2012 Annual Report
Powering the Quality of Life
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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 60,768 on December
31, 2012. The following table provides the closing price ranges
and dividends declared per Ameren common share for each
quarter of 2012 and 2011.
AEE 2012
Quarter Ended
High
Low
Close
Dividends
Declared
March 31
June 30
September 30
December 31
AEE 2011
Quarter Ended
March 31
June 30
September 30
December 31
$33.68
34.04
35.30
$30.89
31.15
32.27
33.21
28.43
$32.58
40 ¢
33.54
32.67
30.72
40
40
40
High
Low
Close
$29.14
30.14
31.44
$26.46
27.78
25.55
34.11
27.98
$28.07
28.84
29.77
33.13
Dividends
Declared
38 1⁄2 ¢
38 1⁄2
38 1⁄2
40
Direct Deposit of Dividends
All registered Ameren common and Ameren Illinois Company
and Union Electric Company preferred shareholders can have
their cash dividends automatically deposited to their bank
accounts. This service gives shareholders immediate access
to their dividend on the dividend payment date and eliminates
the possibility of lost or stolen dividend checks.
Corporate Governance Documents
Ameren makes available, free of charge through its website
(ameren.com), the charters of the board of directors’ audit
and risk committee, human resources committee, nominating
and corporate governance committee, finance committee and
nuclear oversight and environmental committee. Also available
on Ameren’s website are its corporate governance guidelines,
policy regarding nominations of directors, policy regarding
communications to the board of directors, policy and
procedures with respect to related person transactions, code
of business conduct (referred to as the “Corporate Compliance
Policy”) and 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 website, 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 any chief executive
officer and chief financial officer certifications required to be
filed with the Securities and Exchange Commission therewith.
Annual Meeting
The annual meeting of Ameren Corporation shareholders will
convene at 9 a.m. (Central Time), Tuesday, April 23, 2013, at Powell
Symphony Hall, 718 North Grand Boulevard, St. Louis, MO, 63103.
The annual shareholder meetings of Ameren Illinois Company and
Union Electric Company will be held at the same time.
Online Stock Account Access
Ameren’s website (ameren.com) allows registered
shareholders to access their account information online.
Shareholders can securely change their reinvestment options,
view account summaries, receive DRPlus statements and more
through the website. This is a free service.
DRPlus
Any person of legal age or entity, whether or not an
Ameren shareholder, is eligible to participate in DRPlus,
Ameren’s dividend reinvestment and stock purchase plan.
Participants can:
(cid:129) make cash investments by check or automatic direct debit
from their bank accounts to purchase Ameren common stock,
up to a maximum of $120,000 annually,
(cid:129) reinvest their dividends in Ameren common stock
(the minimum dividend reinvestment requirement is 10%),
per share and
(cid:129) place Ameren common stock certificates in safekeeping and
receive regular account statements.
For more information about DRPlus, you may obtain a
prospectus from Ameren’s Investor Services representatives.
Investor Services
Ameren’s Investor Services representatives are available
to help you each business day from 8:00 a.m. to 4:00 p.m.
(Central Time). Please write or call:
Ameren Services Company, Investor Services
P.O. Box 66887
St. Louis, MO 63166-6887
314-554-3502
800-255-2237
invest@ameren.com
Transfer Agent, Registrar and Paying Agent
The Transfer Agent, Registrar and Paying Agent for
Ameren common stock and Ameren Illinois Company
and Union Electric Company preferred stock is Ameren
Services Company.
Office
Ameren Corporation
One Ameren Plaza
1901 Chouteau Avenue
St. Louis, MO 63103
314-621-3222
06
Strengthening
Energy
Security
10
Enhancing
Economic
Vitality
14
Building
Connections
that Count
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Ameren is focused on providing the energy our region needs—safely, reliably,
responsibly and profi tably. By building sustained value for our shareholders, we can
continue to power our customers’ quality of life … now and for generations to come.
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02 | 2012 Annual Report
My fellow shareholders,
Now is a time of great progress and promise in the
energy industry. In 2012, we took a number of defi nitive
actions to position our company for enduring success
and strong fi nancial performance.
We continue to increase and sharpen our focus on
growing our rate-regulated utilities. Refl ecting that
focus, in December we announced our intent to exit
the merchant generation business. The volatility of
earnings and cash fl ows of the merchant generation
business as well as the high degree of uncertainty
regarding future returns on incremental capital
invested in this business do not align with our current
strategy. This decision was the primary reason we
recognized a $6.42 per share noncash impairment
charge related to the merchant generation business
in 2012.
As a result, Ameren lost $4.01 per share for the year.
However, 2012 adjusted earnings were $2.42 per share
after excluding these impairment charges and a $0.01
loss from net unrealized mark-to-market activity. These
adjusted earnings refl ected positive results from our
rate-regulated utilities.
The announcement of our intent to exit the merchant
generation business and other actions discussed in this
letter refl ect our focus on allocating capital resources
to those opportunities that we believe offer the most
attractive risk-adjusted return potential and, specifi cally,
our focus on growing earnings from our regulated
operations through investment in jurisdictions with
constructive regulatory frameworks. We believe that
this is a time of great opportunity to invest in regulated
energy infrastructure, technology and programs that
will deliver superior value to our customers and to you,
our owners.
Essential Investments
In each of its rate-regulated utility businesses,
Ameren continues to pursue constructive regulatory
frameworks that enable much-needed investment
in critical energy infrastructure. In turn, these
investments promote reliable service for customers,
support jobs and economic growth across our region
and generate shareholder returns.
At Our Transmission Business … November marked a
major milestone for Ameren Transmission Company of
Illinois’ (ATXI) largest undertaking, the approximately
400-mile Illinois Rivers project, when the project was
submitted for Illinois Commerce Commission (ICC)
review. This fi ling was the culmination of our employees’
efforts throughout the summer, when they traveled
the state and conducted nearly 100 public meetings to
collect vital input from landowners, business leaders
and others to shape the preferred project route. The ICC
review is expected to be completed by August 2013.
Thomas R. Voss
Chairman, President and Chief Executive Offi cer
Ameren Corporation
Ameren’s Executive Leadership Team (from left): Mary P. Heger,
Mark C. Lindgren, Martin J. Lyons, Jr., Gregory L. Nelson.
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Management is hopeful for a positive outcome that
will allow the project to move forward—enhancing
the electrical grid in Illinois—and creating signifi cant
benefi ts for customers and the regional economy.
Also in November, the Spoon River and Mark Twain
projects received federal approval for incentive rate
treatment, similar to that previously received for the
Illinois Rivers Project, including enhanced cost-recovery
mechanisms that facilitate cost-effective fi nancing of
the projects. Overall, through the end of 2019, Ameren
expects to invest more than $2 billion in transmission
projects in Illinois and Missouri. These rate-regulated
investments are expected to be a major driver of
earnings growth.
At Ameren Illinois … This was the fi rst year of our
multimillion-dollar Modernization Action Plan. It
was enabled by a bipartisan majority of Illinois state
lawmakers in 2011 through the Energy Infrastructure
Modernization Act, and it provided for a decade
of investment in reliability, technology, jobs and
customer service.
In 2012, we began select delivery infrastructure projects
and opened a new smart grid development and training
facility. In December, the ICC approved Ameren Illinois’
advanced metering infrastructure initiative—a key
component of grid modernization. Although the ICC
issued disappointing orders in response to our 2012
Shareholder Letter | 03
electric formula rate fi lings, we see tremendous potential
in upgrading our distribution system for the 21st century.
So do Illinois General Assembly members—the House
and Senate overwhelmingly passed resolutions urging
the ICC to implement formula ratemaking as intended by
statute, and we are working to achieve that end through
corrective legislation and through the courts.
Ameren Illinois is focused on obtaining the constructive
ratemaking needed to facilitate investments that will
reduce outages and create jobs for the state.
At Ameren Missouri … The Missouri Public Service
Commission (MoPSC) in December approved a
$260 million increase in electric rates for Ameren
Missouri. The order preserved important cost-tracking
mechanisms for pension and vegetation management
and infrastructure inspection costs. It also reaffi rmed
the fuel adjustment clause, which allows for continued
rate adjustments between rate cases for changes in fuel
and related costs. In addition, the MoPSC added a new
mechanism for recovery of major storm-related costs.
Furthermore, the MoPSC approved meaningful
enhancements to the regulatory framework for energy
effi ciency. Over the next three years, Ameren Missouri
will invest nearly $150 million in customer energy
effi ciency programs. Residents and businesses can take
advantage of the largest energy-savings portfolio in state
history, which is expected to result in approximately
Ameren’s Executive Leadership Team, cont. (from left): Michael L. Moehn, Charles D. Naslund, Adam C. Hefl in, Richard J. Mark, Warner L. Baxter,
Thomas R. Voss, Maureen A. Borkowski, Daniel F. Cole and Steven R. Sullivan.
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04 | 2012 Annual Report
$500 million in total customer benefi ts over the next
20 years. Regulatory framework enhancements allow
us to recover, on a timely basis, all program costs as
well as revenues to offset sales losses resulting from
these effi ciency programs. They also provide us the
opportunity to earn incentives based on our energy
effi ciency performance over the three-year period.
This is truly a win-win for customers and investors.
Outstanding Performance
I’d like to acknowledge Ameren’s employees, without
whom the year’s successes would not have been
possible. We work diligently to promote our culture
so that every co-worker understands our vision,
“Leading the way to a secure energy future.”
Focus on Safety: Ensuring personal and co-worker
safety is our “bluest of blue chip priorities.” We have
formed a Safety Strategy Team to oversee consistent
implementation of improvements across the enterprise.
In 2012, we saw the lowest rate of lost workday away
incidents in company history; the rate was also among
the best in our industry.
Effi cient Operations: Each day, employees exhibit
their industry-leading approach to operations and
maintenance. Highlights include …
(cid:129) The Metropolitan St. Louis Chapter of the Project
Management Institute conferred on Ameren
Missouri its “Project of the Year” award for effective
management in building the Maryland Heights
Renewable Energy Center. The facility, which began
operating during the summer, was completed
17 percent under budget and 108 days ahead of
schedule. It uses methane gas—naturally created
through the decomposition of organic landfi ll waste—
to power state-of-the-art turbines to produce enough
renewable energy to power 10,000 homes.
(cid:129) In September, the Electric Utility Cost Group
recognized two of Ameren Missouri’s largest coal-
fi red energy centers—the Labadie and Rush Island
energy centers—as “Best Performers” for 2011. This
prestigious honor refl ects our employees’ dedication
to performance, cost effi ciency and reliability.
(cid:129) After an extensive review, the Institute of Nuclear
Power Operations awarded the Callaway Nuclear
Energy Center its highest rating of Excellence.
Callaway performed exceptionally well in 2012, running
continuously since its November 2011 refueling.
(cid:129) Despite extreme summer heat, distribution reliability
for 2012 was the best ever measured at Ameren
Illinois and Ameren Missouri. Excellent reliability
combined with affordable rates provided customers
with a great value proposition.
East Coast Restoration: Last fall, we all were reminded
how vital energy is for life when Hurricane Sandy struck,
Chad Edwards, underground system trainee (left), and Eric Johnson,
underground construction mechanic (right), discuss Ameren’s focus
on safety with Dennis Weisenborn, VP of Safety and Supply Services
for Ameren.
Dwayne Robinson, gas construction journeyman, Ameren Illinois, helps to
ensure the reliability of some of the 21,000 miles of Ameren’s natural gas
transmission and distribution mains in Illinois.
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knocking out power to more than 8 million people. About
67,000 North American utility workers responded to the
crisis including crews from Ameren Illinois and Ameren
Missouri. I am proud of our employees’ performance,
as they responded to this monumental emergency. In
January 2013, the Edison Electric Institute presented
our utilities with the industry’s Emergency Assistance
Award for their extraordinary efforts.
Strategic Priorities
In 2012, we saw the Ameren companies renewing
their credit facilities, at lower costs and for fi ve years,
compared to the prior three-year agreement. Further,
our shareholders, employees and industry peers
successfully defended your dividend—maintaining
parity between dividend and capital gains tax rates—
by contacting elected offi cials and playing our part in
discussions in Washington, D.C.
Looking at 2013 and beyond, our priorities are clear:
Shareholder Letter | 05
Ameren is an economic engine with over 9,000
employees and estimated average annual expenditures
of more than $2.5 billion. Based on independent
studies,* the Ameren companies generate an $8 billion-
plus impact on the economies of Illinois and Missouri—
supporting more than 47,000 direct and indirect jobs.
On a personal note, I’m gratifi ed to have served as
Chairman of the St. Louis Regional Chamber, and I look
forward to the Chamber’s continued success under the
leadership of President and CEO Joe Reagan. Ameren
is an active member of this organization. Our efforts to
attract strong commercial and industrial customers to
our service territory are part of our strategy to keep our
business strong.
Thank you for your trust. I invite you to learn more by
reviewing this report and attending our Annual Meeting
at 9 a.m., Tuesday, April 23, 2013, at Powell Symphony
Hall in St. Louis.
(cid:129) Improve total shareholder returns.
Sincerely,
(cid:129) Pursue growth in our transmission business.
(cid:129) Support constructive regulatory policies that allow
a reasonable opportunity to earn a fair return on
investments.
Safe, reliable and affordable energy is essential.
This is why we do what we do. As a shareholder, you
help Ameren to power the quality of life.
Thomas R. Voss
Chairman, President and Chief Executive Offi cer
Ameren Corporation
Ameren linemen maintain more than 86,000 electric circuit miles. By investing in infrastructure,
we support jobs and economic growth.
* Independent studies of individual service area states by Development Strategies. (Did not include ATXI.)
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06 | 2012 Annual Report
Strengthening
Energy Security
Emergency medical providers at Barnes-Jewish Hospital (pictured) can rely on a new substation for the energy needed to power through disasters.
Known as Central Substation, the St. Louis facility is the fi rst Ameren Missouri substation to incorporate the latest industry seismic design standards.
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Energy Security | 07
We constantly seek innovative ways
to bolster the reliability of our electric
and natural gas service … because
businesses count on us for energy
to grow, and people count on us for
energy to live and work.
A Smarter Substation Built to Last
Emergency medical providers in St. Louis have a new
substation built to power through an earthquake. In
2012, Ameren Missouri employed the latest in seismic
research and design standards to build a bulk substation
serving area Level 1 Trauma Centers. The new $42 million
facility, known as Central Substation, takes up an entire
city block and replaces its 50-year-old predecessor.
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08 | 2012 Annual Report
Besides being the fi rst area substation built to the latest
improves our 7,500-plus circuit miles of high-voltage
industry seismic standards, it incorporates all of the
transmission lines across Illinois and Missouri.
latest smart grid technology, too—enhancing day-to-day
reliability for customers. Dispatchers and engineers can
monitor real-time data and remotely operate equipment
to prevent outages or drastically decrease their duration.
Building Up the Backbone of Our Grid
Transmission lines form the spine of our region’s power
grid—they carry electricity from the generation source
to local distribution systems. Ameren continually
In addition to other planned upgrades, through the end
of the decade we’ll strengthen this robust network with
a trio of federally regulated projects: Illinois Rivers,
Spoon River and Mark Twain. These multi-value projects
will create job opportunities, lower costs for consumers
by reducing transmission congestion and increase
access to renewable energy. Together, they represent
an estimated investment in reliability of more than
$1.3 billion.
In November, our Spoon River and Mark Twain transmission projects received federal
approval for incentive rate treatment—including enhanced cost-recovery mechanisms and
protections that facilitate cost-effective fi nancing—similar to that received previously
for the Illinois Rivers project. Through the end of 2019, Ameren will invest more than
$2 billion in these and other transmission projects in Illinois and Missouri.
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Energy Security | 09
Helping Amid a Hurricane
As Hurricane Sandy approached the East Coast,
Ameren heeded a mutual aid call for assistance from a
New Jersey utility. More than 650 Ameren employees
seen, and they were unfailingly polite throughout.
… You should be very, very proud of the work they did,”
wrote David Crane, CEO of Princeton, N.J.-based
NRG Energy.
and contractors from Illinois and Missouri traveled to
This storm reminded us how the forces of Mother Nature
storm-damaged areas and worked side by side with
can change lives in a moment. It’s why Ameren maintains
local crews to restore residents’ power.
“Ameren crews not only were highly competent, they
worked relentlessly to fi x situations as bad as I had ever
mutual aid agreements with other utilities, to speed
recovery and restoration efforts should a major disaster
strike in our service territory.
650+ Ameren employees and
contractors deployed to Hurricane
Sandy restoration efforts.
“ I was fortunate during Hurricane
Sandy, but a lot of my neighbors had
downed trees and power lines. Crews
from Ameren were working with the
downed lines very close to my home.
… They were professional, friendly
and compassionate to the needs of our
neighborhood. … If more people could
be like Ameren workers, we would have
a much better world.”
—Marta K., Resident, Hamilton, N.J.
Ameren sent more than 250 bucket trucks and material trucks from our Ameren Illinois and Ameren Missouri subsidiaries to
support Hurricane Sandy restoration efforts.
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10 | 2012 Annual Report
Enhancing
Economic Vitality
Members of Ameren’s economic development team and local offi cials tour NTN-Bower in Macomb, Ill. (inset). Our team helps companies
grow by offering valuable services such as site selection, workforce analysis and economic data. The team helped NTN-Bower—one of
North America’s largest manufacturers of precision roller bearings—in planning a major factory expansion.
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Economic Vitality | 11
As a Fortune 500 energy provider,
Ameren works with local leaders and
communities in our service territory
to attract and retain job-generating
businesses. We help Illinois and
Missouri build the capacity to compete
for industry … so our region and
company can thrive.
Resources to Grow
Ameren has a workforce that’s more than 9,000 strong,
including our dedicated economic development team that
helps other employers grow. For instance, in Macomb, Ill.,
we worked closely with roller bearings manufacturer
NTN-Bower in planning a $100 million factory expansion.
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12 | 2012 Annual Report
NTN-Bower broke ground on the addition last summer
Our company was a 2011 recipient of the Secretary of
and aims to add dozens of jobs. For efforts such as this,
Defense Employer Support Freedom Award, the highest
in 2012 Ameren once again was named a “Top Utility in
honor given by the U.S. government for support of
Economic Development” by Site Selection magazine.
employees serving in the National Guard and Reserves.
Our team brings decades of experience in economic
In continuing our commitment to veterans, we pledged
development, engineering, operations, urban/rural
in September 2012 to hire 200 more veterans and
planning and site development.
spouses over the next fi ve years as part of the White
Joining Forces to Hire Veterans
House’s “Joining Forces” initiative. Also in 2012,
G.I. Jobs magazine ranked Ameren 31st among the Top
Ameren is proud to employ military veterans, who
100 Military Friendly Employers in the nation; it’s the
bring invaluable skills and leadership to their jobs.
fourth year Ameren has made this distinguished list.
“ When I was deployed, Ameren paid
the difference between my civilian
and military salaries. Combine that
with great benefi ts, a 401(k) and
education reimbursement, I would
encourage veterans to consider a
career with Ameren. They’re very
military friendly.”
—U.S. Army Reserve Sgt. Kevin
Ford II, Ameren Missouri gas
pipefi tter and laborer
600+ Number of military
veterans who work
at Ameren.
Kevin Ford II, Ameren Missouri gas pipefi tter and laborer, was featured in the December 2012 issue of G.I. Jobs magazine. Ford is a sergeant in the
U.S. Army Reserves, where he repairs and maintains medical equipment. Ford is one of more than 600 military veterans employed by Ameren.
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Economic Vitality | 13
Ideas Into Opportunities
Rising to the Challenge
In December, the Ameren Corporation Charitable
As a business leader, Ameren is promoting a broader
Trust made a large contribution to BioSTL—a new
culture of sustainability by focusing on practices we
collaborative to advance entrepreneurship in the
can implement across our service territory. One example
biosciences. The donation will seed start-up
is the company’s single-stream recycling program.
enterprises so that innovative ideas can become
Employees recycle 6,500 trash cans of material on a
economic opportunities. Our goal is to attract talented
monthly basis, which translates to more than 120 tons of
people to quality jobs in high-growth industries right
trash diverted from a landfi ll.
here in our region.
A Decade of Economic
Development Success
Stories
For this and other sustainable practices, Ameren
received the “Star Circle of Excellence,” the highest
honor from the St. Louis Regional Chamber’s 2012
Green Business Challenge.
“Ameren has always been
a good corporate citizen
in all kinds of aspects—
particularly in our
economic development,
in terms of trying to help
us either retain or attract
new businesses.”
—Phyllis Young, 7th Ward
Alderwoman, St. Louis, Mo.
Ameren’s economic development efforts make an impact in communities throughout Illinois and Missouri. Since 2002, Ameren’s
dedicated economic development team has assisted 185 businesses to expand their current location or to settle into our service
territory. (Locations depicted on the map.)
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14 | 2012 Annual Report
Building Connections
that Count
Tina Hale, community relations coordinator, Ameren Illinois (center), and Richard J. Mark, president and CEO, Ameren Illinois (right), discuss
energy effi ciency tips with customers at the St. Louis Home Show. Customers can fi nd a variety of energy-saving tools and resources at
ActOnEnergy.com. It’s just one way that Ameren serves as an energy advisor for business and residential customers.
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Building Connections | 15
Whether providing our customers with
options and information, supporting
worthwhile causes or celebrating
diversity … Ameren strives to be more
than an energy company. We can be a
resource for life.
More Ways to Save
Our customers tell us that convenience, control and
cost matter, so our award-winning ActOnEnergy®
programs make it easy for people to take control of their
energy use. Each year, Ameren Illinois offers about
$75 million worth of energy-saving tools and incentives
for residential, commercial and industrial customers.
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16 | 2012 Annual Report
Starting in 2013, Ameren Missouri is debuting a
small. Their vast and varied volunteer efforts help many
three-year, nearly $150 million suite of similar
organizations throughout the region. To celebrate our
programs—the most ambitious energy-savings
commitment to service, in 2012 Ameren once again set
portfolio in state history. With constructive regulatory
aside special Community Connections Days, held
frameworks in place, our company is able to partner
Sept. 8 and 22. Co-workers and family members
with customers to use energy more effi ciently.
contributed more than 800 hours at 17 United Way-
Special Days of Service
Our 9,000-plus employees live and volunteer right
alongside our customers in communities large and
supported agency projects across Illinois and Missouri.
“ Leukemia causes more deaths than
any other cancer among children.
At our Light the Night event,
Ameren led the charge to give hope
for a cure. Their employees truly
embraced our mission of curing blood
cancer and supporting patients and
their families. CEO Tom Voss set in
motion a process to raise $840,000 for
the event—the highest amount raised
in the history of the Chapter.”
—Debbie Kersting, Executive Director,
The Leukemia & Lymphoma Society–
Gateway Chapter
100,000+
Amount of volunteer hours
recorded by Ameren co-workers
at charitable, civic and cultural
organizations each year.
In the fall, nearly 200 Ameren co-workers and their families and friends participated in the 2012 Light the Night Walk. The event was organized
by the Leukemia & Lymphoma Society-Gateway Chapter in St. Louis and chaired by Ameren Chairman, President and CEO Thomas R. Voss.
In total, Ameren and our employees contributed $48,000 toward lifesaving blood cancer research and patient support programs.
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Building Connections | 17
Dedicated to Diversity
By focusing on diversity—both in our workforce and
in selecting qualifi ed suppliers—all perspectives can
be shared and the best solutions can be put into action.
In 2012, our commitment to workplace diversity was
recognized for a third year by DiversityInc, which named
Ameren among its Top 5 utilities. Also, the Association of
Diversity Councils ranked Ameren’s council among the
Top 25 in the nation. This honor recognizes our council’s
efforts and its leadership in diversity and inclusion.
1,616,000,000 kWh
Net electricity Illinois and Missouri
customers have saved through Ameren’s
effi ciency programs (since mid-2008).
That’s like taking nearly 125,000 homes
off the grid for a whole year.
Dwayne Foley, troubleman, Ameren Missouri, helped
spark an interest in power line safety. It was part of
an electric safety day for 150 students at Holy Cross
Academy on the campus of Annunciation Catholic
School in Webster Groves, Mo.
Jeff Moore, managing supervisor, project management, Ameren Missouri; and
Gussie Reed, director, Division V, Ameren Illinois, helped build animal shelters
at the TreeHouse Wildlife Center near Dow, Ill., as part of Ameren Community
Connections Days.
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18 | 2012 Annual Report
Financial Highlights
Ameren Consolidated
Years Ended December 31
(In millions, except per share amounts and as noted)
2012
2011
2010
Results of Operations
Operating revenues
Operating expenses
Operating income (loss)
Net income (loss) attributable to Ameren Corporation
Common Stock Data
Earnings (loss) per basic and diluted share
Dividends per common share
Dividend yield (year-end)
Market price per common share (year-end closing)
Shares outstanding (weighted average)
Total market value of common shares (year-end)
Book value per common share
Balance Sheet Data
Property and plant, net
Total assets
Long-term debt obligations, excluding current maturities
Capitalization ratios
Common equity
Preferred stock
Debt, net of cash
Operating Data
Total electric sales (kilowatt-hours)
Native natural gas sales (decatherms in thousands)
Total generation output (kilowatt-hours)
Electric customers
Natural gas customers
$6,828
$8,068
$7,531
$6,290
($1,240)
$1,241
($974)
$519
($4.01)
$1.600
5.2%
$30.72
242.6
$7,453
$27.27
$16,096
$21,835
$6,626
48.9%
1.0%
50.1%
99,971
83,506
70,416
2.4
0.9
$2.15
$1.555
4.7%
$33.13
241.5
$8,037
$32.64
$18,127
$23,645
$6,677
53.4%
1.0%
45.6%
111,299
92,829
77,917
2.4
0.9
$7,638
$6,722
$916
$139
$0.58
$1.540
5.5%
$28.19
238.8
$6,777
$32.15
$17,853
$23,511
$6,853
51.3%
0.9%
47.8%
111,887
103,012
77,698
2.4
0.9
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2012 Annual Report | 19
Ameren Service Territory
Electrical Generating Capacity
(Expected for 2013 summer peak)
5,500
megawatts of merchant
generating capacity
3,300,000
electric and natural gas customers
2,400,000
electric customers
900,000
natural gas customers
10,300
megawatts of
Ameren Missouri
generating capacity
Company Headquarters
Subsidiary Headquarters
Electric Service Territory
Electric and Natural Gas
Service Territory
St. Louis
Collinsville
Ameren companies serve approximately 2.4 million
rate-regulated electric and natural gas transmission and
electric customers and more than 900,000 natural
distribution businesses. Ameren Missouri is the largest
gas customers over 64,000 square miles in Illinois
electric utility in the state, while Ameren Illinois ranks
and Missouri. Our service territory includes a diverse
as the second-largest electric distributor and one of
base of residential, commercial and large industrial
the largest natural gas distributors in Illinois. Ameren’s
customers in both urban and rural areas. In Missouri,
merchant generation business includes several coal-
we operate as a traditional, rate-regulated electric and
fi red energy centers and multiple natural gas-fi red
natural gas utility with approximately 10,300 megawatts
units with a capacity of approximately 5,500 megawatts
of generating capacity. Our Illinois operations include
of generation.
42725.indd 19
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20 | 2012 Annual Report
Ameren Corporation and Subsidiaries Offi cers and Directors
Executive Leadership Team
Thomas R. Voss
Chairman, President and
Chief Executive Officer,
Ameren Corporation
Warner L. Baxter*
Chairman, President and
Chief Executive Officer,
Ameren Missouri
Maureen A. Borkowski*
Chairman, President and
Chief Executive Officer,
Ameren Transmission Company
of Illinois
Daniel F. Cole*
Chairman, President and
Chief Executive Officer,
Ameren Services
Richard J. Mark*
Chairman, President and
Chief Executive Officer,
Ameren Illinois
Steven R. Sullivan*
Chairman, President and
Chief Executive Officer,
Ameren Energy Resources
Adam C. Heflin*
Senior Vice President and
Chief Nuclear Officer,
Ameren Missouri
Mary P. Heger*
Vice President, Information Technology
Ameren Services Center and
Chief Information Officer,
Ameren Services
Mark C. Lindgren*
Vice President and
Chief Human Resources Officer,
Ameren Services
Martin J. Lyons, Jr.
Executive Vice President and
Chief Financial Officer,
Ameren Corporation
Michael L. Moehn*
Senior Vice President,
Customer Operations,
Ameren Missouri
Charles D. Naslund*
Executive Vice President,
Ameren Services
Gregory L. Nelson
Senior Vice President,
General Counsel and Secretary,
Ameren Corporation
Other Officers
Lynn M. Barnes*
Vice President, Business Planning
and Controller, Ameren Missouri
Scott A. Glaeser*
Vice President, Gas Transmission and
Supply, Ameren Services
Mark C. Birk*
Senior Vice President, Corporate
Planning and Business Risk
Management, Ameren Services
S. Mark Brawley*
Vice President, Internal Audit,
Ameren Services
Kendall D. Coyne*
Vice President, Tax, Ameren Services
Sharon Harvey Davis*
Vice President and Chief Diversity
Officer, Ameren Services
David R. Hunt*
Vice President, Corporate
Communications, Ameren Services
Christopher A. Iselin*
Senior Vice President, Generation,
Ameren Energy Resources
Kevin A. DeGraw*
Vice President, Power Operations,
Ameren Missouri
Stephen M. Kidwell*
Vice President, Corporate Planning,
Ameren Services
Fadi M. Diya*
Vice President, Nuclear Operations,
Ameren Missouri
Michael L. Menne*
Vice President, Environmental Services,
Ameren Services
Mark J. Eacret*
Vice President, Business Services and
Controller, Ameren Energy Resources
Michael G. Mueller*
Vice President, Energy Trading and
Fuels Commodities, Ameren Missouri
Craig D. Nelson*
Senior Vice President,
Regulatory Affairs and Financial
Services, Ameren Illinois
Stan E. Ogden*
Vice President, Customer Service and
Metering Operations, Ameren Illinois
Ronald D. Pate*
Vice President, Operations and
Technical Services, Ameren Illinois
Joseph M. Power*
Vice President, Federal Legislative and
Regulatory Affairs, Ameren Services
Cleveland O. Reasoner*
Vice President, Engineering, Callaway
Nuclear Plant, Ameren Missouri
David J. Schepers*
Vice President, Energy Delivery
Technical Services, Ameren Missouri
Shawn E. Schukar*
Senior Vice President, Trading and
Marketing, Ameren Energy Marketing
James A. Sobule*
Vice President and Deputy General
Counsel, Ameren Services
Bruce A. Steinke
Senior Vice President, Finance and Chief
Accounting Officer, Ameren Corporation
David N. Wakeman*
Vice President, Energy Delivery-
Distribution Services, Ameren Missouri
Dennis W. Weisenborn*
Vice President, Safety and Supply
Services, Ameren Services
D. Scott Wiseman*
Vice President, External Affairs,
Ameren Illinois
Warren T. Wood*
Vice President, Regulatory and
Legislative Affairs, Ameren Missouri
Board of Directors
Stephen F. Brauer 2, 4
Chairman and Chief Executive Officer,
Hunter Engineering Company
Dr. Gayle P. W. Jackson 4, 5
President and Chief Executive Officer,
Energy Global, Inc.
Catherine S. Brune 2, 5
President, East Territory,
Allstate Insurance Company
James C. Johnson 3, 4
General Counsel,
Loop Capital Markets, LLC
Ellen M. Fitzsimmons 2, 4
Executive Vice President of Law and
Public Affairs, General Counsel and
Corporate Secretary, CSX Corporation
Walter J. Galvin 1, 2
Retired Vice Chairman,
Emerson Electric Co.
Steven H. Lipstein 1, 3
President and Chief Executive Officer,
BJC HealthCare
Patrick T. Stokes 1, 3, 6
Former Chairman,
Anheuser-Busch Companies, Inc.
* Officer of an Ameren Corporation subsidiary only.
Thomas R. Voss
Chairman, President and
Chief Executive Officer,
Ameren Corporation
Stephen R. Wilson 1, 5
Chairman, President and
Chief Executive Officer,
CF Industries Holdings, Inc.
Jack D. Woodard 3, 5
Retired Executive Vice President
and Chief Nuclear Officer, Southern
Nuclear Operating Company, Inc.
1 Member of the Finance Committee
2 Member of the Audit and Risk
Committee
3 Member of the Human Resources
Committee
4 Member of the Nominating and
Corporate Governance Committee
5 Member of the Nuclear Oversight and
Environmental Committee
6
Lead Director
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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, 2012.
OR
( ) Transition report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934 for the
transition period from
to
.
Commission
File Number
1-14756
1-2967
1-3672
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
Ameren Illinois Company
(Illinois Corporation)
6 Executive Drive
Collinsville, Illinois 62234
(618) 343-8039
IRS Employer
Identification No.
43-1723446
43-0559760
37-0211380
Securities Registered Pursuant to Section 12(b) of the Act:
The following security 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
Securities Registered Pursuant to Section 12(g) of the Act:
Registrant
Union Electric Company
Ameren Illinois Company
Title of each class
Common Stock, $0.01 par value per share
Title of each class
Preferred Stock, cumulative, no par value, stated value
$100 per share
Preferred Stock, cumulative, $100 par value per share
Depository Shares, each representing one-fourth of a share
of 6.625% Preferred Stock, cumulative, $100 par value per
share
Indicate by checkmark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Ameren Corporation
Union Electric Company
Ameren Illinois Company
Yes
Yes
Yes
(X)
( )
( )
No
No
No
( )
(X)
(X)
Indicate by checkmark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Ameren Corporation
Union Electric Company
Ameren Illinois Company
Yes
Yes
Yes
( )
( )
( )
No
No
No
(X)
(X)
(X)
Indicate by checkmark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Ameren Corporation
Union Electric Company
Ameren Illinois Company
Yes
Yes
Yes
(X)
(X)
(X)
No
No
No
( )
( )
( )
Indicate by checkmark whether each registrant has submitted electronically and posted on its corporate website, if any,
every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files).
Ameren Corporation
Union Electric Company
Ameren Illinois Company
Yes
Yes
Yes
(X)
(X)
(X)
No
No
No
( )
( )
( )
Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this
chapter) 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
Ameren Illinois Company
(X)
(X)
(X)
Indicate by checkmark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a
smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in
Rule 12b-2 of the Exchange Act.
Ameren Corporation
Union Electric Company
Ameren Illinois Company
Large
Accelerated
Filer
(X)
( )
( )
Accelerated
Filer
( )
( )
( )
Non-accelerated
Filer
( )
(X)
(X)
Smaller
Reporting
Company
( )
( )
( )
Indicate by checkmark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
Ameren Corporation
Union Electric Company
Ameren Illinois Company
Yes
Yes
Yes
( )
( )
( )
No
No
No
(X)
(X)
(X)
As of June 29, 2012, Ameren Corporation had 242,634,671 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 the common stock on the New York
Stock Exchange on June 29, 2012) held by nonaffiliates was $8,137,966,865. The shares of common stock of the other
registrants were held by Ameren Corporation as of June 29, 2012.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2013, was as follows:
Ameren Corporation
Union Electric Company
Ameren Illinois Company
Common stock, $ 0.01 par value per share: 242,634,671
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
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of
Union Electric Company and Ameren Illinois Company for the 2013 annual meetings of shareholders are incorporated by
reference into Part III of this Form 10-K.
This combined Form 10-K is separately filed by Ameren Corporation, Union Electric Company, and Ameren Illinois
Company. Each registrant hereto is filing on its own behalf all of the information contained in this annual report that relates to
such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes
no representation as to any such information.
TABLE OF CONTENTS
GLOSSARY OF TERMS AND ABBREVIATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forward-looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rates and Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission and Supply of Electric Power
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas Supply for Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industry Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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.
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Quarterly Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 15.
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXHIBIT INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
1
4
5
5
6
6
10
12
14
15
15
17
18
26
26
28
28
28
31
33
33
33
35
54
67
73
73
76
77
82
169
170
170
171
171
172
172
172
173
173
177
180
This report contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included
on pages 4 and 5 of this report under the heading “Forward-looking Statements.” Forward-looking statements are all
statements other than statements of historical fact, including those statements that are identified by the use of the words
“anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.
We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined
below. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.
GLOSSARY OF TERMS AND ABBREVIATIONS
2007 Illinois Electric Settlement Agreement – A
comprehensive settlement of issues in Illinois arising out of
the end of ten years of frozen electric rates. The settlement,
which became effective in 2007, was designed to avoid rate
rollback and freeze legislation and legislation that would
have imposed a tax on electric generation in Illinois. The
settlement addressed the issue of power procurement.
2010 Credit Agreements – The 2010 Genco Credit
Agreement, the 2010 Illinois Credit Agreement, and the
2010 Missouri Credit Agreement, collectively, which
terminated on November 14, 2012.
2010 Genco Credit Agreement – Ameren’s and Genco’s
$500 million multiyear senior unsecured credit agreement,
which was terminated on November 14, 2012.
2010 Illinois Credit Agreement – Ameren’s and Ameren
Illinois’ $800 million multiyear senior unsecured credit
agreement, which was terminated on November 14, 2012.
2010 Missouri Credit Agreement – Ameren’s and Ameren
Missouri’s $800 million multiyear senior unsecured credit
agreement, which was terminated on November 14, 2012.
2012 Credit Agreements – The 2012 Illinois Credit
Agreement and the 2012 Missouri Credit Agreement,
collectively.
2012 Illinois Credit Agreement – Ameren’s and Ameren
Illinois’ $1.1 billion multiyear senior unsecured credit
agreement, which expires on November 14, 2017.
2012 Missouri Credit Agreement – Ameren’s and Ameren
Missouri’s $1 billion multiyear senior unsecured credit
agreement, which expires on November 14, 2017.
AER – AmerenEnergy Resources Company, LLC, an Ameren
Corporation subsidiary that consists of non-rate-regulated
operations, including Genco, AERG, Marketing Company
and Medina Valley. The Medina Valley energy center was
sold in February 2012. On October 1, 2010, AERG stock
was distributed to Ameren, which then contributed it to
AER, thereby making AERG a subsidiary of AER.
AERG – Ameren Energy Resources Generating Company, a
CILCO subsidiary until October 1, 2010, that operates a
merchant electric generation business in Illinois. On
October 1, 2010, AERG stock was distributed to Ameren
and subsequently contributed by Ameren to AER, which
resulted in AERG becoming a subsidiary of AER.
AFS – Ameren Energy Fuels and Services Company, an AER
subsidiary that procured fuel and natural gas and managed
the related risks for the Ameren Companies prior to
January 1, 2011. Effective January 1, 2011, the functions
previously performed by AFS were assumed by the Ameren
Missouri, Ameren Illinois and Merchant Generation
business segments.
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 – Ameren Corporation, Ameren
Missouri, and Ameren Illinois, collectively, which are
individual registrants within the Ameren consolidated
group.
Ameren Illinois or AIC – Ameren Illinois Company, an
Ameren Corporation subsidiary that operates a rate-
regulated electric and natural gas transmission and
distribution business in Illinois, doing business as Ameren
Illinois. This business consists of the combined rate-
regulated electric and natural gas transmission and
distribution businesses operated by CIPS, CILCO and IP
before the Ameren Illinois Merger. References to Ameren
Illinois prior to the Ameren Illinois Merger refer collectively
to the rate-regulated electric and natural gas transmission
and distribution businesses of CIPS, CILCO and IP.
Immediately after the Ameren Illinois Merger, Ameren
Illinois distributed the common stock of AERG to Ameren
Corporation. AERG’s operating results and cash flows prior
to October 1, 2010, were presented as discontinued
operations in Ameren Illinois’ financial statements. Ameren
Illinois is also defined as a financial reporting segment
beginning after 2010.
Ameren Illinois Merger – On October 1, 2010, CILCO and
IP merged with and into CIPS, with the surviving
corporation renamed Ameren Illinois Company.
Ameren Illinois Segment – A financial reporting segment
consisting of Ameren Illinois’ rate-regulated businesses.
Ameren Missouri or AMO – 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, doing business as
Ameren Missouri. Ameren Missouri is also defined as a
financial reporting segment.
Ameren Services – Ameren Services Company, an Ameren
Corporation subsidiary that provides support services to
Ameren and its subsidiaries.
AMIL – The MISO balancing authority area operated by
Ameren, which includes the load of Ameren Illinois and the
Merchant Generation energy centers (excluding EEI and
Elgin CT energy centers).
AMMO – The MISO balancing authority area operated by
Ameren, which includes the load and generation energy
centers of Ameren Missouri.
ARO – Asset retirement obligations.
ATXI – Ameren Transmission Company of Illinois, an
Ameren Corporation subsidiary that is engaged in the
construction and operation of electric transmission assets.
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.
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CAIR – Clean Air Interstate Rule.
Capacity factor – A percentage measure that indicates how
much of an energy center’s capacity was used during a
specific period.
CCR – Coal combustion residuals.
CILCO – Central Illinois Light Company, a former Ameren
Corporation subsidiary that operated a rate-regulated
electric transmission and distribution business, a merchant
electric generation business through AERG, and a rate-
regulated natural gas transmission and distribution
business, all in Illinois, before the Ameren Illinois Merger.
CILCO owned all of the common stock of AERG and
included AERG within its consolidated financial statements.
Immediately after the Ameren Illinois Merger in 2010,
Ameren Illinois distributed the common stock of AERG to
Ameren Corporation. AERG’s operating results and cash
flows prior to October 1, 2010, were presented as
discontinued operations in Ameren Illinois’ financial
statements.
CILCORP – CILCORP Inc., a former Ameren Corporation
subsidiary that operated as a holding company for CILCO
and its merchant generation subsidiary. On March 4, 2010,
CILCORP merged with and into Ameren.
CIPS – Central Illinois Public Service Company, an Ameren
Corporation subsidiary, renamed Ameren Illinois Company
at the effective date of the Ameren Illinois Merger, which
operates a rate-regulated electric and natural gas
transmission and distribution business, all in Illinois.
CO2 – Carbon dioxide.
COL – Nuclear energy center combined construction and
operating license.
Cole County Circuit Court – Circuit Court of Cole County,
Missouri.
Cooling degree-days – The summation of positive
differences between the mean daily temperature and a
65-degree Fahrenheit base. This statistic is useful as an
indicator of electricity demand by residential and
commercial customers for summer cooling.
CSAPR – Cross-State Air Pollution Rule.
CT – Combustion turbine electric energy center used
primarily for peaking capacity.
DOE – Department of Energy, a United States government
agency.
DRPlus – Ameren Corporation’s dividend reinvestment and
direct stock purchase plan.
Dekatherm – One million Btus of natural gas.
EEI – Electric Energy, Inc., an 80%-owned Genco subsidiary
that operates merchant electric generation energy centers
and FERC-regulated transmission facilities in Illinois. The
remaining 20% ownership interest is owned by Kentucky
Utilities Company, a nonaffiliated entity.
Entergy – Entergy Arkansas, Inc.
EPA – Environmental Protection Agency, a United States
government agency.
Equivalent availability factor – A measure that indicates
the percentage of time an energy center was available for
service during a period.
ERISA – Employee Retirement Income Security Act of 1974,
as amended.
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Exchange Act – Securities Exchange Act of 1934, as
amended.
FAC – A fuel and purchased power cost recovery
mechanism that allows Ameren Missouri to recover,
through customer rates, 95% of changes in fuel (coal, coal
transportation, natural gas for generation, and nuclear),
certain fuel additives, emission allowances, purchased
power costs, transmission costs and MISO costs and
revenues, net of off-system revenues, greater or less than
the amount set in base rates without a traditional rate
proceeding, subject to MoPSC prudency reviews. The
MoPSC’s December 2012 electric rate order changed the
FAC to include activated carbon, limestone and urea costs,
along with transmission revenues, starting in 2013.
FASB – Financial Accounting Standards Board, a
rulemaking organization that establishes financial
accounting and reporting standards in the United States.
FERC – Federal Energy Regulatory Commission, a
United States government agency.
Fitch – Fitch Ratings, a credit rating agency.
FTRs – Financial transmission rights, financial instruments
that entitle the holder to pay or receive compensation for
certain congestion-related transmission charges between
two designated points.
Fuelco – Fuelco LLC, a limited liability company that
provides nuclear fuel management and services to its
members. The members are Ameren Missouri, Luminant,
and Pacific Gas and Electric Company.
GAAP – Generally accepted accounting principles in the
United States of America.
Genco – Ameren Energy Generating Company, an AER
subsidiary that operates a merchant electric generation
business in Illinois and holds an 80% ownership interest in
EEI.
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 by residential and commercial customers.
IBEW – International Brotherhood of Electrical Workers, a
labor union.
ICC – Illinois Commerce Commission, a state agency that
regulates Illinois utility businesses, including Ameren
Illinois and ATXI.
IEIMA – Illinois Energy Infrastructure Modernization Act, an
Illinois law that established a performance-based formula
process for determining electric delivery service rates.
Ameren Illinois elected to participate in this regulatory
framework in 2012, which will require it to make
incremental capital expenditures to modernize its electric
distribution system over a ten-year period, to meet
performance standards, and to create jobs in Illinois,
among other things.
Illinois Customer Choice Law – Illinois Electric Service
Customer Choice and Rate Relief Law of 1997, which was
designed to introduce competition into the retail supply of
electric energy in Illinois.
IP – Illinois Power Company, a former Ameren Corporation
subsidiary that operated a rate-regulated electric and natural
gas transmission and distribution business, all in Illinois,
before the Ameren Illinois Merger.
IPA – Illinois Power Agency, a state government agency that
has broad authority to assist in the procurement of electric
power for residential and small commercial customers.
ISRS – Infrastructure system replacement surcharge, which
is a cost recovery mechanism that allows Ameren Missouri
to recover natural gas infrastructure replacement costs
from utility customers without a traditional rate proceeding.
IUOE – International Union of Operating Engineers, a labor
union.
Kilowatthour – A measure of electricity consumption
equivalent to the use of 1,000 watts of power over one
hour.
LIUNA – Laborers’ International Union of North America, a
labor union.
Marketing Company – Ameren Energy Marketing Company,
an AER subsidiary that markets power for Genco, AERG,
and EEI.
MATS – Mercury and Air Toxics Standards.
Medina Valley – Ameren Energy Medina Valley Cogen LLC,
an AER subsidiary, which owned a 40-megawatt natural
gas-fired electric energy center. This energy center was sold
in February 2012.
MEEIA – Missouri Energy Efficiency Investment Act, a
Missouri law that allows electric utilities to recover costs
related to MoPSC-approved energy efficiency programs.
Megawatthour or MWh – One thousand kilowatthours.
Merchant Generation – A financial reporting segment
consisting primarily of the operations of AER, including
Genco, AERG, Medina Valley and Marketing Company.
MGP – Manufactured gas plant.
MIEC – Missouri Industrial Energy Consumers.
MISO – Midwest Independent Transmission System
Operator, Inc., an RTO.
MISO Energy and Operating Reserves Market – A market
that uses market-based pricing, which takes into account
transmission congestion and line losses, to compensate
market participants for power and ancillary services.
Missouri Environmental Authority – Environmental
Improvement and Energy Resources Authority of the state of
Missouri, a governmental body authorized to finance
environmental projects by issuing tax-exempt bonds and notes.
Mmbtu – One million Btus.
Money pool – Borrowing agreements among Ameren and its
subsidiaries to coordinate and provide for certain short-term
cash and working capital requirements. Separate money
pools maintained for rate-regulated and non-rate-regulated
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.
MoOPC – Missouri Office of Public Counsel.
MoPSC – Missouri Public Service Commission, a state
agency that regulates Missouri utility businesses including
Ameren Missouri.
MPS – Multi-Pollutant Standard, a compliance alternative within
Illinois law covering reductions in emissions of SO2, NOx, and
mercury, which Genco, EEI, and AERG elected in 2006.
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MTM – Mark-to-market.
MW – Megawatt.
Native load – End-use retail customers whom we are
obligated to serve by statute, franchise, contract, or other
regulatory requirement.
NERC – North American Electric Reliability Corporation.
NO2 – Nitrogen dioxide.
NOx – Nitrogen oxide.
Noranda – Noranda Aluminum, Inc.
NPNS – Normal purchases and normal sales.
NRC – Nuclear Regulatory Commission, a United States
government agency.
NSPS – New Source Performance Standards, a provision
under the Clean Air Act.
NSR – New Source Review provisions of the Clean Air Act,
which include Nonattainment New Source Review and
Prevention of Significant Deterioration regulations.
NWPA – Nuclear Waste Policy Act of 1982, as amended.
NYMEX – New York Mercantile Exchange.
NYSE – New York Stock Exchange, Inc.
OATT – Open Access Transmission Tariff.
OCI – Other comprehensive income (loss) as defined by
GAAP.
Off-system revenues – Revenues from other than native
load sales, including wholesale sales beginning with the
effective date of the MoPSC’s 2011 electric rate order.
OTC – Over-the-counter.
PGA – Purchased Gas Adjustment tariffs, which permit
prudently incurred natural gas costs to be recovered directly
from utility customers without a traditional rate proceeding.
PJM – PJM Interconnection LLC.
PUHCA 2005 – The Public Utility Holding Company Act of
2005.
Regulatory lag – The effect of adjustments to retail electric
and natural gas rates being based on historic cost and
revenue levels. Rate increase requests can take up to
11 months to be acted upon by the MoPSC and the ICC. As
a result, revenue increases authorized by regulators will lag
behind changing costs and revenues when based on
historical periods.
Revenue requirement – The cost of providing utility service
to customers, which is calculated as the sum of a utility’s
recoverable operating and maintenance expenses,
depreciation and amortization expense, taxes and an
allowed return on investment.
RFP – Request for proposal.
RTO – Regional Transmission Organization.
S&P – Standard & Poor’s Ratings Services, a credit rating
agency.
SEC – Securities and Exchange Commission, a
United States 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.
SO2 – Sulfur dioxide.
Stoddard County Circuit Court – Circuit Court of Stoddard
County, Missouri.
UA – United Association of Plumbers and Pipefitters, a
labor union.
Westinghouse – Westinghouse Electric Company.
FORWARD-LOOKING STATEMENTS
Statements in this report not based on historical facts
are considered “forward-looking” and, accordingly, involve
risks and uncertainties that could cause actual results to
differ materially from those discussed. Although such
forward-looking statements have been made in good faith
and are based on reasonable assumptions, there is no
assurance that the expected results will be achieved. These
statements include (without limitation) statements as to
future expectations, beliefs, plans, strategies, objectives,
events, conditions, and financial performance. In
connection with the “safe harbor” provisions of the Private
Securities Litigation Reform Act of 1995, we are providing
this cautionary statement to identify important factors that
could cause actual results to differ materially from those
anticipated.
The following factors, in addition to those discussed
under Risk Factors and elsewhere in this report and in our
other filings with the SEC, could cause actual results to
differ materially from management expectations suggested
in such forward-looking statements:
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regulatory, judicial, or legislative actions, including
changes in regulatory policies and ratemaking
determinations, such as the outcome of Ameren
Illinois’ natural gas rate case filed in 2013; the court
appeals of Ameren Missouri’s and Ameren Illinois’
electric rate orders issued in 2012; Ameren Missouri’s
FAC prudence review and the related request for an
accounting authority order; Ameren Illinois’ request for
rehearing of a July 2012 FERC order regarding the
inclusion of acquisition premiums in Ameren Illinois
transmission rates; and future regulatory, judicial, or
legislative actions that seek to change regulatory
recovery mechanisms;
the effect of Ameren Illinois participating in a
performance-based formula ratemaking process under
the IEIMA, the related financial commitments required
by the IEIMA, and the resulting uncertain impact on the
financial condition, results of operations and liquidity of
Ameren Illinois;
Ameren’s eventual exit from the Merchant Generation
business could result in impairments of long-lived
assets, disposal-related losses, contingencies,
reduction of existing deferred tax assets, or could have
other adverse impacts on the financial condition,
results of operations and liquidity of Ameren;
the effects of, or changes to, the Illinois power
procurement process;
changes in laws and other governmental actions,
including monetary, fiscal, and tax 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 Ameren Missouri and Marketing Company;
the effects of increased competition in the future due
to, among other things, deregulation of certain aspects
of our business at both the state and federal levels, and
the implementation of deregulation;
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the effects on demand for our services resulting from
technological advances, including advances in energy
efficiency and distributed generation sources, which
generate electricity at the site of consumption;
increasing capital expenditure and operating expense
requirements and our ability to recover these costs;
the cost and availability of fuel such as coal, natural
gas, and enriched uranium used to produce electricity;
the cost and availability of purchased power and natural
gas for distribution; and the level and volatility of future
market prices for such commodities, including the
ability to recover the costs for such commodities;
the effectiveness of our risk management strategies
and the use of financial and derivative instruments;
the level and volatility of future prices for power in the
Midwest, which may have a significant effect on the
financial condition of Ameren’s Merchant Generation
segment;
the development of a multiyear capacity market within
MISO and the outcomes of MISO’s inaugural annual
capacity auction in 2013;
business and economic conditions, including their
impact on interest rates, bad debt expense, and
demand for our products;
disruptions of the capital markets, deterioration in
credit metrics of the Ameren Companies, or other
events that make the Ameren Companies’ access to
necessary capital, including short-term credit and
liquidity, impossible, more difficult, or more costly;
our assessment of our liquidity, including liquidity
concerns for Ameren’s Merchant Generation business,
and specifically for Genco, which has limited access to
third-party financing sources;
the impact of the adoption of new accounting guidance
and the application of appropriate technical accounting
rules and guidance;
actions of credit rating agencies and the effects of such
actions;
the impact of weather conditions and other natural
phenomena on us and our customers, including the
impacts of droughts, which may cause lower river levels
and could limit our energy centers’ ability to generate
power;
the impact of system outages;
generation, transmission, and distribution asset
construction, installation, performance, and cost
recovery;
the effects of our increasing investment in electric
transmission projects and uncertainty as to whether we
will achieve our expected returns in a timely fashion, if
at all;
the extent to which Ameren Missouri prevails in its
claims against insurers in connection with its Taum Sauk
pumped-storage hydroelectric energy center incident;
the extent to which Ameren Missouri is permitted by its
regulators to recover in rates the investments it made
in connection with additional nuclear generation at its
Callaway energy center;
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operation of Ameren Missouri’s Callaway energy center,
including planned and unplanned outages, and
decommissioning costs;
the effects of strategic initiatives, including mergers,
acquisitions and divestitures, and any related tax
implications;
the impact of current environmental regulations on
utilities and power generating companies and new,
more stringent or changing requirements, including
those related to greenhouse gases, other emissions,
cooling water intake structures, CCR, and energy
efficiency, that are enacted over time and that could
limit or terminate the operation of certain of our energy
centers, increase our costs, result in an impairment of
our assets, reduce our customers’ demand for
electricity or natural gas, or otherwise have a negative
financial effect;
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the impact of complying with renewable energy
portfolio requirements in Missouri;
labor disputes, workforce reductions, future wage and
employee benefits costs, including changes in discount
rates and returns on benefit plan assets;
the inability of our counterparties and affiliates to meet
their obligations with respect to contracts, credit
agreements, and financial instruments;
the cost and availability of transmission capacity for the
energy generated by Ameren’s and Ameren Missouri’s
energy centers or required to satisfy energy sales made
by Ameren or Ameren Missouri;
legal and administrative proceedings; and
acts of sabotage, war, terrorism, cybersecurity attacks
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 Ameren Missouri and CIPSCO Inc. Ameren
acquired CILCORP in 2003 and IP in 2004. Ameren’s
primary assets are its equity interests in its subsidiaries,
including Ameren Missouri, Ameren Illinois and AER.
Ameren’s subsidiaries are separate, independent legal
entities with separate businesses, assets, and liabilities.
These subsidiaries operate, as the case may be, rate-
regulated electric generation, transmission, and distribution
businesses, rate-regulated natural gas transmission and
distribution businesses, and merchant generation
businesses in Missouri and Illinois. Dividends on Ameren’s
common stock and the payment of other expenses by
Ameren depend on distributions made to it by its
subsidiaries. In December 2012, Ameren determined that it
intends to, and it is probable that it will, exit its Merchant
Generation business before the end of the previously
estimated useful lives of that business’s long-lived assets.
This determination resulted from Ameren’s analysis of the
current and projected future financial condition of its
Merchant Generation business segment, including the need
to fund Genco debt maturities beginning in 2018 and its
conclusion that this business segment is no longer a core
component of its future business strategy. In consideration
of this determination, Ameren has begun planning to
reduce, and ultimately eliminate, the Merchant Generation
segment’s reliance on Ameren’s financial support and
shared services support. Ameren intends to allocate its
capital resources to those business opportunities, including
electric and natural gas transmission, which offer the most
attractive risk-adjusted return potential.
Below is a summary description of Ameren Missouri,
Ameren Illinois and AER. A more detailed description can be
found in Note 1 – Summary of Significant Accounting
Policies under Part II, Item 8, of this report.
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Ameren Missouri operates a rate-regulated electric
generation, transmission and distribution business, and
a rate-regulated natural gas transmission and
distribution business in Missouri.
Ameren Illinois operates a rate-regulated electric and
natural gas transmission and distribution business in
Illinois.
AER consists of non-rate-regulated operations,
including Genco, AERG, Marketing Company, and,
through Genco, an 80% ownership interest in EEI,
which Ameren consolidates for financial reporting
purposes.
The following table presents our total employees at
December 31, 2012:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,097
3,997
2,994
713
1,393
(a) Total for Ameren includes Ameren registrant and nonregistrant
subsidiaries.
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As of January 1, 2013, the IBEW, the IUOE, the LIUNA,
and the UA labor unions collectively represented about 57%
of Ameren’s total employees. They represented 64% of the
employees at Ameren Missouri and 63% at Ameren Illinois.
The collective bargaining agreements have three- to five-
year terms, and expire between 2013 and 2016. Several
collective bargaining agreements between Ameren
subsidiaries and the IBEW, IUOE, the LIUNA and the UA
labor unions, covering approximately 2,900 employees
expire during 2013.
For additional information about the development of
our businesses, our business operations, and factors
affecting our operations and financial position, see
Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7,
of this report and Note 1 – Summary of Significant
Accounting Policies under Part II, Item 8, of this report.
BUSINESS SEGMENTS
Ameren has three reporting segments: Ameren
Missouri, Ameren Illinois, and Merchant Generation. See
Note 18 – Segment Information under Part II, Item 8, of this
report for additional information on reporting segments.
RATES AND REGULATION
Rates
The rates that Ameren Missouri and Ameren Illinois are
allowed to charge for their utility services significantly
influence the results of operations, financial position, and
liquidity of these companies and Ameren. The electric and
natural gas utility industry is highly regulated. The utility
rates charged to Ameren Missouri and Ameren Illinois
customers are determined, in large part, by governmental
entities, including the MoPSC, the ICC, and FERC. Decisions
by these entities are influenced by many factors, including
the cost of providing service, the prudency of expenditures,
the quality of service, regulatory staff knowledge and
experience, economic conditions, public policy, and social
and political views. Decisions made by these governmental
entities regarding rates are largely outside of Ameren
Missouri’s and Ameren Illinois’ control. These decisions, as
well as the regulatory lag involved in filing and getting new
rates approved, could have a material impact on the results
of operations, financial position, and liquidity of Ameren,
Ameren Missouri and Ameren Illinois. Rate orders are also
subject to appeal, which creates additional uncertainty as to
the rates Ameren Missouri and Ameren Illinois are
ultimately allowed to charge for their services. The effect of
regulatory lag on Ameren Illinois’ electric distribution
business is mitigated to some extent through the use of the
formula ratemaking regulatory framework established under
the IEIMA. Beginning in 2013, regulatory lag on Ameren
Illinois’ and ATXI’s electric transmission business will be
mitigated to some extent through the use of the FERC
revenue requirement reconciliation. To mitigate regulatory
lag on Ameren Illinois’ natural gas distribution business,
recent rate requests have been filed with the ICC using a
future test year.
The ICC regulates rates and other matters for Ameren
Illinois and ATXI. The MoPSC regulates rates and other
matters for Ameren Missouri. The FERC regulates Ameren
Missouri, Ameren Illinois, ATXI, Genco, EEI, and AERG 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 53% of Ameren’s electric and 15% of its natural
gas operating revenues were subject to regulation by the
MoPSC in the year ended December 31, 2012. About 29%
of Ameren’s electric and 85% of its natural gas operating
revenues were subject to regulation by the ICC in the year
ended December 31, 2012. Wholesale revenues for Ameren
Missouri, Ameren Illinois, Genco, Marketing Company and
AERG are subject to FERC regulation, but not subject to
direct MoPSC or ICC regulation.
Ameren Missouri
Electric
Almost 100% of Ameren Missouri’s electric operating
revenues were subject to regulation by the MoPSC in the
year ended December 31, 2012.
In December 2012, the MoPSC issued an order
approving an increase for Ameren Missouri in annual
revenues for electric service of $260 million, including
$84 million related to an anticipated increase in normalized
net fuel costs above the net fuel costs included in base rates
previously authorized by the MoPSC in its July 2011 electric
rate order. The annual increase also included $80 million for
recovery of the costs associated with energy efficiency
programs under the MEEIA. The remaining annual increase
of $96 million approved by the MoPSC was for energy
infrastructure investments and other non-fuel costs,
including $10 million for increased pension and other post-
employment benefit costs and $6 million for increased
amortization of regulatory assets. The revenue increase was
based on a 9.8% return on equity, a capital structure
composed of 52.3% common equity, and a rate base of
$6.8 billion. The new rates became effective on January 2,
2013.
If certain criteria are met, Ameren Missouri’s electric
rates may be adjusted without a traditional rate proceeding.
The FAC permits 95% of prudently incurred fuel, emission
allowances, purchased power costs, transmission costs and
MISO costs and revenues to be passed directly to
customers. The MoPSC’s December 2012 electric rate order
changed the FAC to include activated carbon, limestone and
urea costs, along with transmission revenues, starting in
2013.
FERC regulates the rates charged and the terms and
conditions for electric transmission services. Each RTO
separately files a regional transmission tariff for approval by
FERC. All transmission service within that RTO is then
subjected to that tariff. As a member of MISO, Ameren
Missouri’s transmission rate is calculated in accordance
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with the MISO OATT. The transmission rate is updated in
June of each year; it is based on Ameren Missouri’s filings
with FERC. This rate is not directly charged to Missouri
retail customers, because in Missouri the MoPSC includes
transmission-related costs and revenues in setting bundled
retail rates.
Natural Gas
All of Ameren Missouri’s natural gas operating
revenues were subject to regulation by the MoPSC in the
year ended December 31, 2012. In January 2011, the
MoPSC approved a stipulation and agreement that allowed
Ameren Missouri to increase annual natural gas revenues
by $9 million.
If certain criteria are met, Ameren Missouri’s natural
gas rates may be adjusted without a traditional rate
proceeding. PGA clauses permit prudently incurred natural
gas costs to be passed directly to customers. The ISRS also
permits prudently incurred natural gas infrastructure
replacement costs to be passed directly to customers. The
return on equity to be used by Ameren Missouri for
purposes of the ISRS tariff filing is 10%.
For additional information on Missouri rate matters,
including Ameren Missouri’s 2012 electric rate order and
the related court appeals, see Results of Operations and
Outlook in Management’s Discussion and Analysis of
Financial Condition and Results of Operations under Part II,
Item 7, Quantitative and Qualitative Disclosures About
Market Risk under Part II, Item 7A, and Note 2 – Rate and
Regulatory Matters, and Note 15 – Commitments and
Contingencies under Part II, Item 8, of this report.
Ameren Illinois
Electric
About 99% of Ameren Illinois’ electric operating
revenues were subject to regulation by the ICC in the year
ended December 31, 2012, with the remainder subject to
FERC regulation.
Under the Illinois Customer Choice Law, all electric
customers in Illinois may choose their own electric energy
provider. However, Ameren Illinois is required to serve as
the provider of last resort (POLR) for electric customers
within its territory who have not chosen an alternative retail
electric supplier. Ameren Illinois’ obligation to provide
POLR electric service varies by customer size. Ameren
Illinois is not required to offer fixed-priced electric service
to customers with electric demands of 400 kilowatts or
greater, as the market for service to this group of
customers has been declared competitive. Power and
related procurement costs incurred by Ameren Illinois are
passed directly to its customers through a cost recovery
mechanism.
In 2012, Ameren Illinois elected to participate in the
performance-based formula ratemaking process established
pursuant to the IEIMA by filing initial performance-based
formula rates with the ICC. The IEIMA was designed to
provide for the recovery of actual costs of electric delivery
service that are prudently incurred and to reflect the utility’s
actual regulated capital structure through the inclusion of a
formula for calculating the return on equity component of
the cost of capital. The return on equity component of the
formula rate is equal to the average for the calendar year of
the monthly yields of 30-year United States treasury bonds
plus 590 basis points for 2012 and 580 basis points
thereafter. Ameren Illinois’ actual return on equity relating
to electric delivery service will be subject to a collar
adjustment on earnings in excess of 50 basis points above
or below its allowed return. The IEIMA provides for an
annual reconciliation of the revenue requirement necessary
to reflect the actual costs incurred in a given year with the
revenue requirement that was in effect for that year,
including an allowed return on equity. This annual revenue
reconciliation, along with the collar adjustment, if
necessary, will be collected from or refunded to customers
in a subsequent year.
Ameren Illinois is also subject to performance
standards under the IEIMA. Failure to achieve the standards
will result in a reduction in the company’s allowed return on
equity calculated under the formula. The performance
standards include improvements in service reliability to
reduce both the frequency and duration of outages,
reduction in the number of estimated bills, reduction of
consumption on inactive meters, and a reduction in
uncollectible accounts expense. The IEIMA provides for
return on equity penalties totaling up to 30 basis points in
2013 through 2015, 34 basis points in 2016 through 2018,
and 38 basis points in 2019 through 2022 if the
performance standards are not met. The formula
ratemaking process is effective until the end of 2017, but
could be extended by the Illinois General Assembly for an
additional five years. The formula ratemaking process
would also terminate if the average residential rate
increases by more than 2.5% annually from June 2011
through May 2014. The average residential rate includes
generation service, which is outside of Ameren Illinois’
control, as Ameren Illinois is required to purchase all of its
power through procurement processes administered by the
IPA.
Between 2012 and 2021, Ameren Illinois is required,
pursuant to the IEIMA, to invest $625 million in capital
expenditures incremental to Ameren Illinois’ average electric
delivery capital expenditures for calendar years 2008
through 2010 to modernize its distribution system. Such
investments are expected to encourage economic
development and to create an estimated 450 additional jobs
within Illinois. Ameren Illinois is subject to monetary
penalties if 450 additional jobs are not created during the
peak program year. Also, Ameren Illinois is required to
contribute $1 million annually for certain nonrecoverable
customer assistance programs and $1 million annually to
the Illinois Science and Energy Innovation Trust for as long
as Ameren Illinois participates in the formula ratemaking
process. Ameren Illinois also was required to make a one-
time $7.5 million nonrecoverable donation to the Illinois
Science and Energy Innovation Trust in 2012.
7
Ameren Illinois’ initial filing under IEIMA was based on
2010 recoverable costs and expected net plant additions for
2011 and 2012. In September 2012, the ICC issued an
order approving an Ameren Illinois electric delivery service
revenue requirement of $779 million, which was a
$55 million decrease from the electric delivery service
revenue requirement allowed in the pre-IEIMA 2010 electric
delivery service rate order. The rates became effective on
October 19, 2012, and were effective through the end of
2012. In October 2012, Ameren Illinois filed an appeal of
the ICC order to the Appellate Court of the Fourth District of
Illinois. A decision by the appellate court is expected in
2013. Ameren Illinois believes that the ICC has incorrectly
implemented the IEIMA by using an average rate base as
opposed to a year-end rate base in setting rates, through its
treatment of accumulated deferred income taxes, and
through the method it used for calculating the equity
portion of Ameren Illinois’ capital structure and the method
for calculating interest on the revenue requirement
reconciliation and return on equity collar. The ICC’s
September 2012 order jeopardizes Ameren Illinois’ ongoing
ability to implement infrastructure improvements to the
extent and on the timetable envisioned in the IEIMA. Until
the uncertainty surrounding how the Illinois law will
ultimately be implemented is removed, Ameren Illinois is
reducing its IEIMA capital spending with a corresponding
negative effect on the job creation that the legislature
sought to effectuate with the law. Although Ameren Illinois
intends to meet its IEIMA capital spending requirements, it
is proceeding on a slower investment schedule than
previously contemplated.
In April 2012, Ameren Illinois submitted to the ICC an
update filing under IEIMA based on 2011 recoverable costs
and expected net plant additions for 2012. In December
2012, the ICC issued an order approving an Ameren Illinois
electric delivery service revenue requirement of
$764 million, which was a $15 million decrease in the
revenue requirement allowed in the ICC initial filing order.
The rates became effective on January 1, 2013, and will be
effective through the end of 2013. Ameren Illinois will
submit to the ICC during the second quarter of 2013 an
update filing based on 2012 recoverable costs and expected
net plant additions for 2013, which will determine rates that
are effective during 2014.
In December 2012, the ICC approved Ameren Illinois’
advanced metering infrastructure deployment plan, which
outlines how Ameren Illinois will comply with the IEIMA
requirement to spend $360 million on smart grid assets
over ten years on a cost-beneficial basis to its electric
customers. The plan targets the second quarter of 2014 to
begin installation of smart meters.
Also, Ameren Illinois has approval from the ICC to use
cost recovery mechanisms for energy efficiency programs,
environmental costs and bad debt expense not recovered in
base rates.
Ameren Illinois has a tariff rider to recover the costs of
asbestos-related litigation claims, subject to the following
terms: 90% of cash expenditures in excess of the amount
8
included in base electric rates are to be recovered from a
trust fund that was established when Ameren acquired IP.
At December 31, 2012, the trust fund balance was
$23 million, including accumulated interest. If cash
expenditures are less than the amount in base rates,
Ameren Illinois 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. Following the Ameren Illinois Merger, this rider is
applicable only for claims that occurred within IP’s
historical service territory. Similarly, the rider will permit
recovery only from customers within IP’s historical service
territory.
As a member of MISO, Ameren Illinois’ transmission
rates are calculated in accordance with the MISO OATT.
Ameren Illinois has received FERC approval to use
company-specific, forward-looking rate formula templates
in setting its transmission rates. These forward-looking
rates are updated in January each year based on forecasted
information, with an annual reconciliation to the actual
revenue requirement based on the costs incurred. In
Illinois, the AMIL pricing zone rate is charged directly to
wholesale customers and alternative retail electric suppliers,
which serve unbundled retail load. For Ameren Illinois retail
customers who have not chosen an alternative retail electric
supplier, the AMIL transmission rate, as well as other
MISO-related costs, are collected through a rider
mechanism in Ameren Illinois’ retail distribution tariffs.
Natural Gas
All of Ameren Illinois’ natural gas operating revenues
were subject to regulation by the ICC in the year ended
December 31, 2012.
On January 25, 2013, Ameren Illinois filed a request
with the ICC to increase its annual revenues for natural gas
delivery service by $50 million. The request was based on a
10.4% return on equity, a capital structure composed of
51.8% common equity, and a rate base of $1.1 billion. In an
attempt to reduce regulatory lag, Ameren Illinois is using a
future test year, 2014, in this proceeding. A decision by the
ICC in this proceeding is required by December 2013.
Ameren Illinois cannot predict the level of any delivery
service rate changes the ICC may approve, when any rate
changes may go into effect, or whether any rate changes
that may eventually be approved will be sufficient to enable
Ameren Illinois to recover its costs and earn a reasonable
return on its investments when the rate changes go into
effect.
If certain criteria are met, Ameren Illinois’ natural gas
rates may be adjusted without a traditional rate proceeding.
PGA clauses permit prudently incurred natural gas costs to
be passed directly to the customer. Also, Ameren Illinois
has approval from the ICC to use cost recovery
mechanisms for energy efficiency programs, certain
environmental costs and bad debt expense not recovered in
base rates.
For additional information on Illinois rate matters,
including the IEIMA and the Ameren Illinois’ natural gas
case filed in January 2013, see Results of Operations and
Outlook in Management’s Discussion and Analysis of
Financial Condition and Results of Operations under Part II,
Item 7, Quantitative and Qualitative Disclosures About
Market Risk under Part II, Item 7A, and Note 2 – Rate and
Regulatory Matters, and Note 15 – Commitments and
Contingencies under Part II, Item 8, of this report.
Merchant Generation
Merchant Generation revenues are determined by
market conditions and contractual arrangements. We expect
the Merchant Generation energy centers to have 5,522
megawatts of capacity available for the 2013 peak summer
electrical demand. In December 2012, Ameren determined
that it intends to, and it is probable that it will, exit its
Merchant Generation business before the end of the
previously estimated useful lives of that business’s long-
lived assets. As discussed below, Genco and AERG sell all
of their power and capacity to Marketing Company through
power supply agreements. Marketing Company attempts to
optimize the value of those assets and to mitigate risks
through a variety of techniques, including wholesale sales
of capacity and energy, retail sales in the non-rate-regulated
Illinois market, spot market sales primarily in MISO and
PJM, and financial hedging transactions, including options
and other derivatives. Marketing Company enters into long-
term and short-term contracts. Marketing Company’s
counterparties include cooperatives, municipalities,
residential, commercial and industrial customers, power
marketers, MISO, PJM and investor-owned utilities,
including Ameren Illinois. Illinois law allows municipalities
and counties to negotiate the purchase price of electricity
on behalf of residential and small business utility
customers. In 2012, Marketing Company began serving
those Illinois municipalities electing to aggregate their
residential and small commercial electric supply load, and
which selected Marketing Company as their provider. For
additional information on Marketing Company’s hedging
activities, see Outlook in Management’s Discussion and
Analysis of Financial Condition and Results of Operations
under Part II, Item 7 and Note 7 – Derivative Financial
Instruments under Part II, Item 8, of this report.
General Regulatory Matters
Ameren Missouri, Ameren Illinois, Genco, AERG and
Marketing Company must receive FERC approval to enter
into various transactions, including 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.
Ameren Missouri, Ameren Illinois, Genco, AERG and
ATXI are also subject to mandatory reliability standards,
including cybersecurity standards, adopted by FERC to
ensure the reliability of the bulk power electric system.
These standards are developed and enforced by NERC
pursuant to authority given to it by the FERC. If Ameren or
its subsidiaries were found not to be in compliance with any
of these mandatory reliability standards, they could incur
substantial monetary penalties and other sanctions.
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 the MoPSC and the ICC to request that
FERC review cost allocations by Ameren Services to other
Ameren companies.
Operation of Ameren Missouri’s Callaway energy
center is subject to regulation by the NRC. Its facility
operating license expires on June 11, 2024. In December
2011, Ameren Missouri submitted a license extension
application with the NRC to extend the energy center’s
operating license to 2044. There is no date by which the
NRC must act on this relicensing request. Ameren
Missouri’s Osage hydroelectric energy center and Ameren
Missouri’s Taum Sauk pumped-storage hydroelectric
energy center, as licensed projects under the Federal Power
Act, are subject to FERC regulations affecting, among other
things, the general operation and maintenance of the
projects. The license for Ameren Missouri’s Osage
hydroelectric energy center expires on March 30, 2047. In
June 2008, Ameren Missouri filed a relicensing application
with FERC to operate its Taum Sauk pumped-storage
hydroelectric energy center for another 40 years. The
existing FERC license expired on June 30, 2010. On July 2,
2010, Ameren Missouri received a license extension that
allows Taum Sauk to continue operations until FERC issues
a new license. FERC is reviewing the relicensing application.
A FERC order is expected in 2013 or 2014. Ameren
Missouri cannot predict the ultimate outcome of the order.
Ameren Missouri’s Keokuk energy center and its dam in the
Mississippi River between Hamilton, Illinois, and Keokuk,
Iowa are operated under authority granted by an Act of
Congress in 1905.
For additional information on regulatory matters, see
Note 2 – Rate and Regulatory Matters, Note 10 – Callaway
Energy Center, and Note 15 – Commitments and
Contingencies under Part II, Item 8, of this report, which
include a discussion about the December 2005 breach of
the upper reservoir at Ameren Missouri’s Taum Sauk
pumped-storage hydroelectric energy center.
Environmental Matters
Certain of our operations are subject to federal, state,
and local environmental statutes or regulations relating to
the safety and health of personnel, the public, and the
environment. These environmental statutes and regulations
include requirements for identification, generation, storage,
handling, transportation, disposal, recordkeeping, labeling,
reporting, and emergency response in connection with
9
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, the protection of natural and cultural
resources, and the management of waste and byproduct
materials. Failure to comply with those statutes or
regulations could have material adverse effects on us. We
could be subject to criminal or civil penalties by regulatory
agencies or we could be ordered by the courts to pay
private parties. Except as indicated in this report, we believe
that we are in material compliance with existing statutes
and regulations.
In addition to existing laws and regulations, including
the Illinois MPS that applies to AER’s energy centers in
Illinois, the EPA is developing environmental regulations
that will have a significant impact on the electric utility
industry. These regulations could be particularly
burdensome for certain companies, including Ameren,
Ameren Missouri, Genco, and AERG, that operate coal-fired
energy centers. Significant new rules proposed or
promulgated since the beginning of 2010 include the
regulation of greenhouse gas emissions; revised national
ambient air quality standards for SO2 and NO2 emissions;
the CSAPR, which would have required further reductions
of SO2 emissions, NOx emissions, and fine particulate
matter emissions from energy centers; a regulation that
governs management of CCR and coal ash impoundments;
the MATS, which require reduction of emissions of
mercury, toxic metals, and acid gases from energy centers;
revised NSPS for particulate matter, SO2, and NOx
emissions from new sources; and new regulations under
the Clean Water Act that could require significant capital
expenditures, such as for new water intake structures or
cooling towers, at our energy centers. The EPA has
proposed CO2 limits for new coal-fired and natural gas-fired
combined cycle units and is expected to propose limits for
existing units in the future. These new and proposed
regulations, if adopted, may be challenged through
litigation, so their ultimate implementation as well as the
timing of any such implementation is uncertain, as
evidenced by the CSAPR being vacated and remanded back
to the EPA by the United States Court of Appeals for the
District of Columbia in August 2012. Although many details
of these future regulations are unknown, the combined
effects of the new and proposed environmental regulations
may result in significant capital expenditures and/or
increased operating costs over the next five to ten years for
Ameren, Ameren Missouri and AER. Compliance with these
environmental laws and regulations could be prohibitively
expensive. If they are, these regulations could require us to
close or to significantly alter the operation of our energy
centers, which could have an adverse effect on our results
of operations, financial position, and liquidity, including the
impairment of long-lived assets. Failure to comply with
environmental laws and regulations might also result in the
imposition of fines, penalties, and injunctive measures.
reflects the increased cost for environmental compliance.
During early 2012, the observable market price for power
for delivery in that year and in future years sharply declined
below 2011 levels primarily because of declining natural
gas prices, as well as the impact from the stay of the
CSAPR. As a result of this sharp decline in the market price
for power, as well as uncertain environmental regulations,
Genco decelerated the construction of two scrubbers at its
Newton energy center.
For additional discussion of environmental matters,
including NOx, SO2, and mercury emission reduction
requirements, remediation efforts, and a discussion of the
EPA’s allegations of violations of the Clean Air Act and
Missouri law in connection with projects at Ameren
Missouri’s Rush Island energy center, and the EPA’s Notice
of Violation of permitting requirements at Genco’s Newton
energy center, see Liquidity and Capital Resources in
Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7,
and Note 15 – Commitments and Contingencies under
Part II, Item 8, of this report.
TRANSMISSION AND SUPPLY OF ELECTRIC POWER
Ameren owns an integrated transmission system that
comprises the transmission assets of Ameren Missouri,
Ameren Illinois and ATXI. Ameren also operates two
balancing authority areas, AMMO (which includes Ameren
Missouri), and AMIL (which includes Ameren Illinois, ATXI,
AERG, and Genco excluding EEI and Genco’s Elgin CT
energy center). During 2012, the peak demand was 8,868
megawatts in AMMO and 9,720 megawatts in AMIL. The
Ameren transmission system directly connects with 15
other balancing authority areas for the exchange of electric
energy.
Ameren Missouri, Ameren Illinois and ATXI are
transmission-owning members of MISO. Transmission
service on the Ameren transmission system is provided
pursuant to the terms of the MISO OATT on file with FERC.
EEI operates its own balancing authority area and its own
transmission facilities in southern Illinois. The EEI
transmission system is directly connected to the
transmission systems of MISO, the Tennessee Valley
Authority, and Louisville Gas and Electric Company. EEI’s
energy centers are dispatched separately from those of
Ameren Missouri, Genco and AERG. Ameren Missouri is
authorized by the MoPSC to participate in MISO, subject to
certain conditions, through May 2016.
In May 2011 FERC approved transmission rate
incentives for the Illinois Rivers project, which is being
developed by ATXI. In December 2011, MISO approved the
Illinois Rivers project as well as the Spoon River and Mark
Twain projects. The total investment in these three MISO-
approved projects is expected to be more than $1.3 billion
from 2013 to 2019. These projects are located primarily in
Illinois and Missouri.
The decision to make pollution control equipment
investments at our Merchant Generation business depends
on whether the expected future market price for power
In February 2012, FERC approved ATXI’s request for a
forward-looking rate calculation with an annual
reconciliation adjustment, as well as ATXI’s request for
10
implementation of the incentives FERC approved in its May
2011 order for the Illinois Rivers project. In November
2012, FERC approved transmission rate incentives for the
Spoon River project and the Mark Twain project. FERC also
approved a forward-looking rate calculation with an annual
reconciliation adjustment for Ameren Illinois’ electric
transmission business.
The Ameren Companies and EEI are members of
SERC. SERC is responsible for the bulk electric power
supply system in all or portions of Missouri, Illinois,
Arkansas, Kentucky, Tennessee, North Carolina,
South Carolina, Georgia, Mississippi, Alabama, Louisiana,
Virginia, Florida, Oklahoma, Iowa, and Texas. As a result of
the Energy Policy Act of 2005, owners and operators of the
bulk electric power system are subject to mandatory
reliability standards promulgated by NERC and its regional
entities, such as SERC, which are enforced by FERC. The
Ameren Companies must comply with these standards,
which are in place to ensure the reliability of the bulk
electric power system.
See Note 2 – Rate and Regulatory Matters under
Part II, Item 8, of this report for additional information.
Ameren Missouri
Ameren Missouri’s electric supply is obtained primarily
from its own generation. Factors that could cause Ameren
Missouri to purchase power include, among other things,
absence of sufficient owned generation, energy center
outages, the fulfillment of renewable energy portfolio
requirements, the failure of suppliers to meet their power
supply obligations, extreme weather conditions, and the
availability of power at a cost lower than the cost of
generating it.
Ameren Missouri continues to evaluate its longer-term
needs for new baseload and peaking electric generation
capacity. The MoPSC’s December 2012 electric rate order
approved Ameren Missouri’s implementation of MEEIA
megawatthour savings targets, energy efficiency programs,
and associated cost recovery mechanisms and incentive
awards. The order allows for Ameren Missouri to collect its
program costs and 90% of its projected lost revenue from
customers over the same three-year period starting on
January 2, 2013. The remaining 10% of projected lost
revenue is expected to be recovered as part of future rate
proceedings. The potential need for new generating plant
construction is dependent on several key factors including:
continuation of energy efficiency programs beyond 2015,
load growth, customer participation in energy efficiency
programs, and the potential for more stringent
environmental regulation of coal-fired energy centers, which
could lead to the retirement of current baseload assets.
Because of the significant time required to plan, acquire
permits for, and build a baseload power plant, Ameren
Missouri continues to study future plant alternatives and is
taking steps to preserve options to meet future demand.
These steps include evaluating the potential for further
energy efficiency programs in the long term, evaluating
potential sites for natural gas-fired generation, and pursuing
DOE funds through a partnership with Westinghouse for
development of small modular reactor technology for
nuclear power. Ameren Missouri’s next Integrated Resource
Plan filing with the MoPSC is due October 1, 2014.
See also Outlook in Management’s Discussion and
Analysis of Financial Condition and Results of Operations
under Part II, Item 7, and Note 2 – Rate and Regulatory
Matters and Note 15 – Commitments and Contingencies
under Part II, Item 8, of this report.
Ameren Illinois
Any electric supply purchased by Ameren Illinois for its
retail customers comes either through an annual
procurement process conducted by the IPA or through
markets operated by MISO. The power and related
procurement costs incurred by Ameren Illinois are passed
directly to its customers through a cost recovery
mechanism.
The IPA administers a RFP process that procures
Ameren Illinois’ expected supply obligation. Since the RFP
process began in 2009, the ICC has approved the outcomes
of multiple electric power procurement RFPs for energy,
capacity, and renewable energy credits covering different
time periods.
A portion of the electric power supply required for
Ameren Illinois to satisfy its distribution customers’
requirements is purchased in the RFP process administered
by the IPA from Marketing Company, on behalf of Genco
and AERG, and from Ameren Missouri.
Under Illinois law, transmission and distribution
service rates are regulated, while electric customers are
allowed to purchase generation from an alternative retail
electric supplier. At December 31, 2012, approximately
396,000 retail customers representing approximately 61%
of Ameren Illinois’ annual retail kilowatthour sales had
elected to purchase their electricity from an alternative retail
electric supplier. Customers who receive electricity from an
alternative retail electric supplier continue to pay a delivery
charge to Ameren Illinois for the distribution services they
receive from Ameren Illinois.
See Note 2 – Rate and Regulatory Matters, Note 14 –
Related Party Transactions and Note 15 – Commitments
and Contingencies under Part II, Item 8, of this report for
additional information on power procurement in Illinois.
Merchant Generation
Genco and AERG have entered into power supply
agreements with Marketing Company whereby Genco and
AERG sell, and Marketing Company purchases, all of the
capacity and energy available from Genco’s and AERG’s
energy centers. These power supply agreements continue
through December 31, 2022, and from year to year
11
thereafter unless either party elects to terminate the
agreement by providing the other party with no less than six
months’ advance written notice. EEI and Marketing
Company have entered into a power supply agreement for
EEI to sell all of its capacity and energy to Marketing
Company. This agreement expires on May 31, 2016. All of
Genco’s, AERG’s and EEI’s energy centers compete for the
sale of energy and capacity in the competitive energy
markets through Marketing Company.
POWER GENERATION
The following table presents the source of electric generation, excluding purchased power, for the years ended
December 31, 2012, 2011 and 2010:
Coal
Nuclear
Natural Gas Renewables(a)
Oil
Ameren:(b)
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merchant Generation:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
81%
85
85
73%
77
77
94%
98
98
15%
12
12
24%
19
19
-%
-
-
3%
1
1
1%
1
1
6%
2
2
1%
2
2
2%
3
3
-%
-
-
(c)%
(c)
(c)
(c)%
(c)
-
-%
(c)
(c)
(a) Renewable power generation includes production from Ameren Missouri’s hydroelectric, pumped-storage, and methane gas energy centers,
but excludes purchased renewable energy credits.
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
(c) Less than 1% of total fuel supply.
