2
(4)
(2)
(6)
-
-
-
-
(4)
$ 648
$ 563
$ 444
Net income
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes
$ 125
$
49
$
97
(benefit) of $(2), $2, and $(1), respectively
Reclassification adjustments for derivative (gains) losses included in net income,
net of income taxes (benefit) of $1, $1, and $(1), respectively
Minimum pension liability adjustment, net of income tax (benefit) of $–, $4, and
$(1), respectively
Adjustment to pension and benefit obligation, net of taxes of $5, $– and $–,
respectively
(3)
(1)
-
3
3
(2)
6
-
(2)
1
(2)
-
Total Comprehensive Income, Net of Taxes
$ 124
$
56
$
94
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
92
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
Income Before Cumulative Effect of Change in Accounting Principle
Cumulative Effect of Change in Accounting Principle, Net of Income
Taxes (Benefit) of $–, $–, and $(1)
Net Income
Year Ended December 31,
2007
2006
2005
$
$
660
329
1
990
77
259
237
181
78
23
855
135
5
(6)
(1)
64
70
21
49
2
47
-
47
$
$
399
333
1
733
109
34
246
179
75
25
668
65
2
(5)
(3)
52
10
(11)
21
2
19
-
19
$
$
387
359
1
747
95
63
262
174
72
20
686
61
-
(6)
(6)
51
4
(3)
7
2
5
(2)
3
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
93
CILCORP INC.
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
December 31,
2007
2006
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $2 and $1,
$
6
$
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
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
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
Accrued 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, 12 and 13)
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
4
47
45
10
42
93
42
283
52
54
47
2
110
40
311
$
$
1,494
1,277
542
41
32
39
654
2,459
542
48
84
16
690
$ 2,250
$
-
520
2
75
34
3
54
688
537
16
193
6
92
127
66
484
19
50
215
73
54
60
3
58
513
542
17
201
7
64
171
45
488
19
-
627
58
30
715
2,459
-
627
11
33
671
$ 2,250
$
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
94
CILCORP INC.
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:
$
47
$
19
$
3
Year Ended December 31,
2007
2006
2005
Cumulative effect of change in accounting principle
Depreciation and amortization
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits
Loss on sales of noncore properties
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and postretirement benefit obligations
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Proceeds from note receivable – Resources Company
Proceeds from sales of noncore properties
Changes in money pool advances
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
Changes in money pool borrowings
Redemptions, repurchases, and maturities:
Long-term debt
Intercompany note payable – Ameren
Preferred stock
Issuances:
Long-term debt
Intercompany note payable – Ameren
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 Periods:
Interest
Income taxes, net paid (refunded)
-
87
1
(5)
-
1
(44)
(17)
(21)
(2)
10
(12)
(12)
33
(254)
-
-
40
-
-
-
(214)
-
-
305
-
(50)
(71)
(1)
-
-
-
183
2
4
6
81
11
$
$
-
91
1
10
4
4
36
(8)
(8)
1
1
-
(18)
133
(119)
71
11
(42)
(12)
1
-
(90)
(50)
(2)
215
(154)
(33)
(113)
(1)
96
-
-
(42)
1
3
4
50
(5)
$
$
2
98
-
(25)
-
(1)
(40)
(18)
8
14
(17)
(3)
12
33
(107)
-
13
-
(21)
1
5
(109)
(30)
-
-
(12)
(101)
-
(1)
-
114
102
72
(4)
7
3
53
20
$
$
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
95
CILCORP INC.
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Common stock dividends
Dividend-in-kind to Ameren
Contribution from intercompany sale of leveraged leases
Capital contribution from parent
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
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 gain (loss) on derivative hedging instruments, net of income taxes
(benefit) of $(1), $(13), and $17, respectively
Reclassification adjustments for derivative (gains) included in net income, net of
income taxes of $1, $1, and $6, respectively
Minimum pension liability adjustment, net of income taxes (benefit) of $–, $2, and
$(2), respectively
$
$
Total Comprehensive Income, Net of Taxes
$
44
$
December 31,
2007
2006
2005
$
-
$
-
$
-
627
-
-
-
-
627
11
47
-
58
4
(3)
1
-
-
-
29
-
29
30
715
47
(1)
(2)
-
$
$
640
(42)
-
29
-
627
-
19
(8)
11
25
(21)
4
(2)
2
-
-
29
29
33
671
19
(20)
(1)
2
-
544
(27)
(5)
26
102
640
-
3
(3)
-
4
21
25
-
(2)
(2)
-
-
-
23
663
3
30
(9)
(2)
$
$
$
22
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
96
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
Income Before Cumulative Effect of Change in Accounting Principle
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes (Benefit) of $–, $–, and $(1)
Net Income
Preferred Stock Dividends
Net Income Available to Common Stockholder
$
Year Ended December 31,
2007
2006
2005
660
329
1
990
71
258
237
184
73
23
846
144
5
(7)
(2)
27
115
39
76
-
76
2
74
$
$
399
333
1
733
99
34
246
180
70
25
654
79
1
(5)
(4)
18
57
10
47
-
47
2
45
$
$
387
355
-
742
87
63
258
184
67
20
679
63
-
(5)
(5)
14
44
16
28
(2)
26
2
24
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
97
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $2 and $1, respectively)
Unbilled revenue
Accounts receivable – affiliates
Advances to money pool
Materials and supplies
Other current assets
$
LIABILITIES AND STOCKHOLDERS’ EQUITY
$
Total current assets
Property and Plant, Net
Intangible Assets
Regulatory Assets
Other Assets
TOTAL ASSETS
Current Liabilities:
Current maturities of long-term debt
Short-term debt
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
Accrued pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 12 and 13)
Stockholders’ Equity:
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding
Preferred stock not subject to mandatory redemption
Other paid-in capital
Retained earnings
Accumulated other comprehensive income
Total stockholders’ equity
December 31,
2007
2006
6
52
54
45
-
110
27
294
1,492
1
32
43
$
3
47
45
9
42
93
32
271
1,275
2
84
18
$ 1,862
$ 1,650
$
-
345
75
34
3
45
502
148
16
155
6
220
127
66
574
-
19
429
172
2
622
50
165
54
47
3
47
366
148
17
166
7
197
171
43
584
-
19
415
99
2
535
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$ 1,862
$ 1,650
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
98
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
activities:
Cumulative effect of change in accounting principle
Depreciation and amortization
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Loss on sales of noncore properties
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and postretirement benefit obligations
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Proceeds from sales of noncore properties
Changes in money pool advances
Purchases of emission allowances
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 money pool borrowings
Redemptions, repurchases, and maturities:
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 During the Periods:
Interest
Income taxes, net paid
Year Ended December 31,
2007
2006
2005
$
76
$
47
$
26
-
74
1
(1)
-
-
(42)
(17)
(6)
(2)
2
(12)
1
74
(254)
-
42
-
-
(212)
-
(2)
-
180
-
(50)
(1)
-
14
141
3
3
6
38
32
-
82
1
13
6
(1)
33
(8)
(19)
-
14
(15)
-
153
(119)
11
(42)
(12)
1
(161)
(65)
(2)
(2)
165
(161)
(21)
(1)
96
-
9
1
2
3
19
17
$
$
2
86
-
(25)
-
11
(34)
(19)
10
15
(27)
6
16
67
(107)
13
-
(21)
1
(114)
(20)
(2)
-
-
(16)
(16)
(1)
-
102
47
-
2
2
15
34
$
$
$
$
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
99
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Preferred Stock Not Subject to Mandatory Redemption
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends
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
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:
December 31,
2007
2006
2005
$
$
-
19
-
19
$
-
19
415
14
429
99
76
-
(2)
(1)
172
4
(3)
1
-
-
-
(2)
-
3
1
2
415
-
415
119
47
(65)
(2)
-
99
25
(21)
4
(16)
16
-
-
(2)
-
(2)
2
313
102
415
115
26
(20)
(2)
-
119
7
18
25
(17)
1
(16)
-
-
-
-
9
$ 622
$ 535
$ 562
Net income
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes
$
76
$
47
$
26
(benefit) of $(1), $(13), and $18, respectively
Reclassification adjustments for derivative (gains) included in net income, net of
income taxes of $1, $1, and $6, respectively
Minimum pension liability adjustment, net of income taxes of $–, $10, and $1,
respectively
Adjustment to pension and benefit obligation, net of taxes of $2, $–, and $–,
respectively
(1)
(2)
-
3
(20)
(1)
16
-
27
(9)
1
-
Total Comprehensive Income, Net of Taxes
$
76
$
42
$
45
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
100
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2007
2006
2005
$
1,104
540
2
1,646
$
1,149
543
2
$
1,112
541
-
1,694
1,653
714
390
271
80
16
66
1,537
109
738
394
271
77
-
73
686
393
225
79
-
68
1,553
141
1,451
202
14
(5)
9
77
41
15
26
2
24
$
6
(4)
2
49
94
37
57
2
55
$
7
(3)
4
44
162
65
97
2
95
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
$
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
101
ILLINOIS POWER COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $9 and $3,
$
6
$
-
December 31,
2007
2006
respectively)
Unbilled revenue
Accounts receivable – affiliates
Materials and supplies
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Investment in IP SPT
Goodwill
Other assets
Regulatory assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt payable to IP SPT
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
Long-term Debt Payable to IP SPT
Deferred Credits and Other Liabilities:
Regulatory liabilities
Accrued pension and other postretirement benefits
Accumulated deferred income taxes
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 12 and 13)
Stockholders’ Equity:
137
118
17
134
38
450
2,220
10
214
109
316
649
$ 3,319
$
54
175
-
85
36
7
80
437
1,014
2
129
189
148
92
558
$
$
105
101
1
122
27
356
2,134
8
214
62
438
722
3,212
51
75
43
119
67
7
72
434
772
92
73
230
138
127
568
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
-
1,194
46
64
4
1,308
$ 3,319
-
1,194
46
101
5
1,346
3,212
$
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
102
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
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
Assets, other
Liabilities, other
Pension and other postretirement benefit obligations
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Changes in money pool advances
Other
Net cash provided by (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
IP SPT maturities
Issuance of long-term debt
Overfunding of TFNs
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Cash Paid (Refunded) During the Periods:
Interest
Income taxes, net paid (refunded)
Year Ended December 31,
2007
2006
2005
$
26
$
57
$
97
105
8
4
(1)
(65)
(12)
(44)
(16)
28
(5)
28
(178)
-
(2)
(180)
(61)
(2)
(2)
100
(43)
-
(87)
250
3
158
6
-
6
66
2
$
$
21
4
75
-
71
-
(17)
(13)
(16)
(10)
172
(179)
-
(1)
(180)
-
(2)
(1)
75
(32)
-
(86)
75
(21)
8
-
-
-
39
(13)
$
$
42
2
39
(2)
(66)
(37)
50
(5)
21
7
148
(132)
140
1
9
(76)
(2)
-
-
75
(70)
(86)
-
(3)
(162)
(5)
5
-
36
(22)
$
$
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
103
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Preferred Stock Not Subject to Mandatory Redemption
Other Paid-in Capital:
Beginning of year
Purchase accounting adjustments
Other
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends and tender charges
Retained earnings, end of year
Accumulated Other Comprehensive Income (Loss):
Derivative financial instruments, beginning of year
Change in derivative financial instruments
Derivative financial instruments, end of year
Deferred retirement benefit costs, beginning of year
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 $(1), respectively
Reclassification adjustments for derivative losses included in net income, net of
income taxes (benefit) of $–, $(2), and $–, respectively
Deferred retirement benefit cost adjustment, net of income taxes of $–, $–, and $–,
respectively
December 31,
2007
2006
2005
$
$
-
46
-
46
$
-
46
1,194
-
-
1,194
1,196
-
(2)
1,207
(11)
-
1,194
1,196
101
26
(61)
(2)
64
-
-
-
5
-
(1)
4
4
46
57
-
(2)
101
(1)
1
-
-
5
-
5
5
27
97
(76)
(2)
46
-
(1)
(1)
-
-
-
-
(1)
$1,308
$1,346
$1,287
$
26
$
57
$
97
-
-
(1)
(2)
(1)
3
-
-
-
Total Comprehensive Income, Net of Taxes
$
25
$
58
$
96
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
104
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
AMEREN ENERGY GENERATING COMPANY
(Consolidated)
CILCORP INC. (Consolidated)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS POWER COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 2007
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 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.
(cid:129)
(cid:129)
(cid:129)
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. Before May 2, 2005, it also
operated those businesses in Illinois. 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
3 million and includes the Greater St. Louis area. UE
supplies electric service to 1.2 million customers and
natural gas service to 127,000 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 million in an area
of 20,500 square miles. CIPS supplies electric service to
400,000 customers and natural gas service to 190,000
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
2,549 megawatts of coal-fired electric generating
(cid:129)
(cid:129)
capacity and 1,666 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 a
population of 1 million. CILCO supplies electric service
to 210,000 customers and natural gas service to
213,000 customers. AERG, a non-rate-regulated wholly
owned subsidiary of CILCO, owns 1,074 megawatts of
coal-fired electric generating capacity and 55 megawatts
of natural gas and 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 1.4 million in
an area of 15,000 square miles, contiguous to our other
service territories. IP supplies electric service to
626,000 customers and natural gas service to 427,000
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 during 2007 was held 40% by UE and
40% by Development Company. Ameren consolidates EEI for
financial reporting purposes, while UE for 2007 reported EEI
under the equity method. 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.
The following table presents summarized financial
information of EEI (in millions).
For the years ended December 31,
Operating revenues . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . .
As of December 31:
Current assets . . . . . . . . . . . . . . . .
Noncurrent assets. . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . .
Noncurrent liabilities . . . . . . . . . . . .
2007
$427
216
136
$ 69
124
60
10
2006
$371
227
136
$ 58
108
70
17
2005
$170
37
16
$ 39
102
46
11
The financial statements of the Ameren Companies
(except CIPS) are prepared on a consolidated basis and
therefore include the accounts of their majority-owned
subsidiaries as applicable. All significant intercompany
105
transactions have been eliminated. All tabular dollar amounts
are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial
statements reflect all adjustments (which include normal,
recurring adjustments) that are necessary, in our opinion, for
a fair presentation of our results. The preparation of financial
statements in conformity with GAAP requires management
to make certain estimates and assumptions. Such estimates
and assumptions affect reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at
the dates of financial statements, and the reported amounts
of revenues and expenses during the reported periods.
Actual results could differ from those estimates.
Regulation
Certain Ameren subsidiaries are regulated by the
MoPSC, the ICC, the NRC, and FERC. In accordance with
SFAS No. 71, “Accounting for the Effects of Certain Types of
Regulation,” UE, CIPS, CILCO and IP defer certain costs
Materials and Supplies
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 is our best
estimate of the amount of probable credit losses in our
existing accounts receivable. The allowance is based on the
application of a historical write-off factor to the amount of
outstanding receivables, including unbilled revenue, and a
review for collectibility of certain accounts over 90 days past
due.
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, 2007
and 2006:
2007:
Fuel(b) . . . . . . . . . . . . . . . . . . . . . . . .
Gas stored underground . . . . . . . . . . . .
Other materials and supplies . . . . . . . . .
2006:
Fuel(b) . . . . . . . . . . . . . . . . . . . . . . . .
Gas stored underground . . . . . . . . . . . .
Other materials and supplies . . . . . . . . .
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
$253
245
237
$735
$197
243
207
$647
$129
30
142
$301
$ 86
28
122
$236
$ -
52
14
$66
$ -
58
13
$71
$67
-
26
$93
$70
-
26
$96
$ 36
52
22
$110
$ 21
53
19
$ 93
$ 36
52
22
$110
$ 21
53
19
$ 93
-
$
110
24
$134
$
-
104
18
$122
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Consists of coal, oil, paint, propane, and tire chips.
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.
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 2007, 2006 and
2005 generally ranged from 3% to 4% of the average
depreciable cost. Due to the Missouri electric rate order that
became effective in June 2007, UE’s annual depreciation
expense will be reduced by $53 million. Genco’s annual
depreciation expense will decrease by $12 million according
to a depreciation study completed in September 2007.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the
allowance for funds used during construction, as is the
106
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
Goodwill and Intangible Assets
following table presents the allowance for funds used during
construction rates that were utilized during 2007, 2006 and
2005:
Ameren . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . .
CILCORP and CILCO . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . .
2007
2006
2005
6% - 7% 6% - 9% 3% - 9%
6
6
7
6
6
9
6
6
6
7
3
9
Goodwill. As of December 31, 2007, Ameren, CILCORP and IP had goodwill of $831 million, $542 million and $214 million,
respectively. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets
acquired. We evaluate goodwill for impairment in the fourth quarter of each year, or more frequently if events and circumstances
indicate that the asset might be impaired. Ameren’s and IP’s goodwill relates to the acquisitions of IP and an additional 20%
ownership interest in EEI in 2004, and Ameren’s and CILCORP’s goodwill relates to the acquisitions of CILCORP and Medina
Valley in 2003.
There were no changes in the carrying amount of goodwill at any of the Ameren Companies for the period from January 1,
2007, to December 31, 2007.
Intangible Assets. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets consisted of the following:
December 31, 2007
Emission allowances(c) . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006
Emission allowances(c) . . . . . . . . . . . . . . . . . . . . . . . . . . .
$198
$217
$56
$58
$63
$74
$41
$48
$1
$2
Ameren(a)
UE
Genco
CILCORP(b)
CILCO
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes fair market value adjustments recorded in connection with Ameren’s acquisition of CILCORP.
(a)
(b)
(c) 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, except at UE where usage of emission allowances is deferred as a regulatory
liability.
The following table presents the net book value of emission allowances consumed or (sold) for Ameren, UE, Genco,
CILCORP and CILCO (AERG) and recognized in earnings during the years ended December 31, 2007, 2006 and 2005.
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO (AERG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes allowances consumed that were recorded through purchase accounting.
Impairment of Long-lived Assets
Investments
2007
$35
(5)
30
7
1
2006
$ (3)
(34)
30
21
11
2005
$46
(4)
31
30
19
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.
Ameren and UE evaluate for impairment the
investments held in UE’s nuclear decommissioning trust
fund. Investments are considered to be impaired when a
decline in fair value below the cost basis is estimated to be
other than temporary. If the decline is determined to be
other than temporary, the cost basis of the security is
written down to fair value. 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, any impairment would likely be recorded as a
regulatory asset on Ameren’s and UE’s Consolidated Balance
107
Sheets. Ameren and UE consider, among other factors,
general market conditions, the duration and the extent to
which the security’s fair value has been less than cost, and
UE’s intent and ability to hold the investment. See Note 15 –
Fair Value of Financial Instruments for disclosure of the fair
value and unrealized gains and losses of UE’s investments.
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
Discount, premium and expense associated with long-
term debt are amortized over the lives of the related issues.
Revenue
Operating Revenues
UE, CIPS, Genco, CILCO and IP record operating
revenue for electric or gas service when it is delivered to
Excise Taxes
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.
Fuel and Gas Costs
In UE’s, CIPS’, CILCO’s and IP’s Missouri and Illinois
retail gas utility jurisdictions, changes in gas costs are
generally reflected in billings to gas customers through PGA
clauses.
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.
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 10 – Stock-based Compensation for further
information.
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 Taxes Other Than Income Taxes on the statement of income. Excise taxes reflected
on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They
are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in
Operating Revenues and Taxes Other than Income Taxes for the years ended 2007, 2006 and 2005:
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
$166
110
15
11
11
30
2006
$169
106
16
12
12
35
2005
$159
105
13
10
10
31
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
108
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 11 – 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
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, 2007, 2006, and
2005, Ameren had minority interest expense related to EEI of
$27 million, $27 million and $3 million, respectively, and
preferred dividends of subsidiaries of $11 million,
$11 million, and $13 million, respectively.
Earnings Per Share
There were no material differences between Ameren’s
basic and diluted earnings per share amounts in 2007, 2006,
and 2005. 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 35,545 shares in 2007, 38,438 shares
in 2006, and 65,917 shares in 2005.
Accounting Changes and Other Matters
Staff Accounting Bulletin No. 108, Considering the Effects of
Prior-Year Misstatements When Quantifying Misstatements
in Current Year Financial Statements (SAB 108)
In September 2006, the SEC staff issued SAB 108,
which provides interpretive guidance on how registrants
should quantify misstatements when evaluating the
materiality of financial statement errors. SAB 108 requires
public companies to use a dual approach to assess the
quantitative effects of financial misstatements. The dual
approach includes both an income statement-focused
assessment and a balance sheet-focused assessment.
SAB 108 also provides transition accounting and disclosure
guidance for situations in which a material error existed in
prior-period financial statements, allowing companies to
restate prior-period financial statements or to recognize the
cumulative effect of initially applying SAB 108 through an
adjustment to beginning retained earnings in the year of
adoption. SAB 108 was effective as of December 31, 2006.
Prior to 2000, we concluded that UE’s unbilled revenue
was understated and CIPS’ unbilled revenue was overstated
by a similar amount. We previously concluded that these
differences were immaterial to the financial statements of UE
and CIPS for all years subsequent to 2000. In connection
with our application of SAB 108, we recorded a decrease to
CIPS’ unbilled revenue of $12 million as an adjustment to
retained earnings. Additionally, we concluded the UE unbilled
revenue difference was immaterial to its 2006 financial
statements. Accordingly, we recorded an increase to UE’s
unbilled revenue of $12 million in the fourth quarter of 2006
as an increase in operating revenues. The adoption of
SAB 108 had no impact on Ameren’s consolidated 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)
FIN 48 addresses the determination of whether tax
benefits claimed or expected to be claimed on a tax return
should be recorded in the financial statements. Under FIN 48,
Ameren may recognize the tax benefit from an uncertain tax
position only if it is more likely than not that the tax position
will be sustained on examination by the taxing authorities, on
the technical merits of the position. The tax benefits
recognized in the financial statements from such a position
are based on the largest benefit that has a greater than 50%
likelihood of being realized upon ultimate settlement. FIN 48
also provides guidance on derecognition of income tax assets
and liabilities, classification of current and deferred income
tax assets and liabilities, accounting for interest and penalties
on income taxes, and accounting for income taxes in interim
periods. FIN 48 requires expanded disclosures. The Ameren
Companies adopted the provisions of FIN 48 on January 1,
2007. See Note 11 – Income Taxes for additional FIN 48
discussion.
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 determined
based on the assumptions that market participants would use
in pricing an asset or liability. This standard is effective as of
the beginning of our 2008 fiscal year for financial assets and
liabilities and as of the beginning of our 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, was not material. The impact of the adoption
of SFAS No. 157 for nonfinancial assets and liabilities is not
expected to be material.
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
109
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 are
currently evaluating whether we will elect to apply the
accounting policies permitted under this pronouncement.
The adoption of FSP FIN 39-1 will have no impact on net
income, and we do not expect that the impact will be
material to our financial position.
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 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 141(R) will be effective for us
as of the beginning of our 2009 fiscal year. It will apply
Asset Retirement Obligations
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 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 160 will be effective for
us as of the beginning of our 2009 fiscal year. It will apply
prospectively, except for the presentation and disclosure
requirements, for which it will apply retroactively. This
standard will be applicable to the minority interest in EEI, as
it is 80% owned by Ameren Corporation.
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. Upon adoption of SFAS No. 143 and FIN 47, Ameren, UE, Genco, CILCORP, and
CILCO 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 recorded AROs for the disposal of certain transformers.
Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a
regulatory liability. See Note 2 – Rate and Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2007 and
2006:
CIPS
Genco
CILCORP/
CILCO
Balance at December 31, 2005 . . . . . . . . . . . . . . . . . .
Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion in 2006(c) . . . . . . . . . . . . . . . . . . . . . . . .
Change in estimates. . . . . . . . . . . . . . . . . . . . . . . .
Balance at December 31, 2006 . . . . . . . . . . . . . . . . . .
Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion in 2007(c) . . . . . . . . . . . . . . . . . . . . . . . .
Change in estimates(e) . . . . . . . . . . . . . . . . . . . . . .
Ameren(a)(b)
$523
1
(2)
29
2
553
1
(2)
32
(17)
UE(b)
$466
-
(d)
26
(1)
491
1
(1)
28
(43)
$ 2
-
-
(d)
-
2
-
-
(d)
(d)
$34
(d)
(2)
2
1
35
-
(1)
2
16
Balance at December 31, 2007 . . . . . . . . . . . . . . . . . .
