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UNION ELECTRIC CO - Annual Report: 2012 (Form 10-K)

Table of Contents

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

Exact name of registrant as specified in its charter;
State of Incorporation;
Address and Telephone Number
 

IRS Employer
Identification No.
 
 
 
 
1-14756

Ameren Corporation
 

43-1723446
 

(Missouri Corporation)
 

 
 

1901 Chouteau Avenue
 

 
 

St. Louis, Missouri 63103
 

 
 

(314) 621-3222
 

 
 
 
 
 
1-2967

Union Electric Company
 

43-0559760
 

(Missouri Corporation)
 

 
 

1901 Chouteau Avenue
 

 
 

St. Louis, Missouri 63103
 

 
 

(314) 621-3222
 

 
 
 
 
 
1-3672

Ameren Illinois Company
 

37-0211380
 

(Illinois Corporation)
 

 
 

6 Executive Drive
 

 
 

Collinsville, Illinois 62234
 

 
 

(618) 343-8039
 

 
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
 
Title of each class
 
Ameren Corporation
Common Stock, $0.01 par value per share
Securities Registered Pursuant to Section 12(g) of the Act:
Registrant
 
Title of each class
 
Union Electric Company
Preferred Stock, cumulative, no par value, stated value $100 per share
Ameren Illinois Company
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
Yes
(X)
No
( )
Union Electric Company
Yes
( )
No
(X)
Ameren Illinois Company
Yes
( )
No
(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
Yes
( )
No
(X)
Union Electric Company
Yes
( )
No
(X)
Ameren Illinois Company
Yes
( )
No
(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
Yes
(X)
No
( )
Union Electric Company
Yes
(X)
No
( )
Ameren Illinois Company
Yes
(X)
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
Yes
(X)
No
( )
Union Electric Company
Yes
(X)
No
( )
Ameren Illinois Company
Yes
(X)
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

(X)
Union Electric Company

(X)
Ameren Illinois Company

(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.


Large
Accelerated
Filer

Accelerated
Filer

Non-accelerated
Filer

Smaller
Reporting
Company
Ameren Corporation

(X)

( )

( )

( )
Union Electric Company

( )

( )

(X)

( )
Ameren Illinois Company

( )

( )

(X)

( )
Indicate by checkmark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
Ameren Corporation
Yes
( )
No
(X)
Union Electric Company
Yes
( )
No
(X)
Ameren Illinois Company
Yes
( )
No
(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
Common stock, $0.01 par value per share: 242,634,671
 
 
Union Electric Company
Common stock, $5 par value per share, held by Ameren
Corporation (parent company of the registrant): 102,123,834
 
 
Ameren Illinois Company
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

TABLE OF CONTENTS
 
 
Page
PART I
 
 
Item 1.
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
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.
 
 
 
PART IV
 
 
Item 15.
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.

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined below. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.
2007 Illinois Electric Settlement Agreement - A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates. 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.
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


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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.
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.


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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.
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.


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The following factors, in addition to those discussed under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:
•
regulatory, 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;
•
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;
•
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;
•
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;


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•
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.
•
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)
9,097

Ameren Missouri
3,997

Ameren Illinois
2,994

AER
713

Ameren Services
1,393

(a)
Total for Ameren includes Ameren registrant and nonregistrant subsidiaries.
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


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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 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.


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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.
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


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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 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


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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 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


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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 decision to make pollution control equipment investments at our Merchant Generation business 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 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.
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 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-


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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 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
81
%
 
15
%
 
3
%
 
1
%
 
(c)

2011
85

 
12

 
1

 
2

 
(c)

2010
85

 
12

 
1

 
2

 
(c)

Ameren Missouri:
 
 
 
 
 
 
 
 
 
2012
73
%
 
24
%
 
1
%
 
2
%
 
(c)

2011
77

 
19

 
1

 
3

 
(c)

2010
77

 
19

 
1

 
3

 
—

Merchant Generation:
 
 
 
 
 
 
 
 
 
2012
94
%
 
—

 
6
%
 
—

 
—

2011
98

 
—

 
2

 
—

 
(c)

2010
98

 
—

 
2

 
—

 
(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.
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(c)
Less than 1% of total fuel supply.

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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)
$
2.081

 
$
1.931

 
$
1.848

Nuclear
0.964

 
0.750

 
0.701

Natural gas(b)
3.772

 
6.097

 
6.539

Weighted average – all fuels(c)
$
1.975

 
$
1.873

 
$
1.803

Ameren Missouri:
 
 
 
 
 
Coal(a)
$
1.925

 
$
1.733

 
$
1.675

Nuclear
0.964

 
0.750

 
0.701

Natural gas(b)
4.517

 
5.873

 
6.199

Weighted average – all fuels(c)
$
1.743

 
$
1.610

 
$
1.563

Merchant Generation:
 
 
 
 
 
Coal(a)
$
2.282

 
$
2.184

 
$
2.063

Natural gas(b)
3.392

 
6.374

 
6.972

Weighted average – all fuels(c)
$
2.359

 
$
2.292

 
$
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 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.


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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.
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


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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 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;
•
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.


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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.


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OPERATING STATISTICS
The following tables present key electric and natural gas operating statistics for Ameren for the past three years:
Electric Operating Statistics – Year Ended December 31,
2012
 
2011
 
2010
Electric Sales – kilowatthours (in millions):
 
 
 
 
 
Ameren Missouri:
 
 
 
 
 
Residential
13,385

 
13,867

 
14,640

Commercial
14,575

 
14,743

 
15,002

Industrial
8,660

 
8,691

 
8,656

Other
126

 
127

 
129

Native load subtotal
36,746

 
37,428

 
38,427

Off-system and wholesale
7,293

 
10,715

 
9,796

Subtotal
44,039

 
48,143

 
48,223

Ameren Illinois:
 
 
 
 
 
Residential
 
 
 
 
 
Power supply and delivery service
9,507

 
11,771

 
12,340

Delivery service only
2,103

 
77

 
1

Commercial
 
 
 
 
 
Power supply and delivery service
2,985

 
3,662

 
4,419

Delivery service only
9,175

 
8,561

 
8,051

Industrial
 
 
 
 
 
Power supply and delivery service
1,595

 
1,502

 
1,389

Delivery service only
11,753

 
11,360

 
11,147

Other
523

 
529

 
545

Native load subtotal
37,641

 
37,462

 
37,892

Merchant Generation:
 
 
 
 
 
Nonaffiliate energy sales
25,552

 
31,148

 
30,788

Affiliate native energy sales
1,679

 
1,004

 
949

Subtotal
27,231

 
32,152

 
31,737

Eliminate affiliate sales
(1,679
)
 
(1,004
)
 
(949
)
Eliminate Ameren Illinois/Merchant Generation common customers
(7,261
)
 
(5,454
)
 
(5,016
)
Ameren total
99,971

 
111,299

 
111,887

Electric Operating Revenues (in millions):
 
 
 
 
 
Ameren Missouri:
 
 
 
 
 
Residential
$
1,297

 
$
1,272

 
$
1,193

Commercial
1,088

 
1,084

 
1,004

Industrial
435

 
438

 
399

Other
104

 
76

 
91

Native load subtotal
$
2,924

 
$
2,870

 
$
2,687

Off-system and wholesale
208

 
352

 
343

Subtotal
$
3,132

 
$
3,222

 
$
3,030

Ameren Illinois:
 
 
 
 
 
Residential
 
 
 
 
 
Power supply and delivery service
$
961

 
$
1,194

 
$
1,270

Delivery service only
90

 
3

 
—

Commercial
 
 
 
 
 
Power supply and delivery service
254

 
350

 
425

Delivery service only
177

 
157

 
143

Industrial
 
 
 
 
 
Power supply and delivery service
57

 
65

 
66

Delivery service only
46

 
43

 
38

Other
154

 
128

 
119

Native load subtotal
$
1,739

 
$
1,940

 
$
2,061

Merchant Generation:
 
 
 
 
 
Nonaffiliate energy sales
$
1,047

 
$
1,382

 
$
1,442

Affiliate native energy sales
311

 
232

 
231

Other
15

 
12

 
20

Subtotal
$
1,373

 
$
1,626

 
$
1,693

Eliminate affiliate revenues
(340
)
 
(258
)
 
(263
)
Ameren total
$
5,904

 
$
6,530

 
$
6,521


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Electric Operating Statistics – Year Ended December 31,
2012
 
2011
 
2010
Electric Generation – megawatthours (in millions):
 
 
 
 
 
Ameren Missouri
44.7

 
48.8

 
48.1

Merchant Generation:
 
 
 
 
 
Genco
18.5

 
22.0

 
22.0

AERG
7.2

 
7.0

 
7.5

Medina Valley
—

 
0.1

 
0.1

Subtotal
25.7

 
29.1

 
29.6

Ameren total
70.4

 
77.9

 
77.7

Price per ton of delivered coal (average)
$
36.63

 
$
33.79

 
$
32.91

Source of energy supply:
 
 
 
 
 
Coal
65.1
%
 
66.5
%
 
65.7
%
Nuclear
12.4

 
9.4

 
8.9

Hydroelectric
1.1

 
1.3

 
1.6

Natural gas
2.7

 
1.1

 
1.0

Purchased – Wind
0.4

 
0.3

 
0.3

Purchased – Other
18.3

 
21.4

 
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
6

 
7

 
7

Commercial
3

 
3

 
4

Industrial
1

 
1

 
1

Subtotal
10

 
11

 
12

Ameren Illinois:
 
 
 
 
 
Residential
49

 
56

 
60

Commercial
17

 
21

 
23

Industrial
5

 
5

 
7

Other
3

 
—

 
—

Subtotal
74

 
82

 
90

Other:
 
 
 
 
 
Industrial
—

 
—

 
1

Subtotal
—

 
—

 
1

Ameren total
84

 
93

 
103

Natural Gas Operating Revenues (in millions)
 
 
 
 
 
Ameren Missouri:
 
 
 
 
 
Residential
$
85

 
$
96

 
$
100

Commercial
36

 
41

 
43

Industrial
8

 
9

 
10

Other
10

 
10

 
13

Subtotal
$
139

 
$
156

 
$
166

Ameren Illinois:
 
 
 
 
 
Residential
$
547

 
$
588

 
$
649

Commercial
172

 
195

 
223

Industrial
24

 
30

 
44

Other
43

 
33

 
37

Subtotal
$
786

 
$
846

 
$
953

Other:
 
 
 
 
 
Industrial
$
—

 
$
—

 
$
4

Eliminate affiliate revenues
(1
)
 
(1
)
 
(6
)
Ameren total
$
924

 
$
1,001

 
$
1,117

Peak day throughput (thousands of dekatherms):
 
 
 
 
 
Ameren Missouri
139

 
149

 
167

Ameren Illinois
1,061

 
1,157

 
1,227

Total peak day throughput
1,200

 
1,306

 
1,394


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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 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


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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 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


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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.
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


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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.
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


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losses. Their results of operations, financial position, and liquidity could be adversely affected, resulting in the nondefaulting Ameren entity being unable to meet its obligations, including to unrelated third parties. 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:
•
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;
•
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


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penalties of $1 million per violation per day. Under 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:
•
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.


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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:
•
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 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


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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 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


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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, 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.


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ITEM 2.PROPERTIES
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
Labadie
Franklin County, Mo.
2,374,000

 
Rush Island
Jefferson County, Mo.
1,182,000

 
Sioux
St. Charles County, Mo.
972,000

 
Meramec
St. Louis County, Mo.
833,000

Total coal
 
 
5,361,000

Nuclear
Callaway
Callaway County, Mo.
1,194,000

Hydroelectric
Osage
Lakeside, Mo.
240,000

 
Keokuk
Keokuk, Ia.
140,000

Total hydroelectric
 
 
380,000

Pumped-storage
Taum Sauk
Reynolds County, Mo.
440,000

Oil (CTs)
Meramec
St. Louis County, Mo.
54,000

 
Fairgrounds
Jefferson City, Mo.
54,000

 
Mexico
Mexico, Mo.
53,000

 
Moberly
Moberly, Mo.
53,000

 
Moreau
Jefferson City, Mo.
53,000

 
Howard Bend
St. Louis County, Mo.
39,000

Total oil
 
 
306,000

Natural gas (CTs)
Audrain(b)
Audrain County, Mo.
592,000

 
Venice(c)
Venice, Ill.
487,000

 
Goose Creek
Piatt County, Ill.
426,000

 
Pinckneyville
Pinckneyville, Ill.
312,000

 
Raccoon Creek
Clay County, Ill.
296,000

 
Kinmundy(c)
Kinmundy, Ill.
206,000

 
Peno Creek(b)(c)
Bowling Green, Mo.
188,000

 
Meramec(c)
St. Louis County, Mo.
48,000

 
Kirksville
Kirksville, Mo.
12,000

Total natural gas
 
 
2,567,000

Methane gas (CTs)
Maryland Heights
Maryland Heights, Mo.
8,000

Total Ameren Missouri
 
 
10,256,000

Merchant Generation:
 
 
 
Genco:
 
 
 
Coal
Newton
Newton, Ill.
1,215,000

 
Joppa (EEI)(d)
Joppa, Ill.
1,002,000

 
Coffeen
Coffeen, Ill.
895,000

Total coal
 
 
3,112,000

Natural gas (CTs)
Grand Tower
Grand Tower, Ill.
478,000

 
Elgin
Elgin, Ill.
460,000

 
Gibson City(c)
Gibson City, Ill.
228,000

 
Joppa 7B
Joppa, Ill.
110,000

 
Joppa (EEI)(d)
Joppa, Ill.
74,000

Total natural gas
 
 
1,350,000

Total Genco
 
 
4,462,000

AERG:
 
 
 
Coal
E.D. Edwards
Bartonville, Ill.
650,000

 
Duck Creek
Canton, Ill.
410,000

Total AERG
 
 
1,060,000

Total Merchant Generation
 
 
5,522,000

Total Ameren
 
 
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.

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The following table presents electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2012:
 
Ameren
Missouri
 
Ameren
Illinois
Circuit miles of electric transmission lines(a)
2,956

 
4,506

Circuit miles of electric distribution lines
32,967

 
45,746

Circuit miles of electric distribution lines underground
23
%
 
15
%
Miles of natural gas transmission and distribution mains
3,282

 
18,137

Propane-air plants
1

 
—

Underground gas storage fields
—

 
12

Billion cubic feet of total working capacity of 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 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;
•
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,


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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.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.

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:
Name
Age
 
Positions and Offices Held
Thomas R. Voss
65

 
Chairman, President and Chief Executive Officer, and Director
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.
 
 
 
 
Martin J. Lyons, Jr.
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.
 
 
 
 
Gregory L. Nelson
55

 
Senior Vice President, General Counsel and Secretary
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.
 
 
 
 
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
58

 
Vice President and Treasurer
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.

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SUBSIDIARIES:
Name
Age
 
Positions and Offices Held
Warner L. Baxter
51

 
Chairman, President and Chief Executive Officer (Ameren Missouri)
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.
 
 
 
 
Maureen A. Borkowski
55

 
Chairman, President and Chief Executive Officer (ATXI)
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.
 
 
 
 
Daniel F. Cole
59

 
Chairman, President and Chief Executive Officer (Ameren Services)
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.
 
 
 
 
Adam C. Heflin
48

 
Senior Vice President and Chief Nuclear Officer (Ameren Missouri)
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.
 
 
 
 
Richard J. Mark
57

 
Chairman, President and Chief Executive Officer (Ameren Illinois)
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.
 
 
 
 
Michael L. Moehn
43

 
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.
 
 
 
 
Charles D. Naslund
60

 
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.
 
 
 
 
Steven R. Sullivan
52

 
Chairman, President and Chief Executive Officer (AER)
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.

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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
$
33.68

 
$
30.89

 
$
32.58

 
$
0.400

June 30
34.04

 
31.15

 
33.54

 
0.400

September 30
35.30

 
32.27

 
32.67

 
0.400

December 31
33.21

 
28.43

 
30.72

 
0.400

2011 Quarter Ended:
 
 
 
 
 
 
 
March 31
$
29.14

 
$
26.46

 
$
28.07

 
$
0.385

June 30
30.14

 
27.78

 
28.84

 
0.385

September 30
31.44

 
25.55

 
29.77

 
0.385

December 31
34.11

 
27.98

 
33.13

 
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:
 
 
2012
 
2011
(In millions)
Quarter Ended
 
Quarter Ended
Registrant
December 31
 
September 30
 
June 30
 
March 31
 
December 31
 
September 30
 
June 30
 
March 31
Ameren Missouri
$
100

 
$
100

 
$
100

 
$
100

 
$
184

 
$
84

 
$
67

 
$
68

Ameren Illinois
57

 
57

 
38

 
37

 
89

 
88

 
88

 
62

Ameren
98

 
97

 
97

 
90

 
96

 
93

 
93

 
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
300

 
29.32

 
—

 
—

December 1 – December 31, 2012
3,213

 
29.52

 
—

 
—

Total
3,513

 
$
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.

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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.
December 31,
2007
 
2008
 
2009
 
2010
 
2011
 
2012
Ameren
$
100.00

 
$
65.41

 
$
58.40

 
$
62.41

 
$
77.23

 
$
75.28

S&P 500 Index
100.00

 
63.00

 
79.67

 
91.67

 
93.60

 
108.58

EEI Index
100.00

 
74.10

 
82.04

 
87.81

 
105.36

 
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.

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ITEM 6.
SELECTED FINANCIAL DATA
For the years ended December 31,
(In millions, except per share amounts)
2012
 
2011
 
2010
 
2009
 
2008
Ameren(a):
 
 
 
 
 
 
 
 
 
Operating revenues
$
6,828

 
$
7,531

 
$
7,638

 
$
7,135

 
$
7,869

Operating income (loss)(b)
(1,240
)

1,241


916

 
1,416

 
1,362

Net income (loss) attributable to Ameren Corporation
(974
)
 
519

 
139

 
612

 
605

Common stock dividends
382

 
375

 
368

 
338

 
534

Earnings (loss) per share - basic and diluted
(4.01
)
 
2.15

 
0.58

 
2.78

 
2.88

Common stock dividends per share
1.60

 
1.555

 
1.54

 
1.54

 
2.54

As of December 31:
 
 
 
 
 
 
 
 
 
Total assets
$
21,835

 
$
23,645

 
$
23,511

 
$
23,702

 
$
22,671

Long-term debt, excluding current maturities
6,626

 
6,677

 
6,853

 
7,111

 
6,554

Total Ameren Corporation stockholders’ equity
6,616

 
7,919

 
7,730

 
7,856

 
6,963

Ameren Missouri:
 
 
 
 
 
 
 
 
 
Operating revenues
$
3,272

 
$
3,383

 
$
3,197

 
$
2,874

 
$
2,960

Operating income(c)
845

 
609

 
711

 
566

 
514

Net income available to common stockholder
416

 
287

 
364

 
259

 
245

Dividends to parent
400

 
403

 
235

 
175

 
264

As of December 31:
 
 
 
 
 
 
 
 
 
Total assets
$
13,043

 
$
12,757

 
$
12,504

 
$
12,219

 
$
11,529

Long-term debt, excluding current maturities
3,801

 
3,772

 
3,949

 
4,018

 
3,673

Total stockholders’ equity
4,054

 
4,037

 
4,153

 
4,057

 
3,562

Ameren Illinois:
 
 
 
 
 
 
 
 
 
Operating revenues
$
2,525

 
$
2,787

 
$
3,014

 
$
2,984

 
$
3,508

Operating income
377

 
458

 
498

 
363

 
191

Income from continuing operations
144

 
196

 
212

 
133

 
41

Net income available to common stockholder
141

 
193

 
248

 
241

 
87

Dividends to parent
189

 
327

 
133

 
98

 
60

As of December 31:
 
 
 
 
 
 
 
 
 
Total assets(d)
$
7,282

 
$
7,213

 
$
7,406

 
$
8,298

 
$
8,023

Long-term debt, excluding current maturities
1,577

 
1,657

 
1,657

 
1,847

 
1,850

Total stockholders’ equity
2,401

 
2,452

 
2,576

 
3,072

 
2,655

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
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.
(c)
Includes “Loss from regulatory disallowance” of $89 million recorded during the year ended December 31, 2011.
(d)
Includes total assets from discontinued operations of $1,117 million and $1,081 million at December 31, 2009 and 2008, respectively.

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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.
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


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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. 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


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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 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


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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 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


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•
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.