The following table presents the cost of fuels for electric generation for the years ended December 31, 2012, 2011, and
2010:
Cost of Fuels (Dollars per Mmbtu)
2012
2011
2010
Ameren:
Coal(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2.081
0.964
3.772
$
1.931
0.750
6.097
$
1.848
0.701
6.539
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1.975
$
1.873
$
1.803
Ameren Missouri:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal(a)
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1.925
0.964
4.517
$
1.733
0.750
5.873
$
1.675
0.701
6.199
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1.743
$
1.610
$
1.563
Merchant Generation:
Coal(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2.282
3.392
2.359
$
$
2.184
6.374
2.292
$
$
2.063
6.972
2.169
(a) The fuel cost for coal represents the cost of coal, the costs for transportation, which include railroad diesel fuel additives, and the cost of
emission allowances.
(b) The fuel cost for natural gas represents the cost of natural gas and firm and variable costs for transportation, storage, balancing, and fuel
losses for delivery 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 energy centers.
(c) Represents all costs for fuels used in our energy centers, to the extent applicable, including coal, nuclear, natural gas, methane gas, oil,
propane, tire chips, paint products, and handling. Oil, propane, tire chips, and paint products are not individually listed in this table because
their use is minimal.
Coal
Ameren Missouri and the Merchant Generation
business have agreements in place to purchase a portion of
the coal they need and to transport it to energy centers
through 2019. Ameren Missouri and Merchant Generation
expect to enter into additional contracts to purchase coal
from time to time. Coal supply agreements for Ameren
12
Missouri have terms of up to six years, and expire between
2014 and 2017. Ameren Missouri has an ongoing need for
coal to serve its native load customers, so it pursues a price
hedging strategy consistent with this requirement.
Merchant Generation’s forward coal requirements and coal
supply agreements are dependent on the volume of power
sales contracted. Merchant Generation strives to achieve
increased margin certainty by aligning its fuel purchases
with its power sales. Ameren burned 34 million tons
(Ameren Missouri – 19 million, Merchant Generation –
15 million) of coal in 2012. See Part II, Item 7A –
Quantitative and Qualitative Disclosures About Market Risk
of this report for additional information about coal supply
contracts.
About 97% of Ameren’s coal (Ameren Missouri – 97%,
Merchant Generation – 97%) is purchased from the Powder
River Basin in Wyoming. The remaining coal is typically
purchased from the Illinois Basin. Ameren Missouri and
Merchant Generation have a goal to maintain coal inventory
consistent with their risk management policies. Inventory
may be adjusted because of changes in burn or
uncertainties of supply due to potential work stoppages,
delays in coal deliveries, equipment breakdowns, and other
factors. In the past, deliveries from the Powder River Basin
have occasionally been restricted because of rail
maintenance, weather, and derailments. As of
December 31, 2012, coal inventories for Ameren Missouri
and for Merchant Generation were at or above targeted
levels. Disruptions in coal deliveries could cause Ameren
Missouri and Merchant Generation 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
The steps in the process to provide nuclear fuel
generally involve the mining and milling of uranium ore to
produce uranium concentrates, the conversion of uranium
concentrates to uranium hexafluoride gas, the enrichment
of that gas, and the fabrication of the enriched uranium
hexafluoride gas into usable fuel assemblies. Ameren
Missouri has entered into uranium, uranium conversion,
uranium enrichment, and fabrication contracts to procure
the fuel supply for its Callaway nuclear energy center.
Fuel assemblies for the 2013 spring refueling at
Ameren Missouri’s Callaway energy center were
manufactured and were delivered to the energy center in
January 2013. Ameren Missouri also has agreements or
inventories to price-hedge approximately 99%, 52%, and
46% of Callaway’s 2014, 2016 and 2017 refueling
requirements, respectively. Ameren Missouri has uranium
(concentrate and hexafluoride) inventories and supply
contracts sufficient to meet all of its uranium and
conversion requirements at least through 2017. Ameren
Missouri has enriched uranium inventories and enrichment
supply contracts sufficient to satisfy enrichment
requirements through at least 2017. Fuel fabrication
services are under contract through 2014. Ameren Missouri
expects to enter into additional contracts to purchase
nuclear fuel. As a member of Fuelco, Ameren Missouri can
join with other member companies to increase its
purchasing power, enhance diversification, and pursue
opportunities for volume discounts. The Callaway energy
center normally requires refueling at 18-month intervals.
The last refueling was completed in November 2011. There
is no refueling scheduled for 2015 and 2018. The nuclear
fuel markets are competitive, and prices can be volatile;
however, we do not anticipate any significant problems in
meeting our future supply requirements.
Natural Gas Supply for Generation
To maintain deliveries to natural gas-fired energy
centers throughout the year, especially during the summer
peak demand, Ameren’s portfolio of natural gas supply
resources includes firm transportation capacity and firm no-
notice storage capacity leased from interstate pipelines.
Ameren Missouri and Merchant Generation 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 energy
centers. 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.
Ameren Missouri’s and Merchant Generation’s natural
gas procurement strategy is designed to ensure reliable and
immediate delivery of natural gas to their energy centers.
This is accomplished by optimizing transportation and
storage options and minimizing cost and price risk through
various supply and price-hedging agreements that allow
access to multiple gas pools, supply basins, and storage
services. As of December 31, 2012, Ameren Missouri had
price-hedged about 34% and Merchant Generation had
price hedged 59% of its expected natural gas supply
requirements for generation in 2013.
Renewable Energy
Illinois and Missouri have enacted laws requiring
electric utilities to include renewable energy resources in
their portfolios. Illinois requires renewable energy resources
to equal or exceed 2% of the total electricity that each
electric utility supplies to its eligible retail customers as of
June 1, 2008, with that percentage increasing to 10% by
June 1, 2015, and to 25% by June 1, 2025. In 2012,
Ameren Illinois procured approximately 8% of its total
electricity from renewable energy resources. Ameren Illinois
has procured renewable energy credits under the IPA-
administered procurement process to meet the renewable
energy portfolio requirement through at least May 2017. In
December 2010, Ameren Illinois entered into 20-year
agreements with renewable energy suppliers and
commenced receiving renewable energy credits under these
agreements in June 2012. Approximately 54% of the 2013
plan year renewable energy requirement will be met through
these agreements. The remaining requirement will be met
through IPA procurements, which resulted in contracts that
were executed in February 2012 with a term of June 2013
through December 2017.
13
In Missouri, utilities are required to purchase or
generate from renewable energy sources electricity equaling
at least 2% of native load sales, with that percentage
increasing to at least 15% by 2021, subject to a 1% annual
limit on customer rate impacts. At least 2% of each
renewable energy portfolio requirement must be derived
from solar energy. Ameren Missouri expects to satisfy the
nonsolar requirement through 2017 with its existing
renewable generation, including the Maryland Heights
energy center, along with a 15-year 102-megawatt power
purchase agreement with a wind farm operator in Iowa that
became effective in 2009. Currently, Ameren Missouri
expects to meet the solar energy requirement through the
purchase of solar-generated renewable energy credits, and
generation from solar panels installed on Ameren’s general
office building. However, Ameren Missouri is studying other
options for compliance. In 2012, Ameren Missouri
purchased or generated approximately 3% of its native load
sales from renewable energy resources.
In 2012, Ameren Missouri began generating power at
its Maryland Heights energy center. This energy center,
located at a landfill in Maryland Heights, Missouri, has the
capability to generate up to approximately 15 megawatts of
electricity by burning methane gas collected from the
landfill. Ameren Missouri signed a 20-year supply
agreement with the landfill owner to purchase methane gas.
Energy Efficiency
Ameren’s rate-regulated utilities have implemented
energy efficiency programs to educate and help their
customers become more efficient users of energy. The
MEEIA established a regulatory framework that, among
other things, allows electric utilities to recover costs related
to MoPSC-approved energy efficiency programs. The law
requires the MoPSC to ensure that a utility’s financial
incentives are aligned to help customers use energy more
efficiently, to provide timely cost recovery, and to provide
earnings opportunities associated with cost-effective energy
efficiency programs. Missouri does not have a law
mandating energy efficiency standards.
The MoPSC’s December 2012 electric rate order
approved Ameren Missouri’s implementation of MEEIA
megawatthour savings targets, energy efficiency programs,
and associated cost recovery mechanisms and incentive
awards. Beginning in 2013, Ameren Missouri will invest
approximately $147 million over the next three years for
energy efficiency programs. The order allows for Ameren
Missouri to collect its program costs and 90% of its
projected lost revenue from customers over the same three
years starting on January 2, 2013. The remaining 10% of
projected lost revenue is expected to be recovered as part
of future rate proceedings.
Additionally, the order provides for an incentive award
that would allow Ameren Missouri to earn additional
revenues based on achievement of certain energy efficiency
goals, including approximately $19 million if 100% of its
energy efficiency goals are achieved during the three-year
period, with the potential to earn more if Ameren Missouri’s
energy savings exceed those goals. Ameren Missouri must
achieve at least 70% of its energy efficiency goals before it
earns any incentive award. The recovery of the incentive
award from customers, if the energy efficiency goals are
achieved, would begin after the three-year energy efficiency
plan is complete and upon the effective date of an electric
service rate order or possibly with the future adoption of a
rider mechanism. See Note 2 – Rate and Regulatory Matters
under Part II, Item 8, of this report for additional
information.
Illinois has enacted a law requiring Ameren Illinois to
offer energy efficiency programs. The law also allows
recovery mechanisms of the programs’ costs. The ICC has
issued orders approving Ameren Illinois’ electric and natural
gas energy efficiency plans as well as cost recovery
mechanisms by which program costs can be recovered
from customers. In addition, over a ten-year period,
Ameren Illinois will invest an estimated $625 million to
upgrade and modernize its transmission and distribution
infrastructure in accordance with the IEIMA. As part of
these upgrades, Ameren Illinois expects to invest
$360 million to install smart meters, which could enable
customers to improve efficiency.
NATURAL GAS SUPPLY FOR DISTRIBUTION
Ameren Missouri and Ameren Illinois are responsible
for the purchase and delivery of natural gas to their utility
customers. Ameren Missouri and Ameren Illinois develop
and manage a portfolio of natural gas supply resources.
These include firm gas supply under term agreements with
producers, interstate and intrastate firm transportation
capacity, firm storage capacity leased from interstate
pipelines, and on-system storage facilities to maintain
natural gas deliveries to customers throughout the year and
especially during peak demand periods. Ameren Missouri
and Ameren Illinois primarily use Panhandle Eastern Pipe
Line Company, Trunkline Gas Company, Natural Gas
Pipeline Company of America, Mississippi River
Transmission Corporation, Northern Border Pipeline
Company, and Texas Eastern Transmission Corporation
interstate pipeline systems to transport natural gas to their
systems. In addition to transactions requiring physical
delivery, financial instruments, including those entered into
in the NYMEX futures market and in the OTC financial
markets, are used to hedge the price paid for natural gas.
See Part II, Item 7A – Quantitative and Qualitative
Disclosures About Market Risk of this report for additional
information about natural gas supply contracts. Natural gas
purchase costs are passed on to customers of Ameren
Missouri and Ameren Illinois under PGA clauses, subject to
prudency reviews by the MoPSC and the ICC. As of
December 31, 2012, Ameren Missouri had price-hedged
89%, and Ameren Illinois had price-hedged 81%, of its
expected natural gas supply requirements for distribution in
2013.
For additional information on our fuel and purchased
power supply, see Results of Operations, Liquidity and
14
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 10 – Callaway Energy Center, Note 14 – Related Party
Transactions, and Note 15 – Commitments and
Contingencies under Part II, Item 8 of this report.
INDUSTRY ISSUES
We are facing issues common to the electric and
natural gas utility industry and the merchant electric
generation industry. These issues include:
‰
‰
‰
‰
‰
‰
‰
‰
‰
continually developing and complex environmental
laws, regulations and issues, including air and water
quality standards, mercury emissions standards, and
likely greenhouse gas limitations and CCR management
requirements;
political and regulatory resistance to higher rates;
the potential for changes in laws, regulations, and
policies at the state and federal level;
access to, and uncertainty in, the capital and credit
markets;
cybersecurity risk, including loss of operational control
of energy centers and electric and natural gas
transmission and distribution systems and/or loss of
data, and compliance with related industry regulations;
the potential for more intense competition in
generation, supply and distribution, including new
technologies;
pressure on customer growth and usage in light of
current economic conditions and energy efficiency
initiatives;
the potential for reregulation in some states, which
could cause electric distribution companies to build or
acquire energy centers and to purchase less power
from electric generation companies such as Genco and
AERG;
changes in the structure of the industry as a result of
changes in federal and state laws, including the
formation and growth of independent transmission
entities;
OPERATING STATISTICS
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
increases, decreases, and volatility in power prices due
to the balance of supply and demand and marginal fuel
costs;
weakened financial strength of merchant generators,
especially those with coal-fired energy centers,
including their ability to generate positive cash flows in
competitive markets as they seek to comply with
environmental regulations;
the availability of fuel and increases or decreases in fuel
prices;
the availability of qualified labor and material, and rising
costs;
regulatory lag;
the influence of macroeconomic factors, such as yields
on United States treasury securities, on allowed rates of
return on equity provided by regulators;
decreased or negative free cash flows due to rising
infrastructure investments and regulatory frameworks;
public concern about the siting of new facilities;
aging infrastructure and the need to construct new
power generation, transmission and distribution
facilities, which have long time frames to completion,
while at the same time, having little long-term visibility
on power and commodity prices;
legislation or proposals for programs to encourage or
mandate energy efficiency and renewable sources of
power;
public concerns about nuclear generation and
decommissioning and the disposal of nuclear waste;
and
consolidation of electric and natural gas companies.
We are monitoring these issues. Except as otherwise
noted in this report, we are unable to predict what impact, if
any, these issues will have on our results of operations,
financial position, or liquidity. For additional information,
see Risk Factors under Part I, Item 1A, and Outlook in
Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7,
and Note 2 – Rate and Regulatory Matters and Note
15 –Commitments and Contingencies under Part II, Item 8,
of this report.
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,
2012
2011
2010
Electric Sales – kilowatthours (in millions):
Ameren Missouri:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Native load subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Off-system and wholesale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13,385
14,575
8,660
126
36,746
7,293
44,039
13,867
14,743
8,691
127
37,428
10,715
48,143
14,640
15,002
8,656
129
38,427
9,796
48,223
15
Electric Operating Statistics – Year Ended December 31,
2012
2011
2010
Ameren Illinois:
Residential
Power supply and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Power supply and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Power supply and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Native load subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merchant Generation:
Nonaffiliate energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate native energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate affiliate sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate Ameren Illinois/Merchant Generation common customers . . . . . . . . . . . . . . . . . . . . . . .
Ameren total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric Operating Revenues (in millions):
Ameren Missouri:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Native load subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Off-system and wholesale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Residential
Power supply and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Power supply and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Power supply and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Native load subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merchant Generation:
Nonaffiliate energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate native energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate affiliate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric Generation – megawatthours (in millions):
Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merchant Generation:
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AERG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medina Valley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
$
9,507
2,103
2,985
9,175
1,595
11,753
523
37,641
25,552
1,679
27,231
(1,679)
(7,261)
99,971
1,297
1,088
435
104
2,924
208
3,132
961
90
254
177
57
46
154
1,739
1,047
311
15
1,373
(340)
5,904
44.7
18.5
7.2
-
25.7
70.4
$
$
$
$
$
$
$
$
11,771
77
3,662
8,561
1,502
11,360
529
37,462
31,148
1,004
32,152
(1,004)
(5,454)
12,340
1
4,419
8,051
1,389
11,147
545
37,892
30,788
949
31,737
(949)
(5,016)
111,299
111,887
$
$
$
$
$
$
$
$
1,272
1,084
438
76
2,870
352
3,222
1,194
3
350
157
65
43
128
1,940
1,382
232
12
1,626
(258)
6,530
48.8
22.0
7.0
0.1
29.1
77.9
1,193
1,004
399
91
2,687
343
3,030
1,270
-
425
143
66
38
119
2,061
1,442
231
20
1,693
(263)
6,521
48.1
22.0
7.5
0.1
29.6
77.7
Price per ton of delivered coal (average) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
36.63
$
33.79
$
32.91
16
Electric Operating Statistics – Year Ended December 31,
2012
2011
2010
Source of energy supply:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased – Wind . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased – Other
65.1%
12.4
1.1
2.7
0.4
18.3
66.5%
9.4
1.3
1.1
0.3
21.4
65.7%
8.9
1.6
1.0
0.3
22.5
100.0%
100.0%
100.0%
Gas Operating Statistics – Year Ended December 31,
2012
2011
2010
Natural Gas Sales (millions of dekatherms):
Ameren Missouri:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other:
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas Operating Revenues (in millions)
Ameren Missouri:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other:
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate affiliate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
6
3
1
10
49
17
5
3
74
-
-
84
85
36
8
10
139
547
172
24
43
786
-
(1)
924
$
$
$
$
$
$
Peak day throughput (thousands of dekatherms):
Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total peak day throughput
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
139
1,061
1,200
7
3
1
11
56
21
5
-
82
-
-
93
96
41
9
10
156
588
195
30
33
846
-
(1)
1,001
149
1,157
1,306
$
$
$
$
$
$
7
4
1
12
60
23
7
-
90
1
1
103
100
43
10
13
166
649
223
44
37
953
4
(6)
1,117
167
1,227
1,394
AVAILABLE INFORMATION
The Ameren Companies make available free of charge
through Ameren’s website (www.ameren.com) their annual
reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K, eXtensible Business Reporting
Language (XBRL) documents, and any amendments to
those reports filed with or furnished to pursuant to Sections
13(a) or 15(d) of the Exchange Act as soon as reasonably
possible after such reports are electronically filed with, or
17
furnished to, the SEC. These documents are also available
through an Internet website maintained by the SEC
(www.sec.gov). Ameren also uses its website as a channel
of distribution of material information relating to the
Ameren Companies. Financial and other material
information regarding the Ameren Companies is routinely
posted and accessible at Ameren’s website.
The Ameren Companies also make available free of
charge through Ameren’s website the charters of Ameren’s
board of directors’ audit and risk committee, human
resources committee, nominating and corporate
governance committee, finance committee, and nuclear
oversight and environmental committee; the corporate
governance guidelines; a policy regarding communications
to the board of directors; a policy and procedures with
respect to related-person transactions; a code of ethics for
principal executive and senior financial officers; a code of
business conduct applicable to all directors, officers and
employees; and a director nomination policy that applies to
the Ameren Companies. The information on Ameren’s
website, or any other website referenced in this report, is
not incorporated by reference into this report.
ITEM 1A. RISK FACTORS
Investors should review carefully the following material
risk factors and the other information contained in this
report. The risks that the Ameren Companies face are not
limited to those in this section. There may be further risks
and uncertainties that are not presently known or that are
not currently believed to be material that may adversely
affect the results of operations, financial position, and
liquidity of the Ameren Companies. See Forward-Looking
Statements above and Outlook in Management’s Discussion
and Analysis of Financial Condition and Results of
Operations under Part II, Item 7, of this report.
The Ameren Companies are subject to extensive
regulation of their businesses, which could adversely
affect their results of operations, financial position, and
liquidity.
The Ameren Companies are subject to, or affected by,
extensive federal, state, and local regulation. This extensive
regulatory framework, some but not all of which is more
specifically identified in the following risk factors, regulates,
among other matters, the electric and natural gas
industries; rate and cost structure of utilities; operation of
nuclear energy centers; construction and operation of
generation, transmission, and distribution facilities;
acquisition, disposal, depreciation and amortization of
assets and facilities; transmission reliability; and present or
prospective wholesale and retail competition. The Ameren
Companies must address in their business planning and
management of operations the effects of existing and
proposed laws and regulations and potential changes in the
regulatory framework, including initiatives by federal and
state legislatures, RTOs, utility regulators, and taxing
authorities. Significant changes in the nature of the
regulation of the Ameren Companies’ businesses could
require changes to their business planning and
management of their businesses and could adversely affect
their results of operations, financial position, and liquidity.
Failure of the Ameren Companies to obtain adequate rates
or regulatory approvals in a timely manner, failure to obtain
necessary licenses or permits from regulatory authorities,
new or modified laws, regulations, standards,
interpretations, or other legal requirements, or increased
compliance costs could adversely impact the Ameren
Companies’ results of operations, financial position, and
liquidity.
The electric and natural gas rates that Ameren
Missouri and Ameren Illinois are allowed to charge are
determined through regulatory proceedings, which are
subject to appeal, and are subject to legislative actions,
which are largely outside of their control. Any events that
prevent Ameren Missouri or Ameren Illinois from
recovering their respective costs or from earning
appropriate returns on their investments could adversely
affect the Ameren Companies’ results of operations,
financial position, and liquidity.
The rates that Ameren Missouri and Ameren Illinois are
allowed to charge for their utility services significantly
influence the results of operations, financial position, and
liquidity of these companies and Ameren. The electric and
natural gas utility industries are highly regulated. The utility
rates charged to Ameren Missouri and Ameren Illinois
customers are determined, in large part, by governmental
entities, including the MoPSC, the ICC, and FERC. Decisions
by these entities are influenced by many factors, including
the cost of providing service, the prudency of expenditures,
the quality of service, regulatory staff knowledge and
experience, economic conditions, public policy, and social
and political views. Decisions made by these governmental
entities regarding rates are largely outside of Ameren
Missouri’s and Ameren Illinois’ control. Regulatory lag
involved in filing and getting new rates approved could have
a material adverse effect on our results of operations,
financial position, and liquidity. Rate orders are also subject
to appeal, which creates additional uncertainty as to the
rates Ameren Missouri and Ameren Illinois will ultimately be
allowed to charge for their services.
Ameren Missouri electric and natural gas utility rates
and Ameren Illinois natural gas utility rates are typically
established in regulatory proceedings that take up to 11
months to complete. Rates established in those
proceedings for Ameren Missouri are primarily based on
historical costs and revenues. Rates established in those
proceedings for Ameren Illinois may be based on historical
or estimated future costs and revenues. Thus, the rates a
utility is allowed to charge may not match its costs at any
given time. Rates include an allowed return on investments
by the regulators. Although rate regulation is premised on
providing a reasonable opportunity to earn a reasonable
rate of return on invested capital, there can be no assurance
that the applicable regulatory commission will judge all the
costs of Ameren Missouri and Ameren Illinois to have been
prudently incurred or that the regulatory process in which
rates are determined will always result in rates that will
produce full recovery of such costs or an adequate return
on those investments.
In years when capital investments and operations
costs rise while customer usage declines, such as in 2012,
Ameren Missouri and Ameren Illinois may not be able to
earn the allowed return established by their regulators. This
could result in the deferral or elimination of planned capital
18
investments, which reduces the rate base investments the
utility operations earn a rate of return on. Additionally, a
period of increasing rates for our customers could result in
additional regulatory and legislative actions, as well as
competitive and political pressures, which could adversely
affect the Ameren Companies’ results of operations,
financial position, and liquidity.
Through its participation in the performance-based
formula ratemaking process established pursuant to the
IEIMA, Ameren Illinois’ return on equity will be directly
correlated to yields on United States treasury bonds.
Additionally, Ameren Illinois will be subject to an annual
ICC prudence review and to the ICC’s implementation of
the IEIMA, and Ameren Illinois will be required to
achieve performance objectives, increase capital
spending levels, and meet job creation targets, which if
not successfully completed or achieved could adversely
affect Ameren Illinois’ results of operations, financial
position, and liquidity.
In 2012, Ameren Illinois elected to participate in the
performance-based formula ratemaking process established
pursuant to the IEIMA for its electric distribution business.
The ICC will annually review Ameren Illinois’ performance-
based rate filings under the IEIMA for reasonableness and
prudency. If the ICC were to conclude that Ameren Illinois’
incurred costs were not prudently incurred, the ICC could
disallow recovery of such costs. Ameren is also subject to
the ICC’s implementation of the IEIMA’s formula rates. After
reviewing the ICC’s IEIMA formula rate orders in 2012,
Ameren Illinois believes that the ICC has incorrectly
implemented the IEIMA. Ameren Illinois objects to the ICC’s
use of an average rate base as opposed to a year-end rate
base in setting rates, to its treatment of accumulated
deferred income taxes, and to the methods it used to
calculate the equity portion of Ameren Illinois’ capital
structure and to calculate interest on the revenue
requirement reconciliation and return on equity collar.
The return on equity component of the formula rate is
equal to the average for the calendar year of the monthly
yields of 30-year United States treasury bonds plus 580
basis points for years after 2012. Therefore, Ameren Illinois’
annual return on equity will be directly correlated to yields
on United States treasury bonds, which are outside of
Ameren Illinois’ control.
Ameren Illinois will also be subject to performance
standards. Failure to achieve the standards will result in a
reduction in the company’s allowed return on equity
calculated under the formula. The IEIMA provides for return
on equity penalties totaling 30 basis points in 2013 through
2015, 34 basis points in 2016 through 2018, and 38 basis
points in 2019 through 2022 if the performance standards
are not met.
Between 2012 and 2021, Ameren Illinois will be
required to invest $625 million in capital expenditures
incremental to Ameren Illinois’ average electric delivery
capital expenditures for calendar years 2008 through 2010
to modernize its distribution system. Ameren Illinois is
subject to monetary penalties if 450 additional jobs in
Illinois are not created during the peak program year.
The formula ratemaking process would terminate if the
average residential rate increases by more than 2.5%
annually from June 2011 through May 2014. The average
residential rate includes generation service, which is outside
of Ameren Illinois’ control, as Ameren Illinois is required to
purchase all of its power through procurement processes
administered by the IPA. If the performance-based formula
rate process is terminated, Ameren Illinois would be
required to establish future rates through a traditional rate
proceeding with the ICC, which might not result in rates
that produce a full or timely recovery of costs or an
adequate return on investments. Unless extended, the
IEIMA formula ratemaking process expires in 2017.
Energy conservation, energy efficiency efforts and
other factors that reduce energy demand could adversely
affect the Ameren Companies’ results of operations,
financial position, and liquidity.
Regulatory and legislative bodies have proposed or
introduced requirements and incentives to reduce energy
consumption. Conservation and energy efficiency programs
are designed to reduce energy demand. Unless there is a
regulatory solution ensuring recovery, declining usage will
result in an underrecovery of fixed costs at our rate-
regulated business. Ameren Missouri, even with the
implementation of energy efficiency programs under the
MEEIA, is exposed to declining usage losses from energy
efficiency efforts not related to its specific programs as well
as distributed generation sources such as solar panels.
Macroeconomic factors resulting in low economic growth
or contraction within the Ameren Companies’ service
territories could also reduce energy demand.
We are subject to various environmental laws and
regulations that require significant capital expenditures.
Failure to meet these standards could result in closure of
facilities, increase our operating costs, adversely affect
our results of operations, financial position, and liquidity,
or expose us to fines and liabilities.
We are subject to various environmental laws and
regulations enforced by federal, state, and local authorities.
From the beginning phases of siting and development to the
operation of existing or new electric generating,
transmission and distribution facilities and natural gas
storage, transmission and distribution facilities, our
activities involve compliance with diverse environmental
laws and regulations. These laws and regulations address
emissions, impacts to air, land, and water, noise, protected
natural and cultural resources (such as wetlands,
endangered species, and other protected wildlife, and
archaeological and historical resources), and chemical and
waste handling. Complex and lengthy processes are
required to obtain approvals, permits, or licenses for new,
existing, or modified facilities. Additionally, the use and
handling of various chemicals or hazardous materials
(including wastes) requires release prevention plans and
emergency response procedures.
19
We are also subject to liability under environmental
laws that address the remediation of environmental
contamination of property now or formerly owned by us or
by our predecessors, as well as property contaminated by
hazardous substances that we generated. Such sites include
MGP sites and third-party sites, such as landfills.
Additionally, private individuals may seek to enforce
environmental laws and regulations against us and could
allege injury from exposure to hazardous materials.
In addition to existing laws and regulations, including
the Illinois MPS that applies to our energy centers in
Illinois, the EPA is developing numerous new environmental
regulations that will have a significant impact on the electric
utility industry. These regulations could be particularly
burdensome for certain companies, including Ameren,
Ameren Missouri, and AER, that operate coal-fired energy
centers. These new regulations may be litigated, so the
timing of their ultimate implementation is uncertain, as
evidenced by the stay and remand of the CSAPR.
Ameren is also subject to risks in connection with
changing or conflicting interpretations of existing laws and
regulations. The EPA is engaged in an enforcement initiative
to determine whether coal-fired energy centers failed to
comply with the requirements of the NSR and NSPS
provisions under the Clean Air Act when the energy centers
implemented modifications. Following the issuance of a
Notice of Violation, in January 2011, the Department of
Justice on behalf of the EPA filed a complaint against
Ameren Missouri in the United States District Court for the
Eastern District of Missouri. The EPA’s complaint alleges
that in performing projects at its Rush Island coal-fired
energy center, Ameren Missouri violated provisions of the
Clean Air Act and Missouri law. In January 2012, the United
States District Court granted, in part, Ameren Missouri’s
motion to dismiss various aspects of the EPA’s penalty
claims. The EPA’s claims for injunctive relief, including
requiring the installation of pollution control equipment,
remain. Litigation of this matter could take many years. An
outcome in this matter adverse to Ameren Missouri could
require substantial capital expenditures and the payment of
substantial penalties, neither of which can be determined at
this time. Such expenditures could affect unit retirement
and replacement decisions.
In August 2012, Genco received a Notice of Violation
from the EPA alleging violations of permitting requirements
including Title V of the Clean Air Act. The EPA contends that
projects performed in 1997, 2006, and 2007 at Genco’s
Newton energy center violated federal laws. Ameren and
Genco are unable to predict the outcome of this matter and
whether the EPA will address this Notice of Violation
administratively or through litigation.
Ameren, Ameren Missouri, and AER have incurred and
expect to incur significant costs related to environmental
compliance and site remediation. New environmental
regulations, revised 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, fines, or
closure of facilities for Ameren, Ameren Missouri, and AER.
Actions required to ensure that our facilities and operations
are in compliance with environmental laws and regulations
could be prohibitively expensive. As a result, environmental
regulations could require us to close or to significantly alter
the operation of our energy centers, which could have an
adverse effect on our results of operations, financial
position, and liquidity, including the impairment of plant
assets. Although costs incurred by Ameren Missouri ensure
that its facilities are in compliance with environmental laws
and regulations would be eligible for recovery in rates over
time, subject to MoPSC approval in a rate proceeding, there
is no similar cost recovery mechanism with respect to AER.
We are unable to predict the ultimate impact of these
matters on our results of operations, financial position, and
liquidity.
Future limits on greenhouse gas emissions would
probably require Ameren, Ameren Missouri, and AER to
incur significant increases in capital expenditures and
operating costs, which, if excessive, could result in the
closures of coal-fired energy centers, impairment of
assets, or otherwise adversely affect our results of
operations, financial position, and liquidity.
State and federal authorities, including the United
States Congress, have considered initiatives to limit
greenhouse gas emissions and to address global climate
change. Impacts from any climate change legislation or
regulation could vary, depending upon proposed CO2
emission limits, the timing of implementation of those
limits, the method of distributing any allowances, the
degree to which offsets are allowed and available, and
provisions for cost-containment measures, such as a
“safety valve” provision that provides a maximum price for
emission allowances. As a result of our diverse fuel
portfolio, our emissions of greenhouse gases vary among
our energy centers, but coal-fired energy centers are
significant sources of CO2. The enactment of a climate
change law could result in a significant rise in rates for
electricity, and thereby household costs. The burden could
fall particularly hard on electricity consumers and upon the
economy in the Midwest because of the region’s reliance on
electricity generated by coal-fired energy centers.
Future federal and state legislation or regulations that
mandate limits on the emission of greenhouse gases would
probably result in significant increases in capital
expenditures and operating costs, which, in turn, could lead
to increased liquidity needs and higher financing costs.
Moreover, if Ameren Missouri requests recovery of these
costs through rates, its regulators could deny some or all of
these costs, or defer timely recovery of them. Excessive
costs to comply with future legislation or regulations might
force Ameren, Ameren Missouri, and AER to close some
coal-fired energy centers earlier than planned, which could
lead to possible impairment of assets and reduced revenues.
As a result, mandatory limits could have a material adverse
impact on Ameren’s, Ameren Missouri’s, and AER’s results
of operations, financial position, and liquidity.
20
The construction of, and capital improvements to,
the Ameren Companies’ electric and natural gas utility
infrastructure and AER’s energy centers involve
substantial risks. These risks include escalating costs,
unsatisfactory performance by the projects when
completed, the inability to complete projects as
scheduled, cost disallowances by regulators, and the
inability to earn a reasonable return on invested capital,
any of which could result in higher costs and the closure
of facilities.
The Ameren Companies expect to incur significant
capital expenditures to comply with existing and known
environmental regulations and to make investments in their
electric and natural gas utility infrastructure and in AER’s
energy centers if they are owned by Ameren over the next
five years. Ameren estimates it will incur up to $9.5 billion
(Ameren Missouri – up to $3.8 billion; Ameren Illinois – up
to $3.9 billion; AER – up to $0.4 billion; other – up to
$1.4 billion) of capital expenditures during the period 2013
through 2017. These expenses include construction
expenditures, capitalized interest or allowance for funds
used during construction, and capital expenditures for
compliance with environmental standards and with the
requirements of the IEIMA.
Investments in Ameren’s rate-regulated operations are
expected to be recoverable from ratepayers, but are subject
to prudency reviews and regulatory lag. The recoverability
of amounts expended in Ameren’s Merchant Generation
operations will depend upon market prices for capacity and
energy.
The ability of the Ameren Companies to complete
construction projects successfully, and within projected
estimates, is contingent upon many variables and subject to
substantial risks. These variables include, but are not
limited to, project management expertise and escalating
costs for materials, labor, and environmental compliance.
Delays in obtaining permits, shortages in materials and
qualified labor, suppliers and contractors who do not
perform as required under their contracts, changes in the
scope and timing of projects, the inability to raise capital on
favorable terms, or other events beyond our control that
could occur may materially affect the schedule, cost, and
performance of these projects. With respect to capital
expenditures for pollution control equipment, there is a risk
that energy centers will not be permitted to continue to
operate if pollution control equipment is not installed by
prescribed deadlines or does not perform as expected.
Should any such pollution control equipment not be
installed on time or perform as expected, the Ameren
Companies could be subject to additional costs and to the
loss of their investment in the project or facility. All of these
risks may adversely affect the Ameren Companies’ results
of operations, financial position, and liquidity.
As of December 31, 2012, Ameren Missouri had
capitalized $69 million of costs incurred to license
additional nuclear generation at its Callaway energy site. If
efforts are permanently abandoned or management
concludes it is probable the costs incurred will be
disallowed in rates, a charge to earnings would be
recognized in the period in which that determination was
made.
We may not be able to execute our electric
transmission investment plans and realize the expected
return on those investments.
Ameren, through ATXI and Ameren Illinois, is
allocating significant additional capital resources to electric
transmission investments. This allocation of capital
resources is based on FERC’s regulatory framework and a
rate of return on common equity that is currently higher
than allowed by our state commissions. However the FERC
regulatory framework and rate of return is subject to change
and the regulatory framework may not be as favorable, or
the rate of return may be lower, in the future. A significant
number of our planned electric transmission investments
have been approved by MISO as three separate multi-value
projects to be constructed by ATXI. The total investment in
these three projects is expected to be more than $1.3 billion
with the last of these projects expected to be completed in
2019. Any failure by Ameren to complete these three
projects as designed on time and within projected cost
estimates, could adversely affect our results of operations,
financial position, and liquidity. Future investments may be
affected by changes in FERC policy regarding the utilities’
right of first refusal to construct new transmission projects
within their service territory. In the future, Ameren may not
be able to invest in electric transmission to the extent
desired.
Our counterparties may not meet their obligations to
us, and Ameren affiliates may not meet their obligations
to each other.
We are exposed to the risk that counterparties to
various arrangements who owe us money, credit, energy,
coal, or other commodities or services will not be able to
perform their obligations or, with respect to our credit
facilities, will fail to honor their commitments. Should the
counterparties to commodity arrangements fail to perform,
we might be forced to replace or to sell the underlying
commitment at then-current market prices. Should the
lenders under our credit facilities fail to perform, the level of
borrowing capacity under those arrangements would
decrease, unless we were able to find replacement lenders
to assume the nonperforming lender’s commitment. In
such an event, we might incur losses, or our results of
operations, financial position, and liquidity could otherwise
be adversely affected.
Certain of the Ameren Companies have obligations to
other Ameren Companies or other Ameren subsidiaries as a
result of transactions involving energy, coal, other
commodities and services, borrowing from the money
pools, and as a result of hedging transactions. If one
Ameren entity failed to perform under any of these
arrangements, other Ameren entities might incur losses.
Their results of operations, financial position, and liquidity
could be adversely affected, resulting in the nondefaulting
21
Ameren entity being unable to meet its obligations,
including to unrelated third parties. Ameren (parent) may
itself have to fulfill its subsidiary obligations based on
guarantees it has entered into on behalf of its subsidiaries.
See Note 14 – Related Party Transactions under Part II,
Item 8 for information on Ameren (parent) guarantees.
Increasing costs associated with our defined benefit
retirement and postretirement plans, health care plans,
and other employee benefits could adversely affect our
results of operations, financial position, and liquidity.
We offer defined benefit retirement and postretirement
plans that cover substantially all of our employees.
Assumptions related to future costs, returns on
investments, interest rates, and other actuarial matters have
a significant impact on our earnings and funding
requirements. Ameren expects to fund its pension plans at a
level equal to the greater of the pension expense or the
legally required minimum contribution. Considering
Ameren’s assumptions at December 31, 2012, its
investment performance in 2012, and its pension funding
policy, Ameren expects to make annual contributions of
$60 million to $150 million in each of the next five years,
with aggregate estimated contributions of $550 million. We
expect Ameren Missouri’s and Ameren Illinois’ portion of
the future funding requirements to be 50% and 40%,
respectively. These amounts are estimates. They may
change with actual investment performance, changes in
interest rates, changes in our assumptions, changes in
government regulations, and any voluntary contributions.
In addition to the costs of our retirement plans, the
costs of providing health care benefits to our employees and
retirees have increased in recent years. We believe that our
employee benefit costs, including costs of health care plans
for our employees and former employees, will continue to
rise. The increasing costs and funding requirements
associated with our defined benefit retirement plans, health
care plans, and other employee benefits could increase our
financing needs and otherwise materially adversely affect
our results of operations, financial position, and liquidity.
Our electric generation, transmission and
distribution facilities are subject to operational risks that
could adversely affect our results of operations, financial
position, and liquidity.
The Ameren Companies’ financial performance
depends on the successful operation of electric generation,
transmission, and distribution facilities. Operation of electric
generation, transmission, and distribution facilities involves
many risks, including:
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facility shutdowns due to operator error or a failure of
equipment or processes;
longer-than-anticipated maintenance outages;
older generating equipment may require significant
expenditures to keep it operating at peak efficiency;
disruptions in the delivery of fuel or lack of adequate
inventories, including ultra-low-sulfur coal used for
Ameren Missouri’s compliance with environmental
regulations;
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lack of water, through low river levels or other causes,
required for cooling plant operations;
labor disputes;
inability to comply with regulatory or permit
requirements, including those relating to environmental
contamination;
disruptions in the delivery of electricity, including
impacts on us or our customers;
handling and storage of fossil-fuel combustion
byproducts, such as CCR;
unusual or adverse weather conditions, including
severe storms, droughts, floods and tornadoes;
a workplace accident that might result in injury or loss
of life, extensive property damage, or environmental
damage;
cybersecurity risk, including loss of operational control
of our energy centers and our electric and natural gas
transmission and distribution systems and/or loss of
data, such as utility customer data, account
information, and intellectual property through insider or
outsider actions;
catastrophic events such as fires, explosions, pandemic
health events, or other similar occurrences;
limitations on amounts of insurance available to cover
losses that might arise in connection with operating our
electric generation, transmission, and distribution
facilities; and
other unanticipated operations and maintenance
expenses and liabilities.
Our natural gas distribution and storage activities
involve numerous risks that may result in accidents and
other operating risks and costs that could adversely affect
our results of operations, financial position, and liquidity.
Inherent in our natural gas distribution and storage
activities are a variety of hazards and operating risks, such
as leaks, accidental explosions, mechanical problems and
cybersecurity risks, which could cause substantial financial
losses. In addition, these risks could result in serious injury
to employees and nonemployees, loss of human life,
significant damage to property, environmental pollution,
and impairment of our operations, which in turn could lead
to substantial losses for us. In accordance with customary
industry practice, we maintain insurance against some, but
not all, of these risks and losses. The location of
distribution lines and storage facilities near populated areas,
including residential areas, commercial business centers,
industrial sites, and other public gathering places, could
increase the level of damages resulting from these risks.
The occurrence of any of these events not fully covered by
insurance could materially adversely affect our results of
operations, financial position, and liquidity.
We are subject to federal regulatory compliance and
proceedings, which increase our risk of regulatory
penalties and other sanctions.
The Energy Policy Act of 2005 increased FERC’s civil
penalty authority for violation of FERC statutes, rules, and
orders, including FERC Reliability Standards. FERC can
impose penalties of $1 million per violation per day. Under
22
the Energy Policy Act of 2005, the Ameren Companies, as
owners and operators of bulk power transmission systems
and/or electric energy centers, are subject to mandatory
NERC reliability standards, including cybersecurity
standards. Compliance with these mandatory reliability
standards may subject the Ameren Companies to higher
operating costs and may result in increased capital
expenditures. If the Ameren Companies were found not to
be in compliance with these mandatory reliability standards
or other FERC statutes, rules and orders, the Ameren
Companies could incur substantial monetary penalties and
other sanctions, which could adversely affect our results of
operations, financial position, and liquidity. FERC also
conducts audits and reviews of Ameren Missouri’s, Ameren
Illinois’, and ATXI’s accounting records to assess the
accuracy of its formula rate-making process and has the
ability to require retroactive refunds to customers for
previously billed amounts, with interest.
Even though agreements have been reached with the
state of Missouri and the FERC, the breach of the upper
reservoir of Ameren Missouri’s Taum Sauk pumped-
storage hydroelectric energy center could continue to
have a material adverse effect on Ameren’s and Ameren
Missouri’s results of operations, liquidity, and financial
condition.
In December 2005, there was a breach of the upper
reservoir at Ameren Missouri’s Taum Sauk pumped-storage
hydroelectric energy center. This resulted in significant
flooding in the local area, which damaged a state park.
Ameren Missouri has settled with FERC and the state of
Missouri all issues associated with the December 2005
Taum Sauk incident.
Ameren Missouri had liability insurance coverage for
the Taum Sauk incident, subject to certain limits and
deductibles. Currently, Ameren Missouri has filed separate
lawsuits against two different liability insurance providers
claiming that the insurance companies breached their duty
to indemnify Ameren Missouri for the losses experienced
from the incident. Ameren’s and Ameren Missouri’s results
of operations, financial position, and liquidity could be
adversely affected if Ameren Missouri’s remaining liability
insurance claims of $68 million as of December 31, 2012,
are not paid by insurers.
Ameren’s Merchant Generation energy centers must
compete for the sale of energy and capacity, which
exposes that business to price risks.
All of Ameren’s Merchant Generation energy centers
compete for the sale of energy and capacity in the
competitive energy markets.
To the extent that electricity generated by these energy
centers is not under a fixed-price contract to be sold, the
revenues and results of operations of these Merchant
Generation subsidiaries generally depend on the prices that
can be obtained for energy and capacity in Illinois and
adjacent markets by Marketing Company.
Market prices for energy and capacity may fluctuate
substantially over both the short and long term. For
example, market prices for power have decreased over the
past several years. Demand for electricity and fuel can
fluctuate dramatically, creating periods of substantial
undersupply or oversupply. During periods of oversupply,
prices might be depressed. Also, at times legislators or
regulators with jurisdiction over wholesale and retail energy
commodity and transportation rates may impose price
limitations, bidding rules, and other mechanisms to address
volatility and other issues in these markets.
For power products sold in advance, contract prices
are influenced both by market conditions and by contract
terms such as damage provisions, credit support
requirements, and the number of available counterparties
interested in contracting for the desired forward period.
Depending on differences between market factors at the
time of contracting versus current conditions, Marketing
Company’s contract portfolio may have average contract
prices greater than or less than current market prices,
including at the expiration of the contracts, which could
affect Ameren’s results of operations, financial condition
and liquidity.
Any unhedged forecasted generation will be exposed to
market prices at the time of sale. As a result, any new
physical or financial power sales may be at price levels
lower than previously experienced and lower than the value
of existing hedged sales.
Among the factors that could influence such prices (all
of which are beyond our control to a significant degree) are:
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current and future delivered market prices for natural
gas, coal, and related transportation costs;
current and forward prices for the sale of electricity;
current and future prices for emission allowances that
may be required to operate the fossil-fuel-fired electric
energy centers in compliance with environmental laws
and permits;
the extent of additional supplies of electric energy from
current competitors or new market entrants;
the regulatory and market structures developed for
evolving Midwest energy markets, including a capacity
market in MISO;
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 or decline in electricity usage as a result
of population changes, regional economic conditions,
and the implementation of energy-efficiency and
conservation programs;
climate conditions in the Midwest market and major
natural disasters; and
environmental laws and regulations or delays in their
effective dates.
23
There is substantial uncertainty concerning the
manner, timing, and terms of our anticipated exit from
the Merchant Generation business.
In December 2012, Ameren determined that it intends
to, and it is probable that it will, exit its Merchant
Generation business before the end of the previously
estimated useful lives of that business’s long-lived assets.
However, Ameren’s date and method of exit from the
Merchant Generation business are currently uncertain. Exit
strategies may include the sale of all or parts of Ameren’s
Merchant Generation business and the restructuring of all
or a portion of Ameren’s equity position in Genco. Once a
plan of disposal is finalized, Ameren’s implementation of
that plan may result in long-lived asset impairments,
disposal-related losses, contingencies, reduction of existing
deferred tax assets, and other consequences that are
currently unknown to Ameren.
Ameren’s Merchant Generation business is
experiencing a period of declining operating revenues
and higher costs with limited available sources of
external liquidity, and internal sources of liquidity
available only at Ameren’s discretion, which could be
withheld by Ameren. Merchant Generation, including
Genco, may require liquidity support from Ameren, which
could adversely affect Ameren’s results of operations,
financial position, and liquidity.
Based on projections as of December 31, 2012, of its
operating results and cash flows, Genco expects that, by the
end of the first quarter of 2013, its interest coverage ratio
will be less than the minimum ratio required for the
company to borrow additional funds from external, third-
party sources. Genco’s indenture does not restrict
intercompany borrowings from Ameren’s non-state-
regulated subsidiary money pool. However, borrowings
from the money pool are subject to Ameren’s control. If a
Genco intercompany financing need were to arise,
borrowings from the non-state-regulated subsidiary money
pool by Genco would be dependent on consideration by
Ameren of the facts and circumstances existing at that time.
It is probable that during 2013 Genco will seek mid-month
liquidity from Ameren to support the timing of Genco’s cash
flows. Ameren may decide not to provide funding to Genco
should a financing need arise in 2013 or in the future.
Genco also has significant debt maturities beginning in
2018. If Genco is unable to meet its liquidity needs, this
could result in Genco accelerating asset sales, or
restructuring. Genco expects to sell certain of its long-lived
assets, either individually or through its put option with
AERG, but the proceeds realized from any asset sale may
not be adequate to satisfy Genco’s liquidity needs.
Ameren’s December 2012 decision that the Merchant
Generation segment is no longer a core component of its
future strategy could adversely affect Ameren’s results of
operations, financial position, and liquidity. Ameren has
begun planning to reduce, and ultimately to eliminate, the
reliance of the Merchant Generation segment, including
Genco, on Ameren’s financial support and shared service
support. Ameren’s exit date from the Merchant Generation
segment is uncertain. By requiring the Merchant Generation
segment to duplicate support services, Ameren may reduce
the synergies between its business segments. Further,
counterparties may not extend credit to the Merchant
Generation segment, which could limit Merchant Generation
revenue opportunities and may result in a need for
additional liquidity to operate the business. Also, Ameren
has supplied guarantees to support Marketing Company’s
creditworthiness with counterparties. Under these
guarantees, Ameren may have to fulfill Marketing Company
obligations if Marketing Company becomes unable to
satisfy the counterparty obligation with its own liquidity.
Ameren may also be required to supply liquidity and to
contribute capital to AERG should Genco exercise its put
option agreement relating to three natural-gas-fired energy
centers. See Note 14 – Related Party Transactions under
Part II, Item 8, of this report for additional information
about the put option agreement and Ameren parent
guarantees.
Ameren Missouri’s ownership and operation of a
nuclear energy center creates business, financial, and
waste disposal risks.
Ameren Missouri’s ownership of the Callaway energy
center subjects it to the risks of nuclear generation, which
include the following:
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potential harmful effects on the environment and
human health resulting from the operation of nuclear
facilities and the storage, handling, and disposal of
radioactive materials;
the lack of a permanent waste storage site;
limitations on the amounts and types of insurance
commercially available to cover losses that might arise
in connection with the Callaway energy center or other
United States nuclear operations;
uncertainties with respect to contingencies and
retrospective premium assessments relating to claims
at the Callaway energy center or any other United
States nuclear energy center;
public and governmental concerns over the adequacy
of security at nuclear energy centers;
uncertainties with respect to the technological and
financial aspects of decommissioning nuclear energy
centers at the end of their licensed lives (Ameren
Missouri has submitted an application with the NRC to
extend the Callaway energy center’s operating license
from 2024 to 2044);
limited availability of fuel supply; and
costly and extended outages for scheduled or
unscheduled maintenance and refueling.
The NRC has broad authority under federal law to
impose licensing and safety requirements for nuclear
energy centers. In the event of noncompliance, the NRC has
the authority to impose fines or to shut down a unit, or
both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety
requirements promulgated from time to time by the NRC
could necessitate substantial capital expenditures at nuclear
energy centers such as Ameren Missouri’s. In addition, if a
24
serious nuclear incident were to occur, it could have a
material but indeterminable adverse effect on Ameren
Missouri’s results of operations, financial condition, and
liquidity. A major incident at a nuclear energy center
anywhere in the world could cause the NRC to limit or
prohibit the operation or relicensing of any domestic
nuclear unit. An incident at a nuclear energy center
anywhere in the world also could cause the NRC to impose
additional conditions or requirements on the industry,
which could increase costs and result in additional capital
expenditures. For example, the earthquake in 2011 that
affected nuclear energy centers in Japan has resulted in
regulatory changes in the United States, and may result in
future regulatory changes, that may impose additional costs
on all United States nuclear energy centers.
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, power, emission allowances, renewable energy
credits, and transmission congestion. Prices for natural
gas, fuel, power, emission allowances and renewable
energy credits may fluctuate substantially over relatively
short periods of time, and at other times exhibit sustained
increases or decreases, and expose us to commodity price
risk. We use short-term and long-term purchase and sales
contracts in addition to derivatives such as forward
contracts, futures contracts, options, and swaps to manage
these risks. We attempt to manage our risk associated with
these activities through enforcement of established risk
limits and risk management procedures. We cannot ensure
that these strategies will be successful in managing our
pricing risk or that they will not result in net liabilities
because of future volatility in these markets.
Although we routinely enter into contracts to hedge
our exposure to the risks of demand and changes in
commodity prices, we do not hedge the entire exposure of
our operations from commodity price volatility.
Furthermore, our ability to hedge our exposure to
commodity price volatility depends on liquid commodity
markets. To the extent that commodity markets are illiquid,
we may not be able to execute our risk management
strategies, which could result in greater unhedged positions
than we would prefer at a given time. To the extent that
unhedged positions exist, fluctuating commodity prices can
adversely affect our results of operations, financial position,
and liquidity.
Our facilities are considered critical energy
infrastructure and may therefore be targets of acts of
terrorism.
Like other electric and natural gas utilities and other
merchant electric generators, our energy centers, fuel
storage facilities, and transmission and distribution facilities
may be targets of terrorist activities, including cybersecurity
attacks, which 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 adversely affect on our results of operations, financial
position, and liquidity.
Our businesses are dependent on our ability to
access the capital markets successfully. We may not
have access to sufficient capital in the amounts and at
the times needed.
We use short-term and long-term debt as a significant
source of liquidity and funding for capital requirements not
satisfied by our operating cash flow, including requirements
related to future environmental compliance and capital
expenditures required by the IEIMA. As a result of rising
costs and increased capital and operations and maintenance
expenditures, coupled with regulatory lag, we expect to
continue to rely on short-term and long-term debt
financing. The inability to raise debt or equity capital on
favorable terms, or at all, could negatively affect our ability
to maintain and to expand our businesses. After assessing
our current operating performance, liquidity, and credit
ratings, we believe that Ameren and its rate-regulated
businesses will continue to have access to the capital
markets. However, events beyond our control, such as a
recession or extreme volatility in global debt or equity
capital and credit markets, may create uncertainty that
could increase our cost of capital or impair or eliminate our
ability to access the debt, equity, or credit markets,
including our ability to draw on bank credit facilities. Based
on projections as of December 31, 2012, of its operating
results and cash flows, Genco expects that, by the end of
the first quarter of 2013, its interest coverage ratio will be
less than the minimum ratio required for the company to
borrow additional funds from external, third-party sources.
An inability to raise debt could adversely impact Genco’s
liquidity. Any adverse change in Ameren’s or in its
subsidiaries’ 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 natural gas supply, among other things, which
could have a material adverse effect on our results of
operations, financial position, and liquidity. Certain of the
Ameren’s subsidiaries 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 subsidiaries with
needed capital. In addition, borrowings directly from
Ameren and from the utility and non-state-regulated
subsidiary money pools are subject to Ameren’s control and
any borrowings are dependent on consideration by Ameren
of the facts and circumstances existing at the time of the
borrowing request.
Ameren’s holding company structure could limit its
ability to pay common stock dividends and to service its
debt obligations.
Ameren is a holding company; therefore, its primary
assets are the common stock of its subsidiaries. As a result,
Ameren’s ability to pay dividends on its common stock
25
depends on the earnings of its subsidiaries and the ability of
its subsidiaries to pay dividends or otherwise transfer funds
to Ameren. Similarly, Ameren’s ability to service its debt
obligations is also dependent upon the earnings of
operating subsidiaries and the distribution of those earnings
and other payments, including payments of principal and
interest under intercompany indebtedness. The payment of
dividends to Ameren by its subsidiaries in turn depends on
their results of operations and cash flows and other items
affecting retained earnings. Ameren’s subsidiaries are
separate and distinct legal entities and have no obligation,
contingent or otherwise, to pay any dividends or make any
other distributions (except for payments required pursuant
to the terms of intercompany borrowing arrangements and
cash payments and receipts under the tax allocation
agreement) to Ameren. Certain of the Ameren Companies’
financing agreements and articles of incorporation, in
addition to certain statutory and regulatory requirements,
ITEM 2.
PROPERTIES
may impose restrictions on the ability of such Ameren
Companies to transfer funds to Ameren in the form of cash
dividends, loans or advances.
Failure to retain and attract key officers and other
skilled professional and technical employees could
adversely affect on our operations.
Our businesses depend upon our ability to employ and
retain key officers and other skilled professional and
technical employees. A significant portion of our workforce
is nearing retirement, including many employees with
specialized skills such as maintaining and servicing our
electric and natural gas infrastructure and operating our
energy centers.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
For information on our principal properties, see the energy center 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 a discussion of planned additions, replacements or transfers. See also Note 5 – Long-term
Debt and Equity Financings, and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report.
The following table shows what the capability of our energy centers is anticipated to be at the time of our expected 2013
peak summer electrical demand:
Primary Fuel Source
Energy Center
Location
Net Kilowatt Capability(a)
Ameren Missouri:
Coal
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Total coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Labadie
Rush Island
Sioux
Meramec
Callaway
Osage
Keokuk
Total hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pumped-storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taum Sauk
Oil (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total oil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Meramec
Fairgrounds
Mexico
Moberly
Moreau
Howard Bend
Audrain(b)
Venice(c)
Goose Creek
Pinckneyville
Raccoon Creek
Kinmundy(c)
Peno Creek(b)(c)
Meramec(c)
Kirksville
Franklin County, Mo.
Jefferson County, Mo.
St. Charles County, Mo.
St. Louis County, Mo.
Callaway County, Mo.
Lakeside, Mo.
Keokuk, Ia.
Reynolds County, Mo.
St. Louis County, Mo.
Jefferson City, Mo.
Mexico, Mo.
Moberly, Mo.
Jefferson City, Mo.
St. Louis County, Mo.
Audrain County, Mo.
Venice, Ill.
Piatt County, Ill.
Pinckneyville, Ill.
Clay County, Ill.
Kinmundy, Ill.
Bowling Green, Mo.
St. Louis County, Mo.
Kirksville, Mo.
Total natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Methane gas (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maryland Heights
Maryland Heights, Mo.
Total Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . .
2,374,000
1,182,000
972,000
833,000
5,361,000
1,194,000
240,000
140,000
380,000
440,000
54,000
54,000
53,000
53,000
53,000
39,000
306,000
592,000
487,000
426,000
312,000
296,000
206,000
188,000
48,000
12,000
2,567,000
8,000
10,256,000
26
Primary Fuel Source
Energy Center
Location
Net Kilowatt Capability(a)
Merchant Generation:
Genco:
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AERG:
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total AERG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Merchant Generation . . . . . . . . . . . . . . . . . . . . . .
Total Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Newton
Joppa (EEI)(d)
Coffeen
Grand Tower
Elgin
Gibson City(c)
Joppa 7B
Joppa (EEI)(d)
Newton, Ill.
Joppa, Ill.
Coffeen, Ill.
Grand Tower, Ill.
Elgin, Ill.
Gibson City, Ill.
Joppa, Ill.
Joppa, Ill.
E.D. Edwards
Duck Creek
Bartonville, Ill.
Canton, Ill.
1,215,000
1,002,000
895,000
3,112,000
478,000
460,000
228,000
110,000
74,000
1,350,000
4,462,000
650,000
410,000
1,060,000
5,522,000
15,778,000
(a) Net kilowatt capability is the generating capacity available for dispatch from the energy center into the electric transmission grid.
(b) There are economic development lease arrangements applicable to these CTs.
(c) These CTs have the capability to operate on either oil or natural gas (dual fuel).
(d) Genco owns an 80% interest in EEI. This table reflects the full capability of EEI’s facilities.
The following table presents electric and natural gas
utility-related properties for Ameren Missouri and Ameren
Illinois as of December 31, 2012:
Circuit miles of electric transmission lines(a) . . .
Circuit miles of electric distribution lines . . . . . .
Circuit miles of electric distribution lines
Ameren
Missouri
Ameren
Illinois
2,956
32,967
4,506
45,746
‰
underground . . . . . . . . . . . . . . . . . . . . . . . . .
23%
15%
Miles of natural gas transmission and
distribution mains . . . . . . . . . . . . . . . . . . . . .
Propane-air plants . . . . . . . . . . . . . . . . . . . . . . .
Underground gas storage fields . . . . . . . . . . . . .
Billion cubic feet of total working capacity of
3,282
1
-
18,137
-
12
underground gas storage fields . . . . . . . . . . .
-
24
(a) ATXI and EEI own 29 miles and 42 miles of transmission lines,
respectively, not reflected in this table.
Our other properties include office buildings,
warehouses, garages, and repair shops.
With only a few exceptions, we have fee title to all
principal energy centers and other units of property material
to the operation of our businesses, and to the real property
on which such facilities are located (subject to mortgage
liens securing our outstanding first mortgage bonds and to
certain permitted liens and judgment liens). The exceptions
are as follows:
‰
A portion of Ameren Missouri’s Osage energy center
reservoir, certain facilities at Ameren Missouri’s Sioux
energy center, most of Ameren Missouri’s Peno Creek
and Audrain CT energy centers, certain substations,
and most transmission and distribution lines and
natural gas mains are situated on lands occupied under
leases, easements, franchises, licenses, or permits. The
United States or the state of Missouri may own or may
27
have paramount rights to certain lands lying in the bed
of the Osage River or located between the inner and
outer harbor lines of the Mississippi River on which
certain of Ameren Missouri’s energy centers 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
Ameren Missouri’s Keokuk energy center is located.
Substantially all of the properties and plant of Ameren
Missouri and Ameren Illinois are subject to the first liens of
the indentures securing their mortgage bonds.
Ameren Missouri has conveyed most of its Peno Creek
CT energy center to the city of Bowling Green, Missouri,
and leased the energy center back from the city through
2022. Under the terms of this capital lease, Ameren
Missouri is responsible for all operation and maintenance
for the energy center. Ownership of the energy center will
transfer to Ameren Missouri at the expiration of the lease, at
which time the property and plant will become subject to
the lien of any outstanding Ameren Missouri first mortgage
bond indenture.
Ameren Missouri operates a CT energy center located
in Audrain County, Missouri. Ameren Missouri has rights
and obligations as lessee of the CT energy center under a
long-term lease with Audrain County. The lease will expire
on December 1, 2023. Under the terms of this capital lease,
Ameren Missouri is responsible for all operation and
maintenance for the energy center. Ownership of the energy
center will transfer to Ameren Missouri at the expiration of
the lease, at which time the property and plant will become
subject to the lien of any outstanding Ameren Missouri first
mortgage bond indenture.
ITEM 3.
LEGAL PROCEEDINGS
We are involved in legal and administrative
proceedings before various courts and agencies with
respect to matters that arise in the ordinary course of
business, some of which involve substantial amounts of
money. We believe that the final disposition of these
proceedings, except as otherwise disclosed in this report,
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.
Material legal and administrative proceedings, which are
discussed in Note 2 – Rate and Regulatory Matters and
Note 15 – Commitment and Contingencies under Part II,
Item 8, of this report and incorporated herein by reference,
include the following:
‰
‰
‰
‰
‰
appeal of the MoPSC’s April 2011 FAC prudence review
order and completion of the current FAC prudence
review;
Ameren Missouri’s appeal of the MoPSC’s December
2012 electric rate order;
Ameren Illinois’ appeal of the ICC’s 2012 electric
distribution rate orders in its initial and update IEIMA
filings;
natural gas rate proceeding for Ameren Illinois pending
before the ICC;
FERC litigation to determine wholesale distribution
revenues for five of Ameren Illinois’ wholesale
customers;
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
‰
‰
‰
‰
‰
‰
‰
‰
‰
Entergy’s rehearing request of a FERC May 2012 order
requiring Entergy to refund to Ameren Missouri
additional charges Ameren Missouri paid under an
expired power purchase agreement;
Ameren Illinois’ request for rehearing of a FERC July
2012 order regarding the inclusion of acquisition
premiums in Ameren Illinois’ transmission rates;
ATXI’s request for a certificate of public convenience
and necessity and project approval from the ICC for the
Illinois Rivers project;
the EPA’s Clean Air Act-related litigation filed against
Ameren Missouri, NSR investigations at Genco and
AERG, and the Notice of Violation for alleged permitting
violations at Genco;
remediation matters associated with former MGP and
waste disposal sites of the Ameren Companies;
litigation associated with the breach of the upper
reservoir at Ameren Missouri’s Taum Sauk pumped-
storage hydroelectric energy center;
litigation alleging that the CO2 emissions from several
industrial companies, including Ameren Missouri,
Genco, and AERG, created atmospheric conditions that
intensified Hurricane Katrina;
Ameren Illinois’ receipt of tax liability notices relating to
prior-period electric and natural gas municipal taxes;
asbestos-related litigation associated with Ameren,
Ameren Missouri, and Ameren Illinois; and
‰ Merchant Generation’s challenge before the Informal
Conference Board of the Illinois Department of Revenue
regarding the State’s position that EEI did not qualify
for manufacturing tax exemptions for 2010
transactions.
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, 2012, all positions and offices held with the Ameren Companies as of December 31, 2012 (except as
otherwise noted below), tenure as officer, and business background for at least the last five years. Some executive officers
hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.
AMEREN CORPORATION:
Age Positions and Offices Held
65
Name
Thomas R. Voss
Voss joined Ameren Missouri in 1969. He was elected senior vice president of Ameren Missouri, CIPS, and Ameren Services in
1999, of CILCO in 2003, and of IP in 2004. In 2003, Voss was elected president of Genco; he relinquished his presidency of
this company in 2004. In 2006, he was elected executive vice president of Ameren Missouri, CIPS, CILCO and IP. In 2007,
Voss was elected chairman, president and chief executive officer of Ameren Missouri, and relinquished his positions at CIPS,
CILCO and IP in 2007. In 2009, Voss was elected president and chief executive officer of Ameren; at that time, he relinquished
his other positions. In 2010, the Ameren board of directors elected Voss to the additional position of chairman of the board.
He has been a member of the Ameren board since 2009.
Chairman, President and Chief Executive Officer, and Director
28
Name
Martin J. Lyons, Jr.
Age Positions and Offices Held
46
Executive Vice President (Effective January 1, 2013) and Chief
Financial Officer
Lyons joined Ameren, Ameren Missouri, CIPS, and Ameren Services in 2001 as controller. He was elected controller of CILCO
in 2003. He was also elected vice president of Ameren, Ameren Missouri, CIPS, CILCO, and Ameren Services in 2003 and vice
president and controller of IP in 2004. In 2007, his positions at Ameren Missouri were changed to vice president and principal
accounting officer. In 2008, Lyons was elected senior vice president and principal accounting officer of the Ameren
companies. In 2009, Lyons was also elected chief financial officer of the Ameren companies. Following the Ameren Illinois
Merger in 2010, Lyons remained senior vice president, chief financial officer and principal accounting officer of Ameren
Illinois. Effective January 1, 2013, Lyons was elected executive vice president and chief financial officer of the Ameren
companies, and relinquished his duties as principal accounting officer.
55
Gregory L. Nelson
Nelson joined Ameren Missouri in 1995 as a manager in the tax department and assumed a similar position with Ameren
Services in 1998. Nelson was elected vice president and tax counsel of Ameren Services in 1999 and vice president of Ameren
Missouri, CIPS, and CILCO in 2003 and of IP in 2004. In 2010, Nelson was elected vice president, tax and deputy general
counsel of Ameren Services. He remained vice president of Ameren Missouri, CIPS, CILCO, and IP. Following the Ameren
Illinois Merger in 2010, Nelson remained vice president at Ameren Illinois. In 2011, Nelson was elected to the positions of
senior vice president, general counsel and secretary of the Ameren companies.
Senior Vice President, General Counsel and Secretary
Bruce A. Steinke
51
Senior Vice President, Finance and Chief Accounting Officer (Effective
January 1, 2013)
Steinke joined Ameren Services in 2002 as a manager in the controller’s department and head of investor relations. In 2008, he
was elected vice president and controller of Ameren, CIPS, CILCO, IP and Ameren Services. In 2009, Steinke relinquished his
positions at CIPS, CILCO and IP. Effective January 1, 2013, Steinke was elected senior vice president, finance and chief
accounting officer of the Ameren companies.
Jerre E. Birdsong
Birdsong joined Ameren Missouri in 1977 and was elected treasurer of Ameren Missouri in 1993. He was elected treasurer of
Ameren, CIPS and Ameren Services in 1997. In addition to being treasurer, in 2001, Birdsong was elected vice president at
Ameren, Ameren Missouri, CIPS, and Ameren Services. Additionally, he was elected vice president and treasurer of CILCO in
2003 and of IP in 2004. Following the Ameren Illinois Merger in 2010, Birdsong, remained vice president and treasurer at
Ameren Illinois. Effective February 1, 2013, Birdsong retired from the Ameren companies.
Vice President and Treasurer
58
SUBSIDIARIES:
Age Positions and Offices Held
51
Name
Warner L. Baxter
Baxter joined Ameren Missouri in 1995 as assistant controller. He was elected senior vice president, finance, of Ameren,
Ameren Missouri, CIPS, and Ameren Services in 2001 and of CILCO in 2003. Baxter was elected to the positions of executive
vice president and chief financial officer of Ameren, Ameren Missouri, CIPS, CILCO and Ameren Services in 2003 and of IP in
2004. He was elected chairman, president, chief executive officer and chief financial officer of Ameren Services in 2007. In
2009, Baxter was elected chairman, president and chief executive officer of Ameren Missouri; at that time, he relinquished his
other positions.
Chairman, President and Chief Executive Officer (Ameren Missouri)
Maureen A. Borkowski
Borkowski joined Ameren Missouri in 1981. She left the company in 2000 before rejoining Ameren in 2005 as vice president,
transmission, of Ameren Services. In 2011, Borkowski was elected chairman, president and chief executive officer of ATXI. In
2011, she was also elected senior vice president, transmission, of Ameren Services.
Chairman, President and Chief Executive Officer (ATXI)
55
Daniel F. Cole
Cole joined Ameren Missouri in 1976. He was elected senior vice president of Ameren Missouri and Ameren Services in 1999
and of CIPS in 2001. He was elected senior vice president of CILCO in 2003 and of IP in 2004. In 2009, Cole was elected
chairman, president and chief executive officer of Ameren Services and remained senior vice president of Ameren Missouri,
CIPS, CILCO and IP. Following the Ameren Illinois Merger in 2010, Cole remained senior vice president at Ameren Illinois.
Chairman, President and Chief Executive Officer (Ameren Services)
59
Adam C. Heflin
Heflin joined Ameren Missouri in 2005 as vice president of nuclear operations and was elected senior vice president and chief
nuclear officer of Ameren Missouri in 2008.
Senior Vice President and Chief Nuclear Officer (Ameren Missouri)
48
29
Name
Richard J. Mark
Mark joined Ameren Services in 2002 as vice president of customer service. In 2003, he was elected vice president of
governmental policy and consumer affairs at Ameren Services. He was elected senior vice president, customer operations of
Ameren Missouri in 2005. In 2007, Mark relinquished his position at Ameren Services. Effective June 13, 2012, Mark
relinquished his position at Ameren Missouri and was elected chairman, president and chief executive officer of Ameren
Illinois.
Age Positions and Offices Held
57
Chairman, President and Chief Executive Officer (Ameren Illinois)
Michael L. Moehn
Senior Vice President, Customer Operations (Ameren Missouri)
Moehn joined Ameren Services in 2000 as assistant controller. In 2004, Moehn was elected vice president of corporate
planning of Ameren Services. In 2008, he was elected senior vice president, corporate planning and business risk management
of Ameren Services. Effective January 1, 2012, Moehn relinquished his position at Ameren Services and was elected senior
vice president of customer operations of Ameren Illinois. Effective June 13, 2012, Moehn relinquished his position at Ameren
Illinois and was elected senior vice president, customer operations of Ameren Missouri.
43
60
Charles D. Naslund
Executive Vice President (Ameren Services) (Effective March 1, 2013)
Naslund joined Ameren Missouri in 1974. He was elected vice president of power operations at Ameren Missouri in 1999, vice
president of Ameren Services in 2000 and vice president of nuclear operations at Ameren Missouri in 2004. He relinquished
his position at Ameren Services in 2001. Naslund was elected senior vice president and chief nuclear officer at Ameren
Missouri in 2005. In 2008, he was elected chairman, president and chief executive officer of AER. Naslund relinquished his
positions at Ameren Missouri in 2008. In 2011, Naslund assumed the position of senior vice president, generation and
environmental projects of Ameren Missouri and relinquished his positions of chairman, president and chief executive officer of
AER. On January 1, 2013, Naslund relinquished his position at Ameren Missouri and was elected senior vice president of
Ameren Services. On March 1, 2013, Naslund was elected executive vice president of Ameren Services.
52
Chairman, President and Chief Executive Officer (AER)
Steven R. Sullivan
After previous service as an Ameren Missouri staff attorney, Sullivan rejoined Ameren, Ameren Missouri, CIPS and Ameren
Services in 1998 as vice president and general counsel and later in 1998 was elected secretary. In 2003, Sullivan was elected
vice president, general counsel and secretary of CILCO. He was elected senior vice president, general counsel and secretary of
Ameren, Ameren Missouri, CIPS, CILCO and Ameren Services in 2003 and of IP in 2004. Following the Ameren Illinois Merger
in 2010, Sullivan remained senior vice president, general counsel and secretary at Ameren Illinois. In 2011, Sullivan was
elected to the positions of chairman, president and chief executive officer of AER and relinquished his positions of senior vice
president, general counsel and secretary of the Ameren companies.
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.
30
PART II
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE
OF EQUITY SECURITIES
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled
60,810 on January 31, 2013. The following table presents the price ranges, closing prices, and dividends declared per Ameren
common share for each quarter during 2012 and 2011.
High
Low
Close
Dividends Declared
2012 Quarter Ended:
March 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 Quarter Ended:
March 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
33.68
34.04
35.30
33.21
29.14
30.14
31.44
34.11
$
$
30.89
31.15
32.27
28.43
26.46
27.78
25.55
27.98
$
$
32.58
33.54
32.67
30.72
28.07
28.84
29.77
33.13
$
$
0.400
0.400
0.400
0.400
0.385
0.385
0.385
0.400
There is no trading market for the common stock of Ameren Missouri and Ameren Illinois. Ameren holds all outstanding
common stock of Ameren Missouri and Ameren Illinois.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries
during 2012 and 2011:
(In millions)
Registrant
2012
Quarter Ended
2011
Quarter Ended
December 31
September 30
June 30 March 31
December 31
September 30
June 30 March 31
Ameren Missouri
. . . . . . . . .
Ameren Illinois . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . .
$
100
57
98
$
100
57
97
$
$
100
38
97
100
37
90
$
184
89
96
$
84
88
93
$
67
88
93
$
68
62
93
On February 8, 2013, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 40
cents per share. The common share dividend is payable March 29, 2013, to shareholders of record on March 13, 2013.
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.
Purchases of Equity Securities
The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of
Regulation S-K:
Period
(a) Total Number
of Shares (or Units)
Purchased(a)
(b) Average Price
Paid per Share
(or Unit)
(c) Total Number of Shares
(or Units) Purchased As
Part of Publicly
Announced
Plans or Programs
(d) Maximum Number
(or Approximate Dollar Value)
of Shares (or Units) That
May Yet Be Purchased
Under the
Plans or Programs
October 1 – October 31, 2012 . . . . . .
November 1 – November 30, 2012 . .
December 1 – December 31, 2012 . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . .
-
300
3,213
3,513
$
-
29.32
29.52
$
29.50
-
-
-
-
-
-
-
-
(a) Comprised of shares of Ameren common stock purchased in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive
Compensation Plan in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance units. Ameren does not
have any publicly announced equity securities repurchase plans or programs.
Ameren Missouri and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K
during the period from October 1, 2012 to December 31, 2012.
31
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five years ended December 31, 2012.
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, 2007, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends
were reinvested.
$125
$100
$75
$50
2007
2008
2009
2010
2011
2012
Ameren
S&P 500 Index
EEI Index
December 31,
2007
2008
2009
2010
2011
2012
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S&P 500 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EEI Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
100.00
100.00
100.00
$
65.41
63.00
74.10
$
58.40
79.67
82.04
$
62.41
91.67
87.81
$ 77.23
93.60
105.36
$ 75.28
108.58
107.57
Ameren management cautions that the stock price performance shown in the graph above should not be considered
indicative of potential future stock price performance.
32
ITEM 6. SELECTED FINANCIAL DATA
For the years ended December 31,
(In millions, except per share amounts)
Ameren(a):
2012
2011
2010
2009
2008
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss)(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Ameren Corporation . . . . . . . . . . . . . . . .
Common stock dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Earnings (loss) per share – basic and diluted . . . . . . . . . . . . . . . . . . . . . .
Common stock dividends per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . . . . . . .
Total Ameren Corporation stockholders’ equity . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income available to common stockholder . . . . . . . . . . . . . . . . . . . . . .
Dividends to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income available to common stockholder . . . . . . . . . . . . . . . . . . . . . .
Dividends to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets(d)
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
$
$
$
$
$
6,828
(1,240)
(974)
382
(4.01)
1.60
21,835
6,626
6,616
3,272
845
416
400
13,043
3,801
4,054
2,525
377
144
141
189
7,282
1,577
2,401
7,531
1,241
519
375
2.15
1.555
23,645
6,677
7,919
3,383
609
287
403
12,757
3,772
4,037
2,787
458
196
193
327
7,213
1,657
2,452
$
$
$
$
$
$
7,638
916
139
368
0.58
1.54
23,511
6,853
7,730
3,197
711
364
235
12,504
3,949
4,153
3,014
498
212
248
133
7,406
1,657
2,576
$
$
$
$
$
$
7,135
1,416
612
338
2.78
1.54
23,702
7,111
7,856
2,874
566
259
175
$
$
$
7,869
1,362
605
534
2.88
2.54
22,671
6,554
6,963
2,960
514
245
264
12,219
4,018
4,057
$ 11,529
3,673
3,562
$
$
2,984
363
133
241
98
8,298
1,847
3,072
3,508
191
41
87
60
8,023
1,850
2,655
(a)
(b)
(c)
(d)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes “Impairment and other charges” of $2,578 million, $125 million and $ 589 million recorded at Ameren during the years ended
December 31, 2012, 2011, and 2010, respectively.
Includes “Loss from regulatory disallowance” of $89 million recorded during the year ended December 31, 2011.
Includes total assets from discontinued operations of $1,117 million and $ 1,081 million at December 31, 2009 and 2008, respectively.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Ameren Executive Summary
Operations
In December 2012, Ameren determined that it intends
to, and it is probable that it will, exit its Merchant
Generation business before the end of the previously
estimated useful lives of that business segment’s long-lived
assets. This determination resulted from Ameren’s analysis
of the current and projected future financial condition of its
Merchant Generation business, including the need to fund
Genco debt maturities beginning in 2018, and its
conclusion that this business was no longer a core
component of its future business strategy. The volatility of
earnings and cash flows of the Merchant Generation
business, as well as the high degree of uncertainty
regarding future returns on incremental capital invested in
this business, are not in alignment with Ameren’s current
strategy. Ameren’s decision to exit the business follows a
trend of decreasing earnings and cash flows from the
Merchant Generation business since 2008. Ameren’s date
and method of exit from the Merchant Generation business
is currently uncertain with a sale or restructuring possible.
Senior management and Ameren’s board of directors are
focused on maximizing the overall benefit to Ameren
consistent with its legal obligations.
While working to exit the Merchant Generation
business, Ameren remains focused on its rate-regulated
utilities, including growing investments in jurisdictions with
constructive regulatory frameworks. Ameren continues to
seek modern, constructive regulatory frameworks, which
provide timely cash flows and a reasonable opportunity to
earn fair returns on investments that are in the best long-
term interest of Ameren’s customers. These frameworks
support Ameren’s rate-regulated businesses’ ability to
obtain cash on a timelier basis, to reinvest in energy
infrastructure and also attract capital on terms that facilitate
timely investments to modernize their aging infrastructure.
33
In December 2012, the MoPSC issued an order
approving an increase for Ameren Missouri in annual
revenues for electric service of $260 million. These new
rates became effective on January 2, 2013. The MoPSC’s
December 2012 electric rate order improved Ameren
Missouri’s regulatory framework for energy efficiency
programs as well as authorized the implementation of a
new storm restoration cost tracking mechanism.
In 2012, Ameren Illinois elected to participate in the
IEIMA’s performance-based formula ratemaking framework.
The IEIMA was designed to promote investment in electric
grid modernization and create jobs through the
establishment of formula ratemaking for electric delivery
service. Ameren Illinois believes the ICC has incorrectly
implemented the IEIMA in both of its 2012 electric delivery
service rate orders. As a result, Ameren Illinois has
appealed both 2012 electric delivery service rate orders to
the Appellate Court of the Fourth District of Illinois and is
also seeking a legislative solution to address the ICC’s
implementation of the IEIMA. Additionally, in January 2013,
Ameren Illinois filed a request with the ICC to increase its
annual revenues for natural gas delivery service by
$50 million. This request was based on a 2014 future test
year.
Ameren continues to proceed with its plans to increase
its investment in FERC-regulated electric transmission. In
2013, for both Ameren Illinois and ATXI, transmission rates
will be updated annually based on a forward-looking
calculation with a revenue requirement reconciliation.
Ameren expects to invest a total of approximately
$2.2 billion in FERC-regulated transmission projects over
the next five years. The Ameren Illinois portion of that total,
approximately $1 billion, is for projects focused on local
load growth and reliability needs. ATXI, through its
construction of three MISO-approved regional multi-value
electric transmission projects, expects to invest
approximately $1.2 billion over the next five years. In
November 2012, ATXI filed a request with the ICC for a
certificate of public convenience and necessity for the
Illinois Rivers project. Once ATXI receives the certificate of
public convenience and necessity, it can begin to acquire
right of way for the Illinois Rivers project. A full range of
construction activities for the Illinois Rivers project is
expected to begin in 2014.
Earnings
Ameren reported a net loss of $974 million, or $4.01
per share, for 2012 compared with net income of
$519 million, or $2.15 per share, in 2011. The main factor
contributing to the net loss in 2012, compared with net
income in 2011, was the 2012 impairments of Merchant
Generation’s long-lived assets resulting from Ameren’s
determination in December 2012 that it intends to, and it is
probable that it will, exit its Merchant Generation business
before the end of the previously useful lives of that business
segment’s long-lived assets, coupled with the sharp decline
in the market price for power in the first quarter of 2012.
The decline in Merchant Generation earnings also reflected
lower power prices and higher fuel costs. Ameren’s
earnings also decreased in 2012, compared with 2011,
because of a decline in Ameren Illinois’ earnings primarily
due to the impacts of implementing the IEIMA’s formula
ratemaking in 2012, including a lower allowed return on
equity and required nonrecoverable contributions, as well
as lower natural gas sales volumes as a result of warmer
2012 winter temperatures. Summer weather was much
warmer than normal in 2012, but similar to 2011. The
earnings declines in the Merchant Generation and Ameren
Illinois segments were partially offset by increased Ameren
Missouri earnings due primarily to the full year effect of the
2011 electric rate increase as well as lower operations and
maintenance expense reflecting the absence of a refueling
outage at the Callaway energy center in 2012, decreased
labor costs primarily due to staff reductions resulting from
the 2011 voluntary separation plan, and reduced major
storm-related costs. Ameren Missouri’s 2012 earnings,
compared to 2011 earnings, also benefited from a favorable
2012 FERC order related to a disputed power purchase
agreement that expired in 2009 and the absence of a 2011
charge to earnings related to the FAC. These positive
Ameren Missouri factors were partially offset by higher
depreciation expense and lower electric sales volumes due
to warmer 2012 winter temperatures.
Liquidity
Cash flows from operations of $1.7 billion were used
to pay dividends to common stockholders of $382 million
and to fund capital expenditures of $1.2 billion. At
December 31, 2012, Ameren, on a consolidated basis, had
available liquidity, in the form of cash on hand and amounts
available under existing credit agreements, of approximately
$2.3 billion, which was a $100 million increase from the
amount of available liquidity at December 31, 2011.
Capital Spending
From 2013 through 2017, Ameren’s cumulative capital
spending is projected to range between $7.4 billion and
$9.5 billion. Much of this spending is at Ameren’s rate-
regulated utilities, including a total of approximately
$1.2 billion at ATXI to invest in its electric transmission
assets as discussed above. The Merchant Generation
segment’s capital spending is expected to be up to
$385 million from 2013 through 2017, assuming Ameren
continues to own the Merchant Generation energy centers
for the entire period.
General
Ameren, headquartered in St. Louis, Missouri, is a
public utility holding company under PUHCA 2005,
administered by FERC. Ameren’s primary assets are its
equity interests in its subsidiaries. Ameren’s subsidiaries
are separate, independent legal entities with separate
businesses, assets, and liabilities. These subsidiaries
operate, as the case may be, rate-regulated electric
generation, transmission, and distribution businesses, rate-
regulated natural gas transmission and distribution
businesses, and merchant electric generation businesses.
34
Dividends on Ameren’s common stock and the payment of
other expenses by Ameren depend on distributions made to
it by its subsidiaries. Ameren’s principal subsidiaries are
listed below. See Note 1 – Summary of Significant
Accounting Policies under Part II, Item 8, of this report for a
detailed description of our principal subsidiaries.
‰
‰
‰
Ameren Missouri operates a rate-regulated electric
generation, transmission, and distribution business,
and a rate-regulated natural gas transmission and
distribution business in Missouri.
Ameren Illinois operates a rate-regulated electric and
natural gas transmission and distribution business in
Illinois.
AER consists of non-rate-regulated operations,
including Genco, AERG, Marketing Company, and
through Genco, an 80% ownership interest in EEI,
which Ameren consolidates for financial reporting
purposes.
In December 2012, Ameren determined that it intends
to, and it is probable that it will, exit its Merchant
Generation business before the end of the previously
estimated useful lives of that business’s long-lived assets.
This determination resulted from Ameren’s analysis of the
current and projected future financial condition of its
Merchant Generation business segment, including the need
to fund Genco debt maturities beginning in 2018, and its
conclusion that this business segment is no longer a core
component of its future business strategy. In consideration
of this determination, Ameren has begun planning to
reduce, and ultimately eliminate, the Merchant Generation
business segment’s, including Genco’s, reliance on
Ameren’s financial support and shared services support.
Furthermore, Ameren recorded a noncash long-lived asset
impairment charge to reduce the carrying values of the
Merchant Generation energy centers, except for the Joppa
coal-fired energy center, to their estimated fair values. See
Note 17 – Impairment and Other Charges under Part II,
Item 8, for additional information. Ameren’s date and
method of exit from the Merchant Generation business is
currently uncertain. Exit strategies may include the sale of
all or parts of the Merchant Generation business and the
restructuring of all or a portion of Ameren’s equity position
in Genco. Ameren’s Merchant Generation long-lived assets
have not been classified as held-for-sale under authoritative
accounting guidance as all criteria to qualify for that
presentation were not met as of December 31, 2012.
Specifically, Ameren did not consider it probable that a
disposition would occur within one year.
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG
and AER completed a two-step corporate internal
reorganization. The first step of the reorganization was the
Ameren Illinois Merger. The second step of the
reorganization involved the distribution of AERG stock from
Ameren Illinois to Ameren and the subsequent contribution
by Ameren of the AERG stock to AER. Ameren Illinois
segregated AERG’s operating results and cash flows and
presented them separately as discontinued operations in its
consolidated statement of income and consolidated
statement of cash flows, respectively, for all periods
presented prior to October 1, 2010, in this report. See
Note 16 – 2010 Corporate Reorganization under Part II,
Item 8, for additional information.
The financial statements of Ameren and Ameren Illinois
are prepared on a consolidated basis and therefore include
the accounts of their respective majority-owned
subsidiaries. Ameren Illinois’ financial statements are
consolidated because Ameren Illinois included AERG in its
statements of income and cash flows during 2010. Ameren
Missouri has no subsidiaries, and therefore its financial
statements are not prepared on a consolidated basis. All
significant intercompany transactions have been eliminated.
All tabular dollar amounts are 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 that 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.