$567
$476
$ 2
$52
$13
(d)
(d)
1
3
17
-
(d)
1
10
$28
IP
$ 2
-
-
(d)
-
2
-
-
(d)
-
$ 2
(a) Ameren amounts do not equal total due to AROs at EEI.
(b) The nuclear decommissioning trust fund assets of $307 million and $285 million as of December 31, 2007 and 2006, respectively, are
restricted for decommissioning of the Callaway nuclear plant.
(c) Substantially all accretion expense was recorded as an increase to regulatory assets.
(d) Less than $1 million.
(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.
110
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. We have determined that
the following significant VIEs were held by the Ameren
Companies at December 31, 2007:
(cid:129)
(cid:129)
(cid:129)
Tolling agreement. CILCO has a variable interest in
Medina Valley through a tolling agreement to purchase
steam, chilled water, and electricity. We have concluded
that CILCO is not the primary beneficiary of Medina
Valley. Accordingly, CILCO does not consolidate Medina
Valley. The maximum exposure to loss as a result of
this variable interest in the tolling agreement is not
material.
Leveraged lease and affordable housing partnership
investments. Ameren and UE have 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 and UE are not
primary beneficiaries of any of the VIEs related to these
investments. The maximum exposure to loss as a result
of these variable interests is limited to the investments
in these arrangements. At December 31, 2007, Ameren
and UE had investments in affordable housing and low-
income real estate development partnerships of
$100 million and $15 million, respectively. At
December 31, 2007, Ameren had a net investment in a
leveraged lease of $9 million.
IP SPT. IP has a variable interest in IP SPT, which was
established in 1998 to issue TFNs. IP has indemnified
and is liable to IP SPT if IP does not bill the applicable
charges to its customers on behalf of IP SPT or if it
does not remit the collections to IP SPT; however, the
note holders are considered the primary beneficiaries of
this special-purpose trust. Accordingly, Ameren and IP
do not consolidate IP SPT.
NOTE 2 – RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory
proceedings and related lawsuits. We are unable to predict
the ultimate outcome of these matters, the timing of the final
decisions of the various agencies and courts, or the impact
on our results of operations, financial position, or liquidity.
Missouri
Electric
With the expiration of an electric rate moratorium that
provided for no changes in UE’s electric rates before July 1,
2006, UE filed in July 2006 a request with the MoPSC for an
average increase in electric rates of 17.7%, or $361 million,
based on a requested return on equity of 12.0%. This rate
111
increase filing was based on a test year ended June 30,
2006, and was updated for known and measurable items
through January 1, 2007.
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. The MoPSC order also included the
following significant provisions:
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
Acceptance without rate adjustment of the expiration of
UE’s cost-based power supply contract with EEI, which
expired in December 2005.
Allowance of the full cost of certain CTs purchased or
built in the past few years to be included in UE’s rate
base.
Establishment of a regulatory tracking mechanism,
through the use of a regulatory liability account, 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. These deferred amounts will be addressed as
part of UE’s next rate case. The MoPSC allowed an
annual base level of SO2 emission allowance sales of up
to $5 million, which UE can recognize in its statement
of income.
Approval of a regulatory tracking mechanism for
pension and postretirement benefit costs.
Change of income tax method associated with the cost
of property removal, net of salvage, to the normalization
method of accounting, which reduced income tax
expense in the calculation of UE’s electric rates and in
financial reporting.
Establishment of off-system sales base level of
$230 million used in determining UE’s revenue
requirement.
Extension of UE’s Callaway nuclear plant and fossil
generation plant lives used in calculating depreciation
expense for electric rates and financial reporting
purposes.
(cid:129) MoPSC staff directed to review a possible loss in
capacity sales as a result of the breach of the upper
reservoir of the Taum Sauk pumped-storage
hydroelectric facility. The review is still pending.
Establishment of a requirement to fund low-income
energy assistance and energy conservation programs;
half of such funding will be recoverable through rates to
customers.
Denial of UE’s request to implement a fuel and
purchased power cost recovery mechanism.
(cid:129)
(cid:129)
In June 2007, the MoPSC denied UE’s and other
intervenors’ applications for a rehearing with respect to
certain aspects of the MoPSC rate order. In July 2007, UE
appealed certain aspects of the MoPSC decision, principally
the 10.2% return on equity granted by the MoPSC, to the
Circuit Court of Cole County in Jefferson City, Missouri. The
Office of Public Counsel and the Missouri attorney general,
who were both parties in the electric rate case, also
appealed certain aspects of the MoPSC decision to the
Circuit Court of Cole County. In December 2007, the Circuit
Court of Cole County sustained the MoPSC rate order in all
respects. In January 2008, UE and the other parties
appealed the Circuit Court of Cole County’s decision to the
Court of Appeals for the Western District of Missouri.
Gas
In March 2007, the MoPSC approved a stipulation and
agreement that resolved a July 2006 request by UE to
increase annual natural gas delivery revenues by $11 million.
The stipulation and agreement authorized an increase in
annual natural gas delivery revenues of $6 million, effective
April 1, 2007. Other principal provisions of the stipulation
and agreement include:
(cid:129)
(cid:129)
UE’s agreement to not file a natural gas delivery rate
case before March 15, 2010. This agreement did not
prevent UE from filing to recover infrastructure
replacement costs through an ISRS during this three-
year rate moratorium. The return on equity to be used
by UE for purposes of an ISRS tariff filing is 10.0%.
Authorization for UE to transition from four PGA rates to
a single PGA rate for all its gas customers.
In February 2008, the MoPSC approved UE’s petition
requesting the establishment of an ISRS to recover annual
revenues of $1 million effective March 29, 2008.
Cost Recovery Mechanisms
A Missouri law enacted in July 2005 enables the
MoPSC to put in place fuel and purchased power and
environmental cost recovery mechanisms for Missouri’s
utilities. The law also includes rate case filing requirements,
a 2.5% annual rate increase cap for the environmental cost
recovery mechanism, and prudency reviews, among other
things. Rules for the fuel and purchased power cost
recovery mechanism were approved by the MoPSC in
September 2006 and became effective during the fourth
quarter of 2006. Rules for the environmental cost recovery
mechanism were approved by the MoPSC in February 2008
and will be effective once published in the Missouri Register.
UE will not be able to use the cost recovery mechanisms
until so authorized by the MoPSC as part of a rate case
proceeding.
Taum Sauk
In June 2007, the MoPSC opened an investigation of
the breach of the upper reservoir at UE’s Taum Sauk
pumped-storage hydroelectric facility in December 2005. In
December 2007, the MoPSC issued an order receiving the
MoPSC staff report on the Taum Sauk incident. The order,
which did not require UE to implement any of the staff
recommendations, noted that UE voluntarily agreed to
implement almost all of the recommendations, and it closed
the investigation. See Note 13 – Commitments and
Contingencies for additional information.
January 2007 Ice Storm Cost Recovery
UE submitted a filing to the MoPSC in November 2007
requesting that operations and maintenance expenses UE
incurred as a result of a severe ice storm in January 2007
be deferred as a regulatory asset and, if approved, be
amortized over five years beginning with the effective date of
electric rates approved in UE’s next rate proceeding. UE
incurred approximately $25 million of operations and
maintenance expenses in the first quarter of 2007 as a result
of the January storm. In January 2008, the MoPSC staff
recommended that the MoPSC grant UE’s request with the
amortization to commence on January 15, 2007. The MoPSC
is expected to issue an order on UE’s filing in 2008. If
approved by the MoPSC, this would only provide UE
approval to defer the expenses incurred as a regulatory
asset. The appropriate amount to be amortized would be
decided in UE’s next rate proceeding.
Illinois
Electric
New electric rates for CIPS, CILCO and IP went into
effect on January 2, 2007, reflecting delivery service tariffs
approved by the ICC in November 2006 and full cost
recovery of power purchased on behalf of Ameren Illinois
Utilities’ customers in the September 2006 auction in
accordance with a January 2006 ICC order. These new
electric rates were expected to raise average annual
residential rates overall in 2007 by 40% to 55% over 2006
rates. The average annual residential rate overall increase for
electric heat customers was expected to be 60% to 80%
over 2006 rates.
Due to the magnitude of these rate increases, various
legislators supported legislation that would have reduced
and frozen CIPS, CILCO and IP electric rates at the levels in
effect prior to January 2, 2007, and would have imposed a
tax on electric generation in Illinois to help fund customer
assistance programs. The Illinois governor also supported
rate rollback and freeze legislation. In July 2007, an
agreement was reached among key stakeholders in Illinois to
avoid such legislation and address the increase in electric
rates and the future power procurement process in Illinois.
The terms of the agreement, which includes a
comprehensive rate relief and customer assistance program,
were set forth in a letter dated July 24, 2007, to the leaders
of the Illinois General Assembly and the Illinois attorney
general. They also appear in a release and settlement
agreement with the Illinois attorney general, in funding
agreements among the parties contributing to the rate relief
and assistance programs, and in legislation that became
effective on August 28, 2007. The following discussion of
the Illinois electric settlement agreement includes its impact
on future power procurement for the Ameren Illinois Utilities
and other significant regulatory and related legal matters that
affect our Illinois electric operations.
Illinois Electric Settlement Agreement
The Illinois electric settlement agreement was the result
of many months of negotiations among leaders of the Illinois
112
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
prior to seeking reimbursement from the Generators. At
December 31, 2007, Ameren, CIPS, CILCO (Illinois
Regulated) and IP had receivable balances from nonaffiliated
Illinois generators for reimbursement of customer rate relief
and program funding of $34 million, $13 million, $7 million
and $14 million, respectively.
The Illinois electric settlement agreement preserves
existing rates and rate structures. The Ameren Illinois
Utilities retain the right to file new electric delivery service
rate cases with the ICC at the respective utility’s discretion.
See Electric and Natural Gas Delivery Service Rate Cases
below for information on pending electric delivery service
rate increase requests filed by the Ameren Illinois Utilities.
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.
As part of the Illinois electric settlement agreement, the
reverse auction used for power procurement in Illinois was
discontinued. It will be replaced with a new power
procurement process to be led by the IPA, beginning in
2009. In 2008, Illinois utilities will contract for necessary
power and energy requirements primarily through a request-
for-proposal process, subject to ICC review and approval.
The ICC approved the proposed 2008 power procurement
plans of the Ameren Illinois Utilities in December 2007.
Existing supply contracts from the September 2006 reverse
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
May 2008, one-third expiring in May 2009 and one-third
expiring in May 2010.
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 around-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 became effective
on August 28, 2007, when legislation in connection with the
Illinois electric settlement agreement became law. Below are
House of Representatives and Senate, the office of the
Illinois attorney general, Ameren, on behalf of its affiliates,
including Marketing Company, Genco and AERG, the Ameren
Illinois Utilities, Exelon Corporation (Exelon), on behalf of
Exelon Generation Company LLC, Commonwealth Edison
Company (Commonwealth Edison), Exelon’s Illinois electric
utility subsidiary, Dynegy Holdings Inc., Midwest Generation,
LLC, and MidAmerican Energy Company. The Illinois electric
settlement agreement provides approximately $1 billion of
funding for rate relief for certain electric customers in
Illinois, including approximately $488 million to customers
of the Ameren Illinois Utilities. Pursuant to the Illinois
electric settlement agreement, the Ameren Illinois Utilities,
Genco and AERG agreed to make aggregate contributions of
$150 million over a 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 AERG. Below is a summary of
the total customer relief and assistance to be provided to the
customers of the Ameren Illinois Utilities, the Ameren Illinois
Utilities’, Genco’s and AERG’s portion of the funding that has
been or is expected to be disbursed, and the earnings per
share impact as a result of the program and agreement.
Total
Relief/Assistance
to Ameren
Illinois
Customers
Ameren
Subsidiaries’
Funding
Ameren
Earnings per
Share Impact
$0.26(a)(b)
0.12(d)
0.06(d)
0.01(d)
2007 . . . . .
2008 . . . . .
2009 . . . . .
2010 . . . . .
$232,000,000
150,000,000
100,000,000
6,000,000
$ 79,000,000(a)(c)
43,000,000(d)
26,000,000(d)
2,000,000(d)
Total . . . . .
$488,000,000
$150,000,000
$0.45
(a)
(b)
Includes a $4.5 million contribution in 2007 towards funding of
a newly created IPA.
Includes $3 million for forgiveness of outstanding customer
late payment fees.
(c) Excludes $3 million for forgiveness of outstanding customer
late payment fees.
(d) Estimated.
The Ameren Illinois Utilities, Genco and AERG will
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 shown
in the above table. Ameren, CIPS, CILCO (Illinois Regulated),
IP, Genco, and CILCO (AERG) incurred charges to earnings,
primarily recorded as a reduction to electric operating
revenues, of $82 million, $12 million, $7 million, $15 million,
$33 million, and $15 million, respectively, under the terms of
the Illinois electric settlement agreement including the
forgiveness of $3 million of outstanding customer late
payments during the year ended December 31, 2007.
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
113
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
1,000 MW
January 1, 2011 – December 31, 2011
1,000 MW
January 1, 2012 – December 31, 2012
$47.45
49.47
49.47
51.09
51.09
52.06
53.08
The financial contracts provide that if any one of the
following events occurs during their term, the Ameren
Illinois Utilities and Marketing Company will meet as soon as
practicable, but no later than 30 days after the date such
event occurs, to identify and discuss its effect on the terms
and conditions of, and prices under the financial contracts:
(a) a state tax on electric generation; (b) a state or federal
tax on and/or regulation of greenhouse gas emissions (e.g.,
a carbon tax); or (c) enactment of an Illinois law that
eliminates retail electric supplier choice for the residential
and small commercial customers of the Ameren Illinois
Utilities. The financial contracts also provide that if any one
of these events occurs, the parties to the financial contracts
will negotiate to determine in a commercially reasonable
manner whether the affected terms, conditions and prices
can be revised so as to preserve the economic benefits of
the financial contracts for all parties and, if so, to revise the
financial contracts accordingly. In the event the parties to the
financial contracts are not able to agree on such revisions,
Marketing Company may terminate the financial contracts by
written notice no earlier than 60 days and no later than
90 days after such event occurs, with the termination being
effective when notice is given. 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.
Beginning in June 2009, power procurement will be
accomplished primarily through competitive requests for
proposals to supply power and energy needs of the utility
instead of the full requirements, load-following supply
contracts previously procured through the reverse auction.
The new power procurement process would require the IPA
to develop an annual Procurement Plan (the Plan) for the
Ameren Illinois Utilities and Commonwealth Edison. Each
Plan would govern a utility’s procurement of power to meet
the expected load requirements that are not met by
preexisting contracts or generation facilities. Subject to ICC
approval, the Ameren Illinois Utilities would be allowed to
lease or invest in generation facilities. The objective of each
Plan would be to ensure adequate, reliable, affordable,
efficient, and environmentally sustainable electric service at
the lowest total cost over time, taking into account any
benefits of price stability for the utilities’ eligible retail
customers. The new power procurement process provides
that each Plan be submitted to the ICC for initial approval; if
it is approved, the final design and implementation of a Plan
would be overseen by an independent procurement
administrator selected by the IPA and a procurement
monitor selected by the ICC. The IPA has broad authority to
assist in the procurement of electric power for residential
and nonresidential customers beginning in June 2009.
Winning proposals will be selected on the basis of price,
compared for reasonableness to benchmarks developed by
the procurement administrator and procurement monitor,
and approved by the ICC.
The power procurement process provides for the
subject electric utility in Illinois to file proposed tariffs with
the ICC, which will be designed 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. All such procurement costs will be deemed to
have been prudently incurred and will be recoverable
through rates.
The Illinois electric settlement agreement provides that
the Ameren Illinois Utilities have a right to maintain
membership in a FERC-approved regional transmission
organization of their choice for a period of at least 15 years.
The Illinois electric settlement agreement also includes
a commitment to energy conservation programs designed to
reduce energy consumption through increased energy
efficiency and demand response. In addition, 2% of the
Illinois utilities’ electricity is to be procured from renewable
sources beginning June 1, 2008, with that percentage
increasing in subsequent years, subject to limits on
customer rate impacts. The provision for full and timely
recovery of the cost of these commitments is also included
in the Illinois electric settlement agreement.
Pursuant to the Illinois electric settlement agreement,
all previously pending litigation and regulatory actions by the
office of the Illinois attorney general relating to the reverse
auction procurement process, which was used to determine
market-based rates effective January 1, 2007, and the
alleged electric space heating marketing practices of the
Ameren Illinois Utilities have been withdrawn with prejudice.
These withdrawn litigation and regulatory actions included
those filed by the office of the attorney general with FERC,
the ICC, the U.S. Court of Appeals for the District of
Columbia Circuit, the Circuit Court of the First Judicial Circuit
Jackson County, Illinois, and the Appellate Court of Illinois,
Second Judicial Circuit.
Finally, the Illinois electric settlement agreement
establishes the authority to obtain accelerated review by the
ICC of a merger or combination of the three Ameren Illinois
Utilities, if it is requested in the future.
Appeals of 2006 ICC Procurement Order
The Illinois attorney general, CUB, and ELPC appealed
to Illinois district appellate courts the ICC’s denial of
rehearing requests with respect to its January 2006 order,
which approved the power procurement auction and related
tariffs. In August 2006, the Supreme Court of Illinois ordered
that the appeals be consolidated in the appellate court for
the Second Judicial Circuit in Illinois. The Illinois attorney
general’s appeal was withdrawn as part of the Illinois electric
114
settlement agreement. In September 2007, the Ameren
Illinois Utilities filed a motion to dismiss the appeals of CUB
and ELPC, which was granted in October 2007. No further
appeals have been filed.
Power Procurement Auction Lawsuits
Ameren, CIPS, CILCO, IP, Commonwealth Edison and
its parent company, Exelon, and 15 other electricity
suppliers, including Marketing Company, which are selling
power to the Illinois utilities pursuant to contracts entered
into as a result of the September 2006 power procurement
auction, were named as defendants in two similar lawsuits.
Plaintiffs were filed in the Circuit Court of Cook County,
Illinois in March 2007, seeking class action status to
represent all customers who purchased electric service from
Commonwealth Edison Company or the Ameren Illinois
Utilities. Both lawsuits alleged, among other things, that the
Illinois utilities and the power suppliers illegally manipulated
prices in the September 2006 power procurement auction.
Plaintiffs sought actual and punitive damages. In December
2007, the U.S. District Court for the Northern District of
Illinois granted the defendants’ motion to dismiss the
lawsuits, and the time to appeal this court decision has
expired.
Redesigned Rates
In late 2007, the ICC issued an order, as amended,
authorizing redesigned electric rates for CIPS, CILCO and IP
that was implemented January 1, 2008. These rates were
designed to allow utilities to recover their full costs while
reducing seasonal fluctuations for residential customers who
use large amounts of electricity. The redesigned rates will
not change total annual revenues collected by the Ameren
Illinois Utilities in 2008 and subsequent years.
Electric and Natural Gas Delivery Service Rate Cases
CIPS, CILCO and IP filed requests with the ICC in
November 2007 to increase their annual revenues for electric
delivery service by $180 million in the aggregate (CIPS –
$31 million, CILCO – $10 million, and IP – $139 million). The
Ameren Illinois Utilities pledged in 2007 to keep overall
residential electric bill increase to less than 10% for each
utility in their next rate filings. These filings are consistent
with that pledge. Accordingly, the requested rate increase for
IP residential customers is to be capped at the 10% increase
level in the first year of the increase, even if the final
authorized rate increase exceeds that amount. This rate
increase limit could result in approximately $30 million of
the requested increase not being phased in until the second
year. The amount of CIPS’ and CILCO’s requested increases
did not require inclusion of similar limits, as they were
within the scope of the pledge. The electric rate increase
requests are based on an 11% return on equity, a capital
structure composed of 51% to 53% equity, an aggregate
rate base for the Ameren Illinois Utilities of $2.1 billion and a
test year ended December 31, 2006, with certain prospective
updates.
CIPS, CILCO and IP filed requests with the ICC in
November 2007 to increase their annual revenues for natural
gas delivery service by $67 million in the aggregate (CIPS –
$15 million increase, CILCO – $4 million decrease and IP –
$56 million increase). The natural gas rate change requests
are based on an 11% return on equity, a capital structure
composed of 51% to 53% equity, an aggregate rate base for
the Ameren Illinois Utilities of $0.9 billion, and a test year
ended December 31, 2006, with certain prospective updates.
In their filings, the Ameren Illinois Utilities have also
requested that the ICC approve to implement mechanisms
that would permit the reconciliation and adjustment of actual
bad debt expenses to those established in rates set by the
ICC for electric and gas customers. The filings also seek a
more timely recovery of investments in existing electric
distribution plant. Because general rate adjustment
proceedings require up to 11 months in Illinois, these
mechanisms would allow current revenues to better match
current costs. In addition, the Ameren Illinois Utilities are
seeking approval of a revenue decoupling rate adjustment
mechanism as a part of their natural gas delivery service
rate change requests. This mechanism would separate each
utility’s fixed cost recovery from the volume of gas it sells
by providing a periodic true-up of revenues. The periodic
true-up would result in adjustments to a utility’s ICC-
approved tariffs based on increases or decreases in demand
for natural gas.
The ICC proceedings relating to the proposed electric
and natural gas delivery service rate changes will take place
over a period of up to 11 months, and decisions by the ICC
in such proceedings are required by the end of September
2008. The Ameren Illinois Utilities cannot predict the level of
any delivery service rate change the ICC may approve, when
any rate change may go into effect, whether any rate
adjustment mechanism discussed above will be approved, or
whether any rate increase eventually approved will be
sufficient for the Ameren Illinois Utilities to recover their
costs and earn a reasonable return on their investments
when the increase goes into effect.
Electric and Natural Gas Energy Efficiency Plans
In November 2007, the Ameren Illinois Utilities filed an
electric energy efficiency and demand response plan with the
ICC. The plan is designed to reduce electricity usage by
specific targeted amounts set forth in the Illinois electric
settlement agreement. The Ameren Illinois Utilities’ spending
limit under this plan for the 2008, 2009 and 2010 program
years is $14 million, $29 million and $45 million,
respectively. In February 2008, the ICC issued an order
approving the Ameren Illinois Utilities’ energy efficiency and
demand response plan, as well as the cost recovery
mechanism by which the program costs will be recovered.
In February 2008, the Ameren Illinois Utilities filed a
natural gas energy efficiency plan with the ICC. The plan was
filed as part of the November 2007 natural gas delivery
service rate cases. The Ameren Illinois Utilities proposed to
offer natural gas energy efficiency programs in conjunction
with a revenue decoupling rate adjustment mechanism. The
115
natural gas energy efficiency plan includes annual reduction
targets in energy usage as well as proposed funding levels
for 2009, 2010, and 2011 of $4 million, $5 million and
$6 million, respectively. The ICC is expected to issue an
order on the Ameren Illinois Utilities’ filing by September
2008.
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
approvals by the MoPSC. The MoPSC required UE to file a
study evaluating the costs and benefits of its participation in
MISO prior to the end of the five-year period. The MoPSC
also directed UE to enter into a service agreement for 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. In
particular, 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 recent 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 based on 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 as 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 MISO
tariff changes proposed by MISO and transmission owners
in MISO. UE intends to request FERC for a rehearing of its
order.
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 that
there were a number of uncertainties associated with the
cost-benefit study, including issues associated with the UE-
MISO service agreement discussed above. If some of these
uncertainties are ultimately resolved in a manner adverse to
UE, it could call into question whether it is cost-effective for
UE to remain in MISO. UE has advised MISO of its intent to
withdraw from MISO as of December 31, 2008, in order to
preserve the option to withdraw based on the outcome of
the pending MoPSC proceeding. It is uncertain when or how
the MoPSC will rule on UE’s MISO cost-benefit study or, if
UE were to withdraw from MISO, what the effect of such a
withdrawal would be on UE.
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 scheduled date 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. FERC has
approved many of the settlements. FERC has rejected none
of the settlements but a number have been pending for
some time. 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 pending
completion of the continuing proceedings at FERC regarding
the allocation of these costs. Other MISO participants also
filed appeals. 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
maintain that MISO is required to reallocate certain of
116
MISO’s operational costs among MISO market participants
resulting in refunds to UE, CIPS, CILCO, and IP. This request
and those of other parties are pending.
UE Power Purchase Agreement with Entergy Arkansas, Inc.
