UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

xQuarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the Quarterly Period Ended September 30, 2009March 31, 2010

OR

 

¨Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the transition period from to            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

  Central Illinois Public Service Company  

37-0211380

  

(Illinois Corporation)

  
  

607 East Adams Street

  
  

Springfield, Illinois 62739

  
  

(888) 789-2477

  

333-56594

  Ameren Energy Generating Company  

37-1395586

  

(Illinois Corporation)

  
  

1901 Chouteau Avenue

  
  

St. Louis, Missouri 63103

  
  

(314) 621-3222

2-95569

CILCORP Inc.

37-1169387

(Illinois Corporation)

300 Liberty Street

Peoria, Illinois 61602

(309) 677-5271

  

1-2732

  Central Illinois Light Company  

37-0211050

  

(Illinois Corporation)

  
  

300 Liberty Street

  
  

Peoria, Illinois 61602

  
  

(309) 677-5271

  

1-3004

  Illinois Power Company  

37-0344645

  

(Illinois Corporation)

  
  

370 South Main Street

  
  

Decatur, Illinois 62523

  
  

(217) 424-6600

  


Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

 

Ameren Corporation

  Yes  x  No  ¨  

Union Electric Company

  Yes  x  No  ¨  

Central Illinois Public Service Company

  Yes  x  No  ¨  

Ameren Energy Generating Company

  Yes  x  No  ¨  

Central Illinois Light Company

  Yes  x  No  ¨  

Illinois Power Company

  Yes  x  No  ¨  

CILCORP Inc. has voluntarily filed all reports that it would have been required to file if it had been subject to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 

Ameren Corporation

  Yes  x  No  ¨  

Union Electric Company

  Yes  ¨  No  ¨  

Central Illinois Public Service Company

  Yes  ¨  No  ¨  

Ameren Energy Generating Company

Yes¨No¨

CILCORP Inc.

  Yes  ¨  No  ¨  

Central Illinois Light Company

  Yes  ¨  No  ¨  

Illinois Power Company

  Yes  ¨  No  ¨  

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.

 

   Large
Accelerated Filer
  Accelerated
Filer
  Non-Accelerated
Filer
  Smaller Reporting
Company

Ameren Corporation

  x  ¨  ¨  ¨

Union Electric Company

  ¨  ¨  x  ¨

Central Illinois Public Service Company

  ¨  ¨  x  ¨

Ameren Energy Generating Company

  ¨  ¨  x  ¨

CILCORP Inc.

¨¨x¨

Central Illinois Light Company

  ¨  ¨  x  ¨

Illinois Power Company

  ¨  ¨  x  ¨

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

 

Ameren Corporation

  Yes  ¨  No  x  

Union Electric Company

  Yes  ¨  No  x  

Central Illinois Public Service Company

  Yes  ¨  No  x  

Ameren Energy Generating Company

  Yes  ¨  No  x  

CILCORP Inc.

Yes¨Nox

Central Illinois Light Company

  Yes  ¨  No  x  

Illinois Power Company

  Yes  ¨  No  x  


The number of shares outstanding of each registrant’s classes of common stock as of OctoberApril 30, 2009,2010, was as follows:

 

Ameren Corporation

 

Common stock, $0.01 par value per share - 236,921,011238,286,367

Union Electric Company

 

Common stock, $5 par value per share, held by Ameren

Corporation (parent company of the registrant) - 102,123,834

Central Illinois Public Service Company

 

Common stock, no par value, held by Ameren

Corporation (parent company of the registrant) - 25,452,373

Ameren Energy Generating Company

 

Common stock, no par value, held by Ameren Energy

Resources Company, LLC (parent company of the

registrant and subsidiary of Ameren

Corporation) - 2,000

CILCORP Inc.

Common stock, no par value, held by Ameren

Corporation (parent company of the registrant) - 1,000

Central Illinois Light Company

 

Common stock, no par value, held by CILCORP Inc.Ameren Corporation

(parent company of the registrant and subsidiary of

Ameren Corporation)registrant) - 13,563,871

Illinois Power Company

 

Common stock, no par value, held by Ameren

Corporation (parent company of the registrant) - 23,000,000

OMISSION OF CERTAIN INFORMATION

Ameren Energy Generating Company and CILCORP Inc. meetmeets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and areis therefore filing this form with the reduced disclosure format allowed under that General Instruction.

 

 

This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, Central Illinois Public Service Company, Ameren Energy Generating Company, CILCORP Inc., Central Illinois Light Company, and Illinois Power Company. Each registrant hereto is filing on its own behalf all of the information contained in this quarterly report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

 

 

 


TABLE OF CONTENTS

 

     Page

GLOSSARY OF TERMS AND ABBREVIATIONS

  5

Forward-looking Statements

  7

PART I

 Financial Information  

Item 1.

 

Financial Statements (Unaudited)

  
 Ameren Corporation  
 

Consolidated Statement of Income

  9
 

Consolidated Balance Sheet

  10
 

Consolidated Statement of Cash Flows

  11
 Union Electric Company  
 

Statement of Income

  12
 

Balance Sheet

  13
 

Statement of Cash Flows

  14
 Central Illinois Public Service Company  
 

Statement of Income

  15
 

Balance Sheet

  16
 

Statement of Cash Flows

  17
 Ameren Energy Generating Company  
 

Consolidated Statement of Income

  18
 

Consolidated Balance Sheet

  19
 

Consolidated Statement of Cash Flows

  20
 CILCORP Inc.Central Illinois Light Company  
 

Consolidated Statement of Income

  21
 

Consolidated Balance Sheet

  22
 

Consolidated Statement of Cash Flows

  23
 Central Illinois Light Company

Consolidated Statement of Income

24

Consolidated Balance Sheet

25

Consolidated Statement of Cash Flows

26
Illinois Power Company  
 

Statement of Income

  2724
 

Balance Sheet

  2825
 

Statement of Cash Flows

  2926
 

Combined Notes to Financial Statements

  3027

Item 2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  8864

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

  13088

Item 4 and

  

Item 4T.

 

Controls and Procedures

  13692

PART II

 Other Information  

Item 1.

 

Legal Proceedings

  13693

Item 1A.

 

Risk Factors

  13693

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

  13793

Item 6.

 

Exhibits

  13894

Signatures

  14096

This Form 10-Q contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on page 7 of this Form 10-Q under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined below. When appropriate, subsidiaries of Ameren are named specifically as their various business activities are discussed.

2007 Illinois Electric Settlement Agreement - A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates, effective January 2, 2007. The settlement, which became effective on August 28, 2007, was designed to avoid new rate rollback and freeze legislation and legislation that would impose a tax on electric generation in Illinois. The settlement addressed the issue of power procurement, and it included a comprehensive rate relief and customer assistance program.

2009 Illinois Credit Agreement - On June 30, 2009, Ameren, CIPS, CILCO and IP entered into an $800 million senior secured credit agreement. This agreement is due to expire in June 2011.

2009 Multiyear Credit Agreement - On June 30, 2009, Ameren, UE, and Genco entered into a $1.15 billion credit agreement. This agreement is due to expire in July 2011. Collectively, this agreement and the 2009 Supplemental Credit Agreement are the “2009 Multiyear Credit Agreements.”

2009 Supplemental Credit Agreement - On June 30, 2009, Ameren, UE and Genco entered into a $150 million supplemental credit agreement to the 2009 Multiyear Credit Agreement. This agreement is due to expire in July 2010.

AERG - AmerenEnergy Resources Generating Company, a CILCO subsidiary that operates a merchant electric generation business in Illinois.

AFS - Ameren Energy Fuels and Services Company, a Resources Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.

AITC - Ameren Illinois Transmission Company, an Ameren Corporation subsidiary that is engaged in the construction and operation of transmission assets in Illinois and is regulated by FERC and the ICC.

Ameren - Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.

Ameren Companies - The individual registrants within the Ameren consolidated group.

Ameren Illinois Utilities - CIPS, IP, and the rate-regulated electric and natural gas utility operations of CILCO.

Ameren Services - Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.

ARO - Asset retirement obligations.

Baseload -The minimum amount of electric power delivered or required over a given period of time at a steady rate.

Btu - British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.

Capacity factor - A percentage measure that indicates how much of an electric power generating unit’s capacity was used during a specific period.

CILCO - Central Illinois Light Company, a CILCORPan Ameren Corporation subsidiary that operates a rate-regulated electric transmission and distribution business, a merchant electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO. CILCO owns all of the common stock of AERG.

CILCORP - CILCORP Inc., ana former Ameren Corporation subsidiary that operatesoperated 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 that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS.

CO2 - Carbon dioxide.

COLA - Combined nuclear plant construction and operating license application.

Cooling degree-days - The summation of positive differences between the mean daily temperature and a 65-degree Fahrenheit base. This statistic is useful for estimating electricity demand by residential and commercial customers for summer cooling.

CT - Combustion turbine electric generation equipment used primarily for peaking capacity.

Development Company - Ameren Energy Development Company, which was an Ameren Energy Resources Company subsidiary and parent of Genco, Marketing Company, AFS, and Medina Valley. It was eliminated in an internal reorganization in February 2008.

DOE - Department of Energy, a U.S. government agency.

DRPlus - Ameren Corporation’s dividend reinvestment and direct stock purchase plan.

EEI - Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary that operates merchant electric generation facilities and FERC-regulated transmission facilities in Illinois. Prior to February 29, 2008, EEI was 40% owned by UE and 40% owned by Development Company. On February 29, 2008, UE’s 40%Effective January 1, 2010, in an internal reorganization, Resources Company contributed its 80% ownership interest and Development Company’s 40% ownership interest were transferredin EEI to Resources Company.its subsidiary, Genco. The remaining 20% is owned by Kentucky Utilities Company, a nonaffiliated entity.

EPA - Environmental Protection Agency, a U.S. government agency.

Equivalent availability factor - A measure that indicates the percentage of time an electric power generating unit was available for service during a period.

Exchange Act - Securities Exchange Act of 1934, as amended.

FAC - A fuel and purchased power cost recovery mechanism that allows UE to recover, through customer rates, 95% of changes in fuel (coal, coal transportation, natural gas for generation, and nuclear) and purchased power costs, net of off-system revenues, including MISO costs and revenues, abovegreater or belowless than the amount set in base rates.rates, without a traditional rate proceeding.

FASB - Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.

FERC - The Federal Energy Regulatory Commission, a U.S. government agency.

Fitch - Fitch Ratings, a credit rating agency.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2008,2009, filed by the Ameren Companies with the SEC.

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.

GAAP - Generally accepted accounting principles in the United States of America.

Genco - Ameren Energy Generating Company, a Resources Company subsidiary that operates a merchant electric generation business in Illinois and Missouri. Effective January 1, 2010, after an internal reorganization, EEI became a subsidiary of Genco.

Gigawatthour - - One thousand megawatthours.

Heating degree-days - The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers.

ICC - Illinois Commerce Commission, a state agency that regulates Illinois utility businesses, including the rate-regulated operations of CIPS, CILCO and IP.

Illinois Customer Choice Law - Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provided for electric utility restructuring and was designed to introduce competition into the retail supply of electric energy in Illinois.

Illinois electric settlement agreement - A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates, effective January 2, 2007. The Illinois electric settlement agreement, which became effective on August 28, 2007, was designed to avoid new rate rollback and freeze legislation and legislation that would impose a tax on electric generation in Illinois. The settlement addressed the issue of power procurement, and it included a comprehensive rate relief and customer assistance program.

Illinois EPA - Illinois Environmental Protection Agency, a state government agency.

Illinois Regulated - A financial reporting segment consisting of the regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO, IP and AITC.

IP - Illinois Power Company, an Ameren Corporation subsidiary. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.

IP LLC - Illinois Power Securitization Limited Liability Company, which was a special-purpose Delaware limited-liability company. It was dissolved in February 2009 because the remaining TFNs, with respect to which this entity was created, were redeemed by IP in September 2008.

IP SPT - Illinois Power Special Purpose Trust, which was created as a subsidiary of IP LLC to issue TFNs as allowed under the Illinois Customer Choice Law. It was dissolved in February 2009 because the remaining TFNs were redeemed by IP in September 2008.

IPA - Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and nonresidential customers beginning in June 2009.customers.

Kilowatthour - A measure of electricity consumption equivalent to the use of 1,000 watts of power over a period of one hour.

MACT - Maximum Achievable Control Technology.

Marketing Company - Ameren Energy Marketing Company, a Resources Company subsidiary that markets power for Genco, AERG, EEI and EEI.Medina Valley.

Medina Valley - AmerenEnergy Medina Valley Cogen L.L.C.,LLC, a Resources Company subsidiary, which owns a 40-megawatt gas-fired electric generation plant.

Megawatthour - One thousand kilowatthours.

Merchant Generation - A financial reporting segment consisting primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, Medina Valley, and Marketing Company.

MGP - Manufactured gas plant.

MISO - Midwest Independent Transmission System Operator, Inc., an RTO.

MISO Day Two Energy and Operating Reserves Market - A market that uses market-based pricing, incorporating transmission congestion and line losses, to compensate market participants for power.power and ancillary services.

Missouri Regulated - A financial reporting segment consisting of UE’s rate-regulated businesses.

Mmbtu - One million Btus.

Money pool - Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools maintained for rate-regulated and non-rate-regulated business are referred to as the utility money pool and the non-state-regulated subsidiary money pool, respectively.

Moody’s - Moody’s Investors Service Inc., a credit rating agency.

MoPSC - Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including the rate-regulated operations of UE.

MPS - Multi-Pollutant Standard, an agreement, as amended, reached in 2006 among Genco, CILCO (AERG), EEI and the Illinois EPA, which was codified in Illinois environmental regulations.

MTM - Mark-to-market.

MW - Megawatt.

Native load - Wholesale customers and end-use retail customers, whom we are obligated to serve by statute, franchise, contract, or other regulatory requirement.

NCF&O - National Congress of Firemen and Oilers, a labor union.

NOx - Nitrogen oxide.

Noranda - Noranda Aluminum, Inc.

NPNS - Normal purchases and normal sales.

NRC - Nuclear Regulatory Commission, a U.S. government agency.

NSR - New Source Review provisions of the Clean Air Act.

OCI - Other comprehensive income (loss) as defined by GAAP.

Off-system revenues - Revenues from other than native load sales.

OTC - Over-the-counter.

PGA - Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.

PJM - PJM Interconnection LLC.

PUHCA 2005 - The Public Utility Holding Company Act of 2005, enacted as part of the Energy Policy Act of 2005, effective February 8, 2006.

Regulatory lag - Adjustments to retail electric and natural gas rates are based on historic cost and revenue levels. Rate increase requests can take up to 11 months to be acted upon by the MoPSC and the ICC. As a result, revenue changesincreases authorized by regulators will lag behind changing costs.costs and revenue.

Resources Company - Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Genco, Marketing Company, EEI, AFS, and Medina Valley. It is the successor to Ameren Energy Resources Company, which was eliminated in an internal reorganization in February 2008.

RFP - Request for proposal.

RTO - Regional Transmission OrganizationOrganization.

S&P - Standard & Poor’s Ratings Services, a credit rating agency that is a division of The McGraw-Hill Companies, Inc.

SEC - Securities and Exchange Commission, a U.S. government agency.

SO2 - Sulfur dioxide.

TFN - Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois Customer Choice Law. IP designated a portion of cash received from customer billings to pay the TFNs. The designated funds received by IP were remitted to IP SPT. The designated funds were restricted for the sole purpose of making payments of principal and interest on, and paying other fees and expenses related to, the TFNs. After the implementation of authoritative guidance on the consolidation of variable interest entities, IP did not consolidate IP SPT. Therefore, the obligation to IP SPT appeared on IP’s balance sheet as of December 31, 2007. In September 2008, IP redeemed the remaining TFNs.

UE - Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri as AmerenUE.

VIE - Variable-interest entity.

 

 

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors in the Form 10-K and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

 

regulatory or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of the pending UE rate proceeding, and any rehearings or appeals related to the CIPS, CILCO and IP rate proceedings,order, and future rate proceedings or future legislative actions that seek to limit or reverse rate increases;

uncertainty asthe effects of, or changes to, the continued effectiveness of the Illinois power procurement process;

 

changes in laws and other governmental actions, including monetary and fiscal policies;

 

changes in laws or regulations that adversely affect the ability of electric distribution companies and other purchasers of wholesale electricity to pay their suppliers, including UE and Marketing Company;

 

enactment of legislation taxing electric generators, in Illinois or elsewhere;

the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels, and the implementation of deregulation, such as occurred when the electric rate freeze and power supply contracts expired in Illinois at the end of 2006;

the effects on demand for our services resulting from technological advances, including advances in energy efficiency and distributed generation sources, which generate electricity at the site of consumption;

 

increasing capital expenditure and operating expense requirements and our ability to recover these costs in a timely fashion in light of regulatory lag;

 

the effects of participation in the MISO;

 

the cost and availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities;

 

the effectiveness of our risk management strategies and the use of financial and derivative instruments;

 

prices for power in the Midwest, including forward prices;

 

business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products;

 

disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital, including short-term credit and liquidity, impossible, more difficult, or more costly;

 

our assessment of our liquidity;

 

the impact of the adoption of new accounting guidance and the application of appropriate technical accounting rules and guidance;

 

actions of credit rating agencies and the effects of such actions;

 

the impact of weather conditions and other natural phenomena on us and our customers;

 

the impact of system outages caused by severe weather conditions or other events;outages;

 

generation plant construction, installation and performance, including costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident and the plant’s future operation;

impairments of long-lived assets or goodwill;performance;

 

the recovery of costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident and investment in a COLA for a second unit at its Callaway nuclear plant;

 

impairments of long-lived assets or goodwill;

operation of UE’s nuclear power facility, including planned and unplanned outages, and decommissioning costs;

 

the effects of strategic initiatives, including mergers, acquisitions and divestitures;

 

the impact of current environmental regulations on utilities and power generating companies and the expectation that more stringent requirements, including those related to greenhouse gases and energy efficiency, will be enacted over time, which could limit, or terminate, the operation of certain of our generating units, increase our costs, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect;

labor disputes, workforcework force reductions, future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets;

 

the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit facilities and financial instruments;

 

the cost and availability of transmission capacity for the energy generated by the Ameren Companies’ facilities or required to satisfy energy sales made by the Ameren Companies;

 

legal and administrative proceedings; and

 

acts of sabotage, war, terrorism, or intentionally disruptive acts.acts; and

conditions to, and the timetable for, completion of the merger of CILCO and IP with and into CIPS and the other transactions contemplated in connection with the merger.

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. FINANCIAL INFORMATION

 

ITEM 1.FINANCIAL STATEMENTS.

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions, except per share amounts)

 

  Three Months Ended
September 30,
  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2009          2008          2010          2009    

Operating Revenues:

            

Electric

  $1,679   $1,928   $4,589   $4,944   $1,440   $1,395 

Gas

   136    132    826    987    476    521 
                  

Total operating revenues

   1,815    2,060    5,415    5,931    1,916    1,916 
                  

Operating Expenses:

            

Fuel

   306    461    867    963    293    274 

Coal contract settlement

            (60)

Purchased power

   256    371    708    964    271    233 

Gas purchased for resale

   57    73    523    697    333    383 

Other operations and maintenance

   422    456    1,294    1,361    416    421 

Depreciation and amortization

   185    173    541    513    187    174 

Taxes other than income taxes

   104    98    311    300    118    110 
                  

Total operating expenses

   1,330    1,632    4,244    4,738    1,618    1,595 
                  

Operating Income

   485    428    1,171    1,193    298    321 

Other Income and Expenses:

            

Miscellaneous income

   16    23    49    61    22    16 

Miscellaneous expense

   (3)   (10)   (14)   (23)      
                  

Total other income

   13    13    35    38    15    12 
                  

Interest Charges

   134    113    376    331    132    118 
                  

Income Before Income Taxes

   364    328    830    900    181    215 

Income Taxes

   135    113    288    319    75    70 
                  

Net Income

   229    215    542    581    106    145 

Less: Net Income Attributable to Noncontrolling Interests

      11       33       
                  

Net Income Attributable to Ameren Corporation

  $227   $204   $533   $548   $102   $141 
                  

Earnings per Common Share – Basic and Diluted

  $1.04   $0.97   $2.48   $2.61   $0.43   $0.66 
                  

Dividends per Common Share

  $0.385   $0.635   $1.155   $1.905   $0.385   $0.385 

Average Common Shares Outstanding

   218.2    210.3    214.9    209.5    237.6    212.7 

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

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except per share amounts)

 

  September 30,
        2009        
  December 31,
        2008       ��
  March 31,
        2010         
  December 31,
        2009         

ASSETS

        

Current Assets:

        

Cash and cash equivalents

  $563   $92   $360   $622 

Accounts receivable – trade (less allowance for doubtful accounts of $29 and $28, respectively)

   416    502 

Accounts receivable – trade (less allowance for doubtful accounts of $32 and $24, respectively)

   500    424 

Unbilled revenue

   250    427    253    367 

Miscellaneous accounts and notes receivable

   182    292    319    318 

Materials and supplies

   857    842    635    782 

Mark-to-market derivative assets

   239    207    233    121 

Current regulatory assets

   242    110 

Other current assets

   273    232    116    98 
            

Total current assets

   2,780    2,594    2,658    2,842 
            

Property and Plant, Net

   17,272    16,567    17,671    17,610 

Investments and Other Assets:

        

Nuclear decommissioning trust fund

   280    239    307    293 

Goodwill

   831    831    831    831 

Intangible assets

   138    167    124    129 

Regulatory assets

   1,641    1,653    1,427    1,430 

Other assets

   652    606    670    655 
            

Total investments and other assets

   3,542    3,496    3,359    3,338 
            

TOTAL ASSETS

  $23,594   $22,657   $23,688   $23,790 
            

LIABILITIES AND EQUITY

        

Current Liabilities:

        

Current maturities of long-term debt

  $128   $380   $204   $204 

Short-term debt

   435    1,174       20 

Accounts and wages payable

   443    813    427    694 

Taxes accrued

   135    54    94    54 

Interest accrued

   183    107    165    110 

Customer deposits

   107    126    97    101 

Mark-to-market derivative liabilities

   197    155    254    109 

Current regulatory liabilities

   87    82 

Current accumulated deferred income taxes, net

   93    38 

Other current liabilities

   298    254    219    299 
            

Total current liabilities

   1,926    3,063    1,640    1,711 
            

Credit Facility Borrowings

   630    830 

Long-term Debt, Net

   7,321    6,554    7,113    7,113 

Deferred Credits and Other Liabilities:

        

Accumulated deferred income taxes, net

   2,431    2,131    2,604    2,554 

Accumulated deferred investment tax credits

   93    100    92    94 

Regulatory liabilities

   1,322    1,291    1,340    1,338 

Asset retirement obligations

   423    406    435    429 

Pension and other postretirement benefits

   1,477    1,495    1,181    1,165 

Other deferred credits and liabilities

   555    438    543    496 
            

Total deferred credits and other liabilities

   6,301    5,861    6,195    6,076 
            

Commitments and Contingencies (Notes 2, 8, 9 and 10)

        

Ameren Corporation Stockholders’ Equity:

        

Common stock, $0.01 par value, 400.0 shares authorized – shares outstanding of 236.8 and 212.3, respectively

      

Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 238.2 and 237.4, respectively

      

Other paid-in capital, principally premium on common stock

   5,392    4,780    5,437    5,412 

Retained earnings

   2,467    2,181    2,466    2,455 

Accumulated other comprehensive loss

   (21)      (4)   (16)
            

Total Ameren Corporation stockholders’ equity

   7,840    6,963    7,901    7,853 
            

Noncontrolling Interests

   206    216    209    207 
            

Total equity

   8,046    7,179    8,110    8,060 
            

TOTAL LIABILITIES AND EQUITY

  $23,594   $22,657   $23,688   $23,790 
            

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

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

 

  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2010          2009    

Cash Flows From Operating Activities:

        

Net income

  $542   $581   $106   $145 

Adjustments to reconcile net income to net cash provided by operating activities:

        

Gain on sales of emission allowances

      (2)