RESULTS OF OPERATIONS
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 prices we
charge for our services. Merchant Generation sales are also
subject to market conditions for power. We principally use
coal, nuclear fuel, natural gas, methane gas, and oil for fuel
in our operations. The prices for these commodities can
fluctuate significantly because of the global economic and
political environment, weather, supply and demand, and
many other factors. We have natural gas cost recovery
mechanisms for our Illinois and Missouri natural gas
delivery service businesses, a purchased power cost
recovery mechanism for our Illinois electric delivery service
business, and a FAC for our Missouri electric utility
business. Ameren Illinois’ electric delivery service utility
business, pursuant to the IEIMA, conducts an annual
reconciliation of the revenue requirement necessary to
reflect the actual costs incurred in a given year with the
revenue requirement that was in effect for that year, with
recoveries from or refunds to customers in a subsequent
year. Included in Ameren Illinois’ revenue requirement
reconciliation is a formula for the return on equity, which is
equal to the average of the monthly yields of 30-year United
States treasury bonds plus 590 basis points for 2012 and
580 basis points thereafter. Therefore, Ameren Illinois’
annual return on equity will be directly correlated to yields
on United States treasury bonds. Fluctuations in interest
rates and conditions in the capital and credit markets also
35
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 energy centers and transmission and
distribution systems and the level of purchased power
costs, operations and maintenance costs, and capital
investment are key factors that we seek to control to
optimize our results of operations, financial position, and
liquidity.
Earnings Summary
Net loss attributable to Ameren Corporation was
$974 million, or $4.01 per share, for 2012. Net income
attributable to Ameren Corporation was $519 million, or
$2.15 per share, for 2011, and $139 million, or $0.58 per
share, for 2010.
2012 versus 2011
The net loss attributable to Ameren Corporation in
2012 was primarily caused by a net loss in the Merchant
Generation segment of $1.516 billion in 2012. The
Merchant Generation segment reported net income of
$45 million in 2011. Net income attributable to Ameren
Corporation in 2012 decreased in the Ameren Illinois
Segment by $52 million from 2011 and increased in the
Ameren Missouri segment by $129 million from 2011.
Compared with 2011 earnings per share, 2012
earnings were unfavorably affected by:
‰
‰
‰
‰
‰
the 2012 impairments of Merchant Generation’s long-
lived assets resulting from Ameren’s determination in
December 2012 that it intends to, and it is probable that
it will, exit its Merchant Generation segment before the
end of the previously estimated useful lives of that
business segment’s long-lived assets, coupled with the
sharp decline in the market price of power in the first
quarter of 2012 ($6.42 per share);
lower electric margins in the Merchant Generation
segment, largely due to reduced generation volumes
caused by lower market prices for power as well as
higher fuel and related transportation costs
(34 cents per share);
a reduction in Ameren Illinois’ electric earnings
primarily caused by a lower allowed return on equity
under electric delivery service formula ratemaking and
required donations pursuant to the IEIMA (17 cents per
share);
reduced electric and natural gas demand as a result of
warmer 2012 winter temperatures (estimated at 7 cents
per share); and
reduced rate-regulated retail sales volumes, excluding
the effects of abnormal weather, as sales volumes
declined due to continued economic pressure, energy
efficiency measures, and customer conservation
efforts, among other items (2 cents per share).
Compared with 2011 earnings per share, 2012
earnings were favorably affected by:
‰
‰
‰
‰
‰
‰
‰
‰
‰
the absence in 2012 of charges recorded in 2011 at
Ameren Missouri for the MoPSC’s July 2011
disallowance of costs of enhancements relating to the
rebuilding of Ameren Missouri’s Taum Sauk energy
center in excess of amounts recovered from property
insurance and at Merchant Generation for the closure
of the Meredosia and Hutsonville energy centers
(32 cents per share);
higher utility rates at Ameren Missouri and Ameren
Illinois. Ameren Missouri’s electric rates increased
pursuant to an order issued by the MoPSC, which
became effective in July 2011. The favorable impact of
the Ameren Missouri rate increase on earnings was
reduced by the increased regulatory asset amortization
directed by the rate order. Ameren Illinois’ natural gas
rates increased pursuant to an order issued by the ICC,
which became effective in mid-January 2012 (22 cents
per share);
the absence in 2012 of a Callaway energy center
refueling and maintenance outage (11 cents per share);
reduction in operations and maintenance expenses at
both Ameren Missouri and Merchant Generation energy
centers due to fewer outages and a reduction in
employees (10 cents per share);
the impact of fewer major storms on operations and
maintenance expenses (9 cents per share);
a reduction in Ameren Missouri’s purchased power
expense and an increase in interest income, each as a
result of a FERC-ordered refund received in 2012 from
Entergy for a power purchase agreement that expired in
2009 (7 cents per share);
the absence in 2012 of a 2011 charge associated with
voluntary separation offers to eligible Ameren Missouri
and Ameren Services employees (7 cents per share);
the absence in 2012 of a reduction in Ameren
Missouri’s revenues as a result of the MoPSC’s April
2011 FAC prudence review order covering the period
from March 1, 2009, to September 30, 2009, which
resulted in Ameren Missouri recording an obligation to
refund to its electric customers the earnings associated
with certain previously recognized sales (5 cents per
share); and
a decrease in Merchant Generation depreciation and
amortization expense due to the asset impairments
recorded in 2012, a change in 2011 in the estimates
relating to asset retirement obligations, and the closure
of the Meredosia and Hutsonville energy centers at the
end of 2011, which was partially offset by an increase in
Ameren Missouri depreciation and amortization expense
caused primarily by the installation of scrubbers at the
Sioux energy center (4 cents per share).
The cents per share information presented above is
based on average shares outstanding in 2011.
2011 versus 2010
Net income attributable to Ameren Corporation
increased $380 million, and earnings per share increased
$1.57 in 2011 compared with 2010. The Merchant
36
Generation segment reported net income attributable to
Ameren Corporation of $45 million in 2011, compared with
a $409 million net loss in 2010. Net income attributable to
Ameren Corporation decreased in the Ameren Missouri
segment and Ameren Illinois Segment by $77 million and
$15 million, respectively, in 2011 compared with 2010.
Compared with 2010 earnings per share, 2011
earnings were favorably affected by:
‰
reduced impairment and other charges in the Merchant
Generation segment, offset in part by a charge to
earnings related to the MoPSC’s July 2011
disallowance of costs of enhancements relating to the
rebuilding of the Taum Sauk energy center in excess of
amounts recovered from property insurance ($1.87 per
share);
higher Ameren Missouri electric rates pursuant to
orders issued by the MoPSC, which became effective in
June 2010 and in July 2011, as well as higher Ameren
Missouri natural gas rates pursuant to a MoPSC order,
which became effective in late February 2011. The
impact of the Ameren Missouri electric rate increases
on earnings was reduced by the adoption of life span
depreciation methodology, recognition in 2010 of
regulatory assets for previously expensed costs in the
prior-year period, and increased regulatory asset
amortization as directed by the rate orders (17 cents
per share). These amounts exclude the unfavorable
impact of the charge to earnings related to the
MoPSC’s disallowance of Taum Sauk rebuilding costs
discussed above;
lower interest expense, primarily due to the maturity
and repayment of $200 million of Merchant
Generation’s senior secured notes in November 2010,
the redemption of $66 million of Ameren Missouri’s
subordinated deferrable interest debentures in
September 2010, Ameren Illinois’ redemptions of
$150 million of senior secured notes and $40 million of
first mortgage bonds in June 2011 and September
2010, respectively, and a reduction in borrowings
under credit facility agreements (12 cents per share);
higher Ameren Illinois electric rates pursuant to orders
issued by the ICC in 2010 (6 cents per share);
the absence in 2011 of a charge for the impact on
deferred taxes from changes in federal health care laws
(6 cents per share);
the absence in 2011 of charges recorded in 2010 for
cancelled or unrecoverable projects at Ameren Missouri
(6 cents per share);
a reduction in operations and maintenance expense
related to plant maintenance, primarily at Ameren
Missouri, as fewer costs were incurred for major
outages at coal-fired energy centers because the scope
of the outages in 2011 was not as extensive as the
scope of the outages conducted in 2010 (5 cents per
share); and
reduction in expense as a result of disciplined cost
management efforts to align spending with regulatory
outcomes and economic conditions.
‰
‰
‰
‰
‰
‰
‰
Compared with 2010 earnings per share, 2011
earnings were unfavorably affected by:
‰
‰
‰
‰
‰
‰
‰
‰
‰
lower electric margins in the Merchant Generation
segment, largely due to lower realized revenue per
megawatthour sold and higher fuel and related
transportation costs (21 cents per share). This amount
excludes the unfavorable impacts of net unrealized
MTM activity discussed below;
reduced rate-regulated retail sales volumes, excluding
the effects of abnormal weather, as sales volumes
declined due to continued economic pressure, energy
efficiency measures, and customer conservation efforts
as well as lower wholesale sales at Ameren Missouri
due to a reduction in customers and the expiration of
favorably priced contracts, among other items
(15 cents per share);
unrealized net losses on MTM activity primarily related
to nonqualifying power hedges and fuel-related
contracts as well as unfavorable changes in the market
value of investments used to support Ameren’s
deferred compensation plans (10 cents per share);
the impact of weather conditions on electric and natural
gas demand (estimated at 10 cents per share);
increased operations and maintenance expenses as a
result of major storms in 2011 (9 cents per share);
a reduction in allowance for equity funds used during
construction reflecting the 2010 completion of two
scrubbers at Ameren Missouri’s Sioux energy center
(8 cents per share);
increased operations and maintenance expenses
associated with voluntary separation offers to eligible
Ameren Missouri and Ameren Services employees
during 2011 (7 cents per share);
a reduction in revenues resulting from the MoPSC’s
April 2011 order with respect to its FAC review for the
period from March 1, 2009, to September 30, 2009, as
discussed above. See Note 2 – Rate and Regulatory
Matters under Part II, Item 8, of this report for
additional information (5 cents per share); and
an increase in depreciation and amortization expense
caused primarily by the installation of scrubbers at
Ameren Missouri’s Sioux energy center as well as other
capital additions (4 cents per share).
The cents per share information presented above is
based on average shares outstanding in 2010.
For additional details regarding the Ameren
Companies’ results of operations, including explanations of
Margins, Other Operations and Maintenance Expenses,
Impairment and Other Charges, Depreciation and
Amortization, Taxes Other Than Income Taxes, Other
Income and Expenses, Interest Charges, and Income Taxes,
see the major headings below.
37
Below is a table of income statement components by segment for the years ended December 31, 2012, 2011, and 2010:
Merchant
Generation
Other /
Intersegment
Eliminations
Total
$
$
$
$
$
$
(11)
(1)
(1)
18
-
(12)
(9)
(4)
(1)
7
(14)
(1)
(15)
(10)
(2)
(9)
39
1
(19)
(8)
(7)
(1)
10
(6)
-
(6)
(17)
(2)
(1)
32
-
(27)
(10)
(8)
(8)
17
(24)
-
(24)
$
$
$
$
$
$
3,881
452
-
(1,752)
(2,578)
(775)
(468)
34
(448)
680
(974)
-
(974)
3,997
431
-
(1,820)
(125)
(785)
(457)
46
(451)
(310)
526
(7)
519
4,092
448
-
(1,821)
(589)
(765)
(449)
57
(497)
(325)
151
(12)
139
2012
Electric margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operations and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes other than income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income and (expenses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (taxes) benefit
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncontrolling interest and preferred dividends . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Ameren Corporation . . . . . . . . . . . . . . . . . .
2011
Electric margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operations and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes other than income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income and (expenses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (taxes) benefit
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncontrolling interest and preferred dividends . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Ameren Corporation . . . . . . . . . . . . . . . . . .
2010
Electric margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operations and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes other than income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income and (expenses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (taxes) benefit
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncontrolling interest and preferred dividends . . . . . . . . . . . . . . . . . . . . . . .
Ameren
Missouri
$ 2,340
75
1
(827)
-
(440)
(304)
49
(223)
(252)
$
$
$
$
419
(3)
416
2,252
79
5
(934)
(89)
(408)
(296)
51
(209)
(161)
290
(3)
287
2,233
75
1
(931)
-
(382)
(285)
70
(213)
(199)
369
(5)
Ameren
Illinois
Segment
$ 1,034
378
-
(684)
-
(221)
(130)
(10)
(129)
(94)
144
(3)
$
518
-
-
(259)
(2,578)
(102)
(25)
(1)
(95)
1,019
(1,523)
7
141
$ (1,516)
$
$
$
$
$
$
$
1,087
354
1
(640)
-
(215)
(129)
1
(136)
(127)
196
(3)
193
1,096
375
-
(635)
-
(210)
(128)
(6)
(143)
(137)
212
(4)
668
-
3
(285)
(37)
(143)
(24)
1
(105)
(32)
46
(1)
45
780
-
-
(287)
(589)
(146)
(26)
1
(133)
(6)
(406)
(3)
(409)
Net income (loss) attributable to Ameren Corporation . . . . . . . . . . . . . . . . . .
$
364
$
208
$
38
Margins
The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins from
the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins
are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2012, 2011, and
2010. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and
natural gas operations between periods. We have included the analysis below as a complement to the financial information we
provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and may not be
comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
2012 versus 2011
Ameren
Missouri
Ameren
Illinois
Segment
Merchant
Generation
Other(a)
Ameren
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(19)
$
(1)
$
-
$
-
$
(20)
Electric revenue change:
Effect of weather (estimate)(b)
Regulated rates:
Base rates (estimate) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Formula ratemaking adjustment under IEIMA (estimate) . . . . . . . . . . . . . . . . . . .
Recovery of FAC under-recovery(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Off-system revenues (included in base rates)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
FAC prudence review disallowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois pass-through power supply costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy efficiency programs and environmental remediation cost riders . . . . . . .
Bad debt rider
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hurricane Sandy relief cost recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . .
Rate-regulated sales volume (excluding the impact of abnormal weather)
Merchant Generation sales volume . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merchant Generation sales price changes, including hedge effect . . . . . . . . . . . . . .
Net unrealized MTM gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
102
-
(47)
(131)
17
5
(13)
-
-
-
7
(6)
-
-
-
(5)
-
(55)
-
-
-
(1)
(6)
(154)
11
(4)
10
(3)
-
-
-
2
-
-
-
-
-
-
-
-
-
-
-
-
(225)
(26)
11
(13)
-
-
-
-
-
(3)
-
(77)
-
-
-
-
-
-
-
(2)
102
(55)
(47)
(131)
17
1
(19)
(231)
11
(4)
17
(9)
(225)
(26)
11
(18)
Total electric revenue change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(90)
$
(201)
$
(253)
$
(82)
$
(626)
Fuel and purchased power change:
Fuel:
Merchant Generation production volume and other . . . . . . . . . . . . . . . . . . . . . . .
Fuel, purchased power and transportation costs (included in base rates) . . . . . .
Recovery of FAC under-recovery(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net unrealized MTM gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Price – Merchant Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power purchase agreement settlement
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merchant Generation purchased power and other . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission over-recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois pass-through power supply costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total fuel and purchased power change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net change in electric margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas margins change:
Effect of weather (estimate)(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Base rates (estimate) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate redesign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy efficiency programs and environmental remediation cost riders . . . . . . . . .
Bad debt rider
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hurricane Sandy relief cost recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales volume (excluding impact of abnormal weather) and other . . . . . . . . . . . . . .
$
$
$
$
Net change in natural gas margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
106
47
1
-
24
-
-
-
178
88
(2)
2
(5)
-
-
-
1
(4)
$
$
$
$
$
-
-
-
-
-
-
-
(6)
154
148
(53)
(10)
20
-
8
(5)
3
8
24
$
$
$
$
$
83
-
-
(23)
(13)
-
56
-
-
103
(150)
-
-
-
-
-
-
-
-
$
$
$
$
$
-
-
-
-
-
-
4
-
77
81
(1)
-
-
-
-
-
-
1
1
$
$
$
$
$
83
106
47
(22)
(13)
24
60
(6)
231
510
(116)
(12)
22
(5)
8
(5)
3
10
21
39
Electric revenue change:
2011 versus 2010
Ameren
Missouri
Ameren
Illinois
Segment
Merchant
Generation
Effect of weather (estimate)(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(29)
$
(7)
$
Regulated rates:
Base rates (estimate) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recovery of FAC under-recovery(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Off-system revenues included in base rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FAC prudence review disallowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois pass-through power supply costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy efficiency programs and environmental remediation cost riders . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt rider
. . . . . .
Rate-regulated sales volume (excluding the impact of abnormal weather)
Merchant Generation sales volume . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merchant Generation sales price changes, including hedge effect . . . . . . . . . . . . . . .
Net unrealized MTM losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
172
89
53
(17)
1
(43)
-
-
-
(37)
-
-
(2)
5
20
-
-
-
(4)
9
(112)
6
(17)
(15)
-
-
-
(1)
Total electric revenue change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
192
$ (121)
Fuel and purchased power change:
Fuel:
Merchant Generation production volume and other . . . . . . . . . . . . . . . . . . . . . . . .
Fuel, purchased power and transportation costs included in base rates . . . . . . . .
Recovery of FAC under-recovery(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net unrealized MTM losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Price – Merchant Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Merchant Generation purchased power and other . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois pass-through power supply costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total fuel and purchased power change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net change in electric margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas margins change:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effect of weather (estimate)(b)
Bad debt rider
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Base rates (estimate) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy efficiency programs and environmental remediation cost riders . . . . . . . . . .
Sales volume (excluding impact of abnormal weather) and other . . . . . . . . . . . . . . .
$
$
$
$
Net change in natural gas margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
(84)
(89)
-
-
-
-
(173)
19
(1)
-
5
-
-
4
$
$
$
$
$
-
-
-
-
-
-
112
112
(9)
(5)
(14)
3
(1)
(4)
(21)
$
$
$
$
$
$
-
-
-
-
-
-
-
-
-
-
20
(74)
(16)
4
(66)
11
-
-
(9)
(17)
(31)
-
(46)
(112)
-
-
-
-
-
-
Other(a)
Ameren
$ -
$
(36)
-
-
-
-
3
-
(1)
-
-
-
-
-
2
$ 4
$ 1
-
-
1
-
-
1
$ 3
$ 7
$ -
-
-
-
-
$ -
192
89
53
(17)
-
(34)
(113)
6
(17)
(52)
20
(74)
(18)
10
9
12
(84)
(89)
(8)
(17)
(31)
113
(104)
(95)
(6)
(14)
8
(1)
(4)
(17)
$
$
$
$
$
$
Includes amounts for other nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Represents the estimated margin impact of changes in cooling and heating degree-days on electric and natural gas demand compared with the
prior year based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our
service territories.
(c) Represents the change in the net fuel costs recovered under the FAC through customer rates, with corresponding offsets to fuel expense due to
the amortization of a previously recorded regulatory asset.
2012 versus 2011
Ameren
Ameren’s electric margins decreased by $116 million,
or 3%, in 2012 compared with 2011. The following items
had an unfavorable impact on Ameren’s electric margins:
‰
Decreased utilization of Merchant Generation’s energy
centers, primarily due to lower spot market prices,
resulted in a decline in sales volume, which decreased
revenues by $225 million. The decline was mitigated by
a related $83 million decrease in production volume
and other costs and a $56 million decrease in
purchased power and other costs.
‰
The electric delivery formula ratemaking adjustment at
Ameren Illinois, resulting from the annual reconciliation
of the revenue requirement pursuant to the IEIMA,
which decreased revenues by $55 million. The
reduction in revenues for 2012 was primarily caused by
a lower allowed return on equity as the ICC’s 2010
electric rate order resulted in a higher return on equity
than the 2012 formula rate calculation allowed. The
2012 formula for the return on equity pursuant to the
IEIMA was equal to the 2012 average of the monthly
yields of 30-year United States treasury bonds plus 590
basis points. The return on equity included in Ameren
Illinois’ 2010 electric rate order was 10.2% whereas the
2012 IEIMA formula resulted in an 8.8% return on
equity with the ability to earn above or below this
40
‰
‰
‰
‰
‰
amount by 50 basis points. The 2012 revenue
requirement reconciliation included the impact of the
September ICC order, which reduced revenues from
October through December 2012 by $8 million. See
Note 2 – Rate and Regulatory Matters under Part II,
Item 8, of this report for further information.
Lower sales prices at Merchant Generation, including
hedge effect, primarily driven by lower market prices,
partially offset by a favorable settlement with a large
customer, which decreased revenues by $26 million.
‰ Winter weather conditions in 2012 were mild compared
to near normal conditions in 2011, as evidenced by a
15% decrease in heating degree-days, which decreased
revenues by $20 million.
Reduced capacity revenues at Merchant Generation,
driven by low MISO capacity market prices and the
expiration of older, higher-priced agreements,
contributed to the $13 million decrease in Merchant
Generation’s other revenues.
The inclusion of wholesale sales in Ameren Missouri’s
FAC as an offset to fuel costs beginning July 31, 2011,
decreased revenues by $13 million.
Higher fuel prices in the Merchant Generation segment,
primarily due to higher commodity costs associated
with new coal supply agreements, decreased margins
by $13 million.
Net unrealized MTM activity, principally at the Merchant
Generation segment, related to fuel-related contracts
were partially offset by MTM activity related to
nonqualifying power hedges, which decreased margins
by $11 million.
Excluding the estimated impact of abnormal weather,
rate-regulated sales volumes were flat overall, but were
down 1% in the higher-margin residential sector,
partially attributable to energy efficiency measures and
customer conservation efforts, which decreased
revenues by $9 million.
Lower wholesale distribution revenues at Ameren
Illinois, primarily due to lower demand and the
recognition of a reserve for revenues subject to a
refund as a result of a November 2012 FERC
administrative law judge’s decision, which decreased
revenues by $6 million. See Note 2 – Rate and
Regulatory Matters under Part II, Item 8, of this report
for further information.
Ameren Illinois accrues, as a regulatory asset or
liability, transmission costs that are greater than or less
than the amount set in transmission rates
(transmission under-recovery or over-recovery). In
2012, Ameren Illinois over-recovered from customers
its transmission costs by $6 million. As a result,
Ameren Illinois reduced a previously recognized
regulatory asset that had been established for an under-
recovery of costs.
Decreased recoveries through Ameren Illinois’ bad debt
rider, which reduced margins by $4 million. See Other
Operations and Maintenance Expense in this section for
additional information on a related offsetting decrease
in bad debt expense.
‰
‰
‰
‰
The following items had a favorable impact on
Ameren’s electric margins in 2012 compared with 2011:
‰
‰
‰
‰
‰
‰
Higher electric base rates at Ameren Missouri, effective
July 2011, which increased revenues by $102 million,
offset by an increase in net base fuel expense of
$25 million, which was a result of higher net base fuel
cost rates approved in the 2011 MoPSC rate order. The
change in net base fuel expense was the sum of the
change in fuel, purchased power, and transportation
costs included in base rates (+ $106 million) and the
change in off-system revenues (-$131 million) in the
above table. See below for additional details regarding
the FAC.
Reduced purchased power expense at Ameren Missouri
as a result of a FERC-ordered refund from Entergy
received in 2012 relating to a power purchase
agreement that expired in 2009, which increased
margins by $24 million. See Note 2 – Rate and
Regulatory Matters under Part II, Item 8, of this report
for further information.
Absence in 2012 of a reduction in Ameren Missouri’s
revenues recorded in 2011 resulting from the MoPSC’s
April 2011 FAC prudence review order for the period
from March 1, 2009, to September 30, 2009, which
increased revenues by $17 million. See Note 2 – Rate
and Regulatory Matters under Part II, Item 8, of this
report for further information.
Recovery of labor and benefit costs at Ameren Missouri
and Ameren Illinois associated with crews assisting
with Hurricane Sandy power restoration, which
increased revenues by $17 million and was fully offset
by operations and maintenance costs, with no overall
impact on net income. Our costs related to storm
assistance are reimbursed by the utilities receiving the
assistance.
Increased recovery of energy efficiency program costs
and environmental remediation costs through rate-
adjustment mechanisms at Ameren Illinois, which
increased revenues by $11 million. See Other
Operations and Maintenance Expenses in this section
for information on a related offsetting increase in
energy efficiency and environmental remediation costs.
Summer weather conditions in 2012 that were
comparable to 2011, as evidenced by an increase of
1% in cooling degree-days. However, weather
conditions in Ameren’s service territory in 2012 were
the warmest on record, with 25% more cooling degree-
days than normal.
Ameren’s revenues associated with Illinois pass-
through power supply costs decreased $231 million
because of lower power prices on sales and customers
switching to alternative retail electric suppliers. This
decrease in revenues was offset by a corresponding net
decrease in purchased power expense, including Merchant
Generation which supplied $77 million more power to
Ameren Illinois in 2012, which was eliminated for Ameren
consolidated purposes.
41
Ameren Missouri has a FAC cost recovery mechanism
that allows Ameren Missouri to recover, through customer
rates, 95% of changes in fuel, emission allowances,
purchased power costs, transmission costs and MISO costs
and revenues, net of off-system revenues, greater or less
than the amount set in base rates without a traditional rate
proceeding, subject to MoPSC prudency reviews. The
MoPSC’s December 2012 order authorized the inclusion of
fuel additive costs and transmission revenues in the FAC
starting in 2013. Ameren Missouri accrues, as a regulatory
asset, fuel and purchased power costs that are greater than
the amount set in base rates (FAC under-recovery). Net
recovery of fuel costs under the FAC through customer
rates decreased by $47 million in 2012, as compared with
2011, with corresponding offsets to fuel expense to reduce
the previously recognized FAC regulatory asset. The
MoPSC’s December 2012 order also authorized the
inclusion of fuel additive costs and transmission revenues
in the FAC starting in 2013.
Ameren’s natural gas margins increased by $21 million,
or 5%, in 2012 compared with 2011. The following items
had a favorable impact on Ameren’s natural gas margins:
‰
‰
‰
‰
Higher natural gas rates effective February 2011 at
Ameren Missouri and effective January 2012 at Ameren
Illinois increased revenues by $22 million.
Higher sales volume and other primarily at Ameren
Illinois due to increased transportation sales from two
large industrial customers and 1% higher residential
sales volumes, excluding the impact of abnormal
weather, which combined increased margins by
$10 million.
Increased recovery of energy efficiency program costs
and environmental remediation costs through rate-
adjustment mechanisms at Ameren Illinois, which
increased revenues by $8 million. See Other Operations
and Maintenance Expenses in this section for
information on a related offsetting increase in energy
efficiency and environmental remediation costs.
Recovery of labor and benefit costs at Ameren Illinois
associated with crews assisting with Hurricane Sandy
gas service restoration, which increased revenues by
$3 million, and was fully offset by operations and
maintenance costs, with no overall impact on net
income. Our costs related to storm assistance are
reimbursed by the utilities receiving the assistance.
The following items had an unfavorable impact on
‰
Ameren’s natural gas margins:
‰ Winter weather conditions in 2012 were mild compared
to near normal conditions in 2011, as evidenced by
decrease in heating degree-days of 15%, which
decreased margins $12 million.
Decreased recoveries through Ameren Illinois’ bad debt
rider, which decreased margins by $5 million. See
Other Operations and Maintenance Expenses in this
section for additional information on a related offsetting
decrease in bad debt expense.
Rate redesign at Ameren Missouri, implemented as a
result of the natural gas delivery service rate order that
‰
became effective in late February 2011, allowed Ameren
Missouri to recover more of its non-PGA residential
revenues through a fixed monthly charge, with the
remaining amounts recovered based on sales volumes,
which resulted in revenues being recovered more
evenly throughout the year. Revenues decreased
$5 million, because this rate redesign was not in effect
for the first two months of 2011.
Ameren Missouri
Ameren Missouri has a FAC cost recovery mechanism,
which is discussed in the Ameren margin section above.
Ameren Missouri’s electric margins increased by
$88 million, or 4%, in 2012 compared with 2011. The
following items had a favorable impact on Ameren
Missouri’s electric margins:
‰
‰
‰
‰
‰
‰
Higher electric base rates, effective July 2011, which
increased revenues by $102 million, offset by an
increase in net base fuel expense of $25 million, which
was a result of higher net base fuel cost rates approved
in the 2011 MoPSC rate order. The change in net base
fuel expense was the sum of the change in fuel,
purchased power and transportation costs included in
base rates (+$106 million) and the change in off-
system revenues (-$131 million) in the above table.
Reduced purchased power expense as a result of a
FERC-ordered refund received from Entergy in 2012
relating to a power purchase agreement that expired in
2009, which increased margins by $24 million. See
Note 2 – Rate and Regulatory Matters under Part II,
Item 8, of this report for further information.
Absence in 2012 of a reduction in revenues recorded in
2011 resulting from the MoPSC’s FAC prudence review
order the period from March 1, 2009, to September 30,
2009, which increased revenues by $17 million. See
Note 2 – Rate and Regulatory Matters under Part II,
Item 8, of this report for further information.
Recovery of labor and benefit costs associated with
crews assisting with Hurricane Sandy power
restoration, which increased revenues by $7 million
and was fully offset by operations and maintenance
costs with no overall impact on net income.
Higher transmission services revenues primarily due to
two transmission projects that went into service in
second half of 2011 and were included in transmission
rates in 2012, which increased revenues by $5 million.
Summer weather conditions in 2012 were comparable to
2011, as evidenced by an increase of 1% in cooling
degree-days. However, weather conditions in Ameren
Missouri’s service territory in 2012 were the warmest on
record with 25% more cooling degree-days than normal.
The following items had an unfavorable impact on Ameren
Missouri’s electric margins in 2012 compared with 2011:
‰ Winter weather conditions in 2012 were mild compared
to near normal conditions in 2011, as evidenced by a
16% decrease in heating degree-days, which decreased
revenues by $19 million.
42
‰
‰
The inclusion of wholesale sales in the FAC as an offset
to fuel costs beginning July 31, 2011, decreased
revenues by $13 million.
Excluding the estimated impact of abnormal weather,
rate-regulated retail sales volumes that declined by 1%,
partially attributable to energy efficiency measures and
customer conservation efforts, which decreased
revenues by $6 million.
Ameren Missouri’s natural gas margins decreased by
$4 million, or 5%, in 2012 compared with 2011. The
following items had an unfavorable impact on Ameren
Missouri’s natural gas margins:
‰
Rate redesign, as a result of the natural gas delivery
service rate order that became effective in late February
2011, allowed Ameren Missouri to recover more of its
non-PGA residential revenues through a fixed monthly
charge, with the remaining amounts recovered based
on sales volumes, which resulted in revenues being
recovered more evenly throughout the year. Revenues
decreased by $5 million, because the rate redesign was
not in effect for the first two months of 2011.
‰ Winter weather conditions in 2012 were mild compared
to near normal conditions in 2011, as evidenced by
decrease in heating degree-days of 16%, which
decreased margins by $2 million.
Ameren Missouri’s natural gas margins were favorably
affected by an increase in rates that became effective in
February 2011, which increased margins by $2 million.
Ameren Illinois
Ameren Illinois has a cost recovery mechanism for
power purchased on behalf of its customers. These pass-
through power costs do not affect margins; however, the
electric revenues and offsetting purchased power costs may
fluctuate, primarily because of customer switching to
alternative retail electric suppliers and customer usage.
Ameren Illinois does not generate earnings based on the
resale of power but rather on the delivery of power.
Ameren Illinois’ electric margins decreased by
$53 million, or 5%, in 2012 compared with 2011. The
following items had an unfavorable impact on electric
margins:
‰
The formula ratemaking adjustment related to an
annual reconciliation of the revenue requirement
pursuant to the IEIMA decreased revenues by
$55 million. The reduction in revenues for 2012 was
primarily caused by a lower allowed return on equity as
the ICC’s 2010 electric rate order resulted in a higher
return on equity than the 2012 formula rate calculation
allowed. The 2012 formula for the return on equity is
equal to the 2012 average of monthly yields of 30-year
United States treasury bonds plus 590 basis points.
The return on equity included in Ameren Illinois’ 2010
electric rate order was 10.2% whereas the 2012 IEIMA
formula resulted in an 8.8% return on equity with the
ability to earn above or below this amount by 50 basis
‰
‰
points. The 2012 revenue requirement reconciliation
included the impact of the September ICC order, which
reduced revenues from October through December
2012 by $8 million. See Note 2 – Rate and Regulatory
Matters under Part II, Item 8, of this report for further
information.
Lower wholesale distribution revenues, primarily due to
lower demand, and the recognition of a reserve for
revenues subject to a refund as a result of a November
2012 FERC administrative law judge’s decision, which
in total decreased revenues by $6 million. See Note 2 –
Rate and Regulatory Matters under Part II, Item 8, of
this report for further information.
Ameren Illinois accrues, as a regulatory asset or
liability, transmission costs that are greater than or less
than the amount set in transmission rates
(transmission under-recovery or over-recovery). In
2012, Ameren Illinois over-recovered from customers
its transmission costs by $6 million. As a result,
Ameren Illinois reduced a previously recognized
regulatory asset that had been established for an under-
recovery of costs.
Decreased recoveries through Ameren Illinois’ bad debt
rider, which decreased margins by $4 million. See
Other Operations and Maintenance Expenses in this
section for additional information on a related offsetting
decrease in bad debt expense.
Excluding the estimated impact of abnormal weather,
rate-regulated sales volumes that increased by 1%,
driven largely by the lower-margin industrial sector;
however, margins decreased $3 million due to volume
declines in the higher-margin residential and
commercial sectors, partially attributable to energy
efficiency measures and customer conservation efforts.
‰ Winter weather conditions in 2012 were mild compared
to near normal conditions in 2011, as evidenced by a
decrease of 14% in heating degree-days, which
decreased revenues by $1 million.
‰
‰
The following items had a favorable impact on Ameren
Illinois’ electric margins in 2012 compared with 2011:
‰
‰
‰
Increased recovery of energy efficiency program costs
and environmental remediation costs through rate-
adjustment mechanisms, which increased revenues by
$11 million. See Other Operations and Maintenance
Expenses in this section for information on the related
offsetting increase in energy efficiency and
environmental remediation costs.
Recovery of labor and benefit costs associated with
crews assisting with Hurricane Sandy power
restoration, which increased revenues by $10 million,
and was fully offset by operations and maintenance
costs with no overall impact on net income.
Summer weather conditions in 2012 were comparable
to 2011, as evidenced by an increase of 2% in cooling
degree-days. However, weather conditions in Ameren
Illinois’ service territory in 2012 were the warmest on
record with 24% more cooling degree-days than
normal.
43
Ameren Illinois’ natural gas margins increased by
$24 million, or 7%, in 2012 compared with 2011. The
following items had a favorable impact on Ameren Illinois’
natural gas margins:
‰
‰
‰
‰
Increase in natural gas rates effective January 2012,
which increased revenues by $20 million.
Increased recovery of energy efficiency program costs
and environmental remediation costs through Illinois
cost recovery mechanisms, which increased revenues
by $8 million. See Other Operations and Maintenance
Expenses in this section for information on a related
offsetting increase in energy efficiency and
environmental remediation costs.
Higher sales volume and other primarily due to
increased transportation sales from two large industrial
customers and 1% higher residential sales volumes,
excluding the impact of abnormal weather, which
combined increased margins by $8 million.
Recovery of labor and benefit costs associated with
crews assisting with Hurricane Sandy gas service
restoration, which increased revenues by $3 million,
and was fully offset by operations and maintenance
costs, with no overall impact on net income.
The following items had an unfavorable impact on
Ameren Illinois’ natural gas margins in 2012 compared with
2011:
‰ Winter weather conditions in 2012 were mild compared
to near normal conditions in 2011, as evidenced by a
decrease in heating degree-days of 14%, which
decreased margins $10 million.
Decreased recoveries through Ameren Illinois’ bad debt
rider, which reduced margins by $5 million. See Other
Operations and Maintenance Expenses in this section
for additional information on a related offsetting
decrease in bad debt expense.
‰
Merchant Generation
Merchant Generation’s electric margins decreased by
$150 million, or 22%, in 2012 compared with 2011. The
following items had an unfavorable impact on electric
margins:
‰
‰
Decreased energy center utilization, primarily due to
lower spot market prices and an EEI sales contract in
2011 that was not supplied in 2012. Consequently,
Merchant Generation’s sales volume declined, which
decreased revenues by $225 million. This decline was
mitigated by an $83 million decrease in production
volume and other costs and a $56 million decrease in
purchased power and other costs. Merchant
Generation’s average capacity factor decreased to 66%,
in 2012, compared with 72%, in 2011, because of
lower power prices. Merchant Generation’s equivalent
availability factor remained unchanged at 85% in 2012
and 2011.
Lower sales prices, including hedge effect, primarily
driven by lower market prices, partially offset by a
favorable settlement with a large customer, which
decreased revenues by $26 million.
‰
‰
‰
Reduced capacity revenues, driven by low MISO
capacity market prices and the expiration of older,
higher-priced agreements, contributed to the
$13 million decrease in other revenues.
Higher fuel prices, primarily due to higher commodity
costs associated with new coal supply agreements,
which decreased margins by $13 million.
Net unrealized MTM activity, primarily on fuel-related
contracts, were partially offset by nonqualifying power
hedges, which decreased margins by $12 million.
2011 versus 2010
Ameren
Ameren’s electric margins decreased by $95 million, or
2%, in 2011 compared with 2010. The following items had
an unfavorable impact on Ameren’s electric margins:
‰
‰
‰
Lower sales prices, including hedge effects, at the
Merchant Generation segment due to reductions in
higher-margin sales resulting from the expiration of the
2006 auction power supply agreements on May 31,
2010, and lower market prices resulting in fewer
opportunities for economic power sales, which
decreased margins by $74 million.
Excluding the estimated impact of abnormal weather,
rate-regulated retail sales volumes that declined 1%,
attributable to continued economic pressure, energy
efficiency measures and customer conservation efforts,
which decreased revenues by $52 million.
Lower wholesale sales at Ameren Missouri due to a
reduction in customers, the expiration of favorably
priced contracts and the inclusion of revenues from the
remaining contracts as an offset to fuel costs in the
FAC beginning July 31, 2011, which decreased
revenues by $43 million.
‰ Winter weather conditions in 2011 were near normal
‰
‰
‰
‰
compared to a somewhat colder-than-normal 2010, as
evidenced by a 6% decrease in heating degree-days,
which decreased revenues by $36 million.
Net unrealized MTM losses principally at the Merchant
Generation segment, related to nonqualifying power
hedges and fuel-related contracts, which decreased
margins by $26 million.
A $17 million reduction in revenues recorded in 2011,
at Ameren Missouri resulting from the MoPSC’s order
with respect to its FAC disallowance for the period from
March 1, 2009, to September 30, 2009. See Note 2 –
Rate and Regulatory Matters under Part II, Item 8, for
further information regarding the FAC prudence review.
Decreased recovery of prior years’ bad debt expense at
Ameren Illinois, through the Illinois bad debt rider,
effective March 2010, which decreased margins by
$17 million. See Other Operations and Maintenance
Expenses in this section for additional information on a
related offsetting decrease in bad debt expense.
6% higher fuel prices in the Merchant Generation
segment, primarily due to higher commodity and
transportation costs associated with new supply
contracts, which decreased margins by $17 million.
44
The following items had a favorable impact on
Ameren’s electric margins in 2011 compared with 2010:
‰
‰
‰
‰
‰
Higher electric base rates at Ameren Missouri, effective
June 2010 and July 2011, which increased revenues by
$172 million, offset by an increase in net base fuel
expense of $31 million, which was a result of higher net
base fuel cost rates approved in the 2010 and 2011
MoPSC rate orders and higher fuel and transportation
costs. The change in net base fuel expense was the
sum of the change in the fuel, purchased power and
transportation costs included in base rates
(-$84 million) and the change in off-system revenues
(+$53 million) in the above table. See below for
additional details regarding the FAC.
Energy center utilization at Merchant Generation in
2011 was comparable with 2010. Merchant
Generation’s higher sales volume increased electric
revenues by $20 million, which was mostly offset by a
related increase of $20 million in higher net fuel and
purchased power costs. Merchant Generation’s
purchased power and other costs increased $31 million
because of the availability of lower-priced power on the
open market; however, Merchant Generation’s
production volume and other costs decreased
$11 million because of utilization of a lower-cost mix of
energy centers. Merchant Generation’s average capacity
factor remained unchanged at 72% in 2011 and 2010,
but Merchant Generation’s equivalent availability factor
decreased to 85% in 2011, compared with 87% in
2010.
Higher electric delivery service rates at Ameren Illinois,
effective in early May and November 2010, which
increased margins by $20 million.
Higher wholesale revenues at Ameren Illinois, primarily
due to higher rates effective April 2011, which
increased revenues by $9 million. See Note 2 – Rate
and Regulatory Matters under Part II, Item 8, of this
report for further information.
Increased recovery of energy efficiency program costs
and environmental remediation costs through Illinois
rate-adjustment mechanisms at Ameren Illinois, which
increased margins by $6 million. See Other Operations
and Maintenance Expenses in this section for
information on a related offsetting increase in energy
efficiency and environmental remediation costs.
Ameren’s revenues associated with Illinois pass-
through power supply costs decreased $113 million
because of lower power prices on sales primarily to
nonaffiliated parties. These revenues were offset by a
corresponding net decrease in purchased power.
Net recovery of fuel costs under the FAC through
customer rates increased by $89 million in 2011, as
compared with 2010, with corresponding offsets to fuel
expense to reduce the previously recognized FAC regulatory
asset.
Ameren’s natural gas margins decreased by
$17 million, or 4%, in 2011 compared with 2010. The
following items had an unfavorable impact on Ameren’s
natural gas margins:
‰
‰
‰
Decreased recovery of prior years’ bad debt expense
through the Illinois bad debt rider at Ameren Illinois,
effective March 2010, which decreased margins by
$14 million. See Other Operations and Maintenance
Expenses in this section for additional information on a
related offsetting decrease in bad debt expense.
Unfavorable winter weather conditions, as evidenced by
a 6% decrease in heating degree-days, which
decreased revenues by $6 million. Compared to
normal, Ameren experienced 3% fewer heating degree-
days in 2011.
4% lower native load sales volumes, excluding the
estimated impact of abnormal weather, largely in the
commercial and industrial sectors, attributable to
economic pressure, decreased margins by $4 million.
Ameren’s natural gas margins were favorably affected
by $8 million in 2011 compared with 2010 because of
higher natural gas rates effective February 2011 at Ameren
Missouri and effective in May and November 2010 at
Ameren Illinois.
Ameren Missouri
Ameren Missouri has a FAC cost recovery mechanism,
which is outlined in the Ameren margin section above.
Ameren Missouri’s electric margins increased by
$19 million, or 1%, in 2011 compared with 2010. Ameren
Missouri’s electric margins were favorably affected by
higher electric base rates, effective in June 2010 and July
2011 ($172 million), offset by increased net base fuel
expense of $31 million, which was a result of higher net
base fuel cost rates approved in the 2010 and 2011 MoPSC
rate orders and higher fuel and transportation costs. The
change in net base fuel expense is the sum of the change in
fuel, purchased power and transportation costs included in
base rates (-$84 million) and the change in off-system
revenues (+$53 million) in the above table.
The following items had an unfavorable impact on
Ameren Missouri’s electric margins in 2011 compared with
2010:
‰
‰
Lower wholesale sales due to a reduction in customers,
the expiration of favorably priced contracts, and the
inclusion of revenues from the remaining contracts as
an offset to fuel costs in the FAC beginning July 31,
2011, which decreased revenues by $43 million.
Excluding the estimated impact of abnormal weather,
rate-regulated retail sales volumes declined by 1%,
attributable to continued economic pressure, energy
efficiency measures, and customer conservation
efforts, which decreased revenues by $37 million.
‰ Winter weather conditions in 2011 were near normal
compared to a somewhat colder-than-normal 2010, as
evidenced by a 7% decrease in heating degree-days,
which decreased revenues by $29 million.
45
‰
A $17 million reduction in revenues recorded in 2011
resulting from the MoPSC’s order with respect to its
FAC disallowance for the period from March 1, 2009 to
September 30, 2009. See Note 2 – Rate and Regulatory
Matters under Part II, Item 8, for further information
regarding the FAC prudence review.
Ameren Missouri’s natural gas margins increased by
$4 million, or 5%, in 2011 compared with 2010. Ameren
Missouri’s natural gas margins were favorably affected by
higher natural gas rates, effective February 2011, which
increased margins by $5 million.
Ameren Illinois
Ameren Illinois has a cost recovery mechanism for
power purchased on behalf of its customers. These pass-
through power costs do not affect margins; however, the
electric revenues and offsetting purchased power costs may
fluctuate, primarily because of customer switching to
alternative retail electric suppliers and their usage. Ameren
Illinois does not generate earnings based on the resale of
power, but rather on the delivery of energy.
Ameren Illinois’ electric margins decreased by
$9 million, or 1%, in 2011 compared with 2010. The
following items had an unfavorable impact on electric
margins:
‰
‰
Decreased recovery of prior years’ bad debt expense
through the Illinois bad debt rider, effective March
2010, which decreased margins by $17 million. See
Other Operations and Maintenance Expenses in this
section for additional information on a related offsetting
decrease in bad debt expense.
Continued economic pressure, energy efficiency
measures, and customer conservation efforts, which
decreased revenues by $15 million.
‰ Winter weather conditions in 2011 were near normal
compared to a somewhat colder-than-normal 2010, as
evidenced by a 5% decrease in heating degree-days,
which decreased revenues by $7 million.
The following items had a favorable impact on Ameren
Illinois’ electric margins in 2011 compared with 2010:
‰
‰
‰
Higher electric delivery service rates, effective in May
and November 2010, which increased margins by
$20 million.
Higher wholesale revenues, primarily due to higher
rates effective April 2011, which increased revenues by
$9 million. See Note 2 – Rate and Regulatory Matters
under Part II, Item 8, of this report for further
information.
Increased recovery of energy efficiency program costs
and environmental remediation costs through Illinois
rate-adjustment mechanisms, which increased margins
by $6 million. See Other Operations and Maintenance
Expenses in this section for information on a related
offsetting increase in energy efficiency and
environmental remediation costs.
46
Ameren Illinois’ natural gas margins decreased by
$21 million, or 6%, in 2011 compared with 2010. The
following items had an unfavorable impact on Ameren
Illinois’ natural gas margins:
‰
‰
‰
Decreased recovery of prior years’ bad debt expense
under the Illinois bad debt rider, effective March 2010,
which decreased margins by $14 million. See Other
Operations and Maintenance Expenses in this section
for additional information on a related offsetting
decrease in bad debt expense.
Unfavorable winter weather conditions, as evidenced by
a 5% decrease in heating degree-days, decreased
revenues by $5 million. However, compared to normal,
Ameren Illinois experienced in 2011 a 2% decrease in
heating degree-days.
Native load sales volumes declined by 4%, excluding
the estimated impact of abnormal weather, largely in
the commercial and industrial sectors, attributable to
continued economic pressure, which decreased
revenues by $4 million.
Ameren Illinois’ gas margins were favorably affected
by $3 million due to higher natural gas rates effective in
May and November 2010.
Merchant Generation
Merchant Generation’s electric margins decreased by
$112 million, or 14%, in 2011 compared with 2010. The
following items had an unfavorable impact on electric
margins:
‰
‰
‰
Lower sales prices, including hedge effects, due to
reductions in higher-margin sales resulting from the
expiration of the 2006 auction power supply
agreements on May 31, 2010, and lower market prices
resulting in fewer opportunities for economic power
sales, which decreased revenues by $74 million.
Net unrealized MTM activity on fuel-related
transactions, primarily associated with financial
instruments that were acquired to mitigate the risk of
rising diesel fuel price adjustments embedded in coal
transportation contracts, and on nonqualifying power
hedges, which decreased margins by $25 million.
6% higher fuel prices, primarily due to higher
commodity and transportation costs associated with
escalations in existing transportation agreements and
new commodity supply agreements, which decreased
margins by $17 million.
Merchant Generation’s electric margins were favorably
affected by higher sales volume, which increased electric
revenues by $20 million. Higher revenues were largely
offset by a related increase in net fuel and purchased power
costs of $20 million. Purchased power and other costs
increased $31 million due to the availability of cheaper
power on the open market; however, production volume
and other costs decreased $11 million due to usage of a
lower-cost mix of energy centers. Energy center utilization
in 2011 was comparable with 2010. The average capacity
factor remained unchanged at 72% in 2011 and 2010, but
equivalent availability factor decreased to 85% in 2011,
compared with 87% in 2010.
Other Operations and Maintenance Expenses
2012 versus 2011
Ameren Corporation
Other operations and maintenance expenses decreased
by $68 million in 2012 compared with 2011.
The following items reduced other operations and
maintenance expenses between years:
‰
‰
‰
‰
‰
‰
‰
‰
A $40 million decrease in Callaway energy center
refueling and maintenance costs as there was no
outage in 2012.
A $33 million decrease in storm-related repair costs
due to fewer major storms in 2012.
A $29 million decrease in plant maintenance costs,
primarily due to the December 2011 closure of two
Merchant Generation coal-fired energy centers.
A $28 million decrease in employee severance costs
due to the non-recurrence in 2012 of the voluntary
separation program offered by Ameren Missouri and
Ameren Services in 2011.
A $20 million decrease in labor costs, primarily
because staff reductions at Ameren Missouri more than
offset staff additions at Ameren Illinois due to the
requirements of IEIMA.
A $15 million decrease in bad debt expense, due to
improved customer collections of $6 million and
$5 million at Ameren Missouri and Ameren Illinois,
respectively, and adjustments under the Ameren Illinois
bad debt rider of $4 million. Expenses recorded under
the Ameren Illinois bad debt rider mechanism were
recovered through customer billings, and so were
offset by increased revenues, with no overall effect on
net income.
A $10 million favorable change in unrealized net MTM
gains between years, resulting from changes in the
market value of investments used to support Ameren’s
deferred compensation plans.
Disciplined cost management efforts to align spending
with regulatory outcomes, policies, and economic
conditions.
weather in 2012 at Ameren Illinois allowing crews to
complete more maintenance projects.
A $10 million increase in transmission and distribution
expenses, primarily at Ameren Illinois, because of
National Electric Safety Code repairs, which are
nonrecoverable operating expenditures under formula
ratemaking pursuant to the IEIMA, and pipeline
integration compliance.
A $10 million increase in Ameren’s stock-based
compensation expense. See Note 12 – Stock-based
Compensation under Part II, Item 8, of this report for
additional information.
A $6 million increase in outside legal fees, primarily for
legal consultation regarding strategic matters.
‰
‰
‰
Variations in other operations and maintenance
expenses in Ameren’s business segments and for the
Ameren Companies between 2012 and 2011 were as
follows:
Ameren Missouri
Other operations and maintenance expenses decreased
by $107 million in 2012.
The following items reduced other operations and
maintenance expenses between years:
‰
A $40 million decrease in Callaway energy center
refueling and maintenance costs as there was no
outage in 2012.
A $27 million decrease in employee severance costs
due to the voluntary separation program in 2011.
A $25 million reduction in other labor costs, primarily
because of staff reductions.
A $19 million decrease in storm-related repair costs,
due to fewer major storms in 2012.
A $6 million favorable change in unrealized net MTM
gains between years, resulting from changes in the
market value of investments used to support Ameren’s
deferred compensation plans.
A $6 million decrease in bad debt expense due to
improved customer collections.
A $4 million decrease in non-storm-related distribution
maintenance expenditures, primarily due to lower repair
spending.
Disciplined cost management efforts to align spending
with regulatory outcomes, policies, and economic
conditions.
‰
‰
‰
‰
‰
‰
‰
The following items increased other operations and
maintenance expenses between years:
‰
‰
‰
‰
A $19 million increase in energy efficiency and
environmental remediation costs at Ameren Illinois.
These costs were recovered through customer billings
and so were offset by increased electric and natural gas
revenues, with no overall impact on net income.
An $18 million charge in 2012 for canceled projects at
Ameren Missouri and Merchant Generation.
A $12 million increase in employee benefit costs,
primarily due to increased pension expense.
A $12 million increase in non-storm-related distribution
maintenance expenditures due, in part, to mild winter
Other operations and maintenance expenses increased
between years because of a $6 million charge in 2012 for a
canceled project.
Ameren Illinois
Other operations and maintenance expenses increased
by $44 million in 2012.
The following items increased other operations and
maintenance expenses between years:
‰
A $19 million increase in energy efficiency and
environmental remediation costs, which are discussed
above.
47
‰
‰
‰
‰
A $16 million increase in non-storm-related electric
distribution maintenance expenditures due, in part, to
mild winter weather in 2012 allowing crews to
complete more maintenance projects.
A $15 million increase in other labor costs, primarily
because of staff additions due to the requirements of
the IEIMA.
An $11 million increase in transmission and distribution
expenses, primarily because of National Electric Safety
Code repairs, which are nonrecoverable operating
expenditures under formula ratemaking pursuant to the
IEIMA, and pipeline integration compliance.
A $6 million increase in employee benefit costs,
primarily due to increased pension expense.
The following items reduced other operations and
maintenance expenses between years:
‰
A $14 million decrease in storm-related repair costs,
due to fewer major storms in 2012.
A $9 million decrease in bad debt expense, including
$5 million due to improved customer collections and
$4 million due to adjustments related to prior years
under the bad debt rider.
Merchant Generation
Other operations and maintenance expenses decreased
by $26 million in 2012 in the Merchant Generation segment,
as reduced plant maintenance costs of $32 million, due to
the December 2011 closure of two coal-fired energy
centers, fewer outages, as well as disciplined cost
management more than offset charges for canceled
projects of $12 million and an increase in employee benefit
costs of $6 million, primarily due to increased pension
expense.
2011 versus 2010
Ameren Corporation
Other operations and maintenance expenses were
comparable between 2011 and 2010.
The following items reduced other operations and
maintenance expenses between years:
‰
Charges in 2010 of $22 million due to canceled or
unrecoverable projects at Ameren Missouri that did not
recur in 2011.
A decrease of $20 million in plant maintenance costs,
primarily because the scope of the outages in 2011 was
not as extensive as in 2010. Costs associated with the
2011 refueling and maintenance outage at Ameren
Missouri’s Callaway energy center were consistent with
costs incurred for the 2010 refueling and maintenance
outage.
A $17 million decrease in bad debt expense. Bad debt
expense decreased primarily because of adjustments
under the Ameren Illinois bad debt rider mechanism.
A $5 million decrease in employee benefit costs,
primarily because of adjustments under Ameren
Missouri’s pension and postretirement benefit cost
tracker.
‰
‰
‰
‰
‰
Disciplined cost management efforts to align spending
with regulatory outcomes and economic conditions.
The following items increased other operations and
maintenance expenses between years:
‰
‰
‰
‰
‰
A $34 million increase in storm-related repair costs,
due to major storms in 2011.
Recognition of $28 million of employee severance
costs related to the voluntary separation offers to
eligible Ameren Missouri and Ameren Services
employees in 2011.
A reduction in other operations and maintenance
expenses in 2010 by $11 million for a May 2010
MoPSC rate order, which resulted in the recording of
regulatory assets related to 2009 employee severance
costs and storm costs.
An unfavorable change of $9 million in unrealized net
MTM adjustments between years, resulting from
changes in the market value of investments used to
support Ameren’s deferred compensation plans.
A $5 million increase in Ameren Illinois’ energy
efficiency and environmental remediation costs.
Variations in other operations and maintenance
expenses in Ameren’s business segments and for the
Ameren Companies between 2011 and 2010 were as
follows:
Ameren Missouri
Other operations and maintenance expenses were
comparable between years.
The following items increased other operations and
maintenance expenses between years:
‰
‰
‰
‰
Recognition of $27 million of employee severance
costs related to the voluntary separation plan in 2011.
A $21 million increase in storm-related repair costs,
due to major storms in 2011.
A reduction in other operations and maintenance
expenses in 2010 by $11 million for the May 2010
MoPSC rate order discussed above.
An unfavorable change of $5 million in unrealized net
MTM adjustments between years, resulting from
changes in the market value of investments used to
support Ameren’s deferred compensation plans.
The following items reduced other operations and
maintenance expenses between years:
‰
‰
‰
‰
Plant maintenance costs decreased by $23 million,
primarily because the scope of the outages in 2011 was
not as extensive as in 2010.
Charges in 2010 of $22 million because of canceled or
unrecoverable projects.
A $9 million decrease in employee benefit costs,
primarily because of adjustments under the pension
and postretirement benefit cost tracker.
Disciplined cost management efforts to align spending
with regulatory outcomes and economic conditions.
48
Ameren Illinois
Other operations and maintenance expenses were
comparable between years.
The following items increased other operations and
maintenance expenses between years:
‰
‰
‰
‰
‰
A $13 million increase in storm-related repair costs,
due to major storms in 2011.
Energy efficiency and environmental remediation costs
increased by $5 million, as discussed above.
Injuries and damages expenses were higher by
$4 million because of increased claims.
Expenses of $3 million associated with the electric rate
case in 2011 were written-off because the rate case
was withdrawn after passage of the IEIMA.
A reduction in other operations and maintenance
expenses in 2010 of $3 million for a May 2010 ICC rate
order, which resulted in the recording of a regulatory
asset related to 2009 employee severance costs.
The following items reduced other operations and
maintenance expenses between years:
‰
‰
A $19 million reduction in bad debt expense.
Adjustments of $31 million under the bad debt rider
mechanism were partially offset by higher uncollectible
expense.
A reduction of $5 million in non-storm-related
distribution maintenance expenditures due, in part, to
cost management efforts.
Merchant Generation
Other operations and maintenance expenses were
comparable between years in the Merchant Generation
segment. Increased employee benefit costs, primarily
pension costs, and higher plant maintenance costs resulting
from increased planned outages at AERG mitigated the
favorable impact of property sale gains at Genco.
Impairment and Other Charges
The following table summarizes impairment and other
charges for the years ended December 31, 2012, 2011, and
2010:
Long-lived
Assets and
Related
Charges
Goodwill
Emission
Allowances
Total
2012:
Ameren(a)
. . .
$
2,578
$
2011:
Ameren(a)
. . .
AMO . . . . . . .
123
89
-
-
-
$
-
2
-
$
2,578
125
89
2010:
Ameren(a)
. . .
$
101
$
420
$
68
$
589
(a)
Includes amounts for registrant and nonregistrant subsidiaries.
See Note 1 – Summary of Significant Accounting
Policies, Note 2 – Rate and Regulatory Matters, Note 14 –
Related Party Transactions, and Note 17 – Impairment and
Other Charges under Part II, Item 8, of this report for
additional information. The goodwill and long-lived asset
impairment charges did not result in a violation of any
Ameren or Ameren subsidiary debt covenants or
counterparty agreements.
Ameren Corporation
In 2012, Ameren recorded noncash pretax impairment
charges of $2.6 billion to reduce the carrying values of all
but one of Merchant Generation’s coal and natural gas-fired
energy centers. In December 2012, Ameren determined that
it intends to, and it is probable that it will, exit its Merchant
Generation business before the end of the previously
estimated useful lives of that business’ long-lived assets. As
a result of the December 2012 determination, Ameren
concluded that the estimated undiscounted cash flows
through the period in which Ameren expects to continue to
have a significant economic interest in certain energy
centers would be insufficient to recover the carrying value
of those energy centers. Accordingly, Ameren recorded a
noncash pretax impairment charge of $1.95 billion to
reduce the carrying values of all of the Merchant
Generation’s coal and natural gas-fired energy centers,
except the Joppa coal-fired energy center, to their estimated
fair values. The estimated undiscounted cash flows of the
Joppa coal-fired energy center exceeded its carrying value
and therefore was unimpaired. Following the impairment
charge, the net book value of Ameren’s Merchant
Generation long-lived assets was $748 million as of
December 31, 2012.
Key assumptions used in the determination of
estimated undiscounted cash flows of Ameren’s Merchant
Generation segment’s long-lived assets tested for
impairment included forward price projections for energy
and fuel costs, the expected life or duration of ownership of
the long-lived assets, environmental compliance costs and
strategies, and operating costs. Those same cash flow
assumptions, along with a discount rate and terminal year
earnings multiples, were used to estimate the fair value of
each energy center. These assumptions are subject to a
high degree of judgment and complexity. The fair value
estimate of these long-lived assets was based on a
combination of the income approach, which considers
discounted cash flows, and the market approach, which
considers market multiples for similar assets within the
electric generation industry. For the fourth quarter 2012
long-lived asset impairment test, Ameren used a discount
rate of 10% for the coal-fired energy centers, 10.5% for the
combined cycle energy center, and 11.5% for natural gas-
fired energy centers, used a terminal year earnings multiple
ranging from 4.5 to 6 depending on the energy center’s fuel
type and installed pollution control equipment, and
estimated that the duration of ownership for each energy
center was less than five years, with one energy center’s
duration of ownership being less than two years. Holding all
other assumptions constant, if the discount rate had been
one percentage point higher, or if the terminal year earnings
multiple had been one point lower, or if the duration of
ownership for each energy center was one year less than
49
estimated, the fourth quarter 2012 impairment charge
would have been $30 million to $110 million higher. As
discussed above, the Joppa coal-fired energy center’s
estimated undiscounted cash flows exceeded its carrying
value; however, using the same assumptions to estimate
the fair value of that energy center would result in an
estimated fair value that approximated its carrying value as
of December 31, 2012.
In early 2012, the observable market price for power
for delivery in 2012 and in future years in the Midwest
sharply declined below 2011 levels primarily because of
declining natural gas prices and the impact of the stay of
the CSAPR. As a result of this sharp decline in the market
price of power and the related impact on electric margins,
Genco decelerated the construction of two scrubbers at its
Newton energy center in February 2012. The sharp decline
in the market price of power in early 2012 and the related
impact on electric margins, as well as the deceleration of
construction of Genco’s Newton energy center scrubber
project, caused Merchant Generation to evaluate, during the
first quarter of 2012, whether the carrying values of its coal-
fired energy centers were recoverable. AERG’s Duck Creek
energy center’s carrying value exceeded its estimated
undiscounted future cash flows. As a result, Ameren
recorded a noncash pretax asset impairment charge of
$628 million to reduce the carrying value of AERG’s Duck
Creek energy center to its estimated fair value during the
first quarter of 2012. Similar types of assumptions
described above for the fourth quarter 2012 long-lived asset
impairment test were used in this first quarter 2012 test. In
this first quarter 2012 test, Ameren used a discount rate of
9.5% and estimated each energy center’s useful life based
on its physical life. The estimated useful life assumption in
this first quarter 2012 test was based on energy center
specific facts.
The 2012 long-lived asset impairment charges are
expected to reduce 2013 depreciation expense by
approximately $75 million.
In December 2011, Genco ceased operations of its
Meredosia and Hutsonville energy centers. As a result,
Ameren recorded noncash pretax asset impairment charges
of $26 million to reduce the carrying value of the Meredosia
and Hutsonville energy centers to their estimated fair
values, a $4 million impairment of materials and supplies,
and $4 million for severance costs.
During the third quarter of 2010, the aggregate impact
of a sustained decline in market prices for electricity,
industry market multiples became observable at lower
levels than previously estimated, and potentially more
stringent environmental regulations being enacted caused
Ameren to evaluate if the carrying value of its Merchant
Generation energy centers were recoverable. The Meredosia
energy center’s carrying value and Medina Valley energy
center’s carrying value exceeded their estimated
undiscounted future cash flows. As a result, during 2010,
Ameren recorded a noncash pretax asset impairment
charge of $101 million to reduce the carrying value of the
50
Meredosia and Medina Valley energy centers to their
estimated fair values. In 2012, Ameren sold the Medina
Valley energy center and recognized a $10 million gain on
the sale.
Prior to 2010, Merchant Generation expected to use its
SO2 emission allowances for ongoing operations. In July
2010, the EPA issued the proposed CSAPR, which would
have restricted the use of existing SO2 emission allowances.
As a result, Merchant Generation no longer expected that all
of its SO2 emission allowances would be used in
operations. Therefore, during 2010, Ameren recorded a
noncash pretax impairment charge of $68 million to reduce
the carrying value of the Merchant Generation segment’s
SO2 emission allowances to their estimated fair value. In
July 2011, the EPA issued the final CSAPR, which created
new allowances for SO2 and NOx emissions and restricted
the use of pre-existing SO2 and NOx allowances to the acid
rain program and to the NOx budget trading program,
respectively. As a result, observable market prices for
existing emission allowances declined materially. Ameren
recorded a noncash pretax impairment charge of $2 million
in 2011 relating to Merchant Generation’s emission
allowances.
During 2010, Ameren also recorded a noncash pretax
goodwill impairment charge of $420 million, which
represented all of the goodwill assigned to Ameren’s
Merchant Generation reporting unit. The goodwill
impairment recorded in 2010 was caused by a sustained
decline in market prices for electricity, by industry market
multiples becoming observable at lower levels than
previously estimated, and by the possibility that more
stringent environmental regulations would be enacted.
Ameren Missouri
During 2011, the MoPSC issued an electric rate order
that disallowed the recovery of all costs of enhancements,
or costs that would have been incurred absent the breach,
related to the rebuilding of the Taum Sauk energy center in
excess of the amount recovered from property insurance.
Consequently, Ameren and Ameren Missouri each recorded
a pretax charge to earnings of $89 million.
Depreciation and Amortization
2012 versus 2011
Ameren Corporation
Ameren’s depreciation and amortization expenses
decreased by $10 million in 2012 compared with 2011,
primarily because of decreased depreciation and
amortization expense in the Merchant Generation segment
noted below and a $5 million reduction in depreciation and
amortization expenses at Ameren Services, due to the
retirement of computer equipment in 2011, partially offset
by increases at Ameren Missouri and Ameren Illinois noted
below.
Variations in depreciation and amortization expenses in
Merchant Generation
Ameren’s business segments and for the Ameren
Companies between 2012 and 2011 were as follows:
Ameren Missouri
Depreciation and amortization expenses were
comparable between years in the Merchant Generation
segment.
Depreciation and amortization expenses increased by
Taxes Other Than Income Taxes
$32 million in 2012, primarily because of increased
depreciation and amortization expenses associated with the
new scrubbers at the Sioux energy center (depreciation
expense began with the effective date of the July 2011
electric rate order) and other capital additions.
Ameren Illinois
Depreciation and amortization expenses increased by
$6 million in 2012, primarily due to transmission and
distribution infrastructure additions.
Merchant Generation
Depreciation and amortization expenses decreased by
$41 million in 2012, primarily because of a 2011 change in
estimates related to asset retirement obligations and the
closure of two coal-fired energy centers in December 2011.
Additionally, the long-lived asset impairments recorded
during the first and fourth quarters of 2012 caused a
reduction in the carrying value of net plant assets and thus
depreciation expense.
2011 versus 2010
Ameren Corporation
Ameren’s depreciation and amortization expenses
increased by $20 million in 2011 compared with 2010,
because of items noted below. Partially mitigating these
increases was an $8 million reduction in depreciation and
amortization expenses at Ameren Services, primarily
because computer equipment became fully-depreciated
during 2011.
2012 versus 2011
Ameren Corporation
Taxes other than income taxes increased by
$11 million in 2012 compared with 2011 primarily because
of items noted below at Ameren Missouri.
Variations in taxes other than income taxes in
Ameren’s business segments and for the Ameren
Companies between 2012 and 2011 were as follows:
Ameren Missouri
Taxes other than income taxes increased by $8 million
in 2012, because of higher property taxes resulting from
increased state and local assessments in 2012, the
recording of a refund for protested distributable taxes in
2011, and the subsequent recording in December 2012
based on the MoPSC electric rate order to return this refund
to customers. These unfavorable items more than offset a
decrease in payroll taxes between years.
Ameren Illinois
Taxes other than income taxes were comparable
between years, as a reduction in gross receipts taxes
resulting from decreased sales offset higher property taxes
due to increased rates.
Merchant Generation
Taxes other than income taxes were comparable
between years.
Variations in depreciation and amortization expenses in
Ameren’s business segments and for the Ameren
Companies between 2011 and 2010 were as follows:
2011 versus 2010
Ameren Corporation
Ameren Missouri
Depreciation and amortization expenses increased by
$26 million in 2011, primarily because of increased
depreciation and amortization expenses resulting from the
installation of the new scrubbers at the Sioux energy center
and other capital additions. Additionally, an increase in
Ameren Missouri’s annual depreciation rates as a result of
the 2010 MoPSC electric rate order resulted in higher
depreciation and amortization expenses.
Ameren Illinois
Depreciation and amortization expenses increased by
$5 million in 2011, primarily because of capital additions.
Taxes other than income taxes increased by $8 million
in 2011 compared with 2010, primarily because of items
noted below at Ameren Missouri.
Variations in taxes other than income taxes in
Ameren’s business segments and for the Ameren
Companies between 2011 and 2010 were as follows:
Ameren Missouri
Taxes other than income taxes increased by
$11 million in 2011, primarily because of increased
property taxes, due to higher state and local assessments
and higher tax rates, and to higher gross receipts taxes
from increased revenues.
51
Ameren Illinois
Taxes other than income taxes were comparable
between years. Increased property taxes in 2011, primarily
due to higher tax rates, were mitigated by lower corporate
franchise taxes in 2011 as a result of the Ameren Illinois
Merger.
Merchant Generation
Taxes other than income taxes were comparable
between years.
Other Income and Expenses
2012 versus 2011
Ameren Corporation
Other income, net of expenses, decreased by
$12 million in 2012 compared with 2011, primarily due to
increased expenses at Ameren Illinois as discussed below.
Variations in other income, net of expenses, in
Ameren’s business segments and for the Ameren
Companies between 2012 and 2011 were as follows:
Ameren Missouri
Other income, net of expenses, was comparable
between years. Increased donations offset an increase in
interest income, resulting from the interest paid by Entergy
on the amount it overcharged Ameren Missouri under a
power purchase agreement. See Note 2 – Rate and
Regulatory Matters under Part II, Item 8, of this report for
further information on the power purchase agreement with
Entergy.
Ameren Illinois
Ameren Illinois had net other expenses of $10 million
in 2012, compared with net other income of $1 million in
2011. Donations increased by approximately $10 million
because of a one-time $7.5 million donation and $1 million
annual donation to the Illinois Science and Energy
Innovation Trust and a $1 million annual donation for
customer assistance programs pursuant to the IEIMA,
because Ameren Illinois participated in the formula
ratemaking process in 2012.
Variations in other income, net of expenses, in
Ameren’s business segments and for the Ameren
Companies between 2011 and 2010 were as follows:
Ameren Missouri
Other income, net of expenses, decreased by
$19 million in 2011, primarily because of reduced allowance
for equity funds used during construction. Allowance for
equity funds used during construction was higher in 2010,
primarily due to the new scrubbers being constructed at
Ameren Missouri’s Sioux energy center, which were placed
in service in late 2010.
Ameren Illinois
Other income, net of expenses, increased by $7 million
in 2011, primarily because of reduced expenses associated
with customer assistance programs.
Merchant Generation
Other income, net of expenses, was comparable
between years.
Interest Charges
2012 versus 2011
Ameren Corporation
Interest charges decreased by $3 million in 2012
compared with 2011, primarily because decreases at
Ameren Illinois and in the Merchant Generation segment
more than offset an increase in interest charges at Ameren
Missouri. In addition, reduced credit facility borrowings and
commercial paper issuances at Ameren lowered interest
charges.
Variations in interest charges in Ameren’s business
segments and for the Ameren Companies between 2012
and 2011 were as follows:
Ameren Missouri
Interest charges increased by $14 million in 2012,
primarily because Ameren Missouri no longer recorded an
allowance for funds used during construction for pollution
control equipment installed at its Sioux energy center when
the cost of the equipment was placed in customer rates
beginning July 31, 2011, and an increase in interest charges
associated with uncertain tax positions.
Merchant Generation
Other income, net of expenses, was comparable
Ameren Illinois
between years.
2011 versus 2010
Ameren Corporation
Interest charges decreased by $7 million in 2012,
primarily because of the redemption of $150 million of
senior secured notes in June 2011.
Merchant Generation
Other income, net of expenses, decreased by
$11 million in 2011 compared with 2010, primarily because
of items noted below.
Interest charges decreased by $10 million in 2012,
primarily because of increased capitalized interest due to
the Newton energy center scrubber project.
52
2011 versus 2010
Ameren Corporation
Interest charges decreased by $46 million in 2011
compared with 2010, because of items noted below and
because of reduced credit facility borrowings at Ameren.
Variations in interest charges in Ameren’s business
segments and for the Ameren Companies between 2011
and 2010 were as follows:
Ameren Missouri
Interest charges decreased by $4 million in 2011,
primarily because of a reduction in interest charges
associated with uncertain tax positions of $6 million, the
redemption of $66 million of subordinated deferrable
interest debentures in September 2010, and reduced
amortization of credit facility fees. Offsetting these favorable
items was a reduction in interest charges in 2010 due to the
May 2010 MoPSC electric rate order. The rate order
resulted in a reduction of interest charges of $10 million in
2010, through the recording of a regulatory asset for
recovery of bank credit facility fees incurred in 2009.
Ameren Illinois
Interest charges decreased by $7 million in 2011,
primarily because of the redemption of $150 million of
senior secured notes in June 2011 and the redemption of
$40 million of first mortgage bonds in September 2010.
Merchant Generation
Interest charges decreased by $28 million in 2011
because of the maturity and repayment of $200 million of
Genco senior unsecured notes in November 2010 and
because of reduced intercompany borrowings at AERG.
Income Taxes
The following table presents effective income tax rates
for Ameren’s business segments and for the Ameren
Companies for the years ended December 31, 2012, 2011,
and 2010:
2012
2011
2010
Ameren . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . .
Merchant Generation . . . . . . . . . . . . . .
41%
37
40
40
37%
36
39
41
68%(a)
35
39
(2)(b)
(a) The impact of a goodwill impairment charge, which is not
deductible for income tax purposes, increased the effective tax
rate for 2010 by 32 percentage points.
(b) The impact of a goodwill impairment charge, which is not
deductible for income tax purposes, decreased the effective tax
rate for 2010 by 36 percentage points.
2012 versus 2011
Ameren Corporation
Ameren’s effective tax rate was higher in 2012 than
2011 primarily due to the impact of investment tax credit
amortization, the reduction in the amortization of property-
related regulatory assets and liabilities, and state income
taxes on a large pretax book loss in 2012 compared with
pretax income in 2011.
Variations in effective tax rates in Ameren’s business
segments and for the Ameren Companies between 2012
and 2011 were as follows:
Ameren Missouri
Ameren Missouri’s effective tax rate was higher
primarily because of an increase in reserves for uncertain
tax positions in 2012, compared to a decrease in 2011.
Additionally, the effective tax rate increased because of the
decreased impact of the amortization of property-related
regulatory assets and liabilities, and estimated tax credits
on higher pretax income in 2012 compared with 2011.
Ameren Illinois
Ameren Illinois’ effective tax rate was higher primarily
because of the favorable impact of recording the adjustment
to deferred tax assets due to the Illinois statutory income
tax rate increase in 2011.
Merchant Generation
The Merchant Generation segment’s effective tax rate
was lower primarily because of the unfavorable impact of
recording an adjustment to deferred tax liabilities in the
prior year due to the Illinois statutory income tax rate
increase in 2011, along with the decreased impact of the
permanent book tax differences on a large pretax loss in
2012, which was partially offset by favorable changes in the
reserves for uncertain tax positions in 2011.
2011 versus 2010
Ameren Corporation
Ameren’s effective tax rate was lower in 2011 than in
2010, primarily because of the impact of the nondeductible
goodwill impairment charge in 2010. See Note 17 –
Impairment and Other Charges under Part II, Item 8, of this
report for additional information on the goodwill
impairment charges. In addition, there was a noncash,
after-tax charge to earnings of $13 million, in the first
quarter of 2010, to reduce deferred tax assets. The charge
to earnings was recorded because of legislation enacted in
the first quarter of 2010 that resulted in retiree health care
costs no longer being deductible for tax purposes to the
extent that an employer’s postretirement health care plan
receives federal subsidies to provide retiree prescription
drug benefits equivalent to Medicare prescription drug
benefits. This was offset, in part, by the impact of the
increased Illinois statutory tax rate effective at the beginning
of 2011, along with lower favorable net amortization of
property-related regulatory assets and liabilities in 2011
compared with 2010, changes to reserves for uncertain tax
positions, and the decreased impact of federal and state tax
credits.
53
Variations in effective tax rates in Ameren’s business
segments and for the Ameren Companies between 2011
and 2010 were as follows:
Ameren Missouri
Ameren Missouri’s effective tax rate was higher,
primarily because of lower favorable net amortization of
property-related regulatory assets and liabilities in 2011
compared to 2010, offset, in part, by the effect of the
change in the tax treatment of retiree health care costs in
2010 and changes to reserves for uncertain tax positions.
Ameren Illinois
Ameren Illinois’ effective tax rate was comparable
between years.
Merchant Generation
The effective tax rate was higher in the Merchant
Generation segment, primarily because the impact of the
nondeductible goodwill impairment charge in 2010, the
increase in the Illinois statutory income tax rate in 2011 and
the decrease in the effective tax rate from the effect of the
change in the tax treatment of retiree health care costs in
2010, partially offset by decreased Internal Revenue Code
Section 199 production activity deductions, lower benefits
from state tax credits related to capital investments, and
favorable changes to reserves for uncertain tax positions in
2011, compared to unfavorable changes in 2010.
Income from Discontinued Operations, Net of Tax
Ameren Illinois
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG
and AER completed a two-step corporate internal
reorganization. The first step of the reorganization was the
Ameren Illinois Merger. The second step of the
reorganization involved the distribution of AERG stock from
Ameren Illinois to Ameren and the subsequent contribution
by Ameren of the AERG stock to AER. Ameren Illinois
determined that the operating results of AERG qualified for
discontinued operations presentation. We have therefore
segregated AERG’s operating results and presented them
separately as discontinued operations for all periods
presented prior to October 1, 2010, in this report. For
Ameren’s financial statements, AERG’s results of operation
remain classified as continuing operations. See Note 16 –
2010 Corporate Reorganization under Part II, Item 8, of this
report for additional information.
LIQUIDITY AND CAPITAL RESOURCES
The tariff-based gross margins of Ameren’s rate-
regulated utility operating companies continue to be a
principal source of cash from operating activities for
Ameren and its rate-regulated subsidiaries. A diversified
retail customer mix primarily of rate-regulated residential,
commercial, and industrial classes and a commodity mix of
natural gas and electric service provide a reasonably
predictable source of cash flows for Ameren, Ameren
Missouri and Ameren Illinois. In addition to using cash
flows from operating activities, Ameren, Ameren Missouri
and Ameren Illinois use available cash, credit agreement
borrowings, commercial paper issuances, money pool
borrowings, or other short-term borrowings from affiliates
to support normal operations and other temporary capital
requirements. Ameren, Ameren Missouri and Ameren
Illinois may reduce their credit agreement or short-term
borrowings with cash from operations or, at their
discretion, with long-term borrowings or, in the case of
Ameren Missouri and Ameren Illinois, with equity infusions
from Ameren. Ameren, Ameren Missouri and Ameren
Illinois expect to incur significant capital expenditures over
the next five years as they comply with environmental
regulations and make significant investments in their
electric and natural gas utility infrastructure to support
overall system reliability, achieve IEIMA performance
standards, and other improvements. Ameren intends to
finance those capital expenditures and investments in its
rate-regulated businesses with a blend of equity and debt so
that it maintains a capital structure of approximately 50% to
55% equity, assuming constructive regulatory
environments. Ameren, Ameren Missouri and Ameren
Illinois plan to implement their long-term financing plans
for debt, equity, or equity-linked securities to finance their
operations appropriately, to fund scheduled debt maturities,
and to maintain financial strength and flexibility.
Merchant Generation sells power primarily through
market-based contracts with wholesale and retail customers
to generate operating cash flows. In December 2012,
Ameren announced that it had concluded that the Merchant
Generation segment was no longer a core component of its
future business strategy. Ameren determined that it intends
to, and it is probable that it will, exit the Merchant
Generation business segment before the end of the
previously estimated useful lives of that business segment’s
long lived assets. In consideration of this determination,
Ameren has begun planning to reduce, and ultimately
eliminate, the Merchant Generation segment’s, including
Genco’s, reliance on Ameren’s financial support and shared
services support. While it remains a business of Ameren,
the Merchant Generation segment will seek to fund its
operations internally and therefore will seek not to rely on
financing from Ameren or external, third-party sources. The
Merchant Generation segment will seek to defer or reduce
capital and operating expenses, sell certain assets, and to
take other actions as necessary to fund its operations
internally while maintaining safe and reliable operations.
Under the provisions of its indenture, Genco may not
borrow additional funds from external third-party sources if
its interest coverage ratio is less than a specified minimum
or if its leverage ratio is greater than a specified maximum.
See Note 5 – Long-term Debt and Equity Financings under
Part II, Item 8, of this report for additional information on
Genco’s indenture provisions. Based on projections as of
December 31, 2012, of its operating results and cash flows,
Genco expects that, by the end of the first quarter of 2013,
its interest coverage ratio will be less than the minimum
54
ratio required for the company to borrow additional funds
from external, third-party sources. Genco’s indenture does
not restrict intercompany borrowings from Ameren’s non-
state-regulated subsidiary money pool. However,
borrowings from the money pool are subject to Ameren’s
control, and if a Genco intercompany financing need were
to arise, borrowings from the non-state-regulated
subsidiary money pool by Genco would be dependent on
consideration by Ameren of the facts and circumstances
existing at that time. In March 2012, Genco entered into a
put option agreement with AERG for the potential sale of the
Grand Tower, the Gibson City, and the Elgin energy centers
in order to provide an additional source of liquidity, if
needed in the future. See Note 14 – Related Party
Transactions, under Part II, Item 8, of this report for
additional information regarding the put option agreement
and Ameren’s guarantee of AERG’s contingent obligations
under the put option agreement. Should a financing need
arise at Genco, its sources of liquidity include available cash
on hand, a return of money pool advances, money pool
borrowings at the discretion of Ameren, sale of an asset or
multiple assets, or exercising the put option agreement with
AERG. With existing power market conditions and cash flow
requirements, it is more likely than not that Genco will sell
one or more of its three natural gas fired energy centers
before the put option agreement expires on March 28,
2014. Ameren and AERG do not expect to extend the put
option agreement beyond March 28, 2014. Based on
current projections, it is probable during 2013 that Genco
will need mid-month liquidity from either asset sales or
money pool borrowings to support working capital needs.
However, borrowings from the money pool are subject to
Ameren’s control, and if a Genco intercompany financing
need were to arise, borrowings from the non-state-
regulated subsidiary money pool by Genco would be
dependent on consideration by Ameren of the facts and
circumstances existing at that time. Based on projections as
of December 31, 2012, Genco estimates these financing
sources are adequate to support its operations in 2013.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years
ended December 31, 2012, 2011, and 2010:
Net Cash Provided By
Operating Activities
Net Cash (Used In)
Investing Activities
Net Cash (Used In)
Financing Activities
2012
2011
2010
2012
2011
2010
2012
2011
2010
Ameren(a) . . . . . . . . . . . .
Ameren Missouri . . . . . .
Ameren Illinois . . . . . . .
$
$
1,690
1,004
519
1,878
1,056
504
$
1,823
969
593
$
(1,310) $
(703)
(437)
(1,048) $
(627)
(296)
(1,096) $
(700)
(247)
(426) $
(354)
(103)
(1,120) $
(430)
(509)
(804)
(334)
(330)
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Cash Flows from Operating Activities
2012 versus 2011
Ameren Corporation
Ameren’s cash from operating activities decreased in
2012, compared with 2011. The following items contributed
to the decrease in Ameren’s cash from operating activities
during 2012, compared with 2011:
‰
‰
‰
‰
Cash flows associated with Ameren Missouri’s under-
recovered FAC costs, which decreased by $161 million.
Recoveries outpaced deferrals in 2011 by $87 million,
while deferrals outpaced recoveries in 2012 by
$74 million.
The premiums paid to debt holders in connection with
the repurchase of multiple series of Ameren Missouri
and Ameren Illinois senior secured notes totaled
$138 million. See Note 5 – Long-term Debt and Equity
Financings under Part II, Item 8, of this report for
additional information.
A $105 million decrease in cash collections from
customer receivables, excluding the impacts of the
receipt of funds from, and deposits into, court
registries discussed separately below, primarily caused
by milder weather in December 2011, compared with
December 2010.
Income tax payments of $1 million in 2012, compared
with income tax refunds of $61 million in 2011. The
2011 refund resulted primarily from an IRS settlement,
while the 2012 payment was caused by the purchase of
state tax credits. Ameren did not make material federal
income tax payments in either period because of
accelerated deductions authorized by economic
stimulus legislation and other deductions.
Electric and natural gas margins, as discussed in
Results of Operations, which decreased by $29 million,
excluding impacts of noncash MTM transactions and
Ameren Illinois’ noncash IEIMA formula ratemaking
adjustment.
A net $22 million increase in coal inventory, primarily
caused by a $40 million increase at Ameren Missouri
discussed below offset by an $18 million decrease in
Merchant Generation coal inventory, primarily due to
continued focus on inventory reductions, partially offset
by increased coal prices.
A $22 million increase in energy efficiency
expenditures, primarily for Ameren Illinois customer
programs, which are recovered through customer
billings over time.
‰
‰
‰
The following items partially offset the decrease in
Ameren’s cash from operating activities during 2012,
compared with 2011:
‰
Ameren Missouri’s receipt of $37 million from the
Stoddard County Circuit Court’s registry and the Cole
55
County Circuit Court’s registry as the MoPSC’s 2009
and 2010 electric rate orders were upheld on appeals.
Additionally, $24 million fewer Ameren Missouri
receivables were paid into the court registries in 2012
in connection with the electric rate order appeals. See
Note 2 – Rate and Regulatory Matters under Part II,
Item 8, of this report for additional information.
A $53 million decrease in pension and postretirement
plan contributions. In 2011, Ameren Illinois contributed
to Ameren’s postretirement benefit plan trust an
incremental $100 million in excess of Ameren Illinois’
annual postretirement net periodic cost for regulatory
purposes.
A $50 million decrease in the cost of natural gas held in
storage because of lower prices.
A $35 million decrease in major storm restoration
costs.
A $25 million decrease in taxes other than income tax
payments, primarily related to Ameren Missouri,
caused by the timing of property tax payments at each
year end, partially offset by higher assessed property
tax values.
A $21 million reduction in payments for scheduled
nuclear refueling and maintenance outages at the
Callaway energy center, caused by the absence of a
refueling outage in 2012.
A $21 million increase in natural gas commodity over-
recovered costs under the PGA, primarily related to
Ameren Illinois.
A $20 million decrease in payments related to the MISO
liability due, in part, to fewer payments required for
December 2011 purchases compared to the payments
required for December 2010 purchases.
A $20 million decrease in interest payments, primarily
due to the Ameren Illinois senior secured note
redemption in June 2011 and a $7 million interest
reduction associated with Ameren’s borrowings under
its credit facility agreements and issuances under its
commercial paper program as fewer borrowings and
issuances were made in 2012.
A net $19 million decrease in collateral posted with
counterparties for the reasons discussed at the
registrant subsidiaries below and a decrease in
collateral returned by nonregistrant subsidiaries of
$5 million due to changes in the market prices of
power, natural gas, and coal and in contracted
commodity volumes.
The receipt of $16 million for net coal transfers to
refiners under agreements, primarily for the Merchant
Generation segment, that began in late 2011. The coal
will be purchased back from the refiners in a
subsequent period.