In July 2007, as a consequence of a series of orders
issued by FERC addressing a complaint filed by the
Louisiana Public Service Commission against Entergy
Arkansas, Inc. (Entergy) and certain of its affiliates, which
alleged unjust and unreasonable cost allocations, Entergy
commenced billing UE for additional charges under a
165-megawatt power purchase agreement. The additional
charges to UE were $12 million in 2007. Additional amounts
are expected during the remainder of the term of the power
purchase agreement, which expires effective August 25,
2009. Although UE was not a party to FERC proceedings
that gave rise to these additional charges, UE intervened in
August 2007 in a related FERC proceeding to challenge the
additional charges. UE is unable to predict whether FERC will
grant any relief.
Leveraged Leases
With the acquisition of CILCORP and the merger with
CIPSCO, Ameren acquired interests in certain assets that
were financed as leveraged leases. By orders issued
pursuant to PUHCA 1935, the SEC determined that certain
nonutility interests and investments of CILCORP, CIPSCO
and their subsidiaries, including investments in several
Regulatory Assets and Liabilities
leveraged leases, which primarily consisted of lease interests
in commercial real estate properties and equipment, were
not retainable by Ameren. The SEC orders required that
Ameren cause its subsidiaries to sell or otherwise dispose of
the nonretainable interests. All leveraged leases held by
CILCORP and its subsidiaries that were required to be
divested by an SEC order were sold by the end of 2006.
CILCORP no longer owns any leveraged lease assets. With
respect to the leveraged lease asset subject to a SEC
divestiture order held by CIPSCO, the lessee of the asset
declared bankruptcy and the value of the investment was
written off by Ameren in 2005. CIPSCO had two other
leveraged lease assets that were not subject to an SEC
divestiture order. One of those lease investments was sold in
2007, and one is still owned by CIPSCO.
In 2007, the overall net gain before taxes from the sale
of leveraged lease assets recognized by Ameren was
$4 million. In 2006, the overall net gains (losses) before
taxes from the sale of all leveraged lease assets recognized
by Ameren, CILCORP and CILCO were $3 million,
($7 million), and ($11 million), respectively.
Hydroelectric License Renewal
On March 30, 2007, FERC granted a new 40-year
license for UE’s Osage hydroelectric plant and approved a
settlement agreement among UE, the U.S. Department of the
Interior and various state agencies that was submitted in
May 2005 in support of the license renewal.
In accordance with SFAS No. 71, UE, CIPS, CILCO and IP defer certain costs pursuant to actions of regulators and are
currently recovering such costs in rates charged to customers. The following table presents our regulatory assets and regulatory
liabilities at December 31, 2007 and 2006:
Ameren(a)
UE
CIPS
CILCORP
CILCO
IP
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(k) . . . . . . . . . . . . . . .
SO2 emission allowances sale tracker(l) . . . . . . . . . .
Other(c)(m)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total regulatory assets . . . . . . . . . . . . . . . . . . . . . .
Regulatory liabilities:
Income taxes(n) . . . . . . . . . . . . . . . . . . . . . . . . .
Removal costs(o) . . . . . . . . . . . . . . . . . . . . . . . .
Emission allowances(p)
. . . . . . . . . . . . . . . . . . . .
Pension and postretirement benefit costs(q) . . . . . . .
Financial contracts(r) . . . . . . . . . . . . . . . . . . . . . .
Derivatives marked-to-market(k) . . . . . . . . . . . . . . .
Total regulatory liabilities. . . . . . . . . . . . . . . . . . . . .
$161
248
183
62
28
-
-
-
-
7
8
$697
$162
638
56
8
-
1
$865
$ 75
6
2
-
4
24
-
-
1
-
1
$113
$ 19
208
-
-
38
-
$265
$19
-
1
-
5
5
-
-
-
-
2
$32
$14
60
-
-
18
-
$92
$ 19
-
1
-
5
5
-
-
-
-
2
$ 32
$ 14
188
-
-
18
-
$220
$140
1
2
-
22
77
50
20
2
-
2
$316
$
-
74
-
-
55
-
$129
$ 395
255
188
62
59
106
50
20
3
7
13
$1,158
$ 195
980
56
8
-
1
$1,240
117
2006:
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(k) . . . . . . . . . . . . . . .
Other(c)(m)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total regulatory assets . . . . . . . . . . . . . . . . . . . . . .
Regulatory liabilities:
Income taxes(n) . . . . . . . . . . . . . . . . . . . . . . . . .
Removal costs(o) . . . . . . . . . . . . . . . . . . . . . . . .
Emission allowances(p)
. . . . . . . . . . . . . . . . . . . .
Total regulatory liabilities. . . . . . . . . . . . . . . . . . . . .
Ameren(a)
UE
CIPS
CILCORP
CILCO
IP
$ 647
268
180
66
69
91
67
32
57
11
$1,488
$ 204
915
58
$1,177
$270
260
176
66
31
-
-
-
3
7
$813
$168
598
58
$824
$108
6
2
-
5
25
-
-
8
-
$154
$ 18
198
-
$216
$63
1
1
-
5
3
-
-
9
2
$84
$18
46
-
$64
$ 63
1
1
-
5
3
-
-
9
2
$ 84
$ 18
179
-
$197
$205
1
2
-
28
63
67
32
37
3
$438
$
-
73
-
$ 73
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) See Note 9 – Retirement Benefits for additional information.
(c) These assets do not earn a return.
(d) Amount represents SFAS No. 109 deferred tax asset. See Note 11 – Income Taxes for amortization period.
(e) Represents recoverable costs for AROs at our rate-regulated operations. See Note 1 – Summary of Significant Accounting Policies – Asset
Retirement Obligations.
(f) Represents 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) Represents 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) Represents the recoverable portion of accrued environmental site liabilities, primarily collected from electric and gas customers through
ICC-approved cost recovery riders in Illinois.
(i) Represents 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.
(j) Represents 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 upon the expiration of the electric rate freeze in Illinois on
January 1, 2007.
(k) Represents deferral of SFAS No. 133 natural gas-related derivative mark-to-market gains.
(l) Represents 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.
(m) Represents 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 was amortized over 14 years through 2007. In addition, this amount at December 31,
2006, included the portion of merger-related expenses applicable to the Missouri retail jurisdiction, which were amortized through 2007
based on a MoPSC order.
(n) Represents unamortized portion of investment tax credit and federal excise taxes. See Note 11 – Income Taxes for amortization period.
(o) Represents estimated funds collected for the eventual dismantling and removing 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.
(p) Represents the deferral of gains on emission allowance vintage swaps UE entered into during 2005.
(q) Represents 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.
(r) Represents financial contracts entered into by the Ameren Illinois Utilities with Marketing Company, as part of the Illinois electric settlement
agreement. See Note 2 – Rate and Regulatory Matters for additional information.
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.
118
NOTE 3 – PROPERTY AND PLANT, NET
The following table presents property and plant, net for each of the Ameren Companies at December 31, 2007 and 2006:
Ameren(a)
UE
CIPS
Genco
CILCORP(b)
CILCO
(Illinois
Regulated)
CILCO
(AERG)
IP
2007:
Property and plant, at original cost:
Electric . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . .
$20,544
1,421
354
$12,670
332
290
$1,682
350
5
$2,423
-
4
Less: Accumulated depreciation and
amortization . . . . . . . . . . . . . . . . . .
Construction work in progress:
Nuclear fuel in process . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . .
22,319
13,292
2,037
2,427
8,415
13,904
103
1,062
5,656
7,636
878
972
1,159
1,455
103
450
-
15
-
228
$1,196
209
42
1,447
231
1,216
-
278
$ 921
488
3
1,412
697
715
-
22
$827
-
1
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
2006:
Property and plant, at original cost:
Electric . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . .
$19,973
1,360
108
$12,337
317
63
$1,639
345
5
$2,371
-
3
Less: Accumulated depreciation and
amortization . . . . . . . . . . . . . . . . . .
Construction work in progress:
Nuclear fuel in process . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . .
21,441
12,717
1,989
2,374
7,727
13,714
102
470
5,172
7,545
102
235
845
918
1,144
1,456
-
11
-
83
$1,147
200
41
1,388
193
1,195
-
82
$ 899
479
2
1,380
671
709
-
12
$800
-
1
801
317
484
-
70
$1,648
497
21
2,166
65
2,101
-
33
Property and plant, net . . . . . . . . . . . . .
$14,286
$ 7,882
$1,155
$1,539
$1,277
$ 721
$554
$2,134
(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, 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.
NOTE 4 – CREDIT FACILITIES AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under
$2.15 billion of committed bank credit facilities, and commercial paper issuances.
119
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, 2007 and 2006, respectively, and includes issuances under commercial
paper programs and letters of credit at Ameren, UE, and Genco supported by this credit facility:
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006:
Average daily borrowings outstanding during 2006 . . . . . . . . . . . . . . . . . . . . . . .
Outstanding short-term debt at period end . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak short-term borrowings during 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren
(Parent)
$ 198
550
5.75%
$ 550
8.25%
$ 26
50
5.23%
$ 132
5.55%
UE
Genco
Total
$ 292
82(a)
5.66%
$ 506
8.25%
$ 221
234
5.14%
$ 470
8.25%
$ 22
100
5.43%
$ 100
5.76%
$
$
-
-
-
-
-
$ 512
732(a)
5.68%
$ 856
8.25%
$ 247
287
5.15%
$ 602
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 2006 $500 million credit facility
described below for the years ended December 31, 2007 and 2006, respectively:
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 . . . . . . . . . . . . . . . . .
2006:
Average daily borrowings outstanding during 2006 . . . .
Outstanding short-term debt at period end . . . . . . . . .
Weighted-average interest rate during 2006 . . . . . . . .
Peak short-term borrowings during 2006 . . . . . . . . . .
Peak interest rate during 2006 . . . . . . . . . . . . . . . . .
(a) Amount is less than $1 million
CIPS
$ 98
125
6.52%
$ 135
8.25%
$
(a)
35
6.50%
$ 35
8.25%
CILCORP
(Parent)
CILCO
(Parent)
IP
AERG
Total
$ 49
50
6.89%
$ 50
7.04%
$ 12
50
6.67%
$ 50
6.75%
$ 63
40
6.35%
$ 100
6.47%
$
7
50
6.20%
$ 50
8.25%
$ 63
-
6.56%
$ 125
6.64%
$ 19
75
6.23%
$ 100
8.25%
$ 107
165
6.84%
$ 200
8.25%
$ 27
115
6.68%
$ 130
8.25%
$ 380
380
6.63%
$ 500
8.25%
$ 65
325
6.49%
$ 365
8.25%
The following table summarizes the borrowing activity and relevant interest rates under the 2007 $500 million credit facility
described below for the year ended December 31, 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
$-
-
-
-
-
CILCORP
(Parent)
$ 105
125
6.94%
$ 125
8.63%
CILCO
(Parent)
$ 36
75
6.43%
$ 75
6.47%
IP
$ 134
175
6.59%
$ 200
6.64%
AERG
$ 80
65
6.86%
$ 100
7.02%
Total
$ 355
440
6.74%
$ 500
8.63%
At December 31, 2007, 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
Ameren. The termination date for UE and Genco is July 10,
2008, 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.
120
Ameren, UE and Genco will use the proceeds of any
borrowings under the facility for general corporate purposes,
including for working capital, commercial paper liquidity
support, and to fund loans under the Ameren money pool
arrangements.
CIPS, CILCORP, CILCO, IP and AERG are parties to a
$500 million multiyear, senior secured credit facility expiring
in 2010 (the 2006 $500 million credit facility).
CIPS, CILCORP, CILCO, IP and AERG are parties to
another $500 million multiyear, senior secured credit facility
(the 2007 $500 million credit facility), also expiring in
January 2010.
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 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 mortgage bonds in the amounts of
$75 million and $200 million, respectively. If CIPS or CILCO
elect to transfer borrowing authority from the 2006
$500 million credit facility to the 2007 $500 million credit
facility, that company 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.
The $1.15 billion credit facility is used to support the
commercial paper programs of Ameren and UE. 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. 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.
Indebtedness Provisions and Other Covenants
The Ameren Companies’ bank credit facilities contain
provisions that, among other things, place restrictions on
the 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, AERG and IP 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.
121
Both the 2006 $500 million credit facility and the 2007
$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), and an
event of default under these facilities does not constitute an
event of default under the $1.15 billion credit facility and
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,
have received a below-investment-grade credit rating by
either Moody’s or S&P, then each such borrower will be
limited to capital 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,
2007, AERG was in compliance with this test in the 2006
$500 million credit facility and the 2007 $500 million credit
facility. CIPS, CILCO and IP are not currently limited in their
dividend payments by this provision of the 2006 $500 million
or 2007 $500 million credit facilities. Ameren’s access to
dividends from CILCO and AERG would be 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
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 (a) 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 (b) 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 giving effect
to 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.
The 2007 $500 million credit facility provides that CIPS,
CILCO and IP will agree to reserve future bonding capacity
under their respective mortgage indentures (that is, they
agree to forgo the issuance of additional mortgage bonds
otherwise permitted under the terms of each mortgage
indenture) in the following amounts (subject to, in the case
of CIPS and CILCO, their then current borrowing sublimits
under the facility and similar provisions in the 2006 facility):
CIPS, prior to December 31, 2007 – $50 million, on and after
December 31, 2007, but prior to December 31, 2008 –
$100 million, on and after December 31, 2008, but prior to
December 31, 2009 – $150 million, on and after
December 31, 2009 – $200 million; CILCO, prior to
December 31, 2007 – $25 million, on and after December 31,
2007, but prior to December 31, 2008 – $50 million, on and
after December 31, 2008, but prior to December 31, 2009 –
$75 million, on and after December 31, 2009 – $150 million;
and IP, prior to December 31, 2008 – $100 million, on and
after December 31, 2008, but prior to December 31, 2009 –
$200 million, on and after December 31, 2009 – $350 million.
The 2006 $500 million credit facility provides that CIPS,
CILCO and IP will agree to reserve future bonding capacity
under their respective mortgage indentures in the following
amounts: CIPS, prior to December 31, 2007 – $50 million,
on and after December 31, 2007, but prior to December 31,
2008 – $100 million, on and after December 31, 2008 –
$150 million; CILCO – $25 million; and IP – $100 million.
Pursuant to a waiver dated November 16, 2007, CIPS
was granted relief from complying with the covenant
contained in the 2006 and 2007 credit agreements requiring
CIPS to reserve future bonding capacity under its mortgage
indenture as discussed above. The waiver is scheduled to
expire on March 31, 2008.
As of December 31, 2007, 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 52%, 47% and 46%,
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 54%, 58%, 45%, 49% and 39%,
respectively.
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, 2007, the Ameren
Companies were in compliance with their credit facility
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
operation and administration of the money pool agreements.
122
Utility
Through the utility money pool, the pool participants
may access the committed credit facilities. CIPS, CILCO and
IP borrow from each other through the utility money pool
agreement subject to applicable regulatory short-term
borrowing authorizations. Although UE and Ameren Services
are parties to the utility money pool agreement, they are not
currently borrowing or lending under the agreement. 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 remit 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,
2007, was 5.80% (2006 – 5.03%).
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
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. At December 31, 2007, $409 million was
available through the non-state-regulated subsidiary money
pool, excluding additional funds available through excess
cash balances. The non-state-regulated subsidiary money
pool was established to coordinate and to provide for short-
term cash and working capital requirements of Ameren’s
non-state-regulated activities. It is administered by Ameren
Services. 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. Ameren and CILCORP
are authorized to act only as lenders to the non-state-
regulated subsidiary money pool. The average interest rate
for borrowing under the non-state-regulated subsidiary
money pool for the year ended December 31, 2007 was
5.14% (2006 – 4.65%).
See Note 12 – 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, 2007, 2006, and 2005.
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 agreements.
123
NOTE 5 — LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding for the Ameren Companies as of December 31, 2007 and 2006:
2007
2006
Ameren Corporation (parent):
2002 5.70% notes due 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Senior notes due 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
-
-
-
-
-
UE:
First mortgage bonds:(a)
6.75% Series due 2008. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 148
5.25% Senior secured notes due 2012(b)
173
4.65% Senior secured notes due 2013(b)
200
5.50% Senior secured notes due 2014(b)
104
4.75% Senior secured notes due 2015(b)
114
5.40% Senior secured notes due 2016(b)
260
6.40% Senior secured notes due 2017(b)
425
5.10% Senior secured notes due 2018(b)
200
5.10% Senior secured notes due 2019(b)
300
5.00% Senior secured notes due 2020(b)
85
5.45% Series due 2028(c)
44
5.50% Senior secured notes due 2034(b)
184
5.30% Senior secured notes due 2037(b)
300
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
43
47
60
50
50
64
63
60
66
Capital lease obligations:
City of Bowling Green capital lease (Peno Creek CT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audrain County capital lease (Audrain County CT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86
240
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,366
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(6)
(152)
$ 100
250
350
(350)
$
-
$ 148
173
200
104
114
260
-
200
300
85
44
184
300
43
47
60
50
50
64
63
60
66
90
240
2,945
(6)
(5)
Long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,208
$2,934
124
2007
2006
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)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15
150
40
60
61
$
Environmental improvement and pollution control revenue bonds:
2004 Series due 2025(a)(b)(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2000 Series A 5.50% due 2014(f)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1993 Series C-1 5.95% due 2026(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35
51
35
8
17
472
(1)
(15)
15
150
40
60
61
35
51
35
8
17
472
(1)
-
Long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 456
$ 471
Genco:
Unsecured notes:
Senior notes Series D 8.35% due 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 200
275
Senior notes Series F 7.95% due 2032 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
475
(1)
$ 200
275
475
(1)
Long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 474
$ 474
CILCORP (parent):(g)
Unsecured notes:
8.70% Senior notes due 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 124
210
9.375% Senior bonds due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
55
Fair-market value adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 389
CILCO:
First mortgage bonds:(a)
7.50% Series due 2007. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
54
42
19
1
32
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
148
-
Long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 148
CILCORP consolidated long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 537
$ 124
210
60
$ 394
$
50
54
42
19
1
32
198
(50)
$ 148
$ 542
125
2007
2006
IP:
Mortgage bonds:(a)
7.50% Series due 2009. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 250
6.25% Senior secured notes due 2016(b)
75
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.125% Senior secured notes due 2017(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
250
$ 250
75
-
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
36
19
33
150
112
75
18
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,018
(4)
36
19
33
150
112
75
26
776
(4)
Long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,014
$ 772
Long-term debt payable to IP SPT:
5.54% due 2007 A-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
86
(32)
2
56
(54)
Long-term debt payable to IP SPT, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2
Ameren consolidated long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,691
$
33
139
(35)
6
143
(51)
$
92
$5,285
(a) At December 31, 2007, 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 – 6.75% Series due 2008 and 5.45%
Series due 2028 (callable in October 2008 at 102% of par declining to 101% of par in October 2009 and 100% of par in October 2010);
CIPS – 7.61% Series 1997-2 due 2017 (callable in June 2007 at 103.81% of par declining annually thereafter to 100% of par in June
2012); CILCO – 7.50% Series due 2007, 6.20% Series 1992B due 2012 (currently callable at 100% of par) and 5.90% Series 1993 due
2023 (currently callable at 100% of par); IP – 7.50% Series due 2009 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%
(d)
series, CILCO’s 6.20% Series 1992B, and 5.90% Series 1993 bonds are backed by an insurance guarantee policy.
Interest rates, and the periods during which such rates apply, vary depending on our selection of certain defined rate modes. As of
December 31, 2007, the interest rates on these securities were being set through an auction-rate mode. Maximum interest rates could
range up to 18% depending upon the series of bonds. The average interest rates for the years 2007 and 2006 were as follows:
2007
2006
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 . . . . . . . . . . . . . . . . . . . .
CIPS’ Series B-1 had a fixed interest rate until November 2006.
3.66% 3.34% CIPS Series 2004 . . . . . . . . . . . . . . . . . . . .
3.72% 3.35% CIPS Series B-1 . . . . . . . . . . . . . . . . . . . . .
3.69% 3.41% CILCO Series 2004 . . . . . . . . . . . . . . . . . . .
3.66% 3.42% IP 1997 Series A . . . . . . . . . . . . . . . . . . . . .
3.66% 3.32% IP 1997 Series B . . . . . . . . . . . . . . . . . . . . .
3.55% 3.29% IP 1997 Series C . . . . . . . . . . . . . . . . . . . . .
3.55% 3.26% IP Series 2001 (AMT) . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . .
3.56% 3.32% IP Series 2001 (Non-AMT)
2007
2006
3.68% 3.36%
3.25% 3.81%
3.68% 3.36%
3.93% 3.56%
3.89% 3.50%
3.84% 3.52%
3.89% 3.50%
3.69% 3.38%
(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) Variable-rate tax-exempt pollution control indebtedness that was converted to long-term fixed rates.
(g) CILCORP’s long-term debt is secured by a pledge of the common stock of CILCO.
126
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren
Companies at December 31, 2007:
2008 . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . .
UE
CIPS
Genco
$ 152
4
4
4
178
3,024
$3,366(a)
$ 15
-
-
150
-
307
$472(a)
$
-
-
200
-
-
275
$475(a)
CILCORP
(parent)
$
-
124
-
-
-
210
$334(b)
CILCO
IP
Ameren
Consolidated
$
-
-
-
-
1
147
$148
$
54
250
-
-
-
750
$1,054(a)(c)
$ 221
378
204
154
179
4,713
$5,849
(a) Excludes unamortized discount and premium of $6 million, $1 million, $1 million, and $4 million at UE, CIPS, Genco, and IP, respectively.
(b) Excludes $55 million related to CILCORP’s long-term debt fair market value adjustments.
(c) Excludes $20 million related to IP’s long-term debt fair market value adjustments and includes $32 million for TFN overfunding.
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 – Credit Facilities and Liquidity for a
discussion of external financing availability.
The following table presents the authorized amounts
under Form S-3 shelf registration statements filed and
declared effective for Ameren Companies that have
authorized amounts as of December 31, 2007:
Effective
Date
Authorized
Amount
Issued
Available
Ameren . . . .
June 2004
UE . . . . . . . October 2005
May 2001
CIPS . . . . . .
$2,000
1,000
250
$459
685
211
$1,541
315
39
Ameren
In June 2004, the SEC declared effective a Form S-3
shelf registration statement filed by Ameren and its
subsidiary trusts covering the offering from time to time of
up to $2 billion of various types of securities, including long-
term debt, trust preferred securities, and equity securities.
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, 2007, the remaining unamortized
balance of the fair market value adjustments for CILCORP
and IP were $55 million and $20 million, respectively.
The following table presents the amortization of the
CILCORP and IP fair value adjustments for the succeeding
five years:
CILCORP
IP
2008. . . . . . . . . . . . . . . . . . . . . . . . . . .
2009. . . . . . . . . . . . . . . . . . . . . . . . . . .
2010. . . . . . . . . . . . . . . . . . . . . . . . . . .
2011. . . . . . . . . . . . . . . . . . . . . . . . . . .
2012. . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . .
$6
5
2
2
2
38
$10
5
(a)
(a)
(a)
5
(a) Amount is less than $1 million.
In March 2004, the SEC declared effective a Form S-3
registration statement filed by Ameren, authorizing the
offering of 6 million additional shares of its common stock
under DRPlus. Shares of common stock sold under DRPlus
are, at Ameren’s option, newly issued shares or 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 subsidiary-related plans that are now merged into
the Ameren 401(k) plan), Ameren issued 1.7 million,
1.9 million, and 2.1 million shares of common stock in
2007, 2006, and 2005, respectively, which were valued at
$91 million, $96 million, and $109 million for the respective
years.
In December 2006, Ameren terminated interest rate
swap transactions that were entered into in March 2002 to
effectively convert its 5.70% fixed-rate notes to variable rate.
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 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. As
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. UE as the lessee is responsible for rental
payments under the lease in an amount sufficient to service
the debt of a taxable industrial development revenue bond
(principal amount of $240 million outstanding as of
December 31, 2007) issued to NRG by Audrain County in
exchange for title to the NRG CT facility. As part of this
127
acquisition, UE acquired the bond from NRG. Because rental
payments are equal to debt service on the bond, there is no
net cash expense relating to this lease. No capital was
initially raised in the leasing transaction, and no capital was
raised as a result of UE’s assumption of NRG’s lease
obligations.