Net mark-to-market gain on derivatives

   (26)   (42)   (31)   (51)

Depreciation and amortization

   557    528    190    176 

Amortization of nuclear fuel

   40    31    13    12 

Amortization of debt issuance costs and premium/discounts

   16    14       

Deferred income taxes and investment tax credits, net

   301    130    70    32 

Other

      (2)   (9)   (1)

Changes in assets and liabilities:

        

Receivables

   239    144    37    130 

Materials and supplies

   (11)   (216)   148    185 

Accounts and wages payable

   (241)   (74)   (177)   (245)

Taxes accrued

   81    44    40    29 

Assets, other

   (96)   46    (32)   29 

Liabilities, other

   134    142    11    100 

Pension and other postretirement benefits

   30    23    30    36 

Counterparty collateral, net

   66       (23)   (41)

Taum Sauk costs, net of insurance recoveries

   110    (94)   (1)   (24)
            

Net cash provided by operating activities

   1,746    1,253    381    516 
            

Cash Flows From Investing Activities:

        

Capital expenditures

   (1,295)   (1,316)   (289)   (424)

Nuclear fuel expenditures

   (47)   (161)   (23)   (3)

Purchases of securities – nuclear decommissioning trust fund

   (315)   (386)   (60)   (203)

Sales of securities – nuclear decommissioning trust fund

   315    360    56    200 

Purchases of emission allowances

   (4)   (2)      (2)

Sales of emission allowances

      

Other

         (1)   
            

Net cash used in investing activities

   (1,345)   (1,501)   (317)   (432)
            

Cash Flows From Financing Activities:

        

Dividends on common stock

   (247)   (399)   (91)   (82)

Capital issuance costs

   (64)   (9)      (3)

Dividends paid to noncontrolling interest holders

   (19)   (31)   (2)   (8)

Short-term debt, net

   (739)   (65)

Redemptions, repurchases, and maturities:

    

Long-term debt

   (250)   (823)

Preferred stock

      (16)

Short-term and credit facility borrowings, net

   (220)   (177)

Issuances:

        

Common stock

   617    107    20    28 

Long-term debt

   772    1,335       349 

Generator advances for construction received (refunded), net

   (33)   21 
            

Net cash provided by financing activities

   70    99 

Net cash provided by (used in) financing activities

   (326)   128 
            

Net change in cash and cash equivalents

   471    (149)   (262)   212 

Cash and cash equivalents at beginning of year

   92    355��   622    92 
            

Cash and cash equivalents at end of period

  $563   $206   $360   $304 
            

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

UNION ELECTRIC COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)

 

  Three Months Ended
September 30,
  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2009          2008          2010          2009    

Operating Revenues:

            

Electric – excluding off-system

  $738   $739   $1,818   $1,812 

Electric – off-system

   78    114    302    418 

Electric

  $607   $579 

Gas

   19    21    120    139    75    75 

Other

                  
                  

Total operating revenues

   836    875    2,243    2,370    682    655 
                  

Operating Expenses:

            

Fuel

   153    238    451    489    124    135 

Purchased power

   27    45    88    135    44    33 

Gas purchased for resale

      11    68    84    46    48 

Other operations and maintenance

   229    234    665    689    218    216 

Depreciation and amortization

   90    83    266    246    92    86 

Taxes other than income taxes

   72    69    200    189    68    62 
                  

Total operating expenses

   579    680    1,738    1,832    592    580 
                  

Operating Income

   257    195    505    538    90    75 

Other Income and Expenses:

            

Miscellaneous income

   15    17    43    46    21    13 

Miscellaneous expense

   (2)   (2)   (6)   (6)      
                  

Total other income

   13    15    37    40    19    11 
                  

Interest Charges

   61    51    171    142    59    53 
                  

Income Before Income Taxes and Equity in Income of Unconsolidated Investment

   209    159    371    436 

Income Before Income Taxes

   50    33 

Income Taxes

   67    60    123    160    22    11 
            

Income Before Equity in Income of Unconsolidated Investment

   142    99    248    276 

Equity in Income of Unconsolidated Investment, Net of Taxes

            11 
                  

Net Income

   142    99    248    287    28    22 

Preferred Stock Dividends

                  
                  

Net Income Available to Common Stockholder

  $141   $98   $244   $283   $27   $21 
                  

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

UNION ELECTRIC COMPANY

BALANCE SHEET

(Unaudited) (In millions, except per share amounts)

 

  September 30,
        2009        
  December 31,
        2008        
  March 31,
        2010         
  December 31,
        2009         

ASSETS

        

Current Assets:

        

Cash and cash equivalents

  $229   $  $55   $267 

Accounts receivable – trade (less allowance for doubtful accounts of $6 and $8, respectively)

   201    142 

Accounts receivable – trade (less allowance for doubtful accounts of $7 and $6, respectively)

   174    154 

Accounts receivable – affiliates

   101    22 

Unbilled revenue

   103    111    102    127 

Miscellaneous accounts and notes receivable

   159    261    141    199 

Accounts receivable – affiliates

   140    32 

Materials and supplies

   367    339    332    346 

Mark-to-market derivative assets

   28    50 

Current regulatory assets

   115    63 

Other current assets

   81    58    53    50 
            

Total current assets

   1,308    993    1,073    1,228 
            

Property and Plant, Net

   9,372    8,995    9,519    9,585 

Investments and Other Assets:

        

Nuclear decommissioning trust fund

   280    239    307    293 

Intangible assets

   38    48    33    35 

Regulatory assets

   874    897    758    765 

Other assets

   385    352    383    395 
            

Total investments and other assets

   1,577    1,536    1,481    1,488 
            

TOTAL ASSETS

  $12,257   $11,524   $12,073   $12,301 
            
LIABILITIES AND STOCKHOLDERS’ EQUITY        

Current Liabilities:

        

Current maturities of long-term debt

  $  $  $  $

Short-term debt

      251 

Intercompany note payable – Ameren

      92 

Accounts and wages payable

   178    360    173    336 

Accounts payable – affiliates

   102    151    85    132 

Taxes accrued

   124    20    74    21 

Interest accrued

   75    56    61    63 

Mark-to-market derivative liabilities

   29    28 

Current regulatory liabilities

   34    25 

Other current liabilities

   124    121    89    74 
            

Total current liabilities

   607    1,055    549    683 
            

Long-term Debt, Net

   4,022    3,673    4,018    4,018 

Deferred Credits and Other Liabilities:

        

Accumulated deferred income taxes, net

   1,611    1,372    1,698    1,660 

Accumulated deferred investment tax credits

   76    80    78    79 

Regulatory liabilities

   934    922    825    947 

Asset retirement obligations

   330    317    334    331 

Pension and other postretirement benefits

   519    494    406    400 

Other deferred credits and liabilities

   111    49    139    126 
            

Total deferred credits and other liabilities

   3,581    3,234    3,480    3,543 
            

Commitments and Contingencies (Notes 2, 8, 9 and 10)

        

Stockholders’ Equity:

        

Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding

   511    511    511    511 

Other paid-in capital, principally premium on common stock

   1,555    1,119    1,555    1,555 

Preferred stock not subject to mandatory redemption

   113    113    113    113 

Retained earnings

   1,868    1,794    1,847    1,878 

Accumulated other comprehensive income

      25 
            

Total stockholders’ equity

   4,047    3,562    4,026    4,057 
            

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

  $12,257   $11,524 

TOTAL LIABILITIES AND STOCKHOLDERS EQUITY

  $12,073   $12,301 
            

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

UNION ELECTRIC COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

 

  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2010          2009    

Cash Flows From Operating Activities:

        

Net income

  $248   $287   $28   $22 

Adjustments to reconcile net income to net cash provided by operating activities:

        

Gain on sales of emission allowances

      (1)

Net mark-to-market gain on derivatives

   (29)   (10)      (30)

Depreciation and amortization

   266    246    92    86 

Amortization of nuclear fuel

   40    31    13    12 

Amortization of debt issuance costs and premium/discounts

            

Deferred income taxes and investment tax credits, net

   219    57    34    26 

Allowance for equity funds used during construction

   (12)   (6)

Other

   (15)   (19)   (1)   (1)

Changes in assets and liabilities:

        

Receivables

   (184)   79    (19)   13 

Materials and supplies

   (25)   (45)   15    12 

Accounts and wages payable

   (159)   (200)   (155)   (159)

Taxes accrued

   104    57    53    28 

Assets, other

   (1)   97    (29)   (22)

Liabilities, other

   86    55       26 

Pension and other postretirement benefits

   13    10    11    14 

Taum Sauk costs, net of insurance recoveries

   110    (94)   (1)   (24)
            

Net cash provided by operating activities

   680    555 

Net cash provided by (used in) operating activities

   34    (1)
            

Cash Flows From Investing Activities:

        

Capital expenditures

   (657)   (614)   (163)   (214)

Nuclear fuel expenditures

   (47)   (161)   (23)   (3)

Proceeds from intercompany note receivable

      

Purchases of securities – nuclear decommissioning trust fund

   (315)   (386)   (60)   (203)

Sales of securities – nuclear decommissioning trust fund

   315    360    56    200 

Sales of emission allowances

      

Other

   (1)   
            

Net cash used in investing activities

   (705)   (794)   (190)   (220)
            

Cash Flows From Financing Activities:

        

Dividends on common stock

   (170)   (193)   (58)   (52)

Dividends on preferred stock

   (4)   (4)   (1)   (1)

Capital issuance costs

   (14)   (5)      (3)

Short-term debt, net

   (251)   (82)      46 

Intercompany note payable – Ameren, net

   (92)   17 

Redemptions, repurchases, and maturities of long-term debt

      (378)

Note payable – Ameren, net

      (92)

Issuances of long-term debt

   349    699       349 

Capital contribution from parent

   436    

Other

      
            

Net cash provided by financing activities

   254    54 

Net cash provided by (used in) financing activities

   (56)   248 
            

Net change in cash and cash equivalents

   229    (185)   (212)   27 

Cash and cash equivalents at beginning of year

      185    267    
            

Cash and cash equivalents at end of period

  $229   $  $55   $27 
            

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)

 

  Three Months Ended
September 30,
  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2009          2008          2010          2009    

Operating Revenues:

            

Electric

  $180   $190   $508   $539   $162   $165 

Gas

   27    25    158    173    89    98 

Other

                  
                  

Total operating revenues

   208    217    669    714    251    265 
                  

Operating Expenses:

            

Purchased power

   97    117    297    348    93    106 

Gas purchased for resale

   11    13    100    117    62    73 

Other operations and maintenance

   40    49    138    147    45    43 

Depreciation and amortization

   17    16    51    50    17    17 

Taxes other than income taxes

         26    27    11    10 
                  

Total operating expenses

   173    203    612    689    228    249 
                  

Operating Income

   35    14    57    25    23    16 

Other Income and Expenses:

            

Miscellaneous income

                  

Miscellaneous expense

         (1)   (2)      
                  

Total other income

                  
                  

Interest Charges

         22    23       
                  

Income Before Income Taxes

   28       40       17    11 

Income Taxes

   10       14          
                  

Net Income

   18       26       10    

Preferred Stock Dividends

                  
                  

Net Income Available to Common Stockholder

  $17   $  $24   $  $  $
                  

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

BALANCE SHEET

(Unaudited) (In millions)

 

  March 31,  December 31,
  September 30,
        2009        
  December 31,
        2008        
          2010                  2009        

ASSETS

        

Current Assets:

        

Cash and cash equivalents

  $  $  $38   $28 

Accounts receivable – trade (less allowance for doubtful accounts of $5 and $6, respectively)

   48    79 

Accounts receivable – trade (less allowance for doubtful accounts of $8 and $5, respectively)

   77    53 

Accounts receivable – affiliates

   24    12 

Unbilled revenue

   45    74    35    52 

Miscellaneous accounts and notes receivable

            14 

Accounts receivable – affiliates

      

Current portion of intercompany note receivable – Genco

   45    42 

Current portion of intercompany tax receivable – Genco

      

Current portion of note receivable – Genco

   45    45 

Current portion of tax receivable – Genco

   10    

Materials and supplies

   60    70    20    47 

Counterparty collateral

      21 

Current portion of regulatory assets

   51    31 

Deferred taxes

   17    

Current regulatory assets

   99    59 

Current accumulated deferred income taxes, net

   18    18 

Other current assets

            
            

Total current assets

   299    339    375    342 
            

Property and Plant, Net

   1,249    1,212    1,250    1,268 

Other Assets:

    

Intercompany note receivable – Genco

      45 

Intercompany tax receivable – Genco

   87    93 

Investments and Other Assets:

    

Tax receivable – Genco

   78    82 

Regulatory assets

   286    195    261    248 

Other assets

   25    33    31    25 
            

Total investments and other assets

   398    366    370    355 
            

TOTAL ASSETS

  $1,946   $1,917   $1,995   $1,965 
            

LIABILITIES AND STOCKHOLDERS’ EQUITY

        

Current Liabilities:

        

Short-term debt

  $  $62 

Borrowings from money pool

      44 

Accounts and wages payable

   35    48   $41   $48 

Accounts payable – affiliates

   42    49    34    58 

Taxes accrued

   12       29    

Customer deposits

   20    16    21    21 

Mark-to-market derivative liabilities

   14    17    29    10 

Mark-to-market derivative liabilities – affiliates

   38    14    64    43 

Environmental remediation

   21    22 

Other current liabilities

   43    51    42    45 
            

Total current liabilities

   204    308    281    254 
            

Long-term Debt, Net

   421    421    421    421 

Deferred Credits and Other Liabilities:

        

Accumulated deferred income taxes, net

   268    259 

Accumulated deferred income taxes

   269    273 

Accumulated deferred investment tax credits

            

Regulatory liabilities

   239    234    225    242 

Pension and other postretirement benefits

   77    79    59    58 

Other deferred credits and liabilities

   175    78    158    136 
            

Total deferred credits and other liabilities

   767    659    718    716 
            

Commitments and Contingencies (Notes 2, 8, and 9)

        

Stockholders’ Equity:

        

Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding

            

Other paid-in capital

   204    191    257    257 

Preferred stock not subject to mandatory redemption

   50    50    50    50 

Retained earnings

   300    288    268    267 
            

Total stockholders’ equity

   554    529    575    574 
            

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

  $1,946   $1,917   $1,995   $1,965 
            

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

 

  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008              2010                  2009        

Cash Flows From Operating Activities:

        

Net income

  $26   $  $10   $

Adjustments to reconcile net income to net cash provided by operating activities:

        

Depreciation and amortization

   51    50    17    17 

Amortization of debt issuance costs and premium/discounts

            

Deferred income taxes and investment tax credits, net

   (8)   (2)   (6)   (1)

Changes in assets and liabilities:

        

Receivables

   66    32    (2)   33 

Materials and supplies

   10    (25)   27    43 

Accounts and wages payable

   (14)   (6)   (26)    (22)

Taxes accrued

         22    

Assets, other

   26    19    (6)   (7)

Liabilities, other

   (5)      (2)   (7)

Pension and other postretirement benefits

            
            

Net cash provided by operating activities

   160    80    37    69 
            

Cash Flows From Investing Activities:

        

Capital expenditures

   (83)   (65)   (19)   (18)

Proceeds from intercompany note receivable – Genco

   42    39 
            

Net cash used in investing activities

   (41)   (26)   (19)   (18)
            

Cash Flows From Financing Activities:

        

Dividends on common stock

   (12)      (8)   

Dividends on preferred stock

   (2)   (2)   (1)   (1)

Capital issuance costs

   (3)   

Short-term debt, net

   (62)   (29)      (62)

Changes in money pool borrowings, net

   (44)   

Redemptions, repurchases, and maturities of long-term debt

      (35)

Capital contribution from parent

   13    

Money pool borrowings, net

      12 

Other

      
            

Net cash used in financing activities

   (110)   (66)   (8)   (51)
            

Net change in cash and cash equivalents

      (12)   10    

Cash and cash equivalents at beginning of year

      26    28    
            

Cash and cash equivalents at end of period

  $  $14   $38   $
            

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)

 

  Three Months Ended
September 30,
  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2009          2008          2010          2009*    

Operating Revenues

  $212   $238   $655   $667   $267   $295 

Operating Expenses:

            

Fuel

   79    131    224    268    123    112 

Coal contract settlement

            (60)

Purchased power

      

Other operations and maintenance

   46    40    127    133    49    54 

Depreciation and amortization

   19    16    52    48    24    19 

Taxes other than income taxes

         15    16       
                  

Total operating expenses

   149    192    418    405    205    192 
                  

Operating Income

   63    46    237    262    62    103 

Other Income and Expenses:

        

Miscellaneous income

            

Miscellaneous expense

      (1)      (1)
            

Total other expenses

      (1)      
            

Miscellaneous Expense

      

Interest Charges

   14    14    43    40    19    16 
                  

Income Before Income Taxes

   49    31    194    222    42    87 

Income Taxes

   22    11    74    82    18    32 
                  

Net Income

  $27   $20   $120   $140    24    55 

Less: Net Income Attributable to Noncontrolling Interest

      
                  

Net Income Attributable to Ameren Energy Generating Company

  $23   $53 
      

*Combined as discussed in Note 1 - Summary of Significant Accounting Policies.

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except shares)millions)

 

       March 31,     December 31,
  September 30,
        2009        
  December 31,
        2008        
          2010                  2009*        

ASSETS

        

Current Assets:

        

Cash and cash equivalents

  $  $  $  $

Accounts receivable – affiliates

   82    88    107    129 

Miscellaneous accounts and notes receivable

      15    13    26 

Advances to money pool

   114    73 

Materials and supplies

   126    122    168    170 

Income tax receivable

   22    

Mark-to-market derivative assets

   34    22 

Other current assets

            
            

Total current assets

   237    237    444    428 
            

Property and Plant, Net

   2,093    1,950    2,341    2,337 

Intangible Assets

   37    49 

Other Assets

   13    

Investments and Other Assets:

    

Goodwill

   65    65 

Intangible assets

   60    62 

Other assets

   25    28 
            

TOTAL ASSETS

  $2,380   $2,244   $2,935   $2,920 
            

LIABILITIES AND STOCKHOLDER’S EQUITY

    

LIABILITIES AND EQUITY

    

Current Liabilities:

        

Short-term debt

  $100   $

Current portion of intercompany note payable – CIPS

   45    42 

Borrowings from money pool

   37    80 

Current maturities of long-term debt

  $200   $200 

Current portion of note payable – CIPS

   45    45 

Note payable – Ameren

   109    131 

Accounts and wages payable

   51    82    64    85 

Accounts payable – affiliates

   52    58    17    40 

Current portion of intercompany tax payable – CIPS

      

Current portion of tax payable – CIPS

   10    

Taxes accrued

   14    16    29    17 

Interest accrued

   26    12    32    13 

Deferred taxes

   20    15 

Current accumulated deferred income taxes, net

   25    26 

Other current liabilities

   17    16    42    32 
            

Total current liabilities

   371    330    573    598 
            

Long-term Debt, Net

   774    774    823    823 

Intercompany Note Payable – CIPS

      45 

Deferred Credits and Other Liabilities:

        

Accumulated deferred income taxes, net

   182    136    232    216 

Accumulated deferred investment tax credits

            

Intercompany tax payable – CIPS

   87    93 

Tax payable – CIPS

   78    82 

Asset retirement obligations

   52    49    61    60 

Pension and other postretirement benefits

   69    67    91    89 

Other deferred credits and liabilities

   24    49    37    35 
            

Total deferred credits and other liabilities

   419    400    503    486 
            

Commitments and Contingencies (Notes 2, 8 and 9)

        

Stockholder’s Equity:

    

Ameren Energy Generating Company Stockholder’s Equity:

    

Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding

            

Other paid-in capital

   503    503    620    620 

Retained earnings

   361    241    455    432 

Accumulated other comprehensive loss

   (48)   (49)   (52)   (51)
            

Total stockholder’s equity

   816    695 

Total Ameren Energy Generating Company stockholder’s equity

   1,023    1,001 
            

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY

  $2,380   $2,244 

Noncontrolling Interest

   13    12 
            

Total equity

   1,036    1,013 
      

TOTAL LIABILITIES AND EQUITY

  $2,935   $2,920 
      

*Combined as discussed in Note 1 - Summary of Significant Accounting Policies.

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

 

  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2010          2009*    

Cash Flows From Operating Activities:

        

Net income

  $120   $140   $24   $55 

Adjustments to reconcile net income to net cash provided by operating activities:

        

Gain on sales of emission allowances

      (1)

Net mark-to-market (gain) loss on derivatives

   (8)      (1)   

Depreciation and amortization

   65    68    27    24 

Amortization of debt issuance costs and discounts

            

Deferred income taxes and investment tax credits, net

   49    14    13    

Other

      

Changes in assets and liabilities:

        

Receivables

   18    15    35    29 

Materials and supplies

   (4)   (29)      (3)

Accounts and wages payable

   (9)   (18)   (31)   (30)

Taxes accrued

   (2)   (2)   12    18 

Assets, other

   (14)         

Liabilities, other

   (15)   11    16    18 

Pension and other postretirement benefits

            
            

Net cash provided by operating activities

   208    209    103    118
            

Cash Flows From Investing Activities:

        

Capital expenditures

   (216)   (216)   (40)   (81)

Changes in money pool advances

      (13)   (41)   

Purchases of emission allowances

   (2)   (2)      (2)

Sales of emission allowances

      
            

Net cash used in investing activities

   (218)   (230)   (81)   (83)
            

Cash Flows From Financing Activities:

        

Dividends on common stock

      (84)      (23)

Capital issuance costs

   (4)   (2)

Short-term debt, net

   100   (100)

Changes in money pool borrowings, net

   (43)   (54)

Intercompany note payable – CIPS

   (42)   (39)

Issuances of long-term debt

      300 

Dividends paid to noncontrolling interest holder

      (6)

Money pool borrowings, net

      (24)

Note payable – Ameren

   (22)   18 
            

Net cash provided by financing activities

   11    21 

Net cash used in financing activities

   (22)   (35)
            

Net change in cash and cash equivalents

            

Cash and cash equivalents at beginning of year

            
            

Cash and cash equivalents at end of period

  $  $  $  $
            

*Combined as discussed in Note 1 - Summary of Significant Accounting Policies.

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

CILCORP INC.

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
       2009          2008          2009          2008    

Operating Revenues:

        

Electric

  $200   $227   $548   $584 

Gas

   31    37    188    257 

Support services – affiliates

   19       53    

Other

            
                

Total operating revenues

   251    264    794    842 
                

Operating Expenses:

        

Fuel

   37    40    85    93 

Purchased power

   44    84    131    225 

Gas purchased for resale

   14    25    129    190 

Other operations and maintenance

   63    49    190    145 

Goodwill impairment loss

         462    

Depreciation and amortization

   19    22    55    65 

Taxes other than income taxes

         20    18 
                

Total operating expenses

   183    224    1,072    736 
                

Operating Income (Loss)

   68    40    (278)   106 

Other Income and Expenses:

        

Miscellaneous income

            

Miscellaneous expense

   (2)   (2)   (4)   (4)
                

Total other expenses

   (1)   (1)   (3)   (2)

Interest Charges

   24    13    55    41 
                

Income (Loss) Before Income Taxes

   43    26    (336)   63 

Income Taxes

   14       43    20 
                

Net Income (Loss)

   29    18    (379)   43 

Less: Net Income Attributable to Noncontrolling Interests

            
                

Net Income (Loss) Attributable to CILCORP Inc.

  $28   $18   $(380)  $42 
                

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

CILCORP INC.