Below is a table of income statement components by segment for the years ended December 31, 2012, 2011, and 2010:
2012
Ameren
Missouri
 
Ameren
Illinois Segment
 
Merchant Generation
 
Other /
Intersegment
Eliminations
 
Total
Electric margins
$
2,340

 
$
1,034

 
$
518

 
$
(11
)
 
$
3,881

Natural gas margins
75

 
378

 
—

 
(1
)
 
452

Other revenues
1

 
—

 
—

 
(1
)
 
—

Other operations and maintenance
(827
)
 
(684
)
 
(259
)
 
18

 
(1,752
)
Impairment and other charges
—

 
—

 
(2,578
)
 
—

 
(2,578
)
Depreciation and amortization
(440
)
 
(221
)
 
(102
)
 
(12
)
 
(775
)
Taxes other than income taxes
(304
)
 
(130
)
 
(25
)
 
(9
)
 
(468
)
Other income and (expenses)
49

 
(10
)
 
(1
)
 
(4
)
 
34

Interest charges
(223
)
 
(129
)
 
(95
)
 
(1
)
 
(448
)
Income (taxes) benefit
(252
)
 
(94
)
 
1,019

 
7

 
680

Net income (loss)
419

 
144

 
(1,523
)
 
(14
)
 
(974
)
Noncontrolling interest and preferred dividends
(3
)
 
(3
)
 
7

 
(1
)
 
—

Net income (loss) attributable to Ameren Corporation
$
416

 
$
141

 
$
(1,516
)
 
$
(15
)
 
$
(974
)
2011
 
 
 
 
 
 
 
 
 
Electric margins
$
2,252

 
$
1,087

 
$
668

 
$
(10
)
 
$
3,997

Natural gas margins
79

 
354

 
—

 
(2
)
 
431

Other revenues
5

 
1

 
3

 
(9
)
 
—

Other operations and maintenance
(934
)
 
(640
)
 
(285
)
 
39

 
(1,820
)
Impairment and other charges
(89
)
 
—

 
(37
)
 
1

 
(125
)
Depreciation and amortization
(408
)
 
(215
)
 
(143
)
 
(19
)
 
(785
)
Taxes other than income taxes
(296
)
 
(129
)
 
(24
)
 
(8
)
 
(457
)
Other income and (expenses)
51

 
1

 
1

 
(7
)
 
46

Interest charges
(209
)
 
(136
)
 
(105
)
 
(1
)
 
(451
)
Income (taxes) benefit
(161
)
 
(127
)
 
(32
)
 
10

 
(310
)
Net income (loss)
290

 
196

 
46

 
(6
)
 
526

Noncontrolling interest and preferred dividends
(3
)
 
(3
)
 
(1
)
 
—

 
(7
)
Net income (loss) attributable to Ameren Corporation
$
287

 
$
193

 
$
45

 
$
(6
)
 
$
519

2010
 
 
 
 
 
 
 
 
 
Electric margins
$
2,233

 
$
1,096

 
$
780

 
$
(17
)
 
$
4,092

Natural gas margins
75

 
375

 
—

 
(2
)
 
448

Other revenues
1

 
—

 
—

 
(1
)
 
—

Other operations and maintenance
(931
)
 
(635
)
 
(287
)
 
32

 
(1,821
)
Impairment and other charges
—

 
—

 
(589
)
 
—

 
(589
)
Depreciation and amortization
(382
)
 
(210
)
 
(146
)
 
(27
)
 
(765
)
Taxes other than income taxes
(285
)
 
(128
)
 
(26
)
 
(10
)
 
(449
)
Other income and (expenses)
70

 
(6
)
 
1

 
(8
)
 
57

Interest charges
(213
)
 
(143
)
 
(133
)
 
(8
)
 
(497
)
Income (taxes) benefit
(199
)
 
(137
)
 
(6
)
 
17

 
(325
)
Net income (loss)
369

 
212

 
(406
)
 
(24
)
 
151

Noncontrolling interest and preferred dividends
(5
)
 
(4
)
 
(3
)
 
—

 
(12
)
Net income (loss) attributable to Ameren Corporation
$
364

 
$
208

 
$
(409
)
 
$
(24
)
 
$
139


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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
Electric revenue change:
 
 
 
 
 
 
 
 
 
Effect of weather (estimate)(b)
$
(19
)
 
$
(1
)
 
$
—

 
$
—

 
$
(20
)
Regulated rates:
 
 
 
 
 
 
 
 
 
Base rates (estimate)
102

 
—

 
—

 
—

 
102

Formula ratemaking adjustment under IEIMA (estimate)
—

 
(55
)
 
—

 
—

 
(55
)
Recovery of FAC under-recovery(c)
(47
)
 
—

 
—

 
—

 
(47
)
Off-system revenues (included in base rates)
(131
)
 
—

 
—

 
—

 
(131
)
FAC prudence review disallowance
17

 
—

 
—

 
—

 
17

Transmission services
5

 
(1
)
 
—

 
(3
)
 
1

Wholesale revenues
(13
)
 
(6
)
 
—

 
—

 
(19
)
Illinois pass-through power supply costs
—

 
(154
)
 
—

 
(77
)
 
(231
)
Energy efficiency programs and environmental remediation cost riders
—

 
11

 
—

 
—

 
11

Bad debt rider
—

 
(4
)
 
—

 
—

 
(4
)
Hurricane Sandy relief cost recovery
7

 
10

 
—

 
—

 
17

Rate-regulated sales volume (excluding the impact of abnormal weather)
(6
)
 
(3
)
 
—

 
—

 
(9
)
Merchant Generation sales volume
—

 
—

 
(225
)
 
—

 
(225
)
Merchant Generation sales price changes, including hedge effect
—

 
—

 
(26
)
 
—

 
(26
)
Net unrealized MTM gains
—

 
—

 
11

 
—

 
11

Other
(5
)
 
2

 
(13
)
 
(2
)
 
(18
)
Total electric revenue change
$
(90
)
 
$
(201
)
 
$
(253
)
 
$
(82
)
 
$
(626
)
Fuel and purchased power change:
 
 
 
 
 
 
 
 
 
Fuel:
 
 
 
 
 
 
 
 
 
Merchant Generation production volume and other
$
—

 
$
—

 
$
83

 
$
—

 
$
83

Fuel, purchased power and transportation costs (included in base rates)
106

 
—

 
—

 
—

 
106

Recovery of FAC under-recovery(c)
47

 
—

 
—

 
—

 
47

Net unrealized MTM gains (losses)
1

 
—

 
(23
)
 
—

 
(22
)
Price - Merchant Generation
—

 
—

 
(13
)
 
—

 
(13
)
Power purchase agreement settlement
24

 
—

 
—

 
—

 
24

Merchant Generation purchased power and other
—

 
—

 
56

 
4

 
60

Transmission over-recovery
—

 
(6
)
 
—

 
—

 
(6
)
Illinois pass-through power supply costs
—

 
154

 
—

 
77

 
231

Total fuel and purchased power change
$
178

 
$
148

 
$
103

 
$
81

 
$
510

Net change in electric margins
$
88

 
$
(53
)
 
$
(150
)
 
$
(1
)
 
$
(116
)
Natural gas margins change:
 
 
 
 
 
 
 
 
 
Effect of weather (estimate)(b)
$
(2
)
 
$
(10
)
 
$
—

 
$
—

 
$
(12
)
Base rates (estimate)
2

 
20

 
—

 
—

 
22

Rate redesign
(5
)
 
—

 
—

 
—

 
(5
)
Energy efficiency programs and environmental remediation cost riders
—

 
8

 
—

 
—

 
8

Bad debt rider
—

 
(5
)
 
—

 
—

 
(5
)
Hurricane Sandy relief cost recovery
—

 
3

 
—

 
—

 
3

Sales volume (excluding impact of abnormal weather) and other
1

 
8

 
—

 
1

 
10

Net change in natural gas margins
$
(4
)
 
$
24

 
$
—

 
$
1

 
$
21


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2011 versus 2010
Ameren
Missouri
 
Ameren
Illinois
Segment
 
Merchant Generation
 
Other(a)
 
Ameren
Electric revenue change:
 
 
 
 
 
 
 
 
 
Effect of weather (estimate)(b)
$
(29
)
 
$
(7
)
 
$
—

 
$
—

 
$
(36
)
Regulated rates:
 
 
 
 
 
 
 
 
 
Base rates (estimate)
172

 
20

 
—

 
—

 
192

Recovery of FAC under-recovery(c)
89

 
—

 
—

 
—

 
89

Off-system revenues included in base rates
53

 
—

 
—

 
—

 
53

FAC prudence review disallowance
(17
)
 
—

 
—

 
—

 
(17
)
Transmission services
1

 
(4
)
 
—

 
3

 
—

Wholesale revenues
(43
)
 
9

 
—

 
—

 
(34
)
Illinois pass-through power supply costs
—

 
(112
)
 
—

 
(1
)
 
(113
)
Energy efficiency programs and environmental remediation cost riders
—

 
6

 
—

 
—

 
6

Bad debt rider
—

 
(17
)
 
 
 
 
 
(17
)
Rate-regulated sales volume (excluding the impact of abnormal weather)
(37
)
 
(15
)
 
—

 
—

 
(52
)
Merchant Generation sales volume
—

 
—

 
20

 
—

 
20

Merchant Generation sales price changes, including hedge effect
—

 
—

 
(74
)
 
—

 
(74
)
Net unrealized MTM losses
(2
)
 
—

 
(16
)
 
—

 
(18
)
Other
5

 
(1
)
 
4

 
2

 
10

Total electric revenue change
$
192

 
$
(121
)
 
$
(66
)
 
$
4

 
$
9

Fuel and purchased power change:
 
 
 
 
 
 
 
 
 
Fuel:
 
 
 
 
 
 
 
 
 
Merchant Generation production volume and other
$
—

 
$
—

 
$
11

 
$
1

 
$
12

Fuel, purchased power and transportation costs included in base rates
(84
)
 
—

 
—

 
—

 
(84
)
Recovery of FAC under-recovery(c)
(89
)
 
—

 
—

 
—

 
(89
)
Net unrealized MTM losses
—

 
—

 
(9
)
 
1

 
(8
)
Price - Merchant Generation
—

 
—

 
(17
)
 
—

 
(17
)
Merchant Generation purchased power and other
—

 
—

 
(31
)
 
—

 
(31
)
Illinois pass-through power supply costs
—

 
112

 
—

 
1

 
113

Total fuel and purchased power change
$
(173
)
 
$
112

 
$
(46
)
 
$
3

 
$
(104
)
Net change in electric margins
$
19

 
$
(9
)
 
$
(112
)
 
$
7

 
$
(95
)
Natural gas margins change:
 
 
 
 
 
 
 
 
 
Effect of weather (estimate)(b)
$
(1
)
 
$
(5
)
 
$
—

 
$
—

 
$
(6
)
Bad debt rider
—

 
(14
)
 
—

 
—

 
(14
)
Base rates (estimate)
5

 
3

 
—

 
—

 
8

Energy efficiency programs and environmental remediation cost riders
—

 
(1
)
 
—

 
—

 
(1
)
Sales volume (excluding impact of abnormal weather) and other
—

 
(4
)
 
—

 
—

 
(4
)
Net change in natural gas margins
$
4

 
$
(21
)
 
$
—

 
$
—

 
$
(17
)
(a)
Includes amounts for other nonregistrant subsidiaries and intercompany eliminations.
(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 amount


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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.
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


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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.
•
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


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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.
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


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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.
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


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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.
•
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.


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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.
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


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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.
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 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.
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.
•
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.


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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.
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.


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•
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

 
$
—

 
$
—

 
$
2,578

2011:
 
 
 
 
 
 
 
Ameren(a)
123

 
—

 
2

 
125

AMO
89

 
—

 
—

 
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 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.


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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 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 Ameren's business segments and for the Ameren Companies between 2012 and 2011 were as follows:
Ameren Missouri
Depreciation and amortization expenses increased by $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


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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.
Variations in depreciation and amortization expenses in Ameren's business segments and for the Ameren Companies between 2011 and 2010 were as follows:
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.
Merchant Generation
Depreciation and amortization expenses were comparable between years in the Merchant Generation segment.
Taxes Other Than Income Taxes
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.
2011 versus 2010
Ameren Corporation
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.
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:


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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.
Merchant Generation
Other income, net of expenses, was comparable between years.
2011 versus 2010
Ameren Corporation
Other income, net of expenses, decreased by $11 million in 2011 compared with 2010, primarily because of items noted below.
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.
Ameren Illinois
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
Interest charges decreased by $10 million in 2012, primarily because of increased capitalized interest due to the Newton energy center scrubber project.
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


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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
41%
37%
68%(a)
Ameren Missouri
37
36
35
Ameren Illinois
40
39
39
Merchant Generation
40
41
(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.
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


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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 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


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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)
$
1,690

 
$
1,878

 
$
1,823

 
$
(1,310
)
 
$
(1,048
)
 
$
(1,096
)
 
$
(426
)
 
$
(1,120
)
 
$
(804
)
Ameren Missouri
1,004

 
1,056

 
969

 
(703
)
 
(627
)
 
(700
)
 
(354
)
 
(430
)
 
(334
)
Ameren Illinois
519

 
504

 
593

 
(437
)
 
(296
)
 
(247
)
 
(103
)
 
(509
)
 
(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 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


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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 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.


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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.
•
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.


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•
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.
•
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.


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•
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.
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.


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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)
$
1,240

 
$
1,030

 
$
1,042

Ameren Missouri
595

 
550

 
624

Ameren Illinois
442

 
351

 
281

Merchant Generation
178

 
153

 
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 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
$
720

 
$
2,250

-
$
3,045

 
$
2,970

-
$
3,765

Ameren Illinois
695

 
2,400

-
3,250

 
3,095

-
3,945

AER
70

 
230

-
315

 
300

-
385

ATXI
60

 
965

-
1,310

 
1,025

-
1,370

Other(a)
(5
)
 
60

-
80

 
55

-
75

Ameren
$
1,540

 
$
5,905

-
$
8,000

 
$
7,445

-
$
9,540

(a)
Includes the elimination of intercompany transfers.
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


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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 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.
Cash Flows from Financing Activities
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 $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


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$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

 
1,100

Ameren:
 
 
 
 
 
Less: Letters of credit

 
(c)

 
(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.
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
$
500

 
$
300

Ameren Missouri
800

 
(a)

Ameren Illinois
(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.


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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.


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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
 
$
482

 
$
—

 
$
—

Ameren Illinois:
 
 
 
 
 
 
 
2.70% Senior secured notes due 2022
August
 
400

 
—

 
—

Total Ameren long-term debt issuances
 
 
$
882

 
$
—

 
$
—

Common stock
 
 
 
 
 
 
 
Ameren:
 
 
 
 
 
 
 
DRPlus and 401(k)
Various
 
$
—

 
$
65

 
$
80

Total common stock issuances
 
 
$
—

 
$
65

 
$
80

Total Ameren long-term debt and common stock issuances
 
 
$
882

 
$
65

 
$
80

Redemptions, Repurchases and Maturities
 
 
 
 
 
 
 
Long-term debt
 
 
 
 
 
 
 
Ameren Missouri:
 
 
 
 
 
 
 
City of Bowling Green capital lease (Peno Creek CT)
Various
 
$
5

 
$
5

 
$
4

5.25% Senior secured notes due 2012
September
 
173

 
—

 
—

6.00% Senior secured notes due 2018
September
 
71

 
—

 
—

6.70% Senior secured notes due 2019
September
 
121

 
—

 
—

5.10% Senior secured notes due 2018
September
 
1

 
—

 
—

5.10% Senior secured notes due 2019
September
 
56

 
—

 
—

7.69% Series A subordinated deferrable interest debentures due 2036
September
 
—

 
—

 
66

Ameren Illinois:
 
 
 
 
 
 
 
6.625% Senior secured notes due 2011
June
 
—

 
150

 
—

9.75% Senior secured notes due 2018
August
 
87

 
—

 
—

6.25% Senior secured notes due 2018
August
 
194

 
—

 
—

2000 Series A 5.50% pollution control revenue bonds due 2014
August
 
51

 
—

 
—

7.61% Series 1997-2 first mortgage bonds due 2017
September
 
—

 
—

 
40

6.20% Series 1992B due 2012
November
 
1

 
—

 
—

Genco:
 
 
 
 
 
 
 
Senior notes Series D 8.35% due 2010
November
 
—

 
—

 
200

Total Ameren long-term debt redemptions, repurchases and maturities
 
 
$
760

 
$
155

 
$
310

Preferred stock
 
 
 
 
 
 
 
Ameren Missouri:
 
 
 
 
 
 
 
$7.64 Series
August
 
$
—

 
$
—

 
$
33

Ameren Illinois:
 
 
 
 
 
 
 
4.50% Series
August
 
—

 
—

 
11

4.64% Series
August
 
—

 
—

 
8

4.08% Series(a)
September
 
—

 
—

 
7

4.20% Series(a)
September
 
—

 
—

 
5

4.26% Series(a)
September
 
—

 
—

 
4

4.42% Series(a)
September
 
—

 
—

 
3

4.70% Series(a)
September
 
—

 
—

 
5

7.75% Series(a)
September
 
—

 
—

 
9

Total Ameren preferred stock redemptions and repurchases
 
 
$
—

 
$
—

 
$
85

Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities
 
 
$
760

 
$
155

 
$
395


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(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 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


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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.
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.
 
2012
 
2011
 
2010
Ameren Missouri
$
400

 
$
403

 
$
235

Ameren Illinois
189

 
327

 
133

Dividends paid by Ameren
382

 
375

 
368

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.


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Contractual Obligations

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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)
$
6,992

 
$
355

 
$
654

 
$
1,076

 
$
4,907

Interest payments(d)
4,340

 
428

 
742

 
664

 
2,506

Operating leases(e)
272

 
31

 
53

 
51

 
137

Other obligations(f)
8,338

 
1,891

 
2,808

 
1,948

 
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)
$
4,013

 
$
205

 
$
229

 
$
697

 
$
2,882

Interest payments(d)
2,846

 
225

 
422

 
372

 
1,827

Operating leases(e)
123

 
12

 
24

 
25

 
62

Other obligations(f)
5,121

 
841

 
1,738

 
1,619

 
923

Total cash contractual obligations
$
12,103

 
$
1,283

 
$
2,413

 
$
2,713

 
$
5,694

Ameren Illinois:
 
 
 
 
 
 
 
 
 
Long-term debt(b)(c)
$
1,729

 
$
150

 
$
—

 
$
379

 
$
1,200

Interest payments(d)
790

 
106

 
188

 
174

 
322

Operating leases(e)
7

 
1

 
2

 
2

 
2

Other obligations(f)
2,446

 
695

 
796

 
216

 
739

Total cash contractual obligations
$
4,972

 
$
952

 
$
986

 
$
771

 
$
2,263

(a)
Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.
(b)
Excludes fair-market value adjustments of Ameren Illinois' long-term debt of $4 million.
(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.


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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
Baa3
BBB-
BBB
Senior unsecured debt
Baa3
BB+
BBB
Commercial paper
P-3
A-3
F2
Ameren Missouri:
 
 
 
Issuer/corporate credit rating
Baa2
BBB-
BBB+
Secured debt
A3
BBB+
A
Ameren Illinois:
 
 
 
Issuer/corporate credit rating
Baa2
BBB-
BBB-
Secured debt
A3
BBB+
BBB+
Senior unsecured debt
Baa2
BBB-
BBB
Genco:
 
 
 
Issuer/corporate credit rating
—
CCC+
CC
Senior unsecured debt
B2
CCC+
CCC-
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


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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 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


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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 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.
Merchant Generation Operations
•
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,


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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 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 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.


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•
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
•
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 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.
•
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


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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.
•
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.


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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.








 
•
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.
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.





 
•
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


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

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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.






 
•
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.
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.









 
•
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.

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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.
 
•
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.






 
•
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

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


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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.
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.


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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
$
2

 
$
(1
)
Ameren Missouri
2

 
(1
)
Ameren Illinois
(b)

 
(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 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


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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 AER is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.
The following table shows how our earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for 2013 through 2016:
 
Net  Income(a)
Ameren(b)
$
(10
)
Ameren Missouri
(c)

AER
(10
)
(a)
Calculations are based on an estimated tax rate of 37%, 36% and 42% for Ameren, Ameren Missouri and AER, respectively.
 
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(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 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.
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


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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 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.


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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.
 
2013
 
2014
 
2015 – 2017
Ameren(a):
 
 
 
 
 
Coal
99
%
 
78
%
 
60
%
Coal transportation
99

 
90

 
90

Nuclear fuel
100

 
99

 
49

Natural gas for generation
54

 
2

 
1

Natural gas for distribution(b)
82

 
34

 
9

Purchased power for Ameren Illinois(c)
100

 
100

 
50

Ameren Missouri:
 
 
 
 
 
Coal
100
%
 
100
%
 
94
%
Coal transportation
99

 
98

 
98

Nuclear fuel
100

 
99

 
49

Natural gas for generation
34

 
9

 
2

Natural gas for distribution(b)
89

 
33

 
17

Ameren Illinois:
 
 
 
 
 
Natural gas for distribution(b)
81
%
 
35
%
 
9
%
Purchased power(c)
100

 
100

 
50

AER:
 
 
 
 
 
Coal
98
%
 
49
%
 
15
%
Coal transportation
100

 
80

 
80

Natural gas for generation
59

 
—

 
—

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(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
 
Coal Transportation

Fuel
Expense
 
Net
Income(a)
 
Fuel
Expense
 
Net
Income(a)
Ameren(b)(c)
$
7

 
$
(4
)
 
$
3

 
$
(2
)
Ameren Missouri(c)
(d)

 
(d)

 
(d)

 
(d)

AER
7

 
(4
)
 
3

 
(2
)
(a)
Calculations are based on an estimated tax rate of 37%, 36% and 42% for Ameren, Ameren Missouri and AER, respectively.
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(c)
Includes the impact of the FAC.
(d)
Less than $1 million.
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),

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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.
 
Ameren(a)
 
Ameren
Missouri
 
Ameren
Illinois
 
Other(b)
Fair value of contracts at beginning of year, net
$
(43
)
 
$
18

 
$
(307
)
 
$
246

Contracts realized or otherwise settled during the period
49

 
(27
)
 
320

 
(244
)
Changes in fair values attributable to changes in valuation technique and assumptions
—

 
—

 
—

 
—

Fair value of new contracts entered into during the period
18

 
17

 
(1
)
 
2

Other changes in fair value
(177
)
 
(5
)
 
(216
)
 
44

Fair value of contracts outstanding at end of year, net
$
(153
)
 
$
3

 
$
(204
)
 
$
48

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
Includes amounts for Marketing Company, AERG, Genco and intercompany eliminations.
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
$
(8
)
 
$
(8
)
 
$
—

 
$
—

 
$
(16
)
Level 2(a)
(60
)
 
(39
)
 
(1
)
 
—

 
(100
)
Level 3(b)
37

 
(5
)
 
(19
)
 
(50
)
 
(37
)
Total
$
(31
)
 
$
(52
)
 
$
(20
)
 
$
(50
)
 
$
(153
)
Ameren Missouri:

 

 

 

 

Level 1
$
—

 
$
(4
)
 
$
—

 
$
—

 
$
(4
)
Level 2(a)
(5
)
 
(2
)
 
—

 
—

 
(7
)
Level 3(b)
12

 
2

 
—

 
—

 
14

Total
$
7

 
$
(4
)
 
$
—

 
$
—

 
$
3

Ameren Illinois:

 

 

 

 

Level 1
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Level 2(a)
(55
)
 
(37
)
 
(1
)
 
—

 
(93
)
Level 3(b)
(20
)
 
(21
)
 
(20
)
 
(50
)
 
(111
)
Total
$
(75
)
 
$
(58
)
 
$
(21
)
 
$
(50
)
 
$
(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

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Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
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

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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


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AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME (LOSS)
(In millions, except per share amounts)
 
Year Ended December 31,
 
2012
 
2011
 
2010
Operating Revenues:

 

 
 
Electric
$
5,904

 
$
6,530

 
$
6,521

Gas
924

 
1,001

 
1,117

Total operating revenues
6,828

 
7,531

 
7,638

Operating Expenses:

 

 
 
Fuel
1,369

 
1,567

 
1,323

Purchased power
654

 
966

 
1,106

Gas purchased for resale
472

 
570

 
669

Other operations and maintenance
1,752

 
1,820

 
1,821

Impairment and other charges
2,578

 
125

 
589

Depreciation and amortization
775

 
785

 
765

Taxes other than income taxes
468

 
457

 
449

Total operating expenses
8,068

 
6,290

 
6,722

Operating Income (Loss)
(1,240
)
 
1,241

 
916

Other Income and Expenses:
 
 
 
 
 
Miscellaneous income
71

 
69

 
90

Miscellaneous expense
37

 
23

 
33

Total other income
34

 
46

 
57

Interest Charges
448

 
451

 
497

Income (Loss) Before Income Taxes
(1,654
)
 
836

 
476

Income Taxes (Benefit)
(680
)
 
310

 
325

Net Income (Loss)
(974
)
 
526

 
151

Less: Net Income Attributable to Noncontrolling Interest
—

 
7

 
12

Net Income (Loss) Attributable to Ameren Corporation
$
(974
)
 
$
519

 
$
139

 
 
 
 
 
 
Earnings (Loss) per Common Share – Basic and Diluted
$
(4.01
)
 
$
2.15

 
$
0.58

Dividends per Common Share
$
1.600

 
$
1.555

 
$
1.540

Average Common Shares Outstanding
242.6

 
241.5

 
238.8
















The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents


AMEREN CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(In millions)
 
Year Ended December 31,
 
2012
 
2011
 
2010
 
 
 
 
 
 
Net Income (Loss)
$
(974
)
 
$
526

 
$
151

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
22

 
3

 
(2
)
Reclassification adjustments for derivative (gains) losses included in net income, net of income taxes (benefit) of $1, $(3), and $5, respectively
(4
)
 
4

 
(8
)
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $22, $(32), and $6, respectively
32

 
(46
)
 
4

Total other comprehensive income (loss), net of taxes
50

 
(39
)
 
(6
)
Comprehensive Income (Loss)
(924
)
 
487

 
145

Less: Comprehensive Income Attributable to Noncontrolling Interest
8

 
1

 
10

Comprehensive Income (Loss) Attributable to Ameren Corporation
$
(932
)
 
$
486

 
$
135



































The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
 
December 31,
 
2012
 
2011
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
209

 
$
255

Accounts receivable – trade (less allowance for doubtful accounts of $17 and $20, respectively)
401

 
473

Unbilled revenue
322

 
324

Miscellaneous accounts and notes receivable
95

 
69

Materials and supplies
704

 
712

Mark-to-market derivative assets
125

 
115

Current regulatory assets
247

 
215

Current accumulated deferred income taxes, net
171

 
20

Other current assets
95

 
112

Total current assets
2,369

 
2,295

Property and Plant, Net
16,096

 
18,127

Investments and Other Assets:
 
 
 
Nuclear decommissioning trust fund
408

 
357

Goodwill
411

 
411

Intangible assets
16

 
7

Regulatory assets
1,786

 
1,603

Other assets
749

 
845

Total investments and other assets
3,370

 
3,223

TOTAL ASSETS
$
21,835

 
$
23,645

LIABILITIES AND EQUITY
 
 
 
Current Liabilities:
 
 
 
Current maturities of long-term debt
$
355

 
$
179

Short-term debt
—

 
148

Accounts and wages payable
625

 
693

Taxes accrued
68

 
65

Interest accrued
99

 
101

Customer deposits
108

 
98

Mark-to-market derivative liabilities
155

 
161

Current regulatory liabilities
100

 
133

Other current liabilities
188

 
207

Total current liabilities
1,698

 
1,785

Long-term Debt, Net
6,626

 
6,677

Deferred Credits and Other Liabilities:
 
 
 
Accumulated deferred income taxes, net
2,792

 
3,315

Accumulated deferred investment tax credits
72

 
79

Regulatory liabilities
1,589

 
1,502

Asset retirement obligations
445

 
428

Pension and other postretirement benefits
1,178

 
1,344

Other deferred credits and liabilities
668

 
447

Total deferred credits and other liabilities
6,744

 
7,115

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
2

 
2

Other paid-in capital, principally premium on common stock
5,616

 
5,598

Retained earnings
1,006

 
2,369

Accumulated other comprehensive loss
(8
)
 
(50
)
Total Ameren Corporation stockholders’ equity
6,616

 
7,919

Noncontrolling Interests
151

 
149

Total equity
6,767

 
8,068

TOTAL LIABILITIES AND EQUITY
$
21,835

 
$
23,645


The accompanying notes are an integral part of these consolidated financial statements.