In June 2007, UE issued, pursuant to its October 2005
SEC Form S-3 shelf registration statement, $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. 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, for so long
as those senior secured notes are outstanding, that 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). Any interest
rate increase on these senior secured notes will take effect
on the first day of the interest period during which such
rating downgrade requires an increase in the interest rate.
CIPS
In June 2006, CIPS issued and sold, pursuant to an
effective SEC Form S-3 registration statement, $61 million of
6.70% senior secured notes due June 15, 2036, with
interest payable semi-annually on June 15 and December 15
of each year, beginning in December 2006. These notes are
secured by first mortgage bonds, which are subject to
fallaway provisions, as defined in the related financing
agreements. CIPS received net proceeds of $60 million,
which were used, along with other funds, to repay in full
CIPS’ intercompany note payable to UE.
Also in June 2006, $20 million of CIPS’ 7.05% first
mortgage bonds matured and were retired.
See Note 4 – Credit Facilities and Liquidity regarding
CIPS agreement under the 2007 $500 million credit facility
and the 2006 $500 million credit facility to reserve future
bonding capacity under the mortgage. As a result of
restrictions in the 2007 and 2006 $500 million credit
facilities, CIPS can only issue first mortgage bonds based
upon retired bond capacity of $3 million and/or to refinance
first mortgage bonds currently outstanding.
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
$7 million for the years ended December 31, 2007, 2006,
and 2005, respectively, and costs related to repayments
were $- million, $2 million, and $8 million for the years
ended December 31, 2007, 2006, and 2005, respectively.
These amounts were included in interest expense in the
Consolidated Statements of Income of Ameren and CILCORP.
In March 2006, CILCORP repurchased $2 million in
principal amount of its 9.375% senior bonds due 2029, and
in April 2006, CILCORP repurchased an additional $7 million
in principal amount of these bonds.
See Note 4 – Credit Facilities 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.
CILCO
In each of July 2007, July 2006, and July 2005, 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. These redemptions satisfied CILCO’s
mandatory sinking fund redemption requirement for this
series of preferred stock for each year.
In January 2007, $50 million of CILCO’s 7.50% first
mortgage bonds matured and were retired.
In June 2006, CILCO issued and sold, with registration
rights in a private placement, $54 million of 6.20% senior
secured notes due June 15, 2016, and $42 million of
6.70% senior secured notes due June 15, 2036, both with
interest payable semi-annually on June 15 and December 15
of each year, beginning in December 2006. These notes are
secured by first mortgage bonds, which are subject to
fallaway provisions as defined in the related financing
agreements. CILCO received total net proceeds of $94 million,
which were used to reduce short-term money pool
borrowings and, in July 2006, to redeem CILCO’s $20 million
7.73% secured medium-term notes due 2025. CILCO
exchanged the outstanding unregistered senior secured notes
for registered secured notes on November 16, 2006.
In December 2006, CIPS repurchased all $17 million of
its 1993 Series B-1 Illinois Finance Authority bonds pursuant
to a mandatory tender. Interest payments are being made
monthly by CIPS. The receivable for this repurchased bond
is in Other Current Assets on CIPS’ balance sheet.
See Note 4 – Credit Facilities and Liquidity regarding
CILCO’s agreement under the 2007 $500 million credit
facility and the 2006 $500 million credit facility to reserve
future bonding capacity under its mortgage and regarding
the mortgage and security interest in its power plants issued
128
by AERG as security for its obligations under the 2006
$500 million credit facility and the 2007 $500 million credit
facility.
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 $12 million, $13 million, and $16 million
for the years ended December 31, 2007, 2006, and 2005,
respectively, and was included in interest expense in the
consolidated statements of income of Ameren and IP.
In June 2006, IP issued and sold, with registration
rights in a private placement, $75 million of 6.25% senior
secured notes due June 15, 2016, with interest payable
semi-annually on June 15 and December 15 of each year,
beginning in December 2006. These notes are secured by
mortgage bonds, which are subject to fallaway provisions as
defined in the related financing agreements. IP received net
proceeds of $74 million, which were used to reduce short-
term money pool borrowings. IP exchanged the outstanding
unregistered senior secured notes for registered secured
notes on November 16, 2006.
In November 2007, IP issued and sold, with registration
rights in a private placement, $250 million of 6.125% senior
Indenture Provisions and Other Covenants
secured notes due November 15, 2017, with interest payable
semi-annually on May 15 and November 15 of each year,
beginning May 15, 2008. These notes are 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.
See Note 4 – Credit Facilities and Liquidity regarding
IP’s agreement under the 2007 $500 million credit facility
and the 2006 $500 million credit facility to reserve future
bonding capacity under its mortgage indenture.
In December 1998, the IP SPT issued $864 million of
TFNs, as allowed under the Illinois Electric Utility Transition
Funding Law. In accordance with the Transitional Funding
Securitization Financing Agreement, IP must designate a
portion of the cash received from customer billings to fund
payment of the TFNs. The amounts received are remitted to
the IP SPT and are restricted for the sole purpose of paying
down the TFNs. Due to the adoption of FIN No. 46R and
resulting deconsolidation of IP SPT, restricted cash associated
with amounts collected is netted against the current portion
of IP’s long-term debt payable to IP SPT on IP’s December 31,
2007 and 2006, consolidated balance sheets.
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. 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, 2007, at an assumed interest and dividend rate of 7%.
Required Interest
Coverage Ratio(a)
Actual Interest
Coverage Ratio
Bonds Issuable(b)
Required Dividend
Coverage Ratio(c)
Actual Dividend
Coverage Ratio
Preferred Stock
Issuable
UE . . . . . . . . . . . .
CIPS . . . . . . . . . . .
CILCO . . . . . . . . . .
IP . . . . . . . . . . . . .
(cid:2)2.0
(cid:2)2.0
(cid:2)2.0(d)
(cid:2)2.0
4.0
1.9
13.8
3.4
$2,108
-
59
326
(cid:2)2.5
(cid:2)1.5
(cid:2)2.5
(cid:2)1.5
48.3
1.4
40.7
1.2
$1,556
-
407(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) Amounts are net of future bonding capacity restrictions agreed to by CIPS, CILCO and IP under the 2007 $500 million credit facility and the
2006 $500 million credit facility entered into by these companies. Amount of bonds issuable based on either meeting required coverage
ratios or unfunded property additions, whichever is more restrictive. In addition to these tests, UE, CIPS, CILCO and IP have the ability to
issue bonds based upon retired bond capacity of $15 million, $3 million, $175 million and $664 million, respectively, for which no earnings
coverage test is required. See Note 4 – Credit Facilities and Liquidity for additional information.
(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, 2007, CILCO had earnings
equivalent to at least 42% of the principal amount of all mortgage bonds outstanding.
(d)
(e) See Note 4 – Credit Facilities 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, 2007.
The IP SPT TFNs contain restrictions that prohibit IP
LLC from making any loan or advance to, or certain
investments in, any other person. Also, as long as the TFNs
are outstanding, the IP SPT shall not, directly or indirectly,
129
pay any dividend or make any distribution (by reduction of
capital or otherwise) to any owner of a beneficial interest in
the IP SPT.
Genco’s and CILCORP’s indentures include provisions
that require the companies to maintain certain debt service
coverage and debt-to-capital ratios in order for the
companies to pay dividends, to make certain principal or
interest payments, to make certain loans to affiliates, or to
incur additional indebtedness. The following table
summarizes these ratios for the 12 months ended
December 31, 2007:
Required
Interest
Coverage
Ratio
Actual
Interest
Coverage
Ratio
Genco(a) . . . . . . . (cid:2)1.75(b)
CILCORP(c) . . . . . (cid:2) 2.2
7.0
3.3
Required
Debt-to-
Capital
Ratio
(cid:2)60%
(cid:2)67%
Actual
Debt-to-
Capital
Ratio
40%
28%
(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 and must be met for both the prior four fiscal
quarters and for the succeeding four six-month periods.
(c) CILCORP must maintain the required interest coverage ratio
and debt-to-capital ratio in order to make any payment of
NOTE 6 – OTHER INCOME AND EXPENSES
dividends or intercompany loans to affiliates other than to its
direct or indirect subsidiaries.
Genco’s ratio restrictions under its indenture may be
disregarded if both Moody’s and S&P reaffirm the ratings of
Genco in place at the time of the debt incurrence after
considering the additional indebtedness. In the event
CILCORP is not in compliance with these tests, CILCORP
may 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,
2007, CILCORP’s senior long-term debt ratings from S&P,
Moody’s and Fitch were B+, Ba2, and BB+, 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, 2007, 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, 2007, 2006 and 2005:
Ameren:(a)
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income on industrial development revenue bonds. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for equity funds used during construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Donations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE:
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income on industrial development revenue bonds. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for equity funds used during construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Donations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
2006
2005
$ 27
28
5
17
$ 77
$ (3)
(7)
$(10)
$ 4
28
4
2
$ 38
$ (2)
(5)
$ (7)
$ 10
28
4
8
$ 50
$ (2)
(2)
$ (4)
$
3
28
3
4
$ 38
$ (1)
(7)
$ (8)
$ 10
3
12
4
$ 29
$ (6)
(6)
$(12)
$ 7
-
11
4
$ 22
$ (1)
(6)
$ (7)
130
2007
2006
2005
CIPS:
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
Miscellaneous income:
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP:
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO:
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP:
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for equity funds used during construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
$ 16
1
$ 17
$ (3)
$ (3)
$ 2
$ 2
$ 4
1
$ 5
$ (6)
$ (6)
$ 4
1
$ 5
$ (7)
$ (7)
$ 8
-
6
$ 14
$ (5)
$ (5)
$ 15
2
$ 17
$ (2)
$ (2)
$
$
$
$
-
-
2
-
2
$ (5)
$ (5)
$
$
1
-
1
$ (5)
$ (5)
$
$
4
-
2
6
$ (4)
$ (4)
$ 17
1
$ 18
$ (4)
$ (4)
$ 1
$ 1
$
$
-
-
-
$ (6)
$ (6)
$
$
-
-
-
$ (5)
$ (5)
$ 4
1
2
$ 7
$ (3)
$ (3)
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 cause any of the following:
(cid:129)
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;
(cid:129) 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.
(cid:129)
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
do not qualify for hedge accounting or the normal purchase
and sales exceptions under SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” as amended.
Accordingly, such contracts are recorded at fair value
with changes in the fair value charged or credited to the
131
income statement in the period in which the change
occurred. 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, 2007, 2006 and 2005, 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 due to transactions being delivered or
settled:
Gains (Losses)
2007
2006
2005
Ameren . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . .
$40
-
-
-
$ 9
11
2
(7)
$6
-
1
-
The following table presents the carrying value of all derivative instruments and the amount of pretax net gains on
derivative instruments in Accumulated OCI for cash flow hedges as of December 31, 2007 and 2006:
Ameren(a)
UE
CIPS
Genco
CILCORP/
CILCO
2007:
Derivative instruments carrying value:
Other current assets . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . .
Gains (losses) deferred in Accumulated OCI:
Power forwards(b) . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate swaps(c)(d)
. . . . . . . . . . . . . . . . . . . .
Gas swaps and futures contracts(e) . . . . . . . . . . . . .
Coal options . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gains (losses) deferred in regulatory assets or liabilities:
Gas forwards and futures contracts . . . . . . . . . . . . .
Financial contracts(f)
. . . . . . . . . . . . . . . . . . . . . .
2006:
Derivative instruments carrying value:
Other current assets . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . .
Gains (losses) deferred in Accumulated OCI:
Power forwards(b) . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate swaps(c) . . . . . . . . . . . . . . . . . . . . . .
Gas swaps and futures contracts(d) . . . . . . . . . . . . .
SO2 futures contracts . . . . . . . . . . . . . . . . . . . . . .
Losses deferred in regulatory assets or liabilities:
Gas forwards and futures contracts . . . . . . . . . . . . .
$ 35
9
24
7
15
(2)
-
1
(2)
-
$ 91
16
65
7
87
3
5
(1)
(57)
$ 7
1
1
-
4
-
-
1
1
-
$17
1
9
-
10
-
1
-
$ 1
38
1
-
-
-
-
-
(1)
40
$ 2
-
7
2
-
-
2
-
(3)
(8)
$ 2
-
6
-
-
(2)
-
-
-
-
$ 2
1
1
-
3
3
-
(1)
-
IP
$ 2
61
8
-
-
-
-
-
(2)
57
$
-
-
32
4
-
-
-
-
$ 2
20
1
-
-
-
1
-
-
19
$ 5
2
10
-
-
-
6
-
(9)
(37)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to three years, including
(c)
(d)
$15 million in 2008.
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, 2007 was $3 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 future debt issuances. The cumulative gain and loss on the interest rate swaps will be amortized over
a 10-year period that begins when the debt is issued. The carrying value at December 31, 2007 was $(5) million.
(e) Represents gains associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements
through March 2011.
(f) Current amounts of $2 million at CIPS, $1 million at CILCO, and $2 million at IP were recorded in Other Current Liabilities at December 31,
2007.
132
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 swap are eliminated. See Note 2 – Rate and
Regulatory Matters for additional information on these
financial contracts.
Other Derivatives
The following table represents the net change in market
value for the years ended December 31, 2007, 2006 and
2005, of option and swap transactions used to manage our
positions in SO2 allowances, coal, heating oil, 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
change in the market value of power options is recorded in
Operating Revenues – Electric, 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)
2007
2006
2005
SO2 options and swaps:
Ameren(a)
. . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . .
Coal options:
Ameren(a)
. . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . .
Heating oil options:
Ameren(a)
. . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . .
Nonhedge power swaps and
$ 8
6
1
2
2
6
1
1
$(2)
4
(4)
(2)
(2)
(2)
-
-
forwards:
Ameren(a)
. . . . . . . . . . . . . . . . .
(2)
-
$ 2
4
(2)
(1)
(1)
-
-
-
-
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries and intercompany eliminations.
Through the market allocation process, UE, CIPS,
Genco, CILCO and IP have been granted FTRs associated
with the MISO Day Two Energy Market. Marketing Company
has acquired FTRs for its participation in the PJM-Northern
Illinois portion of the market. The FTRs are intended to
hedge electric transmission congestion charges related to
our delivery of electricity. Depending on the congestion on
the electric transmission grid and prices at various points on
such grid, FTRs could result in either charges or credits. We
use complex grid modeling tools to determine which FTRs
we wish to nominate in the FTR allocation process. There is
a risk that we may incorrectly model the amount of FTRs we
need, and there is the potential that some of the FTR hedges
could be ineffective. FTRs are considered derivatives. As of
December 31, 2007, the net value of FTRs held by the
Ameren Companies was determined to be immaterial.
NOTE 8 – STOCKHOLDER RIGHTS PLAN AND PREFERRED
STOCK
Stockholder Rights Plan
Ameren’s board of directors has adopted a share
purchase rights plan designed to assure stockholders of fair
and equal treatment in the event of a proposed takeover. The
rights are exercisable only if a person or group acquires
15% or more of Ameren’s outstanding common stock or
announces a tender offer that would result in ownership by a
person or group of 15% or more of the Ameren common
stock. Each right will entitle the holder to purchase one one-
hundredth of a newly issued preferred share at an exercise
price of $180. If a person or group acquires 15% or more of
Ameren’s outstanding common stock, each right will entitle
its holder (other than such person or members of such
group) to purchase, at the right’s then-current exercise price,
a number of Ameren’s common shares having a market
value of twice such price. In addition, if Ameren is acquired
in a merger or other business combination transaction after
a person or group has acquired 15% or more of Ameren’s
outstanding common stock, each right will entitle its holder
to purchase, at the right’s then-current exercise price, a
number of the acquiring company’s common shares having
a market value of twice such price. The acquiring person or
group will not be entitled to exercise these rights. These
rights expire in October 2008. One right will accompany
each new share of Ameren common stock prior to such
expiration date.
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 authorized of $1 par value preference stock and
CILCO has 2 million shares authorized of no par value
preference stock, with no such preference stock outstanding.
IP has 5 million shares authorized of no par value serial
preferred stock and 5 million shares authorized of no par
value preference stock, with no such serial preferred stock
and preference stock outstanding. No shares of preference
stock have been issued by any of the Ameren Companies.
133
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, 2007 and 2006:
Redemption Price (per share)
2007
2006
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
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 . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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
150,000 shares . . . . . . . . . . . . . . . . . .
50,000 shares . . . . . . . . . . . . . . . . . .
75,000 shares . . . . . . . . . . . . . . . . . .
50,000 shares . . . . . . . . . . . . . . . . . .
50,000 shares . . . . . . . . . . . . . . . . . .
125,000 shares . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO:
With par value of $100 per share, 1.5 million shares authorized
$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
4.50% Series
4.64% Series
111,264 shares . . . . . . . . . . . . . . . . . .
79,940 shares . . . . . . . . . . . . . . . . . .
$110.00
102.00
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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
225,510 shares . . . . . . . . . . . . . . . . . .
143,760 shares . . . . . . . . . . . . . . . . . .
104,280 shares . . . . . . . . . . . . . . . . . .
102,190 shares . . . . . . . . . . . . . . . . . .
145,170 shares . . . . . . . . . . . . . . . . . .
191,765 shares . . . . . . . . . . . . . . . . . .
$ 51.50
52.00
51.50
51.50
51.50
50.00
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Shares of IP preferred stock owned by Ameren(c) . . . . . . . . . . . . . . .
Total Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
In the event of voluntary liquidation, $105.50.
(a)
(b) Declining to $100 per share in 2012.
(c) Ameren purchased 662,924 shares of IP’s preferred stock on September 30, 2004.
$ 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
(33)
$195
$ 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
(33)
$195
The following table presents the outstanding preferred stock of CILCO that is subject to mandatory redemption. The
preferred stock is entitled to cumulative dividends and is redeemable, at a determinable price on a fixed date or dates, at the
prices presented as of December 31, 2007 and 2006, respectively:
CILCO:(a)
Without par value and stated value of $100 per share, 3.5 million shares authorized:
5.85% Series
180,000 shares . . . . . . . . . . . . . . . . . .
$100.00(b)
$16
$17
Redemption Price (per share)
2007
2006
(a) Beginning July 1, 2003, this preferred stock became redeemable, at the option of CILCO, at $100 per share. A mandatory redemption fund
was established on July 1, 2003. The fund provides for the redemption of 11,000 shares for $1.1 million on July 1 of each year through
July 1, 2007. On July 1, 2008, the remaining shares outstanding will be retired for $16.5 million.
In the event of voluntary or involuntary liquidation, the stockholder receives $100 per share plus accrued dividends.
(b)
134
NOTE 9 – 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 and to 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, Ameren recorded the unfunded obligation of its defined benefit and postretirement benefit plans. The unfunded
obligation is the difference between the projected benefit obligation for defined benefit plans or accumulated postretirement
benefit obligation for postretirement benefit plans and each plan’s assets. 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 and CILCO recorded regulatory assets of $270 million, $108 million and $63 million, respectively, based on the expected
recovery of these costs from ratepayers. The adoption of SFAS No. 158 had no 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. 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 to 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 federal funding requirements. In May 2007, the MoPSC issued an electric rate order
for UE that allows UE to recover through customer rates pension expense incurred under GAAP. Ameren expects to fund its
pension plans at a level equal to the pension expense. Based on Ameren’s assumptions at December 31, 2007, and reflecting
this pension funding policy, Ameren expects annual contributions of $40 million to $65 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 65%, 8%, 11%, 5% and 11%,
respectively. These amounts are estimates and may change with actual stock market 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, 2007:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
$839
297
67
32
127
127
189
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
135
The following table presents the funded status of our pension and postretirement benefit plans for the years ended
December 31, 2007 and 2006:
2007
2006
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) . . . . . . . . . . . . . . .
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(b) . . . . . . . . . . . . . . .
Fair value of plan assets at end of year . . .
Funded status – deficiency . . . . . . . . . . .
$3,120
63
180
3
-
(126)
(164)
-
3,076
2,837
2,608
202
50
-
-
(162)
2,698
378
$1,297
21
72
-
12
(83)
(71)
5
1,253
(c)
742
49
49
4
12
(69)
787
466
$3,106
63
173
-
-
(65)
(157)
-
3,120
2,859
2,468
295
-
-
-
(155)
2,608
512
$1,317
22
72
(12)
10
(45)
(72)
5
1,297
(c)
653
69
74
5
10
(69)
742
555
Accrued benefit cost at December 31 . . . .
$ 378
$ 466
$ 512
$ 555
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
375
$ 378
$ 142
49
-
(34)
10
-
$
2
464
$ 466
$ 233
(45)
16
17
(20)
-
$
2
510
$ 512
$ 284
56
-
(14)
8
-
$
-
555
$ 555
$ 341
(54)
20
36
(24)
(7)
Total . . . . . . . . . . . . . . . . . . . . . . .
$ 167
$ 201
$ 334
$ 312
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Excludes amounts paid from company funds.
(c) Not applicable.
None of the plan assets are expected to be returned to Ameren during 2008.
Downgrades of subprime U.S. mortgage-related assets have resulted in a decline in the fair value of subprime-related
investments. The Ameren Companies have assessed their investments held in trusts related to Ameren’s pension and
postretirement benefit plans and determined that direct exposure to subprime mortgages was not material.
136
The following table presents the assumptions used to determine our benefit obligations at December 31, 2007 and 2006:
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
2007
6.15%
4.00
-
-
-
2006
5.85%
4.00
-
-
-
Postretirement
Benefits
2007
2006
6.05%
4.00
9.00
5.00
4 years
5.80%
4.00
9.00
5.00
4 years
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,
higher than expected increases in medical costs, and market losses on plan assets.
The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts and to our
postretirement plans during 2007 and 2006.
Pension Benefits
Postretirement
Benefits
2007
2006
2007
2006
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$50
21
4
3
9
9
13
$-
-
-
-
-
-
-
$49
25
4
1
12
12
7
$74
42
7
3
15
15
7
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Ameren determines the discount rate assumptions by utilizing 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 500 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 to discount the annual benefit cash flows of the Ameren pension plan and postretirement plans and to
develop a single-point 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 2008 and our pension and postretirement plan asset categories as of
December 31, 2007 and 2006:
Asset
Category
Pension Plan:
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Target Allocation
2008
40 - 80%
25 - 60
0 - 10
0 - 10
Percentage of
Plan Assets at
December 31,
2007
2006
52%
40
6
2
58%
34
6
2
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100%
100%
Postretirement Plan:
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
40 - 80%
15 - 55
0 - 15
62%
33
5
63%
32
5
100%
100%
137
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit
plans during 2007, 2006 and 2005:
Pension Benefits
Ameren(a)
Postretirement Benefits
Ameren(a)
2007:
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of:
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net periodic benefit cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006:
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of:
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net periodic benefit cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005:
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transition obligation (asset)
Prior service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net periodic benefit cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
$ 63
180
(206)
-
11
22
$ 70
$ 63
173
(198)
-
11
42
$ 91
$ 59
169
(186)
(1)
11
38
$ 90
$ 21
72
(53)
2
(8)
24
$ 58
$ 22
72
(50)
2
(7)
35
$ 74
$ 21
73
(46)
2
(7)
39
$ 82
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in
2008 are:
Pension Benefits
Ameren
Postretirement Benefits
Ameren
Regulatory assets:
Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost (credit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated OCI:
Net actuarial (gain) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost (credit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
$21
9
-
$ (2)
2
-
$30
$25
(4)
4
$ -
(3)
-
$22
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting
under the plan. The net actuarial loss subject to amortization is amortized on a straight-line basis over 10 years.
UE, CIPS, Genco, 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,
2007, 2006 and 2005:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension Costs
2006
$91
51
11
9
10
13
9
2007
$70
44
10
7
-
8
4
2005
$90
54
10
7
10
15
8
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
138
Postretirement Costs
2006
2007
2005
$58
26
6
3
8
13
13
$74
40
9
3
9
14
13
$82
44
9
4
9
16
15
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
Paid from
Qualified Trust
Postretirement Benefits
Paid from
Company Funds
Federal Subsidy
2008 . . . . . . . . . . . . .
2009 . . . . . . . . . . . . .
2010 . . . . . . . . . . . . .
2011 . . . . . . . . . . . . .
2012 . . . . . . . . . . . . .
2013 – 2017 . . . . . . . .
$ 182
186
187
192
197
1,044
$ 3
3
2
3
2
10
$ 86
90
95
99
101
524
$ 2
2
2
2
2
12
$ 6
6
6
6
7
34
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, 2007, 2006 and 2005:
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 . . . . . . . . . . . . . . . . . . . . . . . . .