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except shares)

   September 30,
        2009        
  December 31,
        2008        
ASSETS    

Current Assets:

    

Cash and cash equivalents

  $111   $

Accounts receivable – trade (less allowance for doubtful accounts of $9 and $3, respectively)

   30    60 

Unbilled revenue

   17    65 

Accounts and notes receivable – affiliates

   61    59 

Advances to money pool

      

Materials and supplies

   126    131 

Income tax receivable

   29    

Current portion of accumulated deferred income taxes, net

   10    24 

Current portion of regulatory assets

   33    24 

Other current assets

   10    20 
        

Total current assets

   428    385 
        

Property and Plant, Net

   1,750    1,710 

Investments and Other Assets:

    

Goodwill

   80    542 

Intangible assets

   32    35 

Regulatory assets

   193    171 

Other assets

   26    22 
        

Total investments and other assets

   331    770 
        

TOTAL ASSETS

  $2,509   $2,865 
        

LIABILITIES AND EQUITY

    

Current Liabilities:

    

Current maturities of long-term debt

  $124   $126 

Short-term debt

      286 

Borrowings from money pool

      98 

Intercompany note payable – Ameren

   552    152 

Accounts and wages payable

   50    117 

Accounts payable – affiliates

   60    84 

Taxes accrued

      

Mark-to-market derivative liabilities

   12    21 

Mark-to-market derivative liabilities – affiliates

   21    

Other current liabilities

   81    69 
        

Total current liabilities

   904    964 
        

Long-term Debt, Net

   534    536 

Deferred Credits and Other Liabilities:

    

Accumulated deferred income taxes, net

   232    212 

Accumulated deferred investment tax credits

      

Regulatory liabilities

   62    59 

Pension and other postretirement benefits

   229    216 

Asset retirement obligations

   30    28 

Other deferred credits and liabilities

   90    76 
        

Total deferred credits and other liabilities

   647    596 
        

Commitments and Contingencies (Notes 2, 8 and 9)

    

CILCORP Inc. Stockholder’s Equity:

    

Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding

      

Other paid-in capital

   663    627 

Retained earnings (deficit)

   (280)   100 

Accumulated other comprehensive income

   22    23 
        

Total CILCORP Inc. stockholder’s equity

   405    750 
        

Noncontrolling Interest

   19    19 
        

Total equity

   424    769 
        

TOTAL LIABILITIES AND EQUITY

  $2,509   $2,865 
        

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

CILCORP INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

   Nine Months Ended
September 30,
       2009          2008    

Cash Flows From Operating Activities:

    

Net income (loss)

  $(379)  $43 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

    

Net mark-to-market (gain) loss on derivatives

   (3)   

Depreciation and amortization

   56    66 

Amortization of debt issuance costs and premium/discounts

      

Deferred income taxes and investment tax credits, net

   30    30

Goodwill impairment loss

   462    

Changes in assets and liabilities:

    

Receivables

   70    (3)

Materials and supplies

      (46)

Accounts and wages payable

   (48)   16 

Taxes accrued

      

Assets, other

   (8)   (5)

Liabilities, other

      

Pension and postretirement benefits

   11    (4)
        

Net cash provided by operating activities

   201    108 
        

Cash Flows From Investing Activities:

    

Capital expenditures

   (128)   (223)

Money pool advances, net

      (1)

Purchases of emission allowances

   (1)   

Other

      
        

Net cash used in investing activities

   (127)   (222)
        

Cash Flows From Financing Activities:

    

Capital issuance costs

   (14)   -

Dividends paid to noncontrolling interest holders

   (1)   (1)

Short-term debt, net

   (286)   (88)

Intercompany note payable – Ameren, net

   400    61 

Changes in money pool borrowings, net

   (98)   171 

Redemptions, repurchases, and maturities of:

    

Long-term debt

      (19)

Preferred stock

      (16)

Capital contribution from parent

   36    
        

Net cash provided by financing activities

   37    108 
        

Net change in cash and cash equivalents

   111    (6)

Cash and cash equivalents at beginning of year

      
        

Cash and cash equivalents at end of period

  $111   $
        

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

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)

 

  Three Months Ended
September 30,
  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2009          2008          2010          2009    

Operating Revenues:

            

Electric

  $200   $227   $548   $584   $165   $170 

Gas

   31    37    188    257    112    124 

Support services – affiliates

   19       53       21    16 

Other

                  
                  

Total operating revenues

   251    264    794    842    298    311 
            
      

Operating Expenses:

            

Fuel

   35    39    81    89    39    22 

Purchased power

   44    84    131    225    42    47 

Gas purchased for resale

   14    25    129    190    85    96 

Other operations and maintenance

   64    48    193    145    63    63 

Depreciation and amortization

   19    21    53    62    18    16 

Taxes other than income taxes

         20    18       
                  

Total operating expenses

   182    221    607    729    256    252 
                  

Operating Income

   69    43    187    113    42    59 

Other Income and Expenses:

        

Miscellaneous income

            

Miscellaneous expense

   (1)   (2)   (4)   (3)
            

Total other expenses

      (1)   (3)   (1)
            

Miscellaneous Expense

      

Interest Charges

   13       28    16    12    
                  

Income Before Income Taxes

   56    37    156    96    29    51 

Income Taxes

   19    13    55    34    10    18 
                  

Net Income

   37    24    101    62   $19   $33 

Preferred Stock Dividends

            
                  

Net Income Available to Common Stockholder

  $36   $24   $100   $61 
            

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

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions)

 

  September 30,
        2009        
  December 31,
        2008        
  March 31,
        2010        
  December 31,
        2009        

ASSETS

        

Current Assets:

        

Cash and cash equivalents

  $111   $  $98   $88 

Accounts receivable – trade (less allowance for doubtful accounts of $9 and $3, respectively)

   30    60 

Accounts receivable – trade (less allowance for doubtful accounts of $4 and $3, respectively)

   51    39 

Accounts receivable – affiliates

   61    68 

Unbilled revenue

   17    65    26    43 

Accounts receivable – affiliates

   57    51 

Miscellaneous accounts and notes receivable

      16 

Materials and supplies

   125    131    59    107 

Current portion of regulatory assets

   33    24 

Current regulatory assets

   61    29 

Other current assets

   39    35    27    18 
            

Total current assets

   412    366    387    408 
            

Property and Plant, Net

   1,777    1,734    1,775    1,789 

Investments and Other Assets:

    

Investments in Other Assets:

    

Intangible assets

            

Regulatory assets

   193    171    179    162 

Other assets

   20    22    32    22 
            

Total investments and other assets

   214    194    212    185 
            

TOTAL ASSETS

  $2,403   $2,294   $2,374   $2,382 
            

LIABILITIES AND STOCKHOLDERS’ EQUITY

        

Current Liabilities:

        

Short-term debt

  $  $236 

Borrowings from money pool

      98 

Intercompany note payable – Ameren

   334    

Note payable – Ameren

  $245   $288 

Accounts and wages payable

   50    117    44    62 

Accounts payable – affiliates

   57    83    37    50 

Taxes accrued

            

Mark-to-market derivative liabilities

   12    21    30    10 

Mark-to-market derivative liabilities – affiliates

   21       30    19 

Other current liabilities

   64    60    67    72 
            

Total current liabilities

   542    630    460    506 
            

Long-term Debt, Net

   279    279    279    279 

Deferred Credits and Other Liabilities:

        

Accumulated deferred income taxes, net

   198    171    225    214 

Accumulated deferred investment tax credits

            

Regulatory liabilities

   210    206    201    209 

Pension and other postretirement benefits

   229    216    195    193 

Asset retirement obligations

   30    28    35    34 

Other deferred credits and liabilities

   90    75    105    88 
            

Total deferred credits and other liabilities

   761    701    765    742 
            

Commitments and Contingencies (Notes 2, 8 and 9)

        

Stockholders’ Equity:

        

Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding

            

Other paid-in capital

   465    429    480    480 

Preferred stock not subject to mandatory redemption

   19    19    19    19 

Retained earnings

   340    240    369    354 

Accumulated other comprehensive loss

   (3)   (4)

Accumulated other comprehensive income

      
            

Total stockholders’ equity

   821    684    870    855 
            

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

  $2,403   $2,294   $2,374   $2,382 
            

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

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

 

  Nine Months Ended
September 30,
  Three Months  Ended
March 31,
      2009          2008              2010                  2009        

Cash Flows From Operating Activities:

        

Net income

  $101   $62   $19   $33 

Adjustments to reconcile net income to net cash provided by operating activities:

        

Net mark-to-market (gain) loss on derivatives

   (3)   

Net mark-to-market gain on derivatives

      (2)

Depreciation and amortization

   54    62    18    16 

Amortization of debt issuance costs and premium/discounts

            

Deferred income taxes and investment tax credits, net

   26    30       (2)

Changes in assets and liabilities:

        

Receivables

   66    (3)   27    12 

Materials and supplies

      (46)   48    49 

Accounts and wages payable

   (50)   15    (27)   (68)

Taxes accrued

   (4)         12 

Assets, other

      (9)   (22)   (21)

Liabilities, other

   (4)   (2)   (5)   19 

Pension and postretirement benefits

   14          
            

Net cash provided by operating activities

   211    120    72    52 
            

Cash Flows From Investing Activities:

        

Capital expenditures

   (128)   (223)   (14)   (58)

Purchases of emission allowances

   (1)   

Other

      

Proceeds from sale of noncore properties

      
            

Net cash used in investing activities

   (128)   (221)   (12)   (58)
            

Cash Flows From Financing Activities:

        

Dividends on preferred stock

   (1)   (1)

Capital issuance costs

   (7)   

Dividends on common stock

   (4)   

Short-term debt, net

   (236)   (40)      (181)

Intercompany note payable – Ameren, net

   334    

Changes in money pool borrowings, net

   (98)   171 

Redemptions, repurchases, and maturities of:

    

Long-term debt

      (19)

Preferred stock

      (16)

Note payable – Ameren

   (43)   100 

Money pool borrowings, net

      110 

Capital contribution from parent

   36          11 

Other

   (3)   
            

Net cash provided by financing activities

   28    95 

Net cash provided by (used in) financing activities

   (50)   41 
            

Net change in cash and cash equivalents

   111    (6)   10    35 

Cash and cash equivalents at beginning of year

         88    
            

Cash and cash equivalents at end of period

  $111   $  $98   $35 
            

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

ILLINOIS POWER COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)

 

  Three Months Ended
September 30,
  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2009          2008          2010          2009    

Operating Revenues:

            

Electric

  $266   $303   $765   $799   $251   $252 

Gas

   61    49    351    414    200    216 

Other

         10          
                  

Total operating revenues

   329    353    1,126    1,216    453    472 
            
      

Operating Expenses:

            

Purchased power

   126    185    401    499    135    149 

Gas purchased for resale

   23    22    214    298    140    158 

Other operations and maintenance

   56    79    200    233    72    67 

Depreciation and amortization

   24    21    73    61    25    24 

Amortization of regulatory assets

         13    13       

Taxes other than income taxes

   12    12    46    48    21    21 
                  

Total operating expenses

   246    324    947    1,152    397    423 
                  

Operating Income

   83    29    179    64    56    49 

Other Income and Expenses:

            

Miscellaneous income

                  

Miscellaneous expense

   (1)   (2)   (2)   (5)      
                  

Total other income

            

Total other expense

   (1)   
                  

Interest Charges

   24    22    76    72    23    26 
                  

Income (Loss) Before Income Taxes

   59       104    (4)

Income Taxes (Benefit)

   24       42    (2)

Income Before Income Taxes

   32    23 

Income Taxes

   13    
                  

Net Income (Loss)

   35       62    (2)

Net Income

   19    14 

Preferred Stock Dividends

                  
                  

Net Income (Loss) Available to Common Stockholder

  $34   $  $60   $(4)

Net Income Available to Common Stockholder

  $18   $13 
                  

The accompanying notes as they relatedrelate to IP are an integral part of these financial statements.

ILLINOIS POWER COMPANY

BALANCE SHEET

(Unaudited) (In millions)

 

  September 30,
        2009        
  December 31,
        2008        
  March 31,
        2010        
  December 31,
        2009        
ASSETS        

Current Assets:

        

Cash and cash equivalents

  $178   $50   $119   $190 

Accounts receivable – trade (less allowance for doubtful accounts of $8 and $12, respectively)

   93    152 

Accounts receivable – trade (less allowance for doubtful accounts of $12 and $9, respectively)

   149    107 

Accounts receivable – affiliates

   66    49 

Unbilled revenue

   38    133    55    94 

Accounts receivable – affiliates

   64    23 

Advances to money pool

      44 

Miscellaneous accounts and notes receivable

      23 

Materials and supplies

   136    144    54    112 

Counterparty collateral

   11    35 

Current portion of regulatory assets

   84    57 

Counterparty collateral asset

   33    

Current regulatory assets

   149    86 

Other current assets

   28    21    20    21 
            

Total current assets

   632    659    645    687 
            

Property and Plant, Net

   2,379    2,329    2,461    2,450 

Investments and Other Assets:

        

Goodwill

   214    214    214    214 

Regulatory assets

   601    517    562    540 

Other assets

   49    47    64    51 
            

Total investments and other assets

   864    778    840    805 
            

TOTAL ASSETS

  $3,875   $3,766   $3,946   $3,942 
            

LIABILITIES AND STOCKHOLDERS’ EQUITY

        

Current Liabilities:

    

Current maturities of long-term debt

  $  $250 

Current Liabilities:

    

Accounts and wages payable

   67    94   $64   $98 

Accounts payable – affiliates

   119    105    96    117 

Taxes accrued

         10    

Interest accrued

   35    21    34    17 

Customer deposits

   46    50    43    46 

Mark-to-market derivative liabilities

   26    36    59    20 

Mark-to-market derivative liabilities – affiliates

   58    20    88    65 

Environmental remediation

   40    59 

Other current liabilities

   50    64    46    77 
            

Total current liabilities

   405    648    480    505 
            

Long-term Debt, Net

   1,146    1,150    1,147    1,147 

Deferred Credits and Other Liabilities:

        

Accumulated deferred income taxes, net

   211    176    234    232 

Regulatory liabilities

   87    76    90    88 

Pension and other postretirement benefits

   297    314    240    238 

Other deferred credits and liabilities

   300    151    308    281 
            

Total deferred credits and other liabilities

   895    717    872    839 
            

Commitments and Contingencies (Notes 2, 8 and 9)

        

Stockholders’ Equity:

        

Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding

            

Other paid-in-capital

   1,313    1,194    1,349    1,349 

Preferred stock not subject to mandatory redemption

   46    46    46    46 

Retained earnings

   67       49    53 

Accumulated other comprehensive income

            
            

Total stockholders’ equity

   1,429    1,251    1,447    1,451 
            

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

  $3,875   $3,766   $3,946   $3,942 
            

The accompanying notes as they relatedrelate to IP are an integral part of these financial statements.

ILLINOIS POWER COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

 

  Nine Months Ended
September 30,
  Three Months Ended
March 31,
      2009          2008          2010          2009    

Cash Flows From Operating Activities:

        

Net income (loss)

  $62   $(2)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

    

Net income

  $19   $14 

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization

   82    67    29    26 

Amortization of debt issuance costs and premium/discounts

            

Deferred income taxes

   35    23       

Other

   (1)         (1)

Changes in assets and liabilities:

        

Receivables

   116    52       19 

Materials and supplies

      (68)   58    84 

Accounts and wages payable

      13    (39)   (21)

Taxes accrued

   (4)         

Assets, other

   20    (12)   (34)   (23)

Liabilities, other

   23    31    (16)   

Pension and other postretirement benefits

            
            

Net cash provided by operating activities

   351    120    34    117 
            

Cash Flows From Investing Activities:

        

Capital expenditures

   (127)   (128)   (46)   (35)

Changes in money pool advances, net

   44    (9)

Other

      (2)

Advances to AITC for construction

   (3)   (17)

Money pool advances, net

      (12)
            

Net cash used in investing activities

   (83)   (139)   (49)   (64)
            

Cash Flows From Financing Activities:

        

Dividends on common stock

      (45)   (21)   

Dividends on preferred stock

   (2)   (2)   (1)   (1)

Capital issuance costs

   (7)   (2)

Short-term debt, net

      129 

Redemptions, repurchases and maturities of long-term debt

   (250)   (337)

Issuance of long-term debt

      336 

Capital contribution from parent

   119          58 

IP SPT maturities

      (54)

Generator advances for construction received (refunded), net

   (34)   19 
            

Net cash provided by (used in) financing activities

   (140)   25    (56)   76 
            

Net change in cash and cash equivalents

   128       (71)   129 

Cash and cash equivalents at beginning of year

   50       190    50 
            

Cash and cash equivalents at end of period

  $178   $12   $119   $179 
            

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

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

AMEREN ENERGY GENERATING COMPANY (Consolidated)

CILCORP INC. (Consolidated)

CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)

ILLINOIS POWER COMPANY

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

September 30, 2009March 31, 2010

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren and CILCORP holding companies depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.

 

UE, or Union Electric Company, also known as AmerenUE, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

 

CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

 

Genco, or Ameren Energy Generating Company, operates a merchant electric generation business in Illinois and Missouri. Genco has an 80% ownership interest in EEI.

 

CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a merchant electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business, all in Illinois.

 

IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks, and provision of other shared services.

Ameren, through Genco, has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UEEEI. Ameren and 40% by Development Company. Ameren consolidatesGenco consolidate EEI for financial reporting purposes. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred toJanuary 1, 2010, as part of an internal reorganization, Resources Company through an internal reorganization. UE’stransferred its 80% stock ownership interest in EEI was transferred at book value indirectlyto Genco through a dividendcapital contribution. The transfer of EEI to Ameren.Genco was accounted for as a transaction between entities under common control, whereby Genco accounted for the transfer at the historical carrying value of the parent (Ameren) as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in EEI included purchase accounting adjustments relating to Ameren’s acquisition of an additional 20% ownership interest in EEI in 2004. This transfer required Genco’s prior period financial statements to be retrospectively combined for all periods presented. Consequently, Genco’s prior period consolidated financial statements reflect EEI as if it had been a subsidiary of Genco.

The financial statements of Ameren, Genco CILCORP and CILCO are prepared on a consolidated basis. UE, CIPS and IP have no subsidiaries, and therefore their financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

On April 13, 2010, CIPS, CILCO and IP entered into a merger agreement under which CILCO and IP will be merged with and into CIPS as part of a two-step corporate reorganization of Ameren. The second step of the reorganization would involve the distribution of AERG common stock to Ameren and the subsequent contribution by Ameren of the AERG common stock to Resources Company. See Note 14 - Corporate Reorganization for additional information.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect

reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

Management has performed an evaluation of subsequent events through November 6, 2009, which was the date Ameren’s financial statements were issued and the date UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s financial statements were available to be issued.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three and nine months ended September 30, 2009March 31, 2010 and 2008.2009. The number of stock options, restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share. All of Ameren’s remaining stock options expired in February 2010.

Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of September 30, 2009,March 31, 2010, under the Long-term Incentive Plan of 1998, as amended, and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

  Performance Share Units Restricted Shares   Performance Share Units Restricted Shares 
  Share Units Weighted-average
Fair Value Per Unit
 Shares Weighted-average
Fair Value Per Share
   Share Units 

Weighted-average

Fair Value Per Unit

at Grant Date

 Shares 

Weighted-average

Fair Value Per Share

at Grant Date

 

Nonvested at January 1, 2009

  675,977   $43.28   213,683   $47.46  

Nonvested at January 1, 2010

  945,337   $22.07   135,696   $48.92  

Granted(a)

  741,738(a)   15.52   -    -    688,510    32.01   -    -  

Dividends

  -    -   6,116    24.52    -    -   1,162    26.60  

Forfeitures

  (14,163  30.14   (3,645  48.30    (7,501  22.54   (4,369  49.71  

Vested(b)

  (143,610)(b)   19.17   (82,277  45.15    (100,474  31.19   (52,828  47.43  

Nonvested at September 30, 2009

  1,259,942   $29.83   133,877   $48.92  

Nonvested at March 31, 2010

  1,525,872   $25.95   79,661   $49.87  

 

(a)Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in March 2009January 2010 under the 2006 Plan.
(b)Share units vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.

The fair value of each share unit awarded in March 2009January 2010 under the 2006 Plan was determined to be $15.52$32.01. That amount was based on Ameren’s closing common share price of $22.20 per share$27.95 at March 2,December 31, 2009, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2009.2010. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.24%1.70%, volatility of 21.3%23% to 33.1%39% for the peer group, and Ameren’s attainment of a three-year average earnings per share of at least $2.54threshold during each year of the performance period.

Ameren recorded compensation expense of $4$5 million and $7$5 million for the three months ended September 30,March 31, 2010, and 2009, and 2008, respectively, and a related tax benefit of $2 million and $3$2 million for the three months ended September 30,March 31, 2010, and 2009, and 2008, respectively. Ameren recorded compensation expense of $12 million and $21 million for the nine months ended September 30, 2009 and 2008, respectively, and a related tax benefit of $5 million and $8 million for the nine months ended September 30, 2009 and 2008, respectively. As of September 30, 2009,March 31, 2010, total compensation expense of $11$22 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 1929 months.

Accounting Changes and Other Matters

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issuedThe following is a summary of recently adopted authoritative guidance that established accounting and reporting standards for minority interests, which were recharacterized as noncontrolling interests. This guidance requires noncontrolling interests to be classified as a component of equity separate from the parent’s equity; purchases or sales of equity interests that do not result in a change in control to be accounted for as equity transactions; net income attributable to the noncontrolling interest to be included in consolidated net income in the statement of income; and upon a loss of control, the interest sold, as well as any interest retained, to be recorded at fair value, with any gain or loss recognized in earnings. Weguidance issued but not yet adopted that could impact the provisions of this guidance as of the beginning of 2009, which applies prospectively, except for the presentation and disclosure requirements, for which it applies retroactively. This guidance impacts Ameren and CILCORP. See Noncontrolling Interest below for additional information.Companies.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued amended authoritative guidance that requires entities to provide greater transparency in interim and annual financial statements about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for, and how the instruments and related hedged items affect the financial position, results of operations, and cash flows of the entity. This guidance requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. Effective for us in the first quarter of 2009, the adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provided enhanced amended disclosure requirements only. See Note 6 - Derivative Financial Instruments for additional information.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

In April 2009, the FASB issued additional authoritative guidance regarding the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for an asset or liability. The guidance, which applies to all fair value measurements, does not change the objective of a fair value measurement. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.

Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued amended authoritative guidance to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity, because it provided enhanced disclosure requirements only. See Note 7 - Fair Value Measurements for our interim reporting disclosures.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued authoritative guidance that established a new method of recognizing and reporting other-than-temporary impairments of debt securities and contains additional annual and interim disclosure requirements related to debt and equity securities.

Under the new guidance, an impairment of debt securities is other-than-temporary if (1) the entity intends to sell the security, (2) it is more likely than not that the entity will be required to sell the security before recovery of its amortized cost basis, or (3) the entity does not expect to recover the security’s entire amortized cost basis. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.

Subsequent Events

In May 2009, the FASB issued authoritative guidance that established general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.

Variable InterestVariable-Interest Entities

In June 2009, the FASB issued amended authoritative guidance that significantly changes the consolidation rules for VIEs. The guidance requires an enterprise to qualitatively assess the determination of the primary beneficiary of a VIE based on whether the entity (1) has the power to direct matters that most significantly impactaffect the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Further, the guidance requires an ongoing reconsideration of the primary beneficiary. It also amends the events that trigger a reassessment of whether an entity is a VIE. We are in the process of determining the impact theThe adoption of this guidance, effective for us as of January 1, 2010, willdid not have a material impact on our results of operations, financial position, and liquidity, if any.or liquidity. See Variable - interest Entities below for additional information.

The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting PrinciplesDisclosures about Fair Value Measurements

In June 2009,January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance requires disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also requires information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. Further, the FASB Accounting Standards Codification (the “Codification”), which isclarified guidance regarding the primary sourcelevel of authoritative GAAP to be applied by nongovernmental entities. Rulesdisaggregation, inputs, and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification modifies the hierarchy of GAAP to include only two levels: authoritative and nonauthoritative. The Codification supersedes all non-SEC accounting and reporting standards. All other nongrandfathered, non-SEC accounting literature not included in the Codification are nonauthoritative. The adoption of the Codification,valuation techniques. This guidance was effective for us as of JulyJanuary 1, 2009,2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which will be effective for us as of January 1, 2011. The adoption of this guidance did not

have a material impact on our results of operations, financial position, or liquidity.liquidity because it provides enhanced disclosure requirements only. See Note 7 - Fair Value Measurements for additional information.