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
Ameren Missouri
Ameren Missouri’s cash from operating activities
decreased in 2012 compared with 2011. The following
items contributed to the decrease in cash from operating
activities during 2012, compared with 2011:
‰
‰
‰
‰
‰
Cash flows associated with Ameren Missouri’s under-
recovered FAC costs, which decreased by $161 million.
Recoveries outpaced deferrals in 2011 by $87 million,
while deferrals outpaced recoveries in 2012 by
$74 million.
The premiums paid to debt holders for the repurchase
of multiple series of tendered senior secured notes,
which totaled $62 million.
A $40 million increase in coal inventory primarily due to
additional tons held in inventory because generation
levels were below expected levels due to market
conditions, the absence in 2012 of flooding that
impeded coal deliveries in 2011, increased coal prices,
and milder weather conditions in early 2012.
A $25 million decrease in cash collections from
customer receivables, excluding the receipt of funds
from, and deposits into, court registries discussed
separately below, primarily caused by milder weather in
December 2011, compared with December 2010.
A net $6 million increase in collateral posted with
counterparties due, in part, to changes in the market
price of power and gas and in contracted commodity
volumes.
The following items partially offset the decrease in
Ameren Missouri’s cash from operating activities during
2012, compared with 2011:
‰
‰
‰
‰
‰
‰
‰
Electric and natural gas margins, as discussed in
Results of Operations, which increased by $83 million.
Receipt of $37 million from the Stoddard County Circuit
Court’s registry and the Cole County Circuit Court’s
registry as the MoPSC’s 2009 and 2010 electric rate
orders were upheld on appeals. Additionally,
$24 million fewer Ameren Missouri receivables were
paid into the court registries in 2012 in connection with
the electric rate order appeals. See Note 2 – Rate and
Regulatory Matters under Part II, Item 8, of this report
for additional information.
A $28 million decrease in property tax payments
caused by the timing of property tax payments at each
year end, partially offset by higher assessed property
tax values.
A $21 million reduction in payments for scheduled
nuclear refueling and maintenance outages at the
Callaway energy center, caused by the absence of a
refueling outage in 2012.
A $20 million decrease in major storm restoration
costs.
A $15 million reduction in energy efficiency
expenditures.
Income tax refunds of $3 million in 2012, compared
with income tax payments of $9 million in 2011.
Ameren Missouri’s 2011 tax liability was reduced by
accelerated deductions authorized by economic
stimulus legislation, use of its net operating loss
carryforwards, and other deductions. Ameren
Missouri’s 2012 tax refund is primarily due to a tax
deduction related to the repurchase of debt, partially
56
offset by an increase in income from the resolution of
the 2009 and 2010 electric rate order appeals
discussed above
An $11 million reduction in labor costs due to staff
reductions.
‰
Ameren Illinois
Ameren Illinois’ cash from operating activities
increased in 2012 compared with 2011. The following items
contributed to the increase in cash from operating activities
during 2012, compared with 2011:
‰
‰
‰
‰
‰
‰
‰
‰
‰
A $65 million decrease in pension and postretirement
plan contributions. In 2011, Ameren Illinois contributed
to Ameren’s postretirement benefit plan trust an
incremental $100 million in excess of Ameren Illinois’
annual postretirement net periodic cost for regulatory
purposes.
A $46 million decrease in the cost of natural gas held in
storage because of lower prices.
Electric and natural gas margins, as discussed in
Results of Operations, increased by $26 million,
excluding impacts of the noncash IEIMA formula
ratemaking adjustment.
A net $20 million decrease in collateral posted with
counterparties due, in part, to changes in the market
price of natural gas and in contracted commodity
volumes.
A $20 million decrease in payments related to the MISO
liability due, in part, to fewer payments required for
December 2011 purchases compared with payments
required for December 2010 purchases.
A $16 million increase in natural gas commodity over-
recovered costs under the PGA.
A $15 million decrease in major storm restoration
costs.
A $12 million decrease in interest payments, primarily
due to the redemption of senior secured notes in June
2011.
An $8 million increase in income tax refunds primarily
due to lower pretax book income along with a tax
deduction related to the repurchase of debt.
The following items partially offset the increase in
Ameren Illinois cash from operating activities during 2012,
compared with 2011:
‰
‰
‰
‰
‰
The premiums paid to debt holders for the repurchase
of multiple series of tendered senior secured notes,
which totaled $76 million.
A $68 million decrease in cash collections from
customer receivables, primarily caused by milder
weather in December 2011, compared with December
2010.
A $37 million increase in energy efficiency expenditures
for customer programs that are recovered through
customer billings over time.
A $26 million increase in payments to contractors for
additional reliability, maintenance, and IEIMA projects.
A $12 million increase in labor costs, primarily because
of staff additions due to the requirements of the IEIMA.
‰
A one-time $7.5 million payment to the Illinois Science
and Energy Innovation Trust as required by the IEIMA.
2011 versus 2010
Ameren Corporation
Ameren’s cash from operating activities increased in
2011, compared with 2010. The following items contributed
to the increase in cash from operating activities during
2011, compared with 2010:
‰
Ameren Missouri’s regulatory asset for FAC under-
recovery, which decreased by $216 million as more
deferred costs were recovered from customers during
2011.
Trade accounts receivable and unbilled revenues
balances decreased, primarily because of milder
weather in the fourth quarter of 2011, compared with
the fourth quarter of 2010. Those same weather
conditions caused accounts payable balances to MISO
and natural gas suppliers to decrease as less power
and natural gas was purchased. Additionally, during
2011, MISO shortened the length of its settlement
terms for all of its members. The new terms resulted in
an acceleration of payments that previously would not
have been made until 2012. These factors resulted in a
net increase of $120 million in cash from operating
activities in 2011 compared with 2010.
A net $100 million decrease in collateral posted with
counterparties for the reasons discussed at the
registrant subsidiaries below, partially offset by a
decrease in collateral returned from Ameren
counterparties of $10 million and additional collateral
posted to counterparties of $4 million due to changes
in the market price of power.
Deferred budget billing receivables that decreased by
$71 million, partially as a result of milder weather.
A $45 million decrease in interest payments, primarily
due to the long-term debt redemptions at the registrant
subsidiaries discussed below and a reduction in
Ameren’s borrowings under its credit facility
agreements, which resulted in an $11 million reduction
in interest payments.
An $11 million reduction in payments for scheduled
nuclear refueling and maintenance outages at the
Callaway energy center caused primarily by the timing
of the 2011 outage compared with the 2010 outage,
which had unpaid liabilities as of December 31, 2011.
‰
‰
‰
‰
‰
The following items reduced the increase in Ameren’s
cash from operating activities during 2011, compared with
2010:
‰
A $115 million increase in pension and postretirement
benefit plan contributions. Ameren Illinois contributed
to Ameren’s postretirement benefit VEBA trust an
incremental $100 million in excess of Ameren Illinois’
annual postretirement net periodic cost for regulatory
purposes.
Electric and natural gas margins, as discussed in
Results of Operations, which decreased by $86 million,
excluding impacts of noncash MTM transactions.
‰
57
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
During 2010, Ameren’s Merchant Generation coal-fired
energy centers significantly reduced their coal inventory
levels, which resulted in an estimated $64 million cash
savings in excess of the smaller inventory reduction
that occurred in 2011.
A $55 million decrease associated with the December
2005 Taum Sauk incident, primarily as a result of
insurance recoveries received in 2010, but not in 2011.
A $34 million increase in major storm restoration costs.
A $31 million decrease in income tax refunds. The 2010
refund resulted primarily from a 2009 change in tax
treatment of electric generation plant expenditures. The
2011 refund resulted primarily from casualty loss
deductions due to an Internal Revenue Service audit
settlement. Ameren did not make any federal income
tax payments in 2011 because of accelerated
deductions authorized by economic stimulus
legislation, use of its net operating loss carryforwards,
and other deductions.
A $30 million increase in taxes other than income tax
payments that related to higher assessed property tax
values for energy center enhancements, county
property tax rate increases, and the timing of property
tax payments at each year end for Ameren Missouri.
Ameren Illinois incurred an increase in electricity
distribution and invested capital tax payments resulting
from the tiered rate structure for the merged entity.
Reduced collections as more utility customers were
past due on their bills on December 31, 2011, than on
December 31, 2010. Additionally, write-offs of
customer receivable balances increased because of
economic conditions.
An $18 million increase in Ameren Missouri receivables
held in court registries under the appeals of the
MoPSC’s 2009 and 2010 rate orders. See Note 2 – Rate
and Regulatory Matters under Part II, Item 8, of this
report for additional information.
A $16 million decrease in Ameren Illinois’ electric
purchased power commodity over-recovered costs.
A $15 million increase in energy efficiency expenditures
for new customer programs. The Ameren Illinois
amount is recovered through customer billings over
time.
An $11 million decrease in natural gas commodity
over-recovered costs under the PGA, primarily in
Illinois.
A $7 million increase in preliminary study expenditures,
primarily at Ameren Missouri for environmental
compliance testing.
Ameren Missouri
Ameren Missouri’s cash from operating activities
increased in 2011 compared with 2010. The following items
contributed to the increase in cash from operating activities
during 2011, compared with 2010:
‰
The regulatory asset for FAC under-recovery, which
decreased by $216 million as more deferred costs were
recovered from customers during 2011.
58
‰
‰
‰
‰
‰
‰
Trade accounts receivable and unbilled revenue
balances, which decreased by $65 million, primarily
because of milder weather in the fourth quarter of
2011, compared with the fourth quarter of 2010.
Deferred budget billing receivables, which decreased by
$33 million, partially as a result of milder weather.
Electric and natural gas margins, as discussed in
Results of Operations, which increased by $25 million,
excluding impacts of noncash MTM transactions.
A $16 million decrease in payments associated with
major outages at coal-fired energy centers, primarily
because the scope of the major outages in 2011 was
not as extensive in 2010.
An $11 million reduction in payments due to the timing
of scheduled nuclear refueling and maintenance
outages at the Callaway energy center as discussed
above.
A $4 million decrease in interest payments, primarily
due to the redemption of subordinated deferrable
interest debentures in September 2010.
The following items reduced the increase in Ameren
Missouri’s cash from operating activities during 2011,
compared with 2010:
‰
‰
‰
‰
‰
‰
‰
‰
‰
Income tax payments of $9 million in 2011, compared
with income tax refunds of $106 million in 2010. The
2010 refund resulted primarily from a 2009 change in
tax treatment of electric generation plant expenditures
and accelerated deductions authorized by economic
stimulus legislation. Ameren Missouri’s 2011 tax
liability was reduced by accelerated deductions
authorized by economic stimulus legislation, use of its
net operating loss carryforwards, and other deductions.
A $55 million decrease associated with the December
2005 Taum Sauk incident, primarily as a result of
insurance recoveries received in 2010, but not in 2011.
A $23 million increase in property tax payments caused
primarily by higher assessed tax values for energy
center enhancements, county tax rate increases, and
the timing of property tax payments at each year end.
A $21 million increase in major storm restoration costs.
An $18 million increase in receivables held in court
registries under the appeals of the MoPSC’s 2009 and
2010 rate orders.
Reduced collections as more customers were past due
on their bills on December 31, 2011, than on
December 31, 2010. Additionally, write-offs of
customer receivable balances increased because of
economic conditions.
A net $6 million decrease in collateral returned from
exchange counterparties and, to a lesser extent,
additional collateral postings to MISO, all due to
changes in the market price of power and natural gas.
A $6 million increase in preliminary study expenditures,
primarily for environmental compliance testing.
A $6 million increase in energy efficiency expenditures
for new customer programs.
Ameren Illinois
Ameren Illinois’ cash from operating activities
decreased in 2011 compared with 2010. Ameren Illinois’
cash from operating activities included AERG’s operating
cash flows for all periods prior to October 1, 2010, which
were presented as discontinued operations in Ameren
Illinois’ consolidated statement of cash flows. Excluding the
impacts of discontinued operations, Ameren Illinois’ cash
from operating activities decreased in 2011 compared with
2010. The following items contributed to the decrease in
cash from operating activities associated with continuing
operations during 2011, compared with 2010:
‰
‰
‰
‰
‰
‰
‰
‰
‰
A $103 million increase in pension and postretirement
benefit plan contributions. Ameren Illinois contributed
to Ameren’s postretirement benefit VEBA trust an
incremental $100 million in excess of Ameren Illinois’
annual postretirement net periodic cost for regulatory
purposes.
A $38 million decrease in income tax refunds caused
primarily by a reduction in transmission and
distribution repair deductions, partially offset by
additional casualty loss deductions from an Internal
Revenue Service audit settlement. Ameren Illinois did
not make any federal income tax payments in 2011
because of accelerated deductions authorized by
economic stimulus legislation and other deductions.
Electric and natural gas margins, as discussed in
Results of Operations, which decreased by $30 million,
excluding impacts of noncash MTM transactions.
A $16 million decrease in electric purchased power
commodity over-recovered costs.
A $13 million increase in major storm restoration costs.
Reduced collection results as more customers were
past due on their bills on December 31, 2011, than on
December 31, 2010. Additionally, write-offs of
customer receivable balances increased because of
economic conditions.
A $9 million increase in taxes other than income
payments, due primarily to an increase in electricity
distribution and invested capital tax payments resulting
from the tiered rate structure for the merged entity.
A $9 million decrease in natural gas commodity over-
recovered costs under the PGA.
A $9 million increase in energy efficiency expenditures
for new customer programs. These expenditures are
recovered through customer billings over time.
The following items reduced the decrease in Ameren
Illinois’ cash from operating activities associated with
continuing operations during 2011, compared with 2010:
‰
‰
A net $120 million decrease in collateral posted with
counterparties due, in part, to a reduction in the market
price of natural gas and in contracted volumes.
Trade accounts receivable and unbilled revenues
balances decreased, primarily because of milder
weather in the fourth quarter of 2011, compared with
the fourth quarter of 2010. Those same weather
conditions caused accounts payable balances to MISO
and natural gas suppliers to decrease as less power
and natural gas was purchased. Additionally, during
2011, MISO shortened the length of its settlement
terms for all of its members. The new terms resulted in
an acceleration of payments that previously would not
have been made until 2012. These factors resulted in a
net increase of $63 million in cash from operating
activities in 2011 compared with 2010.
Deferred budget billing balances decreased by
$38 million, partially as a result of milder weather.
An $11 million decrease in interest payments, primarily
due to the redemption of first mortgage bonds in
September 2010.
‰
‰
Pension Funding
Ameren’s pension plans are funded in compliance with
income tax regulations and to meet federal funding or
regulatory requirements. As a result, Ameren expects to
fund its pension plans at a level equal to the greater of the
pension expense or the legally required minimum
contribution. Considering Ameren’s assumptions at
December 31, 2012, its investment performance in 2012,
and its pension funding policy, Ameren expects to make
annual contributions of $60 million to $150 million in each
of the next five years, with aggregate estimated
contributions of $550 million. We expect Ameren Missouri’s
and Ameren Illinois’ portion of the future funding
requirements to be 50% and 40%, respectively. These
amounts are estimates. The estimates may change with
actual investment performance, changes in interest rates,
changes in our assumptions, any pertinent changes in
government regulations, and any voluntary contributions. In
2012, Ameren contributed $134 million to its pension plans.
See Note 11 – Retirement Benefits under Part II, Item 8, of
this report for additional information.
Cash Flows from Investing Activities
2012 versus 2011
Ameren’s cash used in investing activities increased by
$262 million during 2012, compared with 2011. Capital
expenditures increased $210 million primarily because of
increased expenditures for maintenance and reliability,
boiler, turbine, and scrubber projects, which more than
offset a decrease in storm restoration costs. Cash flows
used in investing activities also increased because of a
$29 million increase in nuclear fuel expenditures due to
timing of purchases. In 2012, cash flows from investing
activities benefited from property sale proceeds, principally
attributable to $16 million in proceeds received from the
sale of Medina Valley energy center’s net property and
plant, and $18 million federal tax grants related to
renewable energy construction projects. In 2011, cash
flows from investing activities benefited from property sale
proceeds, principally attributable to $45 million of proceeds
received from the sale of Genco’s interest in its Columbia
CT energy center, as well as $8 million in proceeds from the
sale of its investment in a leveraged lease and a $9 million
payment received from an Ameren Missouri settlement with
the DOE related to nuclear waste disposal.
59
Ameren Missouri’s cash used in investing activities
increased $76 million during 2012, compared with 2011.
Capital expenditures increased $45 million primarily
because of increased expenditures for maintenance and
reliability, boiler, and turbine projects, which more than
offset a $29 million decrease in storm restoration costs.
Cash flows used in investing activities also increased due to
a $29 million increase in nuclear fuel expenditures due to
timing of purchases for the spring 2013 reload. In 2012,
cash flows from investing activities benefited from
$18 million of federal tax grants received related to
renewable energy construction projects. In 2011, cash
flows used in investing activities benefited from a $9 million
payment received from a settlement with the DOE related to
nuclear waste disposal.
Ameren Illinois’ cash used in investing activities
increased $141 million during 2012, compared with 2011.
Capital expenditures increased $91 million as a result of
increased expenditures for maintenance and reliability
capital projects, including $27 million for IEIMA projects,
which more than offset a $16 million decrease in storm
restoration costs. In 2011, cash flows from investing
activities benefited from repayments of advances previously
paid to ATXI as a result of the completion of a project under
a joint ownership agreement.
2011 versus 2010
Ameren’s cash used in investing activities decreased
by $48 million during 2011, compared with 2010. In 2011,
cash flows from investing activities benefited from an
increase of proceeds from property sales as well as
$8 million in proceeds from the sale of its investment in a
leveraged lease and a $9 million payment received from the
DOE under the terms of an Ameren Missouri settlement
with the DOE in 2011 related to nuclear waste disposal. Net
cash used for capital expenditures decreased $12 million
during 2011, compared with 2010. Reductions in capital
expenditures caused by the completion of two energy
center scrubber projects in 2010 were offset, in part, by an
increase in storm-related repair costs, an increase in
electric transmission investments, and expenditures for a
third energy center scrubber project in 2011.
Ameren Missouri’s cash used in investing activities
decreased by $73 million during 2011, compared with
2010, principally because of a $74 million decrease in
capital expenditures and a $9 million payment received
from the DOE in 2011 under the terms of the settlement
with the DOE related to nuclear waste disposal. These cash
benefits were reduced by a $6 million net decrease in
nuclear decommissioning trust fund activities. Capital
expenditures were lower in 2011 as a result of the
completion in 2010 of two scrubbers at Ameren Missouri’s
Sioux energy center and boiler projects, which offset a
$28 million increase in capital expenditures related to
storm-related repair costs.
Ameren Illinois’ cash used in investing activities
increased by $49 million during 2011, compared with 2010.
There was a $70 million increase in capital expenditures,
primarily as a result of increased investment in electric
transmission assets and a $17 million increase in capital
expenditures related to storm-related repair costs. In 2011,
cash flows from investing activities benefited from the
repayments of advances previously paid to ATXI, as a result
of the completion of a project under a joint ownership
agreement. In 2010, cash flows from investing activities
benefited from the proceeds received on an intercompany
note receivable, offset, in part, by advances to ATXI.
Capital Expenditures
The following table presents the capital expenditures
by the Ameren Companies for the years ended
December 31, 2012, 2011, and 2010:
2012
2011
2010
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . $
Ameren Missouri . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . .
Merchant Generation . . . . . . . . . . . . .
1,240 $
595
442
178
1,030 $
550
351
153
1,042
624
281
101
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries and the elimination of intercompany transfers.
Ameren’s 2012 capital expenditures principally
consisted of the following expenditures at its subsidiaries.
Ameren Missouri spent $30 million on the replacement of
the Callaway reactor head, scheduled to be replaced during
the 2013 Callaway refueling and maintenance outage and
$23 million on a boiler upgrade project. Ameren Illinois
spent $27 million on IEIMA-related expenditures. Merchant
Generation spent $141 million as part of the construction of
two scrubbers at the Newton energy center to comply with
environmental regulations. Other capital expenditures were
made principally to maintain, upgrade, and expand the
reliability of the transmission and distribution systems of
Ameren Missouri and Ameren Illinois, as well as to fund
various energy center upgrades.
Ameren’s 2011 capital expenditures principally
consisted of the following expenditures at its subsidiaries.
Ameren Missouri spent $24 million on building its Maryland
Heights energy center and $31 million for storm-related
repair costs. Ameren Illinois incurred storm-related repair
costs of $20 million. Merchant Generation spent $75 million
toward scrubbers at the Newton and Coffeen energy centers
to comply with environmental regulations. Other capital
expenditures were made principally to maintain, upgrade,
and expand the reliability of the transmission and
distribution systems of Ameren Missouri and Ameren
Illinois, as well as to fund various energy center upgrades.
Ameren’s 2010 capital expenditures principally
consisted of the following expenditures at its subsidiaries.
Ameren Missouri spent $130 million toward two scrubbers
at its Sioux energy center, which were completed in 2010.
At Merchant Generation, there was a cash outlay of
$29 million for energy center scrubber projects. The
scrubbers are necessary to comply with environmental
regulations. Other capital expenditures were made
60
principally to maintain, upgrade, and expand the reliability
of the transmission and distribution systems of Ameren
Missouri and Ameren Illinois, as well as to fund various
energy center upgrades.
The following table estimates Ameren’s capital
expenditures that will be incurred from 2013 through 2017,
including construction expenditures, capitalized interest for
the Merchant Generation business, allowance for funds
used during construction for Ameren’s rate-regulated utility
businesses, and estimated expenditures for compliance
with known and existing environmental regulations. The
table below includes AER’s estimated capital expenditures
for the installation of the two scrubbers at the Newton
energy center, which are estimated to be installed by the
end of 2019. See Outlook and also Note 15 – Commitments
and Contingencies under Part II, Item 8, of this report for
further discussion of the impact of declining power prices
on the Merchant Generation segment and the Newton
energy center construction milestones. The table below
assumes that Ameren continues to own the AER energy
centers through 2017. See also Note 17 – Impairment and
Other Charges under Part II, Item 8, of this report for
further discussion on Ameren’s plan to exit the Merchant
Generation business.
2013
2014 - 2017
Total
. . . . . . . $
Ameren Missouri
Ameren Illinois . . . . . . . . .
AER . . . . . . . . . . . . . . . . .
ATXI . . . . . . . . . . . . . . . . .
Other(a) . . . . . . . . . . . . . . .
720
695
70
60
(5)
$ 2,250 - $ 3,045
3,250
315
1,310
80
2,400 -
230 -
965 -
60 -
$ 2,970 - $ 3,765
3,945
385
1,370
75
3,095 -
300 -
1,025 -
55 -
Ameren . . . . . . . . . . . . . . $ 1,540
$ 5,905 - $ 8,000
$ 7,445 - $ 9,540
from our portfolio, such as the December 2012 Ameren
announcement to exit the Merchant Generation business
before the end of the previously estimated useful lives of its
long-lived assets, the type of generation asset technology
that will be employed, and whether capacity or power may
be purchased, among other things. Additionally, we
continually review the reliability of our transmission and
distribution systems, expected capacity needs, and
opportunities for transmission investments. The timing and
amount of investments could vary because of changes in
expected capacity, the condition of transmission and
distribution systems, and our ability and willingness to
pursue transmission investments, among other things. Any
changes in future generation, transmission or distribution
needs could result in significant capital expenditures or
losses being incurred, which could be material.
Environmental Capital Expenditures
Ameren, Ameren Missouri and Merchant Generation
will incur significant costs in future years to comply with
existing and known federal and state regulations including
those requiring the reduction of SO2, NOx, and mercury
emissions from coal-fired energy centers.
See Note 15 – Commitments and Contingencies under
Part II, Item 8, of this report for a discussion of existing
environmental laws and regulations that affect, or may
affect, our facilities and capital costs to comply with such
laws and regulations, as well as our assessment of the
potential impacts of the EPA’s proposed regulation of CCR
and the finalized MATS, as of December 31, 2012.
(a)
Includes the elimination of intercompany transfers.
Cash Flows from Financing Activities
Ameren Missouri’s estimated capital expenditures
include transmission, distribution, and generation-related
investments, as well as expenditures for compliance with
the environmental regulations discussed below. Ameren
Illinois’ estimated capital expenditures are primarily for
electric and natural gas transmission and distribution-
related investments, and estimated capital expenditures
incremental to historical average electric delivery capital
expenditures to modernize its distribution system pursuant
to the IEIMA. Until the uncertainty surrounding how the
IEIMA will ultimately be implemented is removed, Ameren
Illinois is slowing its IEIMA capital spending. Even though it
is proceeding on a slower schedule, Ameren Illinois intends
to meet its IEIMA capital spending requirements. For
additional information on the IEIMA, see Note 2 – Rate and
Regulatory Matters under Part II, Item 8, of this report.
AER’s estimated capital expenditures are primarily for
compliance with environmental regulations. Estimated
capital expenditures for ATXI include the MISO-approved
multi-value transmission projects.
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
2012 versus 2011
During 2012, we replaced and extended the expiration
of our credit agreements. We reduced our reliance on short-
term debt while maintaining adequate cash balances for
working capital needs.
Ameren’s net cash used in financing activities
decreased during 2012, compared with 2011. Repayments
of net short-term debt and credit agreement borrowings
decreased by $433 million in 2012 compared with 2011.
The decrease in cash provided by operating activities in
2012, combined with the increase in capital expenditures,
resulted in less cash available to fund financing activities.
However, Ameren was still able to repay all outstanding
short-term debt that existed at the beginning of the year in
2012. In 2012, Ameren subsidiaries issued $885 million in
senior debt and used the proceeds, together with other
available cash, to repurchase, redeem, and repay existing
long-term indebtedness of $754 million and to pay related
premiums. In 2011, Ameren Illinois funded the $150 million
maturity of its senior secured notes with cash on hand and
operating cash flows. There was also a reduction in refunds
of advances previously received from generators of
$73 million due to project completion in 2011. In 2011,
common stock issued for DRPlus and the 401(k) plan
increased cash flows from financing activities by
61
$65 million. In 2012, Ameren shares were purchased in the
open market for DRPlus and the 401(k) plan, resulting in
noncash financing activity of $7 million due to the timing of
DRPlus common stock dividend funding.
Ameren Missouri’s net cash used in financing activities
decreased during 2012, compared with 2011. In September
2012, Ameren Missouri issued $485 million of 3.90% senior
secured notes and used the proceeds, together with other
available cash, to repurchase and repay existing long-term
indebtedness of $422 million and to pay related premiums.
In 2011, refunds of advances previously received from
generators decreased cash flows from financing activities by
$19 million as a result of project completion.
Ameren Illinois’ net cash used in financing activities
decreased during 2012, compared with 2011. In August
2012, Ameren Illinois issued $400 million of 2.70% senior
secured notes and used the proceeds, together with other
available cash, to repurchase and redeem existing long-
term indebtedness of $332 million and pay related
premiums. In 2011, Ameren Illinois funded the $150 million
maturity of its senior secured notes utilizing cash on hand
and operating cash flows. In 2012, Ameren Illinois common
stock dividends decreased by $138 million. Additionally,
there was a reduction in refunds of advances previously
received from generators of $53 million due to project
completion in 2011.
2011 versus 2010
During 2011, we reduced our reliance on borrowings
from short-term debt and credit agreements, and we
reduced long-term debt outstanding while maintaining
adequate cash balances for working capital needs.
Ameren’s cash used in financing activities increased in
2011, compared with 2010. During 2011, Ameren’s cash
flow from operating activities of $1.9 billion exceeded its
capital expenditures of $1.0 billion and common stock
dividend requirements of $375 million. Ameren used this
cash as well as cash on hand to repay $581 million of short-
term debt and credit agreement borrowings, to redeem
$155 million of long-term debt, and to repay $73 million of
advances received from generators due to project
completion. During 2010, Ameren redeemed $310 million of
long-term debt and $52 million of preferred stock.
Ameren Missouri’s cash used in financing activities
increased by $96 million in 2011, compared with 2010.
During 2011, Ameren Missouri’s cash flow from operating
activities of $1.1 billion exceeded its combined capital and
nuclear fuel expenditures of $612 million. Ameren Missouri
used this cash to pay common stock dividends of
$403 million and to repay $19 million of advances
previously received from generators due to project
completion. During 2010, Ameren Missouri paid common
stock dividends of $235 million; redeemed $70 million of
long-term debt, including its 7.69% Series A subordinated
debentures; and it redeemed all outstanding shares of its
$7.64 Series preferred stock.
Ameren Illinois’ net cash used in financing activities
increased by $179 million in 2011 compared with 2010.
Ameren Illinois’ common stock dividend increased
$194 million compared with 2010. In June 2011, Ameren
Illinois’ 6.625% $150 million senior secured notes matured
and were repaid and retired using cash on hand. During
2010, in connection with the Ameren Illinois Merger,
Ameren Illinois (formerly CILCO) redeemed all of its
preferred stock and all $40 million of its 7.61% Series
1997-2 first mortgage bonds (formerly CIPS). Net
repayments of generator advances received for construction
increased $25 million in 2011 compared with 2010.
Credit Agreement Borrowings and Liquidity
The liquidity needs of Ameren, Ameren Missouri and
Ameren Illinois are typically supported through the use of
available cash, short-term intercompany borrowings, and
drawings under committed bank credit agreements, or
commercial paper issuances. See Note 4 – Short-term Debt
and Liquidity under Part II, Item 8, of this report for
additional information on credit agreements, short-term
borrowing activity, commercial paper issuances, relevant
interest rates, and borrowings under Ameren’s utility and
non-state-regulated subsidiary money pool arrangements.
The following table presents the committed 2012 Credit Agreements of Ameren, Ameren Missouri, and Ameren Illinois,
and the credit capacity available under such agreements, considering reductions for letters of credit, as of December 31, 2012:
Expiration
Borrowing Capacity
Credit Available
Ameren and Ameren Missouri:
2012 Missouri Credit Agreement(a)(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
November 2017
$
1,000
$
1,000
Ameren and Ameren Illinois:
2012 Illinois Credit Agreement(a)(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
November 2017
1,100
Ameren:
Less: Letters of credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(c)
1,100
(9)
Total
$
2,100
$
2,091
(a) Certain Ameren subsidiaries not party to the 2012 Credit Agreements may access these credit agreements through intercompany borrowing
arrangements.
(b) Each credit agreement expires on November 14, 2017. The borrowing sublimits of Ameren Missouri and Ameren Illinois will mature and expire
on November 13, 2013, subject to extension on a 364-day basis, as requested by the borrower and approved by the lenders, or for a longer
period upon receipt of any and all required federal or state regulatory approvals, as permitted under each credit agreement, but in no event later
than November 14, 2017. Ameren Missouri and Ameren Illinois will seek state regulatory approval to extend the maturity date of their
borrowing sublimits under the 2012 Credit Agreements to November 14, 2017.
(c) Not applicable.
62
The 2012 Credit Agreements are used to borrow cash,
to issue letters of credit, and to support issuances under
Ameren’s, Ameren Missouri’s, and Ameren Illinois’
commercial paper programs. Any of the 2012 Credit
Agreements are available to Ameren to support borrowings
under Ameren’s commercial paper program, subject to
borrowing sublimits. The 2012 Missouri Credit Agreement
is available to support borrowings under Ameren Missouri’s
commercial paper program, and the 2012 Illinois Credit
Agreement is available to support borrowings under
Ameren Illinois’ commercial paper program.
The maximum aggregate amount available to each
borrower under each facility is shown in the following table
(such amount being such borrower’s “Borrowing
Sublimit”):
2012 Missouri
Credit Agreement
2012 Illinois
Credit Agreement
Ameren . . . . . . . . . . . . . .
Ameren Missouri . . . . . . .
Ameren Illinois . . . . . . . .
$
500
800
(a)
$
300
(a)
800
(a) Not applicable.
Subject to applicable regulatory short-term borrowing
authorizations, these credit arrangements are also available
to 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, 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, Ameren
Illinois, and Ameren Services enables Ameren Illinois to
make short-term borrowings directly from Ameren.
Pursuant to the terms of the unilateral borrowing
agreement, the aggregate amount of borrowings
outstanding at any time by Ameren Illinois under the
unilateral borrowing agreement and the utility money pool
agreement, together with any outstanding Ameren Illinois
external credit facility borrowings or commercial paper
issuances, may not exceed $500 million, pursuant to the
authorization from the ICC. Ameren Illinois did not borrow
under the unilateral borrowing agreement during 2012 or
2011. Ameren Services is responsible for operation and
administration of the money pool agreements. See Note 4 –
Short-term Debt and Liquidity under Part II, Item 8, of this
report for a detailed explanation of the money pool
arrangements and the unilateral borrowing agreement.
The issuance of short-term debt securities by
Ameren’s utility subsidiaries is subject to approval by FERC
under the Federal Power Act. In April 2012, FERC issued an
order authorizing the issuance of up to $1 billion of short-
term debt securities for Ameren Missouri. The authorization
was effective immediately and terminates on March 31,
2014. On September 20, 2012, FERC issued an order
authorizing the issuance of up to $1 billion of short-term
debt securities. The authorization was effective as of
October 1, 2012 and terminates on September 30, 2014.
The issuance of short-term debt securities by Ameren
is not subject to approval by any regulatory body.
The Ameren Companies continually evaluate the
adequacy and appropriateness of their liquidity
arrangements given changing business conditions. When
business conditions warrant, changes may be made to
existing credit agreements or to 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) for the years 2012, 2011, and 2010 for the
Ameren Companies and Genco. For additional information related to the terms and uses of these issuances and the sources of
funds and terms for the redemptions, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.
Month Issued, Redeemed,
Repurchased or Matured
2012
2011
2010
Issuances
Long-term debt
Ameren Missouri:
3.90% Senior secured notes due 2042 . . . . . . . . . . . . . . . . . . . . . . . . .
September
Ameren Illinois:
2.70% Senior secured notes due 2022 . . . . . . . . . . . . . . . . . . . . . . . . .
August
Total Ameren long-term debt issuances . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock
Ameren:
DRPlus and 401(k) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Various
Total common stock issuances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren long-term debt and common stock issuances . . . . . . . . . .
$
$
$
$
$
482
$
400
882
-
-
882
$
$
$
$
-
-
-
65
65
65
$
$
$
$
$
-
-
-
80
80
80
63
Month Issued, Redeemed,
Repurchased or Matured
2012
2011
2010
Redemptions, Repurchases and Maturities
Long-term debt
Ameren Missouri:
City of Bowling Green capital lease (Peno Creek CT)
. . . . . . . . . . . . . . . . . .
5.25% Senior secured notes due 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.00% Senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.70% Senior secured notes due 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.10% Senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.10% Senior secured notes due 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.69% Series A subordinated deferrable interest debentures due 2036 . . . .
Ameren Illinois:
6.625% Senior secured notes due 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9.75% Senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.25% Senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2000 Series A 5.50% pollution control revenue bonds due 2014 . . . . . . . . .
7.61% Series 1997-2 first mortgage bonds due 2017 . . . . . . . . . . . . . . . . .
6.20% Series 1992B due 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
Various
September
September
September
September
September
September
June
August
August
August
September
November
Senior notes Series D 8.35% due 2010 . . . . . . . . . . . . . . . . . . . . . . . . . .
November
Total Ameren long-term debt redemptions, repurchases and maturities . . . . . .
Preferred stock
Ameren Missouri:
$7.64 Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
August
Ameren Illinois:
4.50% Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.64% Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.08% Series(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.20% Series(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.26% Series(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.42% Series(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.70% Series(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.75% Series(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren preferred stock redemptions and repurchases . . . . . . . . . . . . . .
Total Ameren long-term debt and preferred stock redemptions, repurchases
and maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
August
August
September
September
September
September
September
September
$
$
$
$
$
$
5
173
71
121
1
56
-
-
87
194
51
-
1
-
$
5
-
-
-
-
-
-
150
-
-
-
-
-
-
760
$
155
$
4
-
-
-
-
-
66
-
-
-
-
40
-
200
310
-
-
-
-
-
-
-
-
-
-
760
$
$
$
-
-
-
-
-
-
-
-
-
-
155
$
33
11
8
7
5
4
3
5
9
85
395
$
$
(a)
In September 2010, Ameren contributed to the capital of Ameren Illinois (formerly IP), without the payment of any consideration, all of the IP
preferred stock owned by Ameren ($33 million). IP canceled these preferred shares.
In June 2012, Ameren, Ameren Missouri and Ameren
Illinois filed a Form S-3 shelf registration statement
registering the issuance of an indeterminate amount of
certain types of securities, which expires in June 2015.
Ameren filed a Form S-3 registration statement with
the SEC in June 2011, 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. In 2012, Ameren shares were
purchased in the open market for DRPlus and its 401(k)
plan. Under DRPlus and its 401(k) plan, Ameren issued
2.2 million and 3.0 million shares of common stock in 2011
and 2010, respectively, which were valued at $65 million
and $80 million for the respective years.
The Ameren Companies may sell securities registered
under their effective registration statements if market
conditions and capital requirements warrant such sales.
Any offer and sale will be made only by means of a
prospectus that meets the requirements of the Securities
Act of 1933 and the rules and regulations thereunder.
Indebtedness Provisions and Other Covenants
See Note 4 – Short-term Debt and Liquidity and
Note 5 – Long-term Debt and Equity Financings under
Part II, Item 8, of this report for a discussion of covenants
and provisions (and applicable cross-default provisions)
contained in our bank credit and term loan agreements and
in certain of the Ameren Companies’ indentures and articles
of incorporation.
At December 31, 2012, Ameren, Ameren Missouri,
Ameren Illinois and Genco were in compliance with the
provisions and covenants contained within their credit
agreements, indentures, 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
64
requirements not satisfied by our operating cash flows.
Inability to raise capital on reasonable terms, particularly
during times of uncertainty in the capital markets, could
negatively affect our ability to maintain and expand our
businesses. After assessing its current operating
performance, liquidity, and credit ratings (see Credit
Ratings below), Ameren, Ameren Missouri and Ameren
Illinois each believes that it will continue to have access to
the capital markets. However, events beyond Ameren’s,
Ameren Missouri’s and Ameren Illinois’ control may create
uncertainty in the capital markets or make access to the
capital markets uncertain or limited. Such events could
increase our cost of capital and adversely affect our ability
to access the capital markets.
Merchant Generation’s operating results and operating
cash flows are significantly affected by changes in market
prices for power, which have significantly decreased over
the past few years. Under the provisions of its indenture,
Genco may not borrow additional funds from external,
third-party sources if its interest coverage ratio is less than
a specified minimum or if its leverage ratio is greater than a
specified maximum. Based on projections as of
December 31, 2012, of its operating results and cash flows,
Genco expects that, by the end of the first quarter of 2013,
its interest coverage ratio will be less than the minimum
ratio required for the company to borrow additional funds
from external third-party sources. Genco’s indenture does
not restrict intercompany borrowings from Ameren’s non-
state-regulated subsidiary money pool. However,
borrowings from the money pool are subject to Ameren’s
control, and if a Genco intercompany financing need were
to arise, borrowings from the non-state-regulated
subsidiary money pool by Genco would be dependent on
consideration by Ameren of the facts and circumstances
existing at that time. While it remains a business of Ameren,
the Merchant Generation segment, including Genco, seeks
to fund its operations internally and therefore seeks not to
rely on financing from Ameren or external, third-party
sources.
Should a financing need arise at Genco, its sources of
liquidity include available cash on hand, a return of money
pool advances, money pool borrowings at the discretion of
Ameren, sale of an asset or multiple assets, or exercising
the put option agreement with AERG. Given current power
market conditions and cash flow requirements, it is more
likely than not that Genco will sell one or more of its three
natural gas-fired energy centers before the put option
agreement expires on March 28, 2014. Based on current
projections, it is probable during 2013 that Genco will need
mid-month liquidity from either asset sales or money pool
borrowings to support working capital needs. Based on
projections as of December 31, 2012, Genco estimates
these financing sources are adequate to support its
operations in 2013. See Note 14 – Related Party
Transactions, under Part II, Item 8, of this report for
additional information regarding Genco’s put option
agreement with AERG and Ameren’s guarantee of AERG’s
contingent obligations under the put option agreement.
Dividends
Ameren paid to its shareholders common stock
dividends totaling $382 million, or $1.60 per share, in 2012,
$375 million, or $1.555 per share, in 2011, and
$368 million, or $1.54 per share, in 2010. The payout rate
based on net income in 2011 was 72%. The payout of
common stock dividends exceeded net income in 2012 and
2010 because of the noncash impairment and other charges
recorded during those years. Dividends paid to common
shareholders in relation to net cash provided by operating
activities for the same periods were 23% in 2012, 20% in
2011, and 20% in 2010.
The amount and timing of dividends payable on
Ameren’s common stock are within the sole discretion of
Ameren’s board of directors. The board of directors has not
set specific targets or payout parameters when declaring
common stock dividends. However, as it has done in the
past, the board of directors is expected to consider various
issues, including Ameren’s overall payout ratio, payout
ratios of our peers, projected cash flow and potential future
cash flow requirements, historical earnings and cash flow,
projected earnings, impacts of regulatory orders or
legislation, and other key business considerations. On
February 8, 2013, the board of directors of Ameren declared
a quarterly dividend on Ameren’s common stock of
40 cents per share, payable on March 29, 2013, to
stockholders of record on March 13, 2013.
Certain of our financial agreements and corporate
organizational documents contain covenants and conditions
that, among other things, restrict the Ameren Companies’
payment of dividends in certain circumstances.
Ameren Illinois’ 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 dividend payments on its common stock.
Specifically, Genco cannot pay dividends on its common
stock unless the company’s actual interest coverage ratio
for the most recently ended four fiscal quarters and the
interest coverage ratios projected by management for each
of the subsequent four six-month periods are greater than a
specified minimum level. Based on projections as of
December 31, 2012, of Genco’s operating results and cash
flows in 2013 and 2014, we did not believe that Genco
would achieve the minimum interest coverage ratio
necessary to pay dividends on its common stock for each of
the subsequent four six-month periods ending June 30,
2013, December 31, 2013, June 30, 2014, or December 31,
2014. As a result, Genco was restricted from paying
dividends on its common stock as of December 31, 2012,
and we expect Genco will be unable to pay dividends on its
common stock in 2013, 2014, and 2015. See Note 5 –
Long-term Debt and Equity Financings under Part II, Item 8,
of this report for additional information on Genco’s
indenture provisions.
65
Ameren Missouri and Ameren Illinois, as well as certain
other nonregistrant Ameren subsidiaries, are subject to
Section 305(a) of the Federal Power Act, which makes it
unlawful for any officer or director of a public utility, as
defined in the Federal Power Act, to participate in the making
or paying of any dividend from any funds “properly included
in capital account.” The meaning of this limitation has never
been clarified under the Federal Power Act or FERC
regulations. However, FERC has consistently interpreted the
provision to allow dividends to be paid as long as (1) the
source of the dividends is clearly disclosed, (2) the dividends
are not excessive, and (3) there is no self-dealing on the part
of corporate officials. At a minimum, Ameren believes that
dividends can be paid by its subsidiaries that are public
utilities from net income and retained earnings. In addition,
under Illinois law, Ameren Illinois may not pay any dividend
on its stock unless, among other things, its earnings and
earned surplus are sufficient to declare and pay a dividend
after provision is made for reasonable and proper reserves, or
unless Ameren Illinois has specific authorization from the ICC.
In its application for the FERC orders approving the
Ameren Illinois Merger and the AERG distribution, Ameren
committed itself to maintain a minimum of 30% equity in its
capital structure at Ameren Illinois following the Ameren
Illinois Merger and the AERG distribution.
At December 31, 2012, Ameren, Ameren Missouri and
Ameren Illinois were not restricted from paying dividends.
At December, 31, 2012, the amount of restricted net
assets of wholly owned subsidiaries of Ameren that may
not be distributed to Ameren in the form of a loan or
dividend was $2 billion.
The following table presents common stock dividends paid by Ameren Corporation to its common stockholders and by
Ameren’s registrant subsidiaries to Ameren. No dividends were paid by AER to Ameren in 2012, 2011, or 2010.
Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends paid by Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
400
189
382
$
403
327
375
$
235
133
368
2012
2011
2010
Certain of the Ameren Companies have issued
preferred stock, which provides for cumulative preferred
stock dividends. Each company’s board of directors
considers the declaration of the preferred stock dividends to
shareholders of record on a certain date, stating the date on
which the dividend is payable and the amount to be paid.
See Note 5 – Long-term Debt and Equity Financings under
Part II, Item 8, of this report for further detail concerning
the preferred stock issuances.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2012. See Note 11 – Retirement Benefits
under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These
expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order
commitments are not included.
Total
Less than
1 Year
1 - 3 Years
3 - 5 Years
After 5
Years
Ameren:(a)
. . . . . . . . . . . . . . . . . . . . . . .
Long-term debt and capital lease obligations(b)(c)
Interest payments(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases(e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f)
$
6,992
4,340
272
8,338
$
355
428
31
1,891
$
654
742
53
2,808
$
1,076
664
51
1,948
$
4,907
2,506
137
1,691
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
19,942
$
2,705
$
4,257
$
3,739
$
9,241
Ameren Missouri:
Long-term debt and capital lease obligations(c) . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payments(d)
Operating leases(e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f)
$
$
4,013
2,846
123
5,121
205
225
12
841
$
229
422
24
1,738
$
697
372
25
1,619
$
2,882
1,827
62
923
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
12,103
$
1,283
$
2,413
$
2,713
$
5,694
Ameren Illinois:
Long-term debt(b)(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payments(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases(e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
1,729
790
7
2,446
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
4,972
$
150
106
1
695
952
$
$
-
188
2
796
986
$
$
379
174
2
216
771
$
1,200
322
2
739
$
2,263
Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.
(a)
(b) Excludes fair-market value adjustments of Ameren Illinois’ long-term debt of $4 million.
66
(c) Excludes unamortized discount and premium of $15 million at Ameren, $7 million at Ameren Missouri and $6 million at Ameren Illinois.
(d) The weighted-average variable-rate debt has been calculated using the interest rate as of December 31, 2012.
(e) Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $2 million, $1 million, and $1 million
for Ameren, Ameren Missouri and Ameren Illinois, respectively, for these items is included in the Less than 1 Year, 1 – 3 Years, and 3 – 5 Years
columns.
(f) See Other Obligations in Note 15 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included
herein.
As of December 31, 2012, the amounts of
unrecognized tax benefits under the authoritative accounting
guidance for uncertain tax positions were $156 million,
$136 million, and $13 million for Ameren, Ameren Missouri,
and Ameren Illinois, respectively. It is reasonably possible to
expect that the settlement of an unrecognized tax benefit will
result in an underpayment or overpayment of tax and related
interest. However, there is a high degree of uncertainty with
respect to the timing of cash payments or receipts
associated with unrecognized tax benefits. The amount and
timing of certain payments or receipts is not reliably
estimable or determinable at this time. See Note 13 –
Income Taxes under Part II, Item 8, of this report for
information regarding the Ameren Companies’ unrecognized
tax benefits and related liabilities for interest expense.
Off-Balance-Sheet Arrangements
At December 31, 2012, none of the Ameren Companies
had 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. See Note 14 – Related Party Transactions
under Part II, Item 8, of this report for Ameren (parent)
guarantees on behalf of its subsidiaries.
Credit Ratings
The credit ratings of the Ameren Companies affect our
liquidity, our access to the capital markets and credit
markets, our cost of borrowing under our credit facilities
and collateral posting requirements under commodity
contracts.
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 . . . . . . . . . . .
Ameren Missouri:
Issuer/corporate credit rating . .
Secured debt . . . . . . . . . . . . . . .
Ameren Illinois:
Issuer/corporate credit rating . .
Secured debt . . . . . . . . . . . . . . .
. . . . . . .
Senior unsecured debt
Genco:
Issuer/corporate credit rating . .
. . . . . . .
Senior unsecured debt
Baa3
Baa3
P-3
Baa2
A3
Baa2
A3
Baa2
-
B2
BBB-
BB+
A-3
BBB-
BBB+
BBB-
BBB+
BBB-
CCC+
CCC+
BBB
BBB
F2
BBB+
A
BBB-
BBB+
BBB
CC
CCC-
67
The cost of borrowing under our credit facilities can
also increase or decrease depending upon the credit ratings
of the borrower. A credit rating is not a recommendation to
buy, sell, or hold securities. It should be evaluated
independently of any other rating. Ratings are subject to
revision or withdrawal at any time by the rating
organization.
Collateral Postings
Any adverse change in the Ameren Companies’ and
Genco’s 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 natural gas supply, among other things,
resulting in a negative impact on earnings. Cash collateral
postings and prepayments made with external parties,
including postings related to exchange-traded contracts at
December 31, 2012, were $98 million, $13 million, and
$58 million at Ameren, Ameren Missouri and Ameren
Illinois, respectively. The amount of cash collateral external
counterparties posted with Ameren and Ameren Illinois was
$5 million and $2 million, respectively, at December 31,
2012. Sub-investment-grade issuer or senior unsecured
debt ratings (lower than “BBB-” or “Baa3”) at December 31,
2012, could have resulted in Ameren, Ameren Missouri,
Ameren Illinois or AER being required to post additional
collateral or other assurances for certain trade obligations
amounting to $245 million, $71 million, $84 million, and
$90 million, respectively.
Changes in commodity prices could trigger additional
collateral postings and prepayments at current credit
ratings. If market prices were 15% higher than
December 31, 2012, levels in the next 12 months and 20%
higher thereafter through the end of the term of the
commodity contracts, then Ameren, Ameren Missouri,
Ameren Illinois, and AER could be required to post
additional collateral or other assurances for certain trade
obligations up to $174 million, $6 million, $- million, and
$168 million, respectively. If market prices were 15% lower
than December 31, 2012, levels in the next 12 months and
20% lower thereafter through the end of the term of the
commodity contracts, then Ameren, Ameren Missouri,
Ameren Illinois, and AER could be required to post
additional collateral or other assurances for certain trade
obligations up to $152 million, $4 million, $31 million, and
$117 million, respectively.
OUTLOOK
Ameren seeks to earn competitive returns on its
investments in its businesses. Ameren Missouri and
Ameren Illinois are seeking to improve their regulatory
frameworks and cost recovery mechanisms. At the same
time, Ameren’s rate-regulated businesses are pursuing
constructive regulatory outcomes within existing
frameworks and are seeking to align their overall spending,
both operating and capital, with economic conditions and
cash flows provided by their regulators. Consequently,
Ameren’s rate-regulated businesses are focused on
minimizing the gap between allowed and earned returns on
equity. Ameren’s Merchant Generation segment maintains a
fleet of coal-fired and natural gas-fired energy centers. In
December 2012, Ameren determined that it intends to, and
it is probable that it will, exit its Merchant Generation
business before the end of the previously estimated useful
lives of that business’s long-lived assets. As a result,
Ameren no longer considers the Merchant Generation
segment to be a core component of its future business
strategy. Ameren has begun planning to reduce, and
ultimately eliminate, the Merchant Generation segment’s,
including Genco’s, reliance on Ameren’s financial support
and shared services support. Ameren intends to allocate its
capital resources to those business opportunities, including
electric and natural gas transmission, which offer the most
attractive risk-adjusted return potential.
Below are some key trends, events, and uncertainties
that are reasonably likely to affect the Ameren Companies’
results of operations, financial condition, or liquidity, as well
as their ability to achieve strategic and financial objectives,
for 2013 and beyond.
Rate-Regulated Operations
‰
‰
Ameren’s strategy for earning competitive returns on
its rate- regulated investments involves meeting
customer energy needs in an efficient fashion, working
to enhance regulatory frameworks, making timely and
well-supported rate case filings, and aligning overall
spending with those rate case outcomes, economic
conditions and return opportunities.
In December 2012, the ICC issued an order with
respect to Ameren Illinois’ update IEIMA filing
approving an electric delivery service revenue
requirement that was a $70 million decrease from the
requirement allowed in the pre-IEIMA 2010 electric
delivery service rate order. The new rates became
effective on January 1, 2013. We believe that Ameren
Illinois’ participation in the performance-based formula
ratemaking framework pursuant to the IEIMA will better
enable Ameren Illinois to earn its allowed return on
equity for its electric delivery service business. This
framework is expected to give Ameren Illinois the
earnings predictability to invest in modernizing its
distribution system. However, the ICC’s orders in 2012
for Ameren Illinois’ initial and update filings jeopardize
Ameren Illinois’ ongoing ability to implement
infrastructure improvements to the extent and on the
timetable envisioned in the IEIMA. Ameren Illinois has
appealed both of the ICC’s 2012 electric rate orders to
the courts and is also seeking a legislative solution to
address the ICC’s implementation of the IEIMA.
Although Ameren Illinois intends to meet its IEIMA
capital spending requirements, it is proceeding on a
slower investment schedule than previously
contemplated until the uncertainty surrounding how the
IEIMA will ultimately be implemented is removed.
The IEIMA provides for an annual reconciliation of the
revenue requirement necessary to reflect the actual
costs incurred in a given year with the revenue
requirement that was in effect for that year.
Consequently, Ameren Illinois’ 2013 electric delivery
service revenues will be based on its 2013 actual
recoverable costs, rate base, and return on common
equity as calculated under the IEIMA’s performance-
based formula ratemaking framework. The 2013
revenue requirement is expected to be higher than the
2012 revenue requirement, even though the amount
added to the monthly average yields of the 30-year
United States treasury bonds will decrease to 580 basis
points in 2013 from 590 basis points in 2012, due to
expected increases in recoverable costs and rate base
growth.
Ameren Illinois’ 2012 revenue requirement under the
IEIMA framework was lower than the revenue
requirement included in both the ICC’s 2010 electric
rate order and the ICC’s September 2012 order related
to Ameren Illinois’ initial IEIMA filing. Consequently,
Ameren Illinois recorded a $55 million regulatory
liability to represent its estimate of the probable
decrease in electric delivery service revenues expected
to be approved by the ICC in December 2013 to provide
Ameren Illinois recovery of all prudently and reasonably
incurred costs and an allowed rate of return on
common equity for 2012. Any decrease in electric
delivery service revenues approved by the ICC in
December 2013 will be refunded to customers during
2014 with interest pursuant to the provisions of the
IEIMA.
In January 2013, Ameren Illinois filed a request with
the ICC to increase its annual revenues for natural gas
delivery service by $50 million. In an attempt to reduce
regulatory lag, Ameren Illinois used a future test year,
2014, in this proceeding. A decision in this proceeding
is required by December 2013.
In December 2012, the MoPSC issued an order
approving an increase for Ameren Missouri in annual
revenues for electric service of $260 million, including
$84 million related to an anticipated increase in
normalized net fuel costs above the net fuel costs
included in base rates previously authorized by the
MoPSC in its 2011 electric rate order. The annual
increase also includes $80 million for recovery of the
costs associated with energy efficiency programs under
the MEEIA. The remaining annual increase of
$96 million approved by the MoPSC was for energy
infrastructure investments and other non-fuel costs,
including $10 million for increased pension and other
post-employment benefit costs and $6 million for
increased amortization of regulatory assets. The new
rates became effective on January 2, 2013.
The MoPSC’s December 2012 electric rate order
approved Ameren Missouri’s implementation of MEEIA
‰
‰
‰
‰
‰
68
megawatthour savings targets, energy efficiency
programs, and associated cost recovery mechanisms
and incentive awards. Beginning in 2013, Ameren
Missouri will invest approximately $147 million over
the next three years for energy efficiency programs.
The order allows for Ameren Missouri to collect its
program costs and 90% of its projected lost revenue
from customers over the same three years starting on
January 2, 2013. The remaining 10% of projected lost
revenue is expected to be recovered as part of future
rate proceedings. Additionally, the order provides for an
incentive award based on the achievement of certain
energy efficiency goals, including approximately
$19 million if 100% of Ameren Missouri’s energy
efficiency goals are achieved during the three-year
period, with the potential to earn more if energy
savings exceeds those goals. The recovery of the
incentive award from customers, if the energy
efficiency goals are achieved, would begin after the
three-year energy efficiency plan is complete and upon
the effective date of an electric service rate order or
potentially with the future adoption of a rider
mechanism.
As they continue to experience cost recovery pressures,
Ameren Missouri and Ameren Illinois expect to seek
regular electric and natural gas rate increases and
timely cost recovery and tracking mechanisms from
their regulators. Ameren Missouri and Ameren Illinois
will also seek legislative solutions to address cost
recovery pressures. These pressures include a weak
economy, customer conservation efforts, the impacts
of energy efficiency programs, increased investments
and expected future investments for environmental
compliance, system reliability improvements, and new
baseload capacity, including renewable energy
requirements. Increased investments also result in
higher depreciation and financing costs. Increased
costs are also expected from rising employee benefit
costs, higher property and income taxes, and higher
insurance premiums as a result of insurance market
conditions and industry loss experience, among other
things.
The MoPSC issued an order, in April 2011, with respect
to its review of Ameren Missouri’s FAC for the period
from March 1, 2009, to September 30, 2009. The order
required Ameren Missouri to refund $18 million,
including $1 million for interest, to customers related to
pretax earnings associated with certain long-term
partial requirements sales made by Ameren Missouri
after the loss of Noranda’s load in a severe ice storm in
January 2009. Ameren Missouri appealed this decision
to the Cole County Circuit Court, which overturned the
MoPSC’s April 2011 order. The Cole County Circuit
Court decision is being appealed by the MoPSC to the
Missouri Court of Appeals. It is possible that the
MoPSC could order additional refunds of approximately
$25 million related to pretax earnings associated with
these long-term partial requirements sales in periods
after September 2009, and this could result in a charge
to earnings in the period in which such an order is
‰
‰
‰
‰
‰
‰
received. Separately, Ameren Missouri filed a request
with the MoPSC in July 2011 for an accounting authority
order that would allow Ameren Missouri to recover fixed
costs totaling $36 million due to the loss of load caused
by the severe 2009 ice storm in a future electric rate
case. If the courts ultimately rule in favor of Ameren
Missouri’s position regarding the classification of the
long-term partial requirements sales, Ameren Missouri
would no longer seek to recover from customers the
sum covered by the accounting authority order.
Ameren and Ameren Missouri also are pursuing
recovery from insurers, through litigation, for
reimbursement of unpaid liability insurance claims for a
December 2005 breach of the upper reservoir at
Ameren Missouri’s Taum Sauk pumped-storage
hydroelectric energy center.
Ameren Missouri’s Callaway energy center’s next
scheduled refueling and maintenance outage will be in
the spring of 2013. The expected duration of this
outage is approximately 40 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. Changes in purchased power costs
and excess power available for sale are included in the
FAC resulting in limited impact to earnings.
Ameren Missouri continues to evaluate its longer-term
needs for new baseload and peaking electric generation
capacity. Environmental regulations, as well as future
initiatives related to greenhouse gas emissions and
global climate change, could result in significant
increases in capital expenditures and operating costs.
The compliance costs could be prohibitive at some of
Ameren Missouri’s coal-fired energy centers,
particularly at its Meramec energy center. The expected
return from these investments, at current market prices
for energy and capacity, might not justify the required
capital expenditures for their continued operation.
Ameren intends to allocate its capital to those
investment opportunities with the highest expected
risk-adjusted returns. Ameren believes that because of
its strategic location in the country, electric
transmission may provide it with such an opportunity.
MISO has approved three projects, which will be
developed by ATXI. The first project, Illinois Rivers,
involves the building of a 345-kilovolt line from western
Indiana across the state of Illinois to eastern Missouri.
Design and planning work on the first sections of this
project have begun and right-of-way acquisitions are
scheduled to commence in late 2013 after receipt of a
certificate of public convenience and necessity, which
ATXI requested from the ICC in November 2012.
Construction is expected to begin in 2014. The first
sections of the Illinois Rivers project are expected to be
in service in 2016. The last section of this project is
expected to be completed in 2019. The Spoon River
project in northwest Illinois and the Mark Twain project
in northeast Missouri are the other two projects
approved by MISO in its current transmission
expansion plan. These two projects are expected to be
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completed in 2018. The estimated total investment in
these three projects is expected to be more than
$1.3 billion through 2019. FERC has approved
transmission rate incentives for the three MISO
approved projects as well as for the Big Muddy River
project. The Big Muddy River project, located primarily
in southern Illinois, is being evaluated for inclusion in
MISO’s transmission expansion plans. Separate from
the ATXI projects discussed above, Ameren Illinois
expects to invest approximately $1 billion in electric
transmission assets over the next five years to address
load growth and reliability requirements.
In November 2012, FERC approved a forward-looking
rate calculation with an annual revenue requirement
reconciliation for Ameren Illinois’ electric transmission
business. Based on its forward-looking rate calculation,
on January 1, 2013, Ameren Illinois adjusted its electric
transmission rates to reflect an increase in its
transmission revenue requirement of $29 million. The
increase in Ameren Illinois’ transmission revenue
requirement is subject to a revenue requirement
reconciliation, which could result in an adjustment to
revenues based on the actual revenue requirement in
2013.
For additional information regarding recent rate orders
and related appeals, pending requests filed with state
and federal regulatory commissions, the FAC prudence
review and related appeal, Taum Sauk matters, and
separate FERC orders impacting Ameren Missouri and
Ameren Illinois, see Note 2 – Rate and Regulatory
Matters, Note 10 – Callaway Energy Center, and Note
15 – Commitments and Contingencies under Part II,
Item 8, of this report.
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Merchant Generation Operations
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Ameren no longer considers the Merchant Generation
segment to be a core component of its future business
strategy. As a result, Ameren intends to exit its
Merchant Generation segment before the end of the
previously estimated useful lives of that segment’s
long-lived assets. In consideration of this
determination, Ameren has begun planning to reduce,
and ultimately to eliminate, the Merchant Generation
segment’s, including Genco’s, reliance on Ameren’s
financial support and shared services support. Based
on Ameren’s intention to exit its Merchant Generation
segment, Ameren recorded an asset impairment charge
in December 2012 to reduce the carrying value of all of
the Merchant Generation segment’s coal and natural
gas-fired energy centers, except the Joppa coal-fired
energy center, to their estimated fair values. See Note
17 – Impairment and Other Charges under Part II,
Item 8, of this report for additional information.
Ameren’s date and method of exit from the Merchant
Generation business is currently uncertain. Exit
strategies may include the sale of all or parts of the
Merchant Generation business and the restructuring of
all or a portion of Ameren’s equity position in Genco.
Once a plan of disposal is finalized, Ameren’s
implementation of that plan may result in long-lived
asset impairments, disposal-related losses,
contingencies, reduction of existing deferred tax assets,
and other consequences that are currently unknown.
As a result of Merchant Generation’s reduced net
property and plant carrying value, Ameren estimates
that annual depreciation expense will be reduced by
approximately $75 million, before taxes.
Ameren could recognize additional, material long-lived
asset impairment charges in the future if estimated
undiscounted cash flows no longer exceed carrying
values for long-lived assets. This may occur either as a
result of factors outside Ameren’s control, such as
changes in market prices of power or fuel costs,
administrative action or inaction by regulatory agencies
and new environmental laws and regulations that could
reduce the expected useful lives of Merchant
Generation’s energy centers, and also as a result of
factors that may be within Ameren’s control, such as a
failure to achieve forecasted operating results and cash
flows, unfavorable changes in forecasted operating
results and cash flows, or decisions to shut down,
mothball or sell its energy centers. As of December 31,
2012, the net book value of Ameren’s Merchant
Generation long-lived assets was $748 million.
The Merchant Generation segment expects to have
available generation from its coal-fired energy centers
of 31 million megawatthours in any given year.
However, based on currently expected power prices,
the Merchant Generation segment expects to generate
approximately 27.5 million megawatthours in 2013,
with approximately 95% of this generation expected to
be from coal-fired energy centers.
Power prices in the Midwest affect the amount of
revenues and cash flows the Merchant Generation
segment can realize by marketing power into the
wholesale and retail markets. Ameren’s Merchant
Generation segment is adversely affected by the
declining market price of power for any unhedged
generation. Market prices for power have decreased
over the past several years, especially sharply during
the first quarter of 2012.
As of December 31, 2012, Marketing Company had
hedged approximately 25.5 million megawatthours of
Merchant Generation’s expected generation for 2013, at
an average price of $36 per megawatthour. For 2014,
Marketing Company had hedged approximately
14 million megawatthours of Merchant Generation’s
forecasted generation sales at an average price of
$38 per megawatthour. For 2015, Marketing Company
had hedged approximately 6.5 million megawatthours
of Merchant Generation’s forecasted generation sales at
an average price of $40 per megawatthour. Any
unhedged forecasted generation will be exposed to
market prices at the time of sale. As a result, any new
physical or financial power sales may be at price levels
lower than previously experienced and lower than the
value of existing hedged sales.
To further reduce cash flow volatility, Merchant
Generation seeks to hedge fuel costs consistent with
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power sales. As of December 31, 2012, for 2013
Merchant Generation had hedged fuel costs for
approximately 25 million megawatthours of coal and up
to 27 million megawatthours of base transportation at
about $23 per megawatthour. For 2014, Merchant
Generation had hedged fuel costs for approximately
13 million megawatthours of coal and up to 21 million
megawatthours of base transportation at about $24 per
megawatthour. For 2015, Merchant Generation had
hedged fuel costs for approximately 6 million
megawatthours of coal and up to 20 million
megawatthours of base transportation at about $26 per
megawatthour. 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 2013 through 2017.
In June 2012, FERC approved MISO’s proposal to
establish an annual capacity market within the RTO.
MISO’s inaugural annual capacity auction will be held in
March 2013 for the June 2013 to May 2014 planning
year. Participation in MISO’s capacity auction is
voluntary for load-serving entities as they will continue
to be able to plan to meet all of their resource
requirements outside of the auction, including through
self-supply and/or bilateral contracts.
The Merchant Generation segment continues to seek
revenue growth opportunities. One such opportunity is
Marketing Company’s ability to sell additional electric
capacity into PJM. Capacity market prices within PJM
are higher than capacity market prices within MISO. In
addition to the capacity related to Genco’s Elgin energy
center, which is located within PJM, Marketing
Company expects to sell additional capacity associated
with 681 megawatts of PJM-approved transmission
capacity from MISO to PJM. This includes 84
megawatts of transmission capacity associated with
AERG energy centers from October 2011 forward, and
an additional 301 megawatts and 296 megawatts of
transmission capacity associated with AERG and Genco
energy centers, respectively, from June 2015 forward.
Another revenue growth opportunity is Marketing
Company’s efforts to sell power to residential and small
commercial customers in Illinois. Marketing Company
is actively pursuing sales to customers choosing the
state of Illinois municipal aggregation alternative for
electric power supply. Marketing Company’s sales to
municipal aggregation customers at retail prices
provide margins above the current wholesale market
prices. Marketing Company will attempt to expand the
volume of its sales to residential and small commercial
customers through the municipal aggregation initiative.
In September 2012, the Illinois Pollution Control Board
granted AER a variance to extend compliance dates for
SO2 emission levels contained in the MPS through
December 31, 2019, subject to certain conditions. The
Illinois Pollution Control Board approved AER’s
proposed plan to restrict its SO2 emissions through
2014 to levels lower than those previously required by
the MPS to offset any environmental impact from the
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variance. The order also established a schedule of
milestones for completion of various aspects of the
installation and completion of the scrubber project at
Genco’s Newton energy center; the first milestone
relates to the completion of engineering design by July
2015 while the last milestone relates to major
equipment components being placed into final position
on or before September 1, 2019.
EEI reduced its workforce in 2012. Going forward, the
workforce reduction is expected to reduce EEI’s annual
pretax other operations and maintenance expenses by
$2 million to $3.5 million. Additionally, EEI’s
management and labor union postretirement medical
benefit plans were amended in 2012 to adjust for
moving to a Medicare Advantage plan, which resulted
in a reduction of the benefit obligation. Ameren
estimates the pretax impact of the lower benefit
obligation will result in a $5 million to $10 million
reduction in postretirement benefits expense during
2013.
Liquidity and Capital Resources
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The Ameren Companies seek to maintain access to the
capital markets at commercially attractive rates in order
to fund their businesses. The Ameren Companies seek
to enhance regulatory frameworks and returns in order
to improve cash flows, credit metrics, and related
access to capital for Ameren’s rate-regulated
businesses.
The Merchant Generation segment seeks to fund its
operations internally and not to rely on financing from
Ameren or external, third-party sources. The Merchant
Generation segment will continue to seek to defer or
reduce capital and operating expenses, to sell certain
assets, and to take other actions as necessary to seek
to fund its operations internally while maintaining safe
and reliable operations. Consistent with these
objectives, in March 2012, Genco entered into a put
option agreement with AERG for the potential sale of
the Grand Tower, the Gibson City, and the Elgin energy
centers, in order to provide an additional source of
liquidity, if needed in the future. Ameren and AERG do
not expect to extend the put option agreement beyond
March 28, 2014. Given power market conditions and
cash flow requirements, it is more likely than not that
Genco will sell one or more of its three natural gas-fired
energy centers before the put option expires to improve
its liquidity. Based on current projections, it is probable
during 2013 that Genco will need mid-month liquidity
from either asset sales or money pool borrowings to
support working capital needs. Based on projections as
of December 31, 2012, Genco estimates that these
financing sources are adequate to support its
operations in 2013.
Under its indenture, Genco may not borrow additional
funds from external, third-party sources if its interest
coverage ratio is less than a specified minimum or if its
leverage ratio is greater than a specified maximum.
Based on projections as of December 31, 2012, of its
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operating results and cash flows, Genco expects that,
by the end of the first quarter of 2013, its interest
coverage ratio will be less than the minimum ratio
required for the company to borrow additional funds
from external, third-party sources. Genco’s indenture
does not restrict intercompany borrowings from
Ameren’s non-state-regulated subsidiary money pool.
However, borrowings from the money pool are subject
to Ameren’s control. If a Genco intercompany financing
need were to arise, borrowings from the non-state-
regulated subsidiary money pool by Genco would be
dependent on consideration by Ameren of the facts and
circumstances existing at that time. A decision by
Ameren not to provide funding to Genco in the event a
financing need arises could cause Genco to undertake a
corporate restructuring. Under such circumstances,
Ameren may cease to own all or a portion of its equity
interest in Genco, and Ameren may incur restructuring
costs.
Genco cannot pay dividends on its common stock
unless the company’s actual interest coverage ratio for
the most recently ended four fiscal quarters and the
interest coverage ratios projected by management for
each of the subsequent four six-month periods are
greater than a specified minimum level. After a
December 31, 2012 review of Genco’s operating results
and cash flows, we do not expect that Genco will
achieve the minimum interest coverage ratio necessary
to pay dividends on its common stock for each of the
four six-month periods ending June 30,
2013, December 31, 2013, June 30, 2014 or
December 31, 2014. As a result, Genco was restricted
from paying dividends on its common stock as of
December 31, 2012. We expect that Genco will be
unable to pay dividends on its common stock through
at least December 31, 2015.
Based on current projections for 2013, AER and Genco
each expects its operating cash flows to approximate
its nonoperating cash flow requirements in 2013.
Included in this 2013 projection, AER and Genco expect
to receive income tax benefits through the tax allocation
agreement of approximately $100 million and
$60 million, respectively. These estimates may change
significantly depending on the taxable income or loss of
Ameren and each of its subsidiaries and also assume
Ameren’s continued ownership of AER and Genco.
Additional sources of liquidity from either asset sales or
money pool borrowings may be required to support
AER and Genco’s daily working capital needs.
As of December 31, 2012, Ameren had approximately
$605 million in federal income tax net operating loss
carryforwards (Ameren Missouri – $175 million and
Ameren Illinois – $175 million) and $87 million in
federal income tax credit carryforwards (Ameren
Missouri – $11 million and Ameren Illinois – $-million).
These carryforwards are expected to offset income tax
liabilities for Ameren Missouri into 2014, and into 2015
for Ameren and Ameren Illinois, consistent with the tax
allocation agreement.
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In December 2011, the IRS issued new guidance in the
form of temporary regulations on the treatment of
amounts paid to acquire, produce or improve tangible
property and dispositions of such property with respect
to electric transmission, distribution, and generation
assets as well as natural gas transmission and
distribution assets. These new rules are required to be
implemented no later than January 1, 2014. This new
guidance may change how Ameren determines whether
expenditures related to plant and equipment are
deducted as repairs or capitalized for income tax
purposes. Until Ameren completes its evaluation of the
new guidance, Ameren cannot estimate its impact on
Ameren’s results of operation, financial position, and
liquidity.
Depending on the date and method of exit from the
Merchant Generation business, Ameren may not be able
to fully recover the deferred tax assets that are on its
December 31, 2012 balance sheet. Ameren will be
required to expense or create a valuation allowance for
any portion of its deferred tax assets that it cannot use to
offset future taxable income. At this time, based on the
uncertainty regarding the form, structure, and timing of
its exit from the Merchant Generation business, Ameren
cannot determine if it will ultimately be required to
expense or establish a valuation allowance for any
portion of its existing deferred tax assets.
The American Taxpayer Relief Act of 2012, enacted into
law on January 2, 2013, includes provisions accelerating
the depreciation of certain property for income tax
purposes. Qualifying property placed into service in 2013
is eligible for 50% bonus depreciation. It is expected that
additional bonus depreciation deductions in 2013 will,
after the use of net operating loss and tax credit
carryforwards, decrease Ameren’s income tax payments
in 2015 by approximately $120 million. In addition, if
these deductions had been taken into account at
December 31, 2012, the amount of current accumulated
deferred income tax assets would have decreased by
approximately $120 million for Ameren (Ameren
Missouri – $45 million and Ameren Illinois – $35 million)
with a corresponding decrease in long-term accumulated
deferred income tax liabilities.
In November 2012, the Ameren Companies entered into
multiyear credit agreements that cumulatively provide
$2.1 billion of credit through November 14, 2017. The
2010 Genco Credit Agreement was terminated in
November 2012 and not replaced. See Note 4 – Short-
term Debt and Liquidity under Part II, Item 8, of this
report for additional information regarding the 2012
Credit Agreements. Ameren, Ameren Missouri, and
Ameren Illinois believe that their liquidity is adequate
given their expected operating cash flows, capital
expenditures, and related financing plans. However,
there can be no assurance that significant changes in
economic conditions, disruptions in the capital and
credit markets, or other unforeseen events will not
materially affect their ability to execute their expected
operating, capital or financing plans.
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Ameren investments required to achieve compliance
with known environmental laws and regulations from
2013 to 2022 are expected to be more than $1.5 billion.
Ameren continues to closely monitor pending laws and
regulations to determine the most appropriate
investment approach. Some energy centers may be
refueled, retired, replaced or mothballed depending on
environmental laws and regulations and market
conditions. Any pollution control investments will result
in decreased energy center availability during
construction and significantly higher ongoing operating
expenses. Any pollution control investments at Ameren
Missouri are expected to be recoverable from
ratepayers, subject to prudence reviews. Regulatory lag
may materially affect the timing of such recovery and
returns on the investments, and therefore affect our
cash flows and related financing needs. The
recoverability of amounts expended in our Merchant
Generation segment, if retained by Ameren for the
entire period, will depend on whether market prices for
power change to reflect increased environmental costs
for coal-fired energy centers.
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, and opportunities to reduce costs
or increase revenues, and other strategic initiatives to
increase Ameren’s stockholder value. We are unable to
predict which, if any, of these initiatives will be executed.
The execution of these initiatives may have a material
impact on our future results of operations, financial
position, or liquidity.
REGULATORY MATTERS
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
ACCOUNTING MATTERS
Critical Accounting Estimates
Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of
appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments
regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have
outlined below the critical accounting estimates that we believe are most difficult, subjective, or complex. Any change in the
assumptions or judgments applied in determining the following matters, among others, could have a material impact on future
financial results.
Accounting Estimate
Uncertainties Affecting Application
Regulatory Mechanisms and Cost Recovery
The Ameren Companies defer costs in accordance with
authoritative accounting guidance, 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, prudency reviews,
and opposition during the ratemaking process and
ability to recover costs
Ameren Illinois’ assessment of and ability to estimate
the current year’s electric delivery service costs to be
reflected in revenues and recovered from customers in
a subsequent year under the IEIMA performance-based
formula ratemaking process.
Basis for Judgment
We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions
where we operate and any other factors that may indicate whether cost recovery is probable. If facts and circumstances lead
us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of
disallowance, we record a charge to earnings, which could be material. Ameren Illinois estimates its annual revenue
requirement pursuant to the IEIMA for interim periods by using internal forecasted information, such as projected operations
and maintenance expenses, depreciation expense, taxes other than income taxes, and rate base, as well as published
forecasted data regarding that year’s monthly average yields of the 30-year United States treasury bonds. Ameren Illinois
estimates its annual revenue requirement as of December 31st of each year using that year’s actual operating results and
assesses the probability of recovery of or refund to customers that the ICC will order at the end of the following year.
Variations in costs incurred, investments made, or orders by the ICC or courts can result in a subsequent change in Ameren
Illinois’ estimate. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for quantification of these
assets for each of the Ameren Companies.
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Accounting Estimate
Derivative Financial Instruments
We account for derivative financial instruments and
measure their fair value in accordance with authoritative
accounting guidance, which requires the identification and
classification of a derivative and its fair value. See
Commodity Price Risk and Fair Value of Contracts in
Quantitative and Qualitative Disclosures About Market
Risk under Part II, Item 7A, Note 7 – Derivative Financial
Instruments and Note 8 – Fair Value Measurements under
Part II, Item 8, of this report.
Uncertainties Affecting Application
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Our ability to identify derivatives
Our ability to assess whether derivative contracts
qualify for the NPNS exception
Our ability to consume or produce notional values of
derivative contracts
‰ Market conditions in the energy industry, especially the
effects of price volatility and liquidity
Valuation assumptions on longer-term contracts due to
lack of observable inputs
Effectiveness of derivatives that have been designated
as hedges
Counterparty default risk
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Basis for Judgment
We evaluate contracts to determine whether they contain derivatives. Determining whether or not a contract qualifies as a
derivative under authoritative accounting guidance requires us to exercise significant judgment in interpreting the definition
of a derivative and applying that definition. Authoritative accounting guidance regarding derivative instruments requires that
all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS
exception applies. We determine whether to exclude the fair value of certain derivatives from valuation under the NPNS
provisions of authoritative accounting guidance after assessing our intent and ability to physically deliver commodities
purchased and sold. Further, our forecasted purchases and sales also support our designation of some fair valued derivative
instruments as cash flow hedges. Fair value of our derivatives is measured in accordance with authoritative accounting
guidance, which provides a fair value hierarchy that prioritizes inputs to valuation techniques. We use valuation techniques
that maximize the use of observable inputs and minimize the use of unobservable inputs. When we do not have observable
inputs, we use certain assumptions that market participants would use in pricing the asset or liability, including assumptions
about risks inherent in the inputs to the valuation. Our valuations also reflect our own assessment of counterparty default
risk, guided by the best internal and external information available.
Valuation of Long-Lived Assets and Asset Retirement Obligations
We periodically assess the carrying value of our 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.
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Changes in business, industry, laws, technology, or
economic and market conditions
Valuation assumptions and conclusions, including an
appropriate discount rate and terminal year earnings
multiple.
Our assessment of market participants
Estimated useful lives or duration of ownership of our
significant long-lived assets
Actions or assessments by our regulators
Identification of an asset retirement obligation and
assumptions about the timing of asset removals
Basis for Judgment
Whenever events or changes in circumstances indicate a valuation may have changed, we use various methodologies that we
believe market participants would use to determine valuations and discounted, undiscounted, and probabilistic discounted
cash flow models with multiple operating scenarios. The identification of asset retirement obligations is conducted through
the review of legal documents and interviews. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8,
of this report for quantification of our asset retirement obligations. See Impairment and Other Charges in Management’s
Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 17 – Impairment
and Other Charges under Part II, Item 8, of this report for additional information of our long-lived asset impairment
evaluation and charges recorded.
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Accounting Estimate
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs of
providing future employee benefits in accordance with
authoritative accounting guidance regarding benefit plans.
See Note 11 – Retirement Benefits under Part II, Item 8,
of this report.
Uncertainties Affecting Application
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Future rate of return on pension and other plan assets
Valuation inputs and assumptions used in the fair value
measurements of plan assets excluding those inputs
that are readily observable
Interest rates used in valuing benefit obligations
Health care cost trend rates
Timing of employee retirements and mortality
assumptions
Ability to recover certain benefit plan costs from our
ratepayers
Changing market conditions that may affect investment
and interest rate environments
Impacts of the health care reform legislation enacted in
2010
Basis for Judgment
Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other
postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our
review of available historical, current, and projected rates, as applicable. See Note 11 – Retirement Benefits under Part II,
Item 8, of this report for sensitivity of Ameren’s benefit plans to potential changes in these assumptions.
Accounting for Contingencies
We make judgments and estimates in recording and
disclosing liabilities for claims, litigation, environmental
remediation, the actions of various regulatory agencies, or
other matters that occur in the normal course of business.
We record a loss contingency when it is probable that a
liability has been incurred and the amount of the loss can
be reasonably estimated. A gain contingency is not
recorded until realized or realizable.
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Estimating financial impact of events
Estimating likelihood of various potential outcomes
Regulatory and political environments and
requirements
Outcome of legal proceedings, settlements or other
factors
Changes in regulation, expected scope of work,
technology or timing of environmental remediation
Basis for Judgment
The determination of a loss contingency requires significant judgment as to the expected outcome of each contingency in
future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider all
available evidence including the expected outcome of potential litigation. If no estimate is better than another within our
range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. As
additional information becomes available, we reassess the potential liability related to the contingency and revise our
estimates. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case
law and legal precedents. See Note 2 – Rate and Regulatory Matters, Note 10 – Callaway Energy Center, and Note 15 –
Commitments and Contingencies under Part II, Item 8, of this report for information on the Ameren Companies’
contingencies.
Accounting for Income Taxes
Based on authoritative accounting guidance, we record
the provision for income taxes, deferred tax assets and
liabilities and a valuation allowance against net deferred
tax assets, if any. See Note 13 – Income Taxes under
Part II, Item 8, of this report.
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Changes in business, industry, laws, technology, or
economic and market conditions affecting forecasted
financial condition and/or results of operations
Estimates of the amount and character of future taxable
income
Enacted tax rates applicable to taxable income in years
in which temporary differences are recovered or settled
Effectiveness of implementing tax planning strategies
Changes in income tax laws
Results of audits and examinations of filed tax returns
by taxing authorities
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Basis for Judgment
The reporting of tax-related assets requires the use of estimates and significant management judgment. Deferred tax assets
are recorded representing future effects on income taxes for temporary differences between the bases of assets for financial
reporting and tax purposes. Although management believes current estimates for deferred tax assets are reasonable, actual
results could differ from these estimates based on a variety of factors including change in forecasted financial condition and/
or results of operations, change in income tax laws or enacted tax rates, the form, structure, and timing of asset or stock sales
or dispositions, and results of audits and examinations of filed tax returns by taxing authorities. Valuation allowances against
deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in
future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on
tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized.
Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming the
position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is
required to determine recognition thresholds and the related amount of tax benefits to be recognized. At any period end, and
as new developments occur, management will reevaluate its tax positions. See Note 13 – Income Taxes under Part II, Item 8,
of this report for the amount of deferred tax assets and uncertain tax positions recorded at December 31, 2012.
Impact of Future Accounting Pronouncements
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
EFFECTS OF INFLATION AND CHANGING PRICES
Ameren’s rates for retail electric and natural gas utility
service are regulated by the MoPSC and the ICC. Nonretail
electric rates are regulated by FERC. Rate regulation is
generally based on the recovery of historical or projected
costs. As a result, revenue increases could lag behind
changing prices. Ameren Illinois elected to participate in
the performance-based formula ratemaking process
pursuant to the IEIMA for its electric delivery service
business. Ameren Illinois’ participation in this formula
ratemaking process will terminate if the average residential
rate increases by more than 2.5% annually from June 2011
through May 2014. The average residential rate includes
generation service, which is outside of Ameren Illinois’
control. Ameren Illinois is required to purchase all of its
power through procurement processes administered by the
IPA. The cost of procured power can be affected by
inflation. Within the IEIMA formula, the monthly average
yields of 30-year United States treasury bonds are the
basis for Ameren Illinois’ return on equity. Therefore, there
is a direct correlation between the yield of United States
treasury bonds, which are affected by inflation, and the
earnings of Ameren Illinois’ electric distribution business.
Inflation affects our operations, earnings, stockholders’
equity, and financial performance.
The current replacement cost of our utility plant
substantially exceeds our recorded historical cost. Under
existing regulatory practice, only the historical cost of plant
is recoverable from customers. As a result, cash flows
designed to provide recovery of historical costs through
depreciation might not be adequate to replace the plant in
future years. Ameren’s Merchant Generation business does
not have regulated recovery mechanisms and is therefore
dependent on market prices for power to reflect rising
costs.
Ameren Missouri recovers the cost of fuel for electric
generation and the cost of purchased power by adjusting
rates as allowed through the FAC. Ameren Illinois recovers
power supply costs from electric customers by adjusting
rates through a rider mechanism to accommodate changes
in power prices.
Ameren Missouri, Ameren Illinois and ATXI are affected
by changes in the cost of electric transmission services.
FERC regulates the rates charged and the terms and
conditions for electric wholesale and unbundled retail
transmission services. Because they are members of MISO,
Ameren Missouri’s, Ameren Illinois’ and ATXI’s transmission
rates are calculated in accordance with the rate formulas
contained in MISO’s FERC-approved tariff. Under the MISO
OATT, a portion of the revenue requirement related to certain
projects eligible for cost sharing are allocated to multiple
MISO pricing zones. The remaining revenue requirement is
assigned to the pricing zone where the transmission assets
are located. Ameren Missouri uses a rate formula that is
updated in June of each year and is based on the prior-year’s
cost data. The Ameren Missouri zonal rate is charged to
wholesale customers in the AMMO pricing zone. However,
this rate is not directly charged to Missouri retail customers
because the MoPSC includes transmission-related costs in
setting bundled retail rates in Missouri. Ameren Illinois and
ATXI have received FERC approval to use company-specific,
forward-looking rate formula templates in setting their
transmission rates. These forward-looking rates are updated
every January. Each year, after the costs are incurred, the
January forecast rates are reconciled with the actual revenue
requirement. In Illinois, the AMIL pricing zone rate is charged
directly to wholesale customers and alternative retail electric
suppliers that serve unbundled retail load. If Ameren Illinois
retail customers do not choose an alternative retail electric
supplier, the AMIL transmission rate, as well as other MISO
related costs, is collected through the transmission services
rider mechanism.
In our Missouri and Illinois retail natural gas utility
jurisdictions, changes in natural gas costs are generally
reflected in billings to natural gas customers through PGA
clauses.
76
Ameren and Ameren Missouri 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 natural gas pools and supply basins, and to
minimize the impact to their financial statements. Ameren
Missouri’s exposure to changes in market prices of natural
gas for generation is mitigated by its ability to recover
increasing costs via the FAC. See Quantitative and
Qualitative Disclosures About Market Risk - Commodity
Price Risk under Part II, Item 7A, of this report for
additional information.
See Note 2 – Rate and Regulatory Matters under Part
II, Item 8, of this report for additional information on the
cost recovery mechanisms.
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 or index.