Pension Benefits
2006
2007
2005
Postretirement Benefits
2006
2007
2005
5.85%
8.50
4.00
-
-
-
5.60%
8.50
3.25
-
-
-
5.75%
8.50
3.00
-
-
-
5.80%
8.50
4.00
9.00
5.00
4 years
5.60%
8.50
3.25
8.00
5.00
3 years
5.75%
8.50
3.00
9.00
5.00
4 years
(a) The Ameren Companies will utilize an expected return on plan assets of 8.25% in 2008.
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
Pension
Postretirement
Service Cost and
Interest Cost
Projected Benefit
Obligation
Service Cost and
Interest Cost
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
-
-
$97
13
-
-
$ -
-
4
(4)
Projected
Postretirement
Benefit Obligation
$ 33
-
51
(46)
Other
Ameren sponsors a 401(k) plan for eligible employees.
The Ameren plan covered all eligible employees of the
Ameren Companies at December 31, 2007, with the
exception of CIPS employees represented by IBEW Local
702 who were covered by a separate 401(k) plan until
February 1, 2008. The CIPS-related 401(k) plan was merged
into the Ameren plan effective February 1, 2008. The plans
allowed employees to contribute a portion of their base pay
in accordance with specific guidelines. Ameren and CIPS
matched a percentage of the employee contributions up to
certain limits. Ameren’s matching contributions to the 401(k)
plan totaled $21 million, $19 million and $18 million in
2007, 2006 and 2005, respectively. CIPS’ matching
contributions to the CIPS-related 401(k) plan were less than
$1 million annually in 2007, 2006 and 2005.
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, 2007,
2006 and 2005:
2007
2006
2005
Ameren(a) . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . .
CILCORP. . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . .
$21
14
1
1
2
2
3
$19
13
1
1
2
2
2
$18
12
1
1
2
2
2
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
NOTE 10 – 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
139
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, 2007, and changes during the year ended December 31, 2007, under
the 1998 Plan and the 2006 Plan is presented below:
Nonvested at January 1, 2007 . . . . . . . . . . . . . . . . . .
Granted(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested at December 31, 2007 . . . . . . . . . . . . . . . .
Performance Share Units
Restricted Shares
Shares
338,516
357,573
-
(13,711)
(12,975)
669,403
Weighted-average
Fair Value Per
Unit
$56.07
59.60
-
56.64
59.14
$57.88
Shares
377,776
-
15,224
(5,841)
(70,391)
316,768
Weighted-average
Fair Value Per
Share
$45.79
-
51.52
46.47
43.84
$46.23
(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in
February 2007 under the 2006 Plan.
(b) Share units 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 $18 million,
$11 million, and $6 million for the years ended December 31,
2007, 2006, and 2005, respectively, and a related tax benefit
of $7 million, $4 million, and $2 million for the years ended
December 31, 2007, 2006, and 2005, respectively. As of
December 31, 2007, total compensation cost of $20 million
related to nonvested awards not yet recognized is expected
to be recognized over a weighted-average period of
three years.
Performance Share Units
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. If a
share unit 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
2007 under the 2006 Plan was determined to be $59.60,
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 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.
The fair value of each share unit awarded in February
2006 under the 1998 Plan was determined to be $56.07,
based on Ameren’s closing common share price of $50.69
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 4.65%, dividend yields of 2.3% to 4.6% for the peer
group, volatility of 13.87% to 22.45% 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
granted in May 2006 under the 2006 Plan was determined to
be $56.07, according to assumptions similar to those
applied to the February 2006 grant.
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. During 2005, 154,086 restricted stock
awards were granted. The weighted-average fair value for
restricted stock awards granted was $51.21 per share in
2005. We record compensation expense over the vesting
period.
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 89,987 at December 31, 2007,
expire on various dates through 2010. There is no expense
140
from stock options for the years ended December 31, 2007
and 2006, as all options granted were fully vested.
NOTE 11 – INCOME TAXES
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal
income tax rate for the years ended December 31, 2007, 2006 and 2005:
Ameren
UE
CIPS
Genco
CILCORP
CILCO
IP
35%
35%
35%
35%
35%
35%
35%
2007:
Statutory federal income tax rate: . . . . . . . . . . .
Increases (decreases) from:
Permanent items(a) . . . . . . . . . . . . . . . . .
Depreciation differences . . . . . . . . . . . . .
Amortization of investment tax credit . . . . .
State tax . . . . . . . . . . . . . . . . . . . . . . .
Reserve for uncertain tax positions . . . . . .
Other(b) . . . . . . . . . . . . . . . . . . . . . . . .
(2)
-
(1)
4
(1)
(1)
(2)
-
(1)
4
(1)
(2)
2
3
(6)
6
-
(4)
(1)
-
(1)
5
-
-
Effective income tax rate . . . . . . . . . . . . . . . .
34%
33%
36%
38%
2006:
Statutory federal income tax rate: . . . . . . . . . . .
Increases (decreases) from:
Permanent items(a) . . . . . . . . . . . . . . . . .
Sales of noncore properties . . . . . . . . . . .
Nondeductible expenses . . . . . . . . . . . . .
Depreciation differences . . . . . . . . . . . . .
Amortization of investment tax credit . . . . .
State tax . . . . . . . . . . . . . . . . . . . . . . .
Reserve for uncertain tax positions . . . . . .
Other(b) . . . . . . . . . . . . . . . . . . . . . . . .
35%
35%
35%
35%
(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%
2005:
Statutory federal income tax rate: . . . . . . . . . . .
Increases (decreases) from:
Permanent items(a) . . . . . . . . . . . . . . . . .
Sales of noncore properties . . . . . . . . . . .
Depreciation differences . . . . . . . . . . . . .
Amortization of investment tax credit . . . . .
State tax . . . . . . . . . . . . . . . . . . . . . . .
Reserve for uncertain tax positions . . . . . .
Other(b) . . . . . . . . . . . . . . . . . . . . . . . .
(2)
(1)
2
(1)
4
(1)
(1)
(2)
-
5
(1)
3
(2)
(2)
(1)
-
3
(2)
4
(1)
(2)
(1)
-
-
(1)
5
1
-
(5)
(2)
(2)
3
-
1
30%
35%
(c)
(c)
(c)
(c)
(c)
(c)
(c)
(c)
(c)
(2)
(1)
(1)
3
-
-
1
(3)
-
5
-
(1)
34%
37%
35%
35%
(5)
(2)
-
(3)
(2)
5
(11)
-
1
-
-
-
-
5
-
(1)
17%
40%
(c)
(c)
(c)
(c)
(c)
(c)
(c)
(c)
(4)
-
(1)
(2)
4
1
3
-
-
1
-
3
-
1
36%
40%
Effective income tax rate . . . . . . . . . . . . . . . .
35%
36%
36%
39%
(a) Permanent items are treated differently for book and tax purposes and primarily include Internal Revenue 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, CILCORP and CILCO and employee stock ownership plan dividends for Ameren.
(b) Primarily includes low-income housing and other tax credits for Ameren, UE, CIPS, CILCORP, Genco and IP.
(c) 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), the Section 199 deduction ($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 2005 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted
primarily from tax benefits from plant-related depreciation differences ($2 million), low-income housing credits ($1 million), and investment
tax credit amortization ($1 million) that were partially offset by prior-period tax matters ($1 million).
141
35%
35%
35%
35%
35%
35%
35%
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2007,
2006 and 2005:
2007:
Current taxes:
Federal . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . .
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits,
amortization . . . . . . . . . . . . . . . . . .
Total income tax expense . . . . . . . . . . . .
2006:
Current taxes:
Federal . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . .
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits,
amortization . . . . . . . . . . . . . . . . . .
Total income tax expense (benefit) . . . . . .
2005:
Current taxes:
Federal . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . .
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits,
amortization . . . . . . . . . . . . . . . . . .
Included in Income Taxes on Statement of
Income . . . . . . . . . . . . . . . . . . . . . .
Included in cumulative effect of change in
accounting principle:
Federal – deferred . . . . . . . . . . . . . . .
State – deferred . . . . . . . . . . . . . . . .
Total income tax expense (benefit) . . . . . .
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
$339
22
(22)
(1)
(8)
$330
$179
33
80
2
(10)
$284
$232
66
114
(46)
(10)
$128
11
(1)
7
(5)
$140
$123
22
52
(7)
(6)
$ 33
4
(22)
(4)
(2)
$ 9
$ 21
7
(7)
(4)
(2)
$184
$ 15
$148
13
$ 32
8
62
(24)
(6)
(8)
(5)
(2)
$40
8
25
6
(1)
$78
$ (6)
4
20
5
(1)
$22
$41
11
19
2
(1)
$ 20
6
1
(5)
(1)
$ 35
5
$ 12
-
2
(2)
(1)
3
-
-
$ 21
$ 39
$ 15
$(16)
(3)
4
5
(1)
$(11)
$ 3
19
(4)
(19)
(2)
$ 3
(1)
2
7
(1)
$ 10
$ 28
13
(15)
(9)
(1)
$(33)
(3)
63
10
-
$ 37
$ 12
14
41
(2)
-
$356
$193
$ 25
$72
$ (3)
$ 16
$ 65
$ (12)
(3)
$341
$
-
-
$193
$ -
-
$ 25
$ (8)
(2)
$62
$ (1)
-
$ (4)
$ (1)
-
$ 15
$
-
-
$ 65
(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, 2007 and 2006:
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 . . . . . . . . . . . . . . . . . . . . .
Total net accumulated deferred income
tax liabilities(b)
. . . . . . . . . . . . . . .
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
$2,186
$1,355
$171
$276
$224
$224
$149
4
36
(209)
33
7
(35)
(39)
(4)
42
(91)
-
-
(11)
(39)
99
(2)
(8)
-
-
-
(10)
(95)
-
(11)
-
-
(14)
12
-
(3)
(60)
45
-
(9)
(21)
-
(3)
(54)
-
-
(9)
(10)
-
-
30
(42)
-
-
(2)
$1,983
$1,252
$250
$168
$176
$148
$135
142
2006:
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 . . . . . . . . . . . . . . . . . . . . .
Total net accumulated deferred income
tax liabilities(c). . . . . . . . . . . . . . . .
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
$2,238
$1,368
$186
$ 292
$224
$224
$143
2
36
(148)
45
16
(13)
(62)
(4)
40
(89)
-
-
-
(39)
109
-
(5)
-
-
-
(12)
(106)
-
(17)
-
-
(12)
13
-
(4)
(61)
47
-
1
(14)
-
(4)
(59)
-
-
1
(3)
-
-
37
(33)
-
-
(15)
$2,114
$1,276
$278
$ 170
$193
$159
$132
(a)
(b)
(c)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes $61 million, $21 million, $8 million, $17 million, $7 million, and $13 million as current assets recorded in the consolidated balance
sheet for Ameren, UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $7 million as current liabilities recorded in the consolidated
balance sheet for Genco.
Includes $30 million, $17 million, $7 million, $8 million, $7 million and $6 million as current assets recorded in the consolidated balance
sheet for Ameren, UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $5 million as current liabilities recorded in the consolidated
balance sheet for Genco.
Ameren, Genco, CILCORP and IP have Illinois net operating loss carryforwards of $91 million, $8 million, $59 million, and
$21 million, respectively. These will begin to expire in 2016.
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 a tax return should be recorded in the financial statements. The
amounts of unrecognized tax benefits as of January 1, 2007, were $155 million, $58 million, $15 million, $36 million,
$18 million, $18 million, and $12 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP, respectively. These
unrecognized tax benefits, if recognized, would have had the following impacts on the respective company’s tax rate: Ameren –
$20 million, UE – $6 million, CIPS – less than $1 million, Genco – less than $1 million, CILCORP – less than $1 million, CILCO –
less than $1 million, and IP – none.
A reconciliation of the change in the unrecognized tax benefit balance from January 1, 2007 to December 31, 2007, is as follows:
Ameren
UE
CIPS
GENCO
CILCORP
CILCO
IP
Unrecognized tax benefits – opening
balance:
Increases based on tax positions prior to
. . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . .
Decreases based on tax positions prior to
2007 . . . . . . . . . . . . . . . . . . . . . . .
Increases based on tax positions related
to 2007 . . . . . . . . . . . . . . . . . . . . .
Decreases related to settlements with
taxing authorities . . . . . . . . . . . . . . .
Decreases related to the lapse of statute
of limitations. . . . . . . . . . . . . . . . . .
Unrecognized tax benefits – December 31,
$155
$ 58
$ 15
31
(21)
17
(60)
(6)
4
(8)
6
(28)
(6)
-
(3)
-
(12)
-
$36
10
(8)
6
(4)
-
$18
$18
$ 12
3
-
5
(7)
-
3
-
5
(7)
-
-
(2)
-
(10)
-
-
2007 . . . . . . . . . . . . . . . . . . . . . . . .
$116
$ 26
$ -
$40
$19
$19
$
Total unrecognized tax benefits that, if
recognized, would impact the effective tax
rate as of December 31, 2007 . . . . . . . .
$ 26
$ 4
$ -
$ -
$ 1
$ 1
$
-
As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest and penalties accrued on tax
liabilities on a gross basis as interest expense 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. As of January 1, 2007, Ameren,
UE, CIPS, Genco, CILCORP, CILCO, and IP had recorded liabilities of $12 million, $5 million, less than $1 million, $4 million,
$1 million, less than $1 million, and less than $1 million, respectively, for the payment of interest with respect to unrecognized
tax benefits and no amount for penalties with respect to unrecognized tax benefits.
143
A reconciliation of the change in the accrued interest balance from January 1, 2007 to December 31, 2007, is as follows:
Liability for interest expense – January 1, 2007:
. . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . .
Liability for interest expense – December 31, 2007 . .
Ameren
$12
5
$17
UE
$5
-
$5
CIPS
GENCO
CILCORP
CILCO
$1
-
$1
$4
3
$7
$1
1
$2
$1
1
$2
IP
$-
-
$-
As of December 31, 2007, the Ameren Companies have accrued no amount for penalties with respect to unrecognized tax
benefits.
The Ameren Companies are no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for
years before 2002. The Ameren Companies are currently under federal income tax return examination for years 2002 through
2005. State income tax returns are generally subject to examination for a period of three years after filing. 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 also do not now have material state income tax issues under examination, administrative
appeals, or litigation.
It is reasonably possible that events will occur during the next 12 months that would cause the total amount of
unrecognized tax benefits for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to decrease by $28 million, $14 million, less
than $1 million, $10 million, $4 million, $4 million and less than $ million, respectively; however, the Ameren Companies do not
believe such decreases would be material to their results of operations.
NOTE 12 – RELATED PARTY TRANSACTIONS
Electric Power Supply Agreements
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
See Note 2 – Rate and Regulatory Matters and Note 13 –
Commitments and Contingencies for information on the
Illinois electric settlement agreement reached in July 2007
and reflected in legislation, enacted on August 28, 2007, that
addresses electric rate increases and the future power
procurement process in Illinois. As part of the Illinois
electric settlement agreement, the Ameren Illinois Utilities,
Genco and AERG agreed to make contributions of
$150 million as part of a comprehensive program providing
approximately $1 billion of funding for rate relief to certain
Illinois electric customers, including customers of the
Ameren Illinois Utilities. At December 31, 2007, CIPS,
CILCO, and IP had receivable balances from Genco for
reimbursement of customer rate relief of $2 million,
$1 million, and $3 million, respectively. Also at December 31,
2007, CIPS, CILCO, and IP had receivable balances from
AERG for reimbursement of customer rate relief of $1 million,
$1 million, and $1 million, respectively. In addition, 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 a portion of
their around-the-clock power requirements from 2008 to
2012 at relevant market prices. These financial contracts
became effective on August 28, 2007. See also Note 7 –
Derivative Financial Instruments for additional information on
the financial contracts.
The following table presents the amount of
gigawatthour sales under related party electric power supply
agreements for the years ended December 31, 2007, 2006,
and 2005:
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) . . . . . . . . . . . . . . .
December 31
2006
2007
2005
-
-
21,941
22,211
12,593
11,278
17,425
5,316
2,396
1,167
3,493
-
-
-
-
-
-
-
-
-
-
(a) These agreements expired or terminated on December 31,
(b)
(c)
2006.
In December 2006, Genco and Marketing Company, and AERG
and Marketing Company, entered into new 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.
In accordance with a January 2006 ICC order, an auction was
held in September 2006 to procure power for CIPS, CILCO and
IP after their previous power supply contracts expired on
December 31, 2006. Through the auction, Marketing Company
contracted with CIPS, CILCO and IP to provide a portion of the
power requirements of their customers.
Under two electric power supply agreements, which
expired or terminated December 31, 2006, Genco was
obliged to supply power to Marketing Company. Marketing
Company, in turn, was obliged to supply to CIPS all of the
144
energy and capacity CIPS needed to offer service for resale
to its native load customers at ICC-regulated rates and to
fulfill its other obligations under all applicable federal and
state tariffs or contracts. Any power not used by CIPS was
sold by Marketing Company under various long-term
wholesale and retail contracts.
In October 2003, AERG entered into an electric power
supply agreement to supply CILCO with sufficient power to
meet its native load requirements. Also, a bilateral power
supply agreement was entered into between AERG and
Marketing Company: AERG agreed to sell excess power to
Marketing Company for sales outside the CILCO control
area, and Marketing Company agreed to sell power to AERG
to fulfill CILCO’s native load requirements. These agreements
expired at the end of 2006.
In December 2006, Genco and Marketing Company
entered into a new power supply agreement (Genco PSA)
whereby Genco agreed to sell and Marketing Company to
purchase all of the capacity available from Genco’s
generation fleet and all the associated energy. The Genco
PSA provides that Marketing Company shall pay, for each
megawatthour of associated energy delivered by Genco and
purchased by Marketing Company during the month of
delivery, an “energy charge.” The “energy charge” is
calculated by taking Marketing Company’s gross revenues
with respect to power purchased from Genco and AERG in a
particular month and subtracting the monthly capacity
charge assessed on Marketing Company by Genco and
AERG pursuant to the Genco PSA and the AERG PSA (as
defined below), respectively. This produces the monthly net
revenues. From the monthly net revenues, all administrative
and general, transmission, purchased power, and other
expenses are subtracted (excluding those expenses that do
not support in whole or in part the gross revenue associated
with Genco’s generation pursuant to the Genco PSA or
AERG’s generation pursuant to the AERG PSA). This amount
is then divided by the total number of megawatthours
generated by Genco and AERG to determine the per
megawatthour “energy charge.” The Genco PSA also
provides that Marketing Company shall pay a “monthly
capacity charge.” The formula for determining the “monthly
capacity charge” is based on the monthly fixed cost of
operating the generation fleet of Genco and AERG.
Also in December 2006, AERG and Marketing Company
entered into a power supply agreement (AERG PSA) whereby
AERG agreed to sell and Marketing Company to purchase all
of the capacity available from AERG’s generation fleet and all
the associated energy. The calculations of the energy charge
and the monthly capacity charge under this agreement are
substantively identical to those described above with respect
to the Genco PSA. Both the Genco PSA and the AERG PSA
commenced on January 1, 2007, and 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
$64.77
750
$64.75
750
$66.05
Term
Megawatts(a) . . . . . . . . .
Cost per megawatthour . .
(a) Before impact to Ameren Illinois Utilities’ load due to customer
switching.
Through the auction, Marketing Company contracted
with CIPS, CILCO and IP to provide power for large
commercial and industrial customers (one megawatt of
demand or higher) as follows. Nearly all of these customers
switched to other suppliers as a result of the auction price.
Term
Megawatts(a)
. . . . . . . . . . . . . . . . . . . . . .
Cost per megawatthour . . . . . . . . . . . . . . . .
Term Ending
May 31, 2008
17 Months
500
$84.95
(a) Before impact to Ameren Illinois Utilities’ load due to customer
switching.
See Note 2 – Rate and Regulatory Matters for a
discussion of changes in the Illinois power procurement
process as a result of the Illinois electric settlement
agreement.
UE, CIPS, IP and a nonaffiliated company were parties
to a power supply agreement with EEI to purchase and sell
capacity and energy. This agreement expired on
December 31, 2005. Under a separate agreement that also
expired on December 31, 2005, CIPS resold its entitlements
under the agreement with EEI to Marketing Company.
Marketing Company and certain nonaffiliated companies
were also parties to a power supply agreement with a
subsidiary of EEI, to purchase capacity and energy. This
agreement was terminated effective December 31, 2005. In
December 2005, Marketing Company entered into a power
supply agreement with EEI, effective January 2006, whereby
EEI sells 100% of its capacity and energy to Marketing
Company. This agreement expires on December 31, 2015.
UE had a 150-megawatt power supply agreement with
Marketing Company that expired May 31, 2005. Power
supplied by Marketing Company to UE through this
agreement was obtained from Genco.
In December 2004, Marketing Company and IP entered
into an agency agreement that authorized Marketing
Company, on behalf of IP, to sell or purchase, as necessary,
electric energy and capacity in the wholesale market for
2005 and 2006.
145
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.
Joint Dispatch Agreement
Prior to December 31, 2006, UE and Genco jointly
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 sourcing
the power to the other company. In January 2006, the
allocation methodology in the JDA for margins on short-term
sales of excess generation to third parties between UE and
Genco was modified, and in July 2006, UE, CIPS and Genco
mutually consented to waive the one-year termination notice
requirement of the JDA. They agreed to terminate it on
December 31, 2006.
The following table presents the amount of
gigawatthour sales under the JDA.
UE sales to Genco . . . . . . . . . . . . . .
Genco sales to UE . . . . . . . . . . . . . .
2006
2005
10,072
3,917
11,564
2,888
The following table presents the short-term power sales
margins under the JDA for UE and Genco.
UE . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . .
Support Services Agreements
2006
$108
33
$141
2005
$128
79
$207
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.
Executory Tolling, Gas Sales, and Transportation
Agreements
Under an executory tolling agreement, CILCO purchases
steam, chilled water, and electricity from Medina Valley. In
connection with this 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.
Money Pools
See Note 5 – Long-term Debt and Equity Financings for
discussion of affiliate borrowing arrangements.
Intercompany Promissory Notes
On May 1, 2005, Genco and CIPS amended the
maturity date and interest rate of the subordinated note
payable to CIPS. The note payable to CIPS was issued in
conjunction with the transfer of CIPS’ electric generating
assets and related liabilities to Genco. 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, a five-year amortization schedule, and a
maturity date of May 1, 2010. Interest income and expense
for this note recorded by CIPS and Genco, respectively, was
$10 million, $12 million, and $15 million for the years ended
December 31, 2007, 2006, and 2005, respectively.
Also on May 1, 2005, the remaining principal balance
under Genco’s note payable to Ameren of $34 million was
repaid. Genco recorded interest expense of $1 million from
this note payable to Ameren for the year ended December 31,
2005.
On May 2, 2005, CIPS issued to UE a subordinated
promissory note in the principal amount of $67 million as
consideration for 50% of UE’s Illinois-based utility assets
transferred to CIPS on that date. The note bore interest of
4.70% per year and had a five-year amortization schedule
and a maturity date of May 2, 2010. In June 2006, CIPS
repaid in full the remaining balance under this note. UE and
CIPS recorded interest income and expense, respectively, of
$1 million and $2 million for the years ended December 31,
2006 and 2005, respectively.
CILCORP had outstanding borrowings directly from
Ameren of $2 million and $73 million at December 31, 2007
and 2006, respectively. The average interest rate on these
borrowings was 5.14% for the year ended December 31,
2007 (2006 – 4.65%). CILCORP recorded interest expense of
$- million, $7 million, and $6 million for these borrowings
for the years ended December 31, 2007, 2006 and 2005
respectively.
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 $11 million,
$11 million, and $10 million for the three years ended
December 31, 2007, 2006, and 2005, respectively. Under an
electric power supply agreement with Marketing Company,
146
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 power supply
agreement was terminated in February 2008, when an
internal reorganization merged Development Company into
Resources Company.
The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the
years ended December 31, 2007, 2006 and 2005. It is based primarily on the agreements discussed above and the money pool
arrangements discussed in Note 4 – Credit Facilities and Liquidity.