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AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
 
Year Ended December 31,
 
2012
 
2011
 
2010
Cash Flows From Operating Activities:
 
 
 
 
 
Net income (loss)
$
(974
)
 
$
526

 
$
151

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
Impairment and other charges
2,578

 
125

 
589

Net gain on sales of properties
(11
)
 
(15
)
 
(10
)
Net mark-to-market (gain) loss on derivatives
22

 
11

 
(15
)
Depreciation and amortization
735

 
747

 
746

Amortization of nuclear fuel
83

 
61

 
54

Amortization of debt issuance costs and premium/discounts
24

 
21

 
23

Deferred income taxes and investment tax credits, net
(714
)
 
346

 
410

Allowance for equity funds used during construction
(36
)
 
(34
)
 
(52
)
Other
25

 
—

 
21

Changes in assets and liabilities:
 
 
 
 
 
Receivables
33

 
231

 
(197
)
Materials and supplies
5

 
(27
)
 
73

Accounts and wages payable
(29
)
 
(36
)
 
20

Taxes accrued
3

 
(3
)
 
10

Assets, other
(10
)
 
76

 
(47
)
Liabilities, other
71

 
(75
)
 
71

Pension and other postretirement benefits
(23
)
 
(102
)
 
(5
)
Counterparty collateral, net
46

 
27

 
(73
)
Premiums paid on long-term debt repurchases
(138
)
 
—

 
—

Taum Sauk insurance recoveries, net of costs
—

 
(1
)
 
54

Net cash provided by operating activities
1,690

 
1,878

 
1,823

Cash Flows From Investing Activities:
 
 
 
 
 
Capital expenditures
(1,240
)
 
(1,030
)
 
(1,042
)
Nuclear fuel expenditures
(91
)
 
(62
)
 
(68
)
Purchases of securities – nuclear decommissioning trust fund
(403
)
 
(220
)
 
(271
)
Sales and maturities of securities – nuclear decommissioning trust fund
384

 
199

 
256

Proceeds from sales of properties
22

 
53

 
27

Tax grants received related to renewable energy properties
18

 
—

 
—

Other
—

 
12

 
2

Net cash used in investing activities
(1,310
)
 
(1,048
)
 
(1,096
)
Cash Flows From Financing Activities:
 
 
 
 
 
Dividends on common stock
(382
)
 
(375
)
 
(368
)
Dividends paid to noncontrolling interest holders
(6
)
 
(6
)
 
(8
)
Short-term debt and credit facility repayments, net
(148
)
 
(581
)
 
(121
)
Redemptions, repurchases, and maturities:
 
 
 
 
 
Long-term debt
(760
)
 
(155
)
 
(310
)
Preferred stock
—

 
—

 
(52
)
Issuances:
 
 
 
 
 
Long-term debt
882

 
—

 
—

Common stock
—

 
65

 
80

Capital issuance costs
(16
)
 
—

 
(15
)
Generator advances received for construction
4

 
5

 
29

Repayments of generator advances received for construction
—

 
(73
)
 
(39
)
Net cash used in financing activities
(426
)
 
(1,120
)
 
(804
)
Net change in cash and cash equivalents
(46
)
 
(290
)
 
(77
)
Cash and cash equivalents at beginning of year
255

 
545

 
622

Cash and cash equivalents at end of year
$
209

 
$
255

 
$
545

 
 
 
 
 
 
Noncash financing activity – dividends on common stock
$
(7
)
 
—

 
—

Cash Paid (Refunded) During the Year:
 
 
 
 
 
Interest (net of $30, $30, and $34 capitalized, respectively)
$
433

 
$
453

 
$
494

Income taxes, net
1

 
(61
)
 
(92
)
The accompanying notes are an integral part of these consolidated financial statements.

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AMEREN CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
 
December 31,
 
2012
 
2011
 
2010
Common Stock:
 
 
 
 
 
Beginning of year
$
2

 
$
2

 
$
2

Shares issued
—

 
—

 
—

Common stock, end of year
2

 
2

 
2

Other Paid-in Capital:
 
 
 
 
 
Beginning of year
5,598

 
5,520

 
5,412

Shares issued
—

 
65

 
80

Stock-based compensation activity
18

 
13

 
14

Regulatory recovery of prior-period common stock issuance costs
—

 
—

 
14

Other paid-in capital, end of year
5,616

 
5,598

 
5,520

Retained Earnings:
 
 
 
 
 
Beginning of year
2,369

 
2,225

 
2,455

Net income (loss) attributable to Ameren Corporation
(974
)
 
519

 
139

Dividends
(389
)
 
(375
)
 
(368
)
Other
—

 
—

 
(1
)
Retained earnings, end of year
1,006

 
2,369

 
2,225

Accumulated Other Comprehensive Income (Loss):
 
 
 
 
 
Derivative financial instruments, beginning of year
7

 
—

 
10

Change in derivative financial instruments
18

 
7

 
(10
)
Derivative financial instruments, end of year
25

 
7

 
—

Deferred retirement benefit costs, beginning of year
(57
)
 
(17
)
 
(23
)
Change in deferred retirement benefit costs
24

 
(40
)
 
6

Deferred retirement benefit costs, end of year
(33
)
 
(57
)
 
(17
)
Total accumulated other comprehensive income (loss), end of year
(8
)
 
(50
)
 
(17
)
Total Ameren Corporation Stockholders’ Equity
$
6,616

 
$
7,919

 
$
7,730

Noncontrolling Interests:
 
 
 
 
 
Beginning of year
149

 
154

 
204

Net income attributable to noncontrolling interest holders
—

 
7

 
12

Dividends paid to noncontrolling interest holders
(6
)
 
(6
)
 
(8
)
Redemptions of preferred stock
—

 
—

 
(52
)
Other
8

 
(6
)
 
(2
)
Noncontrolling interests, end of year
151

 
149

 
154

Total Equity
$
6,767

 
$
8,068

 
$
7,884

 
 
 
 
 
 
 
 
 
 
 
 
Common stock shares at beginning of year
242.6

 
240.4

 
237.4

Shares issued
—

 
2.2

 
3.0

Common stock shares at end of year
242.6

 
242.6

 
240.4



The accompanying notes are an integral part of these consolidated financial statements.

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UNION ELECTRIC COMPANY
STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions)
 
Year Ended December 31,
 
2012

2011
 
2010
Operating Revenues:



 
 
Electric
$
3,132


$
3,222

 
$
3,030

Gas
139


156

 
166

Other
1


5

 
1

Total operating revenues
3,272


3,383

 
3,197

Operating Expenses:



 
 
Fuel
714


866

 
635

Purchased power
78


104

 
162

Gas purchased for resale
64

 
77

 
91

Other operations and maintenance
827

 
934

 
931

Loss from regulatory disallowance
—

 
89

 
—

Depreciation and amortization
440

 
408

 
382

Taxes other than income taxes
304

 
296

 
285

Total operating expenses
2,427

 
2,774

 
2,486

Operating Income
845

 
609

 
711

Other Income and Expenses:
 
 
 
 
 
Miscellaneous income
63

 
61

 
83

Miscellaneous expense
14

 
10

 
13

Total other income
49

 
51

 
70

Interest Charges
223

 
209

 
213

Income Before Income Taxes
671

 
451

 
568

Income Taxes
252

 
161

 
199

Net Income
419

 
290

 
369

Other Comprehensive Income
—

 
—

 
—

Comprehensive Income
$
419

 
$
290

 
$
369

 
 
 
 
 
 
 
 
 
 
 
 
Net Income
$
419

 
$
290

 
$
369

Preferred Stock Dividends
3

 
3

 
5

Net Income Available to Common Stockholder
$
416

 
$
287

 
$
364


















The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

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UNION ELECTRIC COMPANY
BALANCE SHEET
(In millions, except per share amounts)
 
December 31,
 
2012
 
2011
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
148

 
$
201

Advances to money pool
24

 
—

Accounts receivable – trade (less allowance for doubtful accounts of $5 and $7, respectively)
161

 
212

Accounts receivable – affiliates
4

 
1

Unbilled revenue
145

 
139

Miscellaneous accounts and notes receivable
48

 
42

Materials and supplies
397

 
348

Current regulatory assets
163

 
109

Other current assets
69

 
82

Total current assets
1,159

 
1,134

Property and Plant, Net
10,161

 
9,958

Investments and Other Assets:
 
 
 
Nuclear decommissioning trust fund
408

 
357

Intangible assets
14

 
7

Regulatory assets
852

 
855

Other assets
449

 
446

Total investments and other assets
1,723

 
1,665

TOTAL ASSETS
$
13,043

 
$
12,757

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current Liabilities:
 
 
 
Current maturities of long-term debt
$
205

 
$
178

Accounts and wages payable
345

 
414

Accounts payable – affiliates
66

 
73

Taxes accrued
28

 
74

Interest accrued
60

 
62

Current regulatory liabilities
18

 
57

Other current liabilities
77

 
84

Total current liabilities
799

 
942

Long-term Debt, Net
3,801

 
3,772

Deferred Credits and Other Liabilities:
 
 
 
Accumulated deferred income taxes, net
2,443

 
2,132

Accumulated deferred investment tax credits
64

 
70

Regulatory liabilities
917

 
836

Asset retirement obligations
346

 
328

Pension and other postretirement benefits
461

 
491

Other deferred credits and liabilities
158

 
149

Total deferred credits and other liabilities
4,389

 
4,006

Commitments and Contingencies (Notes 2, 10, 14 and 15)

 

Stockholders’ Equity:
 
 
 
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding
511

 
511

Other paid-in capital, principally premium on common stock
1,556

 
1,555

Preferred stock not subject to mandatory redemption
80

 
80

Retained earnings
1,907

 
1,891

Total stockholders’ equity
4,054

 
4,037

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
13,043

 
$
12,757





The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

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UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(In millions)
 
Year Ended December 31,
 
2012
 
2011
 
2010
Cash Flows From Operating Activities:
 
 
 
 
 
Net income
$
419

 
$
290

 
$
369

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Loss from regulatory disallowance
—

 
89

 
—

Gain on sale of properties
—

 
(3
)
 
(5
)
Net mark-to-market (gain) loss on derivatives
—

 
1

 
(1
)
Depreciation and amortization
407

 
377

 
355

Amortization of nuclear fuel
83

 
61

 
54

Amortization of debt issuance costs and premium/discounts
6

 
6

 
4

Deferred income taxes and investment tax credits, net
287

 
155

 
292

Allowance for equity funds used during construction
(31
)
 
(30
)
 
(50
)
Other
8

 
(6
)
 
10

Changes in assets and liabilities:
 
 
 
 
 
Receivables
27

 
66

 
(122
)
Materials and supplies
(48
)
 
(7
)
 
7

Accounts and wages payable
(27
)
 
13

 
(24
)
Taxes accrued
(46
)
 
(6
)
 
55

Assets, other
(35
)
 
79

 
(101
)
Liabilities, other
14

 
(30
)
 
75

Pension and other postretirement benefits
2

 
2

 
(3
)
Taum Sauk insurance recoveries, net of costs
—

 
(1
)
 
54

Premiums paid on long-term debt repurchases
(62
)
 
—

 
—

Net cash provided by operating activities
1,004

 
1,056

 
969

Cash Flows From Investing Activities:
 
 
 
 
 
Capital expenditures
(595
)
 
(550
)
 
(624
)
Nuclear fuel expenditures
(91
)
 
(62
)
 
(68
)
Purchases of securities – nuclear decommissioning trust fund
(403
)
 
(220
)
 
(271
)
Sales and maturities of securities – nuclear decommissioning trust fund
384

 
199

 
256

Money pool advances, net
(24
)
 
—

 
—

Tax grants received related to renewable energy properties
18

 
—

 
—

Other
8

 
6

 
7

Net cash used in investing activities
(703
)
 
(627
)
 
(700
)
Cash Flows From Financing Activities:
 
 
 
 
 
Dividends on common stock
(400
)
 
(403
)
 
(235
)
Dividends on preferred stock
(3
)
 
(3
)
 
(5
)
Redemptions, repurchases, and maturities:
 
 
 
 
 
Long-term debt
(427
)
 
(5
)
 
(70
)
Preferred stock
—

 
—

 
(33
)
Issuances of long-term debt
482

 
—

 
—

Capital issuance costs
(7
)
 
—

 
(4
)
Capital contribution from parent
1

 
—

 
—

Generator advances received for construction
—

 
—

 
13

Repayments of generator advances received for construction
—

 
(19
)
 
—

Net cash used in financing activities
(354
)
 
(430
)
 
(334
)
Net change in cash and cash equivalents
(53
)
 
(1
)
 
(65
)
Cash and cash equivalents at beginning of year
201

 
202

 
267

Cash and cash equivalents at end of year
$
148

 
$
201

 
$
202

 
 
 
 
 
 
Cash Paid (Refunded) During the Year:
 
 
 
 
 
Interest (net of $15, $25, and $26 capitalized, respectively)
$
220

 
$
210

 
$
213

Income taxes, net
(3
)
 
9

 
(106
)
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

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UNION ELECTRIC COMPANY
STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
 
December 31,
 
2012
 
2011
 
2010
Common Stock
$
511

 
$
511

 
$
511

Other Paid-in Capital:
 
 
 
 
 
Beginning of year
1,555

 
1,555

 
1,555

Capital contribution from parent
1

 
—

 
—

Other paid-in capital, end of year
1,556

 
1,555

 
1,555

Preferred Stock Not Subject to Mandatory Redemption:
 
 
 
 
 
Beginning balance
80

 
80

 
113

Redemptions
—

 
—

 
(33
)
Preferred stock not subject to mandatory redemption, end of year
80

 
80

 
80

Retained Earnings:
 
 
 
 
 
Beginning of year
1,891

 
2,007

 
1,878

Net income
419

 
290

 
369

Common stock dividends
(400
)
 
(403
)
 
(235
)
Preferred stock dividends
(3
)
 
(3
)
 
(5
)
Retained earnings, end of year
1,907

 
1,891

 
2,007

Total Stockholders’ Equity
$
4,054

 
$
4,037

 
$
4,153































The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

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AMEREN ILLINOIS COMPANY
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions)
 
 
Year Ended December 31,
 
2012
 
2011
 
2010
Operating Revenues:

 

 
 
Electric
$
1,739

 
$
1,940

 
$
2,061

Gas
786

 
846

 
953

Other
—

 
1

 
—

Total operating revenues
2,525

 
2,787

 
3,014

Operating Expenses:

 

 
 
Purchased power
705

 
853

 
965

Gas purchased for resale
408

 
492

 
578

Other operations and maintenance
684

 
640

 
635

Depreciation and amortization
221

 
215

 
210

Taxes other than income taxes
130

 
129

 
128

Total operating expenses
2,148

 
2,329

 
2,516

Operating Income
377

 
458

 
498

Other Income and Expenses:
 
 
 
 
 
Miscellaneous income
7

 
7

 
7

Miscellaneous expense
17

 
6

 
13

Total other income (expense)
(10
)
 
1

 
(6
)
Interest Charges
129

 
136

 
143

Income Before Income Taxes
238

 
323

 
349

Income Taxes
94

 
127

 
137

Income from Continuing Operations
144

 
196

 
212

Income from Discontinued Operations, net of tax
—

 
—

 
40

Net Income
144

 
196

 
252

Other Comprehensive Loss, Net of Taxes:
 
 
 
 
 
Pension and other postretirement benefit plan activity, net of
 
 
 
 
 
income tax benefit of $(2), $(2) and $(2), respectively
(3
)
 
(3
)
 
(4
)
Other comprehensive income from discontinued operations
—

 
—

 
(1
)
Comprehensive Income
$
141

 
$
193

 
$
247

 
 
 
 
 
 
 
 
 
 
 
 
Net Income
$
144

 
$
196

 
$
252

Preferred Stock Dividends
3

 
3

 
4

Net Income Available to Common Stockholder
$
141

 
$
193

 
$
248

 











The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.

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AMEREN ILLINOIS COMPANY
BALANCE SHEET
(In millions)
 
December 31,
 
2012
 
2011
ASSETS
 
 
 
Current Assets:
 
 
 
Cash and cash equivalents
$
—

 
$
21

Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13, respectively)
182

 
201

Accounts receivable – affiliates
10

 
15

Unbilled revenue
146

 
146

Miscellaneous accounts receivable
22

 
6

Materials and supplies
173

 
199

Current regulatory assets
84

 
306

Current accumulated deferred income taxes, net
85

 
58

Other current assets
47

 
65

Total current assets
749

 
1,017

Property and Plant, Net
5,052

 
4,770

Investments and Other Assets:
 
 
 
Tax receivable – Genco
39

 
56

Goodwill
411

 
411

Regulatory assets
934

 
748

Other assets
97

 
211

Total investments and other assets
1,481

 
1,426

TOTAL ASSETS
$
7,282

 
$
7,213

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current Liabilities:
 
 
 
Current maturities of long-term debt
$
150

 
$
1

Borrowings from money pool
24

 
—

Accounts and wages payable
146

 
133

Accounts payable – affiliates
86

 
103

Taxes accrued
18

 
15

Customer deposits
85

 
76

Mark-to-market derivative liabilities
77

 
99

Mark-to-market derivative liabilities – affiliates
—

 
200

Environmental remediation
37

 
63

Current regulatory liabilities
82

 
76

Other current liabilities
92

 
92

Total current liabilities
797

 
858

Long-term Debt, Net
1,577

 
1,657

Deferred Credits and Other Liabilities:
 
 
 
Accumulated deferred income taxes, net
1,025

 
895

Accumulated deferred investment tax credits
5

 
7

Regulatory liabilities
672

 
666

Pension and other postretirement benefits
406

 
495

Other deferred credits and liabilities
399

 
183

Total deferred credits and other liabilities
2,507

 
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
1,965

 
1,965

Preferred stock not subject to mandatory redemption
62

 
62

Retained earnings
360

 
408

Accumulated other comprehensive income
14

 
17

Total stockholders’ equity
2,401

 
2,452

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
7,282

 
$
7,213



The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.

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AMEREN ILLINOIS COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
 
Year Ended December 31,
 
2012
 
2011
 
2010
Cash Flows From Operating Activities:
 
 
 
 
 
Net income
$
144

 
$
196

 
$
252

Income from discontinued operations, net of tax
—

 
—

 
(40
)
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
214

 
206

 
201

Amortization of debt issuance costs and premium/discounts
11

 
8

 
10

Deferred income taxes and investment tax credits, net
104

 
155

 
210

Other
(11
)
 
(14
)
 
(3
)
Changes in assets and liabilities:
 
 
 
 
 
Receivables
23

 
146

 
(84
)
Materials and supplies
20

 
(21
)
 
9

Accounts and wages payable
(21
)
 
(46
)
 
(44
)
Taxes accrued
3

 
(12
)
 
11

Assets, other
22

 
(3
)
 
32

Liabilities, other
72

 
(30
)
 
33

Pension and other postretirement benefits
(26
)
 
(101
)
 
(7
)
Counterparty collateral, net
40

 
20

 
(100
)
Premiums paid on long-term debt repurchases
(76
)
 
—

 
—

Operating cash flows provided by discontinued operations
—

 
—

 
113

Net cash provided by operating activities
519

 
504

 
593

Cash Flows From Investing Activities:
 
 
 
 
 
Capital expenditures
(442
)
 
(351
)
 
(281
)
Returns from (advances to) ATXI for construction
—

 
49

 
(10
)
Proceeds from note receivable – Genco
—

 
—

 
45

Other
5

 
6

 
5

Capital expenditures of discontinued operations
—

 
—

 
(6
)
Net cash used in investing activities
(437
)
 
(296
)
 
(247
)
Cash Flows From Financing Activities:
 
 
 
 
 
Dividends on common stock
(189
)
 
(327
)
 
(133
)
Dividends on preferred stock
(3
)
 
(3
)
 
(4
)
Money pool borrowings, net
24

 
—

 
—

Redemptions, repurchases, and maturities:
 
 
 
 
 
Long-term debt
(333
)
 
(150
)
 
(40
)
Preferred stock
—

 
—

 
(19
)
Issuances of long-term debt
400

 
—

 
—

Capital issuance costs
(6
)
 
—

 
(4
)
Repayments of generator advances received for construction
—

 
(53
)
 
(39
)
Generator advances received for construction
4

 
5

 
16

Capital contribution from parent
—

 
19

 
—

Net financing activities used in discontinued operations
—

 
—

 
(107
)
Net cash used in financing activities
(103
)
 
(509
)
 
(330
)
Net change in cash and cash equivalents
(21
)
 
(301
)
 
16

Cash and cash equivalents at beginning of year
21

 
322

 
306

Cash and cash equivalents at end of year
$
—

 
$
21

 
$
322

 
 
 
 
 
 
Cash Paid (Refunded) During the Year:
 
 
 
 
 
Interest (net of $2, $2, and $1 capitalized, respectively)
$
125

 
$
137

 
$
160

Income taxes, net
(22
)
 
(14
)
 
(39
)
Noncash investing activity – asset transfer from ATXI
—

 
—

 
7

Noncash financing activity – capital contribution from parent
—

 
—

 
6


The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.