The following discussion of our risk management activities
includes forward-looking statements that involve risks and
uncertainties. Actual results could differ materially from
those projected in the forward-looking statements. We
handle market risks in accordance with established policies,
which may include entering into various derivative
transactions. In the normal course of business, we also face
risks that are either nonfinancial or nonquantifiable. Such
risks, principally business, legal, and operational risks, are
not part of the following discussion.
Our risk management objective is to optimize our
physical generating assets and to pursue market
opportunities within prudent risk parameters. Our risk
management policies are set by a risk management steering
committee, which is composed of senior-level Ameren
officers.
Interest Rate Risk
We are exposed to market risk through changes in
interest rates associated with:
‰
‰
‰
‰
long-term and short-term variable-rate debt;
fixed-rate debt;
auction-rate long-term debt; and
defined pension and postretirement benefit plans.
We manage our interest rate exposure by controlling
the amount of debt instruments within our total
capitalization portfolio and by monitoring the effects of
market changes on interest rates. For defined pension and
postretirement benefit plans, we control the duration and
the portfolio mix of our plan assets.
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, 2012:
Interest Expense
Net Income(a)
Ameren . . . . . . . . . . . . . . . . . .
. . . . . . . . . .
Ameren Missouri
Ameren Illinois . . . . . . . . . . . .
$
2
2
(b)
$
(1)
(1)
(b)
(a) Calculations are based on an estimated tax rate of 37%, 36% and
40% for Ameren, Ameren Missouri and Ameren Illinois,
respectively.
(b) Less than $1 million.
Credit Risk
Credit risk represents the loss that would be
recognized if counterparties should fail to perform as
contracted. Exchange-traded contracts are supported by the
financial and credit quality of the clearing members of the
respective exchanges and have nominal credit risk. In all
other transactions, we are exposed to credit risk in the
event of nonperformance by the counterparties to the
transaction. See Note 7 – Derivative Financial Instruments
under Part II, Item 8, of this report for information on the
potential loss on counterparty exposure as of December 31,
2012.
Our rate-regulated revenues are primarily derived from
sales or delivery of electricity and natural gas to customers
in Missouri and Illinois. Our physical and financial
instruments are subject to credit risk consisting of trade
accounts receivables and executory contracts with market
risk exposures. The risk associated with trade receivables is
mitigated by the large number of customers in a broad
range of industry groups who make up our customer base.
At December 31, 2012, no nonaffiliated customer
represented more than 10%, in the aggregate, of our
accounts receivable. Additionally, Ameren Illinois has risk
associated with the purchase of receivables. The Illinois
Public Utilities Act requires Ameren Illinois to establish
electric utility consolidated billing and purchase of
receivables services. At the option of an alternative retail
electric supplier, Ameren Illinois is required to purchase the
supplier’s receivables relating to Ameren Illinois’ delivery
service customers who elected to receive power supply
from the alternative retail electric supplier. When that option
is selected, Ameren Illinois produces consolidated bills for
the applicable retail customers reflecting charges for
electric delivery service and purchased receivables.
Beginning in June 2012, Ameren Illinois began purchasing
trade receivables relating to the power supply of residential
customers who use Marketing Company as their alternative
retail electric supplier. As of December 31, 2012, Ameren
Illinois’ balance of purchased accounts receivable
associated with the utility consolidated billing and purchase
of receivables services was $9 million. The risk associated
with Ameren Illinois’ electric and natural gas trade
receivables is also mitigated by a rate adjustment
77
mechanism that allows Ameren Illinois to recover the
difference between its actual bad debt expense under GAAP
and the bad debt expense included in its base rates. Ameren
Missouri and Ameren Illinois continue to monitor the
impact of increasing rates on customer collections. Ameren
Missouri and Ameren Illinois make adjustments to their
respective allowance for doubtful accounts as deemed
necessary to ensure that such allowances are adequate to
cover estimated uncollectible customer account balances.
Ameren, Ameren Missouri, Ameren Illinois and AER
may have credit exposure associated with off-system or
wholesale purchase and sale activity with nonaffiliated
companies. At December 31, 2012, Ameren’s, Ameren
Missouri’s, Ameren Illinois’ and AER’s combined credit
exposure to nonaffiliated trading counterparties, excluding
coal suppliers, deemed below investment grade either
through external or internal credit evaluations, was less
than $1 million, net of collateral (2011 – $48 million). At
December 31, 2012, the combined credit exposures to coal
suppliers, deemed below investment grade either through
external or internal credit evaluations, net of collateral, were
$10 million, $2 million and $8 million at Ameren, Ameren
Missouri and AER, respectively (2011 – $35 million,
$33 million and $2 million, respectively).
We establish credit limits for these counterparties and
monitor the appropriateness of these limits on an ongoing
basis through a credit risk management program.
Monitoring 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. We estimate our credit
exposure to MISO associated with the MISO Energy and
Operating Reserves Market to be $21 million at
December 31, 2012 (2011 – $29 million).
Equity Price Risk
Our costs for providing defined benefit retirement and
postretirement benefit plans are dependent upon a number
of factors, including the rate of return on plan assets.
Ameren manages plan assets in accordance with the
“prudent investor” guidelines contained in ERISA. Ameren’s
goal is to ensure that sufficient funds are available to
provide benefits at the time they are payable while also to
maximizing total return on plan assets and minimizing
expense volatility consistent with its tolerance for risk.
Ameren delegates investment management to specialists.
Where appropriate, Ameren provides the investment
manager with guidelines that specify allowable and
prohibited investment types. Ameren regularly monitors
manager performance and compliance with investment
guidelines.
The expected return on plan assets is based on
historical and projected rates of return for current and
planned asset classes in the investment portfolio. Projected
rates of return for each asset class are estimated after an
analysis of historical experience, future expectations, and
the volatility of the various asset classes. After considering
the target asset allocation for each asset class, we adjust
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 will be reflected
in net income, OCI, or regulatory assets. Contributions to
the plans could increase materially if we do not achieve
pension and postretirement asset portfolio investment
returns equal to or in excess of our 2013 assumed return
on plan assets of 7.50% and 7.25%, respectively.
Ameren Missouri 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,
2012, this fund was invested primarily in domestic equity
securities (65%) and debt securities (35%). It totaled
$408 million (2011 – $357 million). By maintaining a
portfolio that includes long-term equity investments,
Ameren Missouri seeks to maximize the returns to be used
to fund nuclear decommissioning costs within acceptable
parameters of risk. However, the equity securities included
in the portfolio are exposed to price fluctuations in equity
markets. The debt securities are exposed to changes in
interest rates. Ameren Missouri 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. Ameren Missouri’s exposure to equity price market
risk is in large part mitigated because Ameren Missouri is
currently allowed to recover its decommissioning costs,
which would include unfavorable investment results,
through electric rates.
Additionally, Ameren has company-owned life
insurance contracts that are used to support Ameren’s
deferred compensation plans. These life insurance contracts
include equity and debt investments that are exposed to
price fluctuations in equity markets and to changes in
interest rates.
Commodity Price Risk
We are exposed to changes in market prices for power,
emission allowances, coal, transportation diesel, natural gas
and uranium.
Ameren’s, Ameren Missouri’s and AER’s risks of
changes in prices for power sales are partially hedged
through sales agreements. AER also seeks to sell power
forward to wholesale, municipal, and industrial customers
to limit exposure to changing prices. We also attempt to
mitigate financial risks through risk management programs
and policies, which include forward-hedging programs, and
through 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 Ameren, Ameren Missouri and
78
AER is not contracted through physical or financial hedge
arrangements and is therefore exposed to volatility in
market prices.
market and be credited to customers taking power procured
by Ameren Illinois through the IPA process. Ameren Illinois
expects full recovery of its purchased power costs.
The following table shows how our earnings might
decrease if power prices were to decrease by 1% on
unhedged economic generation for 2013 through 2016:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren(b)
Ameren Missouri
. . . . . . . . . . . . . . . . . . . . . . . . . .
AER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income(a)
$
(10)
(c)
(10)
(a) Calculations are based on an estimated tax rate of 37%, 36% and
42% for Ameren, Ameren Missouri and AER, respectively.
Includes amounts for Ameren registrant and nonregistrant
subsidiaries and intercompany eliminations.
(b)
(c) Less than $1 million.
Ameren’s forward-hedging power programs include
the use of derivative financial swap contracts. These swap
contracts financially settle a fixed price against a floating
price. The floating price is typically the realized, or settled,
price at a liquid regional hub at some forward period of
time. Ameren controls the use of derivative financial swap
contracts with volumetric and correlation limits that are
intended to mitigate any material adverse financial impact.
Ameren also uses its portfolio management and
trading capabilities both to manage risk and to deploy
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 and stop-
loss limits that are intended to limit any material negative
financial impacts.
We manage risks associated with changing prices of
fuel for generation with techniques similar to those we use
to manage risks associated with changing market prices for
electricity.
Merchant Generation does not have the ability to pass
higher fuel costs through to its customers for electric
operations, with the exception of an immaterial percentage
of the output that has been contracted with a fuel cost pass-
through. Ameren Missouri has a FAC that allows Ameren
Missouri to recover, through customer rates, 95% of
changes in fuel, certain fuel additives, emission allowances,
purchased power costs, transmission costs, and MISO
costs and revenues, net of off-system revenues, greater or
less than the amount set in base rates, without a traditional
rate proceeding, subject to MoPSC prudency review.
Ameren Missouri remains exposed to the remaining 5% of
such changes. Ameren Illinois expects that purchased
power procured through past IPA procurements will be in
excess of requirements for the 2013 planning year due to
significant switching by customers to alternative retail
electric suppliers associated with municipal aggregation
initiatives. The IPA has proposed and the ICC has approved
that the excess purchased power will settle in the MISO
Ameren, Ameren Missouri and AER have entered into
coal contracts with various suppliers to purchase coal to
manage their exposure to fuel prices. The coal hedging
strategy is intended to secure a reliable coal supply while
reducing exposure to commodity price volatility.
Additionally, the type of coal burned is part of Ameren
Missouri’s environmental compliance strategy. Ameren
Missouri has a multiyear agreement to purchase ultra-low-
sulfur coal through 2017 to comply with environmental
regulations. The coal contract is with a single supplier.
Disruptions of the deliveries of that ultra-low-sulfur coal
from the supplier could compromise Ameren Missouri’s
ability to operate in compliance with emission standards.
Other sources of ultra-low-sulfur coal are limited and the
construction of pollution control equipment requires
significant lead time to become operational. Should a
temporary disruption of ultra-low-sulfur coal deliveries
occur and its existing inventory of ultra-low-sulfur coal
becomes fully depleted, and other sources of ultra-low-
sulfur coal are not available, Ameren Missouri would use its
existing emission allowances or purchase emission
allowances in order to achieve compliance with
environmental regulations. AER purchases coal based on
expected power sales, generally through bid procedures.
Therefore, AER’s forward coal requirements are dependent
on the volume of power sales that have been contracted.
Transportation costs for coal and natural gas can be a
significant portion of fuel costs. Ameren, Ameren Missouri
and AER 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 for the gas-fired
generation units of Ameren, Ameren Missouri and AER are
regulated by FERC through approved tariffs governing the
rates, terms, and conditions of transportation and storage
services. Certain firm transportation and storage capacity
agreements held by the Ameren Companies include rights
to extend the term of contracts. Depending on our
competitive position, we are able in some instances to
negotiate discounts to these tariff rates for our
requirements.
In addition, coal transportation costs are sensitive to
the price of diesel fuel as a result of rail freight fuel
surcharges. We use forward fuel oil contracts (both for
heating and crude oil) to mitigate this market price risk as
changes in these products are highly correlated to changes
in diesel markets. If diesel fuel costs were to increase or
decrease by $0.25 a gallon, Ameren’s fuel expense could
increase or decrease by $13 million annually (Ameren
Missouri – $8 million). As of December 31, 2012, Ameren
had a price cap for approximately 87% of expected fuel
surcharges in 2013.
In the event of a significant change in coal prices,
Ameren, Ameren Missouri and AER would probably take
actions to further mitigate their exposure to this market
79
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, Ameren Missouri has fixed-priced, base-price-
with-escalation, and market-priced agreements. It uses
inventories to provide some price hedge to fulfill its
Callaway energy center’s needs for uranium, conversion,
and enrichment. There is no fuel reloading or planned
maintenance outage scheduled for 2015. Ameren Missouri
has price hedges for approximately 73% of its 2013 to 2017
nuclear fuel requirements.
Nuclear fuel market prices remain subject to an
unpredictable supply-and-demand environment. Ameren
Missouri has continued to follow a strategy of managing its
inventory of nuclear fuel as an inherent price hedge. New
long-term uranium contracts are almost exclusively market-
price-related with an escalating price floor. New long-term
enrichment contracts usually have a base-price-with-
escalation price mechanism, and may also have either a
market-price-related component or market-based price re
benchmarking. Ameren Missouri expects to enter into
additional contracts from time to time in order to supply
nuclear fuel during the expected life of the Callaway energy
center, at prices that cannot now be accurately predicted.
Unlike the electricity and natural gas markets, nuclear fuel
markets have somewhat limited financial instruments
available for price hedging, so most hedging is done
through inventories and forward contracts, if they are
available.
The electric generating operations for Ameren, Ameren
Missouri and AER 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 and auction process,
Ameren and Ameren Missouri have been granted FTRs
associated with the MISO Energy and Operating Reserves
Market. In addition, Marketing Company has acquired FTRs
for its participation in the PJM-Northern Illinois and MISO
market. The FTRs are intended to mitigate electric
transmission congestion charges related to the physical
constraints of the transmission system. Depending on the
congestion, FTRs could result in either charges or credits.
Complex grid modeling tools are used to determine which
FTRs to nominate in the FTR allocation process. There is a
risk of incorrectly modeling the amount of FTRs needed,
and there is the potential that the FTRs could be ineffective
in mitigating transmission congestion charges.
With regard to Ameren Missouri’s and Ameren Illinois’
electric and natural gas distribution businesses, exposure to
changing market prices is in large part mitigated by the fact
that there are cost recovery mechanisms in place. These
cost recovery mechanisms allow Ameren Missouri and
Ameren Illinois to pass on to retail customers prudently
incurred costs for fuel, purchased power, and gas supply.
Ameren Illinois expects that purchased power procured
through past IPA procurements will be in excess of
requirements for the 2013 planning year due to significant
switching by customers to alternative retail electric
suppliers associated with municipal aggregation initiatives.
The IPA has proposed and the ICC has approved that the
excess purchased power will settle in the MISO market and
act as a credit to customers taking power procured by
Ameren Illinois through the IPA process. Ameren Illinois
expects full recovery of its purchased power costs.
Ameren Missouri’s and Ameren Illinois’ strategy is
designed to reduce the effect of market fluctuations for their
regulated customers. The effects of price volatility cannot
be eliminated. However, procurement strategies involve risk
management techniques and instruments similar to those
outlined earlier, as well as the management of physical
assets.
The following table presents, as of December 31, 2012, the percentages of the projected required supply of coal and coal
transportation for our coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway energy center, natural gas for our
CTs and retail distribution, as appropriate, and purchased power needs of Ameren Illinois, which does not own generation, that
are price-hedged over the period 2013 through 2017. The projected required supply of these commodities could be
significantly affected by changes in our assumptions for matters such as customer demand for our electric generation and our
electric and natural gas distribution services, generation output, and inventory levels, among other matters.
Ameren(a):
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for distribution(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power for Ameren Illinois(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
99%
99
100
54
82
100
78%
90
99
2
34
100
60%
90
49
1
9
50
2013
2014
2015 – 2017
80
2013
2014
2015 – 2017
Ameren Missouri:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for distribution(b)
Ameren Illinois:
Natural gas for distribution(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AER:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100%
99
100
34
89
81%
100
98%
100
59
100%
98
99
9
33
35%
100
49%
80
-
94%
98
49
2
17
9%
50
15%
80
-
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2013 represents January
2013 through March 2013. The year 2014 represents November 2013 through March 2014. This continues each successive year through
March 2017.
(c) Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one
megawatt of demand.
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 2013 through 2017.
Coal
Fuel
Expense
Net
Income(a)
Coal Transportation
Fuel
Expense
Net
Income(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren(b)(c)
Ameren Missouri(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
7
(d)
7
$
(4)
(d)
(4)
$
3
(d)
3
$
(2)
(d)
(2)
(a) Calculations are based on an estimated tax rate of 37%, 36% and 42% for Ameren, Ameren Missouri and AER, respectively.
(b)
(c)
(d) Less than $1 million.
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Includes the impact of the FAC.
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 to labor availability.
See Transmission and Supply of Electric Power under Part I, Item 1, of this report for the percentages of our historical
needs satisfied by coal, nuclear power, natural gas, hydroelectric power, and oil. Also see Note 15 – Commitments and
Contingencies under Part II, Item 8, of this report for additional information.
Fair Value of Contracts
We use derivatives principally to manage the risk of changes in market prices for coal, natural gas, diesel, power, and
uranium. 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, 2012. We use various methods to determine the fair value of our contracts. In
accordance with authoritative accounting guidance for fair value with hierarchy levels, the sources we used to determine the
fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling
and valuation methods that are not corroborated by market data (Level 3). See Note 8 – Fair Value Measurements under
Part II, Item 8, of this report for further information regarding the methods used to determine the fair value of these contracts.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
(43)
49
-
18
(177)
$
18
(27)
-
17
(5)
(307) $
320
-
(1)
(216)
246
(244)
-
2
44
Fair value of contracts outstanding at end of year, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(153)
$
3
$
(204) $
48
Ameren(a)
Ameren
Missouri
Ameren
Illinois
Other(b)
(a)
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Includes amounts for Marketing Company, AERG, Genco and intercompany eliminations.
81
The following table presents maturities of derivative contracts as of December 31, 2012, based on the hierarchy levels
used to determine the fair value of the contracts:
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
Ameren:
Level 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 2(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 3(b)
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri:
Level 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 2(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 3(b)
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Level 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 2(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 3(b)
$
$
$
$
$
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(8)
(60)
37
(31)
-
(5)
12
7
-
(55)
(20)
(75)
$
$
$
$
$
$
(8)
(39)
(5)
(52)
(4)
(2)
2
(4)
-
(37)
(21)
(58)
$
$
$
$
$
$
-
(1)
(19)
(20)
-
-
-
-
-
(1)
(20)
(21)
$
$
$
$
$
$
-
-
(50)
(50)
-
-
-
-
-
(50)
(50)
$
$
$
$
$
$
(16)
(100)
(37)
(153)
(4)
(7)
14
3
-
(93)
(111)
(204)
(a) Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed price vs. floating over-the-counter natural gas
swaps.
(b) Principally power forward contract values based on a Black-Scholes model that includes information from external sources and our estimates.
Level 3 also includes option contract values based on our estimates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all
material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 2012 and 2011, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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. Also, in our opinion,
the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012,
based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial
statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial
Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial
statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal control over financial reporting was maintained in
all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made
by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial
reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe
that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
82
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 1, 2013
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Union Electric 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 Union Electric Company at December 31, 2012 and 2011, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally
accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index
appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in
conjunction with the related financial statements. These financial statements and financial statement schedule are the
responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 1, 2013
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois 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 Ameren Illinois Company at December 31, 2012 and 2011, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the
index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in
conjunction with the related financial statements. These financial statements and financial statement schedule are the
responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of these statements in accordance with
the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 1, 2013
83
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME (LOSS)
(In millions, except per share amounts)
Year Ended December 31,
2011
2012
2010
Operating Revenues:
Electric
Gas
Total operating revenues
Operating Expenses:
Fuel
Purchased power
Gas purchased for resale
Other operations and maintenance
Impairment and other charges
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income (Loss)
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other income
Interest Charges
Income (Loss) Before Income Taxes
Income Taxes (Benefit)
Net Income (Loss)
Less: Net Income Attributable to Noncontrolling Interest
Net Income (Loss) Attributable to Ameren Corporation
Earnings (Loss) per Common Share – Basic and Diluted
Dividends per Common Share
Average Common Shares Outstanding
$
$
$
$
5,904
924
6,828
1,369
654
472
1,752
2,578
775
468
8,068
(1,240)
71
37
34
448
(1,654)
(680)
(974)
-
(974)
(4.01)
1.600
242.6
$
$
$
$
6,530
1,001
7,531
1,567
966
570
1,820
125
785
457
6,290
1,241
69
23
46
451
836
310
526
7
519
2.15
1.555
241.5
$ 6,521
1,117
7,638
1,323
1,106
669
1,821
589
765
449
6,722
916
90
33
57
497
476
325
151
12
139
0.58
$
$
$ 1.540
238.8
The accompanying notes are an integral part of these consolidated financial statements.
84
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(In millions)
Net Income (Loss)
Other Comprehensive Income (Loss), Net of Taxes:
Unrealized net gain (loss) on derivative hedging instruments, net of income
taxes (benefit) of $12, $1, and $(1), respectively
Reclassification adjustments for derivative (gains) losses included in net
income, net of income taxes (benefit) of $1, $(3), and $5, respectively
Pension and other postretirement benefit plan activity, net of income taxes
(benefit) of $22, $(32), and $6, respectively
Total other comprehensive income (loss), net of taxes
Comprehensive Income (Loss)
Less: Comprehensive Income Attributable to Noncontrolling Interest
Year Ended December 31,
2010
2011
2012
$
(974)
$
526
$
151
22
(4)
32
50
(924)
8
3
4
(46)
(39)
487
1
(2)
(8)
4
(6)
145
10
Comprehensive Income (Loss) Attributable to Ameren Corporation
$
(932)
$
486
$
135
The accompanying notes are an integral part of these consolidated financial statements.
85
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $17 and $20,
respectively)
Unbilled revenue
Miscellaneous accounts and notes receivable
Materials and supplies
Mark-to-market derivative assets
Current regulatory assets
Current accumulated deferred income taxes, net
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Nuclear decommissioning trust fund
Goodwill
Intangible assets
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt
Short-term debt
Accounts and wages payable
Taxes accrued
Interest accrued
Customer deposits
Mark-to-market derivative liabilities
Current regulatory liabilities
Other current liabilities
Total current liabilities
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Regulatory liabilities
Asset retirement obligations
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 10, 14 and 15)
Ameren Corporation Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6
Other paid-in capital, principally premium on common stock
Retained earnings
Accumulated other comprehensive loss
Total Ameren Corporation stockholders’ equity
Noncontrolling Interests
Total equity
TOTAL LIABILITIES AND EQUITY
December 31,
2012
2011
$
209
$
255
$
$
401
322
95
704
125
247
171
95
2,369
16,096
408
411
16
1,786
749
3,370
21,835
355
-
625
68
99
108
155
100
188
1,698
6,626
2,792
72
1,589
445
1,178
668
6,744
$
$
473
324
69
712
115
215
20
112
2,295
18,127
357
411
7
1,603
845
3,223
23,645
179
148
693
65
101
98
161
133
207
1,785
6,677
3,315
79
1,502
428
1,344
447
7,115
2
5,616
1,006
(8)
6,616
151
6,767
21,835
2
5,598
2,369
(50)
7,919
149
8,068
23,645
$
$
The accompanying notes are an integral part of these consolidated financial statements.
86
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Cash Flows From Operating Activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Impairment and other charges
Net gain on sales of properties
Net mark-to-market (gain) loss on derivatives
Depreciation and amortization
Amortization of nuclear fuel
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Allowance for equity funds used during construction
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement benefits
Counterparty collateral, net
Premiums paid on long-term debt repurchases
Taum Sauk insurance recoveries, net of costs
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Nuclear fuel expenditures
Purchases of securities – nuclear decommissioning trust fund
Sales and maturities of securities – nuclear decommissioning trust fund
Proceeds from sales of properties
Tax grants received related to renewable energy properties
Other
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Dividends paid to noncontrolling interest holders
Short-term debt and credit facility repayments, net
Redemptions, repurchases, and maturities:
Long-term debt
Preferred stock
Issuances:
Long-term debt
Common stock
Capital issuance costs
Generator advances received for construction
Repayments of generator advances received for construction
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
Noncash financing activity – dividends on common stock
Cash Paid (Refunded) During the Year:
Interest (net of $30, $30, and $34 capitalized, respectively)
Income taxes, net
Year Ended December 31,
2011
2012
2010
$
(974)
$
526
$
151
2,578
(11)
22
735
83
24
(714)
(36)
25
33
5
(29)
3
(10)
71
(23)
46
(138)
-
1,690
(1,240)
(91)
(403)
384
22
18
-
(1,310)
(382)
(6)
(148)
(760)
-
882
-
(16)
4
-
(426)
(46)
255
209
(7)
433
1
$
$
$
125
(15)
11
747
61
21
346
(34)
-
231
(27)
(36)
(3)
76
(75)
(102)
27
-
(1)
1,878
(1,030)
(62)
(220)
199
53
-
12
(1,048)
(375)
(6)
(581)
(155)
-
-
65
-
5
(73)
(1,120)
(290)
545
255
-
453
(61)
$
$
$
589
(10)
(15)
746
54
23
410
(52)
21
(197)
73
20
10
(47)
71
(5)
(73)
-
54
1,823
(1,042)
(68)
(271)
256
27
-
2
(1,096)
(368)
(8)
(121)
(310)
(52)
-
80
(15)
29
(39)
(804)
(77)
622
545
-
494
(92)
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
87
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock:
Beginning of year
Shares issued
Common stock, end of year
Other Paid-in Capital:
Beginning of year
Shares issued
Stock-based compensation activity
Regulatory recovery of prior-period common stock issuance costs
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income (loss) attributable to Ameren Corporation
Dividends
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
Deferred retirement benefit costs, beginning of year
Change in deferred retirement benefit costs
Deferred retirement benefit costs, end of year
Total accumulated other comprehensive income (loss), end of year
December 31,
2011
2012
2010
$
$
2
-
2
$
2
-
2
2
-
2
5,598
-
18
-
5,616
2,369
(974)
(389)
-
1,006
7
18
25
(57)
24
(33)
(8)
5,520
65
13
-
5,598
2,225
519
(375)
-
2,369
-
7
7
(17)
(40)
(57)
(50)
5,412
80
14
14
5,520
2,455
139
(368)
(1)
2,225
10
(10)
-
(23)
6
(17)
(17)
Total Ameren Corporation Stockholders’ Equity
$
6,616
$
7,919
$
7,730
Noncontrolling Interests:
Beginning of year
Net income attributable to noncontrolling interest holders
Dividends paid to noncontrolling interest holders
Redemptions of preferred stock
Other
Noncontrolling interests, end of year
Total Equity
Common stock shares at beginning of year
Shares issued
Common stock shares at end of year
149
-
(6)
-
8
151
154
7
(6)
-
(6)
149
204
12
(8)
(52)
(2)
154
$
6,767
$
8,068
$
7,884
242.6
-
242.6
240.4
2.2
242.6
237.4
3.0
240.4
The accompanying notes are an integral part of these consolidated financial statements.
88
UNION ELECTRIC COMPANY
STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions)
Year Ended December 31,
2011
2012
2010
Operating Revenues:
Electric
Gas
Other
Total operating revenues
Operating Expenses:
Fuel
Purchased power
Gas purchased for resale
Other operations and maintenance
Loss from regulatory disallowance
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
Other Comprehensive Income
Comprehensive Income
Net Income
Preferred Stock Dividends
Net Income Available to Common Stockholder
$
3,132
139
1
3,272
$
3,222
156
5
3,383
$ 3,030
166
1
3,197
714
78
64
827
-
440
304
866
104
77
934
89
408
296
635
162
91
931
-
382
285
2,427
845
2,774
609
2,486
711
63
14
49
223
671
252
419
-
419
419
3
$
$
61
10
51
209
451
161
290
-
290
290
3
$
$
83
13
70
213
568
199
369
-
369
369
5
416
$
287
$
364
$
$
$
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
89
UNION ELECTRIC COMPANY
BALANCE SHEET
(In millions, except per share amounts)
December 31,
2012
2011
Current Assets:
ASSETS
Cash and cash equivalents
Advances to money pool
Accounts receivable – trade (less allowance for doubtful accounts of $5 and $7,
$
148
24
$
respectively)
Accounts receivable – affiliates
Unbilled revenue
Miscellaneous accounts and notes receivable
Materials and supplies
Current regulatory assets
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
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
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Interest accrued
Current regulatory liabilities
Other current liabilities
Total current liabilities
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Regulatory liabilities
Asset retirement obligations
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 10, 14 and 15)
Stockholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding
Other paid-in capital, principally premium on common stock
Preferred stock not subject to mandatory redemption
Retained earnings
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
201
-
212
1
139
42
348
109
82
1,134
9,958
161
4
145
48
397
163
69
1,159
10,161
408
14
852
449
1,723
$ 13,043
357
7
855
446
1,665
$ 12,757
$
205
345
66
28
60
18
77
799
3,801
2,443
64
917
346
461
158
4,389
$
178
414
73
74
62
57
84
942
3,772
2,132
70
836
328
491
149
4,006
511
1,556
80
1,907
4,054
$ 13,043
511
1,555
80
1,891
4,037
$ 12,757
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
90
UNION ELECTRIC 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:
Loss from regulatory disallowance
Gain on sale of properties
Net mark-to-market (gain) loss on derivatives
Depreciation and amortization
Amortization of nuclear fuel
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Allowance for equity funds used during construction
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement benefits
Taum Sauk insurance recoveries, net of costs
Premiums paid on long-term debt repurchases
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Nuclear fuel expenditures
Purchases of securities – nuclear decommissioning trust fund
Sales and maturities of securities – nuclear decommissioning trust fund
Money pool advances, net
Tax grants received related to renewable energy properties
Other
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Dividends on preferred stock
Redemptions, repurchases, and maturities:
Long-term debt
Preferred stock
Issuances of long-term debt
Capital issuance costs
Capital contribution from parent
Generator advances received for construction
Repayments of generator advances received for construction
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 (Refunded) During the Year:
Interest (net of $15, $25, and $26 capitalized, respectively)
Income taxes, net
Year Ended December 31,
2010
2011
2012
$
419
$
290
$
369
-
-
-
407
83
6
287
(31)
8
27
(48)
(27)
(46)
(35)
14
2
-
(62)
1,004
(595)
(91)
(403)
384
(24)
18
8
(703)
(400)
(3)
(427)
-
482
(7)
1
-
-
(354)
(53)
201
148
220
(3)
$
$
89
(3)
1
377
61
6
155
(30)
(6)
66
(7)
13
(6)
79
(30)
2
(1)
-
1,056
(550)
(62)
(220)
199
-
-
6
(627)
(403)
(3)
(5)
-
-
-
-
-
(19)
(430)
(1)
202
201
210
9
$
$
-
(5)
(1)
355
54
4
292
(50)
10
(122)
7
(24)
55
(101)
75
(3)
54
-
969
(624)
(68)
(271)
256
-
-
7
(700)
(235)
(5)
(70)
(33)
-
(4)
-
13
-
(334)
(65)
267
202
213
(106)
$
$
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
91
UNION ELECTRIC COMPANY
STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Other paid-in capital, end of year
Preferred Stock Not Subject to Mandatory Redemption:
Beginning balance
Redemptions
Preferred stock not subject to mandatory redemption, end of year
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends
Retained earnings, end of year
Total Stockholders’ Equity
December 31,
2011
2012
2010
$
511
$
511
$
511
1,555
1
1,556
80
-
80
1,891
419
(400)
(3)
1,907
1,555
-
1,555
80
-
80
2,007
290
(403)
(3)
1,891
1,555
-
1,555
113
(33)
80
1,878
369
(235)
(5)
2,007
$ 4,054
$ 4,037
$ 4,153
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
92
AMEREN ILLINOIS COMPANY
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions)
Year Ended December 31,
2011
2012
2010
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 (expense)
Interest Charges
Income Before Income Taxes
Income Taxes
Income from Continuing Operations
Income from Discontinued Operations, net of tax
Net Income
Other Comprehensive Loss, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income tax
benefit of $(2), $(2) and $(2), respectively
Other comprehensive income from discontinued operations
Comprehensive Income
Net Income
Preferred Stock Dividends
Net Income Available to Common Stockholder
$
$
$
$
$
$
$
1,739
786
-
2,525
705
408
684
221
130
2,148
377
7
17
(10)
129
238
94
144
-
144
(3)
-
141
144
3
1,940
846
1
2,787
853
492
640
215
129
2,329
458
$ 2,061
953
-
3,014
965
578
635
210
128
2,516
498
7
6
1
136
323
127
196
-
196
(3)
-
193
196
3
$
$
7
13
(6)
143
349
137
212
40
252
(4)
(1)
247
252
4
141
$
193
$
248
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
93
AMEREN ILLINOIS COMPANY
BALANCE SHEET
(In millions)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13,
$
-
$
21
December 31,
2012
2011
respectively)
Accounts receivable – affiliates
Unbilled revenue
Miscellaneous accounts receivable
Materials and supplies
Current regulatory assets
Current accumulated deferred income taxes, net
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Tax receivable – Genco
Goodwill
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt
Borrowings from money pool
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Customer deposits
Mark-to-market derivative liabilities
Mark-to-market derivative liabilities – affiliates
Environmental remediation
Current regulatory liabilities
Other current liabilities
Total current liabilities
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Regulatory liabilities
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
182
10
146
22
173
84
85
47
749
5,052
39
411
934
97
1,481
$ 7,282
$
150
24
146
86
18
85
77
-
37
82
92
797
1,577
1,025
5
672
406
399
2,507
201
15
146
6
199
306
58
65
1,017
4,770
56
411
748
211
1,426
$ 7,213
$
1
-
133
103
15
76
99
200
63
76
92
858
1,657
895
7
666
495
183
2,246
Commitments and Contingencies (Notes 2, 14 and 15)
Stockholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding
Other paid-in capital
Preferred stock not subject to mandatory redemption
Retained earnings
Accumulated other comprehensive income
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
-
1,965
62
360
14
2,401
$ 7,282
-
1,965
62
408
17
2,452
$ 7,213
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
94
AMEREN ILLINOIS COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2010
2011
2012
Cash Flows From Operating Activities:
Net income
Income from discontinued operations, net of tax
Adjustments to reconcile net income to net cash provided by operating
$ 144
-
$
196
-
$ 252
(40)
activities:
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 benefits
Counterparty collateral, net
Premiums paid on long-term debt repurchases
Operating cash flows provided by discontinued operations
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Returns from (advances to) ATXI for construction
Proceeds from note receivable – Genco
Other
Capital expenditures of discontinued operations
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Dividends on preferred stock
Money pool borrowings, net
Redemptions, repurchases, and maturities:
Long-term debt
Preferred stock
Issuances of long-term debt
Capital issuance costs
Repayments of generator advances received for construction
Generator advances received for construction
Capital contribution from parent
Net financing activities used in discontinued operations
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 (Refunded) During the Year:
Interest (net of $2, $2, and $1 capitalized, respectively)
Income taxes, net
Noncash investing activity – asset transfer from ATXI
Noncash financing activity – capital contribution from parent
214
11
104
(11)
23
20
(21)
3
22
72
(26)
40
(76)
-
519
(442)
-
-
5
-
(437)
(189)
(3)
24
(333)
-
400
(6)
-
4
-
-
(103)
(21)
21
-
$
$ 125
(22)
$
-
-
206
8
155
(14)
146
(21)
(46)
(12)
(3)
(30)
(101)
20
-
-
504
(351)
49
-
6
-
(296)
(327)
(3)
-
(150)
-
-
-
(53)
5
19
-
(509)
(301)
322
21
201
10
210
(3)
(84)
9
(44)
11
32
33
(7)
(100)
-
113
593
(281)
(10)
45
5
(6)
(247)
(133)
(4)
-
(40)
(19)
-
(4)
(39)
16
-
(107)
(330)
16
306
$ 322
137
(14)
$ 160
(39)
-
-
$
7
6
$
$
$
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
95
AMEREN ILLINOIS COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Contribution of Ameren-owned preferred stock without consideration
Transfer of AERG to parent (Notes 1 and 16)
Other paid-in capital, end of year
Preferred Stock Not Subject to Mandatory Redemption:
Beginning balance
Redemptions
Contribution of Ameren-owned preferred stock without consideration
Other
Preferred stock not subject to mandatory redemption, end of year
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends
Transfer of AERG to parent (Notes 1 and 16)
Other
Retained earnings, end of year
Accumulated Other Comprehensive Income:
Deferred retirement benefit costs, beginning of year
Change in deferred retirement benefit costs
Change in accumulated other comprehensive income from discontinued
operations
Deferred retirement benefit costs, end of year
Total accumulated other comprehensive income, end of year
December 31,
2011
2012
2010
$
-
$
-
$
-
1,965
-
-
-
1,965
1,952
13
-
-
1,965
62
-
-
-
62
408
144
(189)
(3)
-
-
360
17
(3)
-
14
14
62
-
-
-
62
542
196
(327)
(3)
-
-
408
20
(3)
-
17
17
2,223
6
33
(310)
1,952
115
(19)
(33)
(1)
62
709
252
(133)
(4)
(281)
(1)
542
25
(4)
(1)
20
20
Total Stockholders’ Equity
$ 2,401
$ 2,452
$ 2,576
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
96
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY
AMEREN ILLINOIS COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 2012
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 its
equity interests in its subsidiaries. Ameren’s subsidiaries
are separate, independent legal entities with separate
businesses, assets, and liabilities. These subsidiaries
operate, as the case may be, rate-regulated electric
generation, transmission and distribution businesses, rate-
regulated natural gas transmission and distribution
businesses, and merchant electric generation businesses.
Dividends on Ameren’s common stock and the payment of
other expenses by Ameren depend on distributions made to
it by its subsidiaries. Ameren’s principal subsidiaries are
listed below.
‰
‰
‰
Union Electric Company, or Ameren Missouri, operates
a rate-regulated electric generation, transmission, and
distribution business, and a rate-regulated natural gas
transmission and distribution business in Missouri.
Ameren Missouri was incorporated in Missouri in 1922
and is successor to a number of companies, the oldest
of which was organized in 1881. It is the largest electric
utility in the state of Missouri. It supplies electric and
natural gas service to a 24,000-square-mile area in
central and eastern Missouri. This area has an
estimated population of 2.8 million and includes the
Greater St. Louis area. Ameren Missouri supplies
electric service to 1.2 million customers and natural
gas service to 127,000 customers.
Ameren Illinois Company, or Ameren Illinois, operates a
rate-regulated electric and natural gas transmission and
distribution business in Illinois. Ameren Illinois was
created by the merger of CILCO and IP with and into
CIPS. CIPS was incorporated in Illinois in 1923 and is
successor to a number of companies, the oldest of
which was organized in 1902. Ameren Illinois supplies
electric and natural gas utility service to portions of
central and southern Illinois having an estimated
population of 3.1 million in an area of 40,000 square
miles. Ameren Illinois supplies electric service to
1.2 million customers and natural gas service to
806,000 customers.
AER consists of non-rate-regulated operations,
including Genco, AERG, Marketing Company, and,
through Genco, an 80% ownership interest in EEI,
which Ameren consolidates for financial reporting
purposes.
Ameren has various other subsidiaries responsible for
activities such as the provision of shared services.
In December 2012, Ameren determined that it intends
to, and it is probable that it will, exit its Merchant
Generation business before the end of the previously
estimated useful lives of that business’s long-lived assets.
This determination resulted from Ameren’s analysis of the
current and projected future financial condition of its
Merchant Generation business segment, including the need
to fund Genco debt maturities beginning in 2018, and its
conclusion that this business segment is no longer a core
component of its future business strategy. In consideration
of this determination, Ameren has begun planning to
reduce, and ultimately to eliminate, the Merchant
Generation business segment’s, including Genco’s, reliance
on Ameren’s financial support and shared services support.
Furthermore, Ameren recorded a noncash long-lived asset
impairment charge to reduce the carrying values of the
Merchant Generation energy centers, except for the Joppa
coal-fired energy center, to their estimated fair values. See
Note 17 – Impairment and Other Charges for additional
information. Ameren’s date and method of exit from the
Merchant Generation business is currently uncertain. Exit
strategies may include the sale of all or parts of the
Merchant Generation business and the restructuring of all
or a portion of Ameren’s equity position in Genco. Ameren’s
Merchant Generation long-lived assets have not been
classified as held-for-sale under authoritative accounting
guidance as all criteria to qualify for that presentation were
not met as of December 31, 2012. Specifically, Ameren did
not consider it probable that a disposition would occur
within one year.
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG
and AER completed a two-step corporate internal
reorganization. The first step of the reorganization was the
Ameren Illinois Merger. The second step of the
reorganization involved the distribution of AERG stock from
Ameren Illinois to Ameren and the subsequent contribution
by Ameren of the AERG stock to AER. Ameren Illinois
segregated AERG’s operating results and cash flows and
presented them separately as discontinued operations in its
consolidated statement of income and consolidated
statement of cash flows, respectively, for all periods
presented prior to October 1, 2010, in this report. See
Note 16 – 2010 Corporate Reorganization for additional
information.
The financial statements of Ameren and Ameren Illinois
are prepared on a consolidated basis and therefore include
the accounts of their respective majority-owned
subsidiaries. Ameren Illinois’ financial statements are
consolidated because Ameren Illinois included AERG in its
statements of income and cash flows during 2010. Ameren
Missouri has no subsidiaries, and therefore its financial
statements are not prepared on a consolidated basis. All
significant intercompany transactions have been eliminated.
All tabular dollar amounts are in millions, unless otherwise
indicated.
Our accounting policies conform to GAAP. Our
financial statements reflect all adjustments (which include
normal, recurring adjustments) that are necessary, in our
97
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, and FERC. In accordance with
authoritative accounting guidance regarding accounting for
the effects of certain types of regulation, Ameren Missouri
and Ameren Illinois defer certain costs as assets pursuant
to actions of rate regulators or because of expectations that
the companies will be able to recover such costs in rates
charged to customers. Ameren Missouri and Ameren
Illinois also defer certain amounts as liabilities pursuant to
actions of rate regulators or based on the expectation that
such amounts will be returned to customers in future rates.
Regulatory assets and liabilities are amortized consistent
with the period of expected regulatory treatment. In addition
to the cost recovery mechanisms discussed in the
Purchased Gas, Power and Fuel Rate-adjustment
Mechanisms section below, Ameren Missouri and Ameren
Illinois have approvals from regulators to use other cost
recovery mechanisms. Ameren Missouri has a vegetation
management and infrastructure inspection cost tracker,
pension and postretirement benefit cost tracker, uncertain
Materials and Supplies
tax positions tracker, renewable energy standards cost
tracker, and, starting in 2013, a storm restoration cost
tracker and the MEEIA energy efficiency cost recovery
mechanisms. Ameren Illinois has an environmental cost
rider, asbestos-related litigation rider, energy efficiency
rider, and a bad debt rider. See Note 2 – Rate and
Regulatory Matters for additional information on regulatory
assets and liabilities. In addition, other costs that Ameren
Missouri and Ameren Illinois expect to recover from
customers are recorded as construction work in progress
and property and plant, net. See Note 3 – Property and
Plant, Net.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and
temporary investments purchased with an original maturity
of three months or less.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our
best estimate of existing accounts receivable that will
ultimately be uncollectible. The allowance is calculated by
applying estimated loss factors to various classes of
outstanding receivables, including unbilled revenue. The
loss factors used to estimate uncollectible accounts are
based upon both historical collections experience and
management’s best estimate of future collections success
given the existing and anticipated future collections
environment. Ameren Illinois has a rate mechanism that
adjusts rates for bad debt expense above or below those
being collected in rates.
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method.
Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when
installed, as appropriate. The following table presents a breakdown of materials and supplies for each of the Ameren
Companies at December 31, 2012, and 2011:
2012
Fuel(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas stored underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011
Fuel(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas stored underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Consists of coal, oil, paint, propane, and tire chips.
Property and Plant
Ameren(a)
Ameren Missouri
Ameren Illinois
$
$
$
$
276
131
297
704
251
171
290
712
$
$
$
$
198
18
181
397
150
22
176
348
$
$
$
$
-
113
60
173
-
149
50
199
We capitalize the cost of additions to and betterments
of units of property and plant. The cost includes labor,
material, applicable taxes, and overhead. An allowance for
funds used during construction, as discussed specifically
below, is also capitalized as a cost of our rate-regulated
assets. Interest incurred during construction is capitalized
as a cost of merchant generation assets. Maintenance
expenditures, including nuclear refueling and maintenance
outages, are expensed as incurred. When units of
depreciable property are retired, the original costs, less
98
salvage values, are charged to accumulated depreciation.
Asset removal costs incurred by our merchant generation
operations that do not constitute legal obligations are
expensed as incurred. Asset removal costs accrued by our
rate-regulated operations that do not constitute legal
obligations are classified as a regulatory liability. See Asset
Retirement Obligations below and Note 3 – Property and
Plant, Net, for additional information.
Depreciation
Depreciation is provided over the estimated lives of the
various classes of depreciable property by applying
composite rates on a straight-line basis to the cost basis of
such property. The provision for depreciation for the
Ameren Companies in 2012, 2011 and 2010 ranged from
3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the
allowance for funds used during construction, or the cost of
borrowed funds and the cost of equity funds (preferred and
common stockholders’ equity) applicable to rate-regulated
construction expenditures, as is the utility industry’s
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 during construction, and it
treats such financing costs in the same manner as
construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of
allowance for funds used during construction and other
construction costs occurs when completed projects are
placed in service and reflected in customer rates. The
following table presents the annual allowance for funds
used during construction rates that were utilized during
2012, 2011 and 2010:
Ameren . . . . . . . . . .
Ameren Missouri . . .
Ameren Illinois . . . .
2012
2011
2010
8% - 9%
8% - 9%
8% - 9%
8
9
8
9
8
9
Goodwill and Intangible Assets
Goodwill. Goodwill represents the excess of the
purchase price of an acquisition over the fair value of the
net assets acquired. As of December 31, 2012, Ameren’s
and Ameren Illinois’ goodwill related to Ameren’s
acquisitions of IP in 2004 and of CILCORP in 2003.
Ameren has three reporting units, which also represent
Ameren’s reportable segments. Ameren’s reporting units
are Ameren Missouri, Ameren Illinois, and Merchant
Generation. Ameren Illinois has one reporting unit, Ameren
Illinois. Ameren’s and Ameren Illinois’ reporting units have
been defined and goodwill has been evaluated at the
operating segment level in accordance with authoritative
accounting guidance. Our reporting units represent
businesses for which discrete financial information is
available and reviewed regularly by management. All of
Ameren’s and Ameren Illinois’ goodwill at December 31,
2012, and 2011 has been assigned to the Ameren Illinois
reporting unit. See Note 17 – Impairment and Other
Charges for information regarding the 2010 goodwill
impairment charge, which represented all the goodwill
assigned to Ameren’s Merchant Generation reporting unit.
We evaluate goodwill for impairment as of October 31
of each year, or more frequently if events and
circumstances indicate that the asset might be impaired.
Ameren and Ameren Illinois applied a qualitative goodwill
evaluation model for its annual goodwill impairment test
conducted as of October 31, 2012. Based on the results of
Ameren’s and Ameren Illinois’ qualitative assessment,
Ameren and Ameren Illinois believe it was more likely than
not that the fair value of the Ameren Illinois reporting unit
exceeded its carrying value as of October 31, 2012,
indicating no impairment of Ameren’s or Ameren Illinois’
goodwill. The following factors, not meant to be all-
inclusive, were considered by Ameren and Ameren Illinois
when assessing whether it was more likely than not that the
fair value of the Ameren Illinois reporting unit exceeded its
carrying value for the October 31, 2012, test:
‰ Macroeconomic conditions, including those conditions
within Ameren Illinois’ service territory;
Pending rate case outcomes and future rate case
outcomes;
Changes in laws and potential law changes;
Observable industry market multiples;
Achievement of IEIMA performance metrics and the
yield of the 30-year United States treasury bonds; and
Actual and forecasted financial performance.
‰
‰
‰
‰
‰
The goodwill assigned to the Ameren Illinois reporting
unit on the December 31, 2012 balance sheets of Ameren
and Ameren Illinois had no accumulated goodwill
impairment losses. Ameren and Ameren Illinois will
continue to monitor the actual and forecasted operating
results, cash flows, market capitalization, and observable
industry market multiples of the Ameren Illinois reporting
unit for signs of possible declines in estimated fair value
and potential goodwill impairment.
Intangible Assets. Ameren and Ameren Missouri
classify emission allowances and renewable energy credits
as intangible assets. We evaluate intangible assets for
impairment if events or changes in circumstances indicate
that their carrying amount might be impaired.
At December 31, 2012, Ameren’s and Ameren
Missouri’s intangible assets consisted of renewable energy
credits obtained through wind and solar power purchase
agreements. The book value of Ameren’s and Ameren
Missouri’s renewable energy credits was $16 million and
$14 million at December 31, 2012, respectively. The book
value of Ameren’s and Ameren Missouri’s renewable energy
credits was $7 million and $7 million at December 31,
2011, respectively.
99
Renewable energy credits and emission allowances are
Investments
charged to purchased power expense and fuel expense,
respectively, as they are used in operations. The following
table presents amortization expense based on usage of
renewable energy credits and emission allowances, net of
gains from sales, for Ameren, Ameren Missouri, and
Ameren Illinois during the years ended December 31, 2012,
2011, and 2010. Amortization expense based on Ameren
Missouri’s renewable energy standards compliance costs is
expensed up to $1 million annually beginning in August
each year in accordance with MoPSC’s 2011 electric rate
order, and the remainder is deferred as a regulatory asset
pending recovery from customers through rates. The
following table does not include the intangible asset
impairment charges referenced below.
Ameren Missouri
. . . . . . . . . .
Ameren Illinois . . . . . . . . . . . .
. . . . . . . . . . . . . . . .
Other(b)(c)
Ameren(c) . . . . . . . . . . . . . . . .
2012
$ (a)
4
3
$
7
2011
$ (a)
3
3
$
6
2010
$
6
7
22
$ 35
(a) Less than $1 million.
(b) Consists of renewable energy credit expense for Marketing
(c)
Company and emission allowance expense for Genco and AERG.
Includes allowances consumed that were recorded through
purchase accounting.
During 2011, Ameren recorded a $2 million noncash
pretax impairment charge of Merchant Generation’s
emission allowances. Ameren Missouri recorded a
$1 million impairment of its SO2 emission allowances by
reducing a previously established regulatory liability relating
to the SO2 emission allowances, which had no impact on
earnings. The impairment was triggered by a significant
observable decline in the market price of SO2 and NOX
allowances used for CAIR compliance. See Note 17 –
Impairment and Other Charges for additional information,
including a discussion of the 2010 intangible asset
impairment charge.
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and
used for impairment when events or changes in
circumstances indicate that the carrying value of such
assets may not be recoverable. Whether impairment has
occurred is determined by comparing the estimated
undiscounted cash flows attributable to the assets with the
carrying value of the assets. If the carrying value exceeds
the undiscounted cash flows, we recognize an impairment
charge equal to the amount of the carrying value that
exceeds the estimated fair value of the assets. In the period
in which we determine an asset meets held for sale criteria,
we record an impairment charge to the extent the book
value exceeds its fair value less cost to sell. See Note 17 –
Impairment and Other Charges for additional information
about Ameren’s and Ameren Missouri’s long-lived asset
impairments.
Ameren and Ameren Missouri evaluate for impairment
the investments held in Ameren Missouri’s nuclear
decommissioning trust fund. Losses on assets in the trust
fund could result in higher funding requirements for
decommissioning costs, which Ameren Missouri believes
would be recovered in electric rates paid by its customers.
Accordingly, Ameren and Ameren Missouri recognize a
regulatory asset on their balance sheets for losses on
investments held in the nuclear decommissioning trust
fund. See Note 9 – Nuclear Decommissioning Trust Fund
Investments for additional information.
Environmental Costs
Liabilities for environmental costs are recorded on an
undiscounted basis when it is probable that a liability has
been incurred and the amount of the liability can be
reasonably estimated. 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
The Ameren Companies record operating revenue for
electric or natural gas service when it is delivered to
customers. We accrue an estimate of electric and natural
gas revenues for service rendered but unbilled at the end of
each accounting period.
Beginning in 2012, Ameren Illinois elected to
participate in performance-based formula ratemaking
framework pursuant to the IEIMA. The IEIMA provides for
an annual reconciliation of Ameren Illinois’ electric
distribution revenue requirement. As of each balance sheet
date, Ameren Illinois records its best estimate of the electric
distribution revenue impact resulting from the reconciliation
of the revenue requirement necessary to reflect the actual
costs incurred for that year with the revenue requirement
that was in effect for that year. If the current year’s revenue
requirement is greater than the revenue requirement
customer rates were based upon, an increase to electric
operating revenues with an offset to a regulatory asset is
recorded to reflect the expected recovery of those additional
costs from customers within the next two years. If the
current year’s revenue requirement is less than the revenue
requirement customer rates were based upon, a reduction
to electric operating revenues with an offset to a regulatory
liability is recorded to reflect the expected refund to
customers within the next two years. See Note 2 – Rate and
100
Regulatory Matters for information regarding Ameren
Illinois’ revenue requirement reconciliation pursuant to the
IEIMA.
Beginning in 2013, Ameren Illinois will record the
impact of a revenue requirement reconciliation for its
electric transmission jurisdiction, pursuant to FERC-
approved rate treatment.
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
“Operating Revenues – Other.”
Nuclear Fuel
Ameren Missouri’s cost of nuclear fuel is capitalized
and then 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 “Operating Expenses – Fuel” in the statement of income.
Purchased Gas, Power and Fuel Rate-adjustment
Mechanisms
Ameren Missouri and Ameren Illinois have various
rate-adjustment mechanisms in place that provide for the
recovery of purchased natural gas and electric fuel and
purchased power costs. See Note 2 – Rate and Regulatory
Matters for the regulatory assets and liabilities recorded at
December 31, 2012, and 2011, related to the rate-
adjustment mechanisms discussed below.
In Ameren Missouri’s and Ameren Illinois’ retail natural
gas utility jurisdictions, changes in natural gas costs are
reflected in billings to their natural gas utility customers
through PGA clauses. The differences between actual
natural gas costs and costs billed to customers in a given
period are deferred as regulatory assets or liabilities. The
deferred amounts are either billed or refunded to natural
gas utility customers in a subsequent period.
In Ameren Illinois’ retail electric utility jurisdictions,
changes in purchased power costs and transmission
service cost are reflected in billings to their electric utility
customers through pass-through rate-adjustment clauses.
The differences between actual purchased power and
transmission service costs and costs billed to customers in
a given period are deferred as regulatory assets or liabilities.
The deferred amounts are either billed or refunded to
electric utility customers in a subsequent period.
Ameren Missouri has a FAC that allows an adjustment
of electric rates three times per year for a pass-through to
customers of 95% of changes in fuel, certain fuel additives,
emission allowances, purchased power costs, transmission
costs, and MISO costs and revenues, net of off-system
revenues, greater or less than the amount set in base rates
without a traditional rate proceeding, subject to MoPSC
prudency review. The differences between the cost of fuel
incurred and the cost of fuel recovered from Ameren
Missouri customers’ base rates are deferred as regulatory
assets or liabilities. The deferred amounts are either billed
or refunded to Ameren Missouri’s electric utility customers
in a subsequent period. The MoPSC’s December 2012
electric rate order changed the FAC to include activated
carbon, limestone and urea costs, along with transmission
revenues starting in 2013.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are
recorded by Ameren, Ameren Missouri and Ameren Illinois
using settlement information provided by MISO. These
purchase and sale transactions are accounted for on a net
hourly position. We record net purchases in a single hour in
“Operating Expenses – Purchased power” and net sales in a
single hour in “Operating Revenues – Electric” in our
statements of income (loss). On occasion, prior-period
transactions will be resettled outside the routine settlement
process because of a change in MISO’s tariff or a material
interpretation thereof. In these cases, the Ameren
Companies recognize expenses associated with
resettlements once the resettlement is probable and the
resettlement amount can be estimated, and the Ameren
Companies recognize revenues once the resettlement
amount is received.
Stock-based Compensation
Stock-based compensation cost is measured at the
grant date based on the fair value of the award. Ameren
recognizes as compensation expense the estimated fair
value of stock-based compensation on a straight-line basis
over the requisite service period. See Note 12 – Stock-
based Compensation for additional information.
Excise Taxes
Excise taxes levied on us are reflected on Ameren
Missouri customer electric bills and on Ameren Missouri
and Ameren Illinois customer natural gas bills. They are
recorded gross in “Operating Revenues – Electric,”
“Operating Revenues – Gas” and “Operating Expenses –
Taxes other than income taxes” on the statement of income
(loss). Excise taxes reflected on Ameren Illinois electric
customer bills are imposed on the customer and are
therefore not included in revenues and expenses. They are
recorded as tax collections payable and included in “Taxes
accrued” on the balance sheet. The following table presents
excise taxes recorded in “Operating Revenues – Electric,”
“Operating Revenues – Gas” and “Operating Expenses –
Taxes other than income taxes” for the years ended 2012,
2011 and 2010:
2012
2011
2010
Ameren Missouri . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . . . .
$
$
139
54
193
$
$
137
57
194
$
$
130
59
189
101
Income Taxes
Ameren uses an asset and liability approach for its
financial accounting and reporting of income taxes, in
accordance with authoritative accounting guidance.
Deferred tax assets and liabilities are recognized for
transactions that are treated differently for financial
reporting and income tax return purposes. These deferred
tax assets and liabilities are based on statutory tax rates.
We recognize that regulators will probably reduce
future revenues for deferred tax liabilities that were initially
recorded at rates in excess of the current statutory rate.
Therefore, reductions in the deferred tax liability, which
were recorded because of decreases in the statutory rate,
have been credited to a regulatory liability. A regulatory
asset has been established to recognize the probable
recovery in rates of future income taxes, resulting
principally from the reversal of allowance for funds used
during construction. This refers to equity and temporary
differences related to property and plant acquired before
1976 that were unrecognized temporary differences prior to
the adoption of the authoritative accounting guidance for
income taxes.
Investment tax credits used on tax returns for prior
years have been deferred for book purposes; the credits are
being amortized over the useful lives of the related
investment. Deferred income taxes were recorded on the
temporary difference represented by the deferred
investment tax credits and a corresponding regulatory
liability. This recognizes the expected reduction in rate
revenue for future lower income taxes associated with the
amortization of the investment tax credits. See Note 13 –
Income Taxes.
For certain renewable energy construction projects
placed in service in 2010 and 2012, Ameren Missouri
elected to seek federal cash tax grants in lieu of investment
tax credits for which the projects also qualified. These
grants were accounted for using a grant recognition
accounting model. Ameren Missouri elected to reduce the
basis of property as cash grants are received, which will
reduce the amount of depreciation expense recognized in
future periods. In 2012, Ameren Missouri received
$18 million in federal cash tax grants.
Ameren Missouri, Ameren Illinois, and all the other
Ameren subsidiary companies are parties to a tax allocation
agreement with Ameren that provides for the allocation of
consolidated tax liabilities. The tax allocation agreement
specifies that each party be allocated an amount of tax
similar to that which would be owed had the party been
separately subject to tax. Any net benefit attributable to the
parent is reallocated to other members. That allocation is
treated as a contribution of capital to the party receiving the
benefit.
Noncontrolling Interests
Ameren’s noncontrolling interests comprised the 20%
of EEI not owned by Ameren and the preferred stock not
subject to mandatory redemption of Ameren’s subsidiaries.
These noncontrolling interests are classified as a
component of equity separate from Ameren’s equity in its
consolidated balance sheet.
Earnings per Share
There were no material differences between Ameren’s
basic and diluted earnings per share amounts in 2012,
2011, and 2010. The number of dilutive stock options,
restricted stock shares, and performance share units had an
immaterial impact on earnings per share. There were no
assumed stock option conversions in 2010, as the
remaining stock options were not dilutive. All of Ameren’s
stock options expired in February 2010.
Accounting Changes and Other Matters
The following is a summary of recently adopted
authoritative accounting guidance as well as guidance
issued but not yet adopted that could impact the Ameren
Companies.
Disclosures about Fair Value Measurements
In May 2011, FASB issued additional authoritative
guidance regarding fair value measurements. The guidance
amended the disclosure requirements for fair value
measurements in order to align the principles for fair value
measurements and the related disclosure requirements
under GAAP and International Financial Reporting
Standards. The amendments did not affect the Ameren
Companies’ results of operations, financial position, or
liquidity, as this guidance only requires additional
disclosures. The Ameren Companies adopted this guidance
for the first quarter of 2012. See Note 8 Fair Value
Measurements for the required additional disclosures.
Presentation of Comprehensive Income
In June 2011, FASB amended its guidance on the
presentation of comprehensive income in financial
statements. The amended guidance changed the
presentation of comprehensive income in the financial
statements. It requires entities to report components of
comprehensive income either in a continuous statement of
comprehensive income or in two separate but consecutive
statements. This guidance was effective for the Ameren
Companies beginning in the first quarter of 2012 with
retroactive application required. The implementation of the
amended guidance did not affect the Ameren Companies’
results of operations, financial position, or liquidity.
In February 2013, the FASB amended this guidance to
require an entity to provide information about the amounts
reclassified out of accumulated OCI by component. In
addition, an entity is required to present significant amounts
reclassified out of accumulated OCI by the respective line
items of net income either on the face of the statement
where net income is presented or in the footnotes. The
amendments will not affect the Ameren Companies’ results
of operations, financial position, or liquidity, as this
guidance only requires additional disclosures and
102
substantially all the information that this amended guidance
requires is already disclosed elsewhere in the financial
statements. This guidance will be effective for the Ameren
Companies beginning in the first quarter of 2013 on a
prospective basis.
Disclosures about Offsetting Assets and Liabilities
In December 2011, FASB issued additional
authoritative guidance to improve information disclosed
about financial and derivative instruments. The guidance
requires an entity to disclose information about offsetting
and related arrangements to enable users of the financial
statements to understand the effect of those arrangements
on financial position. In January 2013, FASB amended this
guidance to limit the scope to derivative instruments,
repurchase agreements and reverse repurchase
agreements, and securities borrowing and securities
lending transactions. The amendments will not affect the
Ameren Companies’ results of operations, financial
positions, or liquidity, as this guidance only requires
additional disclosures. This guidance will be effective for the
Ameren Companies beginning in the first quarter of 2013
with retrospective application required.
Asset Retirement Obligations
Authoritative accounting guidance requires us to
record the estimated fair value of legal obligations
associated with the retirement of tangible long-lived assets
in the period in which the liabilities are incurred and to
capitalize a corresponding amount as part of the book value
of the related long-lived asset. In subsequent periods, we
are required to make adjustments to AROs based on
changes in the estimated fair values of the obligations.
Corresponding increases in asset book values are
depreciated over the remaining useful life of the related
asset. Uncertainties as to the probability, timing, or amount
of cash flows associated with AROs affect our estimates of
fair value. Ameren, Ameren Missouri, Genco and AERG
have recorded AROs for retirement costs associated with
Ameren Missouri’s Callaway energy center
decommissioning costs, asbestos removal, CCR storage
facilities, and river structures. Also, Ameren Illinois has
recorded AROs for retirement costs associated with
asbestos removal. In addition, Ameren, Ameren Missouri
and Ameren Illinois have recorded AROs for the disposal of
certain transformers.
Asset removal costs accrued by our rate-regulated
operations that do not constitute legal obligations are
classified as a regulatory liability. See Note 2 – Rate and
Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2012 and
2011:
Balance at December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion in 2011(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in estimates(e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
363
-
(1)
20
(54)
$
3
-
(c)
(c)
(c)
Ameren
Missouri(a)
Ameren
Illinois(b)
Genco
AERG
Ameren(a)
$
74
(c)
(2)
5
(6)
$
35
-
(c)
2
(6)
$
475
(c)
(3)
27
(66)
Balance at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
328
$
3
$
71
$
31
$
433(f)
Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion in 2012(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in estimates(g) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
(1)
18
1
-
(c)
(c)
(c)
2
(5)
4
(3)
-
(c)
2
2
2
(6)
24
(c)
Balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
346
$
3
$
69
$
35
$
453(h)
(a) The nuclear decommissioning trust fund assets of $408 million and $357 million as of December 31, 2012, and 2011, respectively, were
restricted for decommissioning of the Callaway energy center.
(b) Balance included in “Other deferred credits and liabilities” on the balance sheet.
(c) Less than $1 million.
(d) Accretion expense was recorded as an increase to regulatory assets at Ameren Missouri and Ameren Illinois.
(e) Ameren Missouri changed its fair value estimate related to its Callaway energy center decommissioning costs because of a cost study
performed in 2011 and a decline in the cost escalation factor assumptions. Additionally, Ameren Missouri, Genco and AERG changed their fair
value estimates related to retirement costs for asbestos removal, river structures and their CCR storage facilities.
(f) Balance included $5 million in “Other current liabilities” on the balance sheet as of December 31, 2011.
(g) Ameren Missouri and Genco changed their fair value estimates for asbestos removal. The estimates for asbestos removal costs at Genco’s
Hutsonville and Meredosia energy centers decreased because less asbestos than anticipated was found in the energy centers’ structures during
reviews made after the closure of these energy centers, and because removal was more cost efficient than anticipated due to the closure.
Additionally, Genco and AERG changed their fair value estimates related to updated retirement dates for certain CCR storage facilities.
(h) Balance included $8 million in “Other current liabilities” on the balance sheet as of December 31, 2012.
103
Employee Separation Charges
During the fourth quarter of 2011, as part of efforts to
reduce operations and maintenance expenses, Ameren
Missouri and Ameren Services extended voluntary
separation offers consistent with Ameren’s standard
management separation program to eligible management
and labor union-represented employees. Approximately 340
employees of Ameren Missouri and Ameren Services
accepted the offers and left their employment by
December 31, 2011. Ameren and Ameren Missouri
recorded a pretax charge to earnings of $28 million and
$27 million, respectively, for the severance costs related to
these offers. These charges were recorded in “Other
operations and maintenance” expense in each company’s
statement of income for the year ended December 31,
2011. Substantially all of the severance costs were paid in
the first quarter of 2012 and were recorded in “Accounts
and wages payable” on each company’s balance sheet at
December 31, 2011. The severance costs related to
participating Ameren Services employees were allocated to
affiliates consistent with the terms of its support services
agreement, which is described in Note 14 – Related Party
Transactions.
In each of the past three years, Ameren’s Merchant
Generation segment initiated separation programs to reduce
positions under the terms and benefits consistent with
Ameren’s standard management separation program.
Ameren recorded pretax charges related to these programs
of $1 million, $4 million, and $4 million in 2012, 2011, and
2010, respectively. The 2012 and 2010 charges were
recorded in “Other operations and maintenance” expense
on Ameren’s consolidated statement of income. The 2011
charge related to the closure of the Meredosia and
Hutsonville energy centers and was recorded in
“Impairment and other charges” on Ameren’s consolidated
statement of income. See Note 17 – Impairment and Other
Charges for additional information.
Merchant Generation Asset Sales
In February 2012, Ameren completed the sale of its
Medina Valley energy center’s net property and plant for
cash proceeds of $16 million and an additional $1 million to
be paid at the two-year anniversary date of the sale if all
terms of the sale agreement have been met. Ameren
recognized a $10 million pretax gain from this sale. In
October 2012, the buyer of the Medina Valley energy center
asserted that AER has not met all the terms of the sale
agreement. AER is evaluating the buyer’s claim. The dollar
amount of the asserted claim does not materially differ from
the payment due at the two-year anniversary date of the
sale.
In 2012, Ameren completed the sale of some Merchant
Generation land and an office building for cash proceeds of
$5 million. Ameren recognized a $1 million pretax gain from
these sales.
In June 2010, Ameren completed the sale of 25% of
Genco’s Columbia CT energy center to the city of Columbia,
Missouri. Ameren received cash proceeds of $18 million
and recognized a $5 million pretax gain from the sale. In
June 2011, Ameren completed the sale of Genco’s
remaining interest in the Columbia CT energy center to the
city of Columbia, Missouri. Ameren received cash proceeds
of $45 million and recognized an $8 million pretax gain
from the sale. In 2011, Ameren sold additional property and
assets for cash proceeds of $4 million, which resulted in
pretax gains of $4 million.
NOTE 2 – RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory
proceedings and related lawsuits. We are unable to predict
the ultimate outcome of these matters, the timing of the
final decisions of the various agencies and courts, or the
impact on our results of operations, financial position, or
liquidity.
Missouri
2009, 2010, and 2011 Electric Rate Orders
Noranda, Ameren Missouri’s largest electric customer,
and the MoOPC appealed certain aspects of the MoPSC’s
January 2009 electric rate order to the Stoddard County
Circuit Court. In September 2009, the Stoddard County
Circuit Court issued a stay of the electric order as it applied
specifically to Noranda’s electric service account, which
allowed Noranda to pay a portion of its monthly billings into
the Stoddard County Circuit Court’s registry until the court
ultimately rendered a decision on the appeal. In August
2010, the Stoddard County Circuit Court issued a judgment
that reversed part of the MoPSC’s January 2009 electric
rate order. However, upon issuance, the Stoddard County
Circuit Court suspended its own judgment. Ameren
Missouri appealed the Stoddard County Circuit Court’s
judgment and, in November 2011, the Missouri Court of
Appeals issued a ruling that upheld the MoPSC’s January
2009 electric rate order. In March 2012, the Stoddard
County Circuit Court released to Ameren Missouri all of the
funds held in its registry relating to the stay, which totaled
$21 million, reducing the previously recorded trade
accounts receivable.
In May 2010, the MoPSC issued an order approving an
increase for Ameren Missouri in annual revenues for
electric service of $230 million. The MIEC, MoOPC, and four
industrial customers appealed certain aspects of the
MoPSC’s May 2010 electric rate order to the Cole County
Circuit Court. In December 2010, the Cole County Circuit
Court issued a stay of the electric order as it applied
specifically to four industrial customers’ electric service
accounts, which allowed them to pay a portion of their
monthly billings into the Cole County Circuit Court’s registry
until the court ultimately rendered a decision on the appeal.
In May 2012, the Cole County Circuit Court issued a ruling
that upheld the MoPSC’s May 2010 electric rate order and
released to Ameren Missouri all of the funds held in its
registry relating to the stay, which totaled $16 million,
reducing the previously recorded trade accounts receivable.
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In July 2011, the MoPSC issued an order approving an
increase for Ameren Missouri in annual revenues for
electric service of $173 million, including $52 million
related to an increase in normalized net fuel costs above the
net fuel costs included in base rates previously authorized
by the MoPSC in its May 2010 electric rate order. The
MoPSC’s July 2011 electric rate order disallowed the
recovery of all costs of enhancements, or costs that would
have been incurred absent the breach, related to the
rebuilding of the Taum Sauk energy center in excess of
amounts recovered from property insurance. As a result,
Ameren and Ameren Missouri each recorded in 2011 a
pretax charge to earnings of $89 million. Ameren recorded
the charge to “Impairment and other charges” and Ameren
Missouri recorded the charge to “Loss from regulatory
disallowance.” See Note 17 – Impairment and Other
Charges for additional information. In July 2012, the
Missouri Court of Appeals upheld the MoPSC’s July 2011
electric rate order. Ameren Missouri did not seek further
appeal of the MoPSC order.
2012 Electric Rate Order
In December 2012, the MoPSC issued an order
approving an increase for Ameren Missouri in annual
revenues for electric service of $260 million, including
$84 million related to an anticipated increase in normalized
net fuel costs above the net fuel costs included in base rates
previously authorized by the MoPSC in its July 2011 electric
rate order. The annual increase request also includes
$80 million for recovery of the costs associated with energy
efficiency programs under the MEEIA, which are discussed
below. The remaining annual increase of $96 million
approved by the MoPSC was for energy infrastructure
investments and other nonfuel costs, including $10 million
for increased pension and other post-employment benefit
costs and $6 million for increased amortization of
regulatory assets. The revenue increase was based on a
9.8% return on equity, a capital structure composed of
52.3% common equity, and a rate base of $6.8 billion.
The MoPSC approved Ameren Missouri’s continued use
of its FAC, with no change to its 95% sharing percentage, but
with a modification relating to transmission revenues.
Transmission revenues previously included in base rates will
be included in the FAC prospectively. This change resulted in
the portion of the rate increase attributed to net fuel costs
being reduced, and the portion attributed to other nonfuel
costs being increased, by $33 million as compared to base
rates authorized in the MoPSC’s July 2011 electric rate order.
This change in regulatory treatment will have no immediate
impact on earnings. Transmission charges that had
previously been included in the FAC remain in the FAC.
Further, the order clarified that changes in costs for activated
carbon, limestone and urea are included in the FAC. The
MoPSC order approved the continued use of Ameren
Missouri’s vegetation management and infrastructure
inspection cost tracker, pension and postretirement benefit
cost tracker, renewable energy standards cost tracker, and
the uncertain tax positions tracker.
The order also established a storm restoration cost
tracking mechanism to facilitate the recovery in future rate
cases of storm costs that vary from those included in rates
and allowed retention of the refund received in June 2012
from Entergy related to a power purchase agreement that
existed prior to the implementation of the FAC. See below
under Federal for additional information about this refund,
which remains subject to appeal, and Ameren Missouri’s
power purchase agreement with Entergy. However, the
MoPSC did not approve Ameren Missouri’s request for
plant-in-service accounting treatment for assets placed in
service between rate cases or recovery of its 2011
severance costs.
Rate changes consistent with the order became
effective on January 2, 2013. In January 2013, Ameren
Missouri appealed the amount of property taxes included in
the 2012 electric rate order to the Missouri Court of
Appeals, Western District. In February 2013, the MoOPC,
the MIEC and others filed separate appeals to the Missouri
Court of Appeals, Western District, relating to the 2012
electric rate order’s treatment of transmission costs in the
FAC and other items. A decision is expected by the Missouri
Court of Appeals, Western District, in 2013. Ameren
Missouri cannot predict the ultimate outcome of its appeal.
MEEIA Order
The MEEIA established a regulatory framework that,
among other things, allows electric utilities to recover costs
related to MoPSC-approved energy efficiency programs.
The law requires the MoPSC to ensure that a utility’s
financial incentives are aligned to help customers use
energy more efficiently, to provide timely cost recovery, and
to provide earnings opportunities associated with cost-
effective energy efficiency programs. Missouri does not
have a law mandating energy efficiency standards.
The MoPSC’s December 2012 electric rate order
approved Ameren Missouri’s implementation of MEEIA
megawatthour savings targets, energy efficiency programs,
and associated cost recovery mechanisms and incentive
awards. Beginning in 2013, Ameren Missouri will invest
approximately $147 million over the next three years for
energy efficiency programs. The order allows for Ameren
Missouri to collect its program costs and 90% of its
projected lost revenue from customers over the same three
years starting on January 2, 2013. The remaining 10% of
projected lost revenue is expected to be recovered as part
of future rate proceedings.
Additionally, the order provides for an incentive award
that would allow Ameren Missouri to earn additional
revenues based on achievement of certain energy efficiency
goals, including approximately $19 million if 100% of its
energy efficiency goals are achieved during the three-year
period, with the potential to earn more if Ameren Missouri’s
energy savings exceed those goals. Ameren Missouri must
achieve at least 70% of its energy efficiency goals before it
earns any incentive award. The recovery of the incentive
award from customers, if the energy efficiency goals are
105
achieved, would begin after the three-year energy efficiency
plan is complete and upon the effective date of an electric
service rate order or potentially with the future adoption of a
rider mechanism.
FAC Prudence Review
Missouri law requires the MoPSC to perform prudence
reviews of Ameren Missouri’s FAC at least every 18 months.
In April 2011, the MoPSC issued an order with respect to its
review of Ameren Missouri’s FAC for the period from
March 1, 2009, to September 30, 2009. In this order, the
MoPSC ruled that Ameren Missouri should have included in
the FAC calculation all revenues and costs associated with
certain long-term partial requirements sales that were made
by Ameren Missouri because of the loss of Noranda’s load
caused by a severe ice storm in January 2009. As a result of
the order, Ameren Missouri recorded a pretax charge to
earnings of $18 million, including $1 million for interest, in
2011 for its obligation to refund to Ameren Missouri’s
electric customers the earnings associated with these sales
previously recognized by Ameren Missouri during the
period from March 1, 2009, to September 30, 2009.
Ameren Missouri disagrees with the MoPSC order’s
classification of these sales and believes that the terms of
its FAC tariff did not provide for the inclusion of these sales
in the FAC calculation. In May 2012, upon appeal by
Ameren Missouri, the Cole County Circuit Court reversed
the MoPSC’s April 2011 order. In June 2012, the MoPSC
filed an appeal of the Cole County Circuit Court’s ruling to
the Missouri Court of Appeals, Western District. Ameren
Missouri has not recorded additional revenues as a result of
the Cole County Circuit Court’s May 2012 ruling, as the
MoPSC’s appeal to the Missouri Court of Appeals is
ongoing. A decision is expected to be issued in 2013.
In February 2012, the MoPSC staff issued its FAC
review report for the period from October 1, 2009, to
May 31, 2011. In its report, the MoPSC staff asked the
MoPSC to direct Ameren Missouri to refund to customers
the pretax earnings associated with the same long-term
partial requirements sales contracts subsequent to
September 30, 2009. The MoPSC staff calculated these
pretax earnings to be $26 million. Missouri law does not
impose a specific deadline by which the MoPSC must
complete its prudence reviews. If Ameren Missouri were to
determine that these sales were probable of refund to
Ameren Missouri’s electric customers, a charge to earnings
would be recorded for the refund in the period in which that
determination was made. Ameren Missouri does not
currently believe these amounts are probable of refund to
customers.
Separately, in July 2011, Ameren Missouri filed a
request with the MoPSC for an accounting authority order
that would allow Ameren Missouri to defer, as a regulatory
asset, fixed costs totaling $36 million that were not
recovered from Noranda as a result of the loss of load
caused by the severe 2009 ice storm for potential recovery
in a future electric rate case. We cannot predict the ultimate
outcome of these regulatory or judicial proceedings. If the
courts ultimately rule in favor of Ameren Missouri’s position
regarding the classification of the long-term partial
requirements sales, Ameren Missouri would not seek to
recover from customers the sum that would be covered by
the accounting authority order, if it is granted.
Regional Transmission Organization
Ameren Missouri is a transmission-owning member of
MISO. In April 2012, the MoPSC authorized Ameren
Missouri’s continued conditional MISO participation
through May 2016, including the condition that Ameren
Missouri later file a further study with the MoPSC that
evaluates the costs and benefits of Ameren Missouri’s
continued participation in MISO, as it has periodically done
since its MISO participation began in 2003. The next cost
benefit study is required to be filed with the MoPSC in
November 2015.
Illinois
IEIMA
Ameren Illinois’ initial filing to participate in the
performance based formula ratemaking process under the
IEIMA was based on 2010 recoverable costs and expected
net plant additions for 2011 and 2012. In September 2012,
the ICC issued an order approving an Ameren Illinois
electric delivery service revenue requirement of
$779 million, which was a $55 million decrease from the
electric delivery service revenue requirement allowed in the
pre-IEIMA 2010 electric delivery service rate order. The
rates became effective on October 19, 2012, and were
effective through the end of 2012. In October 2012, Ameren
Illinois filed an appeal of the ICC’s initial filing order to the
Appellate Court of the Fourth District of Illinois. A decision
by the appellate court is expected in 2013. Ameren Illinois
believes that the ICC has incorrectly implemented the IEIMA
by using an average rate base as opposed to a year-end rate
base in setting rates, through its treatment of accumulated
deferred income taxes, and through the method it used for
calculating the equity portion of Ameren Illinois’ capital
structure and the method for calculating interest on the
revenue requirement reconciliation and return on equity
collar. The ICC’s September 2012 order jeopardizes Ameren
Illinois’ ongoing ability to implement infrastructure
improvements to the extent and on the timetable envisioned
in the IEIMA. Until the uncertainty surrounding how the
Illinois law will ultimately be implemented is removed,
Ameren Illinois is slowing IEIMA capital spending with a
corresponding negative effect on the job creation that the
legislature sought to effectuate with the law. Although
Ameren Illinois intends to meet its IEIMA capital spending
requirements, it is proceeding on a slower investment
schedule than previously contemplated.
In April 2012, Ameren Illinois submitted to the ICC an
update filing under IEIMA based on 2011 recoverable costs
and expected net plant additions for 2012. In December
2012, the ICC issued an order approving an Ameren Illinois
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electric delivery service revenue requirement of
$764 million, which is a $15 million decrease in the revenue
requirement allowed in the ICC initial filing order. The rates
became effective on January 1, 2013, and will be effective
through the end of 2013. In January 2013, Ameren Illinois
filed an appeal of the ICC’s update filing order to the
Appellate Court of the Fourth District of Illinois. A decision
by the appellate court is expected in 2013.
Ameren Illinois will submit to the ICC, during the
second quarter of 2013, an update filing based on 2012
recoverable costs and expected net plant additions for
2013, which will determine rates that are effective during
2014.
Ameren Illinois’ 2012 electric delivery service revenues
were based on its 2012 actual recoverable costs, rate base,
and return on common equity as calculated under the
IEIMA’s performance-based formula ratemaking framework.
The 2012 revenue requirement under the IEIMA’s formula
ratemaking framework was lower than the revenue
requirement included in both the ICC’s 2010 electric rate
order and the ICC’s September 2012 order related to
Ameren Illinois’ initial IEIMA filing. As a result, Ameren
Illinois recorded a $55 million regulatory liability with a
corresponding decrease in electric revenues to represent its
estimate of the probable decrease in electric delivery service
revenues expected to be approved by the ICC in December
2013 to provide Ameren Illinois recovery of all prudently
and reasonably incurred costs and an earned rate of return
on common equity for 2012. Any decrease in electric
delivery service revenues approved by the ICC in December
2013 will be refunded to customers during 2014 with
interest pursuant to the provisions of the IEIMA.
In December 2012, the ICC approved Ameren Illinois’
advanced metering infrastructure deployment plan, which
outlines how Ameren Illinois will comply with the IEIMA
requirement to spend $360 million on smart grid assets
over ten years on a cost-beneficial basis to its electric
customers. The plan targets the second quarter of 2014 to
begin installation of smart meters.
2013 Natural Gas Delivery Service Rate Case
On January 25, 2013, Ameren Illinois filed a request
with the ICC to increase its annual revenues for natural gas
delivery service by $50 million. The request was based on a
10.4% return on equity, a capital structure composed of
51.8% common equity, and a rate base of $1.1 billion. In an
attempt to reduce regulatory lag, Ameren Illinois is using a
future test year of 2014 in this proceeding.
Also in its filing, Ameren Illinois is requesting an
increase in the percentage of costs to be recovered through
a fixed non-volumetric customer charge from 80% to 85%
for all residential customers and most commercial
customers.
A decision by the ICC in this proceeding is required by
December 2013. Ameren Illinois cannot predict the level of
any delivery service rate changes the ICC may approve,
when any rate changes may go into effect, or whether any
rate changes that may eventually be approved will be
sufficient to enable Ameren Illinois to recover its costs and
earn a reasonable return on its investments when the rate
changes go into effect.
ATXI Transmission Project
ATXI’s Illinois Rivers project is a MISO-approved
project that involves building a 345-kilovolt line from
western Indiana across the state of Illinois to eastern
Missouri. In 2012, ATXI made a filing with the ICC
requesting a certificate of public convenience and necessity
and project approval. A decision is expected by the ICC in
2013. A certificate of public convenience and necessity is
required before ATXI can proceed with right-of-way
acquisition.
Federal
Electric Transmission Investment
In May 2011, FERC approved transmission rate
incentives for the Illinois Rivers project, which is being
developed by ATXI. In December 2011, MISO approved the
Illinois Rivers project as well as the Spoon River and Mark
Twain projects. The total investment in these three MISO-
approved projects is expected to be more than $1.3 billion
between 2013 to 2019. These projects are primarily located
in Illinois and Missouri.
In February 2012, FERC approved ATXI’s request for a
forward-looking rate calculation with an annual revenue
requirement reconciliation, as well as ATXI’s request for
implementation of the incentives FERC approved in its May
2011 order for the Illinois Rivers project. In November
2012, FERC approved transmission rate incentives for the
Spoon River project and the Mark Twain project. FERC also
approved a forward-looking rate calculation with an annual
revenue requirement reconciliation for Ameren Illinois’
electric transmission business.
2011 Wholesale Distribution Rate Case
In January 2011, Ameren Illinois filed a request with
FERC to increase its annual revenues for electric delivery
service for its wholesale customers by $11 million. These
wholesale distribution revenues are treated as a deduction
from Ameren Illinois’ revenue requirement in retail rate
filings with the ICC. In March 2011, FERC issued an order
authorizing the proposed rates to take effect, subject to
refund when the final rates are determined. Ameren Illinois
has reached an agreement with four of its nine wholesale
customers. The impasse with the remaining five wholesale
customers has resulted in FERC litigation. In November
2012, a FERC administrative law judge issued an initial
decision, which is now pending before FERC. A FERC
decision is expected in 2013. Ameren and Ameren Illinois
each has recorded $8 million in “Current regulatory
liabilities” on its balance sheet as of December 31, 2012, for
its estimate of the refund due to wholesale customers
107
relating to billings from March 2011 through December
2012 based on the administrative law judge’s initial
decision.
Ameren Illinois Electric Transmission Rate Refund
On July 19, 2012, FERC issued an order approving
Ameren Illinois’ accounting for the Ameren Illinois Merger,
which is discussed in Note 16 – 2010 Corporate
Reorganization. As part of this order, FERC concluded that
Ameren Illinois improperly included acquisition premiums,
particularly goodwill, in determining its common equity
used in its electric transmission formula rate, thereby
inappropriately recovering a higher return on rate base from
its electric transmission customers. The order required
Ameren Illinois to make refunds to customers for such
improperly included amounts. In August 2012, Ameren
Illinois filed a request for rehearing of this order. It is
unknown when FERC will rule on Ameren’s rehearing
request, as it is under no deadline to do so. After reviewing
the FERC order and its calculation of the impact on electric
transmission formula rates, Ameren Illinois concluded that
no refund was warranted. Several wholesale customers filed
a protest with FERC regarding Ameren’s conclusion that no
refund is warranted. If Ameren Illinois were to determine
that a refund to its electric transmission customers is
probable, a charge to earnings would be recorded for the
refund in the period in which that determination was made
and the amount could be estimated.
FERC Order – MISO Charges
Ameren Missouri and Ameren Illinois, as well as other
MISO participants, have filed complaints with FERC with
respect to the FERC’s March 2007 order involving the
reallocation of certain MISO operational costs among MISO
participants retroactive to 2005. Subsequently, FERC has
issued a series of orders related to the applicability and the
implementation of the order, which in some cases have
conflicted with previous orders.
In May 2009, FERC changed the effective date for
refunds such that certain operational costs would be
allocated among MISO market participants beginning
November 2008, instead of August 2007. In June 2009,
Ameren Missouri and Ameren Illinois filed a request for
rehearing. The rehearing request is pending.
In June 2009, FERC issued an order dismissing
rehearing requests of a November 2008 order and waiving
refunds of amounts billed that were included in the MISO
charge, under the assumption that there was a rate
mismatch for the period April 2006 through November
2007. Ameren Missouri and Ameren Illinois filed a request
for rehearing in July 2009. This rehearing request is
pending.