Agreement
Financial Statement Line Item
UE
CIPS Genco
CILCORP(a)
IP
Operating Revenues
2007
$ (c) $ (c)
$831
$279
$ (c)
Operating Revenues
2007
18
(c)
(c)
(c)
(c)
JDA – terminated December 31, 2006
Operating Revenues
Operating Revenues:
Genco and AERG power supply
agreements with Marketing Company
Ancillary service agreement with CIPS,
CILCO and IP
Power supply agreement with Marketing
Company – expired December 31, 2006
Power supply agreement with EEI
UE and Genco gas transportation
agreement
Total Operating Revenues
Fuel and Purchased Power:
CIPS, CILCO and IP agreements with
Marketing Company (2006 auction)
Ancillary service agreement with UE
Ancillary service agreement with
Marketing Company
JDA – terminated December 31, 2006
Power supply agreement with Marketing
Company – expired December 31, 2006
Power supply agreement with EEI
Executory tolling agreement with Medina
Valley
UE and Genco gas transportation
agreement
Total Fuel and Purchased Power
Other Operating Expense:
Ameren Services support services
agreement
Ameren Energy, Inc. support services
agreement
Fuel and Purchased Power
2007
$ (c) $157
$ (c)
$ 76
$227
Operating Revenues
Operating Revenues
Operating Revenues
Fuel and Purchased Power
Fuel and Purchased Power
Fuel and Purchased Power
Fuel and Purchased Power
Fuel and Purchased Power
Fuel and Purchased Power
Fuel and Purchased Power
Other Operating Expenses
Other Operating Expenses
2006
2005
2005
2007
2006
2005
2006
2005
2007
2006
2005
(c)
(c)
1
1
1
1
196
230
$ 19
197
232
(c)
36
(c)
(c)
(c)
(c)
(c)
(c)
$ (c)
(c)
36
793
793
1
(c)
(c)
(c)
97
74
$831
890
868
5
24
(c)
(c)
(c)
(c)
(c)
(c)
$279
5
24
(c)
(c)
(c)
(c)
(c)
(c)
(c)
(c)
$ (c)
(c)
(c)
2007
2007
2006
2005
2006
2005
2005
2007
2006
2005
2007
2006
2005
2007
2006
2005
2007
2006
2005
2007
2006
2005
2007
2006
2005
2007
2007
2006
2005
2007
2006
2005
(c)
(c)
97
74
(c)
4
65
(c)
(c)
(c)
(c)
(c)
(c)
6
3
(c)
(c)
448
401
36
(c)
(c)
(c)
(c)
(c)
(c)
(c)
(c)
196
230
(c)
4
(c)
(c)
(c)
(c)
1
1
1
$ (c) $166
448
437
97
143
$
1
197
235
$137
136
153
8
7
5
6
5
4
21
$172
148
162
$ 47
47
42
(c)
(c)
(c)
2
1
1
(c)
$ 49
48
43
$ (d) $ (d)
(2)
(1)
(d)
4
$ 24
23
20
(d)
2
3
2
2
2
5
$ 31
27
25
$
8
10
3
3
1
(c)
(c)
1
11
(c)
38
39
37
(c)
(c)
(c)
$118
40
48
$ 49
48
41
(c)
(c)
(c)
2
2
2
2
$ 53
50
43
$ (d)
4
4
9
4
(c)
(c)
(c)
(c)
46
(c)
(c)
(c)
(c)
(c)
(c)
$240
(c)
46
$ 73
71
64
(c)
(c)
(c)
2
2
2
(c)
$ 75
73
66
$ 1
2
(3)
AFS support services agreement
Other Operating Expenses
Insurance premiums(b)
Total Other Operating Expenses
Other Operating Expenses
Money pool borrowings (advances)
Interest (Expense)
Income
(a) Amounts represent CILCORP and CILCO activity.
(b) Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.
(c) Not applicable.
(d) Amount less than $1 million.
147
NOTE 13 – 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.
Callaway Nuclear Plant
The following table presents insurance coverage at UE’s Callaway nuclear plant at December 31, 2007. The property
coverage and the nuclear liability coverage were renewed on October 1, 2007 and January 1, 2008, respectively.
Type and Source of Coverage
Maximum Coverages
Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers . . . . . . . . . . . . . . . . . . . . . . .
Pool participation . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property damage:
Nuclear Electric Insurance Ltd.
. . . . . . . . . . . . . . . . . . . .
Replacement power:
Nuclear Electric Insurance Ltd.
. . . . . . . . . . . . . . . . . . . .
Energy Risk Assurance Company . . . . . . . . . . . . . . . . . . .
$
300
10,461(a)
$10,761(c)
$ 2,750(d)
$
$
490(e)
64(f)
$
-
101(b)
$101
$ 24
$
$
9
-
(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 $15 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.
(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 12 – 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. 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.
148
Leases
The following table presents our lease obligations at December 31, 2007:
Total
Less than 1 Year
1 - 3 Years
3 - 5 Years
After 5 Years
Ameren:(a)
Capital lease payments(b). . . . . . . . . . . . . .
Less amount representing interest . . . . . . . .
Present value of minimum capital lease
payments . . . . . . . . . . . . . . . . . . . . . .
Operating leases(c) . . . . . . . . . . . . . . . . . .
Total lease obligations . . . . . . . . . . . . . . .
UE:
Capital lease payments(b). . . . . . . . . . . . . .
Less amount representing interest . . . . . . . .
Present value of minimum capital lease
payments . . . . . . . . . . . . . . . . . . . . . .
Operating leases(c) . . . . . . . . . . . . . . . . . .
Total lease obligations . . . . . . . . . . . . . . .
CIPS:
Operating leases(c) . . . . . . . . . . . . . . . . . .
Genco:
Operating leases(c) . . . . . . . . . . . . . . . . . .
CILCORP and CILCO:
Operating leases(c) . . . . . . . . . . . . . . . . . .
IP:
Operating leases(c) . . . . . . . . . . . . . . . . . .
$750
424
326
423
$749
$750
424
326
185
$511
$ 3
$152
$ 24
$ 12
$32
28
4
41
$45
$32
28
4
15
$19
$ 1
$ 9
$ 2
$ 4
$65
56
9
69
$78
$65
56
9
28
$37
$ 1
$17
$ 4
$ 5
$65
56
9
57
$66
$65
56
9
26
$35
$ 1
$17
$ 4
$ 2
$588
284
304
256
$560
$588
284
304
116
$420
$
-
$109
$ 14
$
1
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) See Note 5 – Long-term Debt and Equity Financings for further discussion. See also 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. The $1 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.
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. See Note 5 – Long-term Debt and Equity Financings for
additional information on the Audrain County lease. The following table presents total rental expense, included in other
operations and maintenance expenses, for the years ended December 31, 2007, 2006 and 2005:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP and CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$15
19
9
2
7
12
$15
20
9
2
6
11
$19
18
6
2
4
8
2007
2006
2005
(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 total estimated fuel, power, and natural
gas commitments at December 31, 2007. In addition, the following table presents in the Other column heavy forgings contracts,
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
149
was netted against the related investment in Other Assets at December 31, 2007, as Ameren has a legally enforceable right to
offset under FIN 39.
Coal
Gas
Nuclear
Electric
Capacity
Other
Total
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Ameren:(a)
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP and CILCO:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
$470
251
166
77
-
-
$964
$290
177
129
77
-
-
$673
$
$ 76
44
17
-
-
-
$137
$ 26
11
7
-
-
-
$ 44
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$ 624
386
306
240
171
1,942
$3,669
$
84
58
42
32
20
37
$ 273
$ 122
86
66
44
24
48
$ 390
$
$
37
8
8
8
5
8
74
$ 165
106
83
76
53
874(d)
$1,357
$ 202
125
105
78
68(d)
975(d)
$1,553
$133
67
74
51
59
233
$617
$133
67
74
51
59
233
$617
$
$
$
$
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$22
13
-
-
-
-
$35
$22
13
-
-
-
-
$35
$ (c)
-
-
-
-
-
$ -
$ (c)
-
-
-
-
-
$ -
$ (c)
-
-
-
-
-
$ -
$ (c)
-
-
-
-
-
$ -
$ 51
63
125
54
17
373
$683
$ 28
29
94
23
-
230
$404
$
3
4
2
2
-
17
$ 28
$
$
$
-
-
-
-
-
-
-
2
4
3
3
-
32
$ 44
$ 12
11
9
9
-
94
$135
$1,300
780
671
422
247
2,548
$5,968
$ 557
344
339
183
79
500
$2,002
$ 125
90
68
46
24
65
$ 418
$ 113
52
25
8
5
8
$ 211
$ 193
121
93
79
53
906
$1,445
$ 214
136
114
87
68
1,069
$1,688
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Commitments for natural gas and nuclear fuel are until 2031 and 2020, respectively.
(c) At December 31, 2007, less than $1 million of electric capacity contracts were executed for the Ameren Illinois Utilities with approximately
23% of the capacity resources dedicated to CIPS, 7% to CILCO, and 70% to IP. These capacity purchases were made to serve real-time
pricing customers (one megawatt of demand or higher). The majority of the electric capacity for the Illinois utilities was obtained through
the Illinois power procurement auction. See below for additional information.
(d) Commitments for natural gas purchases for CILCO and IP include projected natural gas purchases pursuant to a 20-year supply contract
beginning in April 2011. Purchases under this contract will be passed through to utility customers under the PGA.
150
Commencing 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 in the Illinois reverse power procurement
auction held in September 2006. As part of the Illinois
electric settlement agreement, the reverse auction used for
power procurement was discontinued and replaced with a
new power procurement process to be led by the IPA,
beginning in 2009. In 2008, utilities will contract for
necessary power and energy requirements not already
supplied through the September 2006 auction contracts,
primary through a request-for-proposal process, subject to
ICC review and approval. Existing supply contracts from the
September 2006 auction remain in place. See Note 2 – Rate
and Regulatory Matters for additional information.
CIPS, CILCO and IP entered into power supply
contracts with winning bidders of the Illinois power
procurement auction held in September 2006. The power
supply contracts stipulate terms of 17 months, 29 months,
and 41 months to serve the electric load requirements of
fixed-price residential and small commercial customers (with
less than one megawatt of demand) commencing January 1,
2007. CIPS, CILCO and IP obtained 17-month-term electric
power supply contracts with winning bidders in the auction
to serve the load requirements of commercial and industrial
fixed-price customers (with one megawatt or greater
demand) commencing January 1, 2007. 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 load of customers at an all-inclusive fixed price.
Through the Illinois auction held in September 2006, CIPS, CILCO and IP contracted for their anticipated fixed-price loads
for residential and small commercial customers (less than one megawatt of demand) as follows:
Term
CIPS’ load in megawatts(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO’s load in megawatts(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP’s load in megawatts(a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total load in megawatts(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost per megawatthour. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
May 31, 2008
17 Months
Term Ending
May 31, 2009
29 Months
May 31, 2010
41 Months
621
318
902
1,841
$64.77
639
328
928
1,895
$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.
Through the Illinois auction held in September 2006, CIPS, CILCO and IP contracted for their anticipated fixed-price loads
for large commercial and industrial customers (one megawatt of demand or higher) as follows:
Term
CIPS’ load in megawatts(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO’s load in megawatts(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP’s load in megawatts(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total load in megawatts(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Term Ending
May 31, 2008
17 Months
12
21
24
57
Cost per megawatthour . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$84.95
(a) Actual load could be different because of weather, among other things.
The Illinois electric settlement agreement provides
approximately $1 billion of funding over a four-year period
that commenced 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,
2007:
CILCO
(Illinois
Regulated)
$3.2
1.9
0.1
$5.2
IP
$ 8.4
4.9
0.4
$13.7
Genco
$17.2
10.9
0.7
$28.8
CILCO
(AERG)
$ 7.7
4.9
0.3
$12.9
2008(a) . .
2009(a) . .
2010(a) . .
Total . . .
Ameren CIPS
$42.9 $ 6.4
3.9
26.5
0.2
1.7
$71.1 $10.5
(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 around-the-
151
clock power requirements from 2008 to 2012. See Note 2 –
Rate and Regulatory Matters for additional information.
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. During the second quarter of 2007, UE
entered into a commitment to purchase heavy forgings
needed to construct a nuclear plant. This commitment does
not mean a decision has been made to build a nuclear plant.
The purpose of the purchase commitment was to secure
access to heavy forgings, which are long-lead-time materials,
in the event that UE decides to build a nuclear plant. As of
December 31, 2007, UE’s commitments to purchase heavy
forgings totaled $84.5 million through 2010 ($6.5 million in
2008, $7.5 million in 2009, and $70.5 million in 2010). They
are included in the other obligations table above.
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
The EPA issued final SO2, NOx and mercury emission
regulations in May 2005. The Clean Air Interstate Rule and
the Clean Air Mercury Rule require significant reductions in
these emissions from UE, Genco, AERG and EEI power
plants in phases, beginning in 2009. States have finalized
rules to implement the federal Clean Air Interstate Rule and
Clean Air Mercury Rule. Although the federal rules mandate
a specific cap for SO2, NOx and mercury emissions by state
from utility boilers, the states have considerable flexibility in
allocating emission allowances to individual utility boilers. In
addition, a state may choose to hold back certain emission
allowances for growth or other reasons, and it may
implement a more stringent program than the federal
program. Illinois has finalized rules to implement the federal
Clean Air Interstate Rule program that will reduce the
number of NOx allowances automatically allocated to
Genco’s, AERG’s and EEI’s plants. 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 selective
catalytic reduction (SCR) systems for NOx reduction at
certain coal-fired plants in Illinois. Missouri rules, which
substantially follow the federal regulations and became
effective in April 2007, and approved by the EPA in
December 2007, are expected to reduce mercury emissions
81% by 2018, and 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.
Current plans include the installation of scrubbers for SO2
reduction and co-benefit reduction of mercury and pollution
control equipment designed to reduce mercury emissions at
certain coal-fired plants in Missouri.
Illinois has adopted rules for mercury emissions that
are significantly stricter than the federal regulations. In 2006,
Genco, CILCO, EEI, and the Illinois EPA entered into an
agreement that was incorporated into Illinois’ mercury
emission regulations. Under the regulations, Illinois
generators may defer until 2015 the requirement to reduce
mercury emissions by 90% in exchange for accelerated
installation of NOx and SO2 controls. In 2009, Genco, AERG
and EEI expect to begin putting into service equipment
designed to reduce mercury emissions. These rules, when
fully implemented, are expected to reduce mercury
emissions 90%, NOx emissions 50%, and SO2 emissions
70% by 2015 in Illinois.
In February 2008, the U.S. Court of Appeals for the
District of Columbia issued a decision that effectively
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 Court’s decision is subject to appeal
and it is uncertain how the EPA will respond. At this time,
we are unable to determine the impact that this action would
have on our estimated expenditures for compliance with
environmental rules, our results of operations, financial
position, or liquidity.
The table below presents estimated capital costs based
on current technology to comply with both the federal Clean
Air Interstate Rule and Clean Air Mercury Rule through 2017
and related state implementation plans. The estimates
described below could change depending upon additional
federal or state requirements, 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 the proposed rules,
thereby deferring capital investment.
2008
UE(a) . . . . $255
300
Genco . . .
170
CILCO . . .
30
EEI . . . . .
2009 – 2012
2013 – 2017
Total
$ 215 – $ 295
955 – 1,210
500
380 –
350
260 –
$ 1,300 – $1,700
70
45 –
90
70 –
30
20 –
$ 1,770 – $2,250
1,300 – 1,580
760
410
620 –
310 –
Ameren . . $755
$1,810 – $2,355
$ 1,435 – $1,890
$ 4,000 – $5,000
(a) UE’s expenditures are expected to be recoverable in rates over
time.
152
Illinois and Missouri must also develop attainment
plans to meet the federal eight-hour ozone ambient standard,
the federal fine particulate ambient standard, and the Clean
Air Visibility rule. Both states have filed ozone attainment
plans for the St. Louis area. The state attainment plans for
fine particulate matter must be submitted to the EPA by April
2008. The plans for the Clean Air Visibility rule were
submitted in December 2007. The costs in the table assume
that emission controls required for the Clean Air Interstate
Rule regulations will be sufficient to meet these new
standards in the St. Louis region. Should Missouri develop
an alternative plan to comply with these standards, the cost
impact could be material to UE, but we would expect these
costs to be recoverable from ratepayers. Illinois is planning
to impose additional requirements beyond the Clean Air
Interstate Rule as part of the attainment plans for ozone and
fine particulate matter. 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 impact of future initiatives related to greenhouse
gas emissions and global warming on us are unknown and
therefore not included in the estimated environmental
expenditures. 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.
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, under the Acid Rain
Program and NOx Budget Trading Programs, created
marketable commodities called allowances. Currently each
allowance gives the owner the right to emit one ton of SO2
or NOx. All existing generating facilities have been allocated
allowances based on past production and the statutory
emission reduction goals. If additional allowances are
needed for new generating facilities, they can be purchased
from facilities that have excess allowances or from
allowance banks. 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. The NOx Budget
Trading Program limits emissions of NOx during the ozone
season (May through September). The NOx Budget Trading
Program has applied to all electric generating units in Illinois
since the beginning of 2004; it was applied to the eastern
third of Missouri, where UE’s coal-fired power plants are
located, beginning in 2007. 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, including low-NOx burners,
over-fire air systems, combustion optimization, rich-reagent
injection, selective noncatalytic reduction, and selective
catalytic reduction systems.
The following table presents the SO2 and NOx emission
allowances held and the related SO2 and NOx emission
allowance book values that are carried as intangible assets
as of December 31, 2007.
SO2
(a) NOx
Ameren . . . . . . . . . . . . . . . . . . . 3.007 33,253
UE . . . . . . . . . . . . . . . . . . . . . . 1.673 15,831
Genco . . . . . . . . . . . . . . . . . . . . 0.693 11,891
2,147
CILCORP . . . . . . . . . . . . . . . . . . 0.326
2,147
CILCO (AERG) . . . . . . . . . . . . . . . 0.326
3,384
EEI . . . . . . . . . . . . . . . . . . . . . . 0.315
(b) Book Value
$198(c)
56
63
41
1
9
(a) Vintages are from 2007 to 2017. Each company possesses
additional allowances for use in periods beyond 2017. Units are
in millions of SO2 allowances (currently one allowance equals
one ton emitted).
(b) Vintages are from 2007 to 2008. Units are in NOx allowances
(c)
(one allowance equals one ton emitted).
Includes value assigned to EEI allowances as a result of
purchase accounting of $29 million.
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 amount 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. 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 will have both an annual
program and an ozone season program for regulating NOx
emissions, with separate allowances issued for each
program. 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. UE, Genco, AERG and EEI
expect to be allocated NOx allowances for both programs in
Illinois in 2008.
Global Climate
Future initiatives regarding greenhouse gas emissions
and global warming are subject to active consideration in the
U.S. Congress. Ameren believes that currently proposed
legislation can be classified as moderate to extreme
depending upon proposed CO2 emission limits, the timing of
implementation of these limits, and the method of allocating
153
allowances. The moderate scenarios include provisions for 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 carbon dioxide, a principal
greenhouse gas. Ameren’s current analysis shows that under
some policy scenarios being considered in 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. When consumed natural gas emits about half
the amount of CO2 as coal. As a result, economy-wide shifts
favoring natural gas as a fuel source for electric generation
also would affect the cost of nonelectric transportation,
heating for our 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 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. The costs to comply with future legislation
or regulations could be so expensive that Ameren and other
similarly situated electric power generators may be forced to
close some coal-fired facilities. 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.
In April 2007, the U.S. Supreme Court issued a decision
that determined that the EPA has the authority to regulate
carbon dioxide and other greenhouse gases from
automobiles as “air pollutants” under the Clean Air Act. 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.” As a result, the EPA could begin to
regulate such emissions.
Ameren has taken actions to address the global climate
issue. These include implementing efficiency improvements
at our power plants; participating in the PowerTree Carbon
Company, LLC, whose purpose is to reforest acreage in the
lower Mississippi valley to sequester carbon; using coal
combustion by-products as a direct replacement for cement,
thereby reducing carbon emissions at cement kilns;
participating in “Missouri Schools Going Solar,” a project
that will install photovoltaic solar arrays on school grounds;
and partnering with other utilities, the Electric Power
Research Institute, and the Illinois State Geological Survey in
the DOE Illinois Basin Initiative, which will examine the
feasibility and methods of storing CO2 within deep unused
coal seams, mature oil fields, and saline reservoirs.
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,
where our Non-rate-regulated Generation coal-fired plants
are located, 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. On
January 25, 2007, the U.S. Court of Appeals for the Second
Circuit remanded many provisions of these rules to the EPA
for revision. Until the EPA reissues these rules and the
studies on the power plants are completed, we will be
unable to estimate the costs of complying with these rules.
Such costs are not expected to be incurred prior to 2010.
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.
In April 2005, Genco 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 its Meredosia, Hutsonville, Coffeen 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. We are 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. Resolution of these matters
could have a material adverse impact on the future results of
operations, financial position or liquidity of Ameren, Genco,
AERG and EEI. A resolution could result in increased capital
expenditures, increased operations and maintenance
expenses, and fines or penalties. We believe that any
potential resolution would likely require the installation of
control technology, some of which is already planned for
compliance with other regulatory requirements such as the
Clean Air Interstate Rule and the Illinois mercury rules.
154
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 degree of fault, legality of
original disposal, or 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 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, 2007, CIPS, CILCO and IP owned
or were otherwise responsible for several former MGP sites
in Illinois. CIPS has 14, CILCO four, 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, 2007, estimated
obligations were: CIPS – $24 million to $42 million, CILCO –
$5 million to $8 million, IP – $76 million to $171 million.
CIPS, CILCO and IP also recorded liabilities of $24 million,
$5 million, and $76 million, respectively, to represent
estimated minimum obligations as no other amount within
the range is a better estimate at this time.
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, 2007, UE estimated its obligation at $5 million
to $13 million. UE recorded $5 million to represent its
estimated minimum obligation for its MGP sites as no other
amount within the range is a better estimate at this time. UE
also is responsible for four electric sites in Missouri that
have corporate cleanup liability, most as a result of federal
agency mandates. As of December 31, 2007, UE estimated
its obligation at $4 million to $17 million. UE recorded
$4 million to represent its estimated minimum obligation for
these sites as no other amount within the range is a better
estimate at this time. We are unable to determine what
portion of these costs, if any, will be eligible for recovery
from insurance carriers.
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 potentially responsible parties (PRPs)
to evaluate the extent of potential contamination with respect
to Sauget Area 2.
Sauget Area 2 investigation activities under the
oversight of the EPA are largely completed, and the results
will be submitted to the EPA by the third quarter of 2008.
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 waste landfill in the Sauget Area 2,
notwithstanding Solutia’s filing for bankruptcy protection.
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
$2 million at December 31, 2007, included 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.
Polychlorinated Biphernals Information Request
Polychlorinated biphernals (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 the
EPA for information regarding its experiences with PCBs in
its gas distribution system. The Ameren Illinois Utilities have
responded to these information requests.
The Ameren Illinois Utilities have evaluated their gas
distribution systems. They believe that the presence of PCBs
is limited to discrete areas and is not widespread throughout
its service territories. We cannot predict whether any further
actions will be required on the part of the Ameren Illinois
155
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.
In October 2006, FERC approved a stipulation and
consent agreement between UE and FERC’s Office of
Enforcement that resolved all issues arising from an
investigation conducted by FERC’s Office of Enforcement into
alleged violations of license conditions and FERC regulations
by UE, as the licensee of the Taum Sauk hydroelectric
facility, that may have contributed to the breach of the upper
reservoir. As part of the stipulation and consent agreement,
UE paid a civil penalty of $10 million, paid $5 million into an
interest-bearing escrow account to fund project
enhancements at or near the Taum Sauk facility, and
implemented a new dam safety program in connection with
the settlement.
In February 2007, UE submitted to FERC an
environmental report to rebuild the upper reservoir at its
Taum Sauk plant. UE received approval from FERC to rebuild
the upper reservoir at its Taum Sauk plant in August 2007
and hired a contractor in November 2007. The estimated
cost to rebuild the upper reservoir is in the range of
$450 million. UE expects the Taum Sauk plant to be out of
service through at least the fall of 2009.
In December 2006, the state of Missouri, through its
attorney general, and 10 business owners filed separate
lawsuits regarding the Taum Sauk breach. The attorney
general’s suit, which was filed in the Missouri Circuit Court
of St. Louis and subsequently transferred to the Circuit
Court of Reynolds County, alleged negligence, violations of
the Missouri Clean Water Act, and various other statutory
and common law claims. The business owners’ suit, which
was filed in the Missouri Circuit Court of Reynolds County
and remains pending, contains similar allegations and seeks
damages relating to business losses, lost profit, and
unspecified punitive damages.