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AMEREN ILLINOIS COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
 
December 31,
 
2012
 
2011
 
2010
Common Stock
$
—

 
$
—

 
$
—

Other Paid-in Capital:
 
 
 
 
 
Beginning of year
1,965

 
1,952

 
2,223

Capital contribution from parent
—

 
13

 
6

Contribution of Ameren-owned preferred stock without consideration
—

 
—

 
33

Transfer of AERG to parent (Notes 1 and 16)
—

 
—

 
(310
)
Other paid-in capital, end of year
1,965

 
1,965

 
1,952

Preferred Stock Not Subject to Mandatory Redemption:
 
 
 
 
 
Beginning balance
62

 
62

 
115

Redemptions
—

 
—

 
(19
)
Contribution of Ameren-owned preferred stock without consideration
—

 
—

 
(33
)
Other
—

 
—

 
(1
)
Preferred stock not subject to mandatory redemption, end of year
62

 
62

 
62

Retained Earnings:
 
 
 
 
 
Beginning of year
408

 
542

 
709

Net income
144

 
196

 
252

Common stock dividends
(189
)
 
(327
)
 
(133
)
Preferred stock dividends
(3
)
 
(3
)
 
(4
)
Transfer of AERG to parent (Notes 1 and 16)
—

 
—

 
(281
)
Other
—

 
—

 
(1
)
Retained earnings, end of year
360

 
408

 
542

Accumulated Other Comprehensive Income:
 
 
 
 
 
Deferred retirement benefit costs, beginning of year
17

 
20

 
25

Change in deferred retirement benefit costs
(3
)
 
(3
)
 
(4
)
Change in accumulated other comprehensive income from discontinued operations
—

 
—

 
(1
)
Deferred retirement benefit costs, end of year
14

 
17

 
20

Total accumulated other comprehensive income, end of year
14

 
17

 
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.

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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 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


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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 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
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:
 
Ameren(a)
 
Ameren Missouri
 
Ameren Illinois
2012
 
 
 
 
 
Fuel(b)
$
276

 
$
198

 
$
—

Gas stored underground
131

 
18

 
113

Other materials and supplies
297

 
181

 
60


$
704

 
$
397

 
$
173

2011
 
 
 
 
 
Fuel(b)
$
251

 
$
150

 
$
—

Gas stored underground
171

 
22

 
149

Other materials and supplies
290

 
176

 
50


$
712

 
$
348

 
$
199

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
Consists of coal, oil, paint, propane, and tire chips.
Property and Plant
We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, 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 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.


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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:
 
2012
 
2011
 
2010
Ameren
8% - 9%

 
8% - 9% 

 
8% - 9% 

Ameren Missouri
8
%
 
8
%
 
8
%
Ameren Illinois
9
%
 
9
%
 
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.
Renewable energy credits and emission allowances are 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.


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2012
 
2011
 
2010
Ameren Missouri
$ (a)

 
$ (a)

 
$
6

Ameren Illinois
4

 
3

 
7

Other(b)(c)
3

 
3

 
22

Ameren(c)
$
7

 
$
6

 
$
35

(a)
Less than $1 million.
(b)
Consists of renewable energy credit expense for Marketing Company and emission allowance expense for Genco and AERG.
(c)
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.
Investments
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 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.


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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
$
139

 
$
137

 
$
130

Ameren Illinois
54

 
57

 
59

Ameren
$
193

 
$
194

 
$
189

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


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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 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.


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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:
 
Ameren
Missouri(a)
 
Ameren
Illinois(b)
 
Genco
 
AERG
 
Ameren(a)
 
Balance at December 31, 2010
$
363

 
$
3

 
$
74

 
$
35

 
$
475

 
Liabilities incurred
—

 
—

 
(c)

 
—

 
(c)

 
Liabilities settled
(1
)
 
(c)

 
(2
)
 
(c)

 
(3
)
 
Accretion in 2011(d)
20

 
(c)

 
5

 
2

 
27

 
Change in estimates(e)
(54
)
 
(c)

 
(6
)
 
(6
)
 
(66
)
 
Balance at December 31, 2011
$
328

 
$
3

 
$
71

 
$
31

 
$
433

(f) 
Liabilities incurred
—

 
—

 
2

 
—

 
2

 
Liabilities settled
(1
)
 
(c)

 
(5
)
 
(c)

 
(6
)
 
Accretion in 2012(d)
18

 
(c)

 
4

 
2

 
24

 
Change in estimates(g)
1

 
(c)

 
(3
)
 
2

 
(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.
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


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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.
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.


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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 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


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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 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


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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 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 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.
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


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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
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 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
 
2011

 
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
Current regulatory assets:
 
 
 
 
 
 
 
 
 
 
 
 
Under-recovered FAC(b)(c)
 
$
145

 
$
145

 
$
—

 
$
83

 
$
83

 
$
—

Under-recovered Illinois electric power costs(b)(d)
 
—

 
—

 
—

 
4

 
—

 
4

Under-recovered PGA(b)(d)
 
12

 
5

 
7

 
8

 
5

 
3

MTM derivative losses(e)
 
90


13


77

 
120

(a) 
21

 
299

Total current regulatory assets
 
$
247

 
$
163

 
$
84

 
$
215

 
$
109

 
$
306

Noncurrent regulatory assets:
 
 
 
 
 
 
 
 
 
 
 
 
Pension and postretirement benefit costs(f)
 
$
772

 
$
348

 
$
424

 
$
878

 
$
382

 
$
496

Income taxes(g)
 
235

 
231

 
4

 
239

 
234

 
5

Asset retirement obligations(h)
 
5

 
—

 
5

 
6

 
—

 
6

Callaway costs(b)(i)
 
44

 
44

 
—

 
48

 
48

 
—

Unamortized loss on reacquired debt(b)(j)
 
181

 
81

 
100

 
47

 
21

 
26

Recoverable costs - contaminated facilities(k)
 
248

 
—

 
248

 
102

 
—

 
102

MTM derivative losses(e)
 
135


7


128


100


13

 
87

SO2 emission allowances sale tracker(l)
 
2

 
2

 
—

 
6

 
6

 
—

Storm costs(m)
 
9

 
9

 
—

 
16

 
16

 
—

Demand-side costs(b)(n)
 
73

 
73

 
—

 
70

 
70

 
—

Reserve for workers’ compensation liabilities(o)
 
12

 
6

 
6

 
13

 
7

 
6

Credit facilities fees(p)
 
6

 
6

 
—

 
10

 
10

 
—

Employee separation costs(q)
 
2

 
1

 
1

 
6

 
3

 
3

Common stock issuance costs(r)
 
7

 
7

 
—

 
10

 
10

 
—

Construction accounting for pollution control equipment(b)(s)
 
23

 
23

 
—

 
25

 
25

 
—

Other(t)
 
32

 
14

 
18

 
27

 
10

 
17

Total noncurrent regulatory assets
 
$
1,786

 
$
852

 
$
934

 
$
1,603

 
$
855

 
$
748

Current regulatory liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Over-recovered FAC(u)
 
$
—

 
$
—

 
$
—

 
$
12

 
$
12

 
$
—

Over-recovered Illinois electric power costs(d)
 
58

 
—

 
58

 
64

 
—

 
64

Over-recovered PGA(d)
 
15

 
—

 
15

 
9

 
—

 
9

MTM derivative gains(v)
 
19


18


1


46


45

 
1

Wholesale distribution refund(w)
 
8

 
—

 
8

 
2

 
—

 
2

Total current regulatory liabilities
 
$
100

 
$
18

 
$
82

 
$
133

 
$
57

 
$
76

Noncurrent regulatory liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Income taxes(x)
 
$
46

 
$
42

 
$
4

 
$
48

 
$
44

 
$
4

Removal costs(y)
 
1,347

 
766

 
581

 
1,269

 
719

 
550

Asset retirement obligation(h)
 
80

 
80

 
—

 
29

 
29

 
—

MTM derivative gains(v)
 
2


2


—


82


4

 
78

Bad debt rider(z)
 
12

 
—

 
12

 
10

 
—

 
10

Pension and postretirement benefit costs tracker(aa)
 
23

 
23

 
—

 
38

 
38

 
—

Energy efficiency rider(ab)
 
20

 
—

 
20

 
24

 
—

 
24

IEIMA revenue requirement reconciliation(ac)
 
55

 
—

 
55

 
—

 
—

 
—

Other(ad)
 
4

 
4

 
—

 
2

 
2

 
—

Total noncurrent regulatory liabilities
 
$
1,589

 
$
917

 
$
672

 
$
1,502

 
$
836

 
$
666

(a)
Includes intercompany eliminations.
(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,

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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.
(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.
(j)
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.
(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.
(r)
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.
(s)
The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution 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.
(t)
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.
(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.



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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
$
22,055

 
$
15,638

 
$
4,985

Natural gas
1,854

 
393

 
1,461

 
23,909

 
16,031

 
6,446

Less: Accumulated depreciation and amortization
8,823

 
6,614

 
1,495

 
15,086

 
9,417

 
4,951

Construction work in progress:
 
 
 
 
 
Nuclear fuel in process
317

 
317

 
—

Other
693

 
427

 
101

Property and plant, net
$
16,096

 
$
10,161

 
$
5,052

2011
 
 
 
 
 
Property and plant, at original cost:
 
 
 
 
 
Electric
$
24,717

 
$
15,099

 
$
4,684

Natural gas
1,751

 
385

 
1,368

 
26,468

 
15,484

 
6,052

Less: Accumulated depreciation and amortization
9,429

 
6,276

 
1,364

 
17,039

 
9,208

 
4,688

Construction work in progress:
 
 
 
 
 
Nuclear fuel in process
255

 
255

 
—

Other
833

 
495

 
82

Property and plant, net
$
18,127

 
$
9,958

 
$
4,770

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
(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:
 
Ameren(a)
 
Ameren
Missouri
 
Ameren
Illinois
2012
$
108

 
$
63

 
$
37

2011
107

 
73

 
18

2010
79

 
53

 
15

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
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.


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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"):
 
2012 Missouri Credit Agreement
2012 Illinois
Credit Agreement
Ameren
$
500

$
300

Ameren Missouri
800

(a)

Ameren Illinois
(a)

$
800

(a)
Not applicable.
Ameren has the option to seek additional commitments 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.
The obligations of all borrowers under the 2012 Credit 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.
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.


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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)
Ameren
(Parent)
 
Ameren
Missouri
 
Total
2012
 
 
 
 
 
Average daily borrowings outstanding during 2012(a)
$
—

 
$
1

 
$
1

Outstanding credit facility borrowings at period end
—

 
—

 
—

Weighted-average interest rate during 2012(a)
—
%
 
4.15
%
 
4.15
%
Peak credit facility borrowings during 2012(a)
$
—

 
$
50

 
$
50

Peak interest rate during 2012
—
%
 
4.15
%
 
4.15
%
2011
 
 
 
 
 
Average daily borrowings outstanding during 2011
$
105

 
$
—

 
$
105

Outstanding credit facility borrowings at period end
—

 
—

 
—

Weighted-average interest rate during 2011
2.30
%
 
—

 
2.30
%
Peak credit facility borrowings during 2011
$
340

 
$
—

 
$
340

Peak interest rate during 2011
4.30
%
 
—

 
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 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


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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 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, 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.


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NOTE 5 - LONG-TERM DEBT AND EQUITY FINANCINGS
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
$
425

 
$
425

Less: Unamortized discount and premium
(1
)
 
(1
)
Long-term debt, net
$
424

 
$
424

Ameren Missouri:
 
 
 
Senior secured notes:(a)
 
 
 
5.25% Senior secured notes due 2012
$
—

 
$
173

4.65% Senior secured notes due 2013
200

 
200

5.50% Senior secured notes due 2014
104

 
104

4.75% Senior secured notes due 2015
114

 
114

5.40% Senior secured notes due 2016
260

 
260

6.40% Senior secured notes due 2017
425

 
425

6.00% Senior secured notes due 2018(b)
179

 
250

5.10% Senior secured notes due 2018
199

 
200

6.70% Senior secured notes due 2019(b)
329

 
450

5.10% Senior secured notes due 2019
244

 
300

5.00% Senior secured notes due 2020
85

 
85

5.50% Senior secured notes due 2034
184

 
184

5.30% Senior secured notes due 2037
300

 
300

8.45% Senior secured notes due 2039(b)
350

 
350

3.90% Senior secured notes due 2042(b)
485

 
—

Environmental improvement and pollution control revenue bonds:
 
 
 
1992 Series due 2022(c)(d)
47

 
47

1993 5.45% Series due 2028(e)
44

 
44

1998 Series A due 2033(c)(d)
60

 
60

1998 Series B due 2033(c)(d)
50

 
50

1998 Series C due 2033(c)(d)
50

 
50

Capital lease obligations:
 
 
 
City of Bowling Green capital lease (Peno Creek CT) through 2022
64

 
69

Audrain County capital lease (Audrain County CT) due 2023
240

 
240

Total long-term debt, gross
4,013

 
3,955

Less: Unamortized discount and premium
(7
)
 
(5
)
Less: Maturities due within one year
(205
)
 
(178
)
Long-term debt, net
$
3,801

 
$
3,772


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2012
 
2011
Ameren Illinois:
 
 
 
Senior secured notes:
 
 
 
8.875% Senior secured notes due 2013(f)(h)
$
150

 
$
150

6.20% Senior secured notes due 2016(f)
54

 
54

6.25% Senior secured notes due 2016(g)
75

 
75

6.125% Senior secured notes due 2017(g)(i)
250

 
250

6.25% Senior secured notes due 2018(g)(i)
144

 
337

9.75% Senior secured notes due 2018(g)(i)
313

 
400

2.70% Senior secured notes due 2022(g)(i)
400

 
—

6.125% Senior secured notes due 2028(g)
60

 
60

6.70% Senior secured notes due 2036(g)
61

 
61

6.70% Senior secured notes due 2036(f)
42

 
42

Environmental improvement and pollution control revenue bonds:
 
 
 
6.20% Series 1992B due 2012
—

 
1

2000 Series A 5.50% due 2014
—

 
51

5.90% Series 1993 due 2023(j)
32

 
32

5.70% 1994A Series due 2024(k)
36

 
36

1993 Series C-1 5.95% due 2026(l)
35

 
35

1993 Series C-2 5.70% due 2026(l)
8

 
8

1993 Series B-1 due 2028(d)(l)
17

 
17

5.40% 1998A Series due 2028(k)
19

 
19

5.40% 1998B Series due 2028(k)
33

 
33

Fair-market value adjustments
4

 
5

Total long-term debt, gross
1,733

 
1,666

Less: Unamortized discount and premium
(6
)
 
(8
)
Less: Maturities due within one year
(150
)
 
(1
)
Long-term debt, net
$
1,577

 
$
1,657

Genco:
 
 
 
Unsecured notes:
 
 
 
Senior notes Series F 7.95% due 2032
$
275

 
$
275

Senior notes Series H 7.00% due 2018
300

 
300

Senior notes Series I 6.30% due 2020
250

 
250

Total long-term debt, gross
825

 
825

Less: Unamortized discount and premium
(1
)
 
(1
)
Less: Maturities due within one year
—

 
—

Long-term debt, net
$
824

 
$
824

Ameren consolidated long-term debt, net
$
6,626

 
$
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-away lien provision similar to that of Ameren Missouri's senior secured notes. The bonds are also backed by an insurance guarantee policy.
(d)
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:
 
2012
 
2011
Ameren Missouri 1992 Series
0.30
%
 
0.34
%
Ameren Missouri 1998 Series A
0.65
%
 
0.69
%
Ameren Missouri 1998 Series B
0.64
%
 
0.68
%
Ameren Missouri 1998 Series C
0.64
%
 
0.69
%
Ameren Illinois 1993 Series B-1
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.
(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

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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 mortgage bonds, and therefore an Ameren Illinois first mortgage bond release date will not occur as long as any of these notes are outstanding.
(j)
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.
(l)
The bonds are callable at 100% of par value.
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
$
—

 
$
205

 
$
150

 
$
—

 
$
355

2014
425

 
109

 
—

 
—

 
534

2015
—

 
120

 
—

 
—

 
120

2016
—

 
266

 
129

 
—

 
395

2017
—

 
431

 
250

 
—

 
681

Thereafter
—

 
2,882

 
1,200

 
825

 
4,907

Total
$
425

 
$
4,013

 
$
1,729

 
$
825

 
$
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.

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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:
 
 
 
Redemption Price(per share)
 
2012
 
2011
Ameren Missouri:
 
 
 
 
 
 
 
Without par value and stated value of $100 per share, 25 million shares authorized
 
 
 
 
 
 
$3.50 Series
130,000 shares
 
$
110.00

 
$
13

 
$
13

$3.70 Series
40,000 shares
 
104.75

 
4

 
4

$4.00 Series
150,000 shares
 
105.625

 
15

 
15

$4.30 Series
40,000 shares
 
105.00

 
4

 
4

$4.50 Series
213,595 shares
 
110.00

(a) 
21

 
21

$4.56 Series
200,000 shares
 
102.47

 
20

 
20

$4.75 Series
20,000 shares
 
102.176

 
2

 
2

$5.50 Series A
14,000 shares
 
110.00

 
1

 
1

Total
 
 
 
$
80

 
$
80

Ameren Illinois:
 
 
 
 
 
 
 
With par value of $100 per share, 2 million shares authorized
 
 
 
 
 
 
4.00% Series
144,275 shares
 
$
101.00

 
$
14

 
$
14

4.08% Series
45,224 shares
 
103.00

 
5

 
5

4.20% Series
23,655 shares
 
104.00

 
2

 
2

4.25% Series
50,000 shares
 
102.00

 
5

 
5

4.26% Series
16,621 shares
 
103.00

 
2

 
2

4.42% Series
16,190 shares
 
103.00

 
2

 
2

4.70% Series
18,429 shares
 
103.00

 
2

 
2

4.90% Series
73,825 shares
 
102.00

 
7

 
7

4.92% Series
49,289 shares
 
103.50

 
5

 
5

5.16% Series
50,000 shares
 
102.00

 
5

 
5

6.625% Series
124,273.75 shares
 
100.00

 
12

 
12

7.75% Series
4,542 shares
 
100.00

 
1

 
1

Total
 
 
 
$
62

 
$
62

Total Ameren(b)
 
 
 
$
142

 
$
142

(a)
In the event of voluntary liquidation, $105.50.
(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 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.

Ameren Missouri
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.

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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
$
71

 
$
19

 
$
179

6.70% senior secured notes due 2019
121

 
35

 
329

5.10% senior secured notes due 2018
1

 
(b)

 
199

5.10% senior secured notes due 2019
56

 
12

 
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.
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
$
87

 
$
36

 
$
313

6.25% senior secured notes due 2018
194

 
47

 
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
Bonds Issuable(b)
 
Required Dividend
Coverage Ratio(c)
Actual Dividend
Coverage Ratio
Preferred Stock
Issuable
Ameren Missouri
          >2.0
4.6

$
4,056

  
>2.5
122.8

$
2,351

Ameren Illinois
          >2.0
7.1

3,439

(d) 
>1.5
2.8

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


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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 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:
 
Required Ratio
Actual Ratio
Restricted payment interest coverage ratio(a)

≥1.75
2.6

Additional indebtedness interest coverage ratio(b)

≥2.50
2.6

Additional indebtedness debt-to-capital ratio(b)

≤60%
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.



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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
$
5

(b) 
$
4

 
$
5

Interest income on industrial development revenue bonds
28

 
28

 
28

Allowance for equity funds used during construction
36

 
34

 
52

Other
2

 
3

 
5

Total miscellaneous income
$
71

 
$
69

 
$
90

Miscellaneous expense:
 
 
 
 
 
Donations
$
24

(c) 
$
8

 
$
19

Other
13

 
15

 
14

Total miscellaneous expense
$
37

 
$
23

 
$
33

Ameren Missouri:
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
Interest and dividend income
$
4

(b) 
$
2

 
$
3

Interest income on industrial development revenue bonds
28

 
28

 
28

Allowance for equity funds used during construction
31

 
30

 
50

Other
—

 
1

 
2

Total miscellaneous income
$
63

 
$
61

 
$
83

Miscellaneous expense:
 
 
 
 
 
Donations
$
9

 
$
3

 
$
8

Other
5

 
7

 
5

Total miscellaneous expense
$
14

 
$
10

 
$
13

Ameren Illinois:
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
Interest and dividend income
$
—

 
$
1

 
$
1

Allowance for equity funds used during construction
5

 
4

 
2

Other
2

 
2

 
4

Total miscellaneous income
$
7

 
$
7

 
$
7

Miscellaneous expense:
 
 
 
 
 
Donations
$
11

(c) 
$
1

 
$
5

Other
6

 
5

 
8

Total miscellaneous expense
$
17

 
$
6

 
$
13

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
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.
(c)
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.