Ameren Missouri Power Purchase Agreement with Entergy
Beginning in 2005, FERC issued a series of orders
addressing a complaint filed in 2001 by the Louisiana Public
Service Commission (LPSC) against Entergy Arkansas, Inc.
(Entergy) and certain of its affiliates. The complaint alleged
unjust and unreasonable cost allocations. As a result of the
FERC orders, Entergy began billing Ameren Missouri in
2007 for additional charges under a 165-megawatt power
purchase agreement, and Ameren Missouri paid those
charges. Additional charges continued during the remainder
of the term of the power purchase agreement, which
expired August 31, 2009. In May 2012, FERC issued an
order upholding its January 2010 ruling that Entergy should
not have included additional charges to Ameren Missouri
under the power purchase agreement. Pursuant to the
order, in June 2012, Entergy paid Ameren Missouri
$31 million, with $24 million recorded as a reduction to
“Purchased power” expense and $5 million for interest
recorded as “Miscellaneous income” in the statement of
income, and the remaining $2 million recorded as an offset
to the FAC under-recovered regulatory asset for the amount
refundable to customers. The amount of the Entergy refund
recorded to the FAC regulatory asset related to the period
when the FAC was effective and, therefore, such costs were
previously included in customer rates. As noted above, the
MoPSC, in its December 2012 electric rate order, confirmed
Ameren Missouri could retain the portion of the refund
received from Entergy that related to the period prior to the
implementation of the FAC. In July 2012, Entergy filed an
appeal of FERC’s January 2010 and May 2012 orders to the
United States Court of Appeals for the District of Columbia.
In December 2012, the Court of Appeals dismissed
Entergy’s appeal as premature because an Entergy motion
seeking clarification or rehearing of the May 2012 order
remains pending before FERC. It is unknown when FERC
may act on the pending Entergy motion.
The LPSC appealed FERC’s orders regarding LPSC’s
complaint against Entergy Services, Inc. to the United
States Court of Appeals for the District of Columbia. In April
2008, that court ordered further FERC proceedings
regarding LPSC’s complaint. The court ordered FERC to
explain its previous denial of retroactive refunds and the
implementation of prospective charges. FERC’s decision on
remand of the retroactive impact of these issues could have
a financial impact on Ameren Missouri. Ameren Missouri is
unable to predict how FERC will respond to the court’s
decisions. Ameren Missouri estimates that it could incur an
additional expense of up to $25 million if FERC orders
retroactive application for the years 2001 to 2005. Ameren
Missouri believes that the likelihood of incurring any
expense is not probable, and therefore no liability has been
recorded as of December 31, 2012.
Combined Construction and Operating License
Ameren Missouri and Ameren Illinois do not believe
that the ultimate resolution of these proceedings will have a
material effect on their results of operations, financial
position, or liquidity.
In 2008, Ameren Missouri filed an application with the
NRC for a COL for a new nuclear unit at Ameren Missouri’s
existing Callaway County, Missouri, energy center site. In
2009, Ameren Missouri suspended its efforts to build a new
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nuclear unit at its existing Missouri nuclear energy center
site, and the NRC suspended review of the COL application.
In March 2012, the DOE announced the availability of
investment funds for the design, engineering,
manufacturing, and sale of American-made small modular
nuclear reactors. In April 2012, Ameren Missouri entered
into an agreement with Westinghouse to exclusively
support Westinghouse’s application for the DOE’s small
modular nuclear reactor investment funds. The DOE
investment funding is intended to support engineering and
design certifications and a COL for up to two small modular
reactor designs over five years. In November 2012, the DOE
awarded investment funds for only one small modular
reactor design, which was not the Westinghouse design,
but also stated that additional investment funds would be
awarded during 2013. Westinghouse continues to pursue
investment funds from the DOE.
If Westinghouse is awarded DOE’s small modular
reactor investment funds, Ameren Missouri will seek a COL
from the NRC for a Westinghouse small modular reactor or
multiple reactors at its Callaway energy center site. A COL is
issued by the NRC to permit construction and operation of a
nuclear energy center at a specific site in accordance with
established laws and regulations. Obtaining a COL from the
NRC does not obligate Ameren Missouri to build a small
modular reactor at the Callaway site; however, it does
preserve the option to move forward in a timely fashion
should conditions be right to build a small modular reactor
in the future. A COL is valid for at least 40 years.
Ameren Missouri estimates the total cost to obtain the
small modular reactor COL will be in the range of
$80 million to $100 million. Ameren Missouri expects its
incremental investment to obtain the small modular reactor
COL to be minimal due to several factors, including the
company’s capitalized investments in new nuclear energy
center development of $69 million as of December 31,
2012, the DOE investment funds that would help support
the COL application, and Ameren Missouri’s agreement with
Westinghouse. If the DOE does not approve
Westinghouse’s application for the small modular reactor
investment funds, Ameren Missouri is not obligated to
pursue a COL for the Westinghouse small modular reactor
design and may terminate its agreement with
Westinghouse.
All of Ameren Missouri’s costs incurred to license
additional nuclear generation at the Callaway site will
remain capitalized while management pursues options to
maximize the value of its investment. If efforts are
permanently abandoned or management concludes it is
probable the costs incurred will be disallowed in rates, a
charge to earnings would be recognized in the period in
which that determination was made.
Pumped-storage Hydroelectric Energy Center Relicensing
In June 2008, Ameren Missouri filed a relicensing
application with FERC to operate its Taum Sauk pumped-
storage hydroelectric energy center for another 40 years.
The existing FERC license expired on June 30, 2010. On
July 2, 2010, Ameren Missouri received a license extension
that allows Taum Sauk to continue operations until FERC
issues a new license. FERC is reviewing the relicensing
application. A FERC order is expected in 2013 or 2014.
Ameren Missouri cannot predict the ultimate outcome of
FERC’s review of the application.
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Regulatory Assets and Liabilities
In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation,
Ameren Missouri and Ameren Illinois defer certain costs pursuant to actions of regulators or based on the expected ability to
recover such costs in rates charged to customers. Ameren Missouri and Ameren Illinois also defer certain amounts because of
actions of regulators or because of the expectation that such amounts will be returned to customers in future rates. The
following table presents Ameren’s, Ameren Missouri’s and Ameren Illinois’ regulatory assets and regulatory liabilities at
December 31, 2012, and 2011:
2012
Ameren
Missouri
Ameren
Ameren
Illinois
Ameren
2011
Ameren
Missouri
Current regulatory assets:
Under-recovered FAC(b)(c)
Under-recovered Illinois electric power costs(b)(d)
Under-recovered PGA(b)(d)
MTM derivative losses(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent regulatory assets:
Pension and postretirement benefit costs(f) . . . . . . . . . . . . . . . . . .
Income taxes(g)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations(h) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Callaway costs(b)(i) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized loss on reacquired debt(b)(j) . . . . . . . . . . . . . . . . . . . .
Recoverable costs – contaminated facilities(k) . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MTM derivative losses(e)
. . . . . . . . . . . . . . . . . . . .
SO2 emission allowances sale tracker(l)
Storm costs(m) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Demand-side costs(b)(n)
. . . . . . . . . . . . . .
Reserve for workers’ compensation liabilities(o)
Credit facilities fees(p)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee separation costs(q) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock issuance costs(r) . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction accounting for pollution control equipment(b)(s)
. . . .
Other(t) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total noncurrent regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . .
Current regulatory liabilities:
Over-recovered FAC(u)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Over-recovered Illinois electric power costs(d) . . . . . . . . . . . . . . . .
Over-recovered PGA(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MTM derivative gains(v) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale distribution refund(w)
Total current regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent regulatory liabilities:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes(x)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Removal costs(y)
Asset retirement obligation(h) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MTM derivative gains(v) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt rider(z) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and postretirement benefit costs tracker(aa)
. . . . . . . . . . .
Energy efficiency rider(ab) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IEIMA revenue requirement reconciliation(ac) . . . . . . . . . . . . . . . . .
Other(ad) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
145
-
12
90
247
772
235
5
44
181
248
135
2
9
73
12
6
2
7
23
32
1,786
-
58
15
19
8
100
46
1,347
80
2
12
23
20
55
4
$
$
$
$
$
$
$
Total noncurrent regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . . .
$
1,589
$
145
-
5
13
163
348
231
-
44
81
-
7
2
9
73
6
6
1
7
23
14
852
-
-
-
18
-
18
42
766
80
2
-
23
-
-
4
917
$
$
$
$
$
$
$
$
-
-
7
77
84
424
4
5
-
100
248
128
-
-
-
6
-
1
-
-
18
934
-
58
15
1
8
82
4
581
-
-
12
-
20
55
-
672
$
$
$
$
$
$
$
$
$
$
$
$
$
$
83
4
8
120(a)
215
878
239
6
48
47
102
100
6
16
70
13
10
6
10
25
27
1,603
12
64
9
46
2
133
48
1,269
29
82
10
38
24
-
2
$
1,502
$
Ameren
Illinois
$
-
4
3
299
83
-
5
21
109
$ 306
382
234
-
48
21
-
13
6
16
70
7
10
3
10
25
10
855
12
-
-
45
-
57
44
719
29
4
-
38
-
-
2
836
$
496
5
6
-
26
102
87
-
-
-
6
-
3
-
-
17
$ 748
$
$
$
-
64
9
1
2
76
4
550
-
78
10
-
24
-
-
$ 666
Includes intercompany eliminations.
(a)
(b) These assets earn a return.
(c) Under-recovered fuel costs for periods from June 2010 through December 2012. Specific accumulation periods aggregate the under-recovered
costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over
the next eight months.
(d) Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the
deferral.
(e) Deferral of commodity-related derivative MTM losses. The December 31, 2011 balance included the MTM losses on financial contracts entered
into by Ameren Illinois with Marketing Company, which expired in December 2012.
110
(f)
These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets), and actuarial
losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 11 – Retirement Benefits for additional
information.
(g) Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 – Income Taxes for amortization
period.
(h) Recoverable or refundable removal costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses
related to the nuclear decommissioning trust fund investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement
Obligations.
(i) Ameren Missouri’s Callaway energy center 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 energy center’s
current operating license which expires in 2024.
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.
(j)
(k) The recoverable portion of accrued environmental site liabilities, primarily collected from electric and natural gas customers through
ICC-approved cost recovery riders. The period of recovery will depend on the timing of actual expenditures. See Note 15 – Commitments and
Contingencies for additional information.
(l) 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. The MoPSC’s May 2010 electric
rate order discontinued any future deferrals under this tracking mechanism. The MoPSC’s December 2012 rate order approved the amortization
of these costs through December 2014.
(m) Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. As approved by the December 2012
MoPSC electric rate order, the 2006, 2007, and 2008 storm costs are being amortized through December 2014. As approved by the May 2010
MoPSC electric rate order, the 2009 storm costs are being amortized through June 2015.
(n) Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response
programs. Costs incurred from May 2008 through September 2008 are being amortized over a 10-year period that began in March 2009. Costs
incurred from October 2008 through December 2009 are being amortized over a six-year period that began in July 2010. Costs incurred from
January 2010 through February 2011 are being amortized over a six-year period that began in August 2011. Costs incurred from March 2011
through July 2012 are being amortized over a six-year period that began in January 2013. The amortization period for the costs incurred after
July 2012 will be determined in a future Ameren Missouri electric rate case.
(o) Reserve for workers’ compensation claims. The period of recovery will depend on the timing of actual expenditures.
(p) Ameren Missouri’s costs incurred to enter into and maintain the 2012 Ameren Missouri Credit Agreement. These costs are being amortized
over five years, beginning in November 2012. These costs are being amortized to construction work in progress, which will be subsequently
depreciated when assets are placed into service.
(q) Costs incurred for voluntary and involuntary separation programs. The 2009 Ameren Missouri-related costs are being amortized over two
years, beginning in January 2013, as approved by the December 2012 MoPSC electric rate order. The 2009 Ameren Illinois-related costs are
being amortized over three years, beginning in May 2010, as approved by the April 2010 ICC electric and natural gas rate order.
The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to recover its portion of Ameren’s September 2009 common stock
issuance costs. These costs are being amortized over five years, beginning in July 2010.
(r)
(s) The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution
(t)
control equipment at its Sioux energy center until the cost of that equipment was placed in customer rates. The amortization of these costs will
be over the expected life of the Sioux energy center.
The Ameren Illinois total includes Ameren Illinois Merger integration and optimization costs, which are amortized over four years, beginning in
January 2012. The Ameren Illinois total includes costs related to delivery service rate cases. The 2012 natural gas rate case costs are being
amortized over a two-year period that began in January 2012. The electric rate case costs for the IEIMA initial rate filing are being amortized
over a three-year period that began in January 2012. The Ameren Illinois total also includes a portion of the unamortized debt fair value
adjustment recorded upon Ameren’s acquisition of IP. This portion is being amortized over the remaining life of the related debt, beginning with
the expiration of the electric rate freeze in Illinois on January 1, 2007. At Ameren Missouri, the balance primarily includes cost associated with
the retirement of renewable energy credits and solar rebates to fulfill its renewable energy portfolio requirement. Costs incurred from January
2010 through July 2012 are being amortized over three years, beginning January 2013. The amortization period for the costs incurred after July
2012 will be determined in a future Ameren Missouri electric rate case.
(u) Over-recovered fuel costs from March 2009 through September 2009 as ordered by the MoPSC in April 2011. Customer refunds concluded in
2012. Specific accumulation periods aggregate the over-recovered costs over four months, any related adjustments occur over the following
four months, and then recovery from customers occurs over the next eight months.
(v) Deferral of commodity-related derivative MTM gains.
(w) Estimated refund to wholesale electric customers. See 2011 Wholesale Distribution Rate Case above.
(x) Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 – Income Taxes for amortization period.
(y) Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our
rate-regulated operations.
(z) A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by Ameren Illinois under GAAP and the level
of such costs included in electric and natural gas rates. The over-recovery relating to 2010 was refunded to customers from June 2011 through
May 2012. The over-recovery relating to 2011 is being refunded to customers from June 2012 through May 2013. The over-recovery relating to
2012 will be refunded to customers from June 2013 through May 2014.
(aa) A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri
under GAAP and the level of such costs built into rates. For periods prior to August 2012, the MoPSC’s December 2012 electric rate order
directed the amortization to occur over five years, beginning in January 2013. For periods after August 2012, the amortization period will be
determined in a future Ameren Missouri electric rate case.
111
(ab) A regulatory tracking mechanism that allows Ameren Illinois to recover its electric and natural gas costs associated with developing,
implementing, and evaluating customer energy efficiency and demand response programs. This over-recovery will be refunded to customers
over the following 12 months after the plan year.
(ac) The difference between Ameren Illinois’ 2012 revenue requirement calculated under the IEIMA’s performance-based formula ratemaking
framework, and the revenue requirement included in customer rates for 2012. Subject to ICC approval, this liability will be refunded to
customers in 2014.
(ad) Balance primarily includes an Ameren Missouri liability relating to its 2010 property tax refund. The MoPSC’s December 2012 electric rate order
directed a refund to customers over a two-year period, beginning in January 2013.
Ameren Missouri and Ameren Illinois continually assess the recoverability of their regulatory assets. Under current
accounting standards, regulatory assets are charged to earnings when it is no longer probable that such amounts will be
recovered through future revenues. To the extent that payments of regulatory liabilities are no longer probable, the amounts
are credited to earnings.
NOTE 3 – PROPERTY AND PLANT, NET
The following table presents property and plant, net, for each of the Ameren Companies at December 31, 2012, and 2011:
Ameren(a)(b)
Ameren
Missouri(b)
Ameren
Illinois
2012
Property and plant, at original cost:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Less: Accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction work in progress:
Nuclear fuel in process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
22,055
1,854
23,909
8,823
15,086
317
693
$
15,638
393
16,031
6,614
9,417
317
427
$ 4,985
1,461
6,446
1,495
4,951
-
101
Property and plant, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
16,096
$
10,161
$ 5,052
2011
Property and plant, at original cost:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Less: Accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction work in progress:
Nuclear fuel in process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
24,717
1,751
26,468
9,429
17,039
255
833
$
15,099
385
15,484
6,276
9,208
255
495
$
4,684
1,368
6,052
1,364
4,688
-
82
Property and plant, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
18,127
$
9,958
$
4,770
Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
(a)
(b) Amounts in Ameren and Ameren Missouri include two electric generation CTs under two separate capital lease agreements. The gross asset
value of those agreements was $228 million and $229 million at December 31, 2012, and 2011, respectively. The total accumulated
depreciation associated with the two CTs was $52 million and $52 million at December 31, 2012, and 2011, respectively. In addition, Ameren
Missouri has investments in debt securities, which are classified as held-to-maturity, related to the two CTs from the city of Bowling Green and
Audrain County. As of December 31, 2012, and 2011, the carrying value of these debt securities was $304 million and $309 million,
respectively.
See Note 17 – Impairment and Other Charges for information regarding Ameren’s noncash long-lived asset impairment
charges recognized in 2012.
The following table provides accrued capital expenditures at December 31, 2012, 2011, and 2010, which represent
noncash investing activity excluded from the statements of cash flows:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
112
Ameren(a)
$
108
107
79
Ameren
Missouri
Ameren
Illinois
$
63
73
53
$
37
18
15
NOTE 4 – SHORT-TERM DEBT AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term
intercompany borrowings, and drawings under committed bank credit agreements, or commercial paper issuances.
2012 Credit Agreements
On November 14, 2012, Ameren and Ameren Missouri entered into the $1 billion 2012 Missouri Credit Agreement. The
2010 Missouri Credit Agreement was terminated when the 2012 Missouri Credit Agreement when into effect. Also on
November 14, 2012, Ameren and Ameren Illinois entered into the $1.1 billion 2012 Illinois Credit Agreement. The 2010 Illinois
Credit Agreement was terminated when the 2012 Illinois Credit Agreement went into effect. These facilities cumulatively
provide $2.1 billion of credit through November 14, 2017, which date is inclusive of the Ameren Missouri and Ameren Illinois
borrowing sublimit extensions discussed below of the maturity date to November 14, 2017, and which may be extended with
the agreement of the lenders, subject to the terms of such agreements, for two additional one-year periods. The facilities
currently include 24 international, national, and regional lenders, with no lender providing more than $125 million of credit in
aggregate.
In addition, the 2010 Genco Credit Agreement, under which Ameren was a borrower, was not renewed and was
terminated contemporaneously with the effectiveness of the 2012 Credit Agreements.
The obligations of each borrower under the respective 2012 Credit Agreements to which it is a party are several and not
joint, and, except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and
Ameren Illinois under the respective 2012 Credit Agreements are not guaranteed by Ameren or any other subsidiary of
Ameren. The maximum aggregate amount available to each borrower under each facility is shown in the following table (such
amount being such borrower’s “Borrowing Sublimit”):
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
500
800
(a)
$
300
(a)
800
(a) Not applicable.
Ameren has the option to seek additional commitments
The obligations of all borrowers under the 2012 Credit
2012 Missouri
Credit Agreement
2012 Illinois
Credit Agreement
from existing or new lenders to increase the total facility
size of the 2012 Credit Agreements up to the following
maximum amounts: 2012 Missouri Credit Agreement –
$1.2 billion; and 2012 Illinois Credit Agreement –
$1.3 billion. Each of the 2012 Credit Agreements will
mature and expire with respect to Ameren on November 14,
2017, unless extended as described above. Borrowing
Sublimits of Ameren Missouri and Ameren Illinois under the
applicable 2012 Credit Agreements will mature and expire
on November 13, 2013, subject to extension thereof on a
364-day basis, as requested by the borrower and approved
by the lenders, or for a longer period upon receipt of any
and all required federal or state regulatory approvals, as
permitted under the 2012 Missouri Credit Agreement and
the 2012 Illinois Credit Agreement, but in no event later
than November 14, 2017. Ameren Missouri and Ameren
Illinois intend to seek regulatory approval to extend the
maturity dates of their respective Borrowing Sublimit under
the 2012 Missouri Credit Agreement and the 2012 Illinois
Credit Agreement to November 14, 2017. If and when such
regulatory approvals are received, no lender approval will be
required to effect the extensions. The principal amount of
each revolving loan owed by a borrower under any of the
2012 Credit Agreements to which it is a party will be due
and payable no later than the final maturity date relating to
such borrower under such 2012 Credit Agreements.
Agreements are unsecured. Loans are available on a
revolving basis under each of the 2012 Credit Agreements
and may be repaid and, subject to satisfaction of the
conditions to borrowing, reborrowed from time to time. At
the election of each borrower, the interest rates on such
loans will be the alternate base rate (“ABR”) plus the margin
applicable to the particular borrower and/ or the Eurodollar
rate plus the margin applicable to the particular borrower.
The applicable margins will be determined by the
borrower’s long-term unsecured credit ratings or, if no such
ratings are then in effect, the borrower’s corporate/issuer
ratings then in effect. Letters of credit in an aggregate
undrawn face amount not to exceed 25% of the applicable
aggregate commitment under the respective 2012 Credit
Agreements are also available for issuance for the account
of the borrowers thereunder (but within the $2.1 billion
overall combined facility borrowing limitations of the 2012
Credit Agreements).
The borrowers will use the proceeds from any
borrowings under the 2012 Credit Agreements for general
corporate purposes, including working capital, commercial
paper liquidity support, loan funding under the Ameren
money pool arrangements or other short-term
intercompany loan arrangements, or paying fees and
expenses incurred in connection with the 2012 Credit
Agreements.
113
The 2012 Credit Agreements are used to borrow cash,
to issue letters of credit, and to support issuances under
Ameren’s $500 million commercial paper program, Ameren
Missouri’s $500 million commercial paper program and
Ameren Illinois’ $500 million commercial paper program.
Any of the 2012 Credit Agreements are available to Ameren
to support borrowings under Ameren’s commercial paper
program, subject to borrowing sublimits. The 2012
Missouri Credit Agreement is available to support issuances
under Ameren Missouri’s commercial paper program, and
the 2012 Illinois Credit Agreement is available to support
issuances under Ameren Illinois’ commercial paper
program. As of December 31, 2012, based on letters of
credit issued under the 2012 Credit Agreements, the
aggregate amount of credit capacity available to Ameren
(parent), Ameren Missouri and Ameren Illinois, collectively
at December 31, 2012, was $2.09 billion.
The following table summarizes the borrowing activity and relevant interest rates under the 2010 Missouri Credit
Agreement, which terminated on November 14, 2012, for the years ended December 31, 2012, and 2011 and excludes issued
letters of credit. Ameren, Ameren Missouri and Ameren Illinois did not borrow under the 2012 Credit Agreements from
November 14, 2012, through December 31, 2012.
2010 Missouri Credit Agreement ($ 800 million) (Terminated)
2012
Average daily borrowings outstanding during 2012(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding credit facility borrowings at period end . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2012(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak credit facility borrowings during 2012(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011
Average daily borrowings outstanding during 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding credit facility borrowings at period end . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak credit facility borrowings during 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren
(Parent)
Ameren
Missouri
Total
$
$
$
$
-
-
-%
-
-%
105
-
2.30%
340
4.30%
$
$
$
$
1
-
4.15%
50
4.15%
-
-
-
-
-
$
$
$
$
1
-
4.15%
50
4.15%
105
-
2.30%
340
4.30%
(a) Calculated through termination date.
Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the years ended
December 31, 2012, and 2011, respectively.
Commercial Paper
At December 31, 2012, Ameren did not have any
commercial paper outstanding. At December 31, 2011,
Ameren had $148 million of commercial paper outstanding.
During the years ended December 31, 2012, and 2011,
Ameren had average daily commercial paper balances
outstanding of $49 million and $311 million with a
weighted-average interest rate of 0.92% and 0.87%,
respectively. The peak amounts of short-term commercial
paper outstanding during the years ended December 31,
2012, and 2011, were $229 million and $435 million,
respectively. The peak interest rate during the years ended
December 31, 2012, and 2011, was 1.25% and 1.46%,
respectively.
Indebtedness Provisions and Other Covenants
The information below presents a summary of the
Ameren Companies’ compliance with indebtedness
provisions and other covenants.
The 2012 Credit Agreements contain conditions to
borrowings and issuances of letters of credit similar to
those contained in the 2010 Credit Agreements, including
the absence of default or unmatured default, material
accuracy of representations and warranties (excluding any
representation after the closing date as to the absence of
material adverse change and material litigation, and the
absence of any notice of any violation, liability or
requirement under any environmental laws that could have
a material adverse effect), and obtaining required regulatory
authorizations. In addition, solely as it relates to borrowings
under the 2012 Illinois Credit Agreement, it is a condition
for any such borrowing that, at the time of and after giving
effect to such borrowing, the borrower not be in violation of
any limitation on its ability to incur unsecured indebtedness
contained in its articles of incorporation.
The 2012 Credit Agreements also contain nonfinancial
covenants similar to those contained in the 2010 Credit
Agreements, including restrictions on the ability to incur
liens, to transact with affiliates, to dispose of assets, to
make investments in or transfer assets to its affiliates, and
to merge with other entities. The 2012 Credit Agreements
require each of Ameren, Ameren Missouri and Ameren
Illinois to maintain consolidated indebtedness of not more
than 65% of its consolidated total capitalization pursuant to
a defined calculation set forth in the agreements. As of
December 31, 2012, the ratios of consolidated
indebtedness to total consolidated capitalization, calculated
in accordance with the provisions of the 2012 Credit
Agreements, were 51%, 48% and 43%, for Ameren,
Ameren Missouri and Ameren Illinois, respectively. In
addition, under the 2012 Illinois Credit Agreement and, by
114
virtue of the cross-default provisions of the 2012 Missouri
Credit Agreement, Ameren is required to maintain a ratio of
consolidated funds from operations plus interest expense to
consolidated interest expense of 2.0 to 1.0, to be calculated
quarterly, as of the end of the most recent four fiscal
quarters then ending, in accordance with the 2012 Illinois
Credit Agreement. Ameren’s ratio as of December 31, 2012
was 5.0 to 1.0. Failure of a borrower to satisfy a financial
covenant constitutes an immediate default under the
applicable 2012 Credit Agreement.
The 2012 Credit Agreements contain default
provisions. The default provisions in the 2012 Credit
Agreements apply separately to each borrower, provided,
however, that a default of Ameren Missouri or Ameren
Illinois under the applicable 2012 Credit Agreement will also
be deemed to constitute a default of Ameren under such
agreement. Defaults include a cross-default to a default of
such borrower under any other agreement covering
outstanding indebtedness of such borrower and certain
subsidiaries (other than project finance subsidiaries and
nonmaterial subsidiaries) in excess of $50 million in the
aggregate (including under the other 2012 Credit
Agreement). However, under the default provisions of the
2012 Credit Agreements, any default of Ameren under any
such 2012 Credit Agreements that results solely from a
default of Ameren Missouri or Ameren Illinois thereunder
does not result in a cross-default of Ameren under the other
2012 Credit Agreement. Further, the 2012 Credit Agreement
default provisions provide that an Ameren default under any
of the 2012 Credit Agreements does not trigger a default by
Ameren Missouri or Ameren Illinois. Finally, for the purpose
of determining whether any event relating solely to Genco
or its subsidiaries constitutes a default with respect to
Ameren under either 2012 Credit Agreement, Ameren will
have the option to exclude Genco and its subsidiaries from
the subsidiaries of Ameren that are subject to such 2012
Credit Agreement, provided that certain conditions are
satisfied. These conditions include (1) the reduction of
Ameren’s Borrowing Sublimits under each 2012 Credit
Agreement by not less than $150 million (as determined
based on the highest Borrower Sublimit that has been in
effect for Ameren at any time under the applicable 2012
Credit Agreement) and (2) that such default would not have
a material adverse effect on Ameren (as such term is
defined in the 2012 Credit Agreements).
None of the Ameren Companies’ credit agreements or
financing arrangements contain credit rating triggers that
would cause a default or acceleration of repayment of
outstanding balances. Management believes that the
Ameren Companies were in compliance with the provisions
and covenants of their credit agreements at December 31,
2012.
Money Pools
Ameren has money pool agreements with and among
its subsidiaries to coordinate and provide for certain short-
term cash and working capital requirements. Separate
money pools are maintained for utility and non-state-
regulated entities. Ameren Services is responsible for the
operation and administration of the money pool
agreements.
Utility
Ameren Missouri, Ameren Illinois and Ameren Services
may participate in the utility money pool as both lenders
and borrowers. 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 sources of external funds for the
utility money pool are the 2012 Credit Agreements and the
commercial paper programs. The total amount available to
the pool participants from the utility money pool at any
given time is reduced by the amount of borrowings made
by participants, but is increased to the extent that the pool
participants advance surplus funds to the utility money pool
or remit funds from other external sources. The availability
of funds is also determined by funding requirement limits
established by regulatory authorizations. The utility money
pool was established to coordinate and to provide short-
term cash and working capital for the participants.
Participants 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, 2012, was 0.13%. There were no utility
money pool borrowings during the year ended
December 31, 2011.
Non-state-regulated Subsidiaries
Ameren, Ameren Services, AER, Genco, AERG,
Marketing Company, and other non-state-regulated Ameren
subsidiaries have the ability, subject to Ameren parent
company and applicable regulatory short-term borrowing
authorizations, to access funding from the 2012 Credit
Agreements and the commercial paper programs through a
non-state-regulated subsidiary money pool agreement. All
participants may borrow from or lend to the non-state-
regulated money pool, except for Ameren Services, which
may participate only as a borrower. The total amount
available to the pool participants from the non-state-
regulated subsidiary money pool at any given time is
reduced by the amount of borrowings made by participants,
but is increased to the extent that the pool participants
advance surplus funds to the non-state-regulated subsidiary
money pool or remit funds from other external sources. The
non-state-regulated subsidiary money pool was established
to coordinate and to provide short-term cash and working
capital for the participants. Participants 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. The average
115
interest rate for borrowing under the non-state-regulated
subsidiary money pool for the year ended December 31,
2012, was 0.61% (2011 – 0.77%).
See Note 14 – Related Party Transactions for the
amount of interest income and expense from the money
pool arrangements recorded by the Ameren Companies for
the years ended December 31, 2012, 2011, and 2010.
Unilateral Borrowing Agreement
In addition, a unilateral borrowing agreement exists
among Ameren, Ameren Illinois, and Ameren Services,
NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS
which enables Ameren Illinois to make short-term
borrowings directly from Ameren. The aggregate amount of
borrowings outstanding at any time by Ameren Illinois
under the unilateral borrowing agreement and the utility
money pool agreement, together with any outstanding
Ameren Illinois external credit facility borrowings or
commercial paper issuances, may not exceed $500 million,
pursuant to authorization from the ICC. Ameren Illinois is
not currently borrowing under the unilateral borrowing
agreement. Ameren Services is responsible for the
operation and administration of the unilateral borrowing
agreement.
The following table presents long-term debt outstanding, including maturities due within one year, for the Ameren
Companies and Genco as of December 31, 2012, and 2011:
2012
2011
Ameren (Parent):
8.875% Senior unsecured notes due 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri:
Senior secured notes:(a)
5.25% Senior secured notes due 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.65% Senior secured notes due 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.50% Senior secured notes due 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.75% Senior secured notes due 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.40% Senior secured notes due 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.40% Senior secured notes due 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.00% Senior secured notes due 2018(b)
5.10% Senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.70% Senior secured notes due 2019(b)
5.10% Senior secured notes due 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.00% Senior secured notes due 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.50% Senior secured notes due 2034 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.30% Senior secured notes due 2037 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8.45% Senior secured notes due 2039(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.90% Senior secured notes due 2042(b)
Environmental improvement and pollution control revenue bonds:
1992 Series due 2022(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1993 5.45% Series due 2028(e)
1998 Series A due 2033(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1998 Series B due 2033(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1998 Series C due 2033(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital lease obligations:
City of Bowling Green capital lease (Peno Creek CT) through 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audrain County capital lease (Audrain County CT) due 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
425
(1)
424
-
200
104
114
260
425
179
199
329
244
85
184
300
350
485
47
44
60
50
50
64
240
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,013
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
(7)
(205)
$
$
$
425
(1)
424
173
200
104
114
260
425
250
200
450
300
85
184
300
350
-
47
44
60
50
50
69
240
3,955
(5)
(178)
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3,801
$ 3,772
116
2012
2011
Ameren Illinois:
Senior secured notes:
8.875% Senior secured notes due 2013(f)(h) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.20% Senior secured notes due 2016(f)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.25% Senior secured notes due 2016(g)
6.125% Senior secured notes due 2017(g)(i) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.25% Senior secured notes due 2018(g)(i) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9.75% Senior secured notes due 2018(g)(i) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.70% Senior secured notes due 2022(g)(i) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.125% Senior secured notes due 2028(g)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.70% Senior secured notes due 2036(g)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.70% Senior secured notes due 2036(f)
$
Environmental improvement and pollution control revenue bonds:
6.20% Series 1992B due 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2000 Series A 5.50% due 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.90% Series 1993 due 2023(j) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.70% 1994A Series due 2024(k)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1993 Series C-1 5.95% due 2026(l)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1993 Series C-2 5.70% due 2026(l)
1993 Series B-1 due 2028(d)(l) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.40% 1998A Series due 2028(k)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.40% 1998B Series due 2028(k)
Fair-market value adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
150
54
75
250
144
313
400
60
61
42
-
-
32
36
35
8
17
19
33
4
$
150
54
75
250
337
400
-
60
61
42
1
51
32
36
35
8
17
19
33
5
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,733
1,666
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
(6)
(150)
(8)
(1)
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,577
$
1,657
Genco:
Unsecured notes:
Senior notes Series F 7.95% due 2032 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior notes Series H 7.00% due 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior notes Series I 6.30% due 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren consolidated long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
275
300
250
825
(1)
-
$
275
300
250
825
(1)
-
$
$
824
6,626
$
$
824
6,677
(a) These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The
notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri
mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds
currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these
notes, at which time these notes would become unsecured obligations. Based on the Ameren Missouri first mortgage bonds and senior
secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first
mortgage bond lien protection associated with these notes to fall away until 2042.
(b) Ameren Missouri has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its first mortgage
bonds. Ameren Missouri has also agreed to prevent a first mortgage bond release date from occurring as long as any of the 8.45% senior
secured notes due 2039 and any of the 3.90% senior secured notes due 2042 remain outstanding.
(c) These bonds are secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-
(d)
away lien provision similar to that of Ameren Missouri’s senior secured notes. The bonds are also backed by an insurance guarantee policy.
Interest rates, and periods during which such rates apply, vary depending on our selection of defined rate modes. Maximum interest rates
could range up to 18% depending on the series of bonds. The average interest rates for 2012 and 2011 were as follows:
Ameren Missouri 1992 Series . . . . . . . . . .
Ameren Missouri 1998 Series A . . . . . . . .
Ameren Missouri 1998 Series B . . . . . . . .
Ameren Missouri 1998 Series C . . . . . . . .
Ameren Illinois 1993 Series B-1 . . . . . . . .
2012
2011
0.30% 0.34%
0.65% 0.69%
0.64% 0.68%
0.64% 0.69%
0.22% 0.28%
(e) These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture and are secured by
substantially all Ameren Missouri property and franchises. The bonds are callable at 100% of par value.
117
(f)
These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture. The notes have a
fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the CILCO mortgage indenture
remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and
any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these
notes would become unsecured obligations. Based on the CILCO first mortgage bonds and senior secured notes currently outstanding, and
assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with
these notes to fall away until 2023.
(g) These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes
have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois
mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently
outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which
time these notes would become unsecured obligations. Based on the Ameren Illinois mortgage bonds and senior secured notes currently
outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection
associated with these notes to fall away until 2028.
(h) Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its CILCO first mortgage
bonds, and therefore a CILCO first mortgage bond release date will not occur while any of such notes are outstanding.
(i) Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its Ameren Illinois
(j)
mortgage bonds, and therefore an Ameren Illinois first mortgage bond release date will not occur as long as any of these notes are outstanding.
These bonds are first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture and are secured by substantially all
property of the former CILCO. The bonds are callable at 100% of par value.
(k) These bonds are mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture and are secured by substantially all
property of the former IP and CIPS. The bonds are callable at 100% of par value. The bonds are also backed by an insurance guarantee policy.
The bonds are callable at 100% of par value.
(l)
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren
Companies and Genco at December 31, 2012:
Ameren
(Parent)(a)
Ameren
Missouri(a)
Ameren
Illinois(a)(b)
Genco(a)
Ameren
Consolidated
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
425
-
-
-
-
425
$
$
205
109
120
266
431
2,882
$
150
-
-
129
250
1,200
$ 4,013
$
1,729
$
-
-
-
-
-
825
825
$
355
534
120
395
681
4,907
$
6,992
(a) Excludes unamortized discount and premium of $1 million, $ 7 million, $ 6 million and $ 1 million at Ameren (Parent), Ameren Missouri,
Ameren Illinois, and Genco, respectively.
(b) Excludes $4 million related to Ameren Illinois’ long-term debt fair-market value adjustments, which are being amortized to interest expense
over the remaining life of the debt.
All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends and have voting
rights. Preferred stock not subject to mandatory redemption of Ameren’s subsidiaries was included in “Noncontrolling
Interests” on Ameren’s consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren
Missouri and Ameren Illinois that is not subject to mandatory redemption. The preferred stock is redeemable, at the option of
the issuer, at the prices shown below as of December 31, 2012, and 2011:
Ameren Missouri:
Without par value and stated value of $100 per share, 25 million shares authorized
130,000 shares . . . . . . . . . . . . . . . . . . . .
40,000 shares . . . . . . . . . . . . . . . . . . . .
150,000 shares . . . . . . . . . . . . . . . . . . . .
40,000 shares . . . . . . . . . . . . . . . . . . . .
213,595 shares . . . . . . . . . . . . . . . . . . . .
200,000 shares . . . . . . . . . . . . . . . . . . . .
20,000 shares . . . . . . . . . . . . . . . . . . . .
14,000 shares . . . . . . . . . . . . . . . . . . . .
$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
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Redemption Price (per share)
2012
2011
$ 110.00
104.75
105.625
105.00
110.00(a)
102.47
102.176
110.00
$
$
13
4
15
4
21
20
2
1
80
$
$
13
4
15
4
21
20
2
1
80
118
Redemption Price (per share)
2012
2011
Ameren Illinois:
With par value of $100 per share, 2 million shares authorized
4.00% Series
4.08% Series
4.20% Series
4.25% Series
4.26% Series
4.42% Series
4.70% Series
4.90% Series
4.92% Series
5.16% Series
6.625% Series
7.75% Series
144,275 shares . . . . . . . . . . . . . . . . . . . .
45,224 shares . . . . . . . . . . . . . . . . . . . .
23,655 shares . . . . . . . . . . . . . . . . . . . .
50,000 shares . . . . . . . . . . . . . . . . . . . .
16,621 shares . . . . . . . . . . . . . . . . . . . .
16,190 shares . . . . . . . . . . . . . . . . . . . .
18,429 shares . . . . . . . . . . . . . . . . . . . .
73,825 shares . . . . . . . . . . . . . . . . . . . .
49,289 shares . . . . . . . . . . . . . . . . . . . .
50,000 shares . . . . . . . . . . . . . . . . . . . .
124,273.75 shares . . . . . . . . . . . . . . . . . . . .
4,542 shares . . . . . . . . . . . . . . . . . . . .
$
101.00
103.00
104.00
102.00
103.00
103.00
103.00
102.00
103.50
102.00
100.00
100.00
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
14
5
2
5
2
2
2
7
5
5
12
1
62
142
$
$
$
14
5
2
5
2
2
2
7
5
5
12
1
62
142
In the event of voluntary liquidation, $105.50.
(a)
(b) Preferred stock not subject to mandatory redemption of Ameren’s subsidiaries was included in “Noncontrolling Interests” on Ameren’s
consolidated balance sheet.
Ameren has 100 million shares of $0.01 par value
preferred stock authorized, with no shares outstanding.
Ameren Missouri has 7.5 million shares of $1 par value
preference stock authorized, with no such preference stock
outstanding. Ameren Illinois has 2.6 million shares of no
par value preferred stock authorized, with no shares
outstanding.
Ameren
Ameren filed a Form S-3 registration statement with
the SEC in June 2011, authorizing the offering of 6 million
Ameren Missouri
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. In 2012, Ameren shares were
purchased in the open market for DRPlus and its 401(k)
plan. Under DRPlus and its 401(k) plan, Ameren issued
2.2 million and 3.0 million shares of common stock in 2011
and 2010, respectively, which were valued at $65 million
and $80 million for the respective years.
On September 11, 2012, Ameren Missouri issued $485 million principal amount of 3.90% senior secured notes due
September 15, 2042, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15,
2013. These notes are secured by first mortgage bonds. Ameren Missouri received net proceeds of $478 million. The proceeds
were used, together with other available cash, to provide the funds necessary to complete Ameren Missouri’s tender offer on
September 20, 2012, including the payment of interest and all related fees and expenses, and to retire the $173 million
principal amount 5.25% senior secured notes that matured in September 2012.
On September 20, 2012, Ameren Missouri completed its tender offer to purchase for cash its outstanding 6.00% senior
secured notes due 2018, 6.70% senior secured notes due 2019, 5.10% senior secured notes due 2018, and 5.10% senior
secured notes due 2019. Any notes that were not tendered and purchased in the tender offer remain outstanding and continue
to be obligations of Ameren Missouri. The following table sets forth the aggregate principal amount of each series of notes
repurchased, along with certain other items of the tender offer:
Senior Secured Notes
Principal Amount
Repurchased
Premium Plus Accrued
and Unpaid Interest(a)
Principal Amount Outstanding
After Tender Offer
6.00% senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . .
6.70% senior secured notes due 2019 . . . . . . . . . . . . . . . . . . . . .
5.10% senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . .
5.10% senior secured notes due 2019 . . . . . . . . . . . . . . . . . . . . .
$
71
121
1
56
$
19
35
(b)
12
$
179
329
199
244
(a) The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the
$485 million 3.90% senior secured notes due 2042.
(b) Amount is less than $1 million.
119
Ameren Illinois
On August 20, 2012, Ameren Illinois issued $400 million principal amount of 2.70% senior secured notes due
September 1, 2022, with interest payable semiannually on March 1 and September 1 of each year, beginning March 1, 2013.
These notes are secured by first mortgage bonds. Ameren Illinois received net proceeds of $397 million. The proceeds were
used, together with other available cash, to provide the funds necessary to complete Ameren Illinois’ tender offer on
August 27, 2012, including the payment of interest and all related fees and expenses, and to redeem all $51 million principal
amount of 5.50% pollution control revenue bonds at par value plus accrued interest.
On August 27, 2012, Ameren Illinois completed its tender offer to purchase for cash its outstanding 9.75% senior
secured notes due 2018 and 6.25% senior secured notes due 2018. Any notes that were not tendered and purchased in the
tender offer remain outstanding and continue to be obligations of Ameren Illinois. The following table sets forth the aggregate
principal amount of each series of notes repurchased, along with certain other items of the tender offer:
Senior Secured Notes
Principal Amount
Repurchased
Premium Plus Accrued
and Unpaid Interest(a)
Principal Amount Outstanding
After Tender Offer
9.75% senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . .
6.25% senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . .
$
87
194
$
36
47
$
313
144
(a) The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the
$400 million 2.70% senior secured notes due 2022.
In November 2012, $1 million of Ameren Illinois’ 6.20% Series 1992B Pollution Control revenue bonds matured and were
retired.
Indenture Provisions and Other Covenants
Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related
to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain
ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a
default under these covenants and provisions but would restrict the companies’ ability to issue bonds or preferred stock. The
following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios
and bonds and preferred stock issuable as of December 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.
Required Interest
Coverage Ratio(a)
Actual Interest
Coverage Ratio
Ameren Missouri . . . .
Ameren Illinois . . . . . .
>2.0
>2.0
4.6
7.1
Bonds Issuable(b)
$
4,056
3,439(d)
Required Dividend
Coverage Ratio(c)
Actual Dividend
Coverage Ratio
Preferred Stock
Issuable
>2.5
>1.5
122.8
2.8
$
2,351
203
(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain
cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b) Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts
shown also include bonds issuable based on retired bond capacity of $485 million and $645 million at Ameren Missouri and Ameren Illinois,
respectively.
(c) Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of
incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage
indenture.
Ameren’s indenture does not require Ameren to
comply with any quantitative financial covenants. The
indenture does, however, include certain cross-default
provisions. Specifically, either (1) the failure by Ameren to
pay when due and upon expiration of any applicable grace
period any portion of any Ameren indebtedness in excess of
$25 million or (2) the acceleration upon default of the
maturity of any Ameren indebtedness in excess of
$25 million under any indebtedness agreement, including
the 2012 Credit Agreements, constitutes a default under the
indenture, unless such past due or accelerated debt is
discharged or the acceleration is rescinded or annulled
within a specified period.
Ameren Missouri and Ameren Illinois and certain other
nonregistrant Ameren subsidiaries are subject to
Section 305(a) of the Federal Power Act, which makes it
unlawful for any officer or director of a public utility, as
defined in the Federal Power Act, to participate in the
making or paying of any dividend from any funds “properly
included in capital account.” The meaning of this limitation
has never been clarified under the Federal Power Act or
FERC regulations. However, FERC has consistently
interpreted the provision to allow dividends to be paid as
long as (1) the source of the dividends is clearly disclosed,
(2) the dividends are not excessive, and (3) there is no self-
dealing on the part of corporate officials. At a minimum,
Ameren believes that dividends can be paid by its
120
subsidiaries that are public utilities from net income and
retained earnings. In addition, under Illinois law, Ameren
Illinois may not pay any dividend on its stock, unless,
among other things, its earnings and earned surplus are
sufficient to declare and pay a dividend after provision is
made for reasonable and proper reserves, or unless Ameren
Illinois has specific authorization from the ICC.
Ameren Illinois’ articles of incorporation require
dividend payments on its 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. Ameren Illinois
committed to FERC to maintain a minimum 30% ratio of
common stock equity to total capitalization after the Ameren
Illinois Merger and AERG distribution. As of December 31,
2012, Ameren Illinois’ ratio of common stock equity to total
capitalization was 57%.
Genco’s indenture includes provisions that require
Genco to maintain certain interest coverage and debt-to-
capital ratios in order for Genco to pay dividends, to make
principal or interest payments on subordinated borrowings,
to make loans to or investments in affiliates, or to incur
additional external, third-party indebtedness. The following
table summarizes these ratios for the 12 months ended and
as of December 31, 2012:
Restricted payment interest
coverage ratio(a) . . . . . . . . . . . . . .
Additional indebtedness interest
coverage ratio(b) . . . . . . . . . . . . . .
Additional indebtedness debt-to-
capital ratio(b) . . . . . . . . . . . . . . . .
Required
Ratio
Actual
Ratio
≥1.75%
≥2.50%
≤60%
2.6%
2.6%
44%
(a) As of the date of the restricted payment, as defined, the
minimum ratio must have been achieved for the most recently
ended four fiscal quarters and projected by management to be
achieved for each of the subsequent four six-month periods.
Investments in the non-state-regulated subsidiary money pool
and repayments of non-state-regulated subsidiary money pool
borrowings are not subject to this incurrence test.
(b) Ratios must be computed on a pro forma basis considering the
additional indebtedness to be incurred and the related interest
expense. Non-state-regulated subsidiary money pool borrowings
are defined as permitted indebtedness and are
not subject to these incurrence tests. Other borrowings from
third-party external sources are included in the definition of
indebtedness and are subject to these incurrence tests.
Genco’s debt incurrence-related 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.
Under the provisions of Genco’s indenture, Genco may
not borrow additional funds from external, third-party
sources if its interest coverage ratio is less than a specified
minimum or its leverage ratio is greater than a specified
maximum. Based on projections as of December 31, 2012,
of its operating results and cash flows, Genco expects that,
by the end of the first quarter of 2013, its interest coverage
ratio will be less than the minimum ratio required for the
company to borrow additional funds from external, third-
party sources. Genco’s indenture does not restrict
intercompany borrowings from Ameren’s non-state-
regulated subsidiary money pool. However, borrowings
from the money pool are subject to Ameren’s control. If a
Genco intercompany financing need were to arise,
borrowings from the non-state-regulated subsidiary money
pool by Genco would be dependent on consideration by
Ameren of the facts and circumstances existing at that time.
Ameren has sought to have its Merchant Generation
business segment and Genco fund their operations
internally and not rely on financing from Ameren. In
December 2012, Ameren determined that it intends to, and
it is probable that it will, exit its Merchant Generation
business before the end of the previously estimated useful
lives of that business’s long-lived assets. As a result,
Ameren no longer considers the Merchant Generation
segment to be a core component of its future business
strategy. See Note 17 – Impairment and Other Charges for
additional Merchant Generation information.
In order for the Ameren Companies to issue securities
in the future, they will have to comply with all applicable
requirements in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2012, 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. See Note 14 – Related Party Transactions
for Ameren (parent) guarantees on behalf of its
subsidiaries.
121
NOTE 6 – OTHER INCOME AND EXPENSES
The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of
income (loss) for the years ended December 31, 2012, 2011, and 2010:
2012
2011
2010
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri:
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for equity funds used during construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Donations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
5(b)
$
28
36
2
71
24(c)
13
37
$
$
$
$
4(b)
28
31
-
63
9
5
14
-
5
2
7
11(c)
6
17
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
4
28
34
3
69
8
15
23
2
28
30
1
61
3
7
10
1
4
2
7
1
5
6
$
$
$
$
$
$
$
$
$
$
$
$
5
28
52
5
90
19
14
33
3
28
50
2
83
8
5
13
1
2
4
7
5
8
13
(a)
(b)
(c)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes interest income relating to a 2012 refund of charges included in an expired power purchase agreement with Entergy. See Note 2 –
Rate and Regulatory Matters for additional information.
Includes Ameren Illinois’ one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and
$1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois’ 2012 participation in the
formula ratemaking process.
NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of
changes in market prices for natural gas, coal, diesel,
electricity, and uranium. Such price fluctuations may cause
the following:
‰
an unrealized appreciation or depreciation of our
contracted commitments to purchase or sell when
purchase or sale prices under the commitments are
compared with current commodity prices;
‰ market values of coal, natural gas and uranium
inventories that differ from the cost of those
commodities in inventory; and
‰
actual cash outlays for the purchase of these
commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are
governed by our risk management policies for forward
contracts, futures, options, and swaps. Our net positions
are continually assessed within our structured hedging
programs to determine whether new or offsetting
transactions are required. The goal of the hedging program
is generally to mitigate financial risks while ensuring that
sufficient volumes are available to meet our requirements.
Contracts we enter into as part of our risk management
program may be settled financially, settled by physical
delivery, or net settled with the counterparty.
122
The following table presents open gross commodity contract volumes by commodity type as of December 31, 2012, and
2011:
Commodity
Accrual & NPNS
Contracts(a)
Cash Flow
Hedges(b)
Other
Derivatives(c)
Derivatives That Qualify for
Regulatory Deferral(d)
2012
2011
2012
2011
2012
2011
2012
2011
Quantity (in millions, except as indicated)
Coal (in tons)
Ameren Missouri . . . . . . . . . . . . . . . . . . . .
Other(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . .
96
39
135
116
31
147
Fuel oils (in gallons)(g)
Ameren Missouri . . . . . . . . . . . . . . . . . . . .
Other(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (in mmbtu)
Ameren Missouri . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . .
Other(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power (in megawatthours)
Ameren Missouri . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . .
Other(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . .
Renewable energy credits(h)
Ameren Missouri . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . .
Other(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uranium (pounds in thousands)
(e)
(e)
(e)
4
16
(e)
20
3
21
66
90
3
12
1
16
(e)
(e)
(e)
8
42
(e)
50
1
11
61
73
4
12
1
17
Ameren Missouri & Ameren . . . . . . . . . . .
5,142
5,553
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
9
9
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
17
17
(e)
(e)
(e)
(e)
(e)
-
7
7
(e)
52
52
-
(e)
47
47
2
(e)
34
36
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
36
36
9
(e)
8
17
1
(e)
30
31
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
26
(e)
26
19
128
(e)
147
9
14
-
23
(e)
(e)
(e)
(e)
(e)
(e)
(e)
53
(e)
53
19
174
(e)
193
6
24
(9)
21
(e)
(e)
(e)
(e)
446
148
(a) Accrual contracts include commodity contracts that do not qualify as derivatives. As of December 31, 2012, these contracts ran through
December 2017, March 2015, September 2035, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and
uranium, respectively.
(b) As of December 31, 2012, these contracts ran through December 2016 for power.
(c) As of December 31, 2012, these contracts ran through December 2015, October 2016, April 2015, and December 2016 for coal, fuel oils,
natural gas, and power, respectively.
(d) As of December 31, 2012, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas,
power, and uranium, respectively.
(e) Not applicable.
(f)
Includes AERG and Genco contracts for coal and fuel oils, Marketing Company and Genco contracts for natural gas, Marketing Company
contracts for power and renewable energy credits, and intercompany eliminations for power.
(g) Fuel oils consist of heating and crude oil.
(h) A renewable energy credit is created for every megawatthour of renewable energy generated. Ameren contracts include renewable energy
credits from solar, wind, and landfill gas-generated power.
Authoritative accounting guidance regarding derivative
instruments requires that all contracts considered to be
derivative instruments be recorded on the balance sheet at
their fair values, unless the NPNS exception applies. See
Note 8 – Fair Value Measurements for discussion of our
methods of assessing the fair value of derivative
instruments. Many of our physical contracts, such as our
purchased power contracts, qualify for the NPNS exception
to derivative accounting rules. The revenue or expense on
NPNS contracts is recognized at the contract price upon
physical delivery.
If we determine that a contract meets the definition of
a derivative and is not eligible for the NPNS exception, we
review the contract to determine if it qualifies for hedge
accounting. We also consider whether gains or losses
resulting from such derivatives qualify for regulatory
deferral. Contracts that qualify for cash flow hedge
accounting are recorded at fair value with changes in fair
value charged or credited to accumulated OCI in the period
in which the change occurs, to the extent the hedge is
effective. To the extent the hedge is ineffective, the related
changes in fair value are charged or credited to the
statement of income and comprehensive income in the
period in which the change occurs. When the contract is
123
settled or delivered, the net gain or loss is recorded in the
statement of income or the statement of income and
comprehensive income.
Derivative contracts that qualify for regulatory deferral
are recorded at fair value, with changes in fair value
recorded as regulatory assets or regulatory liabilities in the
period in which the change occurs. Ameren Missouri and
Ameren Illinois believe derivative gains and losses deferred
as regulatory assets and regulatory liabilities are probable of
recovery or refund through future rates charged to
customers. Regulatory assets and regulatory liabilities are
amortized to operating income as related losses and gains
are reflected in rates charged to customers. Therefore,
gains and losses on these derivatives have no effect on
operating income.
Certain derivative contracts are entered into on a
regular basis as part of our risk management program but
do not qualify for, or we do not choose to elect, the NPNS
exception, hedge accounting, or regulatory deferral
accounting. Such contracts are recorded at fair value, with
changes in fair value charged or credited to the statement of
income or the statement of income and comprehensive
income in the period in which the change occurs.
Authoritative accounting guidance permits companies
to offset fair value amounts recognized for the right to
reclaim cash collateral (a receivable) or the obligation to
return cash collateral (a liability) against fair value amounts
recognized for derivative instruments that are executed with
the same counterparty under the same master netting
arrangement. The Ameren Companies did not elect to adopt
this guidance for any eligible commodity contracts.
The following table presents the carrying value and balance sheet location of all derivative instruments as of
December 31, 2012 and 2011:
Balance Sheet Location
Ameren(a)
Ameren
Missouri
Ameren
Illinois
2012
Derivative assets designated as hedging instruments
Commodity contracts:
Power . . . . . . . . . . . . . . . . MTM derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative assets not designated as hedging instruments(c)
Commodity contracts:
. . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal
Fuel oils . . . . . . . . . . . . . . MTM derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . MTM derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . MTM derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
25
14
39
1
10
-
5
5
-
1
85
-
16
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
123
$
Derivative liabilities not designated as hedging instruments(c)
Commodity contracts:
Coal
. . . . . . . . . . . . . . . . . MTM derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Fuel oils . . . . . . . . . . . . . . MTM derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . MTM derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . MTM derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Uranium . . . . . . . . . . . . . . MTM derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
9
4
3
-
3
68
-
45
74
-
107
1
-
1
315
$
$
$
$
$
(b)
-
-
-
(b)
8
4
(b)
-
1
(b)
14
1
28
(b)
-
(b)
2
2
(b)
8
7
(b)
4
-
(b)
1
1
$
$
$
$
$
(b)
-
-
-
(b)
-
-
(b)
1
-
(b)
-
-
1
-
-
-
-
-
56
-
38
21
-
90
-
-
-
$
25
$
205
124
Balance Sheet Location
Ameren(a)
Ameren
Missouri
Ameren
Illinois
2011
Derivative assets designated as hedging instruments
Commodity contracts:
Power . . . . . . . . . . . . . . . . MTM derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative assets not designated as hedging instruments(c)
Commodity contracts:
Fuel oils . . . . . . . . . . . . . . MTM derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . MTM derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . MTM derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities not designated as hedging instruments(c)
Commodity contracts:
Fuel oils . . . . . . . . . . . . . . MTM derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . MTM derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . MTM derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MTM derivative liabilities - affiliates . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . .
Uranium . . . . . . . . . . . . . .
$
$
$
$
$
$
$
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Balance sheet line item not applicable to registrant.
Includes derivatives subject to regulatory deferral.
(c)
8
16
24
1
1
29
-
8
6
-
-
72
-
99
214
2
-
106
-
92
53
(b)
-
26
1
280
$
$
$
$
$
$
$
$
(b)
-
-
-
-
(b)
17
6
(b)
2
-
(b)
30
-
55
(b)
1
(b)
13
13
(b)
(b)
9
-
1
37
$
$
$
$
$
$
$
$
(b)
-
-
-
-
(b)
-
-
(b)
1
1
(b)
-
77
79
-
-
90
-
79
9
200
-
8
-
386
The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in
accumulated OCI and regulatory assets or regulatory liabilities as of December 31, 2012, and 2011:
2012
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)
Interest rate derivative contracts(c)(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas derivative contracts(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power derivative contracts(g)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uranium derivative contracts(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)
Interest rate derivative contracts(c)(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Fuel oils derivative contracts(e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas derivative contracts(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power derivative contracts(g)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uranium derivative contracts(h)
125
Ameren
Ameren
Missouri
Ameren
Illinois
Other(a)
$
$
47
(7)
4
(107)
(99)
(2)
19
(8)
19
(191)
81
(1)
$
$
-
-
4
(14)
12
(2)
-
-
19
(24)
21
(1)
$
-
-
$
47
(7)
-
(93)
(111)
-
-
-
-
-
$
-
-
$
19
(8)
-
(167)
(140)
-
-
-
200
-
(c)
Includes amounts for Marketing Company, Genco, and intercompany eliminations.
(a)
(b) Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure
through December 2016 as of December 31, 2012. In light of market prices at December 31, 2012, net pretax unrealized gains of $32 million
are expected to be reclassified into earnings during the next 12 months as the hedged transaction occur. However, the actual amount
reclassified from accumulated OCI could vary due to future changes in market prices.
Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The
swaps covered the first 10 years of debt that has a 30-year maturity, and the gain in OCI was amortized over a 10-year period that began in
June 2002. The balance of the gain was fully amortized as of June 30, 2012. The carrying value at December 31, 2011, was less than
$1 million.
Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge
of interest rate risks associated with Genco’s April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year
period that began in April 2008. The carrying value at December 31, 2012, and December 31, 2011, was a loss of $8 million and $9 million,
respectively. Over the next twelve months ending December 31, 2013, $1.4 million of the loss will be amortized.
(d)
(e) Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s
transportation costs for coal through October 2015 as of December 31, 2012. Current gains deferred as regulatory liabilities include $4 million
and $4 million at Ameren and Ameren Missouri as of December 31, 2012, respectively. Current losses deferred as regulatory assets include
$1 million and $1 million at Ameren and Ameren Missouri as of December 31, 2012, respectively.
(f) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through
March 2017 at Ameren and Ameren Missouri and through October 2016 at Ameren Illinois, in each case as of December 31, 2012. Current
gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of December 31, 2012.
Current losses deferred as regulatory assets include $64 million, $8 million, and $56 million at Ameren, Ameren Missouri and Ameren Illinois,
respectively, as of December 31, 2012.
(g) Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May
2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of December 31, 2012. Current gains
deferred as regulatory liabilities include $14 million and $14 million at Ameren and Ameren Missouri, respectively, as of December 31, 2012.
Current losses deferred as regulatory assets include $24 million, $3 million, and $21 million at Ameren, Ameren Missouri and Ameren Illinois,
respectively, as of December 31, 2012.
(h) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium
requirements through September 2014 as of December 31, 2012. Current losses deferred as regulatory assets include $1 million and $1 million
at Ameren and Ameren Missouri as of December 31, 2012, respectively.
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the
transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the
respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk
management program involves establishing credit limits and collateral requirements for counterparties, using master trading
and netting agreements, and reporting daily exposure to senior management.
We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result
from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading
and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural
gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the
National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) the
North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas.
These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further,
collateral requirements are calculated at the master trading and netting agreement level by counterparty.
Concentrations of Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties
and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The
following table presents by groupings the maximum exposure, as of December 31, 2012, and 2011, if counterparty groups
126
were to fail completely to perform on contracts. The maximum exposure is based on the gross fair value of financial
instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding
right to net transactions based on master trading and netting agreements.
Affiliates(a)
Coal
Producers
Commodity
Marketing
Companies
Electric
Utilities
Financial
Companies
Municipalities/
Cooperatives
Oil and Gas
Companies
Retail
Companies
Total
2012
AMO . . . . . . . . . .
AIC . . . . . . . . . . .
Other(b) . . . . . . . .
Ameren . . . . . . .
2011
AMO . . . . . . . . . .
AIC . . . . . . . . . . .
Other(b) . . . . . . . .
Ameren . . . . . . .
$
$
$
$
-
-
71
71
1
-
275
276
$
$
$
$
-
-
3
3
35
-
2
37
$
$
$
$
2
-
38
40
1
84
4
89
$
$
$
$
3
-
10
13
4
-
12
16
$
$
$
$
14
1
13
28
26
1
57
84
$
$
$
$
3
-
192
195
4
-
194
198
$
$
$
$
-
-
3
3
-
-
3
3
$
$
$
$
-
-
85
85
-
-
87
87
$
$
$
$
22
1
415
438
71
85
634
790
(a) Primarily composed of Marketing Company’s exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the
consolidated Ameren level for purposes of this disclosure as it is calculated without regard to the offsetting affiliate counterparty’s liability
position. See Note 14 – Related Party Transactions for additional information on these financial contracts.
Includes amounts for Marketing Company, AERG, Genco, and AFS.
(b)
The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and
collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held.
The amount of cash collateral held by Ameren and Marketing Company from counterparties and based on contractual rights
under agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting
agreements was $3 million from commodity marketing companies at December 31, 2012. Cash collateral held by Ameren and
Marketing Company was less than $1 million and less than $1 million, respectively, from retail companies at December 31,
2011. As of December 31, 2012, other collateral used to reduce exposure consisted of letters of credit in the amount of
$7 million, $1 million, and $6 million held by Ameren, Ameren Missouri, and Marketing Company, respectively. As of
December 31, 2011, other collateral used to reduce exposure consisted of letters of credit in the amount of $9 million,
$1 million, $1 million, and $7 million held by Ameren, Ameren Missouri, Genco and Marketing Company, respectively. The
following table presents the potential loss after consideration of the application of master trading and netting agreements and
collateral held as of December 31, 2012 and 2011:
Affiliates(a)
Coal
Producers
Commodity
Marketing
Companies
Electric
Utilities
Financial
Companies
Municipalities/
Cooperatives
Oil and Gas
Companies
Retail
Companies
Total
2012
AMO . . . . . . . . . .
AIC . . . . . . . . . . .
. . . . . . . .
Other(b)
Ameren . . . . . . . .
2011
AMO . . . . . . . . . .
AIC . . . . . . . . . . .
. . . . . . . .
Other(b)
Ameren . . . . . . . .
$
$
$
$
-
-
68
68
1
-
273
274
$
$
$
$
-
-
1
1
35
-
-
35
$
$
$
$
1
-
29
30
1
84
3
88
$
$
$
$
1
-
4
5
3
-
6
9
$
$
$
$
10
-
11
21
22
-
43
65
$
$
$
$
3
-
185
188
4
-
187
191
$
$
$
$
-
-
-
-
-
-
2
2
$
$
$
$
-
-
85
85
-
-
86
86
$
$
$
$
15
-
383
398
66
84
600
750
(a) Primarily composed of Marketing Company’s exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the
consolidated Ameren level for purposes of this disclosure as it is calculated without regard to the offsetting affiliate counterparty’s liability
position. See Note 14 – Related Party Transactions for additional information on these financial contracts.
Includes amounts for Marketing Company, AERG, Genco, and AFS.
(b)
Derivative Instruments with Credit Risk-Related Contingent Features
Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to
experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding
performance of an obligation requested adequate assurance of performance, additional collateral postings might be required.
The following table presents, as of December 31, 2012, and 2011, the aggregate fair value of all derivative instruments with
credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of
127
additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability
position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features
underlying these agreements were triggered on December 31, 2012, or 2011, respectively, and (2) those counterparties with
rights to do so requested collateral:
Aggregate Fair Value of
Derivative Liabilities(a)
Cash
Collateral Posted
Potential Aggregate Amount of
Additional Collateral Required(b)
2012
Ameren Missouri
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011
Ameren Missouri
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
78
148
130
356
102
220
134
456
$
$
$
$
3
58
7
68
8
96
12
116
$
$
$
$
71
84
90
245
86
125
121
332
(a) Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures.
(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional
collateral required to be posted is determined after consideration of the effects of such agreements.
Includes amounts for Marketing Company, Genco, and Ameren (parent).
(c)
Cash Flow Hedges
The following table presents the pretax net gain or loss for the year ended December 31, 2012 and 2011, associated with
derivative instruments designated as cash flow hedges:
Gain (Loss)
Recognized in OCI(a)
Location of (Gain) Loss
Reclassified from
Accumulated OCI into
Income(b)
(Gain) Loss
Reclassified from
Accumulated OCI
into Income(b)
Location of Gain (Loss)
Recognized in Income(c)
Gain (Loss)
Recognized
in Income(c)
2012
Ameren:(d)
Power . . . . . . . . . . .
Interest rate(e) . . . . .
2011
Ameren:(d)
Power . . . . . . . . . . .
Interest rate(e) . . . . .
$
$
34
-
6
-
Operating Revenues - Electric . .
Interest Charges . . . . . . . . . . . .
Operating Revenues - Electric . .
Interest Charges . . . . . . . . . . . .
$
$
(6)
1
5
(f)
Operating Revenues - Electric . .
Interest Charges . . . . . . . . . . . .
Operating Revenues - Electric . .
Interest Charges . . . . . . . . . . . .
$
$
(12)
-
(10)
-
(a) Effective portion of gain (loss).
(b) Effective portion of (gain) loss on settlements.
(c)
(d)
(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income
Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
over a 10-year period.
Less than $1 million.
(f)
Other Derivatives
The following table represents the net change in market value associated with derivatives not designated as hedging
instruments for the years ended December 31, 2012 and 2011:
Location of Gain (Loss)
Recognized in Income
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (generation)
. . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . .
Operating Expenses - Fuel
. . . . . . . . . . . . .
Operating Expenses - Fuel
Operating Expenses - Fuel
. . . . . . . . . . . . .
Operating Revenues - Electric . . . . . . . . . .
Total
Ameren Missouri
Natural gas (generation)
. . . . . . . . . . . . . .
Operating Expenses - Fuel
. . . . . . . . . . . . .
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Gain (Loss) Recognized
in Income
2012
2011
$
$
$
(12)
(11)
1
12
(10)
-
$
$
$
-
(1)
2
(2)
(1)
(1)
128
Derivatives Subject to Regulatory Deferral
The following table represents the net change in
market value associated with derivatives that qualify for
regulatory deferral for the years ended December 31, 2012
and 2011:
Gain (Loss) Recognized
In Regulatory Liabilities
or Regulatory Assets
2011
2012
Ameren(a)
Ameren
Missouri
Fuel oils . . . . . . . . . . . . .
Natural gas . . . . . . . . . . .
Power . . . . . . . . . . . . . . .
Uranium . . . . . . . . . . . . .
$
(15)
84
(180)
(1)
Total
$ (112)
Fuel oils . . . . . . . . . . . . .
Natural gas . . . . . . . . . . .
Power . . . . . . . . . . . . . . .
Uranium . . . . . . . . . . . . .
Total
$
$
$
$
(15)
10
(9)
(1)
(15)
74
29
103
$
$
$
$
$
$
-
(26)
80
(3)
51
-
-
18
(3)
15
(26)
212
186
Ameren
Illinois
Natural gas . . . . . . . . . . .
Power . . . . . . . . . . . . . . .
Total
(a)
Includes amounts for intercompany eliminations.
NOTE 8 – FAIR VALUE MEASUREMENTS
Fair value is defined as the exchange price that would
be received for an asset or paid to transfer a liability (an exit
price) in the principal or most advantageous market for the
asset or liability in an orderly transaction between market
participants on the measurement date. We use various
methods to determine fair value, including market, income,
and cost approaches. With these approaches, we adopt
certain assumptions that market participants would use in
pricing the asset or liability, including assumptions about
market risk or the risks inherent in the inputs to the
valuation. Inputs to valuation can be readily observable,
market-corroborated, or unobservable. We use valuation
techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs. Authoritative
accounting guidance established a fair value hierarchy that
prioritizes the inputs used to measure fair value. All financial
assets and liabilities carried at fair value are classified and
disclosed in one of the following three hierarchy levels:
Level 1: Inputs based on quoted prices in active markets for
identical assets or liabilities. Level 1 assets and liabilities
are primarily exchange-traded derivatives and assets,
including cash and cash equivalents and listed equity
securities, such as those held in Ameren Missouri’s nuclear
decommissioning trust fund.
The market approach is used to measure the fair value
of equity securities held in Ameren Missouri’s nuclear
decommissioning trust fund. Equity securities in this fund
are representative of the S&P 500 index, excluding
securities of Ameren Corporation, owners and/or operators
129
of nuclear power plants and the trustee and investment
managers. The S&P 500 index comprises stocks of large
capitalization companies.
As part of the 2007 Illinois Electric Settlement
Agreement and subsequent Illinois power procurement
processes, Ameren Illinois entered into financial contracts
with Marketing Company. These financial contracts were
derivative instruments. They were accounted for as cash
flow hedges by Marketing Company and as derivatives that
qualified for regulatory deferral by Ameren Illinois.
Consequently, Ameren Illinois and Marketing Company
recorded the fair value of the contracts on their respective
balance sheets and the changes to the fair value in
regulatory assets or liabilities by Ameren Illinois and OCI by
Marketing Company. In Ameren’s consolidated financial
statements, all financial statement effects of the derivative
instruments entered into among affiliates were eliminated.
As of December 31, 2012 these contracts had fully expired.
The fair value of the financial contracts included in “MTM
derivative liabilities – affiliates” on Ameren Illinois’ balance
sheet was $200 million at December 31, 2011.
Level 2: Market-based inputs corroborated by third-party
brokers or exchanges based on transacted market data.
Level 2 assets and liabilities include certain assets held in
Ameren Missouri’s nuclear decommissioning trust fund,
including corporate bonds and other fixed-income
securities, United States treasury and agency securities, and
certain over-the-counter derivative instruments, including
natural gas and financial power transactions.
Fixed income securities are valued using prices from
independent industry recognized data vendors who provide
values that are either exchange based or matrix based. The
fair value measurements of fixed income securities
classified as Level 2 are based on inputs other than quoted
prices that are observable for the asset or liability. Examples
are matrix pricing, market corroborated pricing, and inputs
such as yield curves and indices. Level 2 fixed income
securities in the nuclear decommissioning trust fund are
primarily corporate bonds, asset-backed securities and
United States agency bonds.
Derivative instruments classified as Level 2 are valued
by corroborated observable inputs, such as pricing services
or prices from similar instruments that trade in liquid
markets. Our development and corroboration process
entails obtaining multiple quotes or prices from outside
sources. To derive our forward view to price our derivative
instruments at fair value, we average the midpoints of the
bid/ask spreads. To validate forward prices obtained from
outside parties, we compare the pricing to recently settled
market transactions. Additionally, a review of all sources is
performed to identify any anomalies or potential errors.
Further, we consider the volume of transactions on certain
trading platforms in our reasonableness assessment of the
averaged midpoint. Natural gas derivative contracts are
valued based upon exchange closing prices without
significant unobservable adjustments. Power derivatives
contracts are valued based upon the use of multiple forward
prices provided by third parties. The prices are averaged
and shaped to a monthly profile when needed without
significant unobservable adjustments.
Level 3: Unobservable inputs that are not corroborated by
market data. Level 3 assets and liabilities are valued by
internally developed models and assumptions or
methodologies that use significant unobservable inputs.
Level 3 assets and liabilities include derivative instruments
that trade in less liquid markets, where pricing is largely
unobservable. We value Level 3 instruments by using
pricing models with inputs that are often unobservable in
the market, as well as certain internal assumptions. Our
development and corroboration process entails obtaining
multiple quotes or prices from outside sources. As a part of
our reasonableness review, an evaluation of all sources is
performed to identify any anomalies or potential errors.
Note 17 – Impairment and Other Charges describes
Ameren’s use of significant unobservable inputs, which are
Level 3 inputs, to estimate the fair value of Merchant
Generation’s long-lived assets.
We perform an analysis each quarter to determine the
appropriate hierarchy level of the assets and liabilities
subject to fair value measurements. Financial assets and
liabilities are classified in their entirety according to the
lowest level of input that is significant to the fair value
measurement. All assets and liabilities whose fair value
measurement is based on significant unobservable inputs
are classified as Level 3.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and
liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:
Fair Value
Assets Liabilities
Valuation Technique(s)
Unobservable Input
Level 3 Derivative asset and liability – commodity contracts(a):
9
Discounted cash flow
Ameren(b)
Fuel oils
(3)
$
$
Power(f)
131
(172)
Option model
Option model
Discounted cash flow
Fundamental energy production
model
Contract price allocation
Uranium
-
(2)
Discounted cash flow
Escalation rate(%)(c)
Counterparty credit risk(%)(d),(e)
Ameren credit risk(%)(d),(e)
Volatilities(%)(c)
Volatilities(%)(d)
Average bid/ask consensus peak and
off-peak pricing($/MWh)(d)
Average bid/ask consensus peak and
off-peak pricing - forwards/
swaps($/MWh)(d)
Estimated auction price for
FTRs($/MW)(c)
Nodal basis($/MWh)(d)
Counterparty credit risk(%)(d),(e)
Ameren credit risk(%)(d),(e)
Estimated future gas prices($/mmbtu)(c)
Estimated renewable energy credit
costs($/ credit)(c)
Average bid/ask consensus
pricing($/pound)(c)
Ameren
Missouri
Fuel oils
$
8
$
(3)
Discounted cash flow
Escalation rate(%)(c)
Power(f)
14
(3)
Option model
Discounted cash flow
Uranium
-
(2)
Discounted cash flow
Counterparty credit risk(%)(d),(e)
Ameren Missouri credit risk(%)(d),(e)
Volatilities(%)(c)
Average bid/ask consensus peak and
off- peak pricing - forwards/
swaps($/MWh)(d)
Estimated auction price for
FTRs($/MW)(c)
Nodal basis($/MWh)(d)
Counterparty credit risk(%)(d),(e)
Ameren Missouri credit risk(%)(d),(e)
Average bid/ask consensus
pricing($/pound)(c)
130
Range
[Weighted Average]
.21 - .68
.12 - 1
2 - 31
7 - 27
13 - 38
24 - 45
16 - 52
[.48]
[1]
[12]
[24]
[26]
[36]
[32]
(133,787) - 19,671[198]
(12) - 1
.04 - 100
2 - 5
4 - 8
5 - 7
43 - 46
.21 - .60
.12 - 1
2
7 - 27
24 - 56
[(1)]
[2]
[5]
[6]
[6]
[44]
[.44]
[1]
[24]
[36]
(281) - 1,851
[178]
(5) - (1)
.22 - 1
2
43 - 46
[(2)]
[1]
[44]
Fair Value
Assets Liabilities
Valuation Technique(s)
Unobservable Input
Range
[Weighted Average]
Ameren
Illinois
Power(f)
$
-
$ (111)
Discounted cash flow
Fundamental energy production
model
Contract price allocation
Average bid/ask consensus peak and
off- peak pricing - forwards/
swaps($/MWh)(c)
Nodal basis($/MWh)(c)
Ameren Illinois credit risk(%)(d),(e)
Estimated future gas prices($/mmbtu)(c)
Estimated renewable energy credit
costs($/ credit)(c)
22 - 47
(5) - (1)
5
4 - 8
5 - 7
[30]
[(3)]
[6]
[6]
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a) The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
(c) Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(d) Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(e) Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit
risk is only applied to counterparties with derivative liability balances.
(f) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak through 2017. Valuations beyond 2017 utilize
fundamentally modeled pricing by month for peak and off-peak.
In accordance with applicable authoritative accounting
guidance, we consider nonperformance risk in our valuation
of derivative instruments by analyzing the credit standing of
our counterparties and considering any counterparty credit
enhancements (e.g., collateral). The guidance also requires
that the fair value measurement of liabilities reflect the
nonperformance risk of the reporting entity, as applicable.
Therefore, we have factored the impact of our credit
standing, as well as any potential credit enhancements, into
the fair value measurement of both derivative assets and
derivative liabilities. Included in our valuation, and based on
current market conditions, is a valuation adjustment for
counterparty default derived from market data such as the
price of credit default swaps, bond yields, and credit
ratings. Ameren recorded net losses of less than $1 million,
net losses of $2 million, and net gains of less than
$1 million in 2012, 2011, and 2010, respectively, related to
valuation adjustments for counterparty default risk in 2012,
2011 and 2010. At December 31, 2012, the counterparty
default risk liability valuation adjustment related to
derivative contracts totaled $7 million, less than $1 million,
and $7 million, for Ameren, Ameren Missouri, and Ameren
Illinois, respectively. At December 31, 2011, the
counterparty default risk liability valuation adjustment
related to derivative contracts totaled $1 million, less than
$1 million, and $19 million for Ameren, Ameren Missouri,
and Ameren Illinois, respectively.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a
recurring basis as of December 31, 2012:
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Other
Unobservable
Inputs
(Level 3)
Assets:
Ameren(a)
Derivative assets - commodity contracts(b):
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1
6
4
-
$
-
-
2
9
Total derivative assets - commodity contracts . . . . . .
$
11
$
11
$
$
-
9
-
131
140
Nuclear decommissioning trust fund(c):
Cash and cash equivalents . . . . . . . . . . . . . . . . .
Equity securities:
U.S. large capitalization . . . . . . . . . . . . . . .
Debt securities:
Corporate bonds . . . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . . . .
U.S. treasury and agency securities . . . . . .
Asset-backed securities . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
264
-
-
-
-
-
-
-
47
1
81
11
1
Total nuclear decommissioning trust fund . . . . . . . . .
Total Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
265
276
$
$
141
152
$
$
-
-
-
-
-
-
-
-
140
Total
$
$
1
15
6
140
162
1
264
47
1
81
11
1
$ 406
$ 568
131
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Other
Unobservable
Inputs
(Level 3)
Total
Ameren
Missouri
Derivative assets - commodity contracts(b):
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total derivative assets - commodity contracts . . . .
Nuclear decommissioning trust fund(c):
Cash and cash equivalents . . . . . . . . . . . . . . .
Equity securities:
$
$
4
-
-
4
1
U.S. large capitalization . . . . . . . . . . . . .
264
Debt securities:
Corporate bonds . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . .
U.S. treasury and agency securities . . . .
Asset-backed securities . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
Total nuclear decommissioning trust fund . . . . . . .
Total Ameren Missouri . . . . . . . . . . . . . . . . . . . . . .
Derivative assets - commodity contracts(b):
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities - commodity contracts(b):
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uranium . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities - commodity contracts(b):
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uranium . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren Missouri
Ameren
Illinois
Liabilities:
Ameren(a)
Ameren
Missouri
Ameren
Illinois
Derivative liabilities - commodity contracts(b):
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . .
-
-
-
-
-
$ 265
$ 269
$
$
$
$
$
$
$
$
-
-
-
13
3
11
-
-
27
1
7
-
-
8
-
-
-
$
$
$
$
$
$
$
$
$
$
$
$
-
1
1
2
-
-
47
1
81
11
1
141
143
1
-
1
-
-
102
9
-
111
-
8
1
-
9
94
-
94
$
$
$
$
$
$
$
$
$
$
$
8
-
14
22
-
-
-
-
-
-
-
-
22
-
-
-
-
3
-
172
2
177
3
-
3
2
8
-
111
$ 111
$
$
$
$
$
$
$
$
$
$
$
$
12
1
15
28
1
264
47
1
81
11
1
406
434
1
-
1
13
6
113
181
2
315
4
15
4
2
25
94
111
205
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $2 million of receivables, payables, and accrued income, net.
132
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a
recurring basis as of December 31, 2011:
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Other
Unobservable
Inputs
(Level 3)
Total
Assets:
Ameren(a)
Ameren
Missouri
Derivative assets - commodity contracts(b):
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total derivative assets - commodity contracts . . . .
Nuclear decommissioning trust fund(c):
Cash and cash equivalents . . . . . . . . . . . . . . .
Equity securities:
$
$
33
4
-
37
3
U.S. large capitalization . . . . . . . . . . . . .
234
Debt securities:
Corporate bonds . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . .
U.S. treasury and agency securities . . . .
Asset-backed securities . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
Total nuclear decommissioning trust fund . . . . . . .
Total Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative assets - commodity contracts(b):
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total derivative assets - commodity contracts . . . .
Nuclear decommissioning trust fund(c):
Cash and cash equivalents . . . . . . . . . . . . . . .
Equity securities:
-
-
-
-
-
237
274
20
2
-
22
3
$
$
$
$
U.S. large capitalization . . . . . . . . . . . . .
234
Debt securities:
Corporate bonds . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . .
U.S. treasury and agency securities . . . .
Asset-backed securities . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
Total nuclear decommissioning trust fund . . . . . . .
Total Ameren Missouri . . . . . . . . . . . . . . . . . . . . . .
Derivative assets - commodity contracts(b):
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities - commodity contracts(b):
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uranium . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities - commodity contracts(b):
Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uranium . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren Missouri . . . . . . . . . . . . . . . . . .
Ameren
Illinois
Liabilities:
Ameren(a)
Ameren
Missouri
-
-
-
-
-
237
259
-
-
-
2
22
-
-
24
1
12
-
-
13
$
$
$
$
$
$
$
$
133
$
$
$
$
$
$
$
$
$
$
$
$
$
$
-
-
2
2
-
-
44
1
65
10
1
121
123
-
-
1
1
-
-
44
1
65
10
1
121
122
-
-
-
-
-
2
-
2
-
-
1
-
1
$
$
4
2
193
199
-
-
-
-
-
-
-
-
199
3
-
29
32
-
-
-
-
-
-
-
-
32
2
77
79
-
176
78
1
255
-
14
8
1
23
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
37
6
195
238
3
234
44
1
65
10
1
358
596
23
2
30
55
3
234
44
1
65
10
1
358
413
2
77
79
2
198
80
1
281
1
26
9
1
37
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
Significant
Other Observable
Inputs
(Level 2)
Significant
Other
Unobservable
Inputs
(Level 3)
Ameren
Illinois
Derivative liabilities - commodity contracts(b):
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . .
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren Illinois . . . . . . . . . . . . . . . . . . .
$
$
7
-
7
$
$
-
-
-
$
$
162
217
379
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $(1) million of receivables, payables, and accrued income, net.
Total
$ 169
217
$ 386
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the
fair value hierarchy as of December 31, 2012:
Net Derivative Commodity Contracts
Ameren
Missouri
Ameren
Illinois
Other(a)
Ameren
Fuel oils:
Beginning balance at January 1, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized and unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers into Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012 . . . . .
Natural gas:
Beginning balance at January 1, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized and unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012 . . . . .
Power:
Beginning balance at January 1, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized and unrealized gains (losses):
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Included in earnings(c)
Included in OCI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Included in regulatory assets/liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized and unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012 . . . . .
Uranium:
Beginning balance at January 1, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized and unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012 . . . . .
$
3
$
(1)
(1)
7
(3)
(2)
1
-
5
(1)
(14)
(2)
(2)
-
1
15
-
-
21
-
-
11
11
21
(1)
(37)
(4)
11
-
(1)
(2)
(2)
1
(2)
(1)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(160)
(25)
(25)
-
15
170
-
-
(140)
-
-
(226)
(226)
-
-
255
-
(111)
$
(191)(d) $
$
1
$
$
$
$
$
$
$
(b)
(b)
-
-
-
1
(1)
1
-
-
(b)
(b)
1
(1)
-
-
-
234
27
26
40
93
8
2
(279)
1
59
44
$
$
$
$
$
$
$
$
(b)
(b)
(b)
(b)
(b)
(b)
$
(b) $
(b)
(b)
(b)
(b) $
(b) $
$
$
4
(1)
(1)
7
(3)
(2)
2
(1)
6
(1)
(174)
(27)
(27)
1
15
185
-
-
115
27
26
(175)
(122)
29
1
(61)
(3)
(41)
(147)
(1)
(2)
(2)
1
(2)
(1)
(a)
Includes amounts for Marketing Company, AERG, Genco, and intercompany eliminations, including the elimination of financial power contracts
between Ameren Illinois and Marketing Company.
(b) Not applicable.
(c) Net gains and losses on power derivative commodity contracts are recorded in “Operating Revenues - Electric”.
(d) The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois swap contracts, which
expire in May 2032.
134
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the
fair value hierarchy as of December 31, 2011:
Net Derivative Commodity Contracts
Ameren
Missouri
Ameren
Illinois
Fuel oils:
Beginning balance at January 1, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
30
$
Realized and unrealized gains (losses):
Included in earnings(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Included in regulatory assets/liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized and unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011 . . . . . .
Natural gas:
Beginning balance at January 1, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized and unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011 . . . . . .
Power:
Beginning balance at January 1, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized and unrealized gains (losses):
Included in earnings(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Included in OCI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Included in regulatory assets/liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized and unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers into Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011 . . . . . .
Uranium:
Beginning balance at January 1, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Realized and unrealized gains (losses):
Included in regulatory assets/liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized and unrealized gains (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011 . . . . . .