In November 2007, UE entered into a settlement
agreement with the state of Missouri represented by the
Missouri Attorney General, the Missouri Conservation
Commission and the Missouri Department of Natural
Resources that resolved the state of Missouri’s lawsuit and
claims for damages and other relief related to the December
2005 Taum Sauk breach. The $177 million settlement
agreement included cash payments to various state funds. In
addition, pursuant to the settlement agreement, UE is
required to replace the breached upper reservoir at the Taum
Sauk pumped-storage hydroelectric plant with a new upper
reservoir, subject to authorization by FERC, which was
received in August 2007. The Circuit Court of Reynolds
County approved the settlement agreement through a
consent judgment in January 2008.
As part of the settlement agreement, UE agreed that it
will not attempt to recover from ratepayers in any future rate
increase any in-kind or monetary payments to the state
parties required by the settlement agreement or costs
incurred in the reconstruction of the new upper reservoir
(expressly excluding, however, enhancements, costs incurred
due to circumstances or conditions that are currently not
reasonably foreseeable and costs that would have been
incurred absent the December 2005 breach of the upper
reservoir at UE’s Taum Sauk pumped-storage hydroelectric
plant).
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 $199 million to $219 million.
As of December 31, 2007, UE had paid $96 million and
accrued a $103 million liability, including costs resulting
from the FERC-approved stipulation and consent agreement
discussed above, while expensing $32 million and recording
a $167 million receivable due from insurance companies. As
of December 31, 2007, UE had received $89 million from
insurance companies, which reduced the insurance
receivable balance to $78 million. As of December 31, 2007,
UE had a $121 million receivable due from insurance
companies related to the rebuilding of the facility. Under
UE’s insurance policies, all claims by or against UE are
subject to review by its insurance carriers.
In September 2007, the Missouri Coalition for the
Environment, the Sierra Club, and American Rivers filed a
motion to seek intervention and rehearing and a stay of
FERC authorization granted to UE to rebuild the upper
reservoir at its Taum Sauk plant. In December 2007, FERC
granted intervention, denied rehearing, and dismissed the
request for stay. In February 2008, the Missouri Coalition for
the Environment and the Missouri Parks Association filed an
appeal of FERC’s decision with the U.S. Court of Appeals for
the Eighth Circuit. We are unable to predict how or when the
Court of Appeals will rule on this appeal.
In December 2007, the Missouri Parks Association filed
a lawsuit in the U.S. District Court for the District of
Columbia against UE and FERC to stop the reconstruction of
the upper reservoir at the Taum Sauk plant. The Missouri
Parks Association claims that FERC failed to adequately
study the environmental effect of reopening the hydroelectric
plant or alternatives to rebuilding it. In January 2008, UE
filed a motion to dismiss the lawsuit, arguing that the
U.S. District Court lacks jurisdiction over the subject matter
of the case. This motion is currently pending.
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.
156
Mechanics’ Liens
Approximately 20 mechanics’ liens were filed by various
subcontractors who provided labor or material for a 2007
planned maintenance outage at the Duck Creek facility of
CILCO subsidiary, AERG. The total lien claim amount was
$26 million plus interest at December 31, 2007. In
November 2007, the primary subcontractor on the project
filed a complaint for foreclosure of its mechanic’s lien of
$19 million plus interest against AERG in the Circuit Court of
Fulton County, Illinois. AERG believes it has paid the general
contractor the amount due in full (less a contract-allowed
holdback of $4 million), and since this arose out of a
contract dispute between the general contractor and the
primary subcontractor, AERG is currently considering its
potential remedies against the general contractor. At this
time, we are unable to predict the impact of these liens and
lawsuit on CILCO’s or AERG’s future 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
189 parties are named in some pending cases and as few as
six in others. However, in the cases that were pending as of
December 31, 2007, the average number of parties was 70.
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 Dynegy 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, which, if
awarded at trial, typically would be shared among the
various defendants.
From October 1, 2007, through December 31, 2007, six additional asbestos-related lawsuits were filed against UE, CIPS,
CILCO and IP, mostly in the circuit court of Madison County, Illinois. Seven lawsuits were settled. The following table presents
the status as of December 31, 2007, of the asbestos-related lawsuits that have been filed against the Ameren Companies:
Filed . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settled . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dismissed . . . . . . . . . . . . . . . . . . . . . . . . .
Pending . . . . . . . . . . . . . . . . . . . . . . . . . . .
349
123
151
75
31
-
27
4
Total(a)
Ameren
Specifically Named as Defendant
UE
194
64
100
30
CIPS
Genco
CILCO
147
56
52
39
2
-
2
-
49
19
12
18
IP
165
63
72
30
(a) Totals do not equal to the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
As of December 31, 2007, nine asbestos-related
NOTE 14 – CALLAWAY NUCLEAR PLANT
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 and financed with
contributions of $10 million each by Ameren and Dynegy. At
December 31, 2007, the trust fund balance was $22 million,
including accumulated interest.
If cash expenditures are less than the amount in base
rates, IP will contribute 90% of the difference to the fund.
Once the trust fund is depleted, 90% of allowed cash
expenditures in excess of base rates will be recovered
through charges assessed to customers under the tariff
rider.
The Ameren Companies believe that the final disposition
of these proceedings will not have a material adverse effect
on their results of operations, financial position, or liquidity.
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
until at least 2017. 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
157
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 then be
decommissioned by immediate dismantlement 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 2007, 2006 and 2005. 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 2005. Minor tritium
contamination was discovered on the Callaway nuclear plant
site in the summer of 2006. Existing facts and regulatory
requirements indicate that this discovery will not cause any
significant increase in the decommissioning cost estimate
when the next study is conducted and filed on September 1,
2008. 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.
NOTE 15 – FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to
estimate the fair value of each class of financial instruments
for which such estimates are practicable to estimate that
value:
Cash, Temporary Investments, and Short-term Borrowings
The carrying amounts approximate fair value because
of the short-term maturity of these instruments.
Marketable Securities
The fair value is based on quoted market prices
obtained from dealers or investment managers.
Nuclear Decommissioning Trust Fund
The fair value estimate is based on quoted market
prices for securities held in the trust fund.
Long-term Debt
The fair value estimate is based on the quoted market
prices for same or similar issues or on the current rates
offered to the Ameren Companies for debt of comparable
maturities.
Preferred Stock of UE, CIPS, CILCO and IP
The fair value estimate is based on the quoted market
prices for the same or similar issues.
Derivative Financial Instruments
Market prices used to determine fair value are primarily
based on published indices and closing exchange prices. In
addition, valuations must rely on management’s estimates,
which take into account time value of money and volatility
factors.
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at
December 31, 2007 and 2006:
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:
2007
2006
Carrying Amount
Fair Value
Carrying Amount
Fair Value
$5,912
211
$3,360
113
$ 471
50
$5,821
147
$3,255
85
$ 472
27
$5,741
212
$2,939
113
$ 471
50
$5,636
162
$2,817
92
$ 480
32
Long-term debt (including current portion) . . . . . . .
$ 474
$ 510
$ 474
$ 540
CILCORP:
Long-term debt (including current portion) . . . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . .
$ 516
27
$ 592
36
$ 552
33
$ 537
35
158
2007
2006
Carrying Amount
Fair Value
Carrying Amount
Fair Value
CILCO:
Long-term debt (including current portion) . . . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . .
IP:
Long-term debt (including current portion) . . . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . .
$ 148
35
$1,069
46
$ 149
27
$1,067
32
$ 198
36
$ 915
46
$ 200
33
$ 898
18
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
UE has investments in debt and equity securities that
are held in a trust fund for the purpose of funding the
nuclear decommissioning of its Callaway nuclear plant. See
Note 14 – 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, 2007 and 2006.
Investments by the nuclear decommissioning trust fund
are allocated 60% to 70% to equity securities, with the
balance invested in fixed-income securities.
Downgrades of subprime U.S. mortgage-related assets
have resulted in a decline in the fair value of
subprime-related investments. UE has assessed the
investments held in its nuclear decommissioning trust fund
and determined that direct exposure to subprime mortgages
was not material.
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, 2007, 2006 and 2005:
Proceeds from sales . . . . .
Gross realized gains . . . . .
Gross realized losses . . . .
2007
$128
4
3
2006
2005
$98
2
2
$99
1
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.
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, 2007 and 2006:
Security Type
Cost
Gross Unrealized Gain
Gross Unrealized Loss
Fair Value
2007:
Debt securities . . . . . . . . . . . . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . . . . .
Cash equivalents. . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006:
Debt securities . . . . . . . . . . . . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . . . . .
Cash equivalents. . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$109
104
2
$215
$ 91
105
4
$200
$ 3
97
-
$100
$ 1
90
-
$ 91
$1
7
-
$8
$1
5
-
$6
$111
194
2
$307
$ 91
190
4
$285
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, 2007:
Less than 5 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5 years to 10 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Due after 10 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost
$ 44
34
31
$109
Fair Value
$ 45
34
32
$111
We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust fund. We
believe that these losses are temporary in nature, and we expect the investments to recover their value in the future given the
long-term nature of these investments. Decommissioning will not occur until the operating license for our nuclear facility
expires. 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 that were not deemed to be other-than-temporarily impaired. They are aggregated by
159
investment category and the length of time that individual securities have been in a continuous unrealized loss position, at
December 31, 2007:
Less than 12 Months
12 Months or Greater
Total
Gross
Unrealized
Losses
$1
2
$3
Gross
Unrealized
Losses
$ -
5
$5
Gross
Unrealized
Losses
$1
7
$8
Fair Value
$25
17
$42
Fair Value
$12
6
$18
Fair Value
$13
11
$24
Debt securities . . . . . . . . . . .
Equity securities . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . .
NOTE 16 – 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.
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
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.
The following tables present information about the reported revenues and specified items included in net income of Ameren
for the years ended December 31, 2007, 2006 and 2005, and total assets as of December 31, 2007, 2006 and 2005.
Missouri
Regulated
Illinois
Regulated
Non-rate-
regulated
Generation
Other
Intersegment
Eliminations
Consolidated
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)
. . . . . . . . . . . . . . . . .
$ 2,915
46
333
34
194
143
281
625
10,852
$ 2,584
227
335
33
171
184
267
782
10,254
$1,313
485
105
2
107
182
281
395
4,027
$ 926
788
106
1
103
78
138
160
3,612
$
14
40
26
52
29
(20)
9
40
965
$
46
27
28
34
29
(43)
27
28
1,161
$
-
(633)
-
(59)
(39)
-
-
-
(1,501)
$
-
(1,057)
-
(50)
(48)
-
-
-
(1,672)
$ 7,546
-
681
55
423
330
618
1,381
20,728
$ 6,880
-
661
38
350
284
547
1,284
19,635
$3,304
62
217
26
132
25
47
321
6,385
$3,324
15
192
20
95
65
115
314
6,280
160
2005
External revenues . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . .
Depreciation and amortization . . . . . . .
Interest and dividend income . . . . . . . .
Interest expense . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . .
Net income(a)(c)
. . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . .
Total assets(b)
. . . . . . . . . . . . . . . . .
Missouri
Regulated
Illinois
Regulated
Non-rate-
regulated
Generation
$ 2,635
254
310
9
116
206
329
775
9,261
$3,264
41
190
21
86
101
166
251
6,072
$ 829
847
106
1
119
86
95
134
3,529
Other
$
52
37
26
32
27
(37)
16
37
1,280
Intersegment
Eliminations
Consolidated
$
-
(1,179)
-
(50)
(47)
-
-
(262)(d)
(1,971)
$ 6,780
-
632
13
301
356
606
935
18,171
(a) Represents net income available to common shareholders; 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).
Includes cumulative effect of change in accounting principal net of income taxes of $(22) for consolidated Ameren.
(c)
(d) Elimination of UE’s CT purchases from Non-rate-regulated Generation.
The following tables present information about the reported revenues and specified items included in net income of UE for
the years ended December 31, 2007, 2006 and 2005, and total assets as of December 31, 2007, 2006 and 2005.
Missouri Regulated
Other(a)
Consolidated UE
2007
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2005
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Includes 40% interest in EEI and other non-rate-regulated activities.
(a)
(b) Represents net income available to the common shareholder (Ameren).
$ 2,961
333
194
143
281
625
10,852
$ 2,811
335
171
184
267
782
10,254
$ 2,889
310
116
206
329
775
9,261
$ -
-
-
(3)
55
-
51
$ 12
-
-
-
76
-
36
$ -
-
-
(13)
17
-
16
$ 2,961
333
194
140
336
625
10,903
$ 2,823
335
171
184
343
782
10,290
$ 2,889
310
116
193
346
775
9,277
161
The following tables present information about the reported revenues and specified items included in net income of
CILCORP for the years ended December 31, 2007, 2006 and 2005, and total assets as of December 31, 2007, 2006 and 2005.
Illinois
Regulated
Non-rate-
regulated
Generation
CILCORP
Other
Intersegment
Eliminations
Consolidated
CILCORP
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)
. . . . . . . . . . . . . . . . . . . . .
2005
External revenues . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . .
Net income (loss)(a)
. . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . .
Total assets(b)
. . . . . . . . . . . . . . . . . . . . .
$ 718
-
54
18
-
9
64
1,202
$ 699
-
53
15
12
25
53
1,217
$ 719
-
52
13
12
30
55
1,231
$ 272
4
24
46
21
38
190
1,455
$
34
181
22
37
(19)
(3)
66
1,246
$
24
182
20
38
(12)
(24)
52
1,210
$ -
-
-
-
-
-
-
1
$ -
-
-
-
(4)
(3)
-
4
$ 4
-
-
-
(3)
(3)
-
4
$
-
(4)
-
-
-
-
-
(199)
$
-
(181)
-
-
-
-
-
(217)
$
-
(182)
-
-
-
-
-
(202)
$ 990
-
78
64
21
47
254
2,459
$ 733
-
75
52
(11)
19
119
2,250
$ 747
-
72
51
(3)
3
107
2,243
(a) Represents net income available to the common shareholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the
Illinois Regulated segment.
(b) Total assets for Illinois Regulated include an allocation of goodwill and other purchase accounting amounts related to CILCO that are
recorded at CILCORP (parent company).
The following tables present information about the reported revenues and specified items included in net income of CILCO
for the years ended December 31, 2007, 2006 and 2005, and total assets as of December 31, 2007, 2006 and 2005.
Illinois
Regulated
Non-rate-
regulated
Generation
CILCO
Other
Intersegment
Eliminations
Consolidated
CILCO
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 . . . . . . . . . . . . . . . . . . . . . . . . .
$ 718
-
54
18
-
9
64
1,012
$ 699
-
53
15
12
25
53
1,029
$272
4
19
8
39
65
190
859
$ 34
181
17
3
2
23
66
642
162
$ -
-
-
1
-
-
-
-
$ -
-
-
-
(4)
(3)
-
1
$
-
(4)
-
-
-
-
-
(9)
$
-
(181)
-
-
-
-
-
(22)
$ 990
-
73
27
39
74
254
1,862
$ 733
-
70
18
10
45
119
1,650
Illinois
Regulated
Non-rate-
regulated
Generation
CILCO
Other
Intersegment
Eliminations
Consolidated
CILCO
2005
External revenues . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . .
Net income (loss)(a)
. . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . .
$ 719
-
52
13
12
30
55
1,008
$ 24
182
15
1
9
(5)
52
563
$(1)
-
-
-
(5)
(1)
-
1
$
-
(182)
-
-
-
-
-
(15)
$ 742
-
67
14
16
24
107
1,557
(a) Represents net income available to the common shareholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the
Illinois Regulated segment.
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, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . .
$2,019
1,800
1,723
1,550
1,997
1,910
1,807
1,620
$288
196
322
276
479
547
253
154
$123
70
143
123
244
293
108
61
$0.59
0.34
0.69
0.60
1.18
1.42
0.52
0.30
Quarter Ended
UE
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . .
September 30, 2006 . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006 . . . . . . . . . . . . . . . . . . . . . .
CIPS
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . .
September 30, 2006 . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006 . . . . . . . . . . . . . . . . . . . . . .
Operating
Revenues
Operating
Income (Loss)
Net
Income (Loss)
Net Income (Loss)
Available to
Common
Stockholder
$ 33
51
81
92
193
166
35
40
$ 13
(1)
5
15
1
29
(2)
(5)
$ 32
50
79
90
192
165
33
38
$ 12
(2)
5
15
-
28
(3)
(6)
$ 68
90
144
170
317
271
61
89
$ 24
2
15
21
8
52
2
(6)
$650
636
697
710
945
857
669
620
$314
257
229
212
224
254
238
231
163
Quarter Ended
Genco(a)
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . .
September 30, 2006 . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006 . . . . . . . . . . . . . . . . . . . . . .
CILCORP(a)
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . .
September 30, 2006 . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006 . . . . . . . . . . . . . . . . . . . . . .
CILCO
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . .
September 30, 2006 . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006 . . . . . . . . . . . . . . . . . . . . . .
IP
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2006 . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . .
September 30, 2006 . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . .
December 31, 2006 . . . . . . . . . . . . . . . . . . . . . .
Operating
Revenues
Operating
Income (Loss)
Net
Income (Loss)
Net Income (Loss)
Available to
Common
Stockholder
$243
247
185
238
221
259
223
248
$310
242
223
146
206
158
251
187
$310
242
223
146
206
158
251
187
$515
497
365
339
356
435
410
423
$81
26
41
19
56
34
78
52
$44
25
36
8
19
27
36
5
$47
31
39
10
25
32
33
6
$40
19
29
37
8
85
32
-
$42
6
17
2
25
19
41
22
$21
8
12
1
1
13
13
(3)
$27
17
21
8
10
19
18
3
$15
4
7
16
(4)
43
8
(6)
$42
6
17
2
25
19
41
22
$21
8
12
1
1
13
13
(3)
$27
17
20
8
10
19
17
1
$14
3
7
16
(5)
42
8
(6)
(a) Genco and CILCORP had no preferred stock outstanding.
During the third quarter of 2007, we identified a misallocation of first quarter 2007 purchased power expense among
Ameren subsidiaries. The error resulted in an understatement of UE and Genco purchased power expense of approximately
$7 million and $2 million, respectively, and an overstatement of CIPS, CILCORP, CILCO and IP purchased power expense of
approximately $4 million, $1 million, $1 million, and $4 million, respectively, during the three months ended March 31, 2007.
The error resulted in an overstatement of UE and Genco net income of $5 million and $1 million, respectively, and an
understatement of CIPS, CILCORP, CILCO and IP net income of approximately $3 million, $1 million, $1 million, and $3 million,
respectively, during the three months ended March 31, 2007. The error did not have a significant impact on previously reported
subsidiary balance sheets or statements of cash flows, and the error had no impact on Ameren’s previously reported
consolidated financial position, results of operations or cash flows.
UE, CIPS, Genco, CILCORP, CILCO and IP information for the quarter ended March 31, 2007 in the table above reflects the
correction of this error. As a result, UE, CIPS, Genco, CILCORP, CILCO and IP financial information for the quarter ended
March 31, 2007, in the table above differs from financial information reflected in the registrants’ previously filed combined
Form 10-Q for the quarter ended March 31, 2007.
164
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 2007 fiscal year.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2007, 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 have 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, 2007. The
effectiveness of Ameren’s internal control over financial reporting as of December 31, 2007, 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) registered public accounting firm regarding internal control over financial reporting. Management’s
report for the Subsidiary Registrants was not subject to attestation by the registered public accounting firm because temporary
rules of the SEC permit the company to provide only management’s report in this annual report.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness into future periods are subject to the risk that controls 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 2007 that has not previously been reported on an SEC Form 8-K.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
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 2008 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 2008 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’ 2008 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.
165
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, Susan S.
Elliott and Richard A. Liddy serve as members. The board of
directors of Ameren has determined that Douglas R.
Oberhelman qualifies as an audit committee financial expert
and that he is “independent” as that term is used in SEC
Regulation 14A.
Also, on the same basis as reported above, the boards
of directors of UE, CIPS, Genco, 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
ITEM 11. EXECUTIVE COMPENSATION.
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, 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 2008 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 their 2008 annual meetings 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’ 2008 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.
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, 2007, with respect to the shares of Ameren’s common stock
that may be issued under its existing equity compensation plans.
Plan
Category
Equity compensation plans approved by
security holders(a) . . . . . . . . . . . . . .
Equity compensation plans not approved
by security holders . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . .
Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
(a)
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
(b)
Number of Securities Remaining
Available for Future Issuance Under
Equity Compensation Plans (excluding
securities reflected in column (a))
(c)
835,045
-
835,045
$33.10(b)
-
$33.10(b)
3,759,292
-
3,759,292
(a) Consists of the Ameren Corporation Long-term Incentive Plan of 1998, which was approved by shareholders in April 1998 and expires 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, 745,058 of the securities represent PSUs at the target level of awards (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.
166
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 2008 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 2008 annual meetings 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 approximately 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, 2008. 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, 2008, 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
2008 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 2008 annual meetings 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’ 2008 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 2008 annual meetings of
shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference.
167
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)(1) Financial Statements
Page No.
Ameren
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholders’ Equity – Years Ended December 31, 2007, 2006 and 2005 . . .
UE
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholders’ Equity – Years Ended December 31, 2007, 2006 and 2005 . . .
CIPS
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Common Stockholders’ Equity – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . .
Genco
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholder’s Equity – Years Ended December 31, 2007, 2006 and 2005. . . .
CILCORP
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholder’s Equity – Years Ended December 31, 2007, 2006 and 2005. . . .
CILCO
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholders’ Equity – Years Ended December 31, 2007, 2006 and 2005 . . .
IP
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholders’ Equity – Years Ended December 31, 2007, 2006 and 2005 . . .
(a)(2) Financial Statement Schedules
Schedule I – Condensed Financial Information of Parent – CILCORP:
Condensed Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . .
Condensed Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condensed Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . .
Schedule I – Condensed Financial Information of Parent – CILCO:
Condensed Statement of Income – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . .
Condensed Balance Sheet – December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condensed Statement of Cash Flows – Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . .
Schedule II – Valuation and Qualifying Accounts for the years ended December 31, 2007, 2006 and 2005 . . . . . .
73
77
78
79
80
74
81
82
83
84
74
85
86
87
88
75
89
90
91
92
75
93
94
95
96
76
97
98
99
100
76
101
102
103
104
169
169
169
170
170
170
171
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 180.
(b)
Exhibits are listed in the Exhibit Index commencing on page 180.
168
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CILCORP INC.
CONDENSED STATEMENT OF INCOME
For the Years Ended December 31, 2007, 2006, and 2005
(In millions)
Operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in earnings of subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
$
-
8
(8)
74
37
(18)
2006
$ -
14
(14)
45
33
(21)
2005
$
-
3
(3)
24
39
(21)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 47
$ 19
$ 3
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CILCORP INC.
CONDENSED BALANCE SHEET
December 31, 2007
December 31, 2006
(In millions)
Assets:
Cash and equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
16
16
606
712
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$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
190
191
389
42
712
$
-
12
12
517
724
$1,253
$
14
137
151
394
39
669
Total liabilities and stockholder’s equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,334
$1,253
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CILCORP INC.
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2007, 2006, and 2005
(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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
2006
2005
$(39)
-
39
-
-
-
-
$ (11)
136
(125)
-
-
-
65
$(32)
31
1
-
-
-
30
CILCORP (Parent Company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2007
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 13 – 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).
169
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED STATEMENT OF INCOME
For the Years Ended December 31, 2007, 2006, and 2005
(In millions)
Operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in earnings of subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
$718
689
29
65
20
-
2006
$699
638
61
20
24
12
2005
$719
657
62
(6)
20
12
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 74
$ 45
$ 24
(In millions)
Assets:
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED BALANCE SHEET
December 31, 2007
December 31, 2006
Cash and equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
4
190
194
385
809
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
52
158
210
148
409
621
$
-
197
197
333
812
$1,342
$
84
140
224
148
435
535
Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,388
$1,342
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2007, 2006, and 2005
(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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
$ 28
(54)
30
4
-
4
10
2006
$ 84
(36)
(49)
(1)
1
-
19
2005
$ 39
(101)
62
-
1
1
-
CENTRAL ILLINOIS LIGHT COMPANY (Parent Company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2007
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 13 – 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).