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. Ameren’s goodwill relates to its acquisition of IP and an additional 20% EEI ownership interest acquired in 2004 as well as its acquisition of CILCORP and Medina Valley in 2003. IP’s goodwill relates to the acquisition of IP in 2004. Ameren’s and CILCORP’sGenco’s goodwill relates to the acquisition of CILCORP in 2003. Ameren’s goodwill also includes an additional 20% EEI ownership interest in EEI acquired in 20042004. We evaluate goodwill for impairment as well asof October 31 of each year, or more frequently if events or changes in circumstances indicate that the acquisition of Medina Valley in 2003. During the first quarter of 2009, CILCORP recognized a non-cash goodwill impairment loss of $462 million. Ameren and IP did not recognize a goodwill impairment during the first nine months of 2009. See Note 14 - Goodwill Impairment for further information about CILCORP’s goodwill impairment.asset might be impaired.

Intangible Assets.We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s, Genco’s CILCORP’s and CILCO’s intangible assets consisted of emission allowances at September 30, 2009.March 31, 2010. See also Note 9 - Commitments and Contingencies for additional information on emission allowances.

The following table presents the SO2 and NOx emission allowances held and the related aggregate SO2 and NOx emission allowance book values that were carried as intangible assets at September 30, 2009.as of March 31, 2010. Emission allowances consist of various individual emission allowance certificates and do not expire. Emission allowances are charged to fuel expense as they are used in operations.

 

SO2 and NOx in tons  SO2(a)  NOx(b)  Book Value(c)   SO2(a)  NOx(b)  Book  Value(c) 

Ameren(d)

  3,085,000  31,213  $138(e)   3,192,000  75,851  $124(d) 

UE

  1,647,000  15,840   38    1,698,000  46,236   33  

Genco

  753,000  11,870   37    1,114,000  25,973   60  

CILCORP

  357,000  758   32(f) 

CILCO (AERG)

  357,000  758   1    380,000  3,642   1  

EEI

  328,000  2,745   7  

 

(a)Vintages are from 20092010 to 2019.2020. Each company possesses additional allowances for use in periods beyond 2019.2020.
(b)Vintage is 2009.2010.
(c)

The book value represents SO2 and NOx emission allowances for use in periods through 2038.2039. The book value at December 31, 2008,2009, for Ameren, UE, Genco CILCORP,and CILCO (AERG), and EEI was $167 million, $48 million, $49$129 million, $35 million, $1$62 million, and $9$1 million, respectively.

(d)Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(e)Includes $24$30 million of fair-market value adjustments recorded in connection with Ameren’s 2004 acquisition of an additional 20% ownership interest in EEI.
(f)Includes fair market value adjustments recorded in connection with Ameren’s2003 acquisition of CILCORP.

The following table presents amortization expense based on usage of emission allowances, net of gains from emission allowance sales, for Ameren, UE, Genco CILCORP and CILCO (AERG) during the three and nine months ended September 30, 2009March 31, 2010 and 2008.2009:

 

  Three Months Nine Months   Three Months 
  2009 2008 2009 2008   2010 2009 

Ameren(b)(a)

  $10   $9   $23   $25    $3   $5  

UE

   -    -    (c  (1   (b  (b)  

Genco(a)

   5    7    13    20     3    5  

CILCORP(b)

   2    2    4    5  

CILCO (AERG)

   (c  (c  1    (c   (b  (b)  

 

(a)Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)Includes allowances consumed that were recorded through purchase accounting.
(c)(b)Less than $1 million.

Employee Separation and Other Charges

In the third quarter of 2009, Ameren initiated a voluntary separation program that provided eligible management employees the opportunity to voluntarily terminate and receive benefits consistent with Ameren’s standard management severance program. This program was offered to eligible management employees at Ameren’s subsidiaries, including UE, CIPS, Genco, CILCORP, CILCO and IP. Additionally, in November 2009, Ameren initiated an involuntary separation program to reduce additional management positions under terms and benefits consistent with Ameren’s standard management severance program. Ameren recorded a pretax charge to earnings of $17.5 million during the quarter ended September 30, 2009, (UE - $9 million, CIPS - $1 million, Genco - $3 million, CILCORP - $3 million, CILCO - $3 million, and IP - $1 million) for the severance costs related to both the voluntary and involuntary separation programs as well as for Merchant Generation staff reductions announced in the third quarter of 2009. This charge was recorded in other operations and maintenance expense in the applicable statements of income. It is anticipated that substantially all of this amount will be paid prior to December 31, 2009. The number of positions eliminated as a result of these separation programs, including the Merchant Generation staff reductions, will total approximately 300. In addition to these programs, Genco recorded a $4 million pretax charge to earnings in the third quarter of 2009 for the retirement of two generating units at its Meredosia power plant and for related obsolete inventory.

Excise Taxes

Excise taxes imposed on us are reflected on Missouri electric, Missouri natural gas, and Illinois natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:

 

  Three Months Nine Months   Three Months 
  2009 2008 2009 2008   2010  2009 

Ameren

  $44   $43   $128   $130    $46  $42  

UE

   36    36    89    88     25   23  

CIPS

   2    2    10    11     5   5  

CILCORP

   2    1    8    8  

CILCO

   2    1    8    8     4   4  

IP

   4    4    21    23     12   10  

Uncertain Tax Positions

The amount of unrecognized tax benefits as of September 30, 2009,March 31, 2010, was $136$139 million, $86$90 million, less than $1 million, $24$30 million, $17 million, $17$15 million, and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. The amount of unrecognized tax benefits (detriments) as of September 30, 2009,March 31, 2010, that would impact the effective tax rate, if recognized, was $6 million, $2$3 million, less than $1 million, $(1) million, less than $1 million, less than $1 million, and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively.

Ameren remains subject to U.S.Ameren’s 2005 and 2006 federal income tax examination byreturns are before the Appeals Office of the Internal Revenue Service. The Internal Revenue Service for 2005is currently examining Ameren’s 2007 and subsequent years. 2008 income tax returns.

State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies do not have material stateAmeren’s 2007 and 2008 State of Illinois income tax issuesreturns are currently under examination administrative appeals, or litigation.by the Illinois Department of Revenue.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their financial condition or results of operations.operations, financial position or liquidity.

Asset Retirement Obligations

AROs at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP increased compared to December 31, 2008,2009, to reflect the accretion of obligations to their fair values.

Variable-interest Entities

According to the applicable authoritative accounting guidance, an entity is considered a VIE if it does not have sufficient equity to finance its activities without assistance from variable-interest holders, or if its equity investors lack any of the following characteristics of a controlling financial interest: control through voting rights, the obligation to absorb expected losses, or the right to receive expected residual returns. The primary beneficiary of a VIE is the entity that (1) has the power to direct matters that most significantly affect the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE if they are its primary beneficiary. We have determined that the following significant VIEs were held by the Ameren Companies at March 31, 2010:

        Affordable housing partnership investments. At March 31, 2010, and December 31, 2009, Ameren had investments in multiple affordable housing and low-income real estate development partnerships as well as an investment in a commercial real estate development partnership of $58 million and $64 million in the aggregate, respectively. Ameren has a variable interest in these investments as a limited partner. With the exception of the commercial real estate development partnership, Ameren owns less than a 50% interest in each partnership and receives the benefits and accepts the risks consistent with its limited partner interest. Ameren is not the primary beneficiary of these investments because Ameren does not have the power to direct matters that most significantly impact the activities of the VIE. These investments are classified as Other Assets on Ameren’s consolidated balance sheet. The maximum exposure to loss as a result of these variable interests is limited to the investments in these partnerships.

See Note 8 - Related Party Transactions for information about IP’s variable interest in AITC.

Noncontrolling Interest

At Ameren,Ameren’s noncontrolling interest comprisesinterests comprise the 20% of EEI’s net assets not owned by Ameren and the Ameren subsidiaries’ outstanding preferred stock not subject to mandatory redemption of the Ameren subsidiaries.not owned by Ameren. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. At CILCORP,Genco’s noncontrolling interest comprises the preferred stock20% of EEI’s net assets not subject to mandatory redemption of its subsidiary, CILCO.owned by Genco. This noncontrolling interest is classified as a component of equity separate from CILCORP’sGenco’s equity in CILCORP’sits consolidated balance sheet.

A reconciliation of the equity changes attributable to the noncontrolling interest at Ameren and CILCORPGenco for the three and nine months ended September 30, 2009 and 2008March 31, 2010, is shown below:

 

  Three Months Nine Months   Three Months 
  2009 2008 2009 2008           2010                 2009         

Ameren:

        

Noncontrolling interest, beginning of period

  $207   $219   $216   $217    $207   $216  

Net income attributable to noncontrolling interest

   2    11    9    33     4    4  

Dividends paid to noncontrolling interest holders

   (3  (11  (19  (31   (2  (8

Noncontrolling interest, end of period

  $206   $219   $206   $219    $209   $212  

CILCORP:

     

Genco:

   

Noncontrolling interest, beginning of period

  $19   $19   $19   $19    $12   $21  

Net income attributable to noncontrolling interest

   1    -    1    1     1    2  

Dividends paid to noncontrolling interest holders

   (1  -    (1  (1   -    (6

Noncontrolling interest, end of period

  $19   $19   $19   $19    $13   $17  

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In January 2009, the MoPSC issued an order approving an increase for UE in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. In February 2009, Noranda, UE’s largest electric customer, and the Missouri Office of Public Counsel appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Circuit Court of Cole County, Missouri. In September 2009, the Circuit Court of Pemiscot County granted Noranda’s request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. The merits of the appeal will be briefed by the parties over the next several months, with a decision likely to be issued by the court in the first half of 2010. During the stay, Noranda will pay into the court registry the contested portion of its monthly billings, approximately $0.5 million per month based on current usage levels. If UE wins the appeal, it will receive those monthly payments plus interest.

Pending Electric Rate Case

UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service. The currently pending request, as amended, seeks to increase annual revenues from electric service by $402$287 million. Included in this increase request wasis approximately $227$118 million of anticipated increases in normalized net fuel costs in excess of the net fuel costs included in base rates previously authorized by the MoPSC in its January 2009 electric rate order, which, absent initiation of this general rate proceeding, would have been eligible for recovery through UE’s existing FAC.order. The balance of the increase request is based primarily on investments made to continue system-wide reliability improvements for customers, increases in costs essential to generating and delivering electricity, and higher financing costs. The electric rate increase request, as amended, is based on an 11.5%a 10.8% return on equity, a capital structure composed of 47.4%51.3% equity, a rate base for UE of $6.0$6 billion, and a test year ended March 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of January 31, 2010. Following Ameren’s September 2009 common stock issuance, UE received a capital contribution from Ameren of $436 million in September 2009. UE expects to true-up its capital structure in the electric rate case to reflect this capital contribution, among other things. See Note 4 - Long-term Debt and Equity Financings for further information on the Ameren common stock issuance.

UE’s filing included a request for interim rate relief, which would place into effect approximately $37 million of the requested increase prior to completion of the full rate case. The amount of this interim increase request reflected the increased revenue requirement associated with rate base additions made by UE between October 2008 and May 2009. The MoPSC has scheduled a hearing in December 2009 to consider UE’s request for interim rate relief.

As part of its original filing, UE also requested that the MoPSC to approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker. The environmental cost recovery mechanism, if approved, would allow UE to twice each year adjust electric rates outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with federal, state or local environmental laws, regulations or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews of the MoPSC. UE’s request is consistent with the environmental cost recovery rules approved by the MoPSC in April 2009. The storm restoration cost tracker would permit UE a more timely recovery of storm restoration operations and maintenance expenditures.

In addition, UE requested that the MoPSC approve the continued use of the FAC and the vegetation management and infrastructure inspection cost tracking mechanism that the MoPSC previously authorized in its January 2009 electric rate order, and the continued use of the regulatory tracking mechanism for pension and postretirement benefit costs that the MoPSC previously authorized in its May 2007 electric rate order. The UE request included the discontinuation of the SO2 emission allowance sales tracker.

The MoPSC staff has responded to the UE request for an electric service rate increase. The MoPSC staff’s recommendation, as amended, is to increase UE’s filingannual revenues by $165 million based on a return on equity of 9.35%. Included in this recommendation is approximately $107 million of increases in normalized net fuel costs. Other parties also made recommendations through testimony filed in this case. The MoPSC staff and other parties have expressed opposition to some of the requested cost recovery mechanisms.

UE, the MoPSC staff, and other parties have agreed to several stipulations resolving various revenue requirement issues, which have been approved by the MoPSC and will be implemented with the MoPSCeffective date of the final rate order. Those stipulations include UE’s agreement to withdraw its request to implement an environmental cost recovery mechanism in this case in exchange for the ability to defer allowance for funds used during construction and depreciation costs for pollution control equipment at one of its power plants until the earlier of January 2012 or that equipment is put in customer rates. The parties also seeks approvalagreed to reviseprospectively include the tariff under which it serves Norandamargins on certain wholesale contracts in UE’s FAC in exchange for an increase in the jurisdictional cost allocation to retail customers. In addition, the parties have agreed to a mechanism that will prospectively address the significant lost revenues UE can incur due to any future operational issues at Noranda’s smelter plant in southeastern Missouri, suchsoutheast Missouri. The agreement will permit UE, when a significant loss of service occurs at the Noranda plant, to sell the power not taken by Noranda and use the proceeds of those sales to offset the revenues lost from Noranda. UE will be allowed to keep the amount of revenues necessary to compensate UE for significant Noranda usage reductions but any excess revenues above the level necessary to compensate UE would be refunded to retail customers through the FAC. Approved stipulations also include the continued use of the regulatory tracking mechanism for pension and postretirement benefit costs, among other things.

The MoPSC still has several important issues to consider in this case. Those issues include determining the appropriate return on equity, depreciation rates, power plant maintenance and certain reliability expenditure levels to be reflected in base rates, as well as whether UE should be able to continue to employ its existing FAC at the revenue losses resulting from the January 2009 storm-related power outage. The tariff change that UE is proposing would permit it to collect from Noranda the revenue authorizedcurrent 95% sharing level and vegetation management and infrastructure inspection cost tracking mechanisms.

A decision by the MoPSC in this rate case regardless of the level at which the Noranda plant is operating prospectively. If the plant is operating at levels less than the levels assumed in rates, Noranda would receive a credit reflecting any revenues received by UE from energy sales resulting from the decrease in actual energy sales to Noranda. The result would be that UE is able to recover its costs without impacting other customers regardless of Noranda’s actual energy use.

The MoPSC proceeding relating to the proposed electric service rate changes (except for the request for interim rate relief as discussed above) will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by the end of June 2010. Hearings are scheduled for March 2010. UE cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change (interim or final) may go into effect, whether the cost recovery mechanisms and trackers requested will be approved or continued, or whether any rate change that may eventually be approved will be sufficient to enable UE to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.

Missouri Energy Efficiency Investment Act

In July 2009, the Missouri governor signed a law that went into effect in August 2009, which, among other things, allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. Recovery is only permitted if the program is approved by the MoPSC, results in energy savings, and is beneficial to all customers in the class for which the program is proposed. The new law would potentially, among other items, allow UE to earn a return on its energy efficiency programs, which the current model of cost recovery does not permit.

Illinois

Pending Electric and Natural Gas Delivery Service Rate Cases

In June 2009, CIPS, CILCO and IP filed requests withOn April 29, 2010, the ICC toissued a consolidated order approving a net increase theirin annual revenues for electric delivery service. The currently pending requests, as amended, seek to increase annual revenues from electric delivery service by $136of $32 million in the aggregate (CIPS

(CIPS - $41$17 million increase, CILCO - $22$1 million increase, and IP - $73 million). The electric rate increase requests are based on an 11.3% to 11.7% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.4 billion,$14 million increase) and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010. In addition, the Ameren Illinois Utilities have requested a rider mechanism that would permit all distribution-related costs incurred to implement reliability recommendations submitted by the Liberty Consulting Group, which are discussed below, to be reflectednet decrease in electric rates outside of general rate proceedings. The Ameren Illinois Utilities estimate that they will incur distribution-related implementation costs of $15 million (CIPS - $5 million, CILCO - $3 million, and IP - $7 million) in 2010.

CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service. The currently pending requests, as amended, seek to increase annual revenues for natural gas delivery service by $26of $27 million in the aggregate (CIPS - $7$3 million decrease, CILCO - $6$9 million decrease, and IP - $13 million). The natural gas rate increase requests are$15 million decrease), based on a 10.8%9.9% to 11.2%10.3% return on equity a capital structure composed of 44%with respect to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion,electric delivery service and a test year ended December 31, 2008,9.2% to 9.4% return on equity with certain known and measurable adjustments through May 2010.

In September 2009, the ICC staff filed direct testimony in responserespect to the Ameren Illinois Utilities electric and natural gas delivery serviceservice. These rate changes became effective on May 6, 2010. On May 6, 2010, the ICC amended the April 2010 rate order to correct a technical error in the calculation of cash working capital, which resulted in an additional increase filings.in annual revenues totaling $10 million in the aggregate. The ICC staff recommended in their testimonyconsolidated rate order, as amended, approves a net increase in annual revenues for electric delivery service for the Ameren Illinois Utilities of $49$35 million in the aggregate (CIPS - $16$18 million increase, CILCO - $6$2 million increase, and IP - $27$15 million increase) and a net decrease in annual revenues for natural gas delivery service of $4$20 million in the aggregate (CIPS - $1$2 million increase,decrease, CILCO - $3$7 million decrease, and IP - $2$11 million decrease). The ICC staff position is based on a 10.2%rate changes relating to 10.4% return on equity for electric delivery service and a 9.4% to 9.8% return on equity for natural gas delivery service. Other parties also made recommendations through direct testimony filed in the electric and natural gas delivery service rate cases.error correction will become effective May 12, 2010.

The ICC proceedings relatingorder confirmed the previously approved 80% allocation of fixed non-volumetric residential and commercial natural gas customer charges, and approved a higher percentage of recovery of fixed non-volumetric electric residential and commercial customer charges. The percentage of costs to be recovered through fixed non-volumetric electric residential and commercial customer and meter charges increased from 27% to 40%. This increase will impact quarterly results of operations and cash flows, but is not expected to have any impact on annual margins.

In response to the proposed electricICC consolidated rate order and natural gasamended rate order, the Ameren Illinois Utilities intend to take immediate action to address the financial pressures created on the respective companies. CIPS, CILCO and IP intend to take the following actions:

significantly reduce budgets;

institute a hiring freeze;

substantially reduce the use of contractors;

delay or cancel certain projects and planned activities; and

reduce expenditures for capital projects designed to enhance reliability of their respective delivery service rate changes will take place oversystems.

The Ameren Illinois Utilities and other parties have 30 days from the date of the order to request an ICC rehearing of the April 2010 consolidated order. The Ameren Illinois Utilities filed a period of upmotion to 11 months, andstay certain decisions byin the ICC in such proceedings are required byorder on May 2010. Hearings are scheduled for December 2009.7, 2010, and will seek rehearing. The Ameren Illinois Utilities may subsequently appeal the ICC rate order. The Ameren Illinois Utilities cannot predict the levelif their requests for an ICC stay of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, certain decisions and/or whether any rate changes that may eventually be approved will be sufficient to enable the Ameren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the rate changes go into effect.

Illinois Electric Settlement Agreement

The Ameren Illinois Utilities, Genco, and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding under the Illinois electric settlement agreement in a manner corresponding with the timing of the funding. As a result, Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended September 30, 2009, of $6 million, $1 million, $1 million, $1 million, $3 million, and $1 million, respectively (quarter ended September 30, 2008 - $10 million, $2 million, less than $1 million, $2 million, $4 million, and $2 million, respectively) and during the nine months ended September 30, 2009, of $18 million, $3 million, $1 million, $4 million, $7 million, and $3 million, respectively (nine months ended September 30, 2008 - $32 million, $5 million, $2 million, $6 million, $13 million, and $6 million, respectively).

Power Procurement Plan

In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products that the IPA procured on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 31, 2014. The IPA procured capacity, energy swaps, and renewable energy credits through a RFP process on behalf of the Ameren Illinois Utilitiesrehearing are granted or, in the second quarter of 2009. See Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies for further information aboutevent the results of the RFPs.

In August 2009, the IPA submitted its plan for procurement of electric power for the Ameren Illinois Utilities and Commonwealth Edison Company for the period June 1, 2010, through May 31, 2015. The plan must be approved or modifiedrequests are denied by the ICC, by December 29, 2009. The IPA is proposing to hold two procurement events in 2010: one in the spring for energy, capacity and renewable energy credits and a second in the fall for demand response resources. The exact dates of each procurement event have not been determined. Once the proposed 2010 procurement events are complete, the Ameren Illinois Utilities will have sufficient capacity and energy hedges in place for 100% of their expected supply obligation for the period June 2010 through May 2011, 70% of their expected supply obligation for the period June 2011 through May 2012, and 44% of their expected supply obligations for the period June 2012 through May 2013. Renewable energy creditswhether court appeals will be procured for 2010 only.

ICC Reliability Audit

In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on the Ameren Illinois Utilities’ transmission and distribution systems and reliability following the July 2006 wind storms and a November 2006 ice storm. In October 2008, Liberty Consulting Group presented the ICC with a final report containing recommendations for the Ameren Illinois Utilities to improve their systemsfiled and their response to emergencies. The ICC directed the Ameren Illinois Utilities to present to the ICC a plan to implement Liberty Consulting Group’s recommendations. The plan was submitted to the ICC in November 2008. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. The Ameren Illinois Utilities expect to incur an estimated $20 million ($15 million for distribution and $5 million for transmission) of capital costs and an estimated $66 million ($50 million for distribution and $16 million for transmission) of cumulative operations and maintenance expenses for the 2009 through 2013 timeframe in order to implement the recommendations. In testimony filed with the ICC in October 2009 as part of the pending electric delivery service rate cases, the Ameren Illinois Utilities requested recovery of all distribution-related costs through the implementation of a rider mechanism that would permit the Ameren Illinois Utilities to reflect these costs in electric rates outside of general rate proceedings. Transmission-related costs will be recoverable through FERC’s ratemaking proceedings.

Illinois 2009 Energy Legislation

In July 2009, a new law became effective in Illinois that, among other things, establishes new energy efficiency targets for Illinois natural gas utilities, develops a percentage of income payment plan for low-income utility customers, and allows electric and gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their rates. The legislation provides utilities the ability to adjust their rates annually through a rate adjustment mechanism that applies to 2008 and subsequent years. During 2008, the Ameren Illinois Utilities incurred approximately $25 million more of bad debt expense (CIPS - $5 million, CILCO - $4 million, and IP - $16 million) than they recovered through rates. In August 2009, the Ameren Illinois Utilities filed with the ICC electric and natural gas rate adjustment clause tariffs to recover bad debt expense not recovered in 2008 and to make corresponding rate adjustments beginning in 2010. The ICC has until February 2010 to approve, or approve as modified, the filed tariffs.

Upon ICC approval of the rate adjustment clause tariffs filed in August 2009, the Ameren Illinois Utilities will be required to make a one-time $10 million donation (CIPS - $3 million, CILCO - $2 million, and IP - $5 million) for customer assistance programs. The amount of the required one-time donation and the impact of the recovery of 2008 bad debt expenses were reflected in earnings during the third quarter of 2009.ultimate outcome.

Federal

Nuclear Combined Construction and Operating License Application

In July 2008, UE filed an application with the NRC for a combined construction and operating license for a potential new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. UE had also signed contracts for COLA-related services and certain long lead-time nuclear-unit related equipment (heavy forgings).

In early 2009, the Missouri Clean and Renewable Energy Construction Act was separately introduced in both the Missouri Senate and House of Representatives. These bills were designed to allow the MoPSC to authorize, among other things, utilities to recover the costs of financing and tax payments associated with a new generating plant while that plant was being constructed. Recovery of actual construction costs still could not have begun until a plant was put into service. UE believes legislation allowing timely recovery of financing costs during construction must be enacted in order for it to build a new nuclear unit to meet its baseload generation capacity needs. However, passage of this or other legislation was not a commitment or guarantee that UE would build a new nuclear unit.