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The following table presents open gross commodity contract volumes by commodity type as of December 31, 2012, and 2011:
  
Quantity (in millions, except as indicated)
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
Coal (in tons)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
96

 
116

 
(e)

 
(e)

 
—

 
(e)

 
(e)

 
(e)

Other(f)
39

 
31

 
(e)

 
(e)

 
7

 
(e)

 
(e)

 
(e)

Ameren
135

 
147

 
(e)

 
(e)

 
7

 
(e)

 
(e)

 
(e)

Fuel oils (in gallons)(g)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
(e)

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

 
26

 
53

Other(f)
(e)

 
(e)

 
(e)

 
(e)

 
52

 
36

 
(e)

 
(e)

Ameren
(e)

 
(e)

 
(e)

 
(e)

 
52

 
36

 
26

 
53

Natural gas (in mmbtu)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
4

 
8

 
(e)

 
(e)

 
—

 
9

 
19

 
19

Ameren Illinois
16

 
42

 
(e)

 
(e)

 
(e)

 
(e)

 
128

 
174

Other(f)
(e)

 
(e)

 
(e)

 
(e)

 
47

 
8

 
(e)

 
(e)

Ameren
20

 
50

 
(e)

 
(e)

 
47

 
17

 
147

 
193

Power (in megawatthours)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
3

 
1

 
(e)

 
(e)

 
2

 
1

 
9

 
6

Ameren Illinois
21

 
11

 
(e)

 
(e)

 
(e)

 
(e)

 
14

 
24

Other(f)
66

 
61

 
9

 
17

 
34

 
30

 
—

 
(9
)
Ameren
90

 
73

 
9

 
17

 
36

 
31

 
23

 
21

Renewable energy credits(h)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
3

 
4

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

Ameren Illinois
12

 
12

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

Other(f)
1

 
1

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

Ameren
16

 
17

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

 
(e)

Uranium (pounds in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri & Ameren
5,142

 
5,553

 
(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 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


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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
$
25

$
(b)

$
(b)

 
 
Other assets
 
14

 
—

 
—

 
 
Total assets
$
39

$
—

$
—

 
Derivative assets not designated as hedging instruments(c)
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
Coal
Other assets
$
1

$
—

$
—

 
Fuel oils
MTM derivative assets
 
10

 
(b)

 
(b)

 
 
Other current assets
 
—

 
8

 
—

 
 
Other assets
 
5

 
4

 
—

 
Natural gas
MTM derivative assets
 
5

 
(b)

 
(b)

 
 
Other current assets
 
—

 
—

 
1

 
 
Other assets
 
1

 
1

 
—

 
Power
MTM derivative assets
 
85

 
(b)

 
(b)

 
 
Other current assets
 
—

 
14

 
—

 
 
Other assets
 
16

 
1

 
—

 
 
Total assets
$
123

$
28

$
1

 
Derivative liabilities not designated as hedging instruments(c)
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
 
Coal
MTM derivative liabilities
$
9

$
(b)

$
—

 
 
Other deferred credits and liabilities
 
4

 
—

 
—

 
Fuel oils
MTM derivative liabilities
 
3

 
(b)

 
—

 
 
Other current liabilities
 
—

 
2

 
—

 
 
Other deferred credits and liabilities
 
3

 
2

 
—

 
Natural gas
MTM derivative liabilities
 
68

 
(b)

 
56

 
 
Other current liabilities
 
—

 
8

 
—

 
 
Other deferred credits and liabilities
 
45

 
7

 
38

 
Power
MTM derivative liabilities
 
74

 
(b)

 
21

 
 
Other current liabilities
 
—

 
4

 
—

 
 
Other deferred credits and liabilities
 
107

 
—

 
90

 
Uranium
MTM derivative liabilities
 
1

 
(b)

 
—

 
 
Other current liabilities
 
—

 
1

 
—

 
 
Other deferred credits and liabilities
 
1

 
1

 
—

 
 
Total liabilities
$
315

$
25

$
205

 

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Balance Sheet Location
 
Ameren(a)
 
Ameren
Missouri
 
Ameren
Illinois
 
2011
 
 
 
 
 
 
 
 
Derivative assets designated as hedging instruments
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
 
Power
MTM derivative assets
$
8

$
(b)

$
(b)

 
 
Other assets
 
16

 
—

 
—

 
 
Total assets
$
24

$
—

$
—

 
Derivative liabilities designated as hedging instruments
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
 
Power
Other deferred credits and liabilities
$
1

$
—

$
—

 
 
Total liabilities
$
1

$
—

$
—

 
Derivative assets not designated as hedging instruments(c)
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
 
Fuel oils
MTM derivative assets
$
29

$
(b)

$
(b)

 
 
Other current assets
 
—

 
17

 
—

 
 
Other assets
 
8

 
6

 
—

 
Natural gas
MTM derivative assets
 
6

 
(b)

 
(b)

 
 
Other current assets
 
—

 
2

 
1

 
 
Other assets
 
—

 
—

 
1

 
Power
MTM derivative assets
 
72

 
(b)

 
(b)

 
 
Other current assets
 
—

 
30

 
—

 
 
Other assets
 
99

 
—

 
77

 
 
Total assets
$
214

$
55

$
79

 
Derivative liabilities not designated as hedging instruments(c)
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
 
Fuel oils
MTM derivative liabilities
$
2

$
(b)

$
—

 
 
Other current liabilities
 
—

 
1

 
—

 
Natural gas
MTM derivative liabilities
 
106

 
(b)

 
90

 
 
Other current liabilities
 
—

 
13

 
—

 
 
Other deferred credits and liabilities
 
92

 
13

 
79

 
Power
MTM derivative liabilities
 
53

 
(b)

 
9

 
 
MTM derivative liabilities - affiliates
 
(b)

 
(b)

 
200

 
 
Other current liabilities
 
—

 
9

 
—

 
 
Other deferred credits and liabilities
 
26

 
—

 
8

 
Uranium
Other deferred credits and liabilities
 
1

 
1

 
—

 
 
Total liabilities
$
280

$
37

$
386

 
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Balance sheet line item not applicable to registrant.
(c)
Includes derivatives subject to regulatory deferral.

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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:
 
 
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Other(a)
2012
 
 
 
 
 
 
 
 
Cumulative gains (losses) deferred in accumulated OCI:
 
 
 
 
 
 
 
 
Power derivative contracts(b)
 
$
47

 
$
—

 
$
—

 
$
47

Interest rate derivative contracts(c)(d)
 
(7
)
 
—

 
—

 
(7
)
Cumulative gains (losses) deferred in regulatory liabilities or assets:
 
 
 
 
 
 
 
 
Fuel oils derivative contracts(e)
 
4

 
4

 
—

 
—

Natural gas derivative contracts(f)
 
(107
)
 
(14
)
 
(93
)
 
—

Power derivative contracts(g)
 
(99
)
 
12

 
(111
)
 
—

Uranium derivative contracts(f)
 
(2
)
 
(2
)
 
—

 
—

2011
 
 
 
 
 
 
 
 
Cumulative gains (losses) deferred in accumulated OCI:
 
 
 
 
 
 
 
 
Power derivative contracts(b)
 
$
19

 
$
—

 
$
—

 
$
19

Interest rate derivative contracts(c)(d)
 
(8
)
 
—

 
—

 
(8
)
Cumulative gains (losses) deferred in regulatory liabilities or assets:
 
 
 
 
 
 
 
 
Fuel oils derivative contracts(e)
 
19

 
19

 
—

 
—

Natural gas derivative contracts(f)
 
(191
)
 
(24
)
 
(167
)
 
—

Power derivative contracts(g)
 
81

 
21

 
(140
)
 
200

Uranium derivative contracts(h)
 
(1
)
 
(1
)
 
—

 
—

(a)
Includes amounts for Marketing Company, Genco, and intercompany eliminations.
(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.
(c)
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.
(d)
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.
(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.

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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 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
$
—

 
$
—

 
$
2

 
$
3

 
$
14

 
$
3

 
$
—

 
$
—

 
$
22

AIC
—

 
—

 
—

 
—

 
1

 
—

 
—

 
—

 
1

Other(b)
71

 
3

 
38

 
10

 
13

 
192

 
3

 
85

 
415

Ameren
$
71

 
$
3

 
$
40

 
$
13

 
$
28

 
$
195

 
$
3

 
$
85

 
$
438

2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AMO
$
1

 
$
35

 
$
1

 
$
4

 
$
26

 
$
4

 
$
—

 
$
—

 
$
71

AIC
—

 
—

 
84

 
—

 
1

 
—

 
—

 
—

 
85

Other(b)
275

 
2

 
4

 
12

 
57

 
194

 
3

 
87

 
634

Ameren
$
276

 
$
37

 
$
89

 
$
16

 
$
84

 
$
198

 
$
3

 
$
87

 
$
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.
(b)
Includes amounts for Marketing Company, AERG, Genco, and AFS.
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
$
—

 
$
—

 
$
1

 
$
1

 
$
10

 
$
3

 
$
—

 
$
—

 
$
15

AIC
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Other(b)
68

 
1

 
29

 
4

 
11

 
185

 
—

 
85

 
383

Ameren
$
68

 
$
1

 
$
30

 
$
5

 
$
21

 
$
188

 
$
—

 
$
85

 
$
398

2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AMO
$
1

 
$
35

 
$
1

 
$
3

 
$
22

 
$
4

 
$
—

 
$
—

 
$
66

AIC
—

 
—

 
84

 
—

 
—

 
—

 
—

 
—

 
84

Other(b)
273

 
—

 
3

 
6

 
43

 
187

 
2

 
86

 
600

Ameren
$
274

 
$
35

 
$
88

 
$
9

 
$
65

 
$
191

 
$
2

 
$
86

 
$
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.
(b)
Includes amounts for Marketing Company, AERG, Genco, and AFS.
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

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collateral posted, and the aggregate amount of 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
$
78

 
$
3

 
$
71

Ameren Illinois
148

 
58

 
84

Other(c)
130

 
7

 
90

Ameren
$
356

 
$
68

 
$
245

2011
 
 
 
 
 
Ameren Missouri
$
102

 
$
8

 
$
86

Ameren Illinois
220

 
96

 
125

Other(c)
134

 
12

 
121

Ameren
$
456

 
$
116

 
$
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.
(c)
Includes amounts for Marketing Company, Genco, and Ameren (parent).
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
$
34

 
Operating Revenues - Electric
 
$
(6
)
 
Operating Revenues - Electric
 
$
(12
)
Interest rate(e)
—

 
Interest Charges
 
1

 
Interest Charges
 
—

2011
 
 
 
 
 
 
 
 
 
Ameren:(d)
 
 
 
 
 
 
 
 
 
Power
$
6

 
Operating Revenues - Electric
 
$
5

 
Operating Revenues - Electric
 
$
(10
)
Interest rate(e)
—

 
Interest Charges
 
(f)

 
Interest Charges
 
—

(a)
Effective portion of gain (loss).
(b)
Effective portion of (gain) loss on settlements.
(c)
Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
(d)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(e)
Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
(f)
Less than $1 million.
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
 
Gain (Loss) Recognized
in Income
 
 
2012
 
2011
Ameren(a)
Coal
 
Operating Expenses - Fuel
 
$
(12
)
 
$
—

 
Fuel oils
 
Operating Expenses - Fuel
 
(11
)
 
(1
)
 
Natural gas (generation)
 
Operating Expenses - Fuel
 
1

 
2

 
Power
 
Operating Revenues - Electric
 
12

 
(2
)
 
 
 
Total
 
$
(10
)
 
$
(1
)
Ameren Missouri
Natural gas (generation)
 
Operating Expenses - Fuel
 
$
—

 
$
(1
)
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

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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
2012
 
2011
Ameren (a)
Fuel oils
 
$
(15
)
 
$
—

 
Natural gas
 
84

 
(26
)
 
Power
 
(180
)
 
80

 
Uranium
 
(1
)
 
(3
)
 
Total
 
$
(112
)
 
$
51

Ameren
Fuel oils
 
$
(15
)
 
$
—

Missouri
Natural gas
 
10

 
—

 
Power
 
(9
)
 
18

 
Uranium
 
(1
)
 
(3
)
 
Total
 
$
(15
)
 
$
15

Ameren
Natural gas
 
$
74

 
$
(26
)
Illinois
Power
 
29

 
212

 
Total
 
$
103

 
$
186

 
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.

(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 of nuclear power plants and the trustee and investment managers. The S&P 500 index comprises stocks of large capitalization companies.
 
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


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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.


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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
 
 
Range [Weighted
 
 
Assets
Liabilities
Valuation Technique(s)
Unobservable Input
 Average]
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
Ameren(b)
Fuel oils
$
9

$
(3
)
Discounted cash flow
Escalation rate(%)(c)
.21 - .68 [.48]
 
 
 
 
 
Counterparty credit risk(%)(d),(e)
.12 - 1 [1]
 
 
 
 
 
Ameren credit risk(%)(d),(e)
2 - 31 [12]
 
 
 
 
Option model
Volatilities(%)(c)
7 - 27 [24]
 
Power(f)
131

(172
)
Option model
Volatilities(%)(d)
13 - 38 [26]
 
 
 
 
 
Average bid/ask consensus peak and off-peak pricing($/MWh)(d)
24 - 45 [36]
 
 
 
 
Discounted cash flow
Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(d)
16 - 52 [32]
 
 
 
 
 
Estimated auction price for FTRs($/MW)(c)
(133,787) - 19,671 [198]
 
 
 
 
 
Nodal basis($/MWh)(d)
(12) - 1 [(1)]
 
 
 
 
 
Counterparty credit risk(%)(d),(e)
.04 - 100 [2]
 
 
 
 
 
Ameren credit risk(%)(d),(e)
2 - 5 [5]
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(c)
4 - 8 [6]
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(c)
5 - 7 [6]
 
Uranium
—

(2
)
Discounted cash flow
Average bid/ask consensus pricing($/pound)(c)
43 - 46 [44]
Ameren Missouri
Fuel oils
$
8

$
(3
)
Discounted cash flow
Escalation rate(%)(c)
.21 - .60 [.44]
 
 
 
 
 
Counterparty credit risk(%)(d),(e)
.12 - 1 [1]
 
 
 
 
 
Ameren Missouri credit risk(%)(d),(e)
2
 
 
 
 
Option model
Volatilities(%)(c)
7 - 27 [24]
 
Power(f)
14

(3
)
Discounted cash flow
Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(d)
24 - 56 [36]
 
 
 
 
 
Estimated auction price for FTRs($/MW)(c)
(281) - 1,851 [178]
 
 
 
 
 
Nodal basis($/MWh)(d)
(5) - (1) [(2)]
 
 
 
 
 
Counterparty credit risk(%)(d),(e)
.22 - 1 [1]
 
 
 
 
 
Ameren Missouri credit risk(%)(d),(e)
2
 
Uranium
—

(2
)
Discounted cash flow
Average bid/ask consensus pricing($/pound)(c)
43 - 46 [44]
Ameren Illinois
Power(f)
$
—

$
(111
)
Discounted cash flow
Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)
22 - 47 [30]
 
 
 
 
 
Nodal basis($/MWh)(c)
(5) - (1) [(3)]
 
 
 
 
 
Ameren Illinois credit risk(%)(d),(e)
5
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(c)
4 - 8 [6]
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(c)
5 - 7 [6]
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(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


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Table of Contents

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)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Ameren(a)
Derivative assets - commodity contracts(b):
 
 
 
 
 
 
 
 
 
Coal
 
$
1

 
$
—

 
$
—

 
$
1

 
Fuel oils
 
6

 
—

 
9

 
15

 
Natural gas
 
4

 
2

 
—

 
6

 
Power
 
—

 
9

 
131

 
140

 
Total derivative assets - commodity contracts
 
$
11

 
$
11

 
$
140

 
$
162

 
Nuclear decommissioning trust fund(c):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
1

 
—

 
—

 
1

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
264

 
—

 
—

 
264

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
47

 
—

 
47

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
81

 
—

 
81

 
Asset-backed securities
 
—

 
11

 
—

 
11

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
265

 
$
141

 
$
—

 
$
406

 
Total Ameren
 
$
276

 
$
152

 
$
140

 
$
568


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Ameren Missouri
Derivative assets - commodity contracts(b):
 
 
 
 
 
 
 
 

Fuel oils
 
$
4

 
$
—

 
$
8

 
$
12

 
Natural gas
 
—

 
1

 
—

 
1

 
Power
 
—

 
1

 
14

 
15

 
Total derivative assets - commodity contracts
 
$
4

 
$
2

 
$
22

 
$
28

 
Nuclear decommissioning trust fund(c):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
1

 
—

 
—

 
1

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
264

 
—

 
—

 
264

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
47

 
—

 
47

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
81

 
—

 
81

 
Asset-backed securities
 
—

 
11

 
—

 
11

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
265

 
$
141

 
$
—

 
$
406

 
Total Ameren Missouri
 
$
269

 
$
143

 
$
22

 
$
434

Ameren Illinois
Derivative assets - commodity contracts(b):
 
 
 
 
 
 
 
 

Natural gas
 
$
—

 
$
1

 
$
—

 
$
1

 
Power
 
—

 
—

 
—

 
—

 
Total Ameren Illinois
 
$
—

 
$
1

 
$
—

 
$
1

Liabilities:
 
 
 
 
 
 
 
 
 
Ameren(a)
Derivative liabilities - commodity contracts(b):
 
 
 
 
 
 
 
 
 
Coal
 
$
13

 
$
—

 
$
—

 
$
13

 
Fuel oils
 
3

 
—

 
3

 
6

 
Natural gas
 
11

 
102

 
—

 
113

 
Power
 
—

 
9

 
172

 
181

 
Uranium
 
—

 
—

 
2

 
2

 
Total Ameren
 
$
27

 
$
111

 
$
177

 
$
315

Ameren Missouri
Derivative liabilities - commodity contracts(b):
 
 
 
 
 
 
 
 

Fuel oils
 
$
1

 
$
—

 
$
3

 
$
4

 
Natural gas
 
7

 
8

 
—

 
15

 
Power
 
—

 
1

 
3

 
4

 
Uranium
 
—

 
—

 
2

 
2

 
Total Ameren Missouri
 
$
8

 
$
9

 
$
8

 
$
25

Ameren Illinois
Derivative liabilities - commodity contracts(b):
 
 
 
 
 
 
 
 

Natural gas
 
$
—

 
$
94

 
$
—

 
$
94

 
Power
 
—

 
—

 
111

 
111

 
Total Ameren Illinois
 
$
—

 
$
94

 
$
111

 
$
205

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(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.
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)
Derivative assets - commodity contracts(b):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
33

 
$
—

 
$
4

 
$
37

 
Natural gas
 
4

 
—

 
2

 
6

 
Power
 
—

 
2

 
193

 
195


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Table of Contents

 
Total derivative assets - commodity contracts
 
$
37

 
$
2

 
$
199

 
$
238

 
Nuclear decommissioning trust fund(c):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
3

 
—

 
—

 
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
234

 
—

 
—

 
234

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
44

 
—

 
44

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
65

 
—

 
65

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
237

 
$
121

 
$
—

 
$
358

 
Total Ameren
 
$
274

 
$
123

 
$
199

 
$
596

Ameren Missouri
Derivative assets - commodity contracts(b):
 
 
 
 
 
 
 
 

Fuel oils
 
$
20

 
$
—

 
$
3

 
$
23

 
Natural gas
 
2

 
—

 
—

 
2

 
Power
 
—

 
1

 
29

 
30

 
Total derivative assets - commodity contracts
 
$
22

 
$
1

 
$
32

 
$
55

 
Nuclear decommissioning trust fund(c):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
3

 
—

 
—

 
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
234

 
—

 
—

 
234

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
44

 
—

 
44

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
65

 
—

 
65

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
237

 
$
121

 
$
—

 
$
358

 
Total Ameren Missouri
 
$
259

 
$
122

 
$
32

 
$
413

Ameren Illinois
Derivative assets - commodity contracts(b):
 
 
 
 
 
 
 
 

Natural gas
 
$
—

 
$
—

 
$
2

 
$
2

 
Power
 
—

 
—

 
77

 
77

 
Total Ameren Illinois
 
$
—

 
$
—

 
$
79

 
$
79

Liabilities:
 
 
 
 
 
 
 
 
 
Ameren(a)
Derivative liabilities - commodity contracts(b):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
2

 
$
—

 
$
—

 
$
2

 
Natural gas
 
22

 
—

 
176

 
198

 
Power
 
—

 
2

 
78

 
80

 
Uranium
 
—

 
—

 
1

 
1

 
Total Ameren
 
$
24

 
$
2

 
$
255

 
$
281

Ameren Missouri
Derivative liabilities - commodity contracts(b):
 
 
 
 
 
 
 
 

Fuel oils
 
$
1

 
$
—

 
$
—

 
$
1

 
Natural gas
 
12

 
—

 
14

 
26

 
Power
 
—

 
1

 
8

 
9

 
Uranium
 
—

 
—

 
1

 
1

 
Total Ameren Missouri
 
$
13

 
$
1

 
$
23

 
$
37

Ameren Illinois
Derivative liabilities - commodity contracts(b):
 
 
 
 
 
 
 
 

Natural gas
 
$
7

 
$
—

 
$
162

 
$
169

 
Power
 
—

 
—

 
217

 
217

 
Total Ameren Illinois
 
$
7

 
$
—

 
$
379

 
$
386

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(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.



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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
$
3

$
(b)

$
1

$
4

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(1
)
 
(b)

 
(b)

 
(1
)
Total realized and unrealized gains (losses)
 
(1
)
 
(b)

 
(b)

 
(1
)
Purchases
 
7

 
(b)

 
—

 
7

Sales
 
(3
)
 
(b)

 
—

 
(3
)
Settlements
 
(2
)
 
(b)

 
—

 
(2
)
Transfers into Level 3
 
1

 
(b)

 
1

 
2

Transfers out of Level 3
 
—

 
(b)

 
(1
)
 
(1
)
Ending balance at December 31, 2012
$
5

$
(b)

$
1

$
6

Change in unrealized gains (losses) related to assets/liabilities held at December 31,2012
$
(1
)
$
(b)

$
—

$
(1
)
Natural gas:
 
 
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
(14
)
$
(160
)
$
—

$
(174
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(25
)
 
(b)

 
(27
)
Total realized and unrealized gains (losses)
 
(2
)
 
(25
)
 
(b)

 
(27
)
Purchases
 
—

 
—

 
1

 
1

Settlements
 
1

 
15

 
(1
)
 
15

Transfers out of Level 3
 
15

 
170

 
—

 
185

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
$
21

$
(140
)
$
234

$
115

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
 
Included in earnings(c)
 
—

 
—

 
27

 
27

Included in OCI
 
—

 
—

 
26

 
26

Included in regulatory assets/liabilities
 
11

 
(226
)
 
40

 
(175
)
Total realized and unrealized gains (losses)
 
11

 
(226
)
 
93

 
(122
)
Purchases
 
21

 
—

 
8

 
29

Sales
 
(1
)
 
—

 
2

 
1

Settlements
 
(37
)
 
255

 
(279
)
 
(61
)
Transfers out of Level 3
 
(4
)
 
—

 
1

 
(3
)
Ending balance at December 31, 2012
$
11

$
(111
)
$
59

$
(41
)
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012
$
—

$
(191
)
(d) $
44

$
(147
)
Uranium:
 
 
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
(1
)
$
(b)

$
(b)

$
(1
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(b)

 
(b)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(b)

 
(b)

 
(2
)
Settlements
 
1

 
(b)

 
(b)

 
1

Ending balance at December 31, 2012
$
(2
)
$
(b)

$
(b)

$
(2
)
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012
$
(1
)
$
(b)

$
(b)

$
(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.