-
19
19
4
(1)
(30)
(19)
3
(11)
(14)
(8)
(8)
-
-
8
(14)
(6)
2
-
-
17
17
30
(1)
(27)
(1)
1
21
1
2
(3)
(3)
(1)
1
(1)
-
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(134)
(107)
(107)
1
(1)
81
(160)
(72)
(352)
-
-
7
7
-
-
205
-
-
(140)
13
(b)
(b)
(b)
(b)
(b)
(b)
(b)
Other(a)
Ameren
$
21
$
51
16
(b)
16
1
-
(26)
(11)
1
(7)
16
19
35
5
(1)
(56)
(30)
4
(18)
$
$
-
$ (148)
(b)
(b)
-
-
-
-
-
(115)
(115)
1
(1)
89
$ (174)
(78)
$
386
$
36
(13)
24
51
62
35
(21)
(227)
1
(2)
234
59
(13)
24
75
86
65
(22)
(49)
-
(1)
$ 115
73
$
(b)
$
2
(b)
(b)
(b)
(b)
(b)
(b)
$
$
(3)
(3)
(1)
1
(1)
-
$
$
$
$
$
$
$
$
$
$
$
(a)
Includes amounts for Marketing Company, AERG, Genco, and intercompany eliminations, including the elimination of financial power contracts
between Ameren Illinois and Marketing Company.
(b) Not applicable.
(c) Net gains and losses on fuel oils derivative commodity contracts are recorded in “Operating Expenses - Fuel,” while net gains and losses on
power derivative commodity contracts are recorded in “Operating Revenues - Electric.”
Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a
higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or
(2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the
lowest significant input became observable during the period. Transfers out of Level 3 into Level 2 for natural gas derivatives
were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing
to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter 2012.
Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas
prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were
primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended
December 31, 2012 and the previous reporting period ended December 31, 2011. Any reclassifications are reported as
135
prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were
primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended
December 31, 2012 and the previous reporting period ended December 31, 2011. Any reclassifications are reported as
transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For
the years ended December 31, 2012 and 2011, there were no transfers between Level 1 and Level 2 related to derivative
commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative
commodity contracts for the years ended December 31, 2012 and 2011:
Ameren - derivative commodity contracts:(a)
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 / Transfers into Level 1 - Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 / Transfers into Level 2 - Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers into Level 3 / Transfers out of Level 2 - Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 / Transfers into Level 2 - Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net fair value of Level 3 transfers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri - derivative commodity contracts:
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 / Transfers into Level 1 - Fuel oils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 / Transfers into Level 2 - Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers into Level 3 / Transfers out of Level 2 - Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 / Transfers into Level 2 - Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net fair value of Level 3 transfers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois - derivative commodity contracts:
Transfers out of Level 3 / Transfers into Level 2 - Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012
2011
$
$
$
$
$
2
(1)
185
-
(3)
183
1
-
15
-
(4)
12
170
$
$
$
$
$
-
(30)
-
-
(1)
(31)
-
(19)
-
(1)
1
(19)
-
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
See Note 11 – Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan
assets as of December 31, 2012, as well as a table summarizing the changes in Level 3 plan assets during 2012. See
Note 17 – Impairment and Other Charges for the fair value hierarchy discussion related to Ameren’s impairment charges.
The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term
nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Ameren’s and Ameren Missouri’s
carrying amounts of investments in debt securities related to the two CTs from the city of Bowling Green and Audrain County
approximate fair value. These investments are classified as held-to-maturity. These investments are considered Level 2 in the
fair value hierarchy as they are valued based on similar market transactions. Short-term borrowings, which are composed of
Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are
considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions.
The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar
issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar
financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at
December 31, 2012 and 2011:
Ameren:(a)(b)
Long-term debt and capital lease obligations (including current portion) . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion) . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Long-term debt (including current portion) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
Long-term debt (including current portion) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012
Carrying Amount
Fair Value
2011
Carrying Amount
Fair Value
$
$
$
$
6,981
142
4,006
80
1,727
62
824
$
$
$
$
7,728
123
4,625
73
2,020
49
618
$
$
$
$
6,856
142
3,950
80
1,658
62
824
$
$
$
$
7,800
92
4,541
55
1,943
37
839
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Preferred stock along with the noncontrolling interest of EEI is recorded in “Noncontrolling Interests” on the balance sheet.
136
NOTE 9 – NUCLEAR DECOMMISSIONING TRUST FUND
INVESTMENTS
and losses resulting from those sales for the years ended
December 31, 2012, 2011, and 2010:
Ameren Missouri has investments in debt and equity
securities that are held in a trust fund for the purpose of
funding the decommissioning of its Callaway energy center.
We have classified these investments as available for sale,
and we have recorded all such investments at their fair
market value at December 31, 2012, and 2011. See
Note 10 – Callaway Energy Center for additional
information.
Investments in the nuclear decommissioning trust
fund have a target allocation of 60% to 70% in equity
securities, with the balance invested in debt securities.
The following table presents proceeds from the sale
and maturities of investments in Ameren Missouri’s nuclear
decommissioning trust fund and the gross realized gains
2012
2011
2010
Proceeds from sales and
maturities . . . . . . . . . . . . . . . . .
Gross realized gains . . . . . . . . . . .
Gross realized losses . . . . . . . . . .
$ 384
6
2
$ 199
5
4
$ 256
5
4
Net realized and unrealized gains and losses are
deferred and recorded as regulatory assets or regulatory
liabilities on Ameren’s and Ameren Missouri’s balance
sheets. This reporting is consistent with the method used to
account for the decommissioning costs recovered in rates.
Gains or losses associated with assets in the trust fund
could result in lower or higher funding requirements for
decommissioning costs, which are expected to be reflected
in electric rates paid by Ameren Missouri’s customers. See
Note 2 – Rate and Regulatory Matters.
The following table presents the costs and fair values of investments in debt and equity securities in Ameren Missouri’s
nuclear decommissioning trust fund at December 31, 2012, and 2011:
Security Type
Cost
Gross Unrealized Gain
Gross Unrealized Loss
Fair Value
2012
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(b)
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(b)
$
$
$
133
145
1
2
281
114
145
3
(1)
$
$
$
8
130
-
-
138
7
101
-
-
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
261
$ 108
$
(a)
11
-
-
$
141
264
1
2
$
11
$ 408
$
(a)
12
-
-
$
12
$ 121
234
3
(1)
$
357
(a) Amount less than $1 million.
(b) Represents payables relating to pending security purchases, net of receivables related to pending security sales and interest receivables.
The following table presents the costs and fair values of investments in debt securities in Ameren Missouri’s nuclear
decommissioning trust fund according to their contractual maturities at December 31, 2012:
Less than 5 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5 years to 10 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Due after 10 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
78
32
23
79
35
27
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
133
$
141
Cost
Fair Value
We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust fund,
recorded as regulatory assets as discussed above. Decommissioning will not occur until the operating license for our nuclear
energy center expires. Ameren Missouri submitted a license extension application to the NRC to extend the Callaway energy
center’s operating license to 2044. The following table presents the fair value and the gross unrealized losses of the available-
for-sale securities held in Ameren Missouri’s nuclear decommissioning trust fund. They are aggregated by investment category
and the length of time that individual securities have been in a continuous unrealized loss position at December 31, 2012:
Less than 12 Months
Gross
Unrealized
Losses
Fair Value
12 Months or Greater
Gross
Unrealized
Losses
Fair Value
Fair Value
Total
Gross
Unrealized
Losses
$
$
(a)
11
11
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
17
7
24
$
$
(a)
1
1
$
$
(a)
14
14
$
$
(a)
10
10
$
$
17
21
38
(a) Amount less than $1 million.
137
NOTE 10 – CALLAWAY ENERGY CENTER
Under the NWPA, the DOE is responsible for disposing
of spent nuclear fuel from the Callaway energy center and
other commercial nuclear energy centers. Under the NWPA,
Ameren and other utilities that own and operate those
energy centers are responsible for paying the disposal
costs. The NWPA established the fee that these utilities pay
the federal government for disposing of the spent nuclear
fuel at one mill, or one-tenth of one cent, for each
kilowatthour generated by those plants and sold. The NWPA
also requires the DOE to review the nuclear waste fee
against the cost of the nuclear waste disposal program and
to propose to the United States Congress any fee
adjustment necessary to offset the costs of the program. As
required by the NWPA, Ameren and other utilities have
entered into standard contracts with the federal
government. The government, represented by the DOE, is
responsible for implementing these provisions of the
NWPA. Consistent with the NWPA and its standard
contract, Ameren Missouri collects one mill from its electric
customers for each kilowatthour of electricity that it
generates and sells from its Callaway energy center.
Although both the NWPA and the standard contract
stated that the federal government would begin to dispose
of spent nuclear fuel by 1998, the federal government has
acknowledged since at least 1994 that it would not meet
that deadline. The federal government is not currently
predicting when it will begin to meet its disposal obligation.
Ameren Missouri has sufficient installed capacity at its
Callaway energy center to store the spent nuclear fuel
generated at Callaway through 2020 and has the capability
for additional storage capacity for spent nuclear fuel
generated through the end of the energy center’s current
licensed life.
Until January 2009, the DOE program provided for
spent nuclear fuel disposal to take place at a geologic
repository to be constructed at Yucca Mountain, Nevada. In
January 2009, the federal government announced that a
repository at Yucca Mountain was unworkable and took
steps to terminate the Yucca Mountain program, while
acknowledging the federal government’s continuing
obligation to dispose of utilities’ spent nuclear fuel. In
January 2012, an advisory commission established by the
DOE issued its report of recommendations for the storage
and disposal of spent nuclear fuel. The recommendations
covered topics such as the approach to siting future nuclear
waste management facilities, the transport and storage of
spent fuel and high-level waste, options for waste disposal,
institutional arrangements for managing spent nuclear fuel
and high-level wastes, and changes needed in the handling
of nuclear waste fees and of the Nuclear Waste Fund.
In January 2013, the DOE issued its plan for the
management and disposal of spent nuclear fuel in response
to the recommendation contained in the advisory
commission’s report. The DOE’s plan calls for a pilot
interim storage facility to begin operation with an initial
focus on accepting spent nuclear fuel from shutdown
reactor sites by 2021. By 2025, a larger interim storage
facility would be available and would be co-located with the
pilot facility. The plan also proposes to site a permanent
geological repository by 2026, to characterize the site and
to design and to license the repository by 2042, and to
begin operation by 2048.
In view of the federal government’s efforts to terminate
the Yucca Mountain program, the Nuclear Energy Institute,
a number of individual utilities, and the National Association
of Regulatory Utility Commissioners sued the DOE in the
United States Court of Appeals for the District of Columbia
Circuit seeking the suspension of the one mill nuclear waste
fee, alleging that the DOE failed to undertake an appropriate
fee adequacy review reflecting the current unsettled state of
the nuclear waste program. In a June 2012 decision, the
court ruled that DOE’s fee adequacy review was legally
inadequate and remanded the matter to the DOE. Although
the court ruled it has the power to direct the DOE to
suspend the fee, the court decided that it was premature to
do so. Instead, the court ordered the DOE to provide within
six months a revised assessment of the amount that should
be collected. On January 19, 2013, the DOE issued the
revised assessment required by the court. The DOE
determined that “neither insufficient nor excess revenues
are being collected” and it proposed no adjustment to the
one mill nuclear waste fee.
The DOE’s delay in carrying out its obligation to
dispose of spent nuclear fuel from the Callaway energy
center is not expected to adversely affect the continued
operation of the energy center.
As a result of DOE’s failure to begin to dispose of the
utilities’ spent nuclear fuel and fulfill its contractual
obligations, Ameren Missouri and other nuclear energy
center owners have also sued the DOE to recover costs
incurred for ongoing storage of their spent fuel. Ameren
Missouri filed a breach of contract lawsuit to recover costs
that it incurred through 2009. This amount included the
cost of reracking the Callaway energy center’s spent fuel
pool, as well as certain NRC fees, and Missouri ad valorem
taxes that Ameren Missouri would not have incurred had
DOE performed its contractual obligations. In June 2011,
the parties reached a settlement that included a payment to
Ameren Missouri of $11 million for spent fuel storage and
related costs through 2010 and, thereafter, annual payment
of such costs after they are incurred through 2013 or any
other mutually agreed extension. As a result of this
settlement agreement, Ameren Missouri recorded a pretax
reduction of $2 million and $2 million to its “Operating
Expenses – Depreciation and amortization” and “Operating
Expenses – Other operations and maintenance” expense
line items, respectively, on its statement of income for the
year ended December 31, 2011. Ameren Missouri reduced
its property and plant net assets by $7 million for the year
ended December 31, 2011. Ameren Missouri received the
2011 cost reimbursement of $1 million and reduced its
property and plant net assets by this amount in 2012. In
March 2013, Ameren Missouri plans to submit
approximately $5 million of 2012 costs to the DOE for
reimbursement under the settlement agreement.
138
In December 2011, Ameren Missouri filed a license
extension application with the NRC to extend its Callaway
energy center’s operating license from 2024 to 2044. There
is no deadline by which the NRC must act on this
application. Among the rules that the NRC has historically
relied upon in approving license extensions are rules
dealing with the storage of spent nuclear fuel at the reactor
site and with the NRC’s confidence that permanent disposal
of spent nuclear fuel will be available when needed. In a
June 2012 decision, the United States Court of Appeals for
the District of Columbia Circuit vacated these rules and
remanded the case to the NRC, holding that the NRC’s
obligations under the National Environmental Policy Act
required a more thorough environmental analysis in support
of the NRC’s waste confidence decision. In June 2012, a
number of groups petitioned the NRC to suspend final
licensing decisions in certain NRC licensing proceedings,
including the Callaway license extension, until the NRC
completed its proceedings on the vacated rules. In
August 2012, the NRC stated that it would not issue
licenses dependent on the vacated rules until it
appropriately addressed the court’s remand. In September
2012, the NRC directed its staff to issue, within two years, a
generic environmental impact statement and a final rule to
address the court’s ruling. The NRC also stated that a site-
specific analysis of these issues could be conducted in rare
circumstances. If the Callaway energy center’s license is
extended, additional spent fuel storage will be required.
Ameren Missouri plans to install a dry spent fuel storage
facility at its Callaway energy center and intends to begin
transferring spent fuel assemblies to this facility by 2016.
Electric utility rates charged to customers provide for
the recovery of the Callaway energy center’s
decommissioning costs, which include decontamination,
dismantling, and site restoration costs, over an assumed
40-year life of the nuclear center, ending with the expiration
of the energy center’s current operating license in 2024. It
is assumed that the Callaway energy center site will be
decommissioned through the immediate dismantlement
method and removed from service. Ameren and Ameren
Missouri have recorded an ARO for the Callaway energy
center decommissioning costs at fair value, which
represents the present value of estimated future cash
outflows. Decommissioning costs are included in the costs
of service used to establish electric rates for Ameren
Missouri’s customers. These costs amounted to $7 million
in each of the years 2012, 2011, and 2010. Every three
years, the MoPSC requires Ameren Missouri to file an
updated cost study and funding analysis for
decommissioning its Callaway energy center. Electric rates
may be adjusted at such times to reflect changed estimates.
The last cost study and funding analysis were filed with the
MoPSC in September 2011. In October 2012, the MoPSC
issued an order approving the stipulation and agreement
between Ameren Missouri and the MoPSC staff that
maintained the current rate of deposits to the trust fund and
the rate of return assumptions used in the analysis. If
Ameren Missouri’s operating license extension application
is approved by the NRC, a revised funding analysis will be
prepared and the rates charged to customers will be
adjusted accordingly to reflect the operating license
extension at the time the next triennial cost study and
funding analysis is approved by the MoPSC. Amounts
collected from customers are deposited in an external trust
fund to provide for the Callaway energy center’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 Ameren
Missouri’s Callaway energy center is reported as “Nuclear
decommissioning trust fund” in Ameren’s and Ameren
Missouri’s balance sheets. This amount is legally restricted
and may be used only to fund the costs of nuclear
decommissioning. Changes in the fair value of the trust
fund are recorded as an increase or decrease to the nuclear
decommissioning trust fund, with an offsetting adjustment
to the related regulatory liability.
See Note 2 – Rate and Regulatory Matters for
additional information related to the Callaway energy center.
NOTE 11 – RETIREMENT BENEFITS
The primary objective of the Ameren pension and
postretirement benefit plans is to provide eligible employees
with pension and postretirement health care and life
insurance benefits. Ameren offers defined benefit pension
and postretirement benefit plans covering substantially all
of its employees. Ameren uses a measurement date of
December 31 for its pension and postretirement benefit
plans. Ameren Missouri and Ameren Illinois each participate
in Ameren’s single-employer pension and other
postretirement plans. Ameren’s qualified pension plan is the
Ameren Retirement Plan. Ameren also has an unfunded
non-qualified pension plan, the Ameren Supplemental
Retirement Plan, which is available for certain management
employees and retirees to provide a supplemental benefit
when their qualified pension plan benefits are reduced to
comply with Internal Revenue Code limitations. Ameren’s
other postretirement plans are the Ameren Retiree Medical
Plan and the Ameren Group Life Insurance Plan. Separately,
EEI employees and retirees participate in EEI’s single-
employer pension and other postretirement plans. EEI’s
pension plan is the Revised Retirement Plan for Employees
of Electric Energy, Inc. EEI’s other postretirement plans are
the Group Insurance Plan for Management Employees of
Electric Energy, Inc. and the Group Insurance Plan for
Bargaining Unit Employees of Electric Energy, Inc.
Nonaffiliated Ameren companies do not participate in the
Ameren Retirement Plan, the Ameren Supplemental
Retirement Plan, the Ameren Retiree Medical Plan, and the
Ameren Group Life Insurance Plan. Ameren consolidates
EEI, and therefore, EEI’s plans are reflected in Ameren’s
pension and postretirement balances and disclosures.
The Group Insurance Plan for Bargaining Unit
Employees of Electric Energy, Inc. was over-funded by
$14 million as of December 31, 2012, which was included
139
in Ameren’s balance sheet in “Other assets.” The following
table presents the benefit liability recorded on the balance
sheets of each of the Ameren Companies as of
December 31, 2012:
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,183
464
408
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
Ameren recognizes the under-funded status of its pension and postretirement plans as a liability on its balance sheet, with
offsetting entries to accumulated OCI and regulatory assets, in accordance with authoritative accounting guidance. The
following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2012, and
2011. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 2012, and 2011, that
have not been recognized in net periodic benefit costs.
2012
2011
Pension Benefits(a)
Postretirement
Benefits(a)
Pension Benefits(a)
Postretirement
Benefits(a)
Accumulated benefit obligation at end of year
. . . . . . . . . . . . . . .
Change in benefit obligation:
Net benefit obligation at beginning of year . . . . . . . . . . . . . . . .
Service cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan amendments(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Participant contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Curtailments(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Early retiree reinsurance program receipt . . . . . . . . . . . . . . . . .
Federal subsidy on benefits paid . . . . . . . . . . . . . . . . . . . . . . . .
Net benefit obligation at end of year . . . . . . . . . . . . . . . . . . . . . . .
Change in plan assets:
Fair value of plan assets at beginning of year . . . . . . . . . . . . . .
Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal subsidy on benefits paid . . . . . . . . . . . . . . . . . . . . . . . .
Early retiree reinsurance program receipt . . . . . . . . . . . . . . . . .
Participant contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of plan assets at end of year . . . . . . . . . . . . . . . . . . . . .
Funded status – deficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued benefit cost at December 31 . . . . . . . . . . . . . . . . . . . . . .
Amounts recognized in the balance sheet consist of:
Noncurrent asset
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net liability recognized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amounts recognized in regulatory assets consist of:
Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost (credit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amounts (pretax) recognized in accumulated OCI consist of:
Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost (credit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
3,929
3,865
83
170
(6)
-
246
2
(209)
(b)
(b)
4,151
2,876
392
134
(b)
(b)
-
(209)
3,193
958
958
-
3
955
958
699
(6)
-
89
(17)
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
765
$
$
$
$
$
$
$
(b)
1,257
24
52
(75)
16
5
(1)
(73)
2
4
1,211
896
110
45
4
2
16
(73)
1,000
211
211
(14)
2
223
211
103
(24)
-
51
(65)
65
$
$
$
$
$
$
3,645
3,451
75
180
(16)
-
348
-
(173)
(b)
(b)
3,865
2,722
224
103
(b)
(b)
-
(173)
2,876
989
989
-
3
986
989
734
(7)
-
79
(15)
$
$
$
$
$
$
(b)
1,120
22
58
-
18
96
-
(66)
3
6
1,257
797
9
129
6
3
18
(66)
896
361
361
-
3
358
361
177
(28)
2
43
(7)
$
791
$
187
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Not applicable.
(c)
In 2012, EEI’s pension plan was amended to adjust the calculation of the future benefit obligation for all of its active employees from a
traditional, final pay formula to a cash balance formula. Additionally, in 2012, EEI’s management and labor union postretirement medical benefit
plans were amended to adjust for moving to a Medicare Advantage plan.
140
(d)
In 2011, Ameren’s pension plan was amended to adjust the calculation of the future benefit obligation of approximately 430 labor union-
represented employees from a traditional, final pay formula to a cash balance formula.
(e) EEI implemented an employee reduction program in 2012, which resulted in a curtailment of EEI’s pension and management postretirement
benefit plans.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2012, and 2011:
Discount rate at measurement date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in future compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medical cost trend rate (initial) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medical cost trend rate (ultimate)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Years to ultimate rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension Benefits
Postretirement Benefits
2012
4.00%
3.50
-
-
-
2011
4.50%
3.50
-
-
-
2012
4.00%
3.50
5.00
5.00
-
2011
4.50%
3.50
5.50
5.00
1 year
Ameren determines discount rate assumptions by
identifying a theoretical settlement portfolio of high-quality
corporate bonds sufficient to provide for a plan’s projected
benefit payments, pursuant to authoritative accounting
guidance on the determination of discount rates used for
defined benefit plan obligations. The settlement portfolio of
bonds is selected from a pool of over 600 high-quality
corporate bonds. A single discount rate is then determined that
results in a discounted value of the plan’s benefit payments that
equates to the market value of the selected bonds.
Funding
Pension benefits are based on the employees’ years of
service and compensation. Ameren’s pension plan is funded
in compliance with income tax regulations and federal
funding or regulatory requirements. As a result, Ameren
expects to fund its pension plan at a level equal to the
greater of the pension expense or the legally required
minimum contribution. Considering Ameren’s assumptions
at December 31, 2012, its investment performance in 2012,
and its pension funding policy, Ameren expects to make
annual contributions of $60 million to $150 million in each
of the next five years, with aggregate estimated
contributions of $550 million. We expect Ameren Missouri’s
and Ameren Illinois’ portion of the future funding
requirements to be 50%, and 40%, respectively. These
amounts are estimates. The estimates may change based
on actual investment performance, changes in interest
rates, changes in our assumptions, any pertinent changes
in government regulations, and any voluntary contributions.
Our funding policy for postretirement benefits is primarily
to fund the Voluntary Employee Beneficiary Association
(VEBA) trusts to match the annual postretirement expense.
The following table presents the cash contributions
made to our defined benefit retirement plan and to our
postretirement plans during 2012, 2011, and 2010:
Investment Strategy and Policies
Ameren manages plan assets in accordance with the
“prudent investor” guidelines contained in ERISA. The
investment committee, to the extent authority is delegated
to it by the finance committee of Ameren’s board of
directors, implements investment strategy and asset
allocation guidelines for the plan assets. The investment
committee includes members of senior management. The
investment committee’s goals are twofold: first, to ensure
that sufficient funds are available to provide the benefits at
the time they are payable and second, to maximize total
return on plan assets and minimize expense volatility
consistent with its tolerance for risk. Ameren delegates
investment management to specialists in each asset class.
As appropriate, Ameren provides the investment manager
with guidelines that specify allowable and prohibited
investment types. The investment committee regularly
monitors manager performance and compliance with
investment guidelines.
The expected return on plan assets assumption is
based on historical and projected rates of return for current
and planned asset classes in the investment portfolio.
Projected rates of return for each asset class were
estimated after an analysis of historical experience, future
expectations, and the volatility of the various asset classes.
After considering the target asset allocation for each asset
class, we adjusted the overall expected rate of return for the
portfolio for historical and expected experience of active
portfolio management results compared with benchmark
returns and for the effect of expenses paid from plan assets.
Ameren will utilize an expected return on plan assets for its
pension plan assets and postretirement plan assets of
7.50% and 7.25%, respectively, in 2013. No plan assets are
expected to be returned to Ameren during 2013.
Pension Benefits
2011
2010
2012
AMO . . . . $
AIC . . . . .
. . .
Other
52 $
46
36
43 $
28
32
Ameren(a)
134
103
36
23
22
81
Postretirement Benefits
2010
2011
2012
$
9 $
35
1
45
9 $
118
2
129
11
20
5
36
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
141
Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant
concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it creates
diversification through investments in assets that differ by type (equity, debt, real estate, private equity), duration, market
capitalization, country, style (growth or value) and industry, among other factors. The diversification of assets is displayed in
the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the
diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is
still subject to overall market risk. The following table presents our target allocations for 2013 and our pension and
postretirement plans’ asset categories as of December 31, 2012, and 2011:
Asset
Category
Target Allocation
2013
Pension Plan:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities:
U.S. large capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. small and mid-capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International and emerging markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Private equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Postretirement Plans:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities:
U.S. large capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. small and mid-capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International
Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0 - 5 %
29 - 39
2 - 12
9 - 19
50 - 60
35 - 45
0 - 9
0 - 4
0 - 10 %
33 - 43
3 - 13
10 - 20
55 - 65
30 - 40
Percentage of Plan Assets at December 31,
2012
2%
34
7
13
54
39
4
1
100%
4%
40%
8%
14%
62%
34%
100%
2011
2%
33%
7%
11%
51%
42%
4%
1%
100%
4%
38%
8%
13%
59%
37%
100%
In general, the United States large capitalization equity investments are passively managed or indexed, whereas the
international, emerging markets, United States small capitalization, and United States mid-capitalization equity investments are
actively managed by investment managers. Debt securities include a broad range of fixed income vehicles. Debt security
investments in high-yield securities, emerging market securities, and non-United States dollar-denominated securities are
owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active
management by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not,
by policy, hold direct investments in real estate property. Ameren’s investment in private equity funds consists of 10 different
limited partnerships, with invested capital ranging from $0.1 million to $5 million each, which invest primarily in a diversified
number of small United States-based companies. No further commitments may be made to private equity investments without
approval by the finance committee of the board of directors. Additionally, Ameren’s investment committee allows investment
managers to use derivatives, such as index futures, exchange traded funds, foreign exchange futures, and options, in certain
situations, to increase or to reduce market exposure in an efficient and timely manner.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2012. The fair
value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the
measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus
accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature
of these instruments. Investments traded in active markets on national or international securities exchanges are valued at
closing prices on the last business day on or before the measurement date. Securities traded in over-the-counter markets are
valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of
price transparency. Derivative contracts are valued at fair value, as determined by the investment managers (or independent
third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange
quotations on underlying instruments, dealer quotations, and other market information. The fair value of real estate is based
on annual appraisal reports prepared by an independent real estate appraiser.
142
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the
pension plan assets measured at fair value as of December 31, 2012:
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant Other
Unobservable
Inputs
(Level 3)
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities:
U.S. large capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. small and mid-capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . .
International and emerging markets . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities:
Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. treasury and agency securities . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Private equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1
$
30
$
83
235
134
-
-
-
-
-
-
-
(1)
1,028
12
306
832
177
250
42
-
-
-
-
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
452
$
2,677
$
Less: Medical benefit assets at December 31(a)
. . . . . . . . . . . . . . . . . .
Plus: Net receivables at December 31(b)
. . . . . . . . . . . . . . . . . . . . . . . .
Fair value of pension plans assets at year end . . . . . . . . . . . . . . . . . . .
-
-
-
-
-
-
-
-
118
19
-
-
137
Total
$
31
1,111
247
440
832
177
250
42
118
19
-
(1)
$
3,266
(102)
29
$
3,193
(a) Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code
(401(h) accounts) to fund a portion of the postretirement obligation.
(b) Receivables related to pending security sales, offset by payables related to pending security purchases.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the
pension plan assets measured at fair value as of December 31, 2011:
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant Other
Unobservable
Inputs
(Level 3)
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities:
U.S. large capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. small and mid-capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . .
International and emerging markets . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities:
Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. treasury and agency securities . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Private equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
$
31
$
72
202
115
-
-
-
-
-
-
1
(1)
922
11
213
794
176
230
47
-
-
-
-
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
389
$
2,424
$
Less: Medical benefit assets at December 31(a)
. . . . . . . . . . . . . . . . . .
Plus: Net receivables at December 31(b)
. . . . . . . . . . . . . . . . . . . . . . . .
Fair value of pension plans assets at year end . . . . . . . . . . . . . . . . . . .
-
-
-
-
-
-
-
-
108
23
-
-
131
Total
$
31
994
213
328
794
176
230
47
108
23
1
(1)
$
2,944
(91)
23
$
2,876
(a) Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code
(401(h) accounts) to fund a portion of the postretirement obligation.
(b) Receivables related to pending security sales, offset by payables related to pending security purchases.
143
The following table summarizes the changes in the fair value of the pension plan assets classified as Level 3 in the fair
value hierarchy for each of the years ended December 31, 2012, and 2011:
Beginning
Balance at
January 1,
Actual Return on
Plan Assets Related
to Assets Still Held
at the Reporting Date
Actual Return on
Plan Assets Related
to Assets Sold
During the Period
Purchases,
Sales, and
Settlements, net
Net
Transfers
into (out of)
of Level 3
Ending Balance at
December 31,
2012:
Real estate . . . . . . . . . . .
Private equity . . . . . . . . .
2011:
Real estate . . . . . . . . . . .
Private equity . . . . . . . . .
$ 108
23
$
98
28
$
$
7
(7)
10
(10)
$
-
8
$
-
11
$
$
3
(5)
-
(6)
$
$
-
-
-
-
$
$
118
19
108
23
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the
postretirement benefit plans assets measured at fair value as of December 31, 2012:
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant Other
Unobservable
Inputs
(Level 3)
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities:
U.S. large capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. small and mid-capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities:
Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. treasury and agency securities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset-backed securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
83
$
277
66
51
-
-
-
-
-
$
1
88
-
69
94
97
78
18
22
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
477
$
467
$
-
-
-
-
-
-
-
-
-
-
Plus: Medical benefit assets at December 31(a) . . . . . . . . . . . . . . . . . . . . .
Less: Net payables at December 31(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of postretirement benefit plans assets at year end . . . . . . . . . .
Total
$
84
365
66
120
94
97
78
18
22
$ 944
102
(46)
$1,000
(a) Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are
included in the pension plan assets shown above.
(b) Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the
postretirement benefit plans assets measured at fair value as of December 31, 2011:
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant Other
Unobservable
Inputs
(Level 3)
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities:
U.S. large capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. small and mid-capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities:
Corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. treasury and agency securities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset-backed securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1
$
235
57
44
-
-
-
-
-
$
66
78
-
56
75
86
82
23
35
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
337
$
501
$
-
-
-
-
-
-
-
-
-
-
Plus: Medical benefit assets at December 31(a)
. . . . . . . . . . . . . . . . . . . .
Less: Net payables at December 31(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of postretirement benefit plans assets at year end . . . . . . . . . .
Total
$
67
313
57
100
75
86
82
23
35
$
838
91
(33)
$
896
(a) Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are
included in the pension plan assets shown above.
(b) Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.
144
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost of our pension and postretirement benefit
plans during 2012, 2011, and 2010:
Pension Benefits
Postretirement Benefits
Ameren(a)
Ameren(a)
2012
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of:
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Curtailment loss(b)
$
83
170
(213)
-
(3)
77
2
$ 24
52
(60)
2
(8)
9
-
Net periodic benefit cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
116
$ 19
2011
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of:
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net periodic benefit cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of:
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net periodic benefit cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
75
180
(216)
-
(1)
42
80
68
185
(212)
-
6
18
65
$
$
$
$ 22
58
(54)
2
(8)
5
$ 25
$ 20
62
(56)
2
(8)
1
$ 21
(a)
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Includes EEI’s pension and management postretirement benefit plans’ curtailment loss of $2 million recognized in 2012 as a result of its
employee reduction program.
The current year expected return on plan assets is determined primarily by adjusting the prior-year market-related
asset value for current year contributions, disbursements, and expected return, plus 25% of the actual return in excess
of (or less than) expected return for the four prior years.
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit
cost in 2013 are as follows:
Pension Benefits
Postretirement Benefits
Ameren(a)
Ameren(a)
Regulatory assets:
Prior service cost (credit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated OCI:
Prior service cost (credit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(1)
97
(2)
7
$
(4)
19
(9)
5
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
101
$ 11
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting
under the plan amendment. The net actuarial loss subject to amortization is amortized on a straight-line basis over 10 years.
145
The Ameren Companies are responsible for their share of the pension and postretirement benefit costs. The following
table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31, 2012, 2011,
and 2010:
Pension Costs
Postretirement Costs
2012
2011
2010
2012
2011
2010
Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren(a)(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
63
37
16
116
$
51
16
13
80
$
42
10
13
65
$
10
4
5
19
$
11
11
3
25
$
11
7
3
21
(a)
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Includes EEI’s pension and management postretirement benefit plans’ curtailment loss of $2 million recognized in 2012 as a result of its
employee reduction program.
The expected pension and postretirement benefit payments from qualified trust and company funds and the federal
subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, as of
December 31, 2012, are as follows:
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 - 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension Benefits
Postretirement Benefits
Paid from
Qualified
Trust
$
235
243
247
253
255
1,317
Paid from
Company
Funds
Paid from
Qualified
Trust
Paid from
Company
Funds
Federal
Subsidy
$
3
3
3
3
3
13
$
60
62
65
68
71
398
$
2
2
2
2
2
11
$
3
3
3
4
4
19
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, 2012, 2011, and 2010:
Pension Benefits
Postretirement Benefits
2012
2011
2010
2012
2011
2010
Discount rate at measurement date . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in future compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medical cost trend rate (initial) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medical cost trend rate (ultimate) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Years to ultimate rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.50%
7.75
3.50
-
-
-
5.25%
8.00
3.50
-
-
-
5.75%
8.00
3.50
-
-
-
4.50%
7.50
3.50
5.50
5.00
1 year
5.25%
7.75
3.50
6.00
5.00
2 years
5.75%
8.00
3.50
6.50
5.00
3 years
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
Pension Benefits
Postretirement Benefits
Service Cost
and Interest
Cost
Projected
Benefit
Obligation
Service Cost
and Interest
Cost
Postretirement
Benefit
Obligation
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 . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
(2)
2
-
-
$
124
13
-
-
$
-
-
1
-
36
-
40
(38)
146
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees at
December 31, 2012. The plan allowed employees to contribute a portion of their compensation in accordance with specific
guidelines. Ameren matched a percentage of the employee contributions up to certain limits. The following table presents the
portion of the matching contribution to the Ameren 401(k) plan attributable to each of the Ameren Companies for the years
ended December 31, 2012, 2011, and 2010:
Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012
2011
2010
$
16
9
4
29
$
16
8
4
28
16
8
3
27
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
NOTE 12 – STOCK-BASED COMPENSATION
Ameren’s long-term incentive plan is available to for eligible employees, under Ameren’s shareholder-approved 2006
Omnibus Incentive Compensation Plan (2006 Plan), which became 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. 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 at December 31, 2012, and changes during the year ended December 31, 2012, under
the 2006 Plan are presented below:
Performance Share Units
Nonvested at January 1, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unearned or forfeited(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Earned and vested(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share
Units
1,156,831
717,151
(477,928)
(203,567)
Nonvested at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,192,487
Weighted-average
Fair Value per Unit
$ 31.70
35.68
32.04
34.01
$
33.56
(a)
(b)
(c)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January
2012 under the 2006 Plan.
Includes share units granted in 2010 that were not earned based on performance provisions of the award grants.
Includes share units granted in 2010 that vested as of December 31, 2012, that were earned pursuant to the provisions of the award grants.
Also includes share units that vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-
eligible employees will vary depending on actual performance over the three-year measurement period.
Ameren recorded compensation expense of $24 million,
$14 million, and $13 million for the years ended
December 31, 2012, 2011, and 2010, respectively, and a
related tax benefit of $9 million, $5 million and $5 million for
the years ended December 31, 2012, 2011, and 2010,
respectively. Ameren settled performance share units and
restricted shares of $11 million, $4 million, and $2 million for
the years ended December 31, 2012, 2011, and 2010. All
outstanding restricted shares vested as of the end of 2011.
There were no significant compensation costs capitalized
related to the performance share units during the years ended
December 31, 2012, 2011, and 2010. As of December 31,
2012, total compensation cost of $21 million related to
nonvested awards not yet recognized is expected to be
recognized over a weighted-average period of 20 months.
Performance Share Units
Performance share units have been granted under the
2006 Plan. A share unit vests and entitles an employee to
receive shares of Ameren common stock (plus accumulated
dividends) if, at the end of the three-year performance
period, certain specified performance or market conditions
have been met and the individual remains employed by
Ameren. The exact number of shares issued pursuant to a
share unit varies from 0% to 200% of the target award,
depending on actual company performance relative to the
performance goals.
The fair value of each share unit awarded in January
2012 under the 2006 Plan was determined to be $35.68.
That amount was based on Ameren’s closing common
share price of $33.13 at December 31, 2011, and lattice
simulations. Lattice simulations are used to estimate
expected share payout based on Ameren’s total shareholder
return for a three-year performance period relative to the
designated peer group beginning January 1, 2012. The
simulations can produce a greater fair value for the share
unit than the applicable closing common share price
because they include the weighted payout scenarios in
which an increase in the share price has occurred. The
significant assumptions used to calculate fair value also
included a three-year risk-free rate of 0.41%, volatility of
17% to 31% for the peer group, and Ameren’s attainment
of a three-year average earnings per share threshold during
the performance period.
147
The fair value of each share unit awarded in January
2011 under the 2006 Plan was determined to be $31.41.
That amount was based on Ameren’s closing common
share price of $28.19 at December 31, 2010, and lattice
simulations. Lattice simulations are used to estimate
expected share payout based on Ameren’s total shareholder
return for a three-year performance period relative to the
designated peer group beginning January 1, 2011. The
simulations can produce a greater fair value for the share
NOTE 13 – INCOME TAXES
unit than the closing common share price because they
include the weighted payout scenarios in which an increase
in the share price has occurred. The significant
assumptions used to calculate fair value also included a
three-year risk-free rate of 1.08%, volatility of 22% to 36%
for the peer group, and Ameren’s attainment of three-year
average earnings per share threshold during the
performance period.
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, 2012, 2011, and 2010:
Ameren
Ameren Missouri
Ameren Illinois
2012
Statutory federal income tax rate:
Increases (decreases) from:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35%
Depreciation differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of investment tax credit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserve for uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011
Statutory federal income tax rate:
Increases (decreases) from:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of investment tax credit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other permanent items(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010
Statutory federal income tax rate:
Increases (decreases) from:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-deductible impairment of goodwill
Depreciation differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of investment tax credit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserve for uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in federal tax law(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
1
5
-
41%
35%
(1)
(1)
4
-
37%
35%
32
(4)
(2)
8
(1)
(3)
3
35%
(1)
(1)
3
1
37%
35%
(2)
(1)
3
1
36%
35%
-
(3)
(1)
3
-
-
1
35%
-
(1)
6
-
40%
35%
-
(1)
5
-
39%
35%
-
-
(1)
5
-
-
-
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
68%
35%
39%
(a) Permanent items are treated differently for book and tax purposes and primarily include nondeductible expenses related to lobbying and stock
issuance expenses for Ameren Missouri.
(b) Relates to change in taxation of prescription drug benefits to retiree participants from the enactment in 2010 of the Patient Protection and
Affordable Care Act and the Health Care and Education Reconciliation Act of 2010.
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2012,
2011, and 2010:
2012
Current taxes:
Ameren(a)
Ameren Missouri Ameren Illinois
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits, amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax expense (benefit)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
31
3
(590)
(117)
(7)
(680)
$
$
(25) $
(10)
248
44
(5)
252
$
(7)
(3)
76
30
(2)
94
148
2011
Current taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits, amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2010
Current taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits, amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Ameren(a)
Ameren Missouri Ameren Illinois
(27)
(5)
273
76
(7)
310
13
10
274
36
(8)
325
$
$
$
$
3 $
2
129
31
(4)
161 $
(14) $
(15)
206
27
(5)
199 $
(24)
(4)
123
34
(2)
127
(20)
(5)
132
32
(2)
137
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The Illinois corporate income tax rate increased from 7.3% to 9.5%, starting in January 2011. The tax rate is scheduled to
decrease to 7.75% in 2015, and it is scheduled to return to 7.3% in 2025. This corporate income tax rate increase in Illinois
increased current income tax expense in 2011 by $6 million and $4 million for Ameren and Ameren Illinois, respectively. As a
result of this corporate income tax rate increase, accumulated deferred tax balances were revalued, resulting in a decrease in
deferred tax expense of $2 million and $3 million for Ameren and Ameren Illinois, respectively, in 2011.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary
differences at December 31, 2012, and 2011:
Ameren(a)
Ameren Missouri
Ameren Illinois
2012
Accumulated deferred income taxes, net liability (asset):
Plant related . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-lived asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred intercompany tax gain/basis step-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred employee benefit costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchase accounting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ARO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(b)
$
Total net accumulated deferred income tax liabilities(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2011
Accumulated deferred income taxes, net liability (asset):
Plant related . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-lived asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred intercompany tax gain/basis step-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred employee benefit costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchase accounting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ARO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total net accumulated deferred income tax liabilities(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
4,201
(986)
2
73
(337)
(10)
(44)
(278)
2,621
3,826
(15)
3
73
(367)
35
(37)
(223)
3,295
$
$
$
$
2,386
-
(1)
73
(84)
-
(7)
50
2,417
2,134
-
(1)
73
(88)
-
-
6
2,124
$
$
$
$
1,106
-
39
-
(102)
(27)
1
(77)
940
1,003
-
55
-
(109)
(27)
1
(86)
837
(a)
(b)
(c)
(d)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below.
Includes $26 million recorded in “Other current assets” on Ameren Missouri’s balance sheet as of December 31, 2012.
Includes $8 million recorded in “Other current assets” on Ameren Missouri’s balance sheet as of December 31, 2011.
149
The following table presents the components of deferred tax assets relating to net operating loss carryforwards and tax
credit carryforwards at December 31, 2012:
Net operating loss carryforwards:
Federal(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State(b)
Total net operating loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax credit carryforwards:
Federal(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State(d)
State valuation allowance(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren
$
$
$
212
29
241
87
35
(4)
Total tax credit carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
118
Ameren
Missouri
Ameren
Illinois
$
$
$
$
61
3
64
11
1
(1)
11
$
$
$
$
61
11
72
-
1
(1)
-
(a) These will begin to expire in 2028.
(b) These will begin to expire in 2017.
(c) These will begin to expire in 2029.
(d) These will begin to expire in 2013.
(e) This balance increased by $2 million, $- million and $1 million for Ameren, Ameren Missouri and Ameren Illinois respectively during 2012.
Uncertain Tax Positions
A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31, 2010, 2011,
and 2012, is as follows:
Ameren
Ameren
Missouri
Ameren
Illinois
Unrecognized tax benefits – January 1, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increases based on tax positions prior to 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decreases based on tax positions prior to 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increases based on tax positions related to 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes related to settlements with taxing authorities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decreases related to the lapse of statute of limitations . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized tax benefits – December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increases based on tax positions prior to 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decreases based on tax positions prior to 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increases based on tax positions related to 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes related to settlements with taxing authorities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decreases related to the lapse of statute of limitations . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized tax benefits – December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increases based on tax positions prior to 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decreases based on tax positions prior to 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increases based on tax positions related to 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes related to settlements with taxing authorities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decreases related to the lapse of statute of limitations . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
135
72
(38)
77
-
-
246
22
(125)
17
(10)
(2)
148
5
(13)
17
-
(1)
Unrecognized tax benefits – December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
156
Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of
December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective
tax rates as of December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
-
1
1
$
$
$
$
$
$
$
88
40
(12)
48
-
-
164
15
(63)
13
(5)
-
124
4
(7)
15
-
-
136
3
1
3
$
$
$
$
$
$
$
-
27
(2)
31
-
-
56
-
(41)
-
(4)
-
11
-
(1)
3
-
-
13
-
-
(1)
The Ameren Companies recognize interest charges (income) and penalties accrued on tax liabilities on a pretax basis as
interest charges (income) or miscellaneous expense, respectively, in the statements of income.
150
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended
December 31, 2010, 2011, and 2012, is as follows:
Ameren
Ameren
Missouri
Ameren
Illinois
Liability for interest – January 1, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges for 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liability for interest – December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income for 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payment
Liability for interest – December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges for 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liability for interest – December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
8
9
17
(11)
(1)
5
1
6
$
$
$
$
4
6
10
(3)
(1)
6
2
8
$
$
$
$
-
2
2
(1)
-
1
-
1
As of December 31, 2010, 2011, and 2012, the Ameren Companies have accrued no amount for penalties with respect to
unrecognized tax benefits.
In 2011, a final settlement for the years 2005 and 2006 was reached with the Internal Revenue Service. It resulted in a
reduction in uncertain tax liabilities of $39 million, $17 million and $12 million for Ameren, Ameren Missouri and Ameren
Illinois, respectively. Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the
Internal Revenue Service. Ameren’s federal income tax return for the year 2011 is currently under examination.
It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the
next twelve months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for
capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in
uncertain tax benefits of approximately $143 million, $119 million, and $13 million for Ameren, Ameren Missouri and Ameren
Illinois, respectively. In addition. it is reasonably possible that other events will occur during the next 12 months that would
cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren
Companies do not believe any such increases or decreases, including the decrease from the reasonably possible IRS Appeals
Office settlement discussed above, would be material to their results of operations, financial position, or liquidity.
State income tax returns are generally subject to examination for a period of three years after filing of the return. The state
impact of any federal changes remains subject to examination by various states for a period of up to one year after formal
notification to the states. The Ameren Companies do not currently have material state income tax issues under examination,
administrative appeals, or litigation.
NOTE 14 – RELATED PARTY TRANSACTIONS
The Ameren Companies have engaged in, and may in
the future engage in, affiliate transactions in the normal
course of business. These transactions primarily consist of
natural 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.
Put Option Agreement and Guarantee
On March 28, 2012, Genco entered into a put option
agreement with AERG. The put option gives Genco the
option to sell to AERG all, but not less than all, of the Grand
Tower, the Gibson City, and the Elgin gas-fired energy
centers. If Genco exercises the put option, the purchase
price for all three energy centers will be the greater of
$100 million or the fair market value of the energy centers,
as determined by three third-party appraisers in accordance
with the terms of the agreement. Upon exercise of the put
option, the $100 million minimum purchase price would be
payable to Genco within one business day. Genco may
exercise the put option at any time through March 28, 2014.
The put option may be extended indefinitely for additional
one-year periods by agreement of AERG and Genco. If
Genco exercises the put option, the closing of the sale of all
three energy centers will be subject to the receipt of all
necessary regulatory approvals. In exchange for entering
into the put option agreement, Genco paid AERG a put
option premium of $2.5 million.
The put option agreement requires AERG to secure and
maintain an Ameren guarantee of payment of contingent
obligations under the agreement. Ameren and AERG
entered into such a guarantee agreement on
March 28, 2012. The guarantee shall remain in effect until
either AERG or Ameren satisfies all of the payment
obligations under the put option agreement, or until the put
option agreement is terminated and no further payments
are owed by AERG to Genco. As of December 31, 2012,
Genco had not exercised the put option. Ameren and AERG
do not expect to extend the put option agreement beyond
March 28, 2014.
151
Electric Power Supply Agreements
Capacity Supply Agreements
Ameren Illinois, as an electric load-serving entity, must
acquire capacity sufficient to meet its obligations to
customers.
In 2009, Ameren Illinois used a RFP process,
administered by the IPA, to contract capacity for the period
from June 1, 2009, through May 31, 2012. Both Marketing
Company and Ameren Missouri were among the winning
suppliers in the capacity RFP process. In April 2009,
Marketing Company contracted to supply a portion of
Ameren Illinois’ capacity requirements to Ameren Illinois for
$4 million, $9 million, and $8 million for the 12 months
ending May 31, 2010, 2011, and 2012, respectively. In April
2009, Ameren Missouri contracted to supply a portion of
Ameren Illinois’ capacity requirements to Ameren Illinois for
$2 million, $2 million, and $1 million for the 12 months
ending May 31, 2010, 2011, and 2012, respectively.
In 2010, Ameren Illinois used a RFP process,
administered by the IPA, to contract capacity for the period
from June 1, 2010, through May 31, 2013. Both Marketing
Company and Ameren Missouri were among the winning
suppliers in the capacity RFP process. In April 2010,
Marketing Company contracted to supply a portion of
Ameren Illinois’ capacity requirements to Ameren Illinois for
$1 million, $2 million, and $3 million for the 12 months
ending May 31, 2011, 2012, and 2013, respectively. In April
2010, Ameren Missouri contracted to supply a portion of
Ameren Illinois’ capacity requirements to Ameren Illinois for
less than $1 million for the period from June 1, 2010,
through May 31, 2013.
During 2012, Ameren Illinois used a RFP process,
administered by the IPA, to contract capacity for the period
from June 1, 2012, through May 31, 2015. Both Marketing
Company and Ameren Missouri were among the winning
suppliers in the capacity RFP process. In April 2012,
Marketing Company contracted to supply a portion of
Ameren Illinois’ capacity requirements for less than
$1 million and $4 million for the 12 months ending May 31,
2013 and 2015, respectively. In April 2012, Ameren
Missouri contracted to supply a portion of Ameren Illinois’
capacity requirements for $1 million and $3 million for the
12 months ending May 31, 2014 and 2015, respectively.
Energy Swaps and Energy Products
Ameren Illinois, as an electric load-serving entity, must
acquire energy sufficient to meet its obligations to
customers.
In 2009, Ameren Illinois used a RFP process,
administered by the IPA, to procure financial energy swaps
from June 1, 2009, through May 31, 2011. Marketing
Company was a winning supplier in the financial energy
swap RFP process. In May 2009, Marketing Company
entered into financial instruments that fixed the price that
Ameren Illinois paid for approximately 80,000
megawatthours at approximately $48 per megawatthour
during the 12 months ending May 31, 2010 and for
approximately 89,000 megawatthours at approximately
$48 per megawatthour during the 12 months ending
May 31, 2011.
In 2010, Ameren Illinois used a RFP process,
administered by the IPA, to procure financial energy swaps
for the period from June 1, 2010, through May 31, 2013.
Marketing Company was a winning supplier in the financial
energy swap RFP process. In May 2010, Marketing
Company entered into financial instruments that fixed the
price that Ameren Illinois paid for approximately 924,000
megawatthours at approximately $33 per megawatthour
during the 12 months ending May 31, 2011 and for
approximately 296,000 megawatthours at approximately
$40 per megawatthour during the 12 months ending
May 31, 2012.
In 2011, Ameren Illinois used a RFP process
administered by the IPA to procure energy products that
will settle physically from June 1, 2011, through May 31,
2014. Marketing Company and Ameren Missouri were
winning suppliers in Ameren Illinois’ energy product RFP
process. In May 2011, Marketing Company and Ameren
Illinois entered into energy product agreements by which
Marketing Company will sell and Ameren Illinois will
purchase approximately 1,747,200 megawatthours at
approximately $37 per megawatthour during the 12 months
ending May 31, 2012, approximately 1,840,800
megawatthours at approximately $42 per megawatthour
during the 12 months ending May 31, 2013, and
approximately 650,000 megawatthours at approximately
$42 per megawatthour during the 12 months ending
May 31, 2014. In May 2011, Ameren Missouri and Ameren
Illinois entered into energy product agreements by which
Ameren Missouri will sell and Ameren Illinois will purchase
approximately 16,800 megawatthours at approximately
$37 per megawatthour during the 12 months ending
May 31, 2012, approximately 40,800 megawatthours at
approximately $29 per megawatthour during the 12 months
ending May 31, 2013, and approximately 40,800
megawatthours at approximately $28 per megawatthour
during the 12 months ending May 31, 2014. The May 31,
2012 and May 31, 2013 energy product agreements
between Ameren Missouri and Ameren Illinois are for off-
peak hours only.
In February 2012, a rate stability procurement for
energy products that will settle physically was administered
by the IPA for the June 2013 through May 2017 period to
meet certain requirements for purchased power related to
the IEIMA. Marketing Company was a winning supplier in
Ameren Illinois’ energy product procurement process. In
February 2012, Marketing Company and Ameren Illinois
entered into energy product agreements pursuant to which
Marketing Company will sell and Ameren Illinois will
purchase approximately 3,942,000 megawatthours at
approximately $30 per megawatthour during the 12 months
ending May 31, 2014, approximately 3,504,000
megawatthours at approximately $32 per megawatthour
during the 12 months ending May 31, 2015, and
152
approximately 1,317,600 megawatthours at approximately
$34 per megawatthour during the 12 months ending
May 31, 2016. The energy product agreements were based
on around-the-clock prices.
Gas Sales and Transportation Agreement
Under a gas transportation agreement, Genco acquires
gas transportation service from Ameren Missouri. This
agreement expires in February 2016.
Interconnection and Transmission Agreements
Ameren Missouri and Ameren Illinois are parties to an
interconnection agreement for the use of their respective
transmission lines and other facilities for the distribution of
power. These agreements have no contractual expiration
date, but may be terminated by either party with three years’
notice.
Joint Ownership Agreement
ATXI and Ameren Illinois have a joint ownership
agreement to construct, own, operate, and maintain certain
electric transmission assets in Illinois. Under the terms of
this agreement, Ameren Illinois and ATXI are responsible
for their applicable share of all costs related to the
construction, operation, and maintenance of electric
transmission systems. Ameren is the primary beneficiary of
ATXI, which is a variable interest entity, and therefore
consolidates ATXI. Currently, there are no construction
projects or joint ownership of existing assets under this
agreement.
In January 2011, ATXI repaid advances for the
construction of transmission assets to Ameren Illinois in
the amount of $52 million, including $3 million of accrued
interest.
In April 2011, ATXI transferred, at cost, all of ATXI’s
construction work in progress assets related to the
construction of a transmission line to Ameren Illinois for
$20 million.
Support Services Agreements
Ameren Services provides support services to its
affiliates. The costs of support services, including wages,
employee benefits, professional services, and other
expenses, are based on, or are an allocation of, actual costs
incurred. The shared services support agreement can be
terminated with respect to a particular affiliate by the mutual
agreement of Ameren Services and that affiliate or by either
Ameren Services or that affiliate with 60 days notice before
the end of a calendar year. Ameren has begun planning how
it will to reduce, and ultimately eliminate AER’s reliance on
the support services agreement.
AFS provided support services to its affiliates through
December 31, 2010. Effective January 1, 2011, the services
previously performed by AFS are performed within Ameren
Missouri, Ameren Illinois and AER.
In addition, Ameren Missouri, Ameren Illinois and AER
provide affiliates, primarily Ameren Services, with access to
their facilities for administrative purposes. The cost of the
rent and facility services are based on, or are an allocation
of, actual costs incurred.
153
Transmission Services Agreement
Under a transmission services agreement, Marketing
Company acquires transmission services from Ameren
Illinois for certain retail and residential customers.
Money Pools
See Note 5 – Long-term Debt and Equity Financings for
a discussion of affiliate borrowing arrangements.
Collateral Postings
Under the terms of the Illinois power procurement
agreements entered into through RFP processes
administered by the IPA, suppliers must post collateral
under certain market conditions to protect Ameren Illinois
in the event of nonperformance. The collateral postings are
unilateral, meaning that only the suppliers would be
required to post collateral. Therefore, Ameren Missouri and
Marketing Company, as winning suppliers in the RFP
process, may be required to post collateral. As of
December 31, 2012 and 2011, there were no collateral
postings required of Ameren Missouri or Marketing
Company related to the Illinois power procurement
agreements.
Marketing Company Sale of Trade Receivables to
Ameren Illinois
In accordance with the Illinois Public Utilities Act,
Ameren Illinois is required to purchase alternative retail
electric suppliers’ receivables relating to Ameren Illinois’
delivery service customers who elected to receive power
supply from the alternative retail electric supplier. Beginning
in June 2012, Marketing Company sold and Ameren Illinois
purchased trade receivables relating to the power supply of
residential customers using Marketing Company as their
alternative retail electric supplier. Marketing Company has
no continuing involvement with or control over the trade
receivables after the sale is completed to Ameren Illinois,
and neither company has any restrictions on the assets
associated with these purchase and sale transactions. As of
December 31, 2012, Ameren Illinois’ payable to Marketing
Company for the purchase of trade receivables totaled
$5 million. For the year ended December 31, 2012, Ameren
Illinois purchased $35 million of trade receivables from
Marketing Company at a discount of less than $1 million.
Marketing Company’s receivable from Ameren Illinois as
well as Ameren Illinois’ payable to Marketing Company are
eliminated in the consolidated Ameren Corporation’s
financial statements.
Intercompany Sales
In 2012, Genco completed the sale of land for cash
proceeds of $2 million to ATXI. Genco recognized a
$2 million gain from the sale. Under authoritative
accounting guidance for rate-regulated entities, the gain
was not eliminated upon consolidation.
Parent Company Guarantees
In the ordinary course of business, Ameren (parent)
enters into various agreements providing financial
assurance to third parties on behalf of its subsidiaries. Such
agreements include, for example, guarantees and letters of
credit. These agreements are entered into primarily to
support or enhance the creditworthiness otherwise
attributed to a subsidiary on a stand-alone basis, thereby
facilitating the extension of sufficient credit and reducing
the amount of cash collateral required to be posted. These
agreements guarantee performance by Ameren’s
subsidiaries of obligations already existing on Ameren’s
consolidated balance sheet.
Upon the ultimate exit of the Merchant Generation
segment, the guarantees relative to that business segment
that are in effect at that time may or may not be retained by
Ameren (parent), depending on the terms of Ameren’s exit
from that business.
At December 31, 2012, Ameren had a total of
$354 million in guarantees outstanding, which included:
‰
$189 million related to Ameren’s Merchant Generation
segment, primarily for Marketing Company as support
for physically and financially settled power transactions
with its counterparties. Of these guarantees
$161 million expire in 2013, $12 million expire in 2014,
and $16 million expire thereafter. Ameren remains
obligated under these guarantees, up to the maximum
level included in the respective guarantee agreements,
after the guarantee expiration date if transactions
between the counterparties were in effect at the
expiration of the guarantee agreement. Consequently,
Ameren’s guarantees may be extended past the
expiration dates listed above depending on future
counterparty transactions. The amounts above do not
represent incremental consolidated Ameren obligations;
rather, they represent Ameren parental guarantees of
subsidiary obligations to third parties in order to allow
the subsidiaries the flexibility needed to conduct
business with counterparties without having to post
other forms of collateral. Ameren’s estimated exposure
for obligations under transactions covered by these
guarantees was $25 million at December 31, 2012,
which represents the total amount Ameren (parent)
could be required to fund based on December 31, 2012
market prices.
$100 million associated with the guarantee agreement
between Ameren and AERG entered into on
March 28, 2012, relating to the put option agreement
between Genco and AERG. As of December 31, 2012,
Genco had not exercised the put option and thus
Ameren had no exposure to this intercompany
guarantee.
$50 million guarantee to MISO for all of Ameren’s
subsidiaries who are MISO market participants.
Ameren’s estimated exposure for obligations under
transactions covered by this guarantee was $32 million
at December 31, 2012, which represents the total
amount Ameren (parent) could be required to fund
based on December 31, 2012 market prices.
$15 million related to requirements for asset
transactions, leasing, and other service agreements. At
December 31, 2012, Ameren estimated it had no
exposure to any of these guarantees.
‰
‰
‰
Additionally, at December 31, 2012, Ameren had
issued letters of credit totaling $9 million as credit support
to certain subsidiaries.
The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the
years ended December 31, 2012, 2011, and 2010. It is based primarily on the agreements discussed above and the money
pool arrangements discussed in Note 4 – Short-term Debt and Liquidity.
Agreement
Ameren Missouri power supply agreements
with Ameren Illinois
Ameren Missouri and Genco gas
transportation agreement
Ameren Missouri and Ameren Illinois
rent and facility services
Ameren Illinois transmission services agreement
with Marketing Company
Total Operating Revenues
Income Statement Line Item
Operating Revenues
Operating Revenues
Operating Revenues
Operating Revenues
154
Ameren
Missouri
Ameren
Illinois
$
$
(b)
2
2
1
1
1
19
16
16
(a)
(a)
(a)
20
19
19
$
$
(a)
(a)
(a)
(a)
(a)
(a)
1
1
1
15
10
10
16
11
11
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
Agreement
Income Statement Line Item
Ameren Illinois power supply agreements
with Marketing Company
Ameren Illinois power supply
agreements with Ameren Missouri
Total Purchased Power
Purchased Power
Purchased Power
Gas purchases from Genco
Gas Purchased for Resale
Ameren Services support services
agreement
AFS support services agreement
Insurance premiums(c)
Total Other Operations and
Maintenance Expenses
Money pool borrowings (advances)
Other Operations and
Maintenance
Other Operations and
Maintenance
Other Operations and
Maintenance
Interest (Charges)
Income
Ameren
Missouri
Ameren
Illinois
$
$
$
$
$
$
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
106
114
128
(a)
(a)
7
(b)
(b)
1
106
114
136
(b)
-
-
$ 311
232
233
(b)
2
2
$ 311
234
235
$
$
$
$
-
-
1
88
87
102
(a)
(a)
(b)
(a)
(a)
(a)
88
87
102
(b)
-
-
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
(a) Not applicable.
(b) Amount less than $1 million.
(c) Represents insurance premiums paid to Energy Risk Assurance Company, an affiliate for replacement power, property damage, and terrorism
coverage.
NOTE 15 – COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, authorities, and
governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial
amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to
our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 10 – Callaway
Energy Center and Note 14 – Related Party Transactions in this report.
Callaway Energy Center
The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at December 31, 2012. The
property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.
Type and Source of Coverage
Maximum Coverages
Maximum Assessments
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 . . . . . . . . . . . .
$
$
$
$
$
375
12,219(a)
12,594(c)
2,750(d)
490(f)
64(g)
$
-
118(b)
$ 118
$
$
$
23(e)
9(e)
-
(a) Provided through mandatory participation in an industrywide retrospective premium assessment program.
155
(b) Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of
$375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c) Limit of liability for each incident under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. A company
could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid
in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed
reactors.
(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) All Nuclear Electric Insurance Ltd. insured plants could be subject to assessments should losses exceed the accumulated funds from Nuclear
Electric Insurance Ltd.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity
up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of
71 weeks thereafter for a total not exceeding the policy limit of $490 million.
(g) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage
commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for
71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage
with third-party insurance companies. See Note 14 – Related Party Transactions for more information on this affiliate transaction.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United
States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the
maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer
Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective
October 29, 2008. The next adjustment could occur during the fourth quarter of 2013. 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 the Price-Anderson Act.
Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd’s policies, subject to an
industrywide 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 energy center exceed the limits of, or are not covered by, insurance, or if
coverage is unavailable, Ameren Missouri 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 Ameren Missouri’s results of operations, financial position, or liquidity.
Leases
We lease various facilities, office equipment, plant equipment, and rail cars under capital and operating leases. The
following table presents our lease obligations at December 31, 2012:
Total
2013
2014
2015
2016
2017 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri:
Capital lease payments(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less amount representing interest . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of minimum capital lease payments . . . . . . . . . . . . . .
Operating leases(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Operating leases(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
588
284
304
272
576
588
284
304
123
427
7
$
$
$
$
$
$
$
32
27
5
31
36
32
27
5
12
17
1
$
$
$
$
$
$
$
32
27
5
27
32
32
27
5
12
17
1
$
$
$
$
$
$
$
33
27
6
26
32
33
27
6
12
18
1
$
$
$
$
$
$
$
33
27
6
26
32
33
27
6
12
18
1
$
$
$
$
$
$
$
33
27
6
25
31
33
27
6
13
19
$
$
$
$
$
425
149
276
137
413
425
149
276
62
$
338
1
$
2
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) See Properties under Part I, Item 2, and Note 3 – Property and Plant, Net of this report for additional information.
(c) Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $ 2 million, $1 million and $1 million
for Ameren, Ameren Missouri and Ameren Illinois for these items is included in the 2013 through 2017 columns, respectively.
156
The following table presents total rental expense, included in operating expenses, for the years ended December 31, 2012,
2011, and 2010:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
48
29
19
$
47
29
17
$
52
29
19
2012
2011
2010
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Other Obligations
To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments
for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term
commitments for purchased power and natural gas for distribution. The table below presents our estimated fuel, purchased
power, and other commitments at December 31, 2012. Ameren’s and Ameren Missouri’s purchased power obligations include
a 102-megawatt power purchase agreement with a wind farm operator that expires in 2024. Ameren’s and Ameren Illinois’
purchased power obligations include the Ameren Illinois power purchase agreements entered into as part of the IPA-
administered power procurement process. Included in the Other column are minimum purchase commitments under
contracts for equipment, design and construction, and meter reading services at December 31, 2012. Ameren’s and Ameren
Illinois’ Other column also include obligations related to IEIMA. In addition, the Other column includes Ameren’s and Ameren
Missouri’s obligations related to energy efficiency programs under the MEEIA as approved by the MoPSC’s December 2012
electric rate order. The order provides that, beginning in 2013, Ameren Missouri will invest approximately $147 million over
three years for energy efficiency programs. See Note 2 – Rate and Regulatory Matters for additional information about the
IEIMA and MEEIA.
Coal
Natural
Gas
Nuclear
Fuel
Purchased
Power(a)
Methane
Gas
Other
Total
Ameren:(b)
2013 . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . .
$
908
774
702
732
701
277
Total
. . . . . . . . . . . . . . . . . . . . .
$
4,094
Ameren Missouri:
2013 . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . .
$
620
625
614
644
676
245
Total
. . . . . . . . . . . . . . . . . . . . .
$
3,424
Ameren Illinois:
2013 . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . .
$
Total
. . . . . . . . . . . . . . . . . . . . .
$
-
-
-
-
-
-
-
$
$
$
$
$
$
349
254
138
54
34
105
934
57
43
25
10
5
28
168
270
206
110
44
29
78
737
$
$
$
$
$
$
36
89
87
95
78
277
662
36
89
87
95
78
277
662
-
-
-
-
-
-
-
$
$
$
$
$
$
421
309
164
78
55
687
$ 1,714
$
$
$
19
19
19
19
19
130
225
401
289
145
59
36
559
$ 1,489
$
3
3
4
4
5
99
118
3
3
4
4
5
99
118
-
-
-
-
-
-
-
$
$
$
$
$
$
174
167
117
62
50
246
816
106
123
87
38
26
144
524
24
22
24
24
24
102
220
$ 1,891
1,596
1,212
1,025
923
1,691
$ 8,338
$
841
902
836
810
809
923
$ 5,121
$
695
517
279
127
89
739
$ 2,446
(a) The purchased power amounts for Ameren and Ameren Illinois includes 20-year agreements for renewable energy credits that were entered
into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the
quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Previously, Ameren Illinois entered into an agreement
to purchase approximately 15.5 billion cubic feet of
synthetic natural gas annually over a 10-year period
beginning in 2016 for its natural gas customers. The
agreement was entered into pursuant to an Illinois law, that
became effective August 2, 2011. Ameren Illinois’
157
obligations under the agreement were contingent on the
counterparty reaching certain milestones during the project
development and the construction of the plant that was to
produce the synthetic natural gas. The counterparty failed to
meet certain milestones during 2012 and, accordingly, the
contract was terminated.
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 and natural gas
storage, transmission and distribution facilities, our
activities involve compliance with diverse environmental
laws and regulations. These laws and regulations address
emissions, impacts to air, land, and water, noise, protected
natural and cultural resources (such as wetlands,
endangered species and other protected wildlife, and
archeological and historical resources), and chemical and
waste handling. Complex and lengthy processes are
required to obtain approvals, permits, or licenses for new,
existing or modified facilities. Additionally, the use and
handling of various chemicals or hazardous materials
(including wastes) requires release prevention plans and
emergency response procedures.
In addition to existing laws and regulations, including
the Illinois MPS that applies to AER’s energy centers in
Illinois, the EPA is developing environmental regulations
that will have a significant impact on the electric utility
industry. These regulations could be particularly
burdensome for certain companies, including Ameren,
Ameren Missouri, Genco and AERG, that operate coal-fired
energy centers. Significant new rules proposed or
promulgated since the beginning of 2010 include the
regulation of greenhouse gas emissions; revised national
ambient air quality standards for fine particulate, SO2, and
NO2 emissions; the CSAPR, which would have required
further reductions of SO2 emissions and NOx emissions
from energy centers; a regulation governing management of
CCR and coal ash impoundments; the MATS, which require
reduction of emissions of mercury, toxic metals, and acid
gases from energy centers; revised NSPS for particulate
matter, SO2, and NOx emissions from new sources; and
new regulations under the Clean Water Act that could
require significant capital expenditures such as new water
intake structures or cooling towers at our energy centers.
The EPA has proposed CO2 limits for new coal-fired and
natural gas-fired combined cycle units and is expected to
propose limits for existing units in the future. These new
and proposed regulations, if adopted, may be challenged
through litigation, so their ultimate implementation as well
as the timing of any such implementation is uncertain, as
evidenced by the CSAPR being vacated and remanded back
to the EPA by the United States Court of Appeals for the
District of Columbia in August 2012. Although many details
of these future regulations are unknown, the combined
effects of the new and proposed environmental regulations
may result in significant capital expenditures and/or
increased operating costs over the next five to ten years for
Ameren, Ameren Missouri and AER. Compliance with these
environmental laws and regulations could be prohibitively
expensive. If they are, these regulations could require us to
close or to significantly alter the operation of our energy
centers, which could have an adverse effect on our results
of operations, financial position, and liquidity, including the
impairment of long-lived assets. Failure to comply with
environmental laws and regulations might also result in the
imposition of fines, penalties, and injunctive measures.
The estimates in the table below contain all of the
known capital costs to comply with existing environmental
regulations, including the CAIR, and our assessment of the
potential impacts of the EPA’s proposed regulation for CCR
and the finalized MATS as of December 31, 2012. The
estimates in the table below assume that CCR will continue
to be regarded as nonhazardous. The estimates in the table
below do not include the impacts of regulations proposed
by the EPA under the Clean Water Act in March 2011
regarding cooling water intake structures as our evaluation
of those impacts is ongoing. The estimates in the table
below assume the Merchant Generation facilities are owned
by Ameren over the entire period shown. The estimates
shown in the table below could change significantly
depending upon a variety of factors including:
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
additional or modified federal or state requirements;
further regulation of greenhouse gas emissions;
revisions to CAIR or reinstatement of CSAPR;
new national ambient air quality standards or changes
to existing standards for ozone, fine particulates, SO2,
and NOx emissions;
additional rules governing air pollutant transport;
regulations under the Clean Water Act regarding
cooling water intake structures or effluent standards;
finalized regulations classifying CCR as being
hazardous or imposing additional requirements on the
management of CCR;
new technology;
expected power prices;
variations in costs of material or labor; and
alternative compliance strategies or investment
decisions.
2013 2014 - 2017
2018 - 2022
Total
AMO(a)
Genco . . . . . .
AERG . . . . . .
. . . . . $ 105 $ 215 - $ 260 $
30
5
100 -
20 -
125
25
795 - $
220 -
20 -
975 $ 1,115 - $ 1,340
425
350 -
270
55
45 -
25
Ameren . . . . . $ 140 $ 335 - $ 410 $ 1,035 - $ 1,270 $ 1,510 - $ 1,820
(a) Ameren Missouri’s expenditures are expected to be recoverable
from ratepayers.
The decision to make pollution control equipment
investments at AER depends on whether the expected
future market price for power reflects the increased cost for
environmental compliance. During early 2012, the
observable market price for power for delivery in that year
and in future years sharply declined below 2011 levels
158
primarily because of declining natural gas prices, as well as
the impact from the stay of the CSAPR. As a result of this
sharp decline in the market price for power, as well as
uncertain environmental regulations, Genco decelerated the
construction of two scrubbers at its Newton energy center.
The table above includes Genco’s estimated costs of
approximately $20 million annually, excluding capitalized
interest, from 2013 through 2017 for the construction of
the two Newton energy center scrubbers. Based on the
MPS variance granted by the Illinois Pollution Control Board
in September 2012, AER is currently scheduled to complete
the Newton scrubbers by the end of 2019. See additional
information below regarding the MPS variance granted by
the Illinois Pollution Control Board.
The following sections describe the more significant
environmental rules that affect or could affect our
operations.
Clean Air Act
Both federal and state laws require significant
reductions in SO2 and NOx emissions that result from
burning fossil fuels. In March 2005, the EPA issued
regulations with respect to SO2 and NOx emissions (the
CAIR). The CAIR required generating facilities in 28 states,
including Missouri and Illinois, and the District of Columbia,
to participate in cap-and-trade programs to reduce annual
SO2 emissions, annual NOx emissions, and ozone season
NOx emissions.
In December 2008, the United States Court of Appeals
for the District of Columbia Circuit remanded the CAIR to
the EPA for further action to remedy the rule’s flaws, but
allowed the CAIR’s cap-and-trade programs to remain
effective until they are replaced by the EPA. In July 2011,
the EPA issued the CSAPR as the CAIR replacement. The
CSAPR was to become effective on January 1, 2012, for
SO2 and annual NOx reductions and on May 1, 2012, for
ozone season NOx reductions, with further reductions in
2014. On December 30, 2011, the United States Court of
Appeals for the District of Columbia Circuit issued a stay of
the CSAPR. In August 2012, the United States Court of
Appeals for the District of Columbia Circuit issued a ruling
that vacated the CSAPR in its entirety, finding that the EPA
exceeded its authority in imposing the CSAPR’s emission
limits on states. In January 2013, the full Court of Appeals
for the District of Columbia Circuit denied the EPA’s request
for rehearing. The EPA will continue to administer the CAIR
until a new rule is ultimately adopted or the decision to
vacate the CSAPR is overturned by the United States
Supreme Court.
In December 2011, the EPA issued the MATS under
the Clean Air Act, which require emission reductions for
mercury and other hazardous air pollutants, such as acid
gases, toxic metals, and particulate matter by setting
emission limits equal to the average emissions of the best
performing 12% of existing coal and oil-fired electric
generating units. Also, the standards require reductions in
hydrogen chloride emissions, which were not regulated
previously, and for the first time require continuous
monitoring systems for hydrogen chloride, mercury and
particulate matter that are not currently in place. The MATS
do not require a specific control technology to achieve the
emission reductions. The MATS will apply to each unit at a
coal-fired power plant; however, emission compliance can
be achieved by averaging emissions from similar electric
generating units at the same power plant. Compliance is
required by April 2015 or, with a case-by-case extension, by
April 2016. Ameren Missouri’s Labadie and Meramec
energy centers requested and were granted extensions to
comply with the MATS by April 2016.
Separately, in December 2012, the EPA issued a final
rule that made the national ambient air quality standard for
fine particulate matter more stringent. States must develop
control measures designed to reduce the emission of fine
particulate matter below required levels to achieve
compliance with the new standard. Such measures may or
may not apply to energy centers but could require
reductions in SO2 and NOx emissions. Compliance with the
finalized rule is required by 2020, or 2025 if an extension of
time to achieve compliance is granted. Ameren Missouri
and AER are currently evaluating the new standard while the
states of Missouri and Illinois develop their attainment
plans.
In September 2011, the EPA announced that it was
implementing the 2008 national ambient air quality
standard for ozone. The EPA is required to revisit this
standard for ozone again in 2013. The states of Illinois and
Missouri will be required to develop attainment plans to
comply with the 2008 ambient air quality standards for
ozone, which could result in additional emission control
requirements for power plants by 2020. Ameren, Ameren
Missouri and AER continue to assess the impacts of these
new standards.
Ameren Missouri’s current environmental compliance
plan for air emissions from its energy centers includes
burning ultra-low-sulfur coal and installing new or
optimizing existing pollution control equipment. In July
2011, Ameren Missouri contracted to procure significantly
higher volumes of lower-sulfur-content coal than Ameren
Missouri’s energy centers have historically burned, which
allowed Ameren Missouri to eliminate or postpone capital
expenditures for pollution control equipment. In 2010,
Ameren Missouri completed the installation of two
scrubbers at its Sioux energy center to reduce SO2
emissions. Currently, Ameren Missouri’s compliance plan
assumes the installation of two scrubbers within its coal-
fired fleet, mercury control technology, and precipitator
upgrades at multiple energy centers during the next 10
years. However, Ameren Missouri is currently evaluating its
operations and options to determine how to comply with
the MATS and other recently finalized or proposed EPA
regulations.
In September 2012, the Illinois Pollution Control Board
granted AER a variance to extend compliance dates for SO2
emission levels contained in the MPS through
159
December 31, 2019, subject to certain conditions described
below. The Illinois Pollution Control Board approved AER’s
proposed plan to restrict its SO2 emissions through 2014 to
levels lower than those previously required by the MPS to
offset any environmental impact from the variance. The
Illinois Pollution Control Board’s order also included the
following provisions:
‰
‰
A schedule of milestones for completion of various
aspects of the installation and completion of the
scrubber projects at Genco’s Newton energy center; the
first milestone relates to the completion of engineering
design by July 2015 while the last milestone relates to
major equipment components being placed into final
position on or before September 1, 2019.
A requirement for AER to refrain from operating the
Meredosia and Hutsonville energy centers through
December 31, 2020; however, this restriction does not
impact Genco’s ability to make the Meredosia energy
center available for any parties that may be interested in
repowering one of its units to create an oxy-fuel
combustion coal-fired energy center designed for
permanent carbon dioxide capture and storage.
Under the MPS, AER is required to reduce mercury
and NOx emissions by 2015 and SO2 emissions by the end
of 2019. The Illinois Pollution Control Board’s September
2012 variance gives AER additional time for economic
recovery and related power price improvements necessary
to support scrubber installations and other pollution
controls at some of AER’s energy centers. To comply with
the MPS and other air emissions laws and regulations,
Genco and AERG are installing equipment designed to
reduce their emissions of mercury, NOx, and SO2. Genco
and AERG have installed a total of three scrubbers at two
energy centers. Two additional scrubbers are being
constructed at Genco’s Newton energy center. AER will
continue to review and adjust its compliance plans in light
of evolving outlooks for power and capacity prices,
delivered fuel costs, emission standards required under
environmental laws and regulations and compliance
technologies, among other factors.
Environmental compliance costs could be prohibitive at
some of Ameren’s, Ameren Missouri’s and AER’s energy
centers as the expected return from these investments, at
current market prices for energy and capacity, might not
justify the required capital expenditures or their continued
operation, which could result in the impairment of long-
lived assets.
Emission Allowances
The Clean Air Act created marketable commodities
called emission allowances under the acid rain program, the
NOx budget trading program, and the CAIR. Environmental
regulations, including those relating to the timing of the
installation of pollution control equipment, fuel mix, and the
level of operations will have a significant impact on the
number of allowances required for ongoing operations. The
CAIR uses the acid rain program’s allowances for SO2
emissions and created annual and ozone season NOx
allowances. Ameren and Ameren Missouri expect to have
adequate CAIR allowances for 2013 to avoid needing to
make external purchases to comply with these programs.
Global Climate Change
State and federal authorities, including the United
States Congress, have considered initiatives to limit
greenhouse gas emissions and to address global climate
change. Potential impacts from any climate change
legislation or regulation could vary, depending upon
proposed CO2 emission limits, the timing of implementation
of those limits, the method of distributing any allowances,
the degree to which offsets are allowed and available, and
provisions for cost-containment measures, such as a
“safety valve” provision that provides a maximum price for
emission allowances. As a result of our fuel portfolio, our
emissions of greenhouse gases vary among our energy
centers, but coal-fired power plants are significant sources
of CO2. The enactment of a climate change law could result
in a significant rise in rates for electricity and thereby
household costs. The burden could fall particularly hard on
electricity consumers and upon the economy in the
Midwest because of the region’s reliance on electricity
generated by coal-fired power plants. Natural gas emits
about half as much CO2 as coal when burned to produce
electricity. Therefore, climate change regulations could
cause the conversion of coal-fired power plants to natural
gas, or the construction of new natural gas plants to replace
coal-fired power plants. As a result, economywide shifts to
natural gas as a fuel source for electricity generation also
could affect the cost of heating for our utility customers and
many industrial processes that use natural gas.
In December 2009, the EPA issued its “endangerment
finding” under the Clean Air Act, which stated that
greenhouse gas emissions, including CO2, endanger human
health and welfare and that emissions of greenhouse gases
from motor vehicles contribute to that endangerment. In
March 2010, the EPA issued a determination that
greenhouse gas emissions from stationary sources, such as
power plants, would be subject to regulation under the
Clean Air Act effective the beginning of 2011. As a result of
these actions, we are required to consider the emissions of
greenhouse gases in any air permit application.
Recognizing the difficulties presented by regulating at
once virtually all emitters of greenhouse gases, the EPA
issued the “Tailoring Rule,” which established new higher
emission thresholds beginning in January 2011, for
regulating greenhouse gas emissions from stationary
sources, such as power plants. The rule requires any source
that already has an operating permit to have greenhouse-
gas-specific provisions added to its permits upon renewal.
Currently, all Ameren energy centers have operating permits
that, when renewed, may be modified to address
greenhouse gas emissions. The Tailoring Rule also provides
that if projects performed at major sources result in an
increase in emissions of greenhouse gases over an
applicable annual threshold, such projects could trigger
permitting requirements under the NSR programs and the
160
application of best available control technology, if any, to
control greenhouse gas emissions. New major sources are
also required to obtain such a permit and to install the best
available control technology if their greenhouse gas
emissions exceed the applicable emissions threshold. The
extent to which the Tailoring Rule could have a material
impact on our energy centers depends upon how state
agencies apply the EPA’s guidelines as to what constitutes
the best available control technology for greenhouse gas
emissions from power plants and whether physical changes
or changes in operations subject to the rule occur at our
energy centers. In June 2012, the United States Court of
Appeals for the District of Columbia Circuit upheld the
Tailoring Rule.
Separately, in March 2012, the EPA issued the
proposed Carbon Pollution Standard for New Power Plants.
This proposed NSPS for greenhouse gas emissions would
apply only to new fossil-fuel fired electric energy centers
and therefore does not affect any of Ameren’s or Ameren
Missouri’s existing energy centers. Ameren anticipates this
proposed rule, if enacted, could make the construction of
new coal-fired energy centers in the United States
prohibitively expensive. A final rule is expected in 2013. Any
federal climate change legislation that is enacted may
preempt the EPA’s regulation of greenhouse gas emissions,
including the Tailoring Rule and the Carbon Pollution
Standard for New Power Plants.
Future federal and state legislation or regulations that
mandate limits on the emission of greenhouse gases would
likely result in significant increases in capital expenditures
and operating costs, which, in turn, could lead to increased
liquidity needs and higher financing costs. Moreover, to the
extent Ameren Missouri requests recovery of these costs
through rates, its regulators might delay or deny timely
recovery of these costs. Excessive costs to comply with
future legislation or regulations might force Ameren,
Ameren Missouri and AER as well as other similarly situated
electric power generators to close some coal-fired facilities
earlier than planned, which could lead to possible
impairment of assets and reduced revenues. As a result,
mandatory limits could have a material adverse impact on
Ameren’s and Ameren Missouri’s results of operations,
financial position, and liquidity.
Recent federal court decisions have considered the
application of common law causes of action, such as
nuisance, to address damages resulting from global climate
change. In March 2012, the United States District Court for
the Southern District of Mississippi dismissed the Comer v.
Murphy Oil lawsuit, which alleged that CO2 emissions from
several industrial companies, including Ameren Missouri,
Genco, and AERG, created atmospheric conditions that
intensified Hurricane Katrina, thereby causing property
damage. The case has been appealed to the appellate court.
The impact on us of future initiatives related to
greenhouse gas emissions and global climate change is
unknown. Compliance costs could increase as future federal
legislative, federal regulatory, and state-sponsored
initiatives to control greenhouse gases continue to
progress, making it more likely that some form of
greenhouse gas emissions control will eventually be
required. Since these initiatives continue to evolve, their
impact on our coal-fired energy centers and our customers’
costs is unknown, but they could result in significant
increases in our capital expenditures and operating costs.
The compliance costs could be prohibitive at some of our
energy centers as the expected return from these
investments, at current market prices for energy and
capacity, might not justify the required capital expenditures
or their continued operation, which could result in the
impairment of long-lived assets.
NSR and Clean Air Litigation
The EPA is engaged in an enforcement initiative to
determine whether coal-fired power plants failed to comply
with the requirements of the NSR and NSPS provisions
under the Clean Air Act when the plants implemented
modifications. The EPA’s inquiries focus on whether
projects performed at power plants should have triggered
various permitting requirements and the installation of
pollution control equipment.
Commencing in 2005, Genco received a series of
information requests from the EPA pursuant to
Section 114(a) of the Clean Air Act. The requests sought
detailed operating and maintenance history data with
respect to Genco’s Coffeen, Hutsonville, Meredosia,
Newton, and Joppa energy centers and AERG’s E.D.
Edwards and Duck Creek energy centers. In August 2012,
Genco received a Notice of Violation from the EPA alleging
violations of permitting requirements including Title V of the
Clean Air Act. The EPA contends that projects performed in
1997, 2006, and 2007 at Genco’s Newton energy center
violated federal law. Genco believes its defenses to the
allegations described in the Notice of Violation are
meritorious. Ameren and Genco are unable to predict the
outcome of this matter and whether EPA will address this
Notice of Violation administratively or through litigation.
Following the issuance of a Notice of Violation, in
January 2011, the Department of Justice on behalf of the
EPA filed a complaint against Ameren Missouri in the
United States District Court for the Eastern District of
Missouri. The EPA’s complaint alleges that in performing
projects at its Rush Island coal-fired energy center, Ameren
Missouri violated provisions of the Clean Air Act and
Missouri law. In January 2012, the United States District
Court granted, in part, Ameren Missouri’s motion to
dismiss various aspects of the EPA’s penalty claims. The
EPA’s claims for injunctive relief, including to require the
installation of pollution control equipment, remain.
Litigation of this matter could take many years to resolve.
Ameren Missouri believes its defenses to the allegations
described in the complaint as well as the Notices of
Violation are meritorious. Ameren Missouri will defend itself
vigorously. However, there can be no assurances that it will
be successful in its efforts.
Ultimate resolution of these matters could have a
material adverse impact on the future results of operations,
161
financial position, and liquidity of Ameren and Ameren
Missouri. A resolution could result in increased capital
expenditures for the installation of pollution control
equipment, increased operations and maintenance
expenses, and penalties. We are unable to predict the
ultimate resolution of these matters or the costs that might
be incurred.
Clean Water Act
In March 2011, the EPA announced a proposed rule
applicable to cooling water intake structures at existing
power plants that have the ability to withdraw more than
2 million gallons of water per day from a body of water and
use at least 25 percent of that water exclusively for cooling.