In April 2009, senior management of UE announced that they had asked the legislative sponsors of the Missouri Clean and Renewable Energy Construction Act to withdraw the bills from consideration by the Missouri General Assembly. UE believed pursuing the legislation being considered in the Missouri Senate in its then proposed form would not give it the financial and regulatory certainty needed to complete the project. As a result, UE announced that it was suspending its efforts to build a new nuclear unit at its existing Missouri nuclear plant site. In June 2009, UE requested the NRC suspend review of the COLA and all activities related to the COLA. UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE is due to file with the MoPSC in 2011.

As of September 30, 2009, UE had capitalized approximately $68 million as construction work in progress related to the COLA. The incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned with respect to the future construction of a new nuclear unit, it is possible that a charge to earnings could be recognized in a future period.

Prior to June 30, 2009, UE made contractual payments to the heavy forgings manufacturer of $14 million and had remaining contractual commitments of $81 million. In July 2009, an agreement was reached with the heavy forgings manufacturer to terminate the heavy forgings procurement agreement, and $5 million of previously-made payments were retained by the manufacturer as a penalty for terminating the contract, which was charged to earnings in June 2009. See Note 9 - Commitments and Contingencies for further information about the contract termination.

FERC Order - MISO Charges

In May 2007, UE, CIPS, CILCO and IP filed with the U.S. Court of Appeals for the District of Columbia Circuit an appeal of FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the appeal in abeyance until the end of the continuing proceedings at FERC regarding these costs. Other MISO participants also filed appeals. On August 10, 2007, UE, CIPS, CILCO, and IP filed a complaint with FERC regarding the MISO tariff’s allocation methodology for these same MISO operational charges. In November 2007, FERC issued two orders relative to these allocation matters. One of these orders addressed requests for rehearing of prior orders in the proceedings, and one concerned MISO’s compliance with FERC’s orders to date in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s clarification or rehearing of its November 2007 order regarding MISO’s compliance with FERC’s orders. UE, CIPS, CILCO, and IP maintained that MISO was required to reallocate certain of MISO’s operational costs among MISO market participants, which would result in refunds to UE, CIPS, CILCO, and IP retroactive to April 2006. On November 7, 2008, FERC issued an order granting the request for clarification and directed MISO to reallocate certain MISO operational costs among MISO participants and provide refunds for the period April 2006 to August 2007 (“November 7, 2008 Clarification Order”). On November 10, 2008, FERC granted further relief requested in the complaints filed by UE, CIPS, CILCO, IP and others regarding further reallocation for these same MISO operational charges and directed MISO to calculate refunds for the period from August 10, 2007, forward (“November 10, 2008 Complaint Order”).

Several parties to these proceedings protested MISO’s proposed implementation of these refunds, requested rehearing of FERC’s orders and, in some cases, have appealed FERC’s orders to the courts. In March 2009, MISO began resettling its markets to provide refunds as FERC directed effective on August 10, 2007. On May 6, 2009, FERC issued an order that upheld most of the conclusions of the November 10, 2008 Complaint Order but changed the effective date for refunds such that certain operational costs will be allocated among MISO market participants beginning November 10, 2008, instead of August 10, 2007. In June 2009, UE, CIPS, CILCO and IP filed for rehearing of the May 2009 order regarding the change to the refund effective date. This rehearing request is pending.

With respect to the November 7, 2008 Clarification Order, in June 2009 FERC issued an order dismissing rehearing requests of such clarification order and waiving refunds of amounts billed that were included in the MISO charge under the assumption that there was a rate mismatch for the period April 25, 2006, through November 4, 2007. UE, CIPS, CILCO and IP filed a request for rehearing in July 2009. This rehearing request is pending.

With respect to the two rehearing requests discussed above, UE, CIPS, CILCO and IP do not believe that the ultimate resolution of either request will have a material effect on their results of operations, financial position, or liquidity.

MISO and PJM Dispute Resolution

During 2009, MISO and PJM discovered an error in the calculation quantifying certain transactions between the RTOs. The error, which originated in April 2005, corresponding withat the initiation of the MISO Day Two Energy and Operating Reserves Market and was corrected prospectively in June 2009. Since discovering the error, MISO and PJM have worked jointly to estimate theits financial impact toon the respective markets. MISO and PJM are in agreement onabout the methodology used to recalculate the market flows occurring from June 2007 to June 2009 for the resettlement due from PJM to MISO estimated at $65 million. MISO and PJM are not in agreement onabout the methodology used to recalculate the market flows occurring from April 2005 to May 2007, nor are they in agreement overabout the resettlement amount. To

Attempts to resolve this issue, MISO and PJM have agreed to participate indispute through FERC’s dispute resolution and settlement process were not successful. In early March 2010, MISO filed complaints with FERC against PJM seeking a $130 million resettlement, plus interest, of the contested transactions. In April 2010, PJM filed a complaint with FERC against MISO alleging MISO violated the joint operating agreement’s market-to-market coordination process for certain transactions between the two RTOs. PJM’s complaint states it is entitled to determine a resettlement amountat least $25 million from MISO for the entire period from April 2005 to June 2009. In October 2009, an administrative law judge was appointed as mediator, and a settlement conference was held at FERC. A final settlement between MISO and PJM, if and when reached, will be subject to FERC approval.amounts improperly paid in result of MISO’s alleged process violation. Ameren and its subsidiaries may receive or pay a to-be-determined portion of theany resettlement amount due from PJM to MISO. Until a settlementbetween the RTOs. No prospective refund or payment has been reached and approved byrecorded related to this matter. We expect FERC will issue an order during the second quarter of 2010; however, it is not required to do so. Until FERC issues an order, we cannot predict the ultimate impact of these proceedings on Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.

NOTE 3 - SHORT-TERMCREDIT FACILITY BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, andshort-term intercompany borrowings, or drawings under committed bank credit facilities.

Amended and New Credit Facilities

On June 30, 2009, Ameren and certain of its subsidiaries entered into multiyear credit facility agreements with 24 international, national and regional lenders with no single lender providing more than $146 million of credit. These facilities, as described below, cumulatively provide $2.1 billion of credit through July 14, 2010, thereafter reducing to $1.8795 billion through June 30, 2011, and thereafter reducing to $1.0795 billion through July 14, 2011.

2009 Multiyear Credit Agreements

On June 30, 2009, Ameren, UE, and Genco entered into an agreement (the “2009 Multiyear Credit Agreement”) to amend and restate the $1.15 billion five-year revolving credit agreement that was originally entered into as of July 14, 2005, then amended and restated as of July 14, 2006, and due to expire in July 2010 (the “Prior $1.15 Billion Credit Facility”). Ameren, UE, and Genco also entered into a $150 million Supplemental Credit Agreement to the 2009 Multiyear Credit Agreement (the “Supplemental Agreement”), which provides Ameren, UE, and Genco with an additional facility of $150 million with terms and conditions substantially identical to the 2009 Multiyear Credit Agreement. Collectively, these agreements are the “2009 Multiyear Credit Agreements.”

The obligations of each borrower under the 2009 Multiyear Credit Agreements are several and not joint, and except under limited circumstances relating to expenses and indemnities, the obligations of UE or Genco are not guaranteed by Ameren or any other subsidiary of Ameren. The combined maximum amount available to all of the borrowers, collectively, under the 2009 Multiyear Credit Agreements is $1.3 billion, and the combined maximum amount available to each borrower, individually, under the 2009 Multiyear Credit Agreements is limited as follows: Ameren - $1.15 billion, UE - $500 million and Genco - $150 million (such amounts being each borrower’s “Borrowing Sublimit”). CIPS, CILCO, and IP have no borrowing authority or liability under the 2009 Multiyear Credit Agreements.

On July 14, 2010, the Supplemental Agreement will terminate, all commitments and all outstanding amounts under the Supplemental Agreement will be consolidated with those under the 2009 Multiyear Credit Agreement, and the combined maximum amount available to all borrowers will be $1.0795 billion with the UE and Genco Borrowing Sublimits remaining the same noted above and Ameren’s changing to $1.0795 billion. Ameren has the option to seek additional commitments from existing or new lenders to increase the total facility size to $1.3 billion after July 14, 2010. The 2009 Multiyear Credit Agreement will terminate with respect to Ameren on July 14, 2011, representing a one-year extension from the Prior $1.15 Billion Credit Facility. The Borrowing Sublimits

of UE and Genco will continue to be subject to extension on a 364-day basis (but in no event later than July 14, 2011) with the current maturity date of their Borrower Sublimits under the 2009 Multiyear Credit Agreements being June 29, 2010.

The obligations of all borrowers under the 2009 Multiyear Credit Agreements are unsecured. The interest rates applicable to loans under the 2009 Multiyear Credit Agreements will be either ABR (alternate base rate) 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 reference to such borrower’s long-term unsecured credit ratings as in effect from time to time. A competitive bid rate is also available if requested by a borrower. Letters of credit in an aggregate undrawn face amount not to exceed $287.5 million are available for issuance for account of the borrowers under (but within the $1.3 billion overall combined facility limitation) the 2009 Multiyear Credit Agreements.

Under the 2009 Multiyear Credit Agreements, the principal amount of each revolving loan will be due and payable no later than the final maturity of the agreements, in the case of Ameren, and the last day of the then applicable 364-day period in the case of UE and Genco. Ameren, UE and Genco will use the proceeds of any borrowings under the 2009 Multiyear Credit Agreements for general corporate purposes, including for working capital, and to fund loans under the Ameren money pool arrangements.

2009 Illinois Credit Agreement

Also on June 30, 2009, Ameren, CIPS, CILCO, and IP entered into an $800 million multiyear, senior secured credit agreement (the “2009 Illinois Credit Agreement”). The 2009 Illinois Credit Agreement replaces the Ameren Illinois Utilities’ existing $500 million credit facility dated as of July 14, 2006 (the “2006 $500 Million Credit Facility (Terminated)”), and their existing $500 million credit facility dated as of February 9, 2007 (the “2007 $500 Million Credit Facility (Terminated)”), each as previously amended (collectively, the “Terminated Illinois Credit Facilities”), which were terminated contemporaneously with the effectiveness of the 2009 Illinois Credit Agreement.

Ameren was not a borrower under the Terminated Illinois Credit Facilities, but is a borrower under the 2009 Illinois Credit Agreement. CILCORP and AERG were borrowers under the Terminated Illinois Credit Facilities, but are not parties to or borrowers under the 2009 Illinois Credit Agreement. All obligations of CILCORP and AERG under the Terminated Illinois Credit Facilities have been repaid and all liens securing such obligations have been released. CILCORP and AERG expect to meet their external liquidity needs through borrowings under the Ameren non-state-regulated subsidiary money pool arrangements or other liquidity arrangements.

The obligations of each borrower under the 2009 Illinois Credit Agreement are several and not joint, and are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum amount available to each borrower under the facility is limited as follows: Ameren - $300 million, CIPS - $135 million, CILCO - $150 million and IP - $350 million (such amounts being such borrower’s “Borrowing Sublimit”).

The 2009 Illinois Credit Agreement will terminate with respect to all borrowers on June 30, 2011. Each borrowing under the 2009 Illinois Credit Agreement must be repaid no later than 364 days after such borrowing, in each case subject to the right of the applicable borrower on such date to make a new borrowing or convert or continue such borrowing as a new borrowing subject to satisfaction of the applicable conditions to borrowing. The obligations of the Ameren Illinois Utilities under the 2009 Illinois Credit Agreement are secured by the issuance of mortgage bonds, for collateral support, by each such utility under its respective mortgage indenture in an amount equal to its respective Borrowing Sublimit. Ameren’s obligations are unsecured.

Loans are available on a revolving basis under the 2009 Illinois Credit Agreement 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 applicable under the 2009 Illinois Credit Agreement are 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 reference to, in the case of Ameren, Ameren’s long-term unsecured credit ratings as in effect from time to time, and in the case of the Ameren Illinois Utilities, such utility’s long-term secured credit ratings as in effect from time to time. Letters of credit in an aggregate undrawn face amount not to exceed $200 million are also available for issuance for the account of the borrowers (but within the $800 million overall facility limitation) under the 2009 Illinois Credit Agreement.

Borrowings were made under the 2009 Illinois Credit Agreement to repay amounts owed under the Terminated Illinois Credit Facilities, and the borrowers will use the proceeds of other borrowings for working capital and other general corporate purposes.

The following table summarizes the borrowing activity and relevant interest rates as of September 30, 2009,March 31, 2010, under the 2009 Multiyear Credit Agreements,Agreement, the 2009 Supplemental Credit Agreement, and the 2009 Illinois Credit Agreement and the Terminated Illinois Credit Facilities (excluding letters of credit issued):

 

2009 Multiyear Credit Agreement ($1.15 billion)(a)          Ameren
   (Parent)   
  

UE

  

    Genco    

  

      Total      

 

September 30, 2009:

        

Average daily borrowings outstanding during 2009

     $252   $355   $49   $656  

Outstanding short-term debt at period end

      279    -    88    367  

Weighted-average interest rate during 2009

      1.75  1.72  2.57  1.75

Peak short-term borrowings during 2009(b)

     $484   $457   $133   $940  

Peak interest rate during 2009

           5.50  5.50  3.56  5.50

            

                         
Supplemental Agreement ($150 million)          Ameren
   (Parent)   
  

UE

  

Genco

  

Total

 

September 30, 2009:

        

Average daily borrowings outstanding during 2009

     $8   $14   $5   $27  

Outstanding short-term debt at period end

      36    -    12    48  

Weighted-average interest rate during 2009

      3.65  3.62  3.53  3.65

Peak short-term borrowings during 2009(b)

     $56   $53   $17   $109  

Peak interest rate during 2009

           5.50  5.50  3.56  5.50

            

                         
2009 Illinois Credit Agreement ($800 million)      Ameren
   (Parent)   
  CIPS  CILCO
    (Parent)    
  IP  Total 

September 30, 2009:

        

Average daily borrowings outstanding during 2009

    $133   $-   $-   $-   $133  

Outstanding short-term debt at period end

     -    -    -    -    -  

Weighted-average interest rate during 2009

     3.54  -    -    -    3.54

Peak short-term borrowings during 2009(b)

    $200   $-   $-   $-   $200  

Peak interest rate during 2009

       3.56  -    -    -    3.56

            

                         
2007 $500 Million Credit Facility (Terminated)  

    CIPS    

  CILCORP
(Parent)
  CILCO
(Parent)
      IP      AERG  Total 

September 30, 2009:

        

Average daily borrowings outstanding during 2009(c)

  $-  $9   $-   $-   $59   $68  

Outstanding short-term debt at period end

   -   -    -    -    -    -  

Weighted-average interest rate during 2009(c)

   -   1.81  -    -    1.42  1.47

Peak short-term borrowings during 2009(b)(c)

  $-  $50   $-   $-   $100   $135  

Peak interest rate during 2009(c)

   -   1.81  -    -    3.25  3.25

2006 $500 Million Credit Facility (Terminated)  

     CIPS     

  CILCORP
   (Parent)   
  CILCO
   (Parent)   
  

        IP        

  

    AERG    

  

     Total     

 

September 30, 2009:

         

Average daily borrowings outstanding during 2009(c)

  $5   $49   $-  $-  $96   $150  

Outstanding short-term debt at period end

   -    -    -   -   -    -  

Weighted-average interest rate during 2009(c)

   2.02  1.88  -   -   1.34  1.54

Peak short-term borrowings during 2009(b)(c)

  $62   $50   $-  $-  $151   $263  

Peak interest rate during 2009(c)

   2.02  3.29  -   -   2.72  3.29
2009 Multiyear Credit Agreement ($1.15 billion)      Ameren
   (Parent)   
  

UE

  

Genco

  

Total

 

March 31, 2010:

        

Average daily borrowings outstanding during 2010

   $629   $-  $-  $629  

Outstanding short-term debt at period end

    557    -   -   557  

Weighted-average interest rate during 2010

    2.98  -   -   2.98

Peak short-term borrowings during 2010(a)

   $712   $-  $-  $712  

Peak interest rate during 2010

       5.5  -   -   5.5
        
2009 Supplemental Credit Agreement ($150 million)      

Ameren

   (Parent)   

  

UE

  

Genco

  

Total

 

March 31, 2010:

        

Average daily borrowings outstanding during 2010

   $82   $-  $-  $82  

Outstanding short-term debt at period end

    73    -   -   73  

Weighted-average interest rate during 2010

    3.49  -   -   3.49

Peak short-term borrowings during 2010(a)

   $93   $-  $-  $93  

Peak interest rate during 2010

       5.5  -   -   5.5
        
2009 Illinois Credit Agreement ($800 million)  

Ameren

   (Parent)   

  

CIPS

  

CILCO

(Parent)

  

IP

  

Total

 

March 31, 2010:

        

Average daily borrowings outstanding during 2010

  $22   $-   $-  $-  $22  

Outstanding short-term debt at period end

   -    -    -   -   -  

Weighted-average interest rate during 2010

   3.48  -    -   -   3.48

Peak short-term borrowings during 2010(a)

  $100   $-   $-  $-  $100  

Peak interest rate during 2010

   3.48  -    -   -   3.48

 

(a)The 2009 Multiyear Credit Agreement amended and restated the Prior $1.15 Billion Credit Facility and therefore information in this table includes borrowing activity under the Prior $1.15 Billion Credit Facility.
(b)The timing of peak short-term borrowings varies by company and therefore the amounts presented by company may not equal the total peak short-term borrowings for the period. The simultaneous peak short-term borrowings under all facilities during the first ninethree months of 20092010 were $1 billion.
(c)Calculated through the termination date.$905 million.

Based on outstanding borrowings under the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement (including reductions for $11$15 million of letters of credit issued under the 2009 Multiyear Credit Agreement), the available amounts under the facilities at September 30, 2009,March 31, 2010, were $874$655 million and $800 million, respectively.

On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. The average annual interest rate for borrowing under the $20 million term loan agreement was 1.98% and 2.06% during the three and nine months ended September 30, 2009, respectively.

On June 25, 2008, Ameren entered into a $300 million term loan agreement due June 24, 2009, which was fully drawn on June 26, 2008. The average annual interest rate for borrowing under the $300 million term loan agreement was 1.98% during the period it was outstanding in 2009. This term loan was repaid at maturity in June 2009 with proceeds from the Ameren $425 million senior unsecured notes due May 2014 issued in May 2009. See Note 4 - - Long-term Debt and Equity Financings.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants. See Note 4 - Short-termCredit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions in the Prior $1.15 Billion Credit Facility, the Terminated Illinois Credit Facilities, the now-terminated 2008 $300 million term loan agreement, and the 2009 $20 million term loan agreement.

The 2009 Multiyear Credit Agreements contain conditions to borrowings and issuances of letters of credit similar to those in the Prior $1.15 Billion Credit Facility, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation) and required regulatory authorizations. The 2009 Multiyear Credit Agreements also contain nonfinancial covenants similar to those in the Prior $1.15 Billion Credit Facility, including restrictions on the ability to incur liens, transact with affiliates, dispose of assets, and merge with other entities. In addition, Ameren and certain subsidiaries are restricted to limited investments in and other transfers to affiliates, including investments in the Ameren Illinois Utilities and their subsidiaries.

The 2009 Multiyear Credit Agreements contain identical default provisions that are, in each case, similar to those in the Prior $1.15 Billion Credit Facility, including a cross default of a borrower to the occurrence of a default by such borrower under any other agreement covering indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and non-material subsidiaries) in excess of $25 million in the aggregate. A default by an Ameren Illinois utility under the 2009 Illinois Credit

Agreement does not constitute a default under the 2009 Multiyear Credit Agreements. Any default of Ameren under the 2009 Illinois Credit Agreement that exists solely as a result of a default by an Ameren Illinois utility thereunder will not constitute a default under either of the 2009 Multiyear Credit Agreements while Ameren is otherwise in compliance with all of its obligations under the 2009 Illinois Credit Agreement.provisions.

The 2009 Multiyear Credit Agreements require Ameren, UE and Genco to each maintain consolidated indebtedness of not more than 65% of consolidated total capitalization pursuant to a calculation set forth in the facilities. All of the consolidated subsidiaries of Ameren, including the Ameren Illinois Utilities, are included for purposes of determining compliance with this capitalization test with respect to Ameren. Failure to satisfy the capitalization covenant constitutes a default under the 2009 Multiyear Credit Agreements. As of September 30, 2009,March 31, 2010, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2009 Multiyear Credit Agreements, were 50%, 48% and 52%, for Ameren, UE and Genco, respectively.

The 2009 Illinois Credit Agreement contains conditions to borrowings and issuance of letters of credit similar to those in the Terminated Illinois Credit Facilities, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding, for so long as ratings conditions shall be satisfied, any representation after the closing date as to the absence of material adverse change and material litigation which exclusion is new to the 2009 Illinois Credit Agreement) and required regulatory authorizations. The rating condition is satisfied if the borrower has a Moody’s rating of Baa3 or higher or an S&P rating of BBB- or higher (in the case of Ameren, with respect to senior unsecured long-term debt, and in the case of the Ameren Illinois Utilities, with respect to senior secured long-term debt). The 2009 Illinois Credit Agreement contains nonfinancial covenants including restrictions on the ability to incur liens, transact with affiliates, dispose of assets, and merge with other entities. The Ameren Illinois Utilities may engage in certain mergers or similar transactions that result in their utility operations being conducted by a single legal entity. In addition, the 2009 Illinois Credit Agreement has nonfinancial covenants limiting the ability of a borrower to invest in or transfer assets to affiliates, covenants regarding the status of the collateral securing the 2009 Illinois Credit Agreement and maintenance of the validity of the security interests therein.

The 2009 Illinois Credit Agreement contains default provisions similar to those in the Terminated Illinois Credit Facilities. Defaults under the 2009 Illinois Credit Agreement apply separately to each borrower; provided that a default by an Ameren Illinois utility will constitute a default by Ameren. Defaults include a cross default of a borrower to the occurrence of a default by such borrower under any other agreement covering indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and non-material subsidiaries) in excess of $25 million in the aggregate. A default by Genco or UE under the 2009 Multiyear Credit Agreements does not constitute an event of default under the 2009 Illinois Credit Agreement. Any default of Ameren under the 2009 Multiyear Credit Agreements that exists solely as a result of a default by UE or Genco thereunder will not constitute a default under the 2009 Illinois Credit Agreement while Ameren is otherwise in compliance with all of its obligations under the 2009 Multiyear Credit Agreements. Furthermore, under the 2009 Illinois Credit Agreement, the occurrence of a default resulting from an event or conditions effecting AERG, shall be deemed to constitute a default with respect to Ameren under the 2009 Illinois Credit Agreement, but shall not in itself constitute a default with respect to CILCO unless the liability that CILCO has in respect of such default or such underlying event or condition giving rise to such default would otherwise constitute a default with respect to CILCO had such underlying event or condition occurred or existed at CILCO.

The 2009 Illinois Credit Agreement requires Ameren and each Ameren Illinois utility to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation. All of the consolidated subsidiaries of Ameren are included for purposes of determining compliance with this capitalization test with respect to Ameren. As of September 30, 2009,March 31, 2010, the ratios of consolidated indebtedness to total consolidated capitalization for Ameren, CIPS, CILCO and IP, calculated in accordance with the provisions of the 2009 Illinois Credit Agreement, were 50%, 45%44%, 44%39%, and 45%, respectively. In addition, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of at least 2.0 to 1, as of the end of the most recent four fiscal quarters and calculated and subject to adjustment in accordance with the 2009 Illinois Credit Agreement. Ameren’s ratio as of September 30, 2009March 31, 2010, was 4.74.5 to 1. Failure to satisfy these covenants constitutes a default under the 2009 Illinois Credit Agreement.

In addition, the 2009 Illinois Credit Agreement prohibits CILCO from issuing any preferred stock if, after such issuance, the aggregate liquidation value of all CILCO preferred stock issued after June 30, 2009, would exceed $50 million. The 2009 Illinois Credit Agreement does not include the $10 million per year restriction on CIPS, CILCORP, CILCO and IP common and preferred stock dividend payments that was included in the Terminated Illinois Credit Facilities.