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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
 
Other(a)
 
Ameren
Fuel oils:
 
 
 
 
 
 
 
 
Beginning balance at January 1, 2011
$
30

$
(b)

$
21

$
51

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
 
Included in earnings(c)
 
—


(b)

 
16

 
16

Included in regulatory assets/liabilities
 
19

 
(b)

 
(b)

 
19

Total realized and unrealized gains (losses)
 
19

 
(b)

 
16

 
35

Purchases
 
4

 
(b)

 
1

 
5

Sales
 
(1
)
 
(b)

 
—

 
(1
)
Settlements
 
(30
)
 
(b)

 
(26
)
 
(56
)
Transfers out of Level 3
 
(19
)
 
(b)

 
(11
)
 
(30
)
Ending balance at December 31, 2011
$
3

$
(b)

$
1

$
4

Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011
$
(11
)
$
(b)

$
(7
)
$
(18
)
Natural gas:
 
 
 
 
 
 
 
 
Beginning balance at January 1, 2011
$
(14
)
$
(134
)
$
—

$
(148
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(8
)
 
(107
)
 
(b)

 
(115
)
Total realized and unrealized gains (losses)
 
(8
)
 
(107
)
 
(b)

 
(115
)
Purchases
 
—

 
1

 
—

 
1

Sales
 
—

 
(1
)
 
—

 
(1
)
Settlements
 
8

 
81

 
—

 
89

Ending balance at December 31, 2011
$
(14
)
$
(160
)
$
—

$
(174
)
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011
$
(6
)
$
(72
)
$
—

$
(78
)
Power:
 
 
 
 
 
 
 
 
Beginning balance at January 1, 2011
$
2

$
(352
)
$
386

$
36

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
 
Included in earnings(c)
 
—

 
—

 
(13
)
 
(13
)
Included in OCI
 
—

 
—

 
24

 
24

Included in regulatory assets/liabilities
 
17

 
7

 
51

 
75

Total realized and unrealized gains (losses)
 
17

 
7

 
62

 
86

Purchases
 
30

 
—

 
35

 
65

Sales
 
(1
)
 
—

 
(21
)
 
(22
)
Settlements
 
(27
)
 
205

 
(227
)
 
(49
)
Transfers into Level 3
 
(1
)
 
—

 
1

 
—

Transfers out of Level 3
 
1

 
—

 
(2
)
 
(1
)
Ending balance at December 31, 2011
$
21

$
(140
)
$
234

$
115

Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011
$
1

$
13

$
59

$
73

Uranium:
 
 
 
 
 
 
 
 
Beginning balance at January 1, 2011
$
2

$
(b)

$
(b)

$
2

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(3
)
 
(b)

 
(b)

 
(3
)
Total realized and unrealized gains (losses)
 
(3
)
 
(b)

 
(b)

 
(3
)
Purchases
 
(1
)
 
(b)

 
(b)

 
(1
)
Settlements
 
1

 
(b)

 
(b)

 
1

Ending balance at December 31, 2011
$
(1
)
$
(b)

$
(b)

$
(1
)
Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011
$
—

$
(b)

$
(b)

$
—

(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."

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Table of Contents

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 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:
 
2012
 
2011
Ameren - derivative commodity contracts:(a)



Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
$
2

 
$
—

Transfers out of Level 3 / Transfers into Level 1 - Fuel oils
(1
)
 
(30
)
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
185

 
—

Transfers into Level 3 / Transfers out of Level 2 - Power
—

 
—

Transfers out of Level 3 / Transfers into Level 2 - Power
(3
)
 
(1
)
Net fair value of Level 3 transfers
$
183

 
$
(31
)
Ameren Missouri - derivative commodity contracts:
 
 
 
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
$
1

 
$
—

Transfers out of Level 3 / Transfers into Level 1 - Fuel oils
—

 
(19
)
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
15

 
—

Transfers into Level 3 / Transfers out of Level 2 - Power
—

 
(1
)
Transfers out of Level 3 / Transfers into Level 2 - Power
(4
)
 
1

Net fair value of Level 3 transfers
$
12

 
$
(19
)
Ameren Illinois - derivative commodity contracts:
 
 
 
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
$
170

 
$
—

(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.

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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:
  
2012
 
2011
  
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Ameren:(a)(b)
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
6,981

 
$
7,728

 
$
6,856

 
$
7,800

Preferred stock
142

 
123

 
142

 
92

Ameren Missouri:
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
4,006

 
$
4,625

 
$
3,950

 
$
4,541

Preferred stock
80

 
73

 
80

 
55

Ameren Illinois:
 
 
 
 
 
 
 
Long-term debt (including current portion)
$
1,727

 
$
2,020

 
$
1,658

 
$
1,943

Preferred stock
62

 
49

 
62

 
37

Genco:
 
 
 
 
 
 
 
Long-term debt (including current portion)
$
824

 
$
618

 
$
824

 
$
839

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Preferred stock along with the noncontrolling interest of EEI is recorded in "Noncontrolling Interests" on the balance sheet.
NOTE 9 - NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS
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 and
 
losses resulting from those sales for the years ended December 31, 2012, 2011, and 2010:
 
2012
 
2011
 
2010
Proceeds from sales and maturities
$
384

 
$
199

 
$
256

Gross realized gains
6

 
5

 
5

Gross realized losses
2

 
4

 
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
$
133

 
$
8

 
(a)

 
$
141

Equity securities
145

 
130

 
11

 
264

Cash
1

 
—

 
—

 
1

Other(b)
2

 
—

 
—

 
2

Total
$
281

 
$
138

 
$
11

 
$
408

2011
 
 
 
 
 
 
 
Debt securities
$
114

 
$
7

 
(a)

 
$
121

Equity securities
145

 
101

 
12

 
234

Cash
3

 
—

 
—

 
3

Other(b)
(1
)
 
—

 
—

 
(1
)
Total
$
261

 
$
108

 
$
12

 
$
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.

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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:
 
Cost
 
Fair Value
Less than 5 years
$
78

 
$
79

5 years to 10 years
32

 
35

Due after 10 years
23

 
27

Total
$
133

 
$
141

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
 
12 Months or Greater
 
Total
  
Fair Value
 
Gross
Unrealized
Losses
 
Fair Value
 
Gross
Unrealized
Losses
 
Fair Value
 
Gross
Unrealized
Losses
Debt securities
$
17

 
$ (a)

 
$ (a)

 
$ (a)

 
$
17

 
$ (a)

Equity securities
7

 
1

 
14

 
10

 
21

 
11

Total
$
24

 
$
1

 
$
14

 
$
10

 
$
38

 
$
11

(a)
Amount less than $1 million.
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


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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.
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


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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 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)
$
1,183

Ameren Missouri
464

Ameren Illinois
408

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.



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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
$
3,929

 
(b)

 
$
3,645

 
(b)

Change in benefit obligation:
 
 
 
 
 
 
 
Net benefit obligation at beginning of year
$
3,865

 
$
1,257

 
$
3,451

 
$
1,120

Service cost
83

 
24

 
75

 
22

Interest cost
170

 
52

 
180

 
58

Plan amendments(c)(d)
(6
)
 
(75
)
 
(16
)
 
—

Participant contributions
—

 
16

 
—

 
18

Actuarial loss
246

 
5

 
348

 
96

Curtailments(e)
2

 
(1
)
 
—

 
—

Benefits paid
(209
)
 
(73
)
 
(173
)
 
(66
)
Early retiree reinsurance program receipt
(b)

 
2

 
(b)

 
3

Federal subsidy on benefits paid
(b)

 
4

 
(b)

 
6

Net benefit obligation at end of year
4,151

 
1,211

 
3,865

 
1,257

Change in plan assets:
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
2,876

 
896

 
2,722

 
797

Actual return on plan assets
392

 
110

 
224

 
9

Employer contributions
134

 
45

 
103

 
129

Federal subsidy on benefits paid
(b)

 
4

 
(b)

 
6

Early retiree reinsurance program receipt
(b)

 
2

 
(b)

 
3

Participant contributions
—

 
16

 
—

 
18

Benefits paid
(209
)
 
(73
)
 
(173
)
 
(66
)
Fair value of plan assets at end of year
3,193

 
1,000

 
2,876

 
896

Funded status - deficiency
958

 
211

 
989

 
361

Accrued benefit cost at December 31
$
958

 
$
211

 
$
989

 
$
361

Amounts recognized in the balance sheet consist of:
 
 
 
 
 
 
 
Noncurrent asset
$
—

 
$
(14
)
 
$
—

 
$
—

Current liability
3

 
2

 
3

 
3

Noncurrent liability
955

 
223

 
986

 
358

Net liability recognized
$
958

 
$
211

 
$
989

 
$
361

Amounts recognized in regulatory assets consist of:
 
 
 
 
 
 
 
Net actuarial loss
$
699

 
$
103

 
$
734

 
$
177

Prior service cost (credit)
(6
)
 
(24
)
 
(7
)
 
(28
)
Transition obligation
—

 
—

 
—

 
2

Amounts (pretax) recognized in accumulated OCI consist of:
 
 
 
 
 
 
 
Net actuarial loss
89

 
51

 
79

 
43

Prior service cost (credit)
(17
)
 
(65
)
 
(15
)
 
(7
)
Total
$
765

 
$
65

 
$
791

 
$
187

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(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.
(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.

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The following table presents the assumptions used to determine our benefit obligations at December 31, 2012, and 2011:
  
Pension Benefits
 
Postretirement Benefits
  
2012
 
2011
 
2012
 
2011
Discount rate at measurement date
4.00
%
 
4.50
%
 
4.00
%
 
4.50
%
Increase in future compensation
3.50

 
3.50

 
3.50

 
3.50

Medical cost trend rate (initial)
—

 
—

 
5.00

 
5.50

Medical cost trend rate (ultimate)
—

 
—

 
5.00

 
5.00

Years to ultimate rate
0

 
0

 
0

 
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:
  
Pension Benefits
 
Postretirement Benefits
  
2012
 
2011
 
2010
 
2012
 
2011
 
2010
AMO
$
52

 
$
43

 
$
36

 
$
9

 
$
9

 
$
11

AIC
46

 
28

 
23

 
35

 
118

 
20

Other
36

 
32

 
22

 
1

 
2

 
5

Ameren(a)
134

 
103

 
81

 
45

 
129

 
36

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
 
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.

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

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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
 
Percentage of Plan Assets at December  31,
2012
 
2011
Pension Plan:
 
 
 
 
 
Cash and cash equivalents
0 - 5  %
 
2
%
 
2
%
Equity securities:
 
 
 
 
 
U.S. large capitalization
29 - 39
 
34

 
33
%
U.S. small and mid-capitalization
2 - 12
 
7

 
7
%
International and emerging markets
9 - 19
 
13

 
11
%
Total equity
50 - 60
 
54

 
51
%
Debt securities
35 - 45
 
39

 
42
%
Real estate
0 -   9  
 
4

 
4
%
Private equity
0 -   4  
 
1

 
1
%
Total
 
 
100
%
 
100
%
Postretirement Plans:
 
 
 
 
 
Cash and cash equivalents
0 - 10 %
 
4
%
 
4
%
Equity securities:
 
 
 
 
 
U.S. large capitalization
33 - 43
 
40
%
 
38
%
U.S. small and mid-capitalization
3 - 13
 
8
%
 
8
%
International
10 - 20
 
14
%
 
13
%
Total equity
55 - 65
 
62
%
 
59
%
Debt securities
30 - 40
 
34
%
 
37
%
Total
 
 
100
%
 
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.

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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)
 
Total
Cash and cash equivalents
$
1

 
$
30

 
$
—

 
$
31

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
83

 
1,028

 
—

 
1,111

U.S. small and mid-capitalization
235

 
12

 
—

 
247

International and emerging markets
134

 
306

 
—

 
440

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
832

 
—

 
832

Municipal bonds
—

 
177

 
—

 
177

U.S. treasury and agency securities
—

 
250

 
—

 
250

Other
—

 
42

 
—

 
42

Real estate
—

 
—

 
118

 
118

Private equity
—

 
—

 
19

 
19

Derivative assets
—

 
—

 
—

 
—

Derivative liabilities
(1
)
 
—

 
—

 
(1
)
Total
$
452

 
$
2,677

 
$
137

 
$
3,266

Less: Medical benefit assets at December 31(a)
 
 
 
 
 
 
(102
)
Plus: Net receivables at December 31(b)
 
 
 
 
 
 
29

Fair value of pension plans assets at year end
 
 
 
 
 
 
$
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)
 
Total
Cash and cash equivalents
$
—

 
$
31

 
$
—

 
$
31

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
72

 
922

 
—

 
994

U.S. small and mid-capitalization
202

 
11

 
—

 
213

International and emerging markets
115

 
213

 
—

 
328

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
794

 
—

 
794

Municipal bonds
—

 
176

 
—

 
176

U.S. treasury and agency securities
—

 
230

 
—

 
230

Other
—

 
47

 
—

 
47

Real estate
—

 
—

 
108

 
108

Private equity
—

 
—

 
23

 
23

Derivative assets
1

 
—

 
—

 
1

Derivative liabilities
(1
)
 
—

 
—

 
(1
)
Total
$
389

 
$
2,424

 
$
131

 
$
2,944

Less: Medical benefit assets at December 31(a)
 
 
 
 
 
 
(91
)
Plus: Net receivables at December 31(b)
 
 
 
 
 
 
23

Fair value of pension plans assets at year end
 
 
 
 
 
 
$
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.

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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
$
108

 
$
7

 
$
—

 
$
3

 
$
—

 
$
118

Private equity
23

 
(7
)
 
8

 
(5
)
 
—

 
19

2011:
 
 
 
 
 
 
 
 
 
 
 
Real estate
$
98

 
$
10

 
$
—

 
$
—

 
$
—

 
$
108

Private equity
28

 
(10
)
 
11

 
(6
)
 
—

 
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)
 
Total
Cash and cash equivalents
$
83

 
$
1

 
$
—

 
$
84

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
277

 
88

 
—

 
365

U.S. small and mid-capitalization
66

 
—

 
—

 
66

International
51

 
69

 
—

 
120

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
94

 
—

 
94

Municipal bonds
—

 
97

 
—

 
97

U.S. treasury and agency securities
—

 
78

 
—

 
78

Asset-backed securities
—

 
18

 
—

 
18

Other
—

 
22

 
—

 
22

Total
$
477

 
$
467

 
$
—

 
$
944

Plus: Medical benefit assets at December 31(a)
 
 
 
 
 
 
102

Less: Net payables at December 31(b)
 
 
 
 
 
 
(46
)
Fair value of postretirement benefit plans assets at year end
 
 
 
 
 
 
$
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)
 
Total
Cash and cash equivalents
$
1

 
$
66

 
$
—

 
$
67

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
235

 
78

 
—

 
313

U.S. small and mid-capitalization
57

 
—

 
—

 
57

International
44

 
56

 
—

 
100

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
75

 
—

 
75

Municipal bonds
—

 
86

 
—

 
86

U.S. treasury and agency securities
—

 
82

 
—

 
82

Asset-backed securities
—

 
23

 
—

 
23

Other
—

 
35

 
—

 
35

Total
$
337

 
$
501

 
$
—

 
$
838

Plus: Medical benefit assets at December 31(a)
 
 
 
 
 
 
91

Less: Net payables at December 31(b)
 
 
 
 
 
 
(33
)
Fair value of postretirement benefit plans assets at year end
 
 
 
 
 
 
$
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.

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(b)
Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.
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
Ameren(a)
 
Postretirement Benefits
Ameren(a)
2012
 
 
 
Service cost
$
83

 
$
24

Interest cost
170

 
52

Expected return on plan assets
(213
)
 
(60
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
(3
)
 
(8
)
Actuarial loss
77

 
9

Curtailment loss(b)
2

 
—

Net periodic benefit cost
$
116

 
$
19

2011
 
 
 
Service cost
$
75

 
$
22

Interest cost
180

 
58

Expected return on plan assets
(216
)
 
(54
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
(1
)
 
(8
)
Actuarial loss
42

 
5

Net periodic benefit cost
$
80

 
$
25

2010
 
 
 
Service cost
$
68

 
$
20

Interest cost
185

 
62

Expected return on plan assets
(212
)
 
(56
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
6

 
(8
)
Actuarial loss
18

 
1

Net periodic benefit cost
$
65

 
$
21

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
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)
$
(1
)
 
$
(4
)
Net actuarial loss
97

 
19

Accumulated OCI:
 
 
 
Prior service cost (credit)
(2
)
 
(9
)
Net actuarial loss
7

 
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.

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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
$
63

 
$
51

 
$
42

 
$
10

 
$
11

 
$
11

Ameren Illinois
37

 
16

 
10

 
4

 
11

 
7

Other (b)
16

 
13

 
13

 
5

 
3

 
3

Ameren(a)(b)
116

 
80

 
65

 
19

 
25

 
21

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
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:
  
Pension Benefits
 
Postretirement Benefits
  
Paid from
Qualified
Trust
 
        Paid from
         Company
      Funds
 
        Paid from
         Qualified
      Trust
 
        Paid from
         Company
      Funds
 
        Federal
         Subsidy
2013
$
235

 
$
3

 
$
60

 
$
2

 
$
3

2014
243

 
3

 
62

 
2

 
3

2015
247

 
3

 
65

 
2

 
3

2016
253

 
3

 
68

 
2

 
4

2017
255

 
3

 
71

 
2

 
4

2018 - 2022
1,317

 
13

 
398

 
11

 
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
4.50
%
 
5.25
%
 
5.75
%
 
4.50
%
 
5.25
%
 
5.75
%
Expected return on plan assets
7.75

 
8.00

 
8.00

 
7.50

 
7.75

 
8.00

Increase in future compensation
3.50

 
3.50

 
3.50

 
3.50

 
3.50

 
3.50

Medical cost trend rate (initial)
—

 
—

 
—

 
5.50

 
6.00

 
6.50

Medical cost trend rate (ultimate)
—

 
—

 
—

 
5.00

 
5.00

 
5.00

Years to ultimate rate
0

 
0

 
0

 
1 year

 
2 years

 
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
$
(2
)
 
$
124

 
$
—

 
$
36

0.25% increase in salary scale
2

 
13

 
—

 
—

1.00% increase in annual medical trend
—

 
—

 
1

 
40

1.00% decrease in annual medical trend
—

 
—

 
—

 
(38
)
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:
 
2012
 
2011
 
2010
Ameren Missouri
$
16

 
$
16

 
$
16

Ameren Illinois
9

 
8

 
8

Other
4

 
4

 
3

Ameren(a)
29

 
28

 
27

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.

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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
  
Share
Units
 
Weighted-average
Fair Value per Unit
Nonvested at January 1, 2012
1,156,831

 
$
31.70

Granted(a)
717,151

 
35.68

Unearned or forfeited(b)
(477,928
)
 
32.04

Earned and vested(c)
(203,567
)
 
34.01

Nonvested at December 31, 2012
1,192,487

 
$
33.56

(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b)
Includes share units granted in 2010 that were not earned based on performance provisions of the award grants.
(c)
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.
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 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.

NOTE 13 - INCOME TAXES
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2012, 2011, and 2010:

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Ameren
 
Ameren Missouri
 
Ameren Illinois
2012
 
 
 
 
 
Statutory federal income tax rate:
35
 %
 
35
 %
 
35
 %
Increases (decreases) from:
 
 
 
 
 
Depreciation differences
—

 
(1
)
 
—

Amortization of investment tax credit
1

 
(1
)
 
(1
)
State tax
5

 
3

 
6

Reserve for uncertain tax positions
—

 
1

 
—

Effective income tax rate
41
 %
 
37
 %
 
40
 %
2011
 
 
 
 
 
Statutory federal income tax rate:
35
 %
 
35
 %
 
35
 %
Increases (decreases) from:
 
 
 
 
 
Depreciation differences
(1
)
 
(2
)
 
—

Amortization of investment tax credit
(1
)
 
(1
)
 
(1
)
State tax
4

 
3

 
5

Other permanent items(a)
—

 
1

 
—

Effective income tax rate
37
 %
 
36
 %
 
39
 %
2010
 
 
 
 
 
Statutory federal income tax rate:
35
 %
 
35
 %
 
35
 %
Increases (decreases) from:
 
 
 
 
 
Non-deductible impairment of goodwill
32

 
—

 
—

Depreciation differences
(4
)
 
(3
)
 
—

Amortization of investment tax credit
(2
)
 
(1
)
 
(1
)
State tax
8

 
3

 
5

Reserve for uncertain tax positions
(1
)
 
—

 
—

Tax credits
(3
)
 
—

 
—

Change in federal tax law(b)
3

 
1

 
—

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.



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The following table presents the components of income tax expense (benefit) for the years ended December 31, 2012, 2011, and 2010:
 
Ameren(a)
 
Ameren Missouri
 
Ameren Illinois
2012
 
 
 
 
 
Current taxes:
 
 
 
 
 
Federal
$
31

 
$
(25
)
 
$
(7
)
State
3

 
(10
)
 
(3
)
Deferred taxes:
 
 
 
 
 
Federal
(590
)
 
248

 
76

State
(117
)
 
44

 
30

Deferred investment tax credits, amortization
(7
)
 
(5
)
 
(2
)
Total income tax expense (benefit)
$
(680
)
 
$
252

 
$
94

2011
 
 
 
 
 
Current taxes:
 
 
 
 
 
Federal
$
(27
)
 
$
3

 
$
(24
)
State
(5
)
 
2

 
(4
)
Deferred taxes:
 
 
 
 
 
Federal
273

 
129

 
123

State
76

 
31

 
34

Deferred investment tax credits, amortization
(7
)
 
(4
)
 
(2
)
Total income tax expense
$
310

 
$
161

 
$
127

2010
 
 
 
 
 
Current taxes:
 
 
 
 
 
Federal
$
13

 
$
(14
)
 
$
(20
)
State
10

 
(15
)
 
(5
)
Deferred taxes:
 
 
 
 
 
Federal
274

 
206

 
132

State
36

 
27

 
32

Deferred investment tax credits, amortization
(8
)
 
(5
)
 
(2
)
Total income tax expense
$
325

 
$
199

 
$
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.

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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
$
4,201

 
$
2,386

 
$
1,106

Long-lived asset impairments
(986
)
 
—

 
—

Deferred intercompany tax gain/basis step-up
2

 
(1
)
 
39

Regulatory assets, net
73

 
73

 
—

Deferred employee benefit costs
(337
)
 
(84
)
 
(102
)
Purchase accounting
(10
)
 
—

 
(27
)
ARO
(44
)
 
(7
)
 
1

Other(b)
(278
)
 
50

 
(77
)
Total net accumulated deferred income tax liabilities(c)
$
2,621

 
$
2,417

 
$
940

2011
 
 
 
 
 
Accumulated deferred income taxes, net liability (asset):
 
 
 
 
 
Plant related
$
3,826

 
$
2,134

 
$
1,003

Long-lived asset impairments
(15
)
 
—

 
—

Deferred intercompany tax gain/basis step-up
3

 
(1
)
 
55

Regulatory assets, net
73

 
73

 
—

Deferred employee benefit costs
(367
)
 
(88
)
 
(109
)
Purchase accounting
35

 
—

 
(27
)
ARO
(37
)
 
—

 
1

Other
(223
)
 
6

 
(86
)
Total net accumulated deferred income tax liabilities(d)
$
3,295

 
$
2,124

 
$
837

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below.
(c)
Includes $26 million recorded in "Other current assets" on Ameren Missouri's balance sheet as of December 31, 2012.
(d)
Includes $8 million recorded in "Other current assets" on Ameren Missouri's balance sheet as of December 31, 2011.
The following table presents the components of deferred tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2012:
 
Ameren
 
Ameren Missouri
 
Ameren Illinois
Net operating loss carryforwards:
 
 
 
 
 
Federal(a)
$
212

 
$
61

 
$
61

State(b)
29

 
3

 
11

Total net operating loss carryforwards
$
241

 
$
64

 
$
72

Tax credit carryforwards:
 
 
 
 
 
Federal(c)
$
87

 
$
11

 
$
—

State(d)
35

 
1

 
1

State valuation allowance(e)
(4
)
 
(1
)
 
(1
)
Total tax credit carryforwards
$
118

 
$
11

 
$
—

(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.