Under the proposed rule, affected facilities would be
required either to meet mortality limits for aquatic life
impinged on the plant’s intake screens or to reduce intake
velocity to a specified level. The proposed rule also requires
existing power plants to meet site-specific entrainment
standards or to reduce the cooling water intake flow
commensurate with the intake flow of a closed-cycle
cooling system. The final rule is scheduled to be issued in
June 2013, with compliance expected within eight years
thereafter. All coal-fired, nuclear, and combined cycle
energy centers at Ameren, Ameren Missouri and AER with
cooling water systems are subject to this proposed rule.
The proposed rule did not mandate cooling towers at
existing facilities, as other technology options potentially
could meet the site-specific standards. Ameren, Ameren
Missouri and AER are currently evaluating the proposed
rule, and their assessment of the proposed rule’s impacts is
ongoing. Therefore, we cannot predict at this time the
capital or operating costs associated with compliance. The
proposed rule, if adopted, could have an adverse effect on
our results of operations, financial position, and liquidity if
its implementation requires the installation of cooling
towers at our energy centers.
In September 2009, the EPA announced its plan to
revise the effluent guidelines applicable to steam electric
generating units under the Clean Water Act. Effluent
guidelines are national standards for wastewater discharges
to surface water that are based on the effectiveness of
available control technology. The EPA is engaged in
information collection and analysis activities in support of
this rulemaking. It has indicated that it expects to issue a
proposed rule in April 2013 and to finalize the rule in May
2014. We are unable at this time to predict the impact of
this development.
Remediation
We are involved in a number of remediation actions to
clean up hazardous waste sites as required by federal and
state law. Such statutes require that responsible parties
fund remediation actions regardless of their degree of fault,
the legality of original disposal, or the ownership of a
disposal site. Ameren Missouri and Ameren Illinois have
each been identified by the federal or state governments as
a potentially responsible party (PRP) at several
contaminated sites. Several of these sites involve facilities
that were transferred by our rate-regulated utility operations
in Illinois to Genco in May 2000 and to AERG in October
2003. As part of each transfer, Ameren Illinois contractually
agreed to indemnify Genco and AERG for remediation costs
associated with pre-existing environmental contamination at
the transferred sites.
As of December 31, 2012, Ameren Illinois owned or
was otherwise responsible for 44 former MGP sites in
Illinois. These are in various stages of investigation,
evaluation, remediation and closure. Based on current
estimated plans, Ameren and Ameren Illinois could
substantially conclude remediation efforts at most of these
sites by 2018. The ICC permits Ameren Illinois to recover
remediation and litigation costs associated with its former
MGP sites from its electric and natural gas utility customers
through environmental adjustment rate riders. To be
recoverable, such costs must be prudently and properly
incurred. Costs are subject to annual review by the ICC.
As of December 31, 2012, Ameren Missouri has one
remaining former MGP site for which remediation is
scheduled. Remediation is complete at the other Ameren
Missouri former MGP sites. Ameren Missouri does not
currently have a rate rider mechanism that permits it to
recover from utility customers remediation costs associated
with MGP sites from utility customers.
The following table presents, as of December 31, 2012,
the estimated probable obligation to remediate these former
MGP sites.
Estimate
Low
High
Recorded
Liability(a)
Ameren . . . . . . . . . . . . . . . . . . . .
Ameren Missouri . . . . . . . . . . . . .
Ameren Illinois . . . . . . . . . . . . . . .
$
257
5
252
$
339
6
333
$
257
5
252
(a) Recorded liability represents the estimated minimum probable
obligations, as no other amount within the range provided a
better estimate.
The scope and extent to which these sites are
remediated has increased as remediation efforts continue.
Considerable uncertainty remains in these estimates as
many factors can influence the ultimate actual costs,
including site specific unanticipated underground
structures, the degree to which groundwater is
encountered, regulatory changes, local ordinances and site
accessibility. The actual costs may vary substantially from
these estimates.
Ameren Illinois utilized an off-site landfill, which
Ameren Illinois did not own, in connection with its
operation of the Coffeen energy center. While not currently
mandated, Ameren Illinois may be required to perform
certain remediation activities associated with that landfill. As
of December 31, 2012, Ameren Illinois estimated the
obligation related to the cleanup at $0.5 million to
$6 million. Ameren Illinois recorded a liability of
$0.5 million to represent its estimated minimum obligation
162
for this site, as no other amount within the range was a
better estimate. Ameren Illinois is also responsible for the
cleanup of a landfill, underground storage tanks, and a
water treatment plant in Illinois. As of December 31, 2012,
Ameren Illinois recorded a liability of $0.8 million to
represent its estimate of the obligation for these sites.
Ameren Missouri has responsibility for the
investigation and potential cleanup of two waste sites in
Missouri as a result of federal agency mandates. One of the
cleanup sites is a former coal tar distillery located in St.
Louis, Missouri. In 2008, the EPA issued an administrative
order to Ameren Missouri pertaining to this distillery
operated by Koppers Company or its predecessor and
successor companies. Ameren Missouri is the current
owner of the site, but Ameren Missouri did not conduct any
of the manufacturing operations involving coal tar or its
byproducts. Ameren Missouri, along with two other PRPs,
is currently performing a site investigation. As of
December 31, 2012, Ameren Missouri estimated its
obligation at $2 million to $5 million. Ameren Missouri
recorded a liability of $2 million to represent its estimated
minimum obligation, as no other amount within the range
was a better estimate. Ameren Missouri’s other active
federal agency-mandated cleanup site in Missouri is a site
in Cape Girardeau. Ameren Missouri was a customer of an
electrical equipment repair and disposal company that
previously operated a facility at this site. A trust was
established in the early 1990s by several businesses and
governmental agencies to fund the cleanup of this site,
which was completed in 2005. Ameren Missouri anticipates
that this trust fund will be sufficient to complete the
remaining adjacent off-site cleanup and it therefore has no
recorded liability at December 31, 2012, for this site.
Ameren Missouri also has a federal agency mandate to
complete an investigation for a site in Illinois. In 2000, the
EPA notified Ameren Missouri 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, Ameren
Missouri operated an energy center adjacent to Sauget Area
2. Ameren Missouri currently owns a parcel of property that
was once used as a landfill. Under the terms of an
Administrative Order on Consent, Ameren Missouri joined
with other PRPs to evaluate the extent of potential
contamination with respect to Sauget Area 2.
The Sauget Area 2 investigations overseen by the EPA
have been completed. The results have been submitted to
the EPA and a record of decision is expected in 2013. Once
the EPA has selected a remedy, if any, it would begin
negotiations with various PRPs regarding implementation.
Over the last several years, numerous other parties have
joined the PRP group. 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. As of December 31, 2012, Ameren
Missouri estimated its obligation at $0.3 million to
$10 million. Ameren Missouri recorded a liability of
$0.3 million to represent its estimated minimum obligation,
as no other amount within the range was a better estimate.
In December 2012, Ameren Missouri signed an
administrative order with the EPA and agreed to investigate
soil and groundwater conditions at an Ameren Missouri
owned substation in St. Charles, Missouri. As of
December 31, 2012, Ameren Missouri estimated the
obligation related to the cleanup at $1.5 million to
$2.3 million. Ameren Missouri recorded a liability of
$1.5 million to represent its estimated minimum obligation
for this site, as no other amount within the range was a
better estimate.
Our operations or those of our predecessor companies
involve the use of, disposal of, and in appropriate
circumstances, the cleanup of substances regulated under
environmental laws. We are unable to determine whether
such practices will result in future environmental
commitments or will affect our results of operations,
financial position, or liquidity.
Ash Management
There has been activity at both state and federal levels
regarding additional regulation of ash pond facilities and
CCR. In May 2010, the EPA announced proposed new
regulations regarding the regulatory framework for the
management and disposal of CCR, which could affect future
disposal and handling costs at our energy centers. Those
proposed regulations include two options for managing
CCRs under either solid or hazardous waste regulations, but
either alternative would allow for some continued beneficial
uses, such as recycling of CCR without classifying it as
waste. As part of its proposal, the EPA is considering
alternative regulatory approaches that require coal-fired
power plants either to close surface impoundments, such
as ash ponds, or to retrofit such facilities with liners.
Existing impoundments and landfills used for the disposal
of CCR would be subject to groundwater monitoring
requirements and requirements related to closure and
postclosure care under the proposed regulations.
Additionally, in January 2010, the EPA announced its intent
to develop regulations establishing financial responsibility
requirements for the electric generation industry, among
other industries, and it specifically discussed CCR as a
reason for developing the new requirements. Ameren,
Ameren Missouri and AER are currently evaluating all of the
proposed regulations to determine whether current
management of CCR, including beneficial reuse, and the use
of the ash ponds should be altered. Ameren, Ameren
Missouri and AER also are evaluating the potential costs
associated with compliance with the proposed regulation of
CCR impoundments and landfills, which could be material,
if such regulations are adopted.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper
reservoir at Ameren Missouri’s Taum Sauk pumped-storage
hydroelectric energy center. This resulted in significant
flooding in the local area, which damaged a state park. The
rebuilt Taum Sauk energy center became fully operational in
April 2010.
163
Ameren Missouri had liability insurance coverage for
The following table presents the pending asbestos-
the Taum Sauk incident, subject to certain limits and
deductibles. As of December 31, 2012, Ameren Missouri
had an insurance receivable balance of $68 million. Ameren
Missouri’s results of operations, financial position and
liquidity could be adversely affected if its remaining liability
insurance claims are not paid by insurers.
In June 2010, Ameren Missouri sued an insurance
company that was providing Ameren Missouri with liability
coverage on the date of the Taum Sauk incident. In the
litigation, filed in the United States District Court for the
Eastern District of Missouri, Ameren Missouri claimed that
the insurance company breached its duty to indemnify
Ameren Missouri for the losses resulting from the incident.
In January 2011, the court ruled that the parties must first
pursue alternative dispute resolution under the terms of
their coverage agreement. Ameren Missouri appealed the
January 2011 ruling to the United States Court of Appeals
for the Eighth Circuit. In August 2012, the court of appeals
remanded the case to the district court for consideration of
whether Missouri law voids the alternative dispute
resolution provision of the insurance policy.
Separately, in April 2012, Ameren Missouri sued a
second insurance company that was providing Ameren
Missouri with liability coverage on the date of the Taum
Sauk incident. In the April 2012 litigation, Ameren Missouri
claimed the insurance company breached its duty to
indemnify Ameren Missouri for the losses resulting from
the incident. In a November 2012 ruling, the United States
District Court for the Eastern District of Missouri denied the
insurer’s motion to require arbitration. The insurer filed an
appeal in the United States Court of Appeals for the Eighth
Circuit.
Asbestos-related Litigation
Ameren, Ameren Missouri, and Ameren Illinois 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 varies, with
as many as 272 parties named in some pending cases and
as few as two in others. In the cases pending as of
December 31, 2012, the average number of parties was 79.
The claims filed against Ameren, Ameren Missouri and
Ameren Illinois allege injury from asbestos exposure during
the plaintiffs’ activities at our present or former energy
centers. Former CIPS energy centers are now owned by
Genco, and former CILCO energy centers are now owned by
AERG. As a part of the transfer of ownership of the CIPS
and CILCO energy centers, CIPS and CILCO, now Ameren
Illinois, contractually agreed to indemnify Genco and AERG,
for liabilities associated with asbestos-related claims and
environmental conditions arising or existing from activities
prior to the transfer. Each lawsuit seeks unspecified
damages that, if awarded at trial, typically would be shared
among the various defendants.
related lawsuits filed against the Ameren Companies as of
December 31, 2012:
Ameren
4
Ameren
Missouri
74
Ameren
Illinois
96
Total(a)
121
(a) Total does not equal the sum of the subsidiary unit lawsuits
because some of the lawsuits name multiple Ameren entities as
defendants.
At December 31, 2012, Ameren, Ameren Missouri and
Ameren Illinois had liabilities of $23 million, $9 million, and
$14 million, respectively, recorded to represent their best
estimate of their obligations related to asbestos claims.
Ameren Illinois has a tariff rider to recover the costs of
asbestos-related litigation claims, subject to the following
terms: 90% of cash expenditures in excess of the amount
included in base electric rates are to be recovered from a
trust fund that was established when Ameren acquired IP.
At December 31, 2012, the trust fund balance was
$23 million, including accumulated interest. If cash
expenditures are less than the amount in base rates,
Ameren Illinois 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. Following the Ameren Illinois Merger, this rider is
applicable only for claims that occurred within IP’s
historical service territory. Similarly, the rider will permit
recovery only from customers within IP’s historical service
territory.
Ameren Illinois Municipal Taxes
Ameren Illinois received tax liability notices from the
city of O’Fallon, Illinois relating to prior-period electric and
natural gas municipal taxes. The city alleges that Ameren
Illinois failed to collect prior-period taxes from more than
2,100 local resident addresses primarily in newly annexed
areas for the period 2005 through 2010. Ameren Illinois is
challenging the city’s position on this matter. Ameren
Illinois believes its defenses to the notices of tax liability are
meritorious and will defend itself vigorously. As of
December 31, 2012, Ameren Illinois did not believe it was
probable that the city of O’Fallon would prevail and
therefore has not recorded a charge to earnings for a loss
contingency related to this matter. Should Ameren Illinois
ultimately be found liable for these prior-period municipal
taxes, the amount is estimated between $2 million and
$4 million, including interest and penalties. In addition, at
the end of 2012, the city of O’Fallon and six other cities
issued tax liability notices alleging that Ameren Illinois failed
to collect prior-period taxes from certain local resident
addresses. At this time, it is too early in Ameren Illinois’
review of the additional notices to reasonably estimate any
likelihood of loss.
164
Illinois Sales and Use Tax Exemptions and Credits
In Exelon Corporation v. Department of Revenue, the
Illinois Supreme Court decided in 2009 that electricity is
tangible personal property for purposes of the Illinois
income tax investment credit. In March 2010, the United
States Supreme Court refused to hear an appeal of the case,
and the decision became final. During the second quarter of
2010, Genco, including EEI, and AERG began claiming
Illinois sales and use tax exemptions and credits for
purchase transactions related to their generation
operations. The primary basis for those claims is that the
determination in the Exelon case that electricity is tangible
personal property applies to sales and use tax
manufacturing exemptions and credits. In November 2011,
EEI received a notice of proposed tax liability, documenting
the state of Illinois’ position that EEI did not qualify for the
manufacturing exemption it used during 2010. EEI is
challenging the state of Illinois’ position. In December 2011,
EEI filed a request for review by the Informal Conference
Board of the Illinois Department of Revenue. Ameren does
not believe that it is probable that the state of Illinois will
prevail and therefore has not recorded a charge to earnings
for the loss contingency. From the second quarter of 2010
through December 31, 2011, Ameren claimed
manufacturing exemptions and credits of $27 million, which
represents the maximum potential tax liability to Ameren,
excluding any penalties assessed or interest accrued.
Genco, including EEI, and AERG did not claim any
additional manufacturing exemptions or credits in 2012 and
do not anticipate claiming any additional manufacturing
exemptions or credits in 2013, pending discussions with
the Illinois Department of Revenue. Each company,
however, is reserving the right to apply for applicable
refunds at a later date.
NOTE 16 – 2010 CORPORATE REORGANIZATION
On October 1, 2010, after receiving all necessary
approvals, Ameren, CIPS, CILCO, IP, AERG and AER
completed a two-step corporate internal reorganization. The
first step of the reorganization was the Ameren Illinois
Merger. Upon consummation of the Ameren Illinois Merger,
the separate legal existence of CILCO and IP ended. The
second step of the reorganization involved the distribution
of AERG stock from Ameren Illinois to Ameren (the AERG
distribution) and the subsequent contribution by Ameren of
the AERG stock to AER. The Ameren Illinois Merger and the
distribution of AERG stock were accounted for as
transactions between entities under common control. In
accordance with authoritative accounting guidance, assets
and liabilities transferred between entities under common
control were accounted for at the historical cost basis of the
common parent, Ameren, as if the transfer had occurred at
the beginning of the earliest reporting period presented.
Ameren’s historical cost basis in Ameren Illinois included
purchase accounting adjustments related to Ameren’s
acquisition of CILCORP in 2003. Ameren Illinois accounted
for the AERG distribution as a spinoff. Ameren Illinois
transferred AERG to Ameren based on AERG’s carrying
value.
Upon the Ameren Illinois Merger, the debt and other
obligations of CILCO and IP under their mortgage
indentures, senior note indentures, and pollution control
bond agreements became debt and obligations of Ameren
Illinois. The property owned by CILCO and IP immediately
before the Ameren Illinois Merger that was subject to the
lien of their respective mortgage indentures remained
subject to such lien, which continued to secure the bonds
outstanding under such mortgage indenture subject to the
release and other provisions of such mortgage indenture.
The senior secured notes of IP and CILCO remained
secured by the mortgage bonds held by their respective
senior note trustee, subject to the release and other
provisions of the respective senior note indenture. The debt
and other obligations of CIPS remained debt and
obligations of Ameren Illinois. Ameren Illinois secured the
senior notes issued by CIPS with the benefit of a lien under
the IP mortgage indenture. Ameren Illinois has also
encumbered substantially all of the real estate, fixtures and
equipment owned by CIPS immediately before the Ameren
Illinois Merger with the lien of the IP mortgage indenture.
At the time of the Ameren Illinois Merger, the common
stock of CILCO and IP, all wholly owned by Ameren, was
canceled without consideration. Then, pursuant to the
merger agreement: (1) every two shares of each series of IP
preferred stock outstanding immediately prior to the Ameren
Illinois Merger were automatically converted into one share
of a newly created series of Ameren Illinois preferred stock
having the same payment and redemption terms as the
existing series of IP preferred stock, except to the extent that
IP preferred stockholders exercised their dissenters’ rights in
accordance with Illinois law; and (2) each outstanding share
of CIPS common and preferred stock remained outstanding,
except to the extent that CIPS preferred stockholders
exercised their dissenters’ rights in accordance with Illinois
law. Stockholders holding approximately 8,337 shares and
423 shares of CIPS and IP preferred stock, respectively,
exercised their dissenters’ rights.
In its application for the FERC orders approving the
Ameren Illinois Merger and the AERG distribution, Ameren
committed to maintain a minimum 30% equity capital
structure at Ameren Illinois after the Ameren Illinois Merger
and the AERG distribution.
Ameren Illinois determined that the operating results of
AERG qualified for discontinued operations presentation;
therefore, Ameren Illinois segregated AERG’s operating
results and presented them separately as discontinued
operations for all periods presented prior to October 1,
2010, in this report. For Ameren’s financial statements,
AERG’s results of operations remain classified as
continuing operations. The following table summarizes the
operating results of Ameren Illinois’ former merchant
generation subsidiary, AERG, classified as discontinued
165
operations in Ameren Illinois’ statements of income for the year ended December 31, 2010:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Income from discontinued operations, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
274
201
73
1
14
20
40
NOTE 17 – IMPAIRMENT AND OTHER CHARGES
The following table summarizes the pretax charges recognized for the years ended December 31, 2012, 2011, and 2010:
Long-Lived
Assets and Related
Charges
Goodwill
Emission
Allowances
Total
2012
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,578
$
123
89
101
-
-
-
420
$
-
2
-
68
$
2,578
125
89
589
(a)
Includes amounts for registrant and nonregistrant subsidiaries.
Each of the above charges was recorded in the
statement of income (loss) as “Impairment and other
charges,” with the exception of the Ameren Missouri
statement of income where it was recorded as “Loss from
regulatory disallowance.” The impairment charges did not
result in a violation of any Ameren or Ameren subsidiary
debt covenants or counterparty agreements. Each of the
charges is discussed below.
Long-lived Assets Impairments
The Ameren Companies evaluate long-lived assets
classified as held and used for impairment when events or
changes in circumstances indicate that the carrying value of
such assets may not be recoverable. Whether an
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, the Ameren
Companies recognize an impairment charge equal to the
amount of the carrying value of the assets that exceeds its
estimated fair value.
Merchant Generation
Ameren’s Merchant Generation segment has
experienced decreasing earnings and cash flows from
operating activities over the past few years, including in
2012, as margins have declined principally as a result of
weaker power prices. In addition, environmental regulations
have resulted in significant investment requirements over
the same time frame. During this period, Ameren has
increasingly focused on allocating its capital resources to
those opportunities that it believes offer the most attractive
risk-adjusted return potential, and specifically focused on
growing earnings from its rate-regulated operations
through investment under constructive regulatory
frameworks. Ameren has sought to have its Merchant
Generation segment fund its operations internally and not
rely on financing from Ameren. In December 2012, Ameren
determined that it intends to, and it is probable that it will,
exit its Merchant Generation business before the end of the
previously estimated useful lives of that business’s long-
lived assets. This determination resulted from Ameren’s
analysis of the current and projected future financial
condition of its Merchant Generation segment, including the
need to fund Genco debt maturities beginning in 2018, and
its conclusion that this segment is no longer a core
component of its future business strategy. In consideration
of this determination, Ameren has begun planning to
reduce, and ultimately eliminate, the Merchant Generation
segment’s reliance on Ameren’s financial support and
shared services support.
Ameren’s date and method of exit from the Merchant
Generation business is currently uncertain. Exit strategies
may include the sale of all or parts of the Merchant
Generation business or the restructuring of all or a portion
of Ameren’s equity position in Genco. Once a plan of
disposal is finalized, Ameren’s implementation of that plan
may result in long-lived asset impairments, disposal-related
losses, contingencies, reduction of existing deferred tax
assets, and other consequences that are currently unknown.
As a result of the December 2012 decision that Ameren
intends to, and it is probable that it will, exit the Merchant
Generation segment before the end of the Merchant
Generation long-lived assets’ previously estimated useful
lives, Ameren determined that estimated undiscounted cash
166
flows during the period in which it expects to continue to
own certain energy centers would be insufficient to recover
the carrying value of those energy centers. Accordingly,
Ameren recorded a noncash pretax impairment charge of
$1.95 billion in the fourth quarter of 2012 to reduce the
carrying values of all of the Merchant Generation’s coal and
natural gas-fired energy centers, except the Joppa coal-fired
energy center, to their estimated fair values. The estimated
undiscounted cash flows of the Joppa coal-fired energy
center exceeded its carrying value; therefore, the Joppa
coal-fired energy center was unimpaired. The net book
value of Ameren’s Merchant Generation long-lived assets
was $748 million as of December 31, 2012.
In early 2012, the observable market price for power
for delivery in that year and in future years in the Midwest
sharply declined below 2011 levels primarily because of
declining natural gas prices and the impact of the stay of
the CSAPR. As a result of this sharp decline in the market
price of power and the related impact on electric margins,
Genco decelerated the construction of two scrubbers at its
Newton energy center in February 2012. The sharp decline
in the market price of power in early 2012 and the related
impact on electric margins, as well as the deceleration of
construction of Genco’s Newton energy center scrubber
project, caused Merchant Generation to evaluate, during the
first quarter of 2012, whether the carrying values of its coal-
fired energy centers were recoverable. The carrying value of
AERG’s Duck Creek energy center’s carrying value exceeded
its estimated undiscounted future cash flows. As a result,
Ameren recorded a noncash pretax asset impairment
charge of $628 million to reduce the carrying value of that
energy center to its estimated fair value during the first
quarter of 2012.
In December 2011, Genco ceased operations of its
Meredosia and Hutsonville energy centers. As a result,
Ameren recorded a noncash pretax asset impairment
charge of $26 million to reduce the carrying value of the
Meredosia and Hutsonville energy centers to their estimated
fair values, a $4 million impairment of materials and
supplies, and $4 million for severance costs. See Note 1 –
Summary of Significant Accounting Policies for further
information regarding severance costs.
During the third quarter of 2010, the aggregate impact
of a sustained decline in market prices for electricity,
industry market multiples became observable at lower levels
than previously estimated, and potentially more stringent
environmental regulations being enacted caused Ameren to
evaluate if the carrying value of its Merchant Generation
energy centers were recoverable. The Meredosia energy
center’s carrying value and Medina Valley energy center’s
carrying value exceeded their estimated undiscounted future
cash flows. As a result, during 2010, Ameren recorded a
noncash pretax asset impairment charges of $101 million to
reduce the carrying value of the Meredosia and Medina
Valley energy centers to their estimated fair value. In 2012,
Ameren sold the Medina Valley energy center. See Note 1 –
Summary of Significant Accounting Policies for additional
information regarding that sale.
Key assumptions used in the determination of
estimated undiscounted cash flows of Ameren’s Merchant
Generation segment’s long-lived assets tested for
impairment included forward price projections for energy
and fuel costs, the expected life or duration of ownership of
the long-lived assets, environmental compliance costs and
strategies, and operating costs. Those same cash flow
assumptions, along with a discount rate and terminal year
earnings multiples, were used to estimate the fair value of
each energy center. These assumptions are subject to a
high degree of judgment and complexity. The fair value
estimate of these long-lived assets was based on a
combination of the income approach, which considers
discounted cash flows, and the market approach, which
considers market multiples for similar assets within the
electric generation industry. The fair value estimate was
determined using observable inputs and significant
unobservable inputs, which are Level 3 inputs as defined by
accounting guidance for fair value measurements.
Impairment within the Merchant Generation business
segment was assessed at the energy center level. Ameren
does not expect to incur material future cash expenditures
as a result of these impairments.
Ameren Missouri
During 2011, the MoPSC issued an electric rate order
that disallowed the recovery of all costs of enhancements,
or costs that would have been incurred absent the breach,
related to the rebuilding of the Taum Sauk energy center in
excess of the amount recovered from property insurance.
Consequently, Ameren and Ameren Missouri each recorded
a pretax charge to earnings of $89 million.
Goodwill
We evaluate goodwill for impairment as of October 31
of each year, or more frequently if events and
circumstances indicate that the asset might be impaired.
Goodwill impairment testing is a two-step process. The first
step involves a comparison of the estimated fair value of a
reporting unit with its carrying amount. If the estimated fair
value of the reporting unit exceeds the carrying value,
goodwill of the reporting unit is considered unimpaired. If
the carrying amount of the reporting unit exceeds its
estimated fair value, a second step is performed to measure
the amount of impairment, if any. The second step of the
goodwill impairment test compares the implied fair value of
the reporting unit’s goodwill with the carrying amount of
that goodwill. The implied fair value of goodwill is
determined by allocating the estimated fair value of the
reporting unit to the estimated fair value of its existing
assets and liabilities. The unallocated portion of the
estimated fair value of the reporting unit is the implied fair
value of goodwill. If the implied fair value of goodwill is less
than the carrying amount, an impairment loss equivalent to
the difference is recorded as a reduction of goodwill and a
charge to operating expense.
During the third quarter of 2010, we concluded that
events had occurred and circumstances had changed
167
which, when considered in the aggregate, indicated that it
was more likely than not that the fair value of Ameren’s
Merchant Generation reporting unit was less than its
carrying value. Such events and circumstances included the
sustained decline in market prices for electricity, industry
market multiples became observable at lower levels than
previously estimated, and potentially more stringent
environmental regulations being enacted. In July 2010, the
EPA issued the proposed CSAPR. The proposed CSAPR,
along with other pending regulations, was expected to
result in a significant increase in capital and operations and
maintenance expenditures for Ameren’s Merchant
Generation energy centers.
Ameren’s Merchant Generation reporting unit failed
step one of the 2010 interim impairment test, as the
reporting unit’s carrying value exceeded its estimated fair
value. Therefore, in order to measure the goodwill
impairment in step two, we estimated the implied fair value
of Ameren’s Merchant Generation goodwill. We determined
that the implied fair value of goodwill was less than the
carrying amount of goodwill, indicating that Ameren’s
Merchant Generation goodwill was impaired. Based on the
results of step two of the impairment test, Ameren recorded
a noncash impairment charge of $420 million, which
represented all of the goodwill assigned to Ameren’s
Merchant Generation reporting unit.
The fair value estimate of Ameren’s Merchant
Generation reporting unit was based on a combination of
the income approach, which considers discounted future
cash flows, and the market approach, which considers
market comparables within the electric generation industry.
Key assumptions in the determination of fair value included
the use of an appropriate discount rate, estimated five-year
cash flows, and observable industry market multiples. We
used our best estimates in making these evaluations. We
considered various factors, including forward price
projections for energy and fuel costs, environmental
compliance costs, and operating costs. The fair value
estimate was determined using observable inputs and
significant unobservable inputs, which are Level 3 inputs as
defined by accounting guidance for fair value
measurements.
Intangible Assets
Prior to 2010, Ameren’s Merchant Generation expected
to use its SO2 emission allowances for ongoing operations.
In July 2010, the EPA issued the proposed CSAPR, which
would have restricted the use of existing SO2 emission
allowances. As a result, Merchant Generation no longer
expected all of its SO2 emission allowances would be used
in operations. Therefore, during 2010, Ameren recorded a
$68 million pretax impairment charge to reduce the carrying
value of Merchant Generation’s SO2 emission allowances to
their estimated fair value.
In July 2011, the EPA issued CSAPR, which created
new allowances for SO2 and NOx emissions, and restricted
the use of preexisting SO2 and NOx allowances to the acid
rain program and to the NOx budget trading program,
respectively. As a result, observable market prices for
existing emission allowances declined materially.
Consequently, Ameren recorded a noncash pretax
impairment charge of $2 million relating to Merchant
Generation’s emission allowances. Ameren Missouri
recorded a $1 million impairment of its SO2 emission
allowances by reducing a previously established regulatory
liability relating to the SO2 emission allowance, which had
no impact on earnings.
The fair value of the SO2 and NOx emission allowances
was based on observable and unobservable inputs, which
were classified as Level 3 inputs for fair value
measurements.
NOTE 18 – SEGMENT INFORMATION
Ameren has three reportable segments: Ameren
Missouri, Ameren Illinois, and Merchant Generation. The
Ameren Missouri segment for both Ameren and Ameren
Missouri includes all the operations of Ameren Missouri’s
business as described in Note 1 – Summary of Significant
Accounting Policies. The Ameren Illinois Segment for both
Ameren and Ameren Illinois consists of all of the operations
of Ameren Illinois as described in Note 1 – Summary of
Significant Accounting Policies. The Merchant Generation
segment for Ameren consists primarily of the operations or
activities of AER, including Genco, EEI, AERG, and
Marketing Company. The category called Other primarily
includes Ameren parent company activities, Ameren
Services, and ATXI.
168
The following table presents information about the reported revenues and specified items reflected in Ameren’s net
income for the years ended December 31, 2012, 2011, and 2010, and total assets as of December 31, 2012, 2011, and 2010:
Ameren
Ameren
Missouri
Ameren
Illinois
Segment
Merchant
Generation
Other
Intersegment
Eliminations
Consolidated
2012
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Ameren Corporation(a) . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Ameren Corporation(a) . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Ameren Corporation(a) . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
3,251
21
440
32
223
252
416
595
13,043
3,358
25
408
30
209
161
287
550
12,757
3,176
21
382
31
213
199
364
624
12,504
$
$
$
2,509
16
221
-
129
94
141
442
7,282
2,774
13
215
1
136
127
193
351
7,213
3,002
12
210
1
143
137
208
281
7,406
$
$
$
$
$
$
1,063
310
102
-
95
(1,019)
(1,516)(b)
178
1,300
$
5
4
12
40
38
(7)
(15)
25
1,228
$
$
1,394
235
143
-
105
32
45
153
3,833
1,459
234
146
1
133
6
(409)(b)
101
3,934
5
4
19
44
44
(10)
(6)
(24)(c)
1,211
1
13
27
25
35
(17)
(24)
36
1,354
-
(351)
-
(39)
(37)
-
-
-
(1,018)
-
(277)
-
(43)
(43)
-
-
-
(1,369)
-
(280)
-
(25)
(27)
-
-
-
(1,687)
$ 6,828
-
775
33
448
(680)
(974)
1,240
21,835
$ 7,531
-
785
32
451
310
519
1,030
23,645
$ 7,638
-
765
33
497
325
139
1,042
23,511
(a) Represents net income (loss) available to common stockholders.
(b)
Includes noncash impairment and other charges, which were $2,578 million and $589 million before tax, recognized during the years ended
December 31, 2012, and 2010, respectively. See Note 17 – Impairment and Other Charges for additional information.
Includes the elimination of intercompany transfers.
(c)
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
Quarter Ended(a)
Ameren
March 31, 2012 . . . . . . . . . . . . . . . . . . .
March 31, 2011 . . . . . . . . . . . . . . . . . . .
June 30, 2012 . . . . . . . . . . . . . . . . . . . .
June 30, 2011 . . . . . . . . . . . . . . . . . . . .
September 30, 2012 . . . . . . . . . . . . . . .
September 30, 2011 . . . . . . . . . . . . . . .
December 31, 2012 . . . . . . . . . . . . . . . .
December 31, 2011 . . . . . . . . . . . . . . . .
Operating
Revenues
$
1,658
1,904
1,660
1,781
2,001
2,268
1,509
1,578
Operating
Income
(Loss)(b)
$
(422)
227
363
316
635
550
(1,816)
148
Net Income (Loss)
Attributable to
Ameren Corporation
Earnings (Loss) per
Common
Share – Basic and
Diluted
$
(403)
71
211
138
374
285
(1,156)
25
$
(1.66)
0.29
0.87
0.57
1.54
1.18
(4.76)
0.10
(a) The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the
(b)
effects of rounding and changes in the number of weighted-average shares outstanding each period.
Includes pretax “Impairment and other charges” of $2,578 million and $ 125 million recorded at Ameren during the years ended December 31,
2012, and 2011, respectively. See Note 17 – Impairment and Other Charges under Part II, Item 8, for additional information.
169
Operating
Revenues
Operating
Income
Net Income
(Loss)
Net Income (Loss)
Available to
Common
Stockholder
Quarter Ended
Ameren Missouri
March 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2012 . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2012 . . . . . . . . . . . . . . . . . . . .
September 30, 2011 . . . . . . . . . . . . . . . . . . . .
December 31, 2012 . . . . . . . . . . . . . . . . . . . . .
December 31, 2011 . . . . . . . . . . . . . . . . . . . . .
$ 691
772
844
822
1,064
1,115
673
674
$ 78
77
269
176
429
333
69
23
$ 22
22
144
91
237
191
16
(14)
Quarter Ended
Ameren Illinois
March 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2012 . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . .
Operating
Revenues
Operating
Income
Net
Income
$
724
808
564
623
648
745
589
611
$
89
88
86
99
151
196
51
75
$
28
34
33
38
71
98
12
26
$ 21
21
143
90
236
190
16
(14)
Net Income
Available to
Common
Stockholder
$
27
33
32
37
71
98
11
25
During preparation of the 2012 annual statements of cash flows, errors were identified in Ameren’s and Ameren
Missouri’s 2012 interim statements of cash flows. The errors, which were $14 million, $26 million, and $49 million through
the year-to-date first, second, and third quarters of 2012, respectively, are not considered material. The errors related to the
classification of certain activity from the nuclear decommissioning trust fund and increased operating cash flows and reduced
investing cash flows for each of these year-to-date periods. The 2012 interim statements of cash flows will be revised to
correct for these errors in the Ameren and Ameren Missouri 2013 Form 10-Q filings.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. 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 2012 fiscal year.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2012, 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 on those evaluations, as of December 31, 2012, the principal executive officer and principal
financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to
provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange
Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such
information is accumulated and communicated to its management, including its principal executive and principal financial
officers, to allow timely decisions regarding required disclosure.
(b) Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such
term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision of 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).
170
After making that evaluation, management concluded that each of the Ameren Companies’ internal control over financial
reporting was effective as of December 31, 2012. The effectiveness of Ameren’s internal control over financial reporting as of
December 31, 2012, 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 Ameren Missouri’s
or Ameren Illinois’ (the Subsidiary Registrants) independent registered public accounting firm regarding internal control over
financial reporting. Management’s report for each of the Subsidiary Registrants is not subject to attestation by the independent
registered public accounting firm.
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 internal controls might become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures might
deteriorate.
(c) Change in Internal Control
There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal
quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.
ITEM 9B. OTHER INFORMATION.
The Ameren Companies have no information reportable under this item that was required to be disclosed in a report on
SEC Form 8-K during the fourth quarter of 2012 that has not previously been reported on an SEC Form 8-K.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
PART III
Information required by Items 401, 405, 406 and
407(c)(3), (d)(4) and (d)(5) of SEC Regulation S-K for
Ameren will be included in its definitive proxy statement for
its 2013 annual meeting of shareholders filed pursuant to
SEC Regulation 14A; such information is incorporated
herein by reference. Information required by these SEC
Regulation S-K items for Ameren Missouri and Ameren
Illinois will be included in each company’s definitive
information statement for its 2013 annual meeting of
shareholders filed pursuant to SEC Regulation 14C; such
information is incorporated herein by reference. Specifically,
reference is made to the following sections of Ameren’s
definitive proxy statement and each of Ameren Missouri’s
and Ameren Illinois’ definitive information statement:
“Information Concerning Nominees to the Board of
Directors,” “Section 16(a) Beneficial Ownership Reporting
Compliance,” “Corporate Governance” and “Board
Structure.”
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.
Ameren Missouri and Ameren Illinois 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.
Walter J. Galvin serves as chairman of Ameren’s audit and
risk committee, and Stephen F. Brauer, Catherine S. Brune
and Ellen M. Fitzsimmons serve as members. The board of
directors of Ameren has determined that Walter J. Galvin
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 Ameren Missouri and Ameren Illinois use the
nominating and corporate governance committee of
Ameren’s board of directors to perform such committee
functions. This committee is responsible for the nomination
of directors and corporate governance practices. Ameren’s
nominating and corporate governance committee will
consider director nominations from stockholders in
accordance with its Policy Regarding Nominations of
Directors, which can be found on Ameren’s website:
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
president, the principal financial officer, the principal
accounting officer, the controller, and the treasurer of each
of the Ameren Companies. Ameren has also adopted a Code
of Business Conduct that applies to the directors, officers,
and employees of the Ameren Companies. It is referred to
as the Corporate Compliance Policy. The Ameren
Companies make available free of charge through Ameren’s
website (www.ameren.com) the Code of Ethics and the
Corporate Compliance Policy. Any amendment to the Code
of Ethics or the Corporate Compliance Policy and any
waiver from a provision of the Code of Ethics or the
Corporate Compliance Policy as it relates to the principal
executive officer, the president, the principal financial
officer, the principal accounting officer, the controller and
the treasurer of each of the Ameren Companies will be
posted on Ameren’s website within four business days
following the date of the amendment or waiver.
171
ITEM 11. EXECUTIVE COMPENSATION.
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 2013 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 Ameren Missouri and Ameren Illinois will be
included in each company’s definitive information statement for its 2013 annual meeting of shareholders filed pursuant to SEC
Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s
definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Executive
Compensation,” and “Human Resources Committee Interlocks and Insider Participation.”
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, 2012, with respect to the shares of Ameren’s common stock
that may be issued under its existing equity compensation plans:
Plan Category
Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
(a)
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
(b)
Number of Securities Remaining
Available for Future Issuance
Equity Compensation Plans (excluding
securities reflected in column (a))
(c)
Equity compensation plans approved by security
holders(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,813,814
Equity compensation plans not approved by
security holders . . . . . . . . . . . . . . . . . . . . . . . . .
-
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,813,814
(b)
-
(b)
1,577,354
-
1,577,354
(a) Consists of 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 2006 Omnibus Incentive Compensation Plan, 230,490
of the securities represent PSUs that vested as of December 31, 2012 (including accrued and reinvested dividends), and 1,538,204 of the
securities represent target PSUs granted but not vested (including accrued and reinvested dividends) as of December 31, 2012. The actual
number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level depending upon the achievement of total
shareholder return objectives established for such awards. For additional information about the PSUs, including payout calculations, see
“Compensation Discussion and Analysis – Long-Term Incentives: Performance Share Unit Program (PSUP)” in Ameren’s definitive proxy
statement for its 2013 annual meeting of shareholders filed pursuant to SEC Regulation 14A. 45,120 of the securities represent shares that may
be issued as of December 31, 2012, to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for members of the
board of directors.
(b) Earned PSUs and deferred compensation stock units are paid in shares of Ameren common stock on a one-for-one basis. Accordingly, the
PSUs and deferred compensation stock units have been excluded for purposes of calculating the weighted-average exercise price.
Ameren Missouri and Ameren Illinois 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 2013 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 Ameren Missouri and Ameren Illinois will be included in each
company’s definitive information statement for its 2013 annual meeting of shareholders filed pursuant to SEC Regulation 14C;
it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy
statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Security Ownership.”
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
Information required by Item 404 and Item 407(a) of SEC Regulation S-K for Ameren will be included in its definitive
proxy statement for its 2013 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by
reference. Information required by Item 404 and Item 407(a) of SEC Regulation S-K for Ameren Missouri and Ameren Illinois
will be included in each company’s definitive information statement for its 2013 annual meeting of shareholders filed pursuant
to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of
Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement:
“Policy and Procedures With Respect to Related Person Transactions” and “Director Independence.”
172
ITEM 14. PRINCIPAL ACCOUNTING 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 Ameren Missouri and Ameren Illinois for their 2013 annual
meetings of stockholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference.
Specifically, reference is made to the following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s
and Ameren Illinois’ definitive information statement: “Independent Registered Public Accounting Firm.”
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)(1) Financial Statements
Ameren
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income (Loss) – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Comprehensive Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet – December 31, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Stockholders’ Equity – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Union Electric Company
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Income and Comprehensive Income – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet – December 31, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Cash Flows – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Stockholders’ Equity – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income and Comprehensive Income – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . .
Balance Sheet – December 31, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Stockholders’ Equity – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)(2) Financial Statement Schedules
Schedule I – Condensed Financial Information of Parent – Ameren:
Condensed Statement of Income (Loss) and Comprehensive Income (Loss) – Years Ended December 31, 2012, 2011, and 2010 . . .
Condensed Balance Sheet – December 31, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condensed Statement of Cash Flows – Years Ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Schedule II – Valuation and Qualifying Accounts for the years ended December 31, 2012, 2011, and 2010 . . . . . . . . . . . . . . . . . . . . . . .
Page No.
82
84
85
86
87
88
83
89
90
91
92
83
93
94
95
96
174
174
175
176
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.
Exhibits are listed in the Exhibit Index commencing on page 180.
(b)
173
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010
(In millions)
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in earnings (loss) of subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income from affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Comprehensive Income (Loss), Net of Taxes:
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $12, $1,and
$(1), respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustments for derivative (gains) losses included in net income, net of income taxes
(benefit) of $1, $(3), and $5, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $22, $(32), and $6,
respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other comprehensive income (loss), net of taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012
2011
2010
$
-
-
22
(22)
(954)
40
4
39
(5)
(974)
22
(4)
32
50
-
-
15
(15)
527
44
4
41
(8)
519
3
4
(46)
(39)
$
-
372
24
(396)
535
28
3
56
(31)
139
(2)
(8)
4
(6)
Comprehensive Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(924) $
480
$
133
(In millions)
Assets:
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET
December 31, 2012
December 31, 2011
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Advances to money pool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts and notes receivable-affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Note receivable – affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
23
316
31
49
419
5,962
462
320
$
3
340
57
-
400
7,482
425
333
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
7,163
$
8,640
Liabilities and Stockholders’ Equity:
Short-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable – affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and Contingencies
Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6 . . . . . . . . . . .
Other paid-in capital, principally premium on common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive income (loss)
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
10
33
43
424
80
547
2
5,616
1,006
(8)
6,616
$
148
13
62
223
424
74
721
2
5,598
2,369
(50)
7,919
Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
7,163
$ 8,640
174
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010
(In millions)
Net cash flows provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from investing activities:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Money pool advances, net
Notes receivable – affiliates, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions from subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash flows provided by (used in) investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from financing activities:
Dividends on common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term debt and credit facility borrowings, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Issuances of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash flows used in financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at the end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash dividends received from consolidated subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncash financing activity – dividends on common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012
2011
2010
$
532
$
804
$
241
24
(20)
(2)
21
(5)
18
(382)
(148)
-
(530)
20
3
23
610
(7)
$
$
$
$
(276)
358
(94)
3
(5)
(14)
(375)
(481)
65
(791)
(1)
4
3
730
-
$
$
$
$
18
242
(13)
1
-
248
(368)
(221)
80
(509)
(20)
24
4
368
-
$
$
$
$
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2012
NOTE 1 – BASIS OF PRESENTATION
Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its
business operations through its subsidiaries. As specified in Note 5 – Long-term Debt and Equity Financings under Part II,
Item 8, of this report, there are restrictions on Ameren Corporation’s (parent company only) ability to obtain funds from
certain of its subsidiaries through dividends, loans or advances. In accordance with authoritative accounting guidance, Ameren
Corporation (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial
statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are
included within the combined notes under Part II, Item 8, of this report.
NOTE 2 – SHORT-TERM DEBT AND LIQUIDITY
See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for a description and details of short-term
debt and liquidity needs of Ameren Corporation (parent company only).
NOTE 3 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description and details of
long-term obligations of Ameren Corporation (parent company only).
NOTE 4 – COMMITMENTS AND CONTINGENCIES
See Note 14 – Related Party Transactions and Note 15 – Commitments and Contingencies under Part II Item 8, of this
report for a description of all material contingencies and guarantees outstanding of Ameren Corporation (parent company only).
NOTE 5 – IMPAIRMENTS
In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation
business before the end of the previously estimated useful lives of that business’s long-lived assets. This determination
resulted from Ameren’s analysis of the current and projected future financial condition of its Merchant Generation segment
and its conclusion that this segment is no longer a core component of its future business strategy. In consideration of this
determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation segment’s reliance on
Ameren’s financial support and shared services support. Ameren’s date and method of exit from the Merchant Generation
business is currently uncertain.
175
As a result of the announcement that Ameren intends to exit the Merchant Generation segment before the end of the
Merchant Generation’s long-lived assets’ previously estimated useful lives, Ameren determined that estimated undiscounted
cash flows during the period in which it expects to continue to own certain energy centers would be insufficient to recover the
carrying value of those energy centers. Accordingly, in the fourth quarter of 2012, Ameren Corporation (parent company only)
recorded a noncash pretax impairment charge of $1.88 billion to reduce its investment in certain of the Merchant Generation
segment’s coal and natural gas-fired energy centers to their estimated fair values. This charge was included within “Equity in
earnings (loss) of subsidiaries” in the Ameren Corporation (parent company only) Condensed Statement of Income (Loss) and
Comprehensive Income (Loss) for the year ended December 31, 2012.
During 2010, Ameren’s Merchant Generation reporting unit failed step one of the interim goodwill impairment test, as the
reporting unit’s carrying value exceeded its estimated fair value. Based on the results of step two of the goodwill impairment
test, Ameren Corporation (parent company only) recorded a noncash impairment charge of $345 million, which represented all
of the goodwill assigned to Ameren’s Merchant Generation reporting unit recorded at Ameren Corporation (parent company
only).
Prior to 2010, Ameren’s Merchant Generation expected to use its SO2 emission allowances for ongoing operations. In
July 2010, the EPA issued the proposed CSAPR, which would have restricted the use of existing SO2 emission allowances. As
a result, Merchant Generation no longer expected all of its SO2 emission allowances would be used in operations. Therefore,
during 2010, Ameren Corporation (parent company only) recorded a $27 million pretax impairment charge to reduce the
carrying value of SO2 emission allowances associated with Merchant Generation recorded at Ameren Corporation (parent
company only), to their estimated fair value.
See Note 17 – Impairment and Other Charges under Part II, Item 8, of this report for additional information on the
impairment charges recognized in 2012 and 2010.
(in millions)
Column A
Column B
Column C
Column D
Column E
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
Description
Ameren:
Deducted from assets – allowance for doubtful accounts:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax valuation allowance:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Missouri:
Deducted from assets – allowance for doubtful accounts:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax valuation allowance:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Illinois:
Deducted from assets – allowance for doubtful accounts:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax valuation allowance:
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at
Beginning
of Period
(1)
Charged to Costs
and Expenses
(2)
Charged to Other
Accounts(a)
Deductions(b)
Balance at End
of Period
$
$
$
$
$
$
20
23
24
2
2
-
7
8
6
1
1
-
13
13
17
-
-
-
$
$
$
$
$
$
30
41
33
2
-
2
11
17
14
-
-
1
19
24
18
1
-
-
$
$
$
$
$
$
2
-
-
-
-
-
-
-
-
-
-
-
2
-
-
-
-
-
$
$
$
$
$
$
35
44
34
-
-
-
13
18
12
-
-
-
22
24
22
-
-
-
$
$
$
$
$
$
17
20
23
4
2
2
5
7
8
1
1
1
12
13
13
1
-
-
(a) Uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers as required by
the Illinois Public Utility Act.
(b) Uncollectible accounts charged off, less recoveries.
176
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each
undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
SIGNATURES
Date: March 1, 2013
AMEREN CORPORATION (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/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
/s/ Bruce A. Steinke
Bruce A. Steinke
Stephen F. Brauer
Catherine S. Brune
Ellen M. Fitzsimmons
Walter J. Galvin
Gayle P.W. Jackson
James C. Johnson
Steven H. Lipstein
Patrick T. Stokes
Stephen R. Wilson
*
*
*
*
*
*
*
*
*
*
Jack D. Woodard
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
Chairman, President and
Chief Executive Officer, and Director
(Principal Executive Officer)
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Senior Vice President, Finance and
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
177
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
Date: March 1, 2013
UNION ELECTRIC COMPANY (registrant)
By /s/ Warner L. Baxter
Warner L. Baxter
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
/s/ Bruce A. Steinke
Bruce A. Steinke
Daniel F. Cole
Adam C. Heflin
Michael L. Moehn
Charles D. Naslund
*
*
*
*
*
Gregory L. Nelson
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
Chairman, President and
Chief Executive Officer, and Director
(Principal Executive Officer)
Executive Vice President and
Chief Financial Officer, and Director
(Principal Financial Officer)
Senior Vice President, Finance and
Chief Accounting Officer
(Principal Accounting)
Director
Director
Director
Director
Director
178
Date: March 1, 2013
AMEREN ILLINOIS COMPANY (registrant)
By /s/ Richard J. Mark
Richard J. Mark
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/ Richard J. Mark
Richard J. Mark
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
/s/ Bruce A. Steinke
Bruce A. Steinke
Daniel F. Cole
*
*
Gregory L. Nelson
*By /s/Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
Chairman, President and Chief Executive
Officer, Chief Executive Officer, and Director
(Principal Executive Officer)
Executive Vice President and Chief Financial
Officer, and Director (Principal Financial
Officer)
Senior Vice President, Finance and Chief
Accounting Officer (Principal Accounting
Officer)
Director
Director
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
March 1, 2013
179
EXHIBIT INDEX
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are
incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously
filed are filed herewith:
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1
Ameren Illinois
Agreement and Plan of Merger, dated as of
April 13, 2010, among CIPS, CILCO and IP
Annex A to Part I of the Registration
Statement on Form S-4,
File No. 333-166095).
Articles of Incorporation/ By-Laws
3.1(i)
3.2(i)
Ameren
Ameren
3.3(i)
Ameren
3.4(i)
Ameren
Restated Articles of Incorporation of Ameren
Annex F to Part I of the Registration
Statement on Form S-4, File No. 33-64165
Certificate of Amendment to Ameren’s
Restated Articles of Incorporation filed
December 14, 1998
Certificate of Amendment to Ameren’s
Restated Articles of Incorporation filed
April 21, 2011
Certificate of Amendment to Ameren’s
Restated Articles of Incorporation filed
December 18, 2012
1998 Form 10-K, Exhibit 3(i),
File No. 1-14756
April 21, 2011 Form 8-K, Exhibit 3(i),
File No. 1-14756
December 18, 2012 Form 8-K,
Exhibit 3.1(i), File No. 1-14756
3.5(i)
3.6(i)
Ameren Missouri
Ameren Illinois
3.7(ii)
Ameren
Restated Articles of Incorporation of Ameren
Missouri
1993 Form 10-K, Exhibit 3(i),
File No. 1-2967
Restated Articles of Incorporation of Ameren
Illinois
2010 Form 10-K, Exhibit 3.4(i),
File No. 1-3672
By-Laws of Ameren, as amended
December 14, 2012
December 18, 2012 Form 8-K,
Exhibit 3.1(ii), File No. 1-14756
3.8(ii)
Ameren Missouri
By-Laws of Ameren Missouri, as amended
December 10, 2010
December 15, 2010 Form 8-K,
Exhibit 3.1(ii), File No. 1-2967
3.9(ii)
Ameren Illinois
Bylaws of Ameren Illinois, as amended
December 10, 2010
December 15, 2010 Form 8-K,
Exhibit 3.2(ii), File No. 1-3672
Instruments Defining Rights of Security Holders, Including Indentures
4.1
Ameren
Ameren
Ameren
Ameren
Ameren Missouri
4.2
4.3
4.4
4.5
4.6
Indenture dated as of December 1, 2001
from Ameren to The Bank of New York
Mellon Trust Company, N.A., as successor
trustee, relating to senior debt securities
(Ameren Indenture)
Exhibit 4.5, File No. 333-81774
First Supplemental Indenture to Ameren
Senior Indenture dated as of May 19, 2008
June 30, 2008 Form 10-Q, Exhibit 4.1,
File No. 1-14756
May 15, 2009 Form 8-K,
Exhibits 4.3 and 4.4, File No. 1-14756
Exhibit B-1, File No. 2-4940
Ameren Indenture Company Order dated
May 15, 2009, establishing 8.875% Senior
Notes, due 2014 (including the global note)
Indenture of Mortgage and Deed of Trust
dated June 15, 1937 (Ameren Missouri
Mortgage), from Ameren Missouri to The
Bank of New York Mellon, as successor
trustee, as amended May 1, 1941, and
Second Supplemental Indenture dated
May 1, 1941
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren
Missouri Mortgage dated as of July 1, 1956
August 2, 1956 Form 8-K, Exhibit 2,
File No. 1-2967
Supplemental Indenture to the Ameren
Missouri Mortgage dated as of April 1,
1971
April 1971 Form 8-K, Exhibit 6,
File No. 1-2967
180
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren
Missouri Mortgage dated as of February 1,
1974
Supplemental Indenture to the Ameren
Missouri Mortgage dated as of July 7, 1980
Supplemental Indenture to the Ameren
Missouri Mortgage dated as of October 1,
1993, relative to Series 2028
Supplemental Indenture to the Ameren
Missouri Mortgage dated as of February 1,
2000
February 1974 Form 8-K, Exhibit 3,
File No. 1-2967
Exhibit 4.6, File No. 2-69821
1993 Form 10-K, Exhibit 4.8,
File No. 1-2967
2000 Form 10-K, Exhibit 4.1,
File No. 1-2967
Supplemental Indenture to the Ameren
Missouri Mortgage dated August 15, 2002
August 23, 2002 Form 8-K, Exhibit 4.3,
File No. 1-2967
Supplemental Indenture to the Ameren
Missouri Mortgage dated March 5, 2003,
relative to Series BB
Supplemental Indenture to the Ameren
Missouri Mortgage dated April 1, 2003,
relative to Series CC
Supplemental Indenture to the Ameren
Missouri Mortgage dated July 15, 2003,
relative to Series DD
Supplemental Indenture to the Ameren
Missouri Mortgage dated October 1, 2003,
relative to Series EE
Supplemental Indenture to the Ameren
Missouri Mortgage dated February 1, 2004,
relative to Series 2004A (1998A)
Supplemental Indenture to the Ameren
Missouri Mortgage dated February 1, 2004,
relative to Series 2004B (1998B)
Supplemental Indenture to the Ameren
Missouri Mortgage dated February 1, 2004,
relative to Series 2004C (1998C)
Supplemental Indenture to the Ameren
Missouri Mortgage dated February 1, 2004,
relative to Series 2004H (1992)
Supplemental Indenture to the Ameren
Missouri Mortgage dated May 1, 2004
relative to Series FF
Supplemental Indenture to the Ameren
Missouri Mortgage dated September 1,
2004 relative to Series GG
Supplemental Indenture to the Ameren
Missouri Mortgage dated January 1, 2005
relative to Series HH
Supplemental Indenture to the Ameren
Missouri Mortgage dated July 1, 2005
relative to Series II
Supplemental Indenture to the Ameren
Missouri Mortgage dated December 1,
2005 relative to Series JJ
Supplemental Indenture to the Ameren
Missouri Mortgage dated June 1, 2007
relative to Series KK
181
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 4.8,
File No. 1-2967
May 18, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
September 23, 2004 Form 8-K,
Exhibit 4.4, File No. 1-2967
January 27, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
July 21, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
December 9, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
June 15, 2007 Form 8-K, Exhibit 4.5,
File No. 1-2967
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
4.36
4.37
4.38
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
April 8, 2008 Form 8-K, Exhibit 4.7,
File No. 1-2967
June 19, 2008 Form 8-K, Exhibit 4.5,
File No. 1-2967
March 23, 2009 Form 8-K, Exhibit 4.5,
File No. 1-2967
Exhibit 4.45, File No. 333-182258
September 11, 2012 Form 8-K, Exhibit 4.4,
File No. 1-2967
1992 Form 10-K, Exhibit 4.38,
File No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.10,
File No. 1-2967
September 30, 1998 Form 10-Q,
Exhibit 4.28, File No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.11,
File No. 1-2967
September 30, 1998 Form 10-Q,
Exhibit 4.29, File No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.12,
File No. 1-2967
September 30, 1998 Form 10-Q,
Exhibit 4.30, File No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.13,
File No. 1-2967
Supplemental Indenture to the Ameren
Missouri Mortgage dated April 1, 2008
relative to Series LL
Supplemental Indenture to the Ameren
Missouri Mortgage dated June 1, 2008
relative to Series MM
Supplemental Indenture to the Ameren
Missouri Mortgage dated March 1, 2009
relative to Series NN
Supplemental Indenture to the Ameren
Missouri Mortgage dated May 15, 2012
Supplemental Indenture to the Ameren
Missouri Mortgage dated September 1,
2012 relative to Series OO
Loan Agreement dated as of December 1,
1992, between the Missouri Environmental
Authority and Ameren Missouri, 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 Ameren
Missouri
Series 1998A Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and Ameren
Missouri
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
Ameren Missouri
Series 1998B Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and Ameren
Missouri
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
Ameren Missouri
Series 1998C Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and Ameren
Missouri
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
Ameren Missouri
182
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.39
4.40
4.41
4.42
4.43
4.44
4.45
4.46
4.47
4.48
4.49
4.50
4.51
4.52
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Missouri
August 23, 2002 Form 8-K, Exhibit 4.1,
File No. 1-2967
Exhibit 4.48, File No. 333-182258
March 11, 2003 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
April 10, 2003 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
August 4, 2003 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
October 8, 2003 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
May 18, 2004 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
September 23, 2004 Form 8-K, Exhibits 4.2
and 4.3, File No. 1-2967
January 27, 2005 Form 8-K, Exhibits 4.2
and 4.3, File No. 1-2967
July 21, 2005 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
December 9, 2005 Form 8-K, Exhibits 4.2
and 4.3, File No. 1-2967
June 15, 2007 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
April 8, 2008 Form 8-K, Exhibits 4.3 and
4.5, File No. 1-2967
June 19, 2008 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
Indenture dated as of August 15, 2002,
from Ameren Missouri to The Bank of New
York Mellon, as successor trustee (relating
to senior secured debt securities) (Ameren
Missouri Indenture)
First Supplemental Indenture to the Ameren
Missouri Indenture, dated as of May 15,
2012
Ameren Missouri Indenture Company Order
dated March 10, 2003, establishing the
5.50% Senior Secured Notes due 2034
(including the global note)
Ameren Missouri Indenture Company Order
dated April 9, 2003, establishing the 4.75%
Senior Secured Notes due 2015 (including
the global note)
Ameren Missouri Indenture Company Order
dated July 28, 2003, establishing the 5.10%
Senior Secured Notes due 2018 (including
the global note)
Ameren Missouri Indenture Company Order
dated October 7, 2003, establishing the
4.65% Senior Secured Notes due 2013
(including the global note)
Ameren Missouri Indenture Company Order
dated May 13, 2004, establishing the
5.50% Senior Secured Notes due 2014
(including the global note)
Ameren Missouri Indenture Company Order
dated September 1, 2004, establishing the
5.10% Senior Secured Notes due 2019
(including the global note)
Ameren Missouri Indenture Company Order
dated January 27, 2005, establishing the
5.00% Senior Secured Notes due 2020
(including the global note)
Ameren Missouri Indenture Company Order
dated July 21, 2005, establishing the 5.30%
Senior Secured Notes due 2037 (including
the global note)
Ameren Missouri Indenture Company Order
dated December 8, 2005, establishing the
5.40% Senior Secured Notes due 2016
(including the global note)
Ameren Missouri Indenture Company Order
dated June 15, 2007, establishing the
6.40% Senior Secured Notes due 2017
(including the global note)
Ameren Missouri Indenture Company Order
dated April 8, 2008, establishing the 6.00%
Senior Secured Notes due 2018 (including
the global note)
Ameren Missouri Indenture Company Order
dated June 19, 2008, establishing the
6.70% Senior Secured Notes due 2019
(including the global note)
183
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
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
4.67
Ameren
Ameren Missouri
Ameren
Ameren Missouri
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
March 23, 2009 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
September 30, 2012 Form 10-Q, Exhibit 4.1
and September 11, 2012 Form 8-K,
Exhibit 4.2, File No. 1-2967
Exhibit 4.4, File No. 333-59438
Ameren Missouri Indenture Company Order
dated March 20, 2009, establishing 8.45%
Senior Secured Notes due 2039 (including
the global note)
Ameren Missouri Indenture Company Order
dated September 11, 2012, establishing
3.90% Senior Secured Notes due 2042
(including the global note)
Indenture dated as of December 1, 1998,
from Central Illinois Public Service
Company (now known as Ameren Illinois)
to The Bank of New York Mellon Trust
Company, N.A., as successor trustee (CIPS
Indenture)
First Supplemental Indenture to the CIPS
Indenture, dated as of June 14, 2006
June 19, 2006 Form 8-K, Exhibit 4.2,
File No. 1-3672
Second Supplemental Indenture to the CIPS
Indenture, dated as of March 1, 2010
Exhibit 4.17, File No. 333-166095
Third Supplemental Indenture to the CIPS
Indenture, dated as of October 1, 2010
2010 Form 10-K, Exhibit 4.59,
File No. 1-3672
2010 Form 10-K, Exhibit 4.60,
File No. 1-3672
2010 Form 10-K, Exhibit 4.62,
File No. 1-3672
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
Ameren Illinois Global Note, dated October
1, 2010, representing CIPS Indenture
Senior Notes, 6.125% due 2028
Ameren Illinois Global Note, dated October
1, 2010, representing CIPS Indenture
Senior Notes, 6.70% Series Secured Notes
due 2036
Indenture of Mortgage and Deed of Trust
between Illinois Power Company
(predecessor in interest to CILCO and
Ameren Illinois) and Bankers Trust
Company (now known as Deutsche Bank
Trust Company Americas), 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
(predecessor in interest to Ameren Illinois)
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
December 1949 Form 8-K, Exhibit A,
File No. 1-2732
Supplemental Indenture to the CILCO
Mortgage, dated July 1, 1957
July 1957 Form 8-K, Exhibit A,
File No. 1-2732
Supplemental Indenture to the CILCO
Mortgage, dated February 1, 1966
February 1966 Form 8-K, Exhibit A,
File No. 1-2732
Supplemental Indenture to the CILCO
Mortgage, dated January 15, 1992
January 30, 1992 Form 8-K, Exhibit 4(b),
File No. 1-2732
Supplemental Indenture to the CILCO
Mortgage, dated June 1, 2006 for the
Series AA and BB
Supplemental Indenture to the CILCO
Mortgage, dated December 1, 2008 for the
Series CC
June 19, 2006 Form 8-K, Exhibit 4.11,
File No. 1-2732
December 9, 2008 Form 8-K, Exhibit 4.5,
File No. 1-2732
184
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.68
4.69
4.70
4.71
4.72
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
4.73
Ameren Ameren Illinois
4.74
Ameren
Ameren Illinois
4.75
4.76
4.77
4.78
4.79
4.80
4.81
4.82
4.83
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Supplemental Indenture to the CILCO
Mortgage, dated as of October 1, 2010
October 7, 2010 Form 8 K, Exhibit 4.4,
File No. 1-14756
Indenture dated as of June 1, 2006, from
CILCO (predecessor in interest to Ameren
Illinois) to The Bank of New York Mellon
Trust Company, N.A., as successor trustee
(CILCO Indenture)
June 19, 2006 Form 8-K, Exhibit 4.3,
File No. 1-2732
First Supplemental Indenture to the CILCO
Indenture, dated October 1, 2010
October 7, 2010 Form 8 K, Exhibit 4.1,
File No. 1-3672
Second Supplemental Indenture to the
CILCO Indenture dated as of July 21, 2011
September 30, 2011 Form 10-Q,
Exhibit 4.1, File No. 1-3672
June 19, 2006 Form 8-K, Exhibit 4.6,
File No. 1-2732
December 9, 2008 Form 8-K, Exhibits 4.2
and 4.3, File No. 1-2732
1992 Form 10-K, Exhibit 4(cc),
File No. 1-3004
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
December 23, 2002 Form 8-K, Exhibit 4.1,
File No. 1-3004
June 19, 2006 Form 8-K, Exhibit 4.13,
File No. 1-3004
November 20, 2007 Form 8-K, Exhibit 4.4,
File No. 1-3004
April 8, 2008 Form 8-K, Exhibit 4.9,
File No. 1-3004
October 23, 2008 Form 8-K, Exhibit 4.4,
File No. 1-3004
CILCO Indenture Company Order, dated
June 14, 2006, establishing the 6.20%
Senior Secured Notes due 2016 (including
the global note) and the 6.70% Senior
Secured Notes due 2036 (including the
global note)
CILCO Indenture Company Order, dated
December 9, 2008, establishing the 8.875%
Senior Secured Notes due 2013 (including
the global note)
General Mortgage Indenture and Deed of
Trust dated as of November 1, 1992
between Illinois Power Company
(predecessor in interest to Ameren Illinois)
and The Bank of New York Mellon Trust
Company, N.A., as successor trustee
(Ameren Illinois Mortgage)
Supplemental Indenture dated as of
March 1, 1998, to Ameren Illinois Mortgage
for Series S
Supplemental Indenture dated as of
March 1, 1998, to Ameren Illinois Mortgage
for Series T
Supplemental Indenture amending the
Ameren Illinois Mortgage dated as of
June 15, 1999
Supplemental Indenture dated as of July
15, 1999, to Ameren Illinois Mortgage for
Series U
Supplemental Indenture amending the
Ameren Illinois Mortgage dated as of
December 15, 2002
Supplemental Indenture dated as of June 1,
2006, to Ameren Illinois Mortgage for
Series AA
Supplemental Indenture dated as of
November 15, 2007, to Ameren Illinois
Mortgage for Series BB
Supplemental Indenture dated as of April 1,
2008, to Ameren Illinois Mortgage for
Series CC
Supplemental Indenture dated as of
October 1, 2008, to Ameren Illinois
Mortgage for Series DD
185
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.84
4.85
4.86
4.87
4.88
4.89
4.90
4.91
4.92
4.93
4.94
4.95
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
Ameren
Ameren Illinois
4.96
Ameren
4.97
Ameren
4.98
Ameren
October 7, 2010 Form 8 K, Exhibit 4.9,
File No. 1-3672
Exhibit 4.78, File No. 333-182258
August 20, 2012 Form 8-K, Exhibit 4.4,
File No. 1-3672
June 19, 2006 Form 8-K, Exhibit 4.4,
File No. 1-3004
October 7, 2010 Form 8 K, Exhibit 4.5,
File No. 1-14756
September 30, 2011 Form 10-Q,
Exhibit 4.2, File No. 1-3672
Exhibit 4.83, File No. 333-182258
June 19, 2006 Form 8-K, Exhibit 4.7,
File No. 1-3004
November 20, 2007 Form 8-K, Exhibit 4.2,
File No. 1-3004
April 8, 2008 Form 8-K, Exhibit 4.4,
File No. 1-3004
October 23, 2008 Form 8-K, Exhibit 4.2,
File No. 1-3004
August 20, 2012 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-3004
Exhibit 4.1, File No. 333-56594
June 30, 2002 Form 10-Q, Exhibit 4.1,
File No. 1-14756
2002 Form 10-K, Exhibit 4.5,
File No. 1-14756
Supplemental Indenture, dated as of
October 1, 2010, to Ameren Illinois
Mortgage for Series CIPS-AA, CIPS-BB and
CIPS-CC
Supplemental Indenture, dated as of
January 15, 2011, to Ameren Illinois
Mortgage
Supplemental Indenture dated as of
August 1, 2012, to Ameren Illinois
Mortgage for Series EE
Indenture, dated as of June 1, 2006 from IP
(predecessor in interest to Ameren Illinois)
to The Bank of New York Mellon Trust
Company, N.A., as successor trustee
(Ameren Illinois Indenture)
First Supplemental Indenture, dated as of
October 1, 2010, to the Ameren Illinois
Indenture for Series CIPS-AA, CIPS-BB and
CIPS-CC
Second Supplemental Indenture to the
Ameren Illinois Indenture dated as of
July 21, 2011
Third Supplemental Indenture to the
Ameren Illinois Indenture dated as of
May 15, 2012
Ameren Illinois Indenture Company Order,
dated June 14, 2006, establishing the
6.25% Senior Secured Notes due 2016
(including the global note)
Ameren Illinois Indenture Company Order,
dated November 15, 2007, establishing
6.125% Senior Secured Notes due 2017
(including the global note)
Ameren Illinois Indenture Company Order,
dated April 8, 2008, establishing 6.25%
Senior Secured Notes due 2018 (including
the global note)
Ameren Illinois Indenture Company Order
dated October 23, 2008, establishing 9.75%
Senior Secured Notes due 2018 (including
the global note)
Ameren Illinois Indenture Company Order
dated August 20, 2012, establishing 2.70%
Senior Secured Notes due 2022 (including
the global note)
Indenture dated as of November 1, 2000,
from Genco to The Bank of New York
Mellon Trust Company, N.A., as successor
trustee (Genco Indenture)
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
186
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.99
Ameren
4.100
Ameren
4.101
Ameren
Material Contracts
10.1
Ameren
Ameren Illinois
10.2
Ameren Companies
10.3
Ameren
10.4
10.5
10.6
10.7
10.8
Ameren
Ameren Missouri
Ameren
Ameren Illinois
Ameren
Ameren
Ameren
10.9
Ameren
10.10
Ameren Companies
10.11
Ameren Companies
10.12
Ameren Companies
Fifth Supplemental Indenture dated as of
April 1, 2008, to Genco Indenture, relating
to Genco 7.00% Senior Notes, Series G due
2018
Sixth Supplemental Indenture, dated as of
July 7, 2008, to Genco Indenture, relating
to Genco 7.00% Senior Notes, Series H due
2018
Seventh Supplemental Indenture, dated as
of November 1, 2009, to Genco Indenture,
relating to Genco 6.30% Senior Notes,
Series l due 2020
Unilateral Borrowing Agreement by and
among Ameren, IP (predecessor in interest
to Ameren Illinois) and Ameren Services,
dated as of September 30, 2004
Third Amended Ameren Corporation
System Utility Money Pool Agreement, as
amended September 30, 2004
Ameren Corporation System Amended and
Restated Non- Regulated Subsidiary Money
Pool Agreement, dated March 1, 2008
Credit Agreement, dated as of
November 14, 2012, by and among
Ameren, Ameren Missouri and JPMorgan
Chase Bank, N.A., as agent, and the lenders
party thereto.
Credit Agreement, dated as of
November 14, 2012, by and among
Ameren, Ameren Illinois and JPMorgan
Chase Bank, N.A., as agent, and the lenders
party thereto.
April 9, 2008 Form 8-K, Exhibit 4.2,
File No. 1-14756
Exhibit No. 4.55, File No. 333-155416
November 17, 2009 Form 8-K, Exhibit 4.8,
File No. 1-14756
October 1, 2004 Form 8-K, Exhibit 10.3,
File No. 1-3004
October 1, 2004 Form 8-K, Exhibit 10.2,
File No. 1-14756
March 31, 2008 Form 10-Q, Exhibit 10.1,
File No. 1-14756
November 15, 2012 Form 8-K, Exhibit 10.1,
File No. 1-14756
November 15, 2012 Form 8-K, Exhibit 10.2,
File No. 1-14756
Put Option Agreement, dated as of
March 28, 2012, between Genco and AERG
March 28, 2012 Form 8-K, Exhibit 10.1,
File No. 1-14756
Guaranty, dated as of March 28, 2012,
made by Ameren in favor of Genco
March 28, 2012 Form 8-K, Exhibit 10.2,
File No. 1-14756
*Summary Sheet of Ameren Corporation
Non- Management Director Compensation
revised on August 8, 2008
*Ameren’s Deferred Compensation Plan for
Members of the Board of Directors
amended and restated effective January 1,
2009, dated June 13, 2008
*Amendment dated October 12, 2009, to
Ameren’s Deferred Compensation Plan for
Members of the Board of Directors,
effective January 1, 2010
*Amendment dated October 14, 2010, to
Ameren’s Deferred Compensation Plan for
Members of the Board of Directors
*Ameren’s Deferred Compensation Plan as
amended and restated effective January 1,
2010
September 30, 2008 Form 10-Q,
Exhibit 10.1, File No. 1-14756
June 30, 2008 Form 10-Q, Exhibit 10.3,
File No. 1-14756
2009 Form 10-K, Exhibit 10.15 ,
File No. 1-14756
2010 Form 10-K, Exhibit 10.15,
File No. 1-14756
October 14, 2009 Form 8-K, Exhibit 10.1,
File No. 1-14756
10.13
Ameren Companies
*Amendment dated October 14, 2010 to
Ameren’s Deferred Compensation Plan
2010 Form 10-K, Exhibit 10.17,
File No. 1-14756
187
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.14
Ameren Companies
*2012 Ameren Executive Incentive Plan
10.15
Ameren Companies
*2013 Ameren Executive Incentive Plan
December 14, 2011 Form 8-K, Exhibit 10.1,
File No. 1-14756
December 18, 2012 Form 8-K, Exhibit 10.1,
File No. 1-14756
10.16
Ameren Companies
*2012 Base Salary Table for Named
Executive Officers
2011 Form 10-K, Exhibit 10.23,
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 Companies
10.24
Ameren Companies
*2013 Base Salary Table for Named
Executive Officers
*Second Amended and Restated Ameren
Corporation Change of Control Severance
Plan
*First Amendment dated October 12, 2009,
to the Second Amended and Restated
Ameren Change of Control Severance Plan
*Revised Schedule I to Second Amended
and Restated Ameren Change of Control
Severance Plan, as amended
*Formula for Determining 2010 Target
Performance Share Unit Awards to be
Issued to Named Executive Officers
*Formula for Determining 2011 Target
Performance Share Unit Awards to be
Issued to Named Executive Officers
*Formula for Determining 2012 Target
Performance Share Unit Awards to be
Issued to Named Executive Officers
*Formula for Determining 2013 Target
Performance Share Unit Awards to be
Issued to Named Executive Officers
2008 Form 10-K, Exhibit 10.37,
File No. 1-14756
October 14, 2009 Form 8-K, Exhibit 10.2,
File No. 1-14756
September 30, 2012 Form 10-Q,
Exhibit 10.2, File No. 1-14756
December 17, 2009 Form 8-K, Exhibit 99.1,
File No. 1-14756
December 15, 2010 Form 8-K, Exhibit 99.1,
File No. 1-14756
December 14, 2011 Form 8-K, Exhibit 99.1,
File No. 1-14756
December 18, 2012 Form 8-K, Exhibit 99.1,
File No. 1-14756
10.25
Ameren Companies
*Ameren Corporation 2006 Omnibus
Incentive Compensation Plan
February 16, 2006 Form 8-K, Exhibit 10.3,
File No. 1-14756
10.26
Ameren Companies
10.27
Ameren Companies
10.28
Ameren Companies
10.29
Ameren Companies
10.30
Ameren Companies
10.31
Ameren Companies
10.32
Ameren Companies
*Form of Performance Share Unit Award
Agreement for Award Issued in 2010
pursuant to 2006 Omnibus Incentive
Compensation Plan
*Form of Performance Share Unit Award
Agreement for Award Issued in 2011
pursuant to 2006 Omnibus Incentive
Compensation Plan
*Form of Performance Share Unit Award
Agreement for Awards Issued in 2012
pursuant to 2006 Omnibus Incentive
Compensation Plan
*Form of Performance Share Unit Award
Agreement for Awards Issued in 2013
pursuant to 2006 Omnibus Incentive
Compensation Plan
*Performance Stock Bonus Award
Agreement, dated March 1, 2011, between
Ameren and Adam C. Heflin
*Ameren Supplemental Retirement Plan
amended and restated effective January 1,
2008, dated June 13, 2008
*First Amendment to amended and restated
Ameren Supplemental Retirement Plan,
dated October 24, 2008
188
December 17, 2009 Form 8-K, Exhibit 10.2,
File No. 1-14756
December 15, 2010 Form 8-K, Exhibit 10.2,
File No. 1-14756
December 14, 2011 Form 8-K, Exhibit 10.2,
File No. 1-14756
December 18, 2012 Form 8-K, Exhibit 10.2,
File No. 1-14756
March 31, 2011 Form 10-Q, Exhibit 10.1,
File No. 1-14756
June 30, 2008 Form 10-Q, Exhibit 10.1,
File No. 1-14756
2008 Form 10-K, Exhibit 10.44,
File No. 1-14756
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.33
Ameren Ameren Illinois
*CILCO Executive Deferral Plan as amended
effective August 15, 1999
1999 Form 10-K, Exhibit 10,
File No. 1-2732
10.34
Ameren Ameren Illinois
*CILCO Executive Deferral Plan II as
amended effective April 1, 1999
1999 Form 10-K, Exhibit 10(a),
File No. 1-2732
10.35
Ameren Ameren Illinois
*CILCO Restructured Executive Deferral
Plan (approved August 15, 1999)
1999 Form 10-K, Exhibit 10(e),
File No. 1-2732
10.36
Ameren Illinois
Separation Agreement, effective as of
September 4, 2012, between Scott A. Cisel
and Ameren Illinois
September 30, 2012 Form 10-Q,
Exhibit 10.1, File No. 1-3672
Statement re: Computation of Ratios
12.1
12.2
Ameren
Ameren Missouri
12.3
Ameren Illinois
Ameren’s Statement of Computation of
Ratio of Earnings to Fixed Charges
Ameren Missouri’s Statement of
Computation of Ratio of Earnings to Fixed
Charges and Combined Fixed Charges and
Preferred Stock Dividend Requirements
Ameren Illinois’ Statement of Computation
of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred
Stock Dividend Requirements
Code of Ethics
14.1
Ameren Companies
Code of Ethics, as amended February 8,
2013
Subsidiaries of the Registrant
21.1
Ameren Companies
Subsidiaries of Ameren
Consent of Experts and Counsel
23.1
23.2
Ameren
Ameren Missouri
23.3
Ameren Illinois
Power of Attorney
Consent of Independent Registered Public
Accounting Firm with respect to Ameren
Consent of Independent Registered Public
Accounting Firm with respect to Ameren
Missouri
Consent of Independent Registered Public
Accounting Firm with respect to Ameren
Illinois
24.1
24.2
24.3
Ameren
Power of Attorney with respect to Ameren
Ameren Missouri
Ameren Illinois
Power of Attorney with respect to Ameren
Missouri
Power of Attorney with respect to Ameren
Illinois
Rule 13a-14(a)/15d-14(a) Certifications
31.1
31.2
31.3
Ameren
Ameren
Ameren Missouri
31.4
Ameren Missouri
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 Ameren
Missouri
Rule 13a-14(a)/15d-14(a) Certification of
Principal Financial Officer of Ameren
Missouri
189
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
31.5
Ameren Illinois
31.6
Ameren Illinois
Rule 13a-14(a)/15d-14(a) Certification of
Principal Executive Officer of Ameren
Illinois
Rule 13a-14(a)/15d-14(a) Certification of
Principal Financial Officer of Ameren Illinois
Section 1350 Certifications
32.1
Ameren
32.2
Ameren Missouri
32.3
Ameren Illinois
Additional Exhibits
99.1
Ameren Companies
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 Ameren Missouri
Section 1350 Certification of Principal
Executive Officer and Principal Financial
Officer of Ameren Illinois
Amended and Restated Tax Allocation
Agreement, dated as of September 30,
2004
Interactive Data File
101.INS**
Ameren Companies
XBRL Instance Document
101.SCH**
Ameren Companies
101.CAL**
Ameren Companies
101.LAB**
Ameren Companies
101.PRE**
Ameren Companies
101.DEF**
Ameren Companies
XBRL Taxonomy Extension Schema
Document
XBRL Taxonomy Extension Calculation
Linkbase Document
XBRL Taxonomy Extension Label Linkbase
Document
XBRL Taxonomy Extension Presentation
Linkbase Document
XBRL Taxonomy Extension Definition
Document
The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; Ameren Missouri,
1-2967; and Ameren Illinois, 1-3672.
*Compensatory plan or arrangement.
**Attached as Exhibit 101 to this report is the following financial information for each of the Ameren Companies’ Annual
Report on Form 10-K for the year ended December 31, 2012, formatted in XBRL (eXtensible Business Reporting Language):
(i) the Consolidated Statement of Income (Loss) for the years ended December 31, 2012, 2011, and 2010, (ii) the
Consolidated Statement of Comprehensive Income (Loss) for the years ended December 31, 2012, 2011 and 2010, (iii) the
Consolidated Balance Sheet at December 31, 2012 and December 31, 2011, (iv) the Consolidated Statement of Cash Flows for
the years ended December 31, 2012, 2011, and 2010, (v) the Consolidated Statement of Stockholders’ Equity for the years
ended December 31, 2012, 2011, and 2010, and (vi) the Combined Notes to the Financial Statements for the year ended
December 31, 2012. For Ameren Missouri and Ameren Illinois, these exhibits are deemed furnished and not filed pursuant to
Rule 406T of Regulation S-T.
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed
above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of
Regulation S-K.
190
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, Thomas R. Voss, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2012, 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)
b)
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
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
Date: March 1, 2013
/s/ Thomas R. Voss
Thomas R. Voss
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF AMEREN CORPORATION
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.2
I, Martin J. Lyons, Jr., certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2012, 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)
b)
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
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
Date: March 1, 2013
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
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, Warner L. Baxter, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2012, 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)
b)
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
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
Date: March 1, 2013
/s/ Warner L. Baxter
Warner L. Baxter
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, Martin J. Lyons, Jr., certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2012, 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)
b)
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
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
Date: March 1, 2013
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN ILLINOIS COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.5
I, Richard J. Mark, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2012, of Ameren Illinois 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)
b)
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
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
Date: March 1, 2013
/s/ Richard J. Mark
Richard J. Mark
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ILLINOIS COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.6
I, Martin J. Lyons, Jr., certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2012, of Ameren Illinois 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)
b)
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
Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
Date: March 1, 2013
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
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, 2012, of Ameren Corporation (the
“Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”),
each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of
the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934 (15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: March 1, 2013
/s/ Thomas R. Voss
Thomas R. Voss
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
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, 2012, of Union Electric Company (the
“Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”),
each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of
the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934 (15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: March 1, 2013
/s/ Warner L. Baxter
Warner L. Baxter
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
SECTION 1350 CERTIFICATION OF
AMEREN ILLINOIS 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, 2012, of Ameren Illinois Company
(the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the
“Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted
pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934 (15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: March 1, 2013
/s/ Richard J. Mark
Richard J. Mark
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
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 60,768 on December
31, 2012. The following table provides the closing price ranges
and dividends declared per Ameren common share for each
quarter of 2012 and 2011.
AEE 2012
Quarter Ended
High
Low
Close
Dividends
Declared
March 31
June 30
September 30
December 31
AEE 2011
Quarter Ended
March 31
June 30
September 30
December 31
$33.68
34.04
35.30
$30.89
31.15
32.27
33.21
28.43
$32.58
40 ¢
33.54
32.67
30.72
40
40
40
High
Low
Close
$29.14
30.14
31.44
$26.46
27.78
25.55
34.11
27.98
$28.07
28.84
29.77
33.13
Dividends
Declared
38 1⁄2 ¢
38 1⁄2
38 1⁄2
40
Direct Deposit of Dividends
All registered Ameren common and Ameren Illinois Company
and Union Electric Company preferred shareholders can have
their cash dividends automatically deposited to their bank
accounts. This service gives shareholders immediate access
to their dividend on the dividend payment date and eliminates
the possibility of lost or stolen dividend checks.
Corporate Governance Documents
Ameren makes available, free of charge through its website
(ameren.com), the charters of the board of directors’ audit
and risk committee, human resources committee, nominating
and corporate governance committee, finance committee and
nuclear oversight and environmental committee. Also available
on Ameren’s website are its corporate governance guidelines,
policy regarding nominations of directors, policy regarding
communications to the board of directors, policy and
procedures with respect to related person transactions, code
of business conduct (referred to as the “Corporate Compliance
Policy”) and 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 website, 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 any chief executive
officer and chief financial officer certifications required to be
filed with the Securities and Exchange Commission therewith.
Annual Meeting
The annual meeting of Ameren Corporation shareholders will
convene at 9 a.m. (Central Time), Tuesday, April 23, 2013, at Powell
Symphony Hall, 718 North Grand Boulevard, St. Louis, MO, 63103.
The annual shareholder meetings of Ameren Illinois Company and
Union Electric Company will be held at the same time.
Online Stock Account Access
Ameren’s website (ameren.com) allows registered
shareholders to access their account information online.
Shareholders can securely change their reinvestment options,
view account summaries, receive DRPlus statements and more
through the website. This is a free service.
DRPlus
Any person of legal age or entity, whether or not an
Ameren shareholder, is eligible to participate in DRPlus,
Ameren’s dividend reinvestment and stock purchase plan.
Participants can:
(cid:129) make cash investments by check or automatic direct debit
from their bank accounts to purchase Ameren common stock,
up to a maximum of $120,000 annually,
(cid:129) reinvest their dividends in Ameren common stock
(the minimum dividend reinvestment requirement is 10%),
per share and
(cid:129) place Ameren common stock certificates in safekeeping and
receive regular account statements.
For more information about DRPlus, you may obtain a
prospectus from Ameren’s Investor Services representatives.
Investor Services
Ameren’s Investor Services representatives are available
to help you each business day from 8:00 a.m. to 4:00 p.m.
(Central Time). Please write or call:
Ameren Services Company, Investor Services
P.O. Box 66887
St. Louis, MO 63166-6887
314-554-3502
800-255-2237
invest@ameren.com
Transfer Agent, Registrar and Paying Agent
The Transfer Agent, Registrar and Paying Agent for
Ameren common stock and Ameren Illinois Company
and Union Electric Company preferred stock is Ameren
Services Company.
Office
Ameren Corporation
One Ameren Plaza
1901 Chouteau Avenue
St. Louis, MO 63103
314-621-3222
06
Strengthening
Energy
Security
10
Enhancing
Economic
Vitality
14
Building
Connections
that Count
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Powering the Quality of Life
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