Under the $20 million term loan agreement entered into in January 2009, Ameren may elect, for up to three 30-day periods, to pay down and reduce to zero the outstanding principal balance. The term loan agreement requires Ameren to maintain consolidated indebtedness of not more than 65% of consolidated total capitalization pursuant to a calculation defined in the term loan agreement. As of September 30, 2009, the ratio of consolidated indebtedness to consolidated total capitalization for Ameren calculated in accordance with the provisions of the $20 million term loan agreement was 49%.

None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At September 30, 2009,March 31, 2010, management believes that the Ameren Companies were in compliance with their credit facilities and term loan agreementfacilities’ provisions and covenants.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

Through the utility money pool, the pool participants may access the committed credit facilities. See discussion above for amounts available under the facilities at September 30, 2009.March 31, 2010. UE, CIPS, CILCO and IP may borrow from each other through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. Ameren and AERG may participate in the utility money pool only as lenders. The primary sources of external funds for the utility money pool are the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2009,March 31, 2010, was 0.2% and 0.2%, respectively (20080.14% (2009 - 2.9% and 3.3%, respectively)0.24%).

Non-state-regulated Subsidiaries

Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from the 2009 Multiyear Credit Agreements through a non-state-regulated subsidiary money pool agreement. In addition, Ameren had available cash balances at September 30, 2009,March 31, 2010, which can be loaned into this arrangement. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and nine months ended September 30, 2009,March 31, 2010, was 2.2% and 1.5%, respectively (20080.62% (2009 - 3.5% and 3.7%, respectively)1.2%).

See Note 8 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three and nine months ended September 30, 2009.March 31, 2010.

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.70.8 million new shares of common stock valued at $18 million and 2.6 million new shares of common stock valued at $65$20 million in the three and nine months ended September 30, 2009, respectively.March 31, 2010.

In May 2009, Ameren issued $425 million of 8.875% senior unsecured notes due May 15, 2014, with interest payable semiannually on May 15 and November 15 of each year, beginning November 15, 2009. Ameren received net proceeds of $420 million, which were used, together with other corporate funds, to repay borrowings under its $300 million term loan agreement and, by way ofFebruary 2010, CILCORP completed a capital contribution to CILCORP, providing funds for it to repay its outstanding 8.70% senior notes on their due date of October 15, 2009.

In September 2009, Ameren issued and sold 21.9 million sharescovenant defeasance of its common stock at $25.25 per share, for proceeds of $535 million, net of $17 million of issuance costs. Ameren used the net offering proceeds to make investments in its rate-regulated utility subsidiaries in the form of equity capital contributions as follows: UE - $436 million, CIPS - $13 million, CILCO - - $25 million, and IP - $61 million.

UE

In March 2009, UE issued $350 million of 8.45% senior secured notes due March 15, 2039, with interest payable semiannually on March 15 and September 15 of each year, beginning in September 2009. These notes are secured by first mortgage bonds. UE received net proceeds of $346 million, which were used to repay short-term debt. In connection with this issuance of $350 million of senior secured notes, UE agreed, for so long as these senior secured notes are outstanding, that it will not, prior to maturity, cause a first mortgage bond release date to occur. The first mortgage bond release date is the date at which the security provided by the pledge under UE’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness.

CILCORP

In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was increased to fair value by $111 million. Amortization related to fair-value adjustments was $1 million and $4 million (2008 - $1 million and $4 million) for the three and nine months ended September 30, 2009, respectively, and was included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.

In September 2008, CILCORP commenced a cash tender offer and related consent solicitation for any and all of its then outstanding 8.70% senior notes due 2009 and its 9.375% senior bonds due 2029. In April 2009, CILCORP terminated the tender offer and the consent solicitation related to the then outstanding 8.70% senior notes due 2009. In July 2009, CILCORP terminated the tender offer and the consent solicitation related to the outstanding 9.375% senior bonds due 2029. None of the 2009 notes or the 2029 bonds were purchased in the tender offer and consent solicitation.

In November 2009, CILCORP commenced a cash tender offer for any and all of itsremaining outstanding 9.375% senior bonds due 2029 ($210.565by depositing approximately $2.7 million aggregate principal amount). Concurrentin U.S. government obligations and cash with the tender offer, CILCORP solicited consents from the holders of the bonds to certain proposed amendments to the indenture governing the bonds. Any holder tendering bonds as part of this offer is deemed to consent to the proposed amendments. No consentstrustee. This deposit will be accepted separate from a tenderused solely to satisfy the principal and remaining interest obligations on these bonds. In connection with this covenant defeasance, the lien on the capital stock of such holder’s bonds. The amendments would eliminate certain restrictive covenants in the indenture and the bonds. The total consideration for each $1,000 principal amount ofCILCO securing these bonds validly tendered on or prior to November 17, 2009, the consent date, is $1,210, which includes a consent payment of $50 per $1,000 principal amount of such bonds tendered on or prior to the consent date. Holders validly tendering and not withdrawing bonds on or before the consent date are eligible to receive the total consideration. Holders validly tendering bonds after the consent date but on or before the expiration date, which is scheduled for December 7, 2009, are eligible to receive the total consideration less the consent payment. In addition, tenders of bonds may be withdrawn (and related consents may be rescinded) at any time prior to the consent date. Consummation of the tender offer and the consent solicitation is subject to a number of conditions, including the absence of certain adverse legal and market developments, as described in the offer to purchase. CILCORP has reserved the right to amend, extend, terminate, or waive any conditions to the tender offer and the consent solicitation at any time. The impact on CILCORP’s net income of the tender offer is not expected to be material.

IP

In March 2009, IP exchanged all $400 million of its unregistered 9.75% senior secured notes due November 15, 2018, for a like amount of registered 9.75% senior secured notes due November 15, 2018. The unregistered senior secured notes were issued and sold in October 2008 with registration rights in a private placement.

In June 2009, $250 million of IP’s 7.50% series first mortgage bonds matured and were retired.was released.

Indenture Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indenture provisions and other covenants. See Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a detailed description of those provisions.

UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. UE, CIPS, CILCO and IP are required to meet certain ratios to issue first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended September 30, 2009,March 31, 2010, at an assumed interest rate of 7% and dividend rate of 8%.

 

  Required Interest
Coverage Ratio(a)
 Actual Interest
Coverage Ratio
  Bonds
Issuable(b)
  Required Dividend
Coverage Ratio(c)
  Actual Dividend
Coverage Ratio
  Preferred Stock
Issuable
   

Required Interest

Coverage Ratio(a)

 

Actual Interest

Coverage Ratio

  

Bonds

Issuable(b)

  

Required Dividend

Coverage Ratio(c)

  

Actual Dividend

Coverage Ratio

  

Preferred Stock

Issuable

 

UE

  ³2.0     2.4  $713  ³2.5  35.8  $988    ³2.0     3.0  $1,424  ³2.5  45.7  $1,283  

CIPS

  ³2.0     4.4   368  ³1.5  2.1   154    ³2.0     4.6   356  ³1.5  2.1   140  

CILCO

  ³2.0(d) 7.5   214  ³2.5  124.9   50(e)   ³2.0(d) 7.2   214  ³2.5  139.6   50(e) 

IP

  ³2.0     3.2   1,364  ³1.5  1.7   135    ³2.0     3.9   1,213  ³1.5  1.9   342  

 

(a)Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b)Amount of bonds issuable based either on meeting required coverage ratios or unfunded property additions, whichever is more restrictive. These amounts shown also include bonds issuable based on retired bond capacity of $95$94 million, $18 million, $44 million and $536 million, at UE, CIPS, CILCO and IP, respectively.
(c)Coverage required on the annual interest charges on all long-term debt (CIPS only) and the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. For CILCO, this ratio must be met for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance.

(d)In lieu of meeting the interest coverage ratio requirement, CILCO may attempt to meet an earnings requirement of at least 12% of the principal amount of all mortgage bonds outstanding and to be issued. For the three and nine months ended September 30, 2009,March 31, 2010, CILCO had earnings equivalent to at least 33%36% of the principal amount of all mortgage bonds outstanding.
(e)See Note 34 - Short-termCredit Facility Borrowings and Liquidity in the Form 10-K for a discussion regarding the restriction on the issuance of preferred stock by CILCO under the 2009 Illinois Credit Agreement.

UE, CIPS, Genco, CILCO and IP as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, CIPS, CILCO and IP may not pay any dividend on their respective stock, unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless CIPS, CILCO or IP has specific authorization from the ICC.

UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.8 billion of free and unrestricted retained earnings at September 30, 2009.March 31, 2010.

CIPS’ articles of incorporation and mortgage indentures require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus.

CILCO’s articles of incorporation contain certain provisions that prohibit the payment of dividends on its common stock (1) from either paid-in surplus or any surplus created by a reduction of stated capital or capital stock, or (2)stock. Dividend payment is also prohibited if at the time of dividend declaration there shall not remain to the credit of earned surplus account (after deducting the amountpayment of such dividends) would not contain an amount at least equal to two times the annual dividend requirement on all outstanding shares of CILCO’s preferred stock.

Genco’s and CILCORP’s indentures includeindenture includes provisions that require the companiesGenco to maintain certain debt service coverage and/or debt-to-capital ratios in order for the companiesGenco to pay dividends, to make certain principal or interest payments, to make certain loans to or investments in affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended September 30, 2009:March 31, 2010:

 

    Required
Interest
Coverage
Ratio
  Actual
Interest
Coverage
Ratio
  Required
Debt-to-
Capital
Ratio
  Actual
Debt-to-
Capital
Ratio
 

Genco (a)

  ³1.75(b)  5.8  £60 47

CILCORP(c)

  ³2.2     3.8  £67 39
    

Required

Interest

Coverage

Ratio

  

Actual

Interest

Coverage

Ratio

  

Required

Debt-to-

Capital

Ratio

  

Actual

Debt-to-

Capital

Ratio

 

Genco(a)

  ³1.75(b)  4.9  £60 50

 

(a)Interest coverage ratio relates to covenants regarding certain dividend, principal and interest payments on certain subordinated intercompany borrowings. The debt-to-capital ratio relates to a debt incurrence covenant, which also requires an interest coverage ratio of 2.5 for the most recently ended four fiscal quarters.
(b)Ratio excludes amounts payable under Genco’s intercompany note to CIPS. The ratio must be met both for the prior four fiscal quarters and for the succeeding four six-month periods.
(c)CILCORP must maintain the required interest coverage ratio and debt-to-capital ratio in order to make any payment of dividends or intercompany loans to affiliates other than direct or indirect subsidiaries.

Genco’s debt incurrence-related ratio restrictions and restricted payment limitations under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. Even if CILCORP is not in compliance with these restrictions, CILCORP may still make payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. At September 30, 2009, CILCORP’s senior long-term debt ratings from Moody’s, S&P, and Fitch were Ba1, BB+, and BBB-, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior bonds.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At September 30, 2009,March 31, 2010, 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.

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:

 

    Three Months  Nine Months 
            2009                  2008                  2009                  2008         

Ameren:(a)

     

Miscellaneous income:

     

Interest and dividend income

  $7   $10   $22   $35  

Allowance for equity funds used during construction

   8    8    22    19  

Other

   1    5    5    7  

Total miscellaneous income

  $16   $23   $49   $61  

Miscellaneous expense:

     

Donations

  $(1 $(4 $(5 $(10

Other

   (2  (6  (9  (13

Total miscellaneous expense

  $(3 $(10 $(14 $(23

UE:

     

Miscellaneous income:

     

Interest and dividend income

  $8   $8   $22   $26  

Allowance for equity funds used during construction

   7    8    20    19  

Other

   -    1    1    1  

Total miscellaneous income

  $15   $17   $43   $46  

Miscellaneous expense:

     

Donations

  $-   $-   $(3 $(2

Other

   (2  (2  (3  (4

Total miscellaneous expense

  $(2 $(2 $(6 $(6

CIPS:

     

Miscellaneous income:

     

Interest and dividend income

  $1   $2   $4   $7  

Other

   -    1    2    2  

Total miscellaneous income

  $1   $3   $6   $9  

Miscellaneous expense:

     

Donations

  $-   $-   $(1 $(1

Other

   -    -    -    (1

Total miscellaneous expense

  $-   $-   $(1 $(2

Genco:

     

Miscellaneous income:

     

Other

  $-   $-   $-   $1  

Total miscellaneous income

  $-   $-   $-   $1  

Miscellaneous expense:

     

Other

  $-   $(1 $-   $(1

Total miscellaneous expense

  $-   $(1 $-   $(1

CILCORP:

     

Miscellaneous income:

     

Interest income

  $1   $1   $1   $2  

Total miscellaneous income

  $1   $1   $1   $2  

  Three Months Nine Months   Three Months
          2009                 2008                 2009                 2008                   2010                  2009        

Miscellaneous expense:

     

Donations

  $-   $-   $(1 $(1

Other

   (2  (2  (3  (3

Total miscellaneous expense

  $(2 $(2 $(4 $(4

CILCO:

     

Ameren:(a)

    

Miscellaneous income:

         

Interest income

  $1   $1   $1   $2  

Total miscellaneous income

  $1   $1   $1   $2  

Miscellaneous expense:

     

Donations

  $-   $-   $(1 $(1

Other

   (1  (2  (3  (2

Total miscellaneous expense

  $(1 $(2 $(4 $(3

IP:

     

Miscellaneous income:

     

Interest income

  $-   $-   $-   $4  

Allowance for equity funds used during construction

   1    -    2    -    $13  $6

Interest income on industrial development revenue bonds

   7   7

Interest and dividend income

   1   1

Other

   -    3    1    5     1   2

Total miscellaneous income

  $1   $3   $3   $9    $22  $16

Miscellaneous expense:

         

Donations

  $-   $-   $(1 $(2  $2  $3

Other

   (1  (2  (1  (3   5   1

Total miscellaneous expense

  $(1 $(2 $(2 $(5  $7  $4

UE:

    

Miscellaneous income:

    

Allowance for equity funds used during construction

  $13  $6

Interest income on industrial development revenue bonds

   7   7

Other

   1   -

Total miscellaneous income

  $21  $13

Miscellaneous expense:

    

Donations

  $1  $2

Other

   1   -

Total miscellaneous expense

  $2  $2

CIPS:

    

Miscellaneous income:

    

Interest and dividend income

  $1  $2

Other

   -   1

Total miscellaneous income

  $1  $3

Miscellaneous expense:

    

Other

  $-  $1

Total miscellaneous expense

  $-  $1

Genco:

    

Miscellaneous expense:

    

Other

  $1  $-

Total miscellaneous expense

  $1  $-

CILCO:

    

Miscellaneous expense:

    

Other

  $1  $1

Total miscellaneous expense

  $1  $1

IP:

    

Miscellaneous income:

    

Other

  $1  $1

Total miscellaneous income

  $1  $1

Miscellaneous expense:

    

Other

  $2  $1

Total miscellaneous expense

  $2  $1

 

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

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel,coal, diesel, electricity, uranium, and emission allowances. Such price fluctuations may cause the following:

 

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

 

market values of fuelcoal, natural gas, and natural gasuranium inventories or emission allowances that differ from the cost of those commodities in inventory; and

 

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting

transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

The following table presents open gross derivative volumes by commodity type as of September 30,March 31, 2010, and December 31, 2009:

 

  Quantity (in millions) 
  Quantity   

NPNS

Contracts(a)

  

Cash Flow

Hedges(b)

  

Other

Derivatives(c)

  

Derivatives that Qualify for

Regulatory Deferral(d)

 
Commodity  NPNS
Contracts(a)
 Cash Flow
Hedges(b)
 Other
Derivatives(c)
 Derivatives Subject to
Regulatory Deferral(d)
    
  2010 2009 2010 2009 2010 2009 2010 2009 

Coal (in tons)

              

Ameren(e)

  84,560,000   (f (f (f                  74                 115                 (f               (f               (f               (f (f (f

UE

  47,016,000   (f (f (f  41   81   (f (f (f (f (f (f

Genco

  17,740,000   (f (f (f  17   17   (f (f (f (f (f (f

CILCORP/CILCO

  9,926,000   (f (f (f

CILCO

  7   8   (f (f (f (f (f (f

Natural gas (in mmbtu)

              

Ameren(e)

  182,466,000   (f 155,075,000   126,137,000    149   165   (f (f 55   28   174   136  

UE

  23,660,000   (f 935,000   20,870,000    20   22   (f (f (g 5   25   21  

CIPS

  30,727,000   (f (f 19,593,000    25   28   (f (f (f (f 29   22  

Genco

  (f (f 3,700,000   (f  (f (f (f (f 5   7   (f (f

CILCORP/CILCO

  54,303,000   (f (f 31,135,000  

CILCO

  45   50   (f (f (f (f 46   36  

IP

  73,776,000   (f (f 54,539,000    59   66   (f (f (f (f 74   57  

Heating oil (in gallons)

              

Ameren(e)

  (f (f 181,062,000   51,660,000    (f (f (f (f 83   94   107   117  

UE

  (f (f (f 51,660,000    (f (f (f (f (f (f 107   117  

Genco

  (f (f (f (f 65   73   (f (f

CILCO

  (f (f (f (f 19   21   (f (f

Power (in megawatthours)

              

Ameren(e)

  82,584,000   33,007,000   33,534,000   12,738,000    71   76   29   32   33   22   33   36  

UE

  4,577,000   (f 706,000   5,341,000    3   4   (f (f (g (g 5   4  

CIPS

  (f (f (f 11,521,000    (f (f (f (f (f (f 9   10  

CILCORP/CILCO

  (f (f (f 5,935,000  

Genco

  (f (f (f (f 2   3   (f (f

CILCO

  (f (f (f (f (f (f 5   5  

IP

  (f (f (f 17,456,000    (f (f (f (f (f (f 14   16  

SO2 emission allowances (in tons)

              

Ameren

  (f (f 1,000   (f  (f (f (f (f (g (f (f (f

Genco

  (f (f 1,000   (f  (f (f (f (f (g (f (f (f

CILCO

  (f (f (f (f (g (f (f (f

Uranium (in pounds)

              

Ameren

  (f (f (f 250,000    6   (f (f (f (f (f (g (g

UE

  (f (f (f 250,000    6   (f (f (f (f (f (g (g

 

(a)Contracts through December 2013, March 2015, September 2035, and 2035June 2020 for coal, natural gas, power, and power, respectively.uranium, respectively, as of March 31, 2010.
(b)Contracts through 2011December 2012 for power.power, as of March 31, 2010.
(c)

Contracts through 2009,April 2012, December 2013, December 2013, and 2009December 2010 for natural gas, heating oil, power, and SO2 emission allowances, respectively.respectively, as of March 31, 2010.

(d)Contracts through October 2015, December 2013, 2012,December 2012, and November 2011 for natural gas, heating oil, power, and uranium, respectively.respectively, as of March 31, 2010.
(e)Includes amounts from Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.subsidiaries.
(f)Not applicable.
(g)Less than 1 million.

Authoritative 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 7 - Fair Value Measurements for our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense 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 in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Regulatory assets orand regulatory liabilities are amortized to the statement of income as related losses and gains are reflected in rates charged to customers.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.

The following table presents the carrying value and balance sheet location of all derivative instruments as of September 30,March 31, 2010, and December 31, 2009:

 

  Balance Sheet Location  

 Ameren(a) 

 

      UE      

 

    CIPS    

 

   Genco   

 

CILCORP/

CILCO

                 
IP
   Balance Sheet Location  

Ameren(a)

 

     UE     

 

   CIPS   

 

  Genco  

  CILCO  

      IP      

 
2010:         
Derivative assets designated as hedging instrumentsDerivative assets designated as hedging instruments  

Commodity contracts:

         

Power

  

MTM derivative assets

  $32   $(b)   $(b)   $-   $(b)   $(b)  
  

Other assets

   12    -    -    -    -    -  
  

Total assets

  $44   $-   $-   $-   $-   $-  
Derivative assets not designated as hedging instrumentsDerivative assets not designated as hedging instruments  

Commodity contracts:

         

Natural gas

  

MTM derivative assets

  $16   $(b $(b $1   $(b $(b
  

Other current assets

   -    1    -    -    -    -  
  

Other assets

   2    -    -    -    1    1  

Heating oil

  

MTM derivative assets

   39    (b  (b  13    (b  (b
  

Other current assets

   -    22    -    -    4    -  
  

Other assets

   34    20    -    12    3    -  

Power

  

MTM derivative assets

   146    (b  (b  20    (b  (b
  

Other current assets

   -    16    -    -    -    -  
  

Other assets

   21    2    -    -    -    -  
  

Total assets

  $258   $61   $-   $46   $8   $1  
Derivative liabilities not designated as hedging instrumentsDerivative liabilities not designated as hedging instruments  

Commodity contracts:

         

Natural gas

  

MTM derivative liabilities

  $115   $16   $18   $(b $23   $42  
  

Other current liabilities

   -    -    -    1    -    -  
  

Other deferred credits and liabilities

   85    13    14    2    20    37  

Heating oil

  

MTM derivative liabilities

   14    8    -    (b  1    -  
  

Other current liabilities

   -    -    -    6    -    -  
  

Other deferred credits and liabilities

   5    3    -    1    1    -  

Power

  

MTM derivative liabilities

   123    3    11    (b  6    17  
  

MTM derivative liabilities - affiliates

   (b  (b  64    (b  30    88  
  

Other current liabilities

   -    -    -    17    -    -  
  

Other deferred credits and liabilities

   12    1    111    -    57    169  

Uranium

  

MTM derivative liabilities

   2    2    -    (b  -    -  
  

Other deferred credits and liabilities

   1    1    -    -    -    -  
  

Total liabilities

  $357   $47   $218   $27   $138   $353  
2009:         
Derivative assets designated as hedging instrumentsDerivative assets designated as hedging instruments       Derivative assets designated as hedging instruments  

Commodity contracts:

                  

Power

  

MTM derivative assets

  $43   $-   $(b $(b $(b $(b  

MTM derivative assets

  $20   $(b $(b $-   $(b $(b
  

Other assets

   10    -    -    -    -    -    

Other assets

   4    -    -    -    -    -  
  

Total assets

  $53   $-   $-   $-   $-   $-    

Total assets

  $24   $-   $-   $-   $-   $-  
Derivative liabilities designated as hedging instrumentsDerivative liabilities designated as hedging instruments       Derivative liabilities designated as hedging instruments  

Commodity contracts:

                  

Power

  

MTM derivative liabilities

  $1   $(b $-   $(b $-   $-    

MTM derivative liabilities

  $1   $-   $-   $(b $-   $-  
  

Total liabilities

  $1   $-   $-   $-   $-   $-    

Total liabilities

  $1   $-   $-   $-   $-   $-  
Derivative assets not designated as hedging instrumentsDerivative assets not designated as hedging instruments       Derivative assets not designated as hedging instruments  

Commodity contracts:

                  

Natural gas

  

MTM derivative assets

  $53   $2   $(b $(b $(b $(b  

MTM derivative assets

  $19   $(b $(b $-   $(b $(b
  

Other current assets

   -    -    1    -    3    2    

Other current assets

   -    2    1    -    2    1  
  

Other assets

   12    1    1    -    2    4    

Other assets

   4    -    -    -    1    1  

Heating oil

  

MTM derivative assets

   31    6    (b  (b  (b  (b  

MTM derivative assets

   39    (b  (b  14    (b  (b
  

Other assets

   44    12    -    -    -    -    

Other current assets

   -    22    -    -    4    -  
  

Other assets

   41    23    -    14    4    -  

Power

  

MTM derivative assets

   112    20    (b  (b  (b  (b  

MTM derivative assets

   43    (b  (b  8    (b  (b
  

Other current assets

   -    -    -    -    -    -  
  

Other assets

   17    -    -    -    -    -    

Other assets

   10    7    -    -    -    -  
  

Total assets

  $269   $41   $2   $-   $5   $6    

Total assets

  $156   $54   $1   $36   $11   $2  
Derivative liabilities not designated as hedging instrumentsDerivative liabilities not designated as hedging instruments       Derivative liabilities not designated as hedging instruments  