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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
$
135

 
$
88

 
$
—

Increases based on tax positions prior to 2010
72

 
40

 
27

Decreases based on tax positions prior to 2010
(38
)
 
(12
)
 
(2
)
Increases based on tax positions related to 2010
77

 
48

 
31

Changes related to settlements with taxing authorities
—

 
—

 
—

Decreases related to the lapse of statute of limitations
—

 
—

 
—

Unrecognized tax benefits - December 31, 2010
$
246

 
$
164

 
$
56

Increases based on tax positions prior to 2011
22

 
15

 
—

Decreases based on tax positions prior to 2011
(125
)
 
(63
)
 
(41
)
Increases based on tax positions related to 2011
17

 
13

 
—

Changes related to settlements with taxing authorities
(10
)
 
(5
)
 
(4
)
Decreases related to the lapse of statute of limitations
(2
)
 
—

 
—

Unrecognized tax benefits - December 31, 2011
$
148

 
$
124

 
$
11

Increases based on tax positions prior to 2012
5

 
4

 
—

Decreases based on tax positions prior to 2012
(13
)
 
(7
)
 
(1
)
Increases based on tax positions related to 2012
17

 
15

 
3

Changes related to settlements with taxing authorities
—

 
—

 
—

Decreases related to the lapse of statute of limitations
(1
)
 
—

 
—

Unrecognized tax benefits - December 31, 2012
$
156

 
$
136

 
$
13

Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of December 31, 2010
$
—

 
$
3

 
$
—

Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of December 31, 2011
$
1

 
$
1

 
$
—

Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates as of December 31, 2012
$
1

 
$
3

 
$
(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.

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
$
8

 
$
4

 
$
—

Interest charges for 2010
9

 
6

 
2

Liability for interest - December 31, 2010
$
17

 
$
10

 
$
2

Interest income for 2011
(11
)
 
(3
)
 
(1
)
Interest payment
(1
)
 
(1
)
 
—

Liability for interest - December 31, 2011
$
5

 
$
6

 
$
1

Interest charges for 2012
1

 
2

 
—

Liability for interest - December 31, 2012
$
6

 
$
8

 
$
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

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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.
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


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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 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.
 
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.
Gas Sales and Transportation Agreement
Under a gas transportation agreement, Genco acquires gas transportation service from Ameren Missouri. This agreement expires in February 2016.


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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.


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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
Income Statement Line Item                    
 
  
 
Ameren
Missouri
 
Ameren
Illinois
Ameren Missouri power supply agreements
Operating Revenues
 
2012
 
$(b)

 
$(a)

with Ameren Illinois
 
 
2011
 
2

 
(a)

 
 
 
2010
 
2

 
(a)

Ameren Missouri and Genco gas
Operating Revenues
 
2012
 
1

 
(a)

transportation agreement
 
 
2011
 
1

 
(a)

 
 
 
2010
 
1

 
(a)

Ameren Missouri and Ameren Illinois
Operating Revenues
 
2012
 
19

 
1

rent and facility services
 
 
2011
 
16

 
1

 
 
 
2010
 
16

 
1

Ameren Illinois transmission services agreement
Operating Revenues
 
2012
 
(a)

 
15

with Marketing Company
 
 
2011
 
(a)

 
10

 
 
 
2010
 
(a)

 
10

Total Operating Revenues
 
 
2012
 
$
20

 
$
16

 
 
 
2011
 
19

 
11

 
 
 
2010
 
19

 
11

Ameren Illinois power supply agreements
Purchased Power
 
2012
 
$(a)

 
$
311

with Marketing Company
 
 
2011
 
(a)

 
232

 
 
 
2010
 
(a)

 
233

Ameren Illinois power supply
Purchased Power
 
2012
 
(a)

 
(b)

agreements with Ameren Missouri
 
 
2011
 
(a)

 
2

 
 
 
2010
 
(a)

 
2

Total Purchased Power
 
 
2012
 
$(a)

 
$
311

 
 
 
2011
 
(a)

 
234

 
 
 
2010
 
(a)

 
235

Gas purchases from Genco
Gas Purchased for Resale
 
2012
 
$(a)

 
$
—

 
 
 
2011
 
(a)

 
—

 
 
 
2010
 
(a)

 
1

Ameren Services support services
Other Operations and
 
2012
 
$
106

 
$
88

agreement
Maintenance
 
2011
 
114

 
87

 
 
 
2010
 
128

 
102

AFS support services agreement
Other Operations and
 
2012
 
(a)

 
(a)

 
Maintenance
 
2011
 
(a)

 
(a)

 
 
 
2010
 
7

 
(b)

Insurance premiums(c)
Other Operations and
 
2012
 
(b)

 
(a)

 
Maintenance
 
2011
 
(b)

 
(a)

 
 
 
2010
 
1

 
(a)

Total Other Operations and
 
 
2012
 
$
106

 
$
88

Maintenance Expenses
 
 
2011
 
114

 
87

 
 
 
2010
 
136

 
102

Money pool borrowings (advances)
Interest (Charges)
 
2012
 
$(b)

 
$(b)

 
Income
 
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.


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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
$
375


$
—

 
Pool participation
12,219

(a)  
118

(b)  
 
$
12,594

(c)  
$
118

 
Property damage:
 
 
 
 
Nuclear Electric Insurance Ltd.
$
2,750

(d)  
$
23

(e)  
Replacement power:
 
 
 
 
Nuclear Electric Insurance Ltd
$
490

(f)  
$
9

(e)  
Energy Risk Assurance Company
$
64

(g)  
$
—

 
(a)
Provided through mandatory participation in an industrywide retrospective premium assessment program.
(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.

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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)
$
588

 
$
32

 
$
32

 
$
33

 
$
33

 
$
33

 
$
425

Less amount representing interest
284

 
27

 
27

 
27

 
27

 
27

 
149

Present value of minimum capital lease payments
$
304

 
$
5

 
$
5

 
$
6

 
$
6

 
$
6

 
$
276

Operating leases(c)
272

 
31

 
27

 
26

 
26

 
25

 
137

Total lease obligations
$
576

 
$
36

 
$
32

 
$
32

 
$
32

 
$
31

 
$
413

Ameren Missouri:
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital lease payments(b)
$
588

 
$
32

 
$
32

 
$
33

 
$
33

 
$
33

 
$
425

Less amount representing interest
284

 
27

 
27

 
27

 
27

 
27

 
149

Present value of minimum capital lease payments
$
304

 
$
5

 
$
5

 
$
6

 
$
6

 
$
6

 
$
276

Operating leases(c)
123

 
12

 
12

 
12

 
12

 
13

 
62

Total lease obligations
$
427

 
$
17

 
$
17

 
$
18

 
$
18

 
$
19

 
$
338

Ameren Illinois:
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating leases(c)
$
7

 
$
1

 
$
1

 
$
1

 
$
1

 
$
1

 
$
2

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(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.
The following table presents total rental expense, included in operating expenses, for the years ended December 31, 2012, 2011, and 2010:
 
2012
 
2011
 
2010
Ameren(a)
$
48

 
$
47

 
$
52

Ameren Missouri
29

 
29

 
29

Ameren Illinois
19

 
17

 
19

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

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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
$
908

 
$
349

 
$
36

 
$
421

 
$
3

 
$
174

 
$
1,891

2014
774

 
254

 
89

 
309

 
3

 
167

 
1,596

2015
702

 
138

 
87

 
164

 
4

 
117

 
1,212

2016
732

 
54

 
95

 
78

 
4

 
62

 
1,025

2017
701

 
34

 
78

 
55

 
5

 
50

 
923

Thereafter
277

 
105

 
277

 
687

 
99

 
246

 
1,691

Total
$
4,094

 
$
934

 
$
662

 
$
1,714

 
$
118

 
$
816

 
$
8,338

Ameren Missouri:
 
 
 
 
 
 
 
 
 
 
 
 
 
2013
$
620

 
$
57

 
$
36

 
$
19

 
$
3

 
$
106

 
$
841

2014
625

 
43

 
89

 
19

 
3

 
123

 
902

2015
614

 
25

 
87

 
19

 
4

 
87

 
836

2016
644

 
10

 
95

 
19

 
4

 
38

 
810

2017
676

 
5

 
78

 
19

 
5

 
26

 
809

Thereafter
245

 
28

 
277

 
130

 
99

 
144

 
923

Total
$
3,424

 
$
168

 
$
662

 
$
225

 
$
118

 
$
524

 
$
5,121

Ameren Illinois:
 
 
 
 
 
 
 
 
 
 
 
 
 
2013
$
—

 
$
270

 
$
—

 
$
401

 
$
—

 
$
24

 
$
695

2014
—

 
206

 
—

 
289

 
—

 
22

 
517

2015
—

 
110

 
—

 
145

 
—

 
24

 
279

2016
—

 
44

 
—

 
59

 
—

 
24

 
127

2017
—

 
29

 
—

 
36

 
—

 
24

 
89

Thereafter
—

 
78

 
—

 
559

 
—

 
102

 
739

Total
$
—

 
$
737

 
$
—

 
$
1,489

 
$
—

 
$
220

 
$
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.
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
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' 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.


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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)
$
105

$
215

-
$
260

$
795

-
$
975

$
1,115

-
$
1,340

Genco
30

100

-
125

220

-
270

350

-
425

AERG
5

20

-
25

20

-
25

45

-
55

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 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


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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 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


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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 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


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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, 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


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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
 
Recorded
Liability(a)
  
Low
 
High
 
Ameren
$
257

 
$
339

 
$
257

Ameren Missouri
5

 
6

 
5

Ameren Illinois
252

 
333

 
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 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


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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.
Ameren Missouri had liability insurance coverage for 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.


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The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of December 31, 2012:
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Total(a)
4
 
74
 
96
 
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.
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


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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 operations in Ameren Illinois’ statements of income for the year ended December 31, 2010:
Operating revenues
$
274

Operating expenses
201

Operating income
73

Other income
1

Interest charges
14

Income taxes
20

Income from discontinued operations, net of tax
$
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)
$
2,578

 
$
—

 
$
—

 
$
2,578

2011
 
 
 
 
 
 
 
Ameren(a)
123

 
—

 
2

 
125

Ameren Missouri
89

 
—

 
—

 
89

2010
 
 
 
 
 
 
 
Ameren(a)
101

 
420

 
68

 
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


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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 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.


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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 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.


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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
$
3,251

 
$
2,509

 
$
1,063

 
$
5

 
$
—

 
$
6,828

Intersegment revenues
21

 
16

 
310

 
4

 
(351
)
 
—

Depreciation and amortization
440

 
221

 
102

 
12

 
—

 
775

Interest and dividend income
32

 
—

 
—

 
40

 
(39
)
 
33

Interest charges
223

 
129

 
95

 
38

 
(37
)
 
448

Income taxes (benefit)
252

 
94

 
(1,019
)
 
(7
)
 
—

 
(680
)
Net income (loss) attributable to Ameren Corporation(a)
416

 
141

 
(1,516
)
(b) 
(15
)
 
—

 
(974
)
Capital expenditures
595

 
442

 
178

 
25


—

 
1,240

Total assets
13,043

 
7,282

 
1,300

 
1,228

 
(1,018
)
 
21,835

2011
 
 
 
 
 
 
 
 
 
 
 
External revenues
$
3,358

 
$
2,774

 
$
1,394

 
$
5

 
$
—

 
$
7,531

Intersegment revenues
25

 
13

 
235

 
4

 
(277
)
 
—

Depreciation and amortization
408

 
215

 
143

 
19

 
—

 
785

Interest and dividend income
30

 
1

 
—

 
44

 
(43
)
 
32

Interest charges
209

 
136

 
105

 
44

 
(43
)
 
451

Income taxes (benefit)
161

 
127

 
32

 
(10
)
 
—

 
310

Net income (loss) attributable to Ameren Corporation(a)
287

 
193

 
45


(6
)
 
—

 
519

Capital expenditures
550

 
351

 
153

 
(24
)
(c) 
—

 
1,030

Total assets
12,757

 
7,213

 
3,833

 
1,211

 
(1,369
)
 
23,645

2010
 
 
 
 
 
 
 
 
 
 
 
External revenues
$
3,176

 
$
3,002

 
$
1,459

 
$
1

 
$
—

 
$
7,638

Intersegment revenues
21

 
12

 
234

 
13

 
(280
)
 
—

Depreciation and amortization
382

 
210

 
146

 
27

 
—

 
765

Interest and dividend income
31

 
1

 
1

 
25

 
(25
)
 
33

Interest charges
213

 
143

 
133

 
35

 
(27
)
 
497

Income taxes (benefit)
199

 
137

 
6

 
(17
)
 
—

 
325

Net income (loss) attributable to Ameren Corporation(a)
364

 
208

 
(409
)
(b) 
(24
)
 
—

 
139

Capital expenditures
624

 
281

 
101

 
36

 
—

 
1,042

Total assets
12,504

 
7,406

 
3,934

 
1,354

 
(1,687
)
 
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.
(c)
Includes the elimination of intercompany transfers.

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SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
Quarter Ended(a)
 
Operating
Revenues
 
Operating
Income (Loss)(b)
 
Net Income (Loss)
Attributable to
Ameren Corporation
 
Earnings (Loss) per
Common
Share - Basic and
Diluted
Ameren
 
 
 
 
 
 
 
 
March 31, 2012
 
$
1,658

 
$
(422
)
 
$
(403
)
 
$
(1.66
)
March 31, 2011
 
1,904

 
227

 
71

 
0.29

June 30, 2012
 
1,660

 
363

 
211

 
0.87

June 30, 2011
 
1,781

 
316

 
138

 
0.57

September 30, 2012
 
2,001

 
635

 
374

 
1.54

September 30, 2011
 
2,268

 
550

 
285

 
1.18

December 31, 2012
 
1,509

 
(1,816
)
 
(1,156
)
 
(4.76
)
December 31, 2011
 
1,578

 
148

 
25

 
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 effects of rounding and changes in the number of weighted-average shares outstanding each period.
(b)
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.
Quarter Ended
 
Operating
Revenues
 
Operating
Income
 
Net Income
(Loss)
 
Net Income (Loss)
Available
to Common
Stockholder
Ameren Missouri
 
 
 
 
 
 
 
 
March 31, 2012
 
$
691

 
$
78

 
$
22

 
$
21

March 31, 2011
 
772

 
77

 
22

 
21

June 30, 2012
 
844

 
269

 
144

 
143

June 30, 2011
 
822

 
176

 
91

 
90

September 30, 2012
 
1,064

 
429

 
237

 
236

September 30, 2011
 
1,115

 
333

 
191

 
190

December 31, 2012
 
673

 
69

 
16

 
16

December 31, 2011
 
674

 
23

 
(14
)
 
(14
)
Quarter Ended
 
Operating
Revenues
 
Operating
Income
 
Net Income
 
Net Income
Available
to Common
Stockholder
Ameren Illinois
 
 
 
 
 
 
 
 
March 31, 2012
 
$
724

 
$
89

 
$
28

 
$
27

March 31, 2011
 
808

 
88

 
34

 
33

June 30, 2012
 
564

 
86

 
33

 
32

June 30, 2011
 
623

 
99

 
38

 
37

September 30, 2012
 
648

 
151

 
71

 
71

September 30, 2011
 
745

 
196

 
98

 
98

December 31, 2012
 
589

 
51

 
12

 
11

December 31, 2011
 
611

 
75

 
26

 
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.

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(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). 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.
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Information required by Items 401, 405, 406 and 407(c)(3),(d)(4) and (d)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 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


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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.

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

 
(b)

 
1,577,354

Equity compensation plans not approved by security holders
 
—

 
—

 
—

Total
 
1,813,814

 
(b)

 
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.

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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.”
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
Page No.
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
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 181.
(b)
 
Exhibits are listed in the Exhibit Index commencing on page 181.


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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)
2012
 
2011
 
2010
Operating revenues
$
—

 
$
—

 
$
—

Impairment and other charges
—

 
—

 
372

Operating expenses
22

 
15

 
24

Operating loss
(22
)
 
(15
)
 
(396
)
Equity in earnings (loss) of subsidiaries
(954
)
 
527

 
535

Interest income from affiliates
40

 
44

 
28

Miscellaneous expense
4

 
4

 
3

Interest charges
39

 
41

 
56

Income tax (benefit)
(5
)
 
(8
)
 
(31
)
Net income (loss)
(974
)
 
519

 
139

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
22

 
3

 
(2
)
Reclassification adjustments for derivative (gains) losses included in net income, net of income taxes (benefit) of $1, $(3), and $5, respectively
(4
)
 
4

 
(8
)
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $22, $(32), and $6, respectively
32

 
(46
)
 
4

Total other comprehensive income (loss), net of taxes
50

 
(39
)
 
(6
)
Comprehensive Income (Loss)
$
(924
)
 
$
480

 
$
133

 
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET
(In millions)
December 31, 2012
 
December 31, 2011
Assets:
 
 
 
Cash and cash equivalents
$
23

 
$
3

Advances to money pool
316

 
340

Accounts and notes receivable - affiliates
31

 
57

Other current assets
49

 
—

Total current assets
419

 
400

Investments in subsidiaries
5,962

 
7,482

Note receivable - affiliates
462

 
425

Other non-current assets
320

 
333

Total assets
$
7,163

 
$
8,640

Liabilities and Stockholders’ Equity:
 
 
 
Short-term debt
$
—

 
$
148

Accounts payable - affiliates
10

 
13

Other current liabilities
33

 
62

Total current liabilities
43

 
223

Long-term debt
424

 
424

Other deferred credits and liabilities
80

 
74

Total liabilities
547

 
721

Commitments and Contingencies
 
 
 
Stockholders’ Equity:
 
 
 
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6
2

 
2

Other paid-in capital, principally premium on common stock
5,616

 
5,598

Retained earnings
1,006

 
2,369

Accumulated other comprehensive income (loss)
(8
)
 
(50
)
Total stockholders’ equity
6,616

 
7,919

Total liabilities and stockholders’ equity
$
7,163

 
$
8,640

 


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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)
2012
 
2011
 
2010
Net cash flows provided by operating activities
$
532

 
$
804

 
$
241

Cash flows from investing activities:
 
 
 
 
 
Money pool advances, net
24

 
(276
)
 
18

Notes receivable - affiliates, net
(20
)
 
358

 
242

Investments in subsidiaries
(2
)
 
(94
)
 
(13
)
Distributions from subsidiaries
21

 
3

 
1

Other
(5
)
 
(5
)
 
—

Net cash flows provided by (used in) investing activities
18

 
(14
)
 
248

Cash flows from financing activities:
 
 
 
 
 
Dividends on common stock
(382
)
 
(375
)
 
(368
)
Short-term debt and credit facility borrowings, net
(148
)
 
(481
)
 
(221
)
Issuances of common stock
—

 
65

 
80

Net cash flows used in financing activities
(530
)
 
(791
)
 
(509
)
Net change in cash and cash equivalents
$
20

 
$
(1
)
 
$
(20
)
Cash and cash equivalents at beginning of year
3

 
4

 
24

Cash and cash equivalents at the end of year
$
23

 
$
3

 
$
4

Cash dividends received from consolidated subsidiaries
$
610

 
$
730

 
$
368

 
 
 
 
 
 
Noncash financing activity – dividends on common stock
$
(7
)
 
$
—

 
$
—



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

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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.
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.

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SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
(in millions)
 
 
 
 
 
 
 
 
 
Column A
Column B
 
Column C
 
Column D
 
Column E
Description
Balance at
Beginning
of Period
 
(1)
Charged to Costs
and Expenses
 
(2)
Charged to Other
Accounts(a)
 
Deductions(b)
 
Balance at End
of Period
Ameren:
 
 
 
 
 
 
 
 
 
Deducted from assets - allowance for doubtful accounts:
 
 
 
 
 
 
 
 
 
2012
$
20

 
$
30

 
$
2

 
$
35

 
$
17

2011
23

 
41

 
—

 
44

 
20

2010
24

 
33

 
—

 
34

 
23

Deferred tax valuation allowance:
 
 
 
 
 
 
 
 
 
2012
$
2

 
$
2

 
$
—

 
$
—

 
$
4

2011
2

 
—

 
—

 
—

 
2

2010
—

 
2

 
—

 
—

 
2

Ameren Missouri:
 
 
 
 
 
 
 
 
 
Deducted from assets - allowance for doubtful accounts:
 
 
 
 
 
 
 
 
 
2012
$
7

 
$
11

 
$
—

 
$
13

 
$
5

2011
8

 
17

 
—

 
18

 
7

2010
6

 
14

 
—

 
12

 
8

Deferred tax valuation allowance:
 
 
 
 
 
 
 
 
 
2012
$
1

 
$
—

 
$
—

 
$
—

 
$
1

2011
1

 
—

 
—

 
—

 
1

2010
—

 
1

 
—

 
—

 
1

Ameren Illinois:
 
 
 
 
 
 
 
 
 
Deducted from assets - allowance for doubtful accounts:
 
 
 
 
 
 
 
 
 
2012
$
13

 
$
19

 
$
2

 
$
22

 
$
12

2011
13

 
24

 
—

 
24

 
13

2010
17

 
18

 
—

 
22

 
13

Deferred tax valuation allowance:
 
 
 
 
 
 
 
 
 
2012
$
—

 
$
1

 
$
—

 
$
—

 
$
1

2011
—

 
—

 
—

 
—

 
—

2010
—

 
—

 
—

 
—

 
—

(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.

180
Table of Contents

SIGNATURES
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.
 
 
AMEREN CORPORATION (registrant)
 
 
 
 
Date:
March 1, 2013
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
 
Chairman, President and Chief Executive Officer, and Director (Principal Executive Officer)
 
March 1, 2013
Thomas R. Voss
  
 
 

 
 
 
 
/s/ Martin J. Lyons, Jr.
 
Executive Vice President and Chief Financial Officer (Principal Financial Officer)
 
March 1, 2013
Martin J. Lyons, Jr.
  
 
 
 
 
 
 
 
 
 
/s/ Bruce A. Steinke
 
Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer)
 
March 1, 2013
     Bruce A. Steinke
 
 
 
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Stephen F. Brauer
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Catherine S. Brune
  

 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Ellen M. Fitzsimmons
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Walter J. Galvin
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Gayle P.W. Jackson
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
James C. Johnson
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Steven H. Lipstein
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Patrick T. Stokes
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Stephen R. Wilson
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Jack D. Woodard
  
 
 
 
 
 
 
 
*By
/s/ Martin J. Lyons, Jr.
  
 
 
March 1, 2013
 
Martin J. Lyons, Jr.
 
 
 
 
 
Attorney-in-Fact
 
 
 
 

181
Table of Contents

 
 
UNION ELECTRIC COMPANY (registrant)
 
 
 
 
Date:
March 1, 2013
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
 
Chairman, President and Chief Executive Officer, and Director (Principal Executive Officer)
 
March 1, 2013
Warner L. Baxter
  

 
 
 
 
 
 

/s/ Martin J. Lyons, Jr.
 
Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer)
 
March 1, 2013
Martin J. Lyons, Jr.
  
 
 
 
 
 
 
 

/s/ Bruce A. Steinke
 
Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer)
 
March 1, 2013
     Bruce A. Steinke
 
 
 
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Daniel F. Cole
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Adam C. Heflin
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Michael L. Moehn
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Charles D. Naslund
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Gregory L. Nelson
  
 
 
 
 
 
 
 
*By
/s/ Martin J. Lyons, Jr.
  