170
(In millions)
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
Column A
Description
Column B
Balance at
Beginning of
Period
Column C
Column D
Column E
(1)
Charged to Costs
and Expenses
(2)
Charged to Other
Accounts
Deductions(a)
Balance at End
of Period
$-
-
-
$-
-
-
$-
-
-
$-
-
-
$-
-
-
$-
-
-
$42
39
30
$14
13
16
$ 7
5
6
$ 6
6
6
$ 6
6
6
$15
14
1
$22
11
22
$ 6
6
6
$ 5
2
4
$ 2
1
5
$ 2
1
5
$ 9
3
8
Ameren:
Deducted from assets – allowance for doubtful
accounts:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . .
UE:
Deducted from assets – allowance for doubtful
accounts:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS:
Deducted from assets – allowance for doubtful
accounts:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP:
Deducted from assets – allowance for doubtful
accounts:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO:
Deducted from assets – allowance for doubtful
accounts:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . .
IP:
Deducted from assets – allowance for doubtful
accounts:
2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . .
2005 . . . . . . . . . . . . . . . . . . . . . . . . . .
(a) Uncollectible accounts charged off, less recoveries.
$11
22
14
$ 6
6
3
$ 2
4
1
$ 1
5
3
$ 1
5
3
$ 3
8
6
$53
28
38
$14
13
19
$10
3
9
$ 7
2
8
$ 7
2
8
$21
9
3
171
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned
company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
SIGNATURES
Date: February 29, 2008
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
Richard A. Liddy
Gordon R. Lohman
*
*
*
*
*
*
*
*
Charles W. Mueller
*
Douglas R. Oberhelman
*
Harvey Saligman
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
172
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
*
*
Patrick T. Stokes
Jack D. Woodard
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
Director
Director
February 29, 2008
February 29, 2008
February 29, 2008
173
Date: February 29, 2008
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
Richard J. Mark
Steven R. Sullivan
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
*
*
*
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
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
174
Date: February 29, 2008
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (registrant)
By /s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
*
*
*
Daniel F. Cole
Steven R. Sullivan
Thomas R. Voss
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
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
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
175
Date: February 29, 2008
AMEREN ENERGY GENERATING COMPANY (registrant)
By /s/ R. Alan Kelley
R. Alan Kelley
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/ R. Alan Kelley
R. Alan Kelley
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
Daniel F. Cole
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
Steven R. Sullivan
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
176
Date: February 29, 2008
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
Richard A. Liddy
Steven R. Sullivan
Thomas R. Voss
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
*
*
*
*
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
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
177
Date: February 29, 2008
CENTRAL ILLINOIS LIGHT COMPANY (registrant)
By /s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
*
*
*
Daniel F. Cole
Steven R. Sullivan
Thomas R. Voss
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
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
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
178
Date: February 29, 2008
ILLINOIS POWER COMPANY (registrant)
By /s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
*
*
*
Daniel F. Cole
Steven R. Sullivan
Thomas R. Voss
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
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
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
February 29, 2008
179
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are
incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed
are filed herewith:
EXHIBIT INDEX
Exhibit Designation
Articles of Incorporation/ By-Laws
Registrant(s)
3.1(i)
Ameren
3.2(i)
Ameren
3.3(i)
UE
3.4(i)
CIPS
3.5(i)
Genco
3.6(i)
Genco
3.7(i)
CILCORP
3.8(i)
CILCORP
3.9(i)
CILCO
3.10(i)
3.11(i)
IP
IP
3.12(ii)
Ameren
3.13(ii)
UE
3.14(ii)
CIPS
3.15(ii)
Genco
Nature of Exhibit
Previously Filed as Exhibit to:
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
Restated Articles of
Incorporation of CIPS
1993 Form 10-K, Exhibit 3(i),
File No. 1-2967
March 31, 1994 Form 10-Q,
Exhibit 3(b), File No. 1-3672
Articles of Incorporation of
Genco
Exhibit 3.1, Form S-4, File
No. 333-56594
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
Articles of Incorporation of
CILCO as amended May 29,
1998
Amended and Restated Articles
of Incorporation of IP, dated
September 7, 1994
Articles of Amendment to IP’s
Amended and Restated Articles
of Incorporation filed March 28,
2002
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
1998 Form 10-K, Exhibit 3, File
No. 1-2732
September 7, 1994 Form 8-K,
Exhibit 3(a), File No. 1-3004
Exhibit 4.1(ii), File
No. 333-84008
By-Laws of Ameren as amended
effective August 28, 2005
August 29, 2005 Form 8-K,
Exhibit 3.2(ii), File No. 1-14756
By-Laws of UE as amended to
August 25, 2005
August 29, 2005 Form 8-K/A,
Exhibit 3.1(ii), File No. 1-2967
By-Laws of CIPS as amended
October 8, 2004
October 14, 2004 Form 8-K,
Exhibit 3.1, 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
180
Exhibit Designation
3.16(ii)
Registrant(s)
CILCORP
Nature of Exhibit
By-Laws of CILCORP as
amended as of October 8, 2004
Previously Filed as Exhibit to:
September 30, 2004 Form 10-Q,
Exhibit 3.2, File No. 1-8946
3.17(ii)
CILCO
3.18(ii)
IP
By-Laws of CILCO as amended
effective October 8, 2004
October 14, 2004 Form 8-K,
Exhibit 3.2, File No. 1-2732
By-Laws of IP as amended
October 8, 2004
October 14, 2004 Form 8-K,
Exhibit 3.3, File No. 1-3004
Instruments Defining Rights of Security Holders, Including Indentures
4.1
Ameren
4.2
Ameren
4.3
4.4
4.5
4.6
4.7
4.8
4.9
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
October 14, 1998 Form 8-K,
Exhibit 4, File No. 1-14756
Exhibit 4.5, File No. 333-81774
Exhibit B-1, File No. 2-4940
April 1971 Form 8-K, Exhibit 6,
File No. 1-2967
February 1974 Form 8-K,
Exhibit 3, File No. 1-2967
Exhibit 4.6, File No. 2-69821
1993 Form 10-K, Exhibit 4.6,
File No. 1-2967
1993 Form 10-K, Exhibit 4.8,
File No. 1-2967
2000 Form 10-K, Exhibit 4.1,
File No. 1-2967
Agreement, dated as of
October 9, 1998, between
Ameren and Computershare
Trust Company, Inc., as
successor rights agent, which
includes the form of Certificate
of Designation of the Preferred
Shares as Exhibit A, the form of
Rights Certificate as Exhibit B,
and the Summary of Rights as
Exhibit C
Indenture of Ameren with The
Bank of New York, as Trustee,
relating to senior debt securities
dated as of December 1, 2001
(Ameren’s Senior Indenture)
Indenture of Mortgage and
Deed of Trust dated June 15,
1937 (UE Mortgage), from UE
to The Bank of New York, 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
Supplemental Indenture to the
UE Mortgage dated as of
February 1, 1974
Supplemental Indenture to the
UE Mortgage dated as of July 7,
1980
Supplemental Indenture to the
UE Mortgage dated as of May 1,
1993
Supplemental Indenture to the
UE Mortgage dated as of
October 1, 1993
Supplemental Indenture to the
UE Mortgage dated as of
February 1, 2000
181
Exhibit Designation
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
Registrant(s)
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Previously Filed as Exhibit to:
August 23, 2002 Form 8-K,
Exhibit 4.3, File No. 1-2967
March 11, 2003 Form 8-K,
Exhibit 4.4, File No. 1-2967
April 10, 2003 Form 8-K,
Exhibit 4.4, File No. 1-2967
August 4, 2003 Form 8-K,
Exhibit 4.4, File No. 1-2967
October 8, 2003 Form 8-K,
Exhibit 4.4, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.1, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.2, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.3, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.4, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.5, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.6, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.7, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.8, File No. 1-2967
Nature of Exhibit
Supplemental Indenture to the
UE Mortgage dated August 15,
2002
Supplemental Indenture to the
UE Mortgage dated March 5,
2003
Supplemental Indenture to the
UE Mortgage dated April 1,
2003
Supplemental Indenture to the
UE Mortgage dated July 15,
2003
Supplemental Indenture to the
UE Mortgage dated October 1,
2003
Supplemental Indenture to the
UE Mortgage dated February 1,
2004, relative to Series 2004A
(1998A) Bonds
Supplemental Indenture to the
UE Mortgage dated February 1,
2004, relative to Series 2004B
(1998B) Bonds
Supplemental Indenture to the
UE Mortgage dated February 1,
2004, relative to Series 2004C
(1998C) Bonds
Supplemental Indenture to the
UE Mortgage dated February 1,
2004, relative to Series 2004D
(2000B) Bonds
Supplemental Indenture to the
UE Mortgage dated February 1,
2004, relative to Series 2004E
(2000A) Bonds
Supplemental Indenture to the
UE Mortgage dated February 1,
2004, relative to Series 2004F
(2000C) Bonds
Supplemental Indenture to the
UE Mortgage dated February 1,
2004, relative to Series 2004G
(1991) Bonds
Supplemental Indenture to the
UE Mortgage dated February 1,
2004, relative to Series 2004H
(1992) Bonds
182
Exhibit Designation
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
Registrant(s)
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
4.32
Ameren
UE
Nature of Exhibit
Supplemental Indenture to the
UE Mortgage dated May 1,
2004
Supplemental Indenture to the
UE Mortgage dated
September 1, 2004
Supplemental Indenture to the
UE Mortgage dated January 1,
2005
Previously Filed as Exhibit to:
May 18, 2004 Form 8-K,
Exhibit 4.4, File No. 1-2967
September 23, 2004 Form 8-K,
Exhibit 4.4, File No. 1-2967
January 27, 2005 Form 8-K,
Exhibit 4.4, File No. 1-2967
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
June 15, 2007 Form 8-K,
Exhibit 4.5, File No. 1-2967
1992 Form 10-K, Exhibit 4.37,
File No. 1-2967
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
Supplemental Indenture to the
UE Mortgage dated June 1,
2007
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.
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
183
Exhibit Designation
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
4.41
4.42
Registrant(s)
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Previously Filed as Exhibit to:
September 30, 1998 Form 10-Q,
Exhibit 4.28, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.11, File No. 1-2967
September 30, 1998 Form 10-Q,
Exhibit 4.29, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.12, File No. 1-2967
September 30, 1998 Form 10-Q,
Exhibit 4.30, File No. 1-2967
March 31, 2004 Form 10-Q,
Exhibit 4.13, File No. 1-2967
August 23, 2002 Form 8-K,
Exhibit 4.1, File No. 1-2967
August 23, 2002 Form 8-K,
Exhibit 4.2, File No. 1-2967
March 11, 2003 Form 8-K,
Exhibits 4.2 and 4.3, File
No. 1-2967
April 10, 2003 Form 8-K,
Exhibits 4.2 and 4.3, File
No. 1-2967
Nature of Exhibit
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, as Trustee (relating
to senior secured debt
securities)
UE Company Order dated
August 22, 2002, establishing
the 5.25% Senior Secured
Notes due 2012 (including the
global note)
UE Company Order dated
March 10, 2003, establishing
the 5.50% Senior Secured
Notes due 2034 (including the
global note)
UE Company Order dated
April 9, 2003, establishing the
4.75% Senior Secured Notes
due 2015 (including the global
note)
184
Exhibit Designation
4.43
4.44
4.45
4.46
4.47
4.48
4.49
4.50
4.51
4.52
Registrant(s)
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
CIPS
Ameren
CIPS
Previously Filed as Exhibit to:
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
Exhibit 2.01, File No. 2-60232
Amended Exhibit 7(b), File
No. 2-7341
Nature of Exhibit
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)
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
185
Exhibit Designation
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60
4.61
4.62
4.63
4.64
4.65
4.66
Registrant(s)
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
4.67
Ameren
CIPS
Nature of Exhibit
Supplemental Indenture to the
CIPS Mortgage, dated January 1,
1949
Previously Filed as Exhibit to:
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
Exhibit 4.5, 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
Trust Company, N.A., as
successor trustee (CIPS
Indenture)
CIPS Global Note, dated
December 22, 1998,
representing Senior Secured
Notes, 5.375% due 2008
186
Exhibit Designation
4.68
4.69
4.70
4.71
4.72
4.73
4.74
4.75
4.76
Registrant(s)
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
CILCORP
Previously Filed as Exhibit to:
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
Exhibits 4.1 and 4.2, File
No. 333-90373
Nature of Exhibit
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
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
Form of 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
Indenture, dated as of
October 18, 1999, between
Midwest Energy, Inc., and The
Bank of New York
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
Trust Company, N.A., as
successor trustee
187
Exhibit Designation
4.77
4.78
4.79
4.80
4.81
4.82
4.83
4.84
4.85
4.86
Registrant(s)
Nature of Exhibit
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
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
Indenture dated as of June 1,
2006, from CILCO to The Bank
of New York Trust Company,
N.A., as trustee
188
Previously Filed as Exhibit to:
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
June 19, 2006 Form 8-K,
Exhibit 4.3, File No. 1-2732
Exhibit Designation
4.87
4.88
4.89
4.90
4.91
4.92
4.93
4.94
4.95
4.96
4.97
Registrant(s)
Nature of Exhibit
Ameren
CILCO
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
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)
General Mortgage Indenture and
Deed of Trust dated as of
November 1, 1992 between IP
and BNY Midwest Trust
Company, 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
189
Previously Filed as Exhibit to:
June 19, 2006 Form 8-K,
Exhibit 4.6, 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
Registrant(s)
Nature of Exhibit
Exhibit Designation
4.98
4.99
4.100
4.101
4.102
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
4.103
Ameren
IP
4.104
Material Contracts
10.1
10.2
Ameren
CIPS
Genco
Ameren
Genco
Ameren
IP
10.3
Ameren Companies
10.4
Ameren
Genco
CILCORP
Previously Filed as Exhibit to:
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
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
May 2, 2005 Form 8-K, Exhibit
4.1, File No. 1-14756
December 21, 2006 Form 8-K,
Exhibit 10.1, File No. 1-14756
October 1, 2004 Form 8-K,
Exhibit 10.3, File No. 3004
October 1, 2004 Form 8-K,
Exhibit 10.2, File No. 1-14756
September 30, 2003 Form 10-Q,
Exhibit 10.4, File No. 1-14756
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
Indenture, dated as of June 1,
2006 from IP to The Bank of
New York Trust Company, N.A.,
as 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)
Amended and Restated Genco
Subordinated Promissory Note
dated as of May 1, 2005
Power Supply Agreement, dated
as of December 18, 2006,
between Marketing Company
and Genco
Unilateral Borrowing Agreement
by and among Ameren, IP and
Ameren Services, dated as of
September 30, 2004
Third Amended Ameren
Corporation System Utility
Money Pool Agreement, as
amended September 30, 2004
Ameren Corporation System
Non-State-Regulated Subsidiary
Money Pool Agreement, dated
as of February 27, 2003
190
Exhibit Designation
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
Registrant(s)
Nature of Exhibit
Ameren
UE
Genco
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Ameren
CIPS
CILCORP
CILCO
IP
Ameren
CIPS
CILCORP
CILCO
IP
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
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 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 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
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
Pledge Agreement dated as of
October 18, 1999, between
CILCORP and The Bank of New
York, as collateral agent
Pledge Agreement Supplement,
dated as of July 14, 2006,
between CILCORP and The
Bank of New York, as Collateral
Agent
Pledge Agreement Supplement,
dated as of February 9, 2007,
between CILCORP and The
Bank of New York, 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 Trust
Company, N.A., as agent
191
Previously Filed as Exhibit to:
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
February 13, 2007 Form 8-K,
Exhibit 10.1, File No. 1-14756
October 29, 1999 Form 8-K,
Exhibit 10.1, File No. 2-95569
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
Exhibit Designation
10.14
Registrant(s)
Ameren
CILCORP
CILCO
10.15
Ameren
Nature of Exhibit
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
Trust Company, N.A., as agent
*Summary Sheet of Ameren
Corporation Non-Management
Director Compensation
Previously Filed as Exhibit to:
July 18, 2006 Form 8-K,
Exhibit 10.5, File No. 2-95569
June 12, 2006 Form 8-K,
Exhibit 10.1, File No. 1-14756
10.16
Ameren Companies
*Ameren’s Long-Term Incentive
Plan of 1998
1998 Form 10-K, Exhibit 10.1,
File No. 1-14756
10.17
Ameren Companies
10.18
Ameren Companies
10.19
Ameren Companies
10.20
Ameren Companies
10.21
Ameren Companies
10.22
Ameren Companies
10.23
Ameren
10.24
Ameren Companies
10.25
Ameren Companies
10.26
Ameren Companies
*First Amendment to Ameren’s
Long-Term Incentive Plan of
1998
*Form of Restricted Stock
Award under Ameren’s Long-
Term Incentive Plan of 1998
*Ameren’s Deferred
Compensation Plan for
Members of the Board of
Directors
*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
*Ameren 2007 Deferred
Compensation Plan
*2007 Deferred Compensation
Plan for Ameren Board of
Directors
*2004 Ameren Executive
Incentive Plan
*2005 Ameren Executive
Incentive Plan
*2006 Ameren Executive
Incentive Plan
February 16, 2006 Form 8-K,
Exhibit 10.6, File No. 1-14756
February 14, 2005 Form 8-K,
Exhibit 10.1, File No. 1-14756
1998 Form 10-K, Exhibit 10.4,
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
December 5, 2006 Form 8-K,
Exhibit 10.1, File No. 1-14756
December 5, 2006 Form 8-K,
Exhibit 10.2, File No. 1-14756
2003 Form 10-K, Exhibit 10.7,
File No. 1-14756
February 14, 2005 Form 8-K,
Exhibit 10.2, File No. 1-14756
February 16, 2006 Form 8-K,
Exhibit 10.2, File No. 1-14756
10.27
Ameren Companies
*2007 Executive Incentive
Compensation Plan
February 15, 2007 Form 8-K,
Exhibit 99.3, File No. 1-14756
192
Exhibit Designation
10.28
Registrant(s)
Ameren Companies
10.29
Ameren Companies
Nature of Exhibit
*2008 Executive Incentive
Compensation Plan
*2005 and 2006 Base Salary
Table for Named Executive
Officers and 2006 Executive
Officer Bonus Targets
Previously Filed as Exhibit to:
December 18, 2007 Form 8-K,
Exhibit 99.1, File No. 1-14756
December 15, 2005 Form 8-K,
Exhibit 10.1, File No. 1-14756
10.30
Ameren Companies
*2007 Base Salary Table for
Named Executive Officers
March 31, 2007 Form 10-Q,
Exhibit 10.2, File No. 1-14756
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
10.40
10.41
10.42
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
*2008 Base Salary Table for
Named Executive Officers
*Amended and Restated
Ameren Corporation Change of
Control Severance Plan
*December 14, 2007 Revised
Schedule I to 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 Pursuant to
2006 Omnibus Incentive
Compensation Plan
*CILCO Executive Deferral Plan
as amended effective August 15,
1999
*CILCO Executive Deferral
Plan II as amended effective
April 1, 1999
*CILCO Benefit Replacement
Plan as amended effective
August 15, 1999
*CILCO Restructured Executive
Deferral Plan (approved
August 15, 1999)
193
March 31, 2007 Form 10-Q,
Exhibit 10.1, 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
1999 Form 10-K, Exhibit 10, File
No. 1-2732
1999 Form 10-K, Exhibit 10(a),
File No. 1-2732
1999 Form 10-K, Exhibit 10(b),
File No. 1-2732
1999 Form 10-K, Exhibit 10(e),
File No. 1-2732
Exhibit Designation
Statement re: Computation of Ratios
Registrant(s)
12.1
Ameren
12.2
UE
12.3
CIPS
12.4
Genco
12.5
CILCORP
12.6
CILCO
12.7
IP
Code of Ethics
Nature of Exhibit
Previously Filed as Exhibit to:
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
14.1
Ameren Companies
Code of Ethics amended as of
June 11, 2004
June 30, 2004 Form 10-Q,
Exhibit 14.1, 1-14756
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
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
194
Exhibit Designation
Power of Attorney
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
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
31.5
CIPS
31.6
CIPS
31.7
Genco
31.8
Genco
31.9
CILCORP
31.10
CILCORP
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
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
Rule 13a-14(a)/15d-14(a)
Certification of Principal
Financial Officer of CILCORP
195
Previously Filed as Exhibit to:
Exhibit Designation
31.11
Registrant(s)
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
32.6
CILCO
32.7
IP
Nature of Exhibit
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
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
Additional Exhibits
99.1
Ameren
CILCORP
CILCO
Power Supply Agreement, dated
as of December 18, 2006,
between Marketing Company
and AERG
December 21, 2006 Form 8-K,
Exhibit 99.1, File No. 2-95569
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.
196
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, 2007 of Ameren Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were made,
not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over
financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
Date: February 29, 2008
/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, 2007 of Ameren Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were made,
not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over
financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
Date: February 29, 2008
/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, 2007 of Union Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were made,
not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over
financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
Date: February 29, 2008
Thomas R. Voss
/s/
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, 2007 of Union Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were made,
not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over
financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
Date: February 29, 2008
/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 PUBLIC SERVICE COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.5
I, Scott A. Cisel, certify that:
1.
Company;
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2007 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: February 29, 2008
/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 PUBLIC SERVICE COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.6
I, Warner L. Baxter, certify that:
1.
Company;
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2007 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: February 29, 2008
/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, R. Alan Kelley, certify that:
1.
Company;
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2007 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: February 29, 2008
/s/ R. Alan Kelley
R. Alan Kelley
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, 2007 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: February 29, 2008
/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, 2007 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: February 29, 2008
/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, 2007 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: February 29, 2008
/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, 2007 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: February 29, 2008
/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, 2007 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: February 29, 2008
/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, 2007 of Illinois Power Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were made,
not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over
financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
Date: February 29, 2008
/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, 2007 of Illinois Power Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were made,
not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over
financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
Date: February 29, 2008
/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, 2007 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)
(2)
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
The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of
operations of the Registrant.
Date: February 29, 2008
/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, 2007 of Union Electric Company (the
“Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”),
each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of
the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of
operations of the Registrant.
Date: February 29, 2008
Thomas R. Voss
/s/
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, 2007 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)
(2)
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
The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of
operations of the Registrant.
Date: February 29, 2008
/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, 2007 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)
(2)
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
The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of
operations of the Registrant.
Date: February 29, 2008
/s/ R. Alan Kelley
R. Alan Kelley
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, 2007 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)
(2)
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
The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of
operations of the Registrant.
Date: February 29, 2008
/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, 2007 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)
(2)
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
The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of
operations of the Registrant.
Date: February 29, 2008
/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, 2007 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)
(2)
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
The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of
operations of the Registrant.
Date: February 29, 2008
/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 74,774
on December 31, 2007. The following table presents the price
ranges and dividends paid per Ameren common share for
each quarter during 2007 and 2006.
aee 2007
Quarter Ended
High
Low Close
Dividends
Paid
March 31
June 30
September 30
December 31
aee 2006
$55.00 $48.56 $50.30
48.23
47.10
52.50
49.01
55.00
53.89
54.74
51.81
54.21
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
$52.75 $48.51 $49.82
47.96
49.80
52.79
51.30
50.50
53.77
55.24
52.19
53.73
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 22, 2008, at
The Saint Louis Art Museum, One Fine Arts Drive, Forest Park,
St. Louis, Missouri. The annual shareholder meetings of Central
Illinois Light Company, Central Illinois Public Service Company,
.
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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,
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, including the chief executive officer and chief financial
officer certifications required to be filed with the Securities and
Exchange Commission with the annual and quarterly reports.
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
Illinois Power Company and Union Electric Company will be
more through the Web site. This is a free service.
held at the same time.
drPluS
Any person of legal age or entity, whether or not an Ameren
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).
shareholder, is eligible to participate in DRPlus, Ameren’s dividend
Please write or call:
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
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
n place Ameren common stock certificates in safekeeping
Public Service Company, Illinois Power Company, and Union
and receive regular account statements.
Electric Company preferred stock is Ameren Services Company.
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
offiCe
Ameren Corporation
One Ameren Plaza
1901 Chouteau Avenue
Company, Central Illinois Public Service Company, Illinois Power
St. Louis, MO 63103
Company, and Union Electric Company preferred shareholders
314-621-3222
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P.O. Box 66149
St. Louis, Missouri
63166-6149
www.ameren.com