Commodity contracts:

                  

Natural gas

  

MTM derivative liabilities

  $102   $(b $10   $(b $10   $20    

MTM derivative liabilities

  $55   $10   $8   $(b $7   $17  
  

Other current liabilities

   -    10    -    1    -    -    

Other current liabilities

   -    -    -    1    -    -  
  

Other deferred credits and liabilities

   34    5    6    -    5    14    

Other deferred credits and liabilities

   44    6    8    -    8    19  

Heating oil

  

MTM derivative liabilities

   22    (b  -    (b  -    -    

MTM derivative liabilities

   15    9    -    (b  2    -  
  

Other deferred credits and liabilities

   15    -    -    -    -    -    

Other current liabilities

   -    -    -    5    -    -  
  

Other deferred credits and liabilities

   5    3    -    2    -    -  

Power

  

MTM derivative liabilities

   70    (b  4    (b  2    6    

MTM derivative liabilities

   37    8    2    (b  1    3  
  

MTM derivative liabilities – affiliates

   (b  (b  38    (b  21    58    

MTM derivative liabilities - affiliates

   (b  (b  43    (b  19    65  
  

Other current liabilities

   -    7    -    -    -    -    

Other current liabilities

   -    -    -    7    -    -  
  

Other deferred credits and liabilities

   8    -    105    -    54    159    

Other deferred credits and liabilities

   4    -    95    -    49    145  

Uranium

  

MTM derivative liabilities

   2    (b  -    (b  -    -    

MTM derivative liabilities

   1    1    -    (b  -    -  
  

Other current liabilities

   -    2    -    -    -    -    

Other deferred credits and liabilities

   1    1    -    -    -    -  
  Total liabilities  $253   $24   $163   $1   $92   $257    

Total liabilities

  $162   $38   $156   $15   $86   $249  

 

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

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 September 30,March 31, 2010, and December 31, 2009:

 

    Ameren(a)  UE  CIPS  Genco  

CILCORP/

CILCO

  IP 

Cumulative gains (losses) deferred in accumulated OCI:

       

Power forwards(b)

  $56   $-   $-   $-   $-   $-  

Interest rate swaps(c)(d)

   (10  -    -    (10  -    -  

Cumulative gains (losses) deferred in regulatory assets or liabilities:

       

Natural gas swaps and futures contracts(e)

   (65  (11  (15  -    (10  (28

Financial contracts(f)

   -    14    (146  -    (76  (222

Heating oil options and swaps(g)

   (7  (7  -    -    -    -  

Uranium swaps(h)

   (2  (2  -    -    -    -  
    Ameren(a)      UE         CIPS       Genco     CILCO        IP      

2010:

       

Cumulative gains (losses) deferred in accumulated OCI:

       

Power derivative contracts(b)

  $46   $-   $-   $-   $-   $-  

Interest rate derivative contracts(c)(d)

   (10  -    -    (10  -    -  

Cumulative gains (losses) deferred in regulatory liabilities or assets:

       

Natural gas derivative contracts(e)

   (180  (28  (32  -    (42  (78

Power derivative contracts(f)

   (21  15    (186  -    (93  (274

Heating oil derivative contracts(g)

   6    6    -    -    -    -  

Uranium derivative contracts(h)

   (3  (3  -    -    -    -  

2009:

       

Cumulative gains (losses) deferred in accumulated OCI:

       

Power derivative contracts(b)

  $24   $-   $-   $-   $-   $-  

Interest rate derivative contracts(c)(d)

   (10  -    -    (10  -    -  

Cumulative gains (losses) deferred in regulatory liabilities or assets:

       

Natural gas derivative contracts(e)

   (74  (13  (15  -    (12  (34

Power derivative contracts(f)

   (11  (1  (140  -    (69  (213

Heating oil derivative contracts(g)

   5    5    -    -    -    -  

Uranium derivative contracts(h)

   (2  (2  -    -    -    -  

 

(a)Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)Represents net gains associated with power forwardsderivative contracts at Ameren as of September 30, 2009. The power forwardsAmeren. These contracts are a partial hedge of electricity price exposure through August 2011, including currentDecember 2012 as of March 31, 2010. Current gains of $45$35 million and $22 million were recorded at Ameren as of September 30, 2009.March 31, 2010, and December 31, 2009, respectively.
(c)Includes a gainnet gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period whichthat began in June 2002. The carrying value at September 30,March 31, 2010, and December 31, 2009, was $1 million.million and $1 million, respectively. Over the next twelve months, $0.7 million of the gain will be amortized.
(d)Includes a lossnet 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 whichthat began in April 2008. The carrying value at September 30,March 31, 2010, and December 31, 2009, was a loss of $11 million.million and $11 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e)Represents net losses associated with natural gas swaps and futuresderivative contracts. The swaps and futuresThese contracts are a partial hedge of natural gas requirements through March 2014October 2015 at UE, through October 2014 at CIPS, CILCO, and IP, and through October 2013 at CILCO, in each case as of September 30, 2009.March 31, 2010. Current gains deferred as regulatory liabilities include $2 million, $1 million $3at UE as of March 31, 2010. Current losses deferred as regulatory assets include $16 million, $18 million, $23 million, and $2$42 million at UE, CIPS, CILCO and IP, respectively, as of September 30, 2009.March 31, 2010. Current lossesgains deferred as regulatory assetsliabilities include $10$1 million, $10$1 million, $10$2 million, and $20$1 million at UE, CIPS, CILCO and IP, respectively, as of September 30, 2009.
(f)Represents gains (losses) associated with financial contracts. The financial contracts are a partial hedge of power price exposure through December 2011 at UE and December 2012 at CIPS, CILCO and IP. Current gains deferred as regulatory liabilities include $20 million at UE as of September 30,31, 2009. Current losses deferred as regulatory assets include $8 million, $8 million, $7 million, $42 million, $23 million, and $64$17 million at UE, CIPS, CILCO and IP, respectively, as of September 30,December 31, 2009.
(f)Represents net gains (losses) associated with power derivative contracts. These contracts are a partial hedge of power price requirements through December 2012 at UE, CIPS, CILCO, and IP, in each case as of March 31, 2010. Current gains deferred as regulatory liabilities include $16 million at UE as of March 31, 2010. Current losses deferred as regulatory assets include $3 million, $75 million, $36 million, and $105 million at UE, CIPS, CILCO and IP, respectively, as of March 31, 2010. Current gains deferred as regulatory liabilities include $5 million at UE as of December 31, 2009. Current losses deferred as regulatory assets include $6 million, $45 million, $20 million, and $68 million at UE, CIPS, CILCO and IP, respectively, as of December 31, 2009.

(g)Represents lossesnet gains on heating oil options and swapsderivative contracts at UE. The options and swapsThese contracts are a partial hedge of our transportation costs for coal through December 2013.2013 as of March 31, 2010. Current gains deferred as regulatory liabilities include $2$5 million at UE as of September 30,March 31, 2010. Current losses deferred as regulatory assets include $8 million at UE as of March 31, 2010. Current gains deferred as regulatory liabilities include $5 million at UE as of December 31, 2009. Current losses deferred as regulatory assets include $11$9 million at UE as of September 30,December 31, 2009.
(h)Represents net losses on uranium swapsderivative contracts at UE. The swapsThese contracts are a partial hedge of our uranium requirements through November 2011.2011 as of March 31, 2010. Current losses deferred as regulatory assets include $2 million at UE as of September 30,March 31, 2010. Current losses deferred as regulatory assets include $1 million at UE as of December 31, 2009.

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure reporting to senior management.

We believe that entering into master trading and netting agreements mitigates the level of financial loss resultingthat could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) International Swaps and Derivatives Association agreement, - a standardized financial natural gas and electric contract,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,power; and (3) North American Energy Standards Board Inc. agreement, - a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of September 30,March 31, 2010 and December 31, 2009, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

 

  Affiliates  

Coal

Producers

  

Electric

Utilities

  

Financial

Companies

  

Commodity

Marketing

Companies

  

Municipalities/

Cooperatives

  Oil and Gas
Companies
  

Retail

Companies

  Total   Affiliates(a)  

Coal

Producers

  

Commodity

Marketing

Companies

  

Electric

Utilities

  

Financial

Companies

  

Municipalities/

Cooperatives

  

Oil and Gas

Companies

  

Retail

Companies

      Total     

Ameren(a)

  $622  $6  $37  $147  $23  $203  $11  $80  $1,129   

2010:

                  

Ameren(b)

  $590  $27  $8  $23  $106  $397  $10  $99  $1,260  

UE

   46   4   7   26   1   24   -   -   108     -   19   1   5   28   23   -   -   76  

CIPS

   -   -   -   2   -   -   -   -   2     -   -   -   -   -   -   -   -   -  

Genco

   -   1   1   2   -   -   1   -   5     -   5   1   2   4   -   5   -   17  

CILCORP/CILCO

   -   1   -   6   -   -   -   -   7  

CILCO

   -   3   -   -   1   -   -   -   4  

IP

   -   -   -   6   -   -   1   -   7     -   -   -   -   -   -   1   -   1  

2009:

                  

Ameren(b)

  $517  $9  $16  $23  $123  $165  $11  $63  $927  

UE

   -   5   2   7   30   22   -   -   66  

CIPS

   -   -   -   -   1   -   -   -   1  

Genco

   -   2   1   2   3   -   6   -   14  

CILCO

   -   1   -   -   3   -   -   -   4  

IP

   -   -   -   -   2   -   1   -   3  

 

(a)Primarily comprised of Marketing Company’s exposure to the Ameren Illinois Utilities related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14 - Related Party Transactions in the Form 10-K for additional information on these financial contracts.
(b)Includes amounts for Ameren registrant and nonregistrant subsidiaries.

The following table presents the amount of cash collateral held from counterparties, as of September 30,March 31, 2010, and December 31, 2009, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:

 

    Affiliates  

Coal

Producers

  

Electric

Utilities

  Financial
Companies
  

Commodity
Marketing

Companies

  

Municipalities/

Cooperatives

  

Oil and Gas

Companies

  

Retail

Companies

  Total 

Ameren(a)

  $-  $-  $-  $9  $3  $-  $-  $-  $12   
    Affiliates(a)  

Coal

Producers

  

Commodity

Marketing

Companies

  

Electric

Utilities

  

Financial

Companies

  

Municipalities/

Cooperatives

  

Oil and Gas

Companies

  

Retail

Companies

      Total     

2010:

                  

Ameren(a)

  $-  $-  $-  $-  $6  $5  $-  $-  $11  

2009:

                  

Ameren(a)

  $-  $-  $3  $-  $7  $-  $-  $-  $10  

 

(a)Represents amounts held by Marketing Company. As of September 30,March 31, 2010, and December 31, 2009, Ameren registrant subsidiaries held no cash collateral.

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. OtherAs of March 31, 2010, other collateral consisted of letters of credit in the amount of $40$27 million and $1 million held by Ameren and Genco, respectively. As of December 31, 2009, other collateral consisted of letters of credit in the amount of $32 million, $1 million, and $1 million held by Ameren, UE respectively, as of September 30, 2009.and Genco, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of September 30, 2009:March 31, 2010:

 

  Affiliates  

Coal

Producers

  

Electric

Utilities

  

Financial

Companies

  

Commodity
Marketing

Companies

  

Municipalities/

Cooperatives

  Oil and Gas
Companies
  

Retail

Companies

  Total   Affiliates(a)  

Coal

Producers

  

Commodity
Marketing

Companies

  

Electric

Utilities

  

Financial

Companies

  

Municipalities/

Cooperatives

  Oil and Gas
Companies
  

Retail

Companies

      Total     

Ameren(a)

  $622  $1  $14  $101  $8  $155  $9  $79  $989   

2010:

                  

Ameren(b)

  $587  $-  $3  $8  $72  $366  $8  $98  $1,142  

UE

   46   1   6   22   -   23   -   -   98     -   -   -   4   25   23   -   -   52  

CIPS

   -   -   -   -   -   -   -   -   -     -   -   -   -   -   -   -   -   -  

Genco

   -   -   -   -   -   -   1   -   1     -   -   -   2   -   -   3   -   5  

CILCORP/ CILCO

   -   -   -   2   -   -   -   -   2  

CILCO

   -   -   -   -   -   -   -   -   -  

IP

   -   -   -   -   -   -   -   -   -     -   -   -   -   -   -   1   -   1  

2009:

                  

Ameren(b)

  $515  $-  $3  $11  $93  $132  $10  $61  $825  

UE

   -   -   1   5   26   21   -   -   53  

CIPS

   -   -   -   -   -   -   -   -   -  

Genco

   -   -   -   2   -   -   5   -   7  

CILCO

   -   -   -   -   1   -   -   -   1  

IP

   -   -   -   -   -   -   1   -   1  

 

(a)Primarily comprised of Marketing Company’s exposure to the Ameren Illinois Utilities related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14 - Related Party Transactions in the Form 10-K for additional information on these financial contracts.
(b)Includes amounts for Ameren registrant and nonregistrant subsidiaries.

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 September 30,March 31, 2010, and December 31, 2009, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties, based oncounterparties. The additional collateral required is the net liability position as allowed under the master trading and netting agreements, ifassuming (1) the credit risk-related contingent features underlying these agreements were triggered on September 30,March 31, 2010, or December 31, 2009, and (2) those counterparties with rights to do so requested collateral:

 

  

Aggregate Fair Value of

Derivative Liabilities(a)

  

Cash

Collateral Posted

  Aggregate Amount of Additional
Collateral Required(b)
   

Aggregate Fair Value of

Derivative Liabilities(a)

  

Cash

Collateral Posted

  

Potential Aggregate Amount of Additional

Collateral Required(b)

 

2010:

      

Ameren(c)

  $555  $42  $413    $573  $133  $                         257  

UE

   160   12   157     127   14  89  

CIPS

   39   8   26     48   13  23  

Genco

   62   -   53     46   -  29  

CILCORP/CILCO

   69   3   63  

CILCO

   68   23  43  

IP

   81   17   45     124   56  42  

    

Aggregate Fair Value of

Derivative Liabilities(a)

  

Cash

Collateral Posted

  

Potential Aggregate Amount of Additional

Collateral Required(b)

 

2009:

      

Ameren(c)

  $500  $61  $                                 367  

UE

   151   8  129  

CIPS

   41   3  29  

Genco

   60   -  48  

CILCO

   56   -  44  

IP

   71   11  52  

 

(a)Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b)As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is after consideration of the effects of such agreements.
(c)Includes amounts for Ameren registrant and nonregistrant subsidiaries.

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three months ended September 30,March 31, 2010 and 2009, associated with derivative instruments designated as cash flow hedges:

 

Derivatives in

Cash Flow

Hedging Relationship

  

Amount of

Gain (Loss)

Recognized in OCI

on Derivatives(a)

  

Location of (Gain) Loss

Reclassified from

Accumulated
OCI into Income(b)

  

Amount of

(Gain) Loss

Reclassified from

Accumulated OCI

into Income(b)

 Location of Gain (Loss)
Recognized in Income on
Derivatives(c)
  

Amount of Gain
(Loss) Recognized

in Income on

Derivatives(c)

  

Amount of

Gain (Loss)

Recognized in OCI

on Derivatives(a)

 

Location of

(Gain) Loss

Reclassified

from

Accumulated

OCI into

Income(b)

 

Amount of

(Gain) Loss

Reclassified from

Accumulated OCI

into Income(b)

 

Location of Gain (Loss)

Recognized in Income on

Derivatives(c)

 

Amount of Gain

(Loss) Recognized

in Income on

Derivatives(c)

 

2010:

     

Ameren:(d)

              

Power

  $7  Operating Revenues - Electric  $(19 Operating Revenues - Electric  $(4 $                26   

Operating Revenues - Electric

 $                  (4 

Operating Revenues - Electric

 $                -  

Interest rate(e)

   -  Interest Charges   (f Interest Charges   -   -   

Interest Charges

 (f 

Interest Charges

 -  

Genco:

              

Interest rate(e)

   -  Interest Charges   (f Interest Charges   -   -   

Interest Charges

 (f 

Interest Charges

 -  

2009:

     

Ameren:(d)

     

Power

 $                46   

Operating Revenues - Electric

 $                (40 

Operating Revenues - Electric

 $           (12

Interest rate(e)

 -   

Interest Charges

 (f 

Interest Charges

 -  

UE:

     

Power

 (20 

Operating Revenues - Electric

 (19 

Operating Revenues - Electric

 2  

Genco:

     

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 from 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.

The following table presents the pretax net gain or loss for the nine months ended September 30, 2009, associated with derivative instruments designated as cash flow hedges:

Derivatives in

Cash Flow

Hedging Relationship

  

Amount of

Gain (Loss)

Recognized in OCI

on Derivatives(a)

  

Location of (Gain) Loss

Reclassified from

Accumulated

OCI into Income(b)

  

Amount of

(Gain) Loss

Reclassified from

Accumulated OCI

into Income(b)

  Location of Gain (Loss)
Recognized in Income on
Derivatives(c)
  

Amount of Gain
(Loss) Recognized

in Income on

Derivatives(c)

 

Ameren:(d)

        

Power

  $54   Operating Revenues - Electric  $(82 Operating Revenues - Electric  $(20

Interest rate(e)

   -   Interest Charges   (f Interest Charges   -  

UE:

        

Power

   (21 

Operating Revenues -

Electric - off-system

   (19 

Operating Revenues -

Electric - off-system

   2  

Genco:

        

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 from Ameren registrants 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.

See Note 11 - Other Comprehensive Income for additional information regarding changes in OCI.

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three months ended September 30,March 31, 2010 and 2009:

 

    

Derivatives Not Designated

as Hedging Instruments

  

Location of Gain (Loss)

Recognized in Income on

Derivatives

  

Amount of Gain (Loss)

Recognized in Income on

Derivatives

 

Ameren(a)                  

  

Natural gas (generation)

  

Operating Expenses - Fuel

  $1  
  

Heating oil

  

Operating Expenses - Fuel

   (1
   

Power

  

Operating Revenues - Electric

   (26
      Total  $(26

UE

  

Natural gas (generation)

  

Operating Expenses - Fuel

  $(1

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

The following table represents the net change in market value for derivatives not designated as hedging instruments for the nine months ended September 30, 2009:
    

Derivatives Not Designated

as Hedging Instruments

  

Location of Gain (Loss)

Recognized in Income on

Derivatives

  

Amount of Gain (Loss)

Recognized in Income on

Derivatives

 

2010:

      

Ameren(a)

  

Heating oil

  

Operating Expenses - Fuel

  $1  
  

Natural gas (generation)

  

Operating Expenses - Fuel

   (1
   

Power

  

Operating Revenues - Electric

   31  
      

Total

  $31  

UE

  

Natural gas (generation)

  

Operating Expenses - Fuel

  $1  
   

Power

  

Operating Revenues - Electric

   (1
      

Total

  $-  

Genco

  

Heating oil

  

Operating Expenses - Fuel

  $1  
  

Natural gas (generation)

  

Operating Expenses - Fuel

   (1
   

Power

  

Operating Revenues

   1  
      

Total

  $1  

  

Derivatives Not Designated

as Hedging Instruments

  

Location of Gain (Loss)

Recognized in Income on

Derivatives

  

Amount of Gain (Loss)

Recognized in Income on

Derivatives

   

Derivatives Not Designated

as Hedging Instruments

  

Location of Gain (Loss)

Recognized in Income on

Derivatives

  

Amount of Gain (Loss)

Recognized in Income on

Derivatives

 

2009:

      

Ameren(a)

  

Natural gas (generation)

  

Operating Expenses - Fuel

  $5    

Heating oil

  

Operating Expenses - Fuel

  $24  
  

Natural gas (generation)

  

Operating Expenses - Fuel

   3  
  

Heating oil

  

Operating Expenses - Fuel

   38    

Natural gas (resale)

  

Operating Revenues - Gas

   2  
  

Power

  

Operating Revenues - Electric

   3    

Power

  

Operating Revenues - Electric

   34  
     Total  $46       

Total

  $63  

UE

  

Natural gas (generation)

  

Operating Expenses - Fuel

  $3    

Heating oil

  

Operating Expenses - Fuel

  $25  
  

Heating oil

  

Operating Expenses - Fuel

   25    

Natural gas (generation)

  

Operating Expenses - Fuel

   4  
  

Power

  

Operating Revenues - Electric - excluding off-system

   (2  

Power

  

Operating Revenues - Electric

   (1
  

Power

  

Operating Revenues - Electric - off-system

   1       

Total

  $28  

Genco

  Heating oil  Operating Expenses - Fuel  $(2
     Total  $27    Natural gas (generation)  Operating Expenses - Fuel   (1

Genco

  

Heating oil

  

Operating Expenses - Fuel

  $8  

CILCORP/CILCO

  

Heating oil

  

Operating Expenses - Fuel

  $3  
  Power  Operating Revenues   2  
     

Total

  $(1

CILCO

  

Natural gas (resale)

  

Operating Revenues - Gas

  $2  

 

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

Derivatives Subject tothat Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three months ended September 30,March 31, 2010 and 2009:

 

  Derivatives Subject to Regulatory Deferral  

Amount of Gain

(Loss) Recognized in
Regulatory Assets or
Regulatory Liabilities
on Derivatives

   Derivatives that Qualify for Regulatory Deferral  

Amount of Gain

(Loss) Recognized in

Regulatory Liabilities or

Regulatory Assets

on Derivatives

 

2010:

    

Ameren(a)

  

Natural gas

  $63    

Heating oil

  $1  
  

Heating oil

   (1  

Natural gas

   (106
  

Power

   (17  

Power

   (10
  

Uranium

   (2  

Uranium

   (1
  

Total

  $43    

Total

  $(116

UE

  

Natural gas

  $10    

Heating oil

  $1  
  

Heating oil

   (1  

Natural gas

   (15
  

Power

   (7  

Power

   16  
  

Uranium

   (2  

Uranium

   (1
  

Total

  $-    

Total

  $1  

CIPS

  

Natural gas

  $12    

Natural gas

  $(17
  

Power

   (20  

Power

   (46
  

Total

  $(8  

Total

  $(63

CILCORP/CILCO

  

Natural gas

  $16  

CILCO

  

Natural gas

  $(30
  

Power

   (13  

Power

   (24
  

Total

  $3    

Total

  $(54

IP

  

Natural gas

  $25    

Natural gas

  $(44
  

Power

   (40  

Power

   (61
  

Total

  $(15  

Total

  $(105

2009:

    

Ameren(a)

  

Heating oil

  $(27
  

Natural gas

   (84
  

Power

   38  
  

Total

  $(73

UE

  

Heating oil

  $(27
  

Natural gas

   (15
  

Power

   38  
  

Total

   (4

CIPS

  

Natural gas

  $(13
  

Power

   (73
  

Total

  $(86

CILCO

  

Natural gas

  $(19
  

Power

   (36
  

Total

  $(55

IP

  

Natural gas

  $(37
  

Power

   (106
  

Total

  $(143

 

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

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the nine months ended September 30, 2009:

    Derivatives Subject to Regulatory Deferral  

Amount of Gain

(Loss) Recognized in
Regulatory Assets or
Regulatory Liabilities
on Derivatives

 

Ameren(a)                  

  

Natural gas

  $53  
  

Heating oil

   (6
  

Power

   (1
   

Uranium

   (2
   

Total

  $44  

UE

  

Natural gas

  $4  
  

Heating oil

   (6
  

Power

   14  
   

Uranium

   (2
   

Total

  $10  

CIPS

  

Natural gas

  $13  
   

Power

   (90
   

Total

  $(77

CILCORP/CILCO

  

Natural gas

  $15  
   

Power

   (47
   

Total

  $(32

IP

  

Natural gas

  $21  
   

Power

   (137
   

Total

  $(116

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

UE, CIPS, CILCO and IP believe gains and losses on derivatives deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating expenses as related losses and gains are reflected in revenue through rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.