 
 
March 1, 2013
 
Martin J. Lyons, Jr.
 
 
 
 
 
Attorney-in-Fact
 
 
 
 

 

182
Table of Contents



 
 
AMEREN ILLINOIS COMPANY (registrant)
 
 
 
 
 
Date:
March 1, 2013
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
 
Chairman, President and Chief Executive Officer, Chief Executive Officer, and Director (Principal Executive Officer)
 
March 1, 2013
Richard J. Mark
  

 
 
 
 
 
 
/s/ Martin J. Lyons, Jr.
 
Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer)
 
March 1, 2013
Martin J. Lyons, Jr.
  

 
 
 
 
 
 
/s/ Bruce A. Steinke
 
Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer)
 
March 1, 2013
     Bruce A. Steinke
 

 
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Daniel F. Cole
  
 
 
 
 
 
 
 
*
 
Director
 
March 1, 2013
Gregory L. Nelson
  
 
 
 
 
 
 
 
*By
/s/ Martin J. Lyons, Jr.
  
 
 
March 1, 2013
 
Martin J. Lyons, Jr.
 
 
 
 
 
Attorney-in-Fact
 
 
 
 

183
Table of Contents

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)
Ameren
Restated Articles of Incorporation of Ameren
Annex F to Part I of the Registration Statement on Form S-4, File No. 33-64165
3.2(i)
Ameren
Certificate of Amendment to Ameren's Restated Articles of Incorporation filed December 14, 1998
1998 Form 10-K, Exhibit 3(i),
File No. 1-14756
3.3(i)
Ameren
Certificate of Amendment to Ameren's Restated Articles of Incorporation filed April 21, 2011
April 21, 2011 Form 8-K, Exhibit 3(i),
File No. 1-14756
3.4(i)
Ameren
Certificate of Amendment to Ameren's Restated Articles of Incorporation filed December 18, 2012
December 18, 2012 Form 8-K, Exhibit 3.1(i),
File No. 1-14756
3.5(i)
Ameren Missouri
Restated Articles of Incorporation of Ameren Missouri
1993 Form 10-K, Exhibit 3(i),
File No. 1-2967
3.6(i)
Ameren Illinois
Restated Articles of Incorporation of Ameren Illinois
2010 Form 10-K, Exhibit 3.4(i),
File No. 1-3672
3.7(ii)
Ameren
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
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
4.2
Ameren
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
4.3
Ameren
Ameren Indenture Company Order dated May 15, 2009, establishing 8.875% Senior Notes, due 2014 (including the global note)
May 15, 2009 Form 8-K, Exhibits 4.3 and
4.4, File No. 1-14756
4.4
Ameren
Ameren Missouri
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
Exhibit B-1, File No. 2-4940
4.5
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
4.6
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated as of April 1, 1971
April 1971 Form 8-K, Exhibit 6,
File No. 1-2967
4.7
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated as of February 1, 1974
February 1974 Form 8-K, Exhibit 3,
File No. 1-2967
4.8
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated as of July 7, 1980
Exhibit 4.6, File No. 2-69821
4.9
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated as of October 1, 1993, relative to Series 2028
1993 Form 10-K, Exhibit 4.8,
File No. 1-2967
4.10
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated as of February 1, 2000
2000 Form 10-K, Exhibit 4.1,
File No. 1-2967
4.11
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated August 15, 2002
August 23, 2002 Form 8-K, Exhibit 4.3,
File No. 1-2967
4.12
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated March 5, 2003, relative to Series BB
March 11, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.13
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated April 1, 2003, relative to Series CC
April 10, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967

184
Table of Contents

4.14
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated July 15, 2003, relative to Series DD
August 4, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.15
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated October 1, 2003, relative to Series EE
October 8, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.16
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004A (1998A)
March 31, 2004 Form 10-Q, Exhibit 4.1,
File No. 1-2967
4.17
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004B (1998B)
March 31, 2004 Form 10-Q, Exhibit 4.2,
File No. 1-2967
4.18
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004C (1998C)
March 31, 2004 Form 10-Q, Exhibit 4.3,
File No. 1-2967
4.19
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004H (1992)
March 31, 2004 Form 10-Q, Exhibit 4.8,
File No. 1-2967
4.20
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated May 1, 2004 relative to Series FF
May 18, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.21
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated September 1, 2004 relative to Series GG
September 23, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.22
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated January 1, 2005 relative to Series HH
January 27, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.23
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated July 1, 2005 relative to Series II
July 21, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.24
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated December 1, 2005 relative to Series JJ
December 9, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.25
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated June 1, 2007 relative to Series KK
June 15, 2007 Form 8-K, Exhibit 4.5,
File No. 1-2967
4.26
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated April 1, 2008 relative to Series LL
April 8, 2008 Form 8-K, Exhibit 4.7,
File No. 1-2967
4.27
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated June 1, 2008 relative to Series MM
June 19, 2008 Form 8-K, Exhibit 4.5,
File No. 1-2967
4.28
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated March 1, 2009 relative to Series NN
March 23, 2009 Form 8-K, Exhibit 4.5,
File No. 1-2967
4.29
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated May 15, 2012
Exhibit 4.45, File No. 333-182258
4.30
Ameren
Ameren Missouri
Supplemental Indenture to the Ameren Missouri Mortgage dated September 1, 2012 relative to Series OO
September 11, 2012 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.31
Ameren
Ameren Missouri
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.
1992 Form 10-K, Exhibit 4.38,
File No. 1-2967
4.32
Ameren
Ameren Missouri
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
March 31, 2004 Form 10-Q, Exhibit 4.10,
File No. 1-2967
4.33
Ameren
Ameren Missouri
Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri
September 30, 1998 Form 10-Q,
Exhibit 4.28, File No. 1-2967
4.34
Ameren
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
March 31, 2004 Form 10-Q, Exhibit 4.11,
File No. 1-2967
4.35
Ameren
Ameren Missouri
Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri
September 30, 1998 Form 10-Q,
Exhibit 4.29, File No. 1-2967
4.36
Ameren
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
March 31, 2004 Form 10-Q, Exhibit 4.12,
File No. 1-2967
4.37
Ameren
Ameren Missouri
Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri
September 30, 1998 Form 10-Q,
Exhibit 4.30, File No. 1-2967

185
Table of Contents

4.38
Ameren
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
March 31, 2004 Form 10-Q, Exhibit 4.13,
File No. 1-2967
4.39
Ameren
Ameren Missouri
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)
August 23, 2002 Form 8-K, Exhibit 4.1,
File No. 1-2967
4.40
Ameren
Ameren Missouri
First Supplemental Indenture to the Ameren Missouri Indenture, dated as of May 15, 2012
Exhibit 4.48, File No. 333-182258
4.41
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated March 10, 2003, establishing the 5.50% Senior Secured Notes due 2034 (including the global note)
March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.42
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated April 9, 2003, establishing the 4.75% Senior Secured Notes due 2015 (including the global note)
April 10, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.43
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated July 28, 2003, establishing the 5.10% Senior Secured Notes due 2018 (including the global note)
August 4, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.44
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated October 7, 2003, establishing the 4.65% Senior Secured Notes due 2013 (including the global note)
October 8, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.45
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated May 13, 2004, establishing the 5.50% Senior Secured Notes due 2014 (including the global note)
May 18, 2004 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.46
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated September 1, 2004, establishing the 5.10% Senior Secured Notes due 2019 (including the global note)
September 23, 2004 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.47
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated January 27, 2005, establishing the 5.00% Senior Secured Notes due 2020 (including the global note)
January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.48
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated July 21, 2005, establishing the 5.30% Senior Secured Notes due 2037 (including the global note)
July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.49
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated December 8, 2005, establishing the 5.40% Senior Secured Notes due 2016 (including the global note)
December 9, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.50
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated June 15, 2007, establishing the 6.40% Senior Secured Notes due 2017 (including the global note)
June 15, 2007 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.51
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated April 8, 2008, establishing the 6.00% Senior Secured Notes due 2018 (including the global note)
April 8, 2008 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-2967
4.52
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated June 19, 2008, establishing the 6.70% Senior Secured Notes due 2019 (including the global note)
June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.53
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated March 20, 2009, establishing 8.45% Senior Secured Notes due 2039 (including the global note)
March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.54
Ameren
Ameren Missouri
Ameren Missouri Indenture Company Order dated September 11, 2012, establishing 3.90% Senior Secured Notes due 2042 (including the global note)
September 30, 2012 Form 10-Q, Exhibit 4.1 and September 11, 2012 Form 8-K, Exhibit 4.2, File No. 1-2967
4.55
Ameren
Ameren Illinois
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)
Exhibit 4.4, File No. 333-59438
4.56
Ameren
Ameren Illinois
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
4.57
Ameren
Ameren Illinois
Second Supplemental Indenture to the CIPS Indenture, dated as of March 1, 2010
Exhibit 4.17, File No. 333-166095
4.58
Ameren
Ameren Illinois
Third Supplemental Indenture to the CIPS Indenture, dated as of October 1, 2010
2010 Form 10-K, Exhibit 4.59, File No. 1-3672
4.59
Ameren
Ameren Illinois
Ameren Illinois Global Note, dated October 1, 2010, representing CIPS Indenture Senior Notes, 6.125% due 2028
2010 Form 10-K, Exhibit 4.60, File No. 1-3672
4.60
Ameren
Ameren Illinois
Ameren Illinois Global Note, dated October 1, 2010, representing CIPS Indenture Senior Notes, 6.70% Series Secured Notes due 2036
2010 Form 10-K, Exhibit 4.62, File No. 1-3672

186
Table of Contents

4.61
Ameren
Ameren Illinois
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
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
4.62
Ameren
Ameren Illinois
Supplemental Indenture to the CILCO Mortgage, dated December 1, 1949
December 1949 Form 8-K, Exhibit A, File No. 1-2732
4.63
Ameren
Ameren Illinois
Supplemental Indenture to the CILCO Mortgage, dated July 1, 1957
July 1957 Form 8-K, Exhibit A, File No. 1-2732
4.64
Ameren
Ameren Illinois
Supplemental Indenture to the CILCO Mortgage, dated February 1, 1966
February 1966 Form 8-K, Exhibit A, File No. 1-2732
4.65
Ameren
Ameren Illinois
Supplemental Indenture to the CILCO Mortgage, dated January 15, 1992
January 30, 1992 Form 8-K, Exhibit 4(b), File No. 1-2732
4.66
Ameren
Ameren Illinois
Supplemental Indenture to the CILCO Mortgage, dated June 1, 2006 for the Series AA and BB
June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732
4.67
Ameren
Ameren Illinois
Supplemental Indenture to the CILCO Mortgage, dated December 1, 2008 for the Series CC
December 9, 2008 Form 8-K, Exhibit 4.5, File No. 1-2732
4.68
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
4.69
Ameren
Ameren Illinois
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
4.70
Ameren
Ameren Illinois
First Supplemental Indenture to the CILCO Indenture, dated October 1, 2010
October 7, 2010 Form 8 K, Exhibit 4.1, File No. 1-3672
4.71
Ameren
Ameren Illinois
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
4.72
Ameren
Ameren Illinois
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)
June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-2732
4.73
Ameren
Ameren Illinois
CILCO Indenture Company Order, dated December 9, 2008, establishing the 8.875% Senior Secured Notes due 2013 (including the global note)
December 9, 2008 Form 8-K, Exhibits 4.2 and 4.3,
File No. 1-2732
4.74
Ameren
Ameren Illinois
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)
1992 Form 10-K, Exhibit 4(cc), File No. 1-3004
4.75
Ameren
Ameren Illinois
Supplemental Indenture dated as of March 1, 1998, to Ameren Illinois Mortgage for Series S
Exhibit 4.41, File No. 333-71061
4.76
Ameren
Ameren Illinois
Supplemental Indenture dated as of March 1, 1998, to Ameren Illinois Mortgage for Series T
Exhibit 4.42, File No. 333-71061
4.77
Ameren
Ameren Illinois
Supplemental Indenture amending the Ameren Illinois Mortgage dated as of June 15, 1999
June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004
4.78
Ameren
Ameren Illinois
Supplemental Indenture dated as of July 15, 1999, to Ameren Illinois Mortgage for Series U
June 30, 1999 Form 10-Q, Exhibit 4.4, File No. 1-3004
4.79
Ameren
Ameren Illinois
Supplemental Indenture amending the Ameren Illinois Mortgage dated as of December 15, 2002
December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004
4.80
Ameren
Ameren Illinois
Supplemental Indenture dated as of June 1, 2006, to Ameren Illinois Mortgage for Series AA
June 19, 2006 Form 8-K, Exhibit 4.13, File No. 1-3004
4.81
Ameren
Ameren Illinois
Supplemental Indenture dated as of November 15, 2007, to Ameren Illinois Mortgage for Series BB
November 20, 2007 Form 8-K, Exhibit 4.4, File No. 1-3004
4.82
Ameren
Ameren Illinois
Supplemental Indenture dated as of April 1, 2008, to Ameren Illinois Mortgage for Series CC
April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004
4.83
Ameren
Ameren Illinois
Supplemental Indenture dated as of October 1, 2008, to Ameren Illinois Mortgage for Series DD
October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004

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4.84
Ameren
Ameren Illinois
Supplemental Indenture, dated as of October 1, 2010, to Ameren Illinois Mortgage for Series CIPS-AA, CIPS-BB and CIPS-CC
October 7, 2010 Form 8 K, Exhibit 4.9, File No. 1-3672
4.85
Ameren
Ameren Illinois
Supplemental Indenture, dated as of January 15, 2011, to Ameren Illinois Mortgage
Exhibit 4.78, File No. 333-182258
4.86
Ameren
 Ameren Illinois
Supplemental Indenture dated as of August 1, 2012, to Ameren Illinois Mortgage for Series EE
August 20, 2012 Form 8-K, Exhibit 4.4, File No. 1-3672
4.87
Ameren
Ameren Illinois
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)
June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-3004
4.88
Ameren
Ameren Illinois
First Supplemental Indenture, dated as of October 1, 2010, to the Ameren Illinois Indenture for Series CIPS-AA, CIPS-BB and CIPS-CC
October 7, 2010 Form 8 K, Exhibit 4.5, File No. 1-14756
4.89
Ameren
Ameren Illinois
Second Supplemental Indenture to the Ameren Illinois Indenture dated as of July 21, 2011
September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672
4.90
Ameren
Ameren Illinois
Third Supplemental Indenture to the Ameren Illinois Indenture dated as of May 15, 2012
Exhibit 4.83, File No. 333-182258
4.91
Ameren
Ameren Illinois
Ameren Illinois Indenture Company Order, dated June 14, 2006, establishing the 6.25% Senior Secured Notes due 2016 (including the global note)
June 19, 2006 Form 8-K, Exhibit 4.7, File No. 1-3004
4.92
Ameren
Ameren Illinois
Ameren Illinois Indenture Company Order, dated November 15, 2007, establishing 6.125% Senior Secured Notes due 2017 (including the global note)
November 20, 2007 Form 8-K, Exhibit 4.2, File No. 1-3004
4.93
Ameren
Ameren Illinois
Ameren Illinois Indenture Company Order, dated April 8, 2008, establishing 6.25% Senior Secured Notes due 2018 (including the global note)
April 8, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004
4.94
Ameren
Ameren Illinois
Ameren Illinois Indenture Company Order dated October 23, 2008, establishing 9.75% Senior Secured Notes due 2018 (including the global note)
October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004
4.95
Ameren
Ameren Illinois
Ameren Illinois Indenture Company Order dated August 20, 2012, establishing 2.70% Senior Secured Notes due 2022 (including the global note)
August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3004
4.96
Ameren
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)
Exhibit 4.1, File No. 333-56594
4.97
Ameren
Third Supplemental Indenture dated as of June 1, 2002, to Genco Indenture, relating to Genco's 7.95% Senior Notes, Series E due 2032
June 30, 2002 Form 10-Q, Exhibit 4.1, File No. 1-14756
4.98
Ameren
Fourth Supplemental Indenture dated as of January 15, 2003, to Genco Indenture, relating to Genco 7.95% Senior Notes, Series F due 2032
2002 Form 10-K, Exhibit 4.5, File No. 1-14756
4.99
Ameren
Fifth Supplemental Indenture dated as of April 1, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series G due 2018
April 9, 2008 Form 8-K, Exhibit 4.2, File No. 1-14756
4.100
Ameren
Sixth Supplemental Indenture, dated as of July 7, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series H due 2018
Exhibit No. 4.55, File No. 333-155416
4.101
Ameren
Seventh Supplemental Indenture, dated as of November 1, 2009, to Genco Indenture, relating to Genco 6.30% Senior Notes, Series l due 2020
November 17, 2009 Form 8-K, Exhibit 4.8, File No. 1-14756
Material Contracts
10.1
Ameren
Ameren Illinois
Unilateral Borrowing Agreement by and among Ameren, IP (predecessor in interest to Ameren Illinois) and Ameren Services, dated as of September 30, 2004
October 1, 2004 Form 8-K, Exhibit 10.3, File No. 1-3004
10.2
Ameren Companies
Third Amended Ameren Corporation System Utility Money Pool Agreement, as amended September 30, 2004
October 1, 2004 Form 8-K, Exhibit 10.2, File No. 1-14756
10.3
Ameren
Ameren Corporation System Amended and Restated Non-Regulated Subsidiary Money Pool Agreement, dated March 1, 2008
March 31, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.4
Ameren
Ameren Missouri
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.
November 15, 2012 Form 8-K, Exhibit 10.1, File No. 1-14756
10.5
Ameren
Ameren Illinois
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.
November 15, 2012 Form 8-K, Exhibit 10.2, File No. 1-14756
10.6 
Ameren
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

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10.7
Ameren
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
10.8
Ameren
*Summary Sheet of Ameren Corporation Non-Management Director Compensation revised on August 8, 2008
September 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.9
Ameren
*Ameren's Deferred Compensation Plan for Members of the Board of Directors amended and restated effective January 1, 2009, dated June 13, 2008
June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756
10.10
Ameren Companies
*Amendment dated October 12, 2009, to Ameren's Deferred Compensation Plan for Members of the Board of Directors, effective January 1, 2010
2009 Form 10-K, Exhibit 10.15 , File No. 1-14756
10.11
Ameren Companies
*Amendment dated October 14, 2010, to Ameren's Deferred Compensation Plan for Members of the Board of Directors
2010 Form 10-K, Exhibit 10.15, File No. 1-14756
10.12
Ameren Companies
*Ameren's Deferred Compensation Plan as amended and restated effective January 1, 2010
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
10.14
Ameren Companies
*2012 Ameren Executive Incentive Plan
December 14, 2011 Form 8-K, Exhibit 10.1, File No. 1-14756
10.15
Ameren Companies
*2013 Ameren Executive Incentive Plan
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
*2013 Base Salary Table for Named Executive Officers
 
10.18
Ameren Companies
*Second Amended and Restated Ameren Corporation Change of Control Severance Plan
2008 Form 10-K, Exhibit 10.37, File No. 1-14756
10.19
Ameren Companies
*First Amendment dated October 12, 2009, to the Second Amended and Restated Ameren Change of Control Severance Plan
October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756
10.20
Ameren Companies
*Revised Schedule I to Second Amended and Restated Ameren Change of Control Severance Plan, as amended
September 30, 2012 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.21
Ameren Companies
*Formula for Determining 2010 Target Performance Share Unit Awards to be Issued to Named Executive Officers
December 17, 2009 Form 8-K, Exhibit 99.1, File No. 1-14756
10.22
Ameren Companies
*Formula for Determining 2011 Target Performance Share Unit Awards to be Issued to Named Executive Officers
December 15, 2010 Form 8-K, Exhibit 99.1, File No. 1-14756
10.23
Ameren Companies
*Formula for Determining 2012 Target Performance Share Unit Awards to be Issued to Named Executive Officers
December 14, 2011 Form 8-K, Exhibit 99.1, File No. 1-14756
10.24
Ameren Companies
*Formula for Determining 2013 Target Performance Share Unit Awards to be Issued to Named Executive Officers
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
*Form of Performance Share Unit Award Agreement for Award Issued in 2010 pursuant to 2006 Omnibus Incentive Compensation Plan
December 17, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756
10.27
Ameren Companies
*Form of Performance Share Unit Award Agreement for Award Issued in 2011 pursuant to 2006 Omnibus Incentive Compensation Plan
December 15, 2010 Form 8-K, Exhibit 10.2, File No. 1-14756
10.28
Ameren Companies
*Form of Performance Share Unit Award Agreement for Awards Issued in 2012 pursuant to 2006 Omnibus Incentive Compensation Plan
December 14, 2011 Form 8-K, Exhibit 10.2, File No. 1-14756
10.29
Ameren Companies
*Form of Performance Share Unit Award Agreement for Awards Issued in 2013 pursuant to 2006 Omnibus Incentive Compensation Plan
December 18, 2012 Form 8-K, Exhibit 10.2,
File No. 1-14756
10.30
Ameren Companies
*Performance Stock Bonus Award Agreement, dated March 1, 2011, between Ameren and Adam C. Heflin
March 31, 2011 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.31
Ameren Companies
*Ameren Supplemental Retirement Plan amended and restated effective January 1, 2008, dated June 13, 2008
June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.32
Ameren Companies
*First Amendment to amended and restated Ameren Supplemental Retirement Plan, dated October 24, 2008
2008 Form 10-K, Exhibit 10.44, File No. 1-14756
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

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Statement re: Computation of Ratios
12.1
Ameren
Ameren's Statement of Computation of Ratio of Earnings to Fixed Charges
 
12.2
Ameren Missouri
Ameren Missouri's Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
 
12.3
Ameren Illinois
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
Ameren
Consent of Independent Registered Public Accounting Firm with respect to Ameren
 
23.2
Ameren Missouri
Consent of Independent Registered Public Accounting Firm with respect to Ameren Missouri
 
23.3
Ameren Illinois
Consent of Independent Registered Public Accounting Firm with respect to Ameren Illinois
 

Power of Attorney
24.1
Ameren
Power of Attorney with respect to Ameren
 
24.2
Ameren Missouri
Power of Attorney with respect to Ameren Missouri
 
24.3
Ameren Illinois
Power of Attorney with respect to Ameren Illinois
 

Rule 13a-14(a)/15d-14(a) Certifications
31.1
Ameren
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
 
31.2
Ameren
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
 
31.3
Ameren Missouri
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri
 
31.4
Ameren Missouri
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri
 
31.5
Ameren Illinois
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois
 
31.6
Ameren Illinois
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois
 

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Table of Contents


Section 1350 Certifications
32.1
Ameren
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
 
32.2
Ameren Missouri
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri
 
32.3
Ameren Illinois
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois
 
Additional Exhibits
99.1
Ameren Companies
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
XBRL Taxonomy Extension Schema Document
 
101.CAL**
Ameren Companies
XBRL Taxonomy Extension Calculation Linkbase Document
 
101.LAB**
Ameren Companies
XBRL Taxonomy Extension Label Linkbase Document
 
101.PRE**
Ameren Companies
XBRL Taxonomy Extension Presentation Linkbase Document
 
101.DEF**
Ameren Companies
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.



191