As part of the electric rate order issued by2007 Illinois Electric Settlement Agreement and the MoPSC in January 2009 UE was granted permission to implement a FAC, which was effective March 1, 2009. UE utilizes derivatives to mitigate its exposure to changing prices of fuel for generation and related transportation costs, and for power price volatility. In connection with the MoPSC’s approval of the FAC, gains and losses associated with these types of derivatives are considered refundable to, or recoverable from, customers and, thus, represent regulatory liabilities or regulatory assets, respectively. During the first quarter of 2009, UE recorded a net regulatory liability of $5 million associated with the reclassification of unrealized gains and losses previously recorded in accumulated OCI and earnings related to open UE derivative positions with delivery dates subsequent to March 1, 2009. The reclassification of previously recorded unrealized gains associated with the derivatives resulted in a $47 million reduction of accumulated OCI. The reclassification of previously recognized unrealized losses resulted in a $42 million increase in pretax earnings, of which $38 million offset fuel expense and $4 million increased operating revenues. See Note 2 - Rate and Regulatory Matters for additional information on the FAC.

As part of the Illinois electric settlement agreement,RFP process, the Ameren Illinois Utilities entered into financial contracts with Marketing Company. These financial contracts are derivative instruments beinginstruments. They are accounted for as cash flow hedges atby Marketing Company while they are being accounted forand as derivatives subject to regulatory deferral atby the Ameren Illinois Utilities. Consequently, the Ameren Illinois Utilities and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes

to the fair value in regulatory assets or liabilities forby the Ameren Illinois Utilities and OCI atby Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the derivative instruments are eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts.

NOTE 7 - FAIR VALUE MEASUREMENTS

The Ameren Companies adopted authoritative accounting guidance for fair value measurements as of the beginning of their 2008 fiscal year for financial assets and liabilities and as of the beginning of their 2009 fiscal year for nonfinancial assets and liabilities, except those already reported at fair value on a recurring basis. The impact of the adoption of this guidance for financial assets and liabilities at January 1, 2008, and for nonfinancial assets and liabilities at January 1, 2009, was not material. 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 the 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. TheAuthoritative accounting guidance also establishesestablished 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 include exchange-traded derivatives and assets, including U.S. treasury securities and listed equity securities, such as those held in UE’s Nuclear Decommissioning Trust Fund.

Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in UE’s Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, and certain over-the-counter derivative instruments, including natural gas swaps and financial power transactions. Derivative instruments classified as Level 2 are valued using corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between the Ameren Illinois Utilities and Marketing Company as part of the Illinois electric settlement agreement.Company. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, a reviewan evaluation of all sources is performed to identify any anomalies or potential errors.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

WeIn accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded $2losses totaling less than $1 million in losses in the thirdfirst quarter of 20092010 related to valuation adjustments for counterparty default risk. At September 30, 2009,March 31, 2010, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $1$3 million, $- million, $12$3 million, $- million, $5 million, and $17$14 million for Ameren, UE, CIPS, Genco, CILCORP/CILCO and IP, 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 September 30, 2009:March 31, 2010:

 

  

Quoted Prices in

Active Markets for
Identified Assets

(Level 1)

  

Significant Other
Observable Inputs

(Level 2)

  

Significant Other

Unobservable Inputs

(Level 3)

  Total   

Quoted Prices in

Active Markets for
Identified Assets

(Level 1)

  

Significant Other
Observable Inputs

(Level 2)

  

Significant Other

Unobservable Inputs

(Level 3)

  Total 

Assets:

                    

Ameren(a)

  

Other current assets

  $-  $-  $2  $2    

Derivative assets - commodity contracts(b):

        
  

Derivative assets(b)

   47   60   215   322    

Heating oil

  $-  $-  $73  $73 
  

Nuclear Decommissioning Trust Fund(c)

   224   53   2   279    

Natural gas

   15   -   3   18 
  

Power

   11   56   144   211 
  

Nuclear Decommissioning Trust Fund(c):

        
  

Equity securities:

        
  

U.S. large capitalization

   202   -   -   202 
  

Debt securities:

        
  

Corporate bonds

   -   42   -   42 
  

Municipal bonds

   -   1   -   
  

U.S. treasury and agency securities

   40   14   -   54 
  

Asset-backed securities

   -   6   -   
  

Other

   -   1   -   

UE

  

Derivative assets

   -   8   33   41    

Derivative assets - commodity contracts(b):

        
  

Nuclear Decommissioning Trust Fund(c)

   224   53   2   279    

Heating oil

   -   -   42   42 

CIPS

  

Derivative assets(b)

   -   -   2   2  
  

Natural gas

   -   -   1   
  

Power

   -   11   7   18 
  

Nuclear Decommissioning Trust Fund(c):

        
  

Equity securities:

        
  

U.S. large capitalization

   202   -   -   202 
  

Debt securities:

        
  

Corporate bonds

   -   42   -   42 
  

Municipal bonds

   -   1   -   
  

U.S. treasury and agency securities

   40   14   -   54 
  

Asset-backed securities

   -   6   -   
  

Other

   -   1   -   

Genco

  

Derivative assets(b)

   -   -   -   -    

Derivative assets - commodity contracts(b):

        

CILCORP/CILCO

  

Derivative assets(b)

   -   -   5   5  
  

Heating oil

   -   -   25   25 
  

Natural gas

   1   -   -   
  

Power

   -   -   20   20 

CILCO

  

Derivative assets - commodity contracts(b):

        
  

Heating oil

   -   -   7   
  

Natural gas

   -   -   1   

IP

  

Derivative assets(b)

   1   -   5   6    

Derivative assets - commodity contracts(b):

        
  

Natural gas

   -   -   1   

Liabilities:

                    

Ameren(a)

  

Derivative liabilities(b)

  $60  $30  $164  $254    

Derivative liabilities - commodity contracts(b):

        
  

Heating oil

  $-  $-  $19  $19 
  

Natural gas

   35   -   165   200 
  

Power

   1   27   107   135 
  

Uranium

   -   -   3   

UE

  

Derivative liabilities(b)

   5   3   16   24    

Derivative liabilities - commodity contracts(b):

        
  

Heating oil

   -   -   11   11 
  

Natural gas

   10   -   19   29 
  

Power

   -   2   2   
  

Uranium

   -   -   3   

CIPS

  

Derivative liabilities(b)

   1   -   162   163    

Derivative liabilities - commodity contracts(b):

        
  

Natural gas

   1   -   31   32 
  

Power

   -   -   186   186 

Genco

  

Derivative liabilities(b)

   -   -   1   1    

Derivative liabilities - commodity contracts(b):

        

CILCORP/CILCO

  

Derivative liabilities(b)

   -   -   92   92  
  

Heating oil

   -   -   7   
  

Natural gas

   3   -   -   
  

Power

   -   -   17   17 

CILCO

  

Derivative liabilities - commodity contracts(b):

        
  

Heating oil

   -   -   2   
  

Natural gas

   2   -   40   42 
  

Power

   -   -   94   94 

IP

  

Derivative liabilities(b)

   -   -   257   257    

Derivative liabilities - commodity contracts(b):

        
  

Natural gas

   5   -   74   79 
  

Power

   -   -   274           274 

(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.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2008:2009:

 

  

Quoted Prices in

Active Markets for
Identified Assets

(Level 1)

  

Significant Other
Observable Inputs

(Level 2)

  

Significant Other

Unobservable Inputs

(Level 3)

  Total   

Quoted Prices in

Active Markets for
Identified Assets

(Level 1)

  

Significant Other
Observable Inputs

(Level 2)

  

Significant Other

Unobservable Inputs

(Level 3)

  Total 

Assets:

                    

Ameren(a)

  

Other current assets

  $-  $-  $6  $6    

Derivative assets - commodity contracts(b):

        
  

Derivative assets(b)

   1   19   234   254    

Heating oil

  $-  $-  $80  $80 
  

Nuclear Decommissioning Trust Fund(c)

   164   81   2   247    

Natural gas

   13   -   10   23 
  

Power

   -   3   74   77 
  

Nuclear Decommissioning Trust Fund(c):

        
  

Equity securities:

        
  

U.S. large capitalization

   195   -   -   195 
  

Debt securities:

        
  

Corporate bonds

   -   45   -   45 
  

Municipal bonds

   -   1   -   
  

U.S. treasury and agency securities

   37   12   -   49 
  

Other

   -   2   -   

UE

  

Derivative assets

   -   14   36   50    

Derivative assets - commodity contracts(b):

        
  

Nuclear Decommissioning Trust Fund(c)

   164   81   2   247    

Heating oil

   -   -   44   44 
  

Natural gas

   1   -   2   
  

Power

   -   2   5   
  

Nuclear Decommissioning Trust Fund(c):

        
  

Equity securities:

        
  

U.S. large capitalization

   195   -   -   195 
  

Debt securities:

        
  

Corporate bonds

   -   45   -   45 
  

Municipal bonds

   -   1   -   
  

U.S. treasury and agency securities

   37   12   -   49 
  

Other

   -   2   -   

CIPS

  

Derivative assets(b)

   -   -   -   -    

Derivative assets - commodity contracts(b):

        
  

Natural gas

   -   -   1   1

Genco

  

Derivative assets(b)

   -   -   -   -    

Derivative assets - commodity contracts(b):

        

CILCORP/CILCO

  

Derivative assets(b)

   -   -   -   -  
  

Heating oil

   -   -   28   28 
  

Power

   -   -   8   

CILCO

  

Derivative assets - commodity contracts(b):

        
  

Heating oil

   -   -   8   
  

Natural gas

   -   -   3   

IP

  

Derivative assets(b)

   -   -   -   -    

Derivative assets - commodity contracts(b):

        
  

Natural gas

   -   -   2   

Liabilities:

                    

Ameren(a)

  

Derivative liabilities(b)

  $9  $6  $219  $234    

Derivative liabilities - commodity contracts(b):

        
  

Heating oil

  $-  $-  $20  $20 
  

Natural gas

   22   -   77   99 
  

Power

   4   2   36   42 
  

Uranium

   -   -   2   

UE

  

Derivative liabilities(b)

   -   3   31   34    

Derivative liabilities - commodity contracts(b):

        
  

Heating oil

   -   -   12   12 
  

Natural gas

   8   -   8   16 
  

Power

   -   2   6   
  

Uranium

   -   -   2   

CIPS

  

Derivative liabilities(b)

   -   -   84   84    

Derivative liabilities - commodity contracts(b):

        
  

Natural gas

   -   -   16   16 
  

Power

   -   -   140   140 

Genco

  

Derivative liabilities(b)

   -   -   1   1    

Derivative liabilities - commodity contracts(b):

        

CILCORP/CILCO

  

Derivative liabilities(b)

   4   -   55   59  
  

Heating oil

   -   -   7   
  

Natural gas

   1   -   -   
  

Power

   -   -   7   

CILCO

  

Derivative liabilities - commodity contracts(b):

        
  

Heating oil

   -   -   2   
  

Natural gas

   -   -   15   15 
  

Power

   -   -   69   69 

IP

  

Derivative liabilities(b)

   -   -   134   134    

Derivative liabilities - commodity contracts(b):

        
  

Natural gas

   1   -   36   37 
  

Power

   -   -   212           212 

(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 ($8)$1 million of receivables, payables, and accrued income, net.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended September 30, 2009:March 31, 2010:

 

          Realized and Unrealized Gains (Losses)  Total
Realized
  Purchases,          

Change in
Unrealized
Gains (Losses)

Related to

 
      Beginning
Balance at
July 1,
2009
  Included in
Earnings(a)
  

Included

in AOCI

 Included in
Regulatory
Assets/
Liabilities
  and
Unrealized
Gains
(Losses)
  Issuances,
and Other
Settlements,
Net
  Net
Transfers
Into (Out of)
Level 3
  Ending
Balance at
September 30,
2009
  Assets/Liabilities
Still Held at
September 30,
2009
 

Other current

assets

 

Ameren

 $2   $-   $- $-   $-   $-   $-   $2   $-  

Net derivative

 

Ameren

 $25   $13   $4 $(14 $3   $27   $(4 $51   $(29

contracts

 

UE

  13    -    -  7    7    (3  -    17    9  
 

CIPS

  (153  -    -  (40  (40  33    -    (160  (31
 

Genco

  (1  -    -  -    -    -    -    (1  -  
 

CILCORP/CILCO

  (89  (1  -  (23  (24  26    -    (87  (18
  

IP

  (236  -    -  (71  (71  55    -    (252  (58

Nuclear

 

Ameren

 $3   $-   $- $-   $-   $(1 $-   $2   $-  

Decommissioning

Trust Fund

 

UE

  3    -    -  -    -    (1  -    2    -  

(a)See Note 6 - Derivative Financial Instruments for additional information on the recording of net gains and losses on derivatives to the statement of income.
            Realized and Unrealized Gains (Losses)  Total
Realized
  Purchases,          Change in
Unrealized
Gains (Losses)
 
        Beginning
Balance at
January 1,
2010
  Included in
Earnings(a)
  Included
in OCI
  Included in
Regulatory
Assets/
Liabilities
  and
Unrealized
Gains
(Losses)
  Issuances,
and Other
Settlements,
Net
  Transfers
out of
Level 3
  Ending
Balance at
March 31,
2010
  Related to
Assets/Liabilities
Still Held at
March 31, 2010
 

Net derivative

  

Ameren:

           

commodity

  

Heating oil

  $59   $(1 $-  $(2 $(3 $(2 $-   $54   $-  

contracts

  

Natural gas

   (70  1    -   (101  (100  8    -    (162  (94
  

Power

   42    17    23   (23  17    (4  (18  37    (6
  

Uranium

   (2  -    -   (1  (1  -    -    (3  (1
  

UE:

           
  

Heating oil

   33    -    -   (2  (2  -    -    31    (1
  

Natural gas

   (7  -    -   (12  (12  1    -    (18  (12
  

Power

   (1  -    -   12    12    (3  (3  5    6  
  

Uranium

   (2  -    -   (1  (1  -    -    (3  (1
  

CIPS:

           
  

Natural gas

   (15  -    -   (17  (17  1    -    (31  (16
  

Power

   (140  -    -   (57  (57  11    -    (186  (57
  

Genco:

           
  

Heating oil

   19    -    -   -    -    (1  -    18    1  
  

Natural gas

   -    1    -   -    1    (1  -    -    -  
  

Power

   2    1    -   -    1    -    -    3    1  
  

CILCO:

           
  

Heating oil

   6    (1  -   -    (1  -    -    5    -  
  

Natural gas

   (13  -    -   (27  (27  1    -    (39  (26
  

Power

   (68  -    -   (32  (32  6    -    (94  (31
  

IP:

           
  

Natural gas

   (34  -    -   (45  (45  6    -    (73  (42
   

Power

   (212  -    -   (79  (79  17    -    (274  (78

(a)    See Note 6 - Derivative Financial Instruments for additional information on the recording of net gains and losses on derivatives to the statement of income.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2009:

 

       

   

            Realized and Unrealized Gains (Losses)  Total
Realized
  Purchases,          Change in
Unrealized
Gains (Losses)
 
        Beginning
Balance at
January 1,
2009
  Included  in
Earnings(a)
  Included
in OCI
  Included in
Regulatory
Assets/
Liabilities
  and
Unrealized
Gains
(Losses)
  Issuances,
and Other
Settlements,
Net
  Transfers
out of
Level 3
  Ending
Balance at
March 31,
2009
  Related to
Assets/Liabilities
Still Held at
March 31, 2009
 

Other current

  

Ameren:

           

assets

  

Mutual fund

  $6   $-   $-  $-   $-   $-   $(4 $2   $-  

Net derivative

  

Ameren:

           

commodity

  

Heating oil

  $6   $(2 $-  $7   $5   $(2 $-   $9   $(4

contracts

  

Natural gas

   (122  (25  12   (96  (109  28    -    (203  (92
  

Power

   134    44    69   6    119    (41  (11  201    91  
   

SO2

   (1  -    -   -    -    -    -    (1  (1

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2009:

       Realized and Unrealized Gains (Losses)  Total
Realized
 Purchases,       Change in
Unrealized
Gains (Losses)
Related to
 
    Beginning
Balance at
January 1,
2009
 Included in
Earnings(a)
 

Included

in AOCI

 Included in
Regulatory
Assets/
Liabilities
 and
Unrealized
Gains
(Losses)
 Issuances,
and Other
Settlements,
Net
 Net
Transfers
Into (Out of)
Level 3
 Ending
Balance at
September 30,
2009
 Assets/Liabilities
Still Held at
September 30,
2009
 

Other current

assets

 

Ameren

 $ $-   $-   $-   $-   $-   $(4 $2   $-  

Net derivative

 

Ameren

 $15  $66   $61   $(67 $60   $34   $(58 $51   $20  

contracts

 

UE

    -    37    4    41    (11  (18  17    5  
 

CIPS

  (84)  -    (10  (148  (158  82    -    (160  (102
 

Genco

  (1)  (1  -    -    (1  1    -    (1  -        Realized and Unrealized Gains (Losses)  Total
Realized
 Purchases,       Change in
Unrealized
Gains (Losses)
 
 

CILCORP/CILCO

  (55)  (20  (5  (70  (95  63    -    (87  (58  Beginning
Balance at
January 1,
2009
 Included  in
Earnings(a)
 Included
in OCI
  Included in
Regulatory
Assets/
Liabilities
 and
Unrealized
Gains
(Losses)
 Issuances,
and Other
Settlements,
Net
 Transfers
out of
Level 3
 Ending
Balance at
March 31,
2009
 Related to
Assets/Liabilities
Still Held at
March 31, 2009
 
 

IP

  (134)  -    (16  (237  (253  135    -    (252  (166  

UE:

           
  

Heating oil

  $-   $-   $-  $7   $7   $(1 $-   $6   $-  
  

Natural gas

   (20  -    12   (27  (15  4    -    (31  (14
  

Power

   27    -    20   4    24    (14  (13  24    12  
  

CIPS:

           
  

Natural gas

   (28  -    -   (20  (20  7    -    (41  (17
  

Power

   (56  -    -   (84  (84  11    -    (129  (80
  

Genco:

           
  

Natural gas

   -    -    -   -    -    (1  -    (1  -  
  

Power

   -    -    -   -    -    2    -    2    -  
  

SO2

   (1  -    -   -    -    -    -    (1  (1
  

CILCO:

           
  

Natural gas

   (26  (24  -   -    (24  7    -    (43  (22
  

Power

   (29  -    -   (42  (42  6    -    (65  (39
  

IP:

           
  

Natural gas

   (49  -    -   (48  (48  10    -    (87  (39
  

Power

   (85  -    -   (123  (123  18    -    (190  (116

Net derivative

  

Ameren

  $(2 $-   $-  $(3 $(3 $-   $-   $(5 $(3

foreign currency

             

contracts

  

UE

   (2  -    -   (3  (3  -    -    (5  (3

Nuclear

 

Ameren

 $ $-   $-   $-   $-   $-   $-   $2   $-    

Ameren:

           

Decommissioning

Trust Fund

 

UE

    -    -    -    -    -    -    2    -  

Decommissioning

  

Mutual fund

  $2   $-   $-  $-   $-   $(2 $-   $-   $-  

Trust Fund

  

UE:

           
  Mutual fund   2    -    -   -    -    (2  -    -    -  

 

(a)See Note 6 - Derivative Financial Instruments for additional information on the recording of net gains and losses on derivatives to the statement of income.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended September 30, 2008:

         Realized and Unrealized Gains (Losses)  Total
Realized
  Purchases,         Change in
Unrealized
Gains (Losses)
Related to
 
      Beginning
Balance at
July 1,
2008
 Included in
Earnings
  

Included

in AOCI

 Included in
Regulatory
Assets/
Liabilities
  and
Unrealized
Gains
(Losses)
  Issuances,
and Other
Settlements,
Net
  Net
Transfers
Into (Out of)
Level 3
 Ending
Balance at
September 30,
2008
  Assets/Liabilities
Still Held at
September 30,
2008
 

Other current

assets

 

Ameren

 $- $-   $- $-   $-   $-   $16 $16   $-  

Net derivative

 

Ameren

 $202 $(66 $64 $(161 $(163 $(33 $35 $41   $(252

Contracts

 

UE

  40  (4  2  (2  (4  (26  11  21    6  
 

CIPS

  112  (1  -  (115  (116  (8  -  (12  (31
 

Genco

  4  (5  -  -    (5  -    -  (1  (4
 

CILCORP/CILCO

  77  (6  -  (72  (78  (7  -  (8  (34
  

IP

  195  (1  -  (208  (209  (5  -  (19  (77

Nuclear

 

Ameren

 $1 $-   $- $-   $-   $(a $- $1   $-  

Decommissioning

Trust Fund

 

UE

  1  -    -  -    -    (a  -  1    -  

(a)Less than $1 million.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2008:

         Realized and Unrealized Gains (Losses)  Total
Realized
  Purchases,         Change in
Unrealized
Gains (Losses)
Related to
 
      Beginning
Balance at
January 1,
2008
 Included in
Earnings
  

Included

in AOCI

 Included in
Regulatory
Assets/
Liabilities
  and
Unrealized
Gains
(Losses)
  Issuances,
and Other
Settlements,
Net
  Net
Transfers
Into (Out of)
Level 3
 Ending
Balance at
September 30,
2008
  Assets/Liabilities
Still Held at
September 30,
2008
 

Other current

assets

 

Ameren

 $- $-   $- $-   $-   $-   $16 $16   $-  

Net derivative

 

Ameren

 $19 $26   $5 $17   $48   $(50 $24 $41   $10  

contracts

 

UE

  3  7    12  17    36    (30  12  21    10  
 

CIPS

  38  -    -  (41  (41  (9  -  (12  (36
 

Genco

  1  (1  -  -    (1  (1  -  (1  -  
 

CILCORP/CILCO

  21  (7  -  (10  (17  (12  -  (8  (21
  

IP

  55  (1  -  (67  (68  (6  -  (19  (59

Nuclear

 

Ameren

 $5 $-   $- $-   $-   $(4 $- $1   $-  

Decommissioning

Trust Fund

 

UE

  5  -    -  -    -    (4  -  1    -  

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 betweeninto Level 2 andfrom Level 3 were primarily caused by changes in availability of financial power trades observable on electronic exchanges compared with previous periods for the quarters ended September 30, 2009March 31, 2010 and 2008.2009. Any reclassifications are reported as transfers in or out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.

Related to our nonfinancial assets For the quarters ended March 31, 2010 and liabilities, Note 14 - Goodwill Impairment details the inputs to the valuation2009, there were no transfers into or out of goodwill, which is considered a Level 3 asset, and the goodwill impairment charge recorded by CILCORP in 2009. CILCORP’s goodwill is measured at fair value on a nonrecurring basis and was impaired during the first quarter1, out of 2009. The following table sets forth, by level within the fair value hierarchy, CILCORP’s goodwill as of September 30, 2009:Level 2, nor into Level 3.

        

Quoted Prices in

Active Markets for
Identified Assets

(Level 1)

  

Significant Other
Observable Inputs

(Level 2)

  

Significant Other

Unobservable Inputs

(Level 3)

  Total  Total Loss 

CILCORP

  

Goodwill(a)

  $-  $-  $80  $80  $(462

(a)CILCORP’s goodwill with a carrying amount of $542 million was written down to its implied fair value of $80 million at March 31, 2009, resulting in an impairment charge of $462 million.

The Ameren Companies’ carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at September 30, 2009,March 31, 2010, and December 31, 2008:2009:

 

  September 30, 2009  December 31, 2008  March 31, 2010  December 31, 2009
  Carrying Amount  Fair Value  Carrying Amount  Fair Value  Carrying Amount  Fair Value  Carrying Amount  Fair Value 

Ameren:(a)(b)

                

Long-term debt and capital lease obligations (including current portion)

  $7,449  $7,908   $6,934  $6,144   $7,317  $7,849  $7,317  $7,719 

Preferred stock

   195   136    195   100    195   152   195   150 

UE:

                

Long-term debt and capital lease obligations (including current portion)

  $4,026  $4,219   $3,677  $3,156   $4,022  $4,213  $4,022  $4,152 

Preferred stock

   113   86    113   62    113   97   113   95 

CIPS:

                

Long-term debt (including current portion)

  $421  $438   $421  $371   $421  $436  $421  $436 

Preferred stock

   50   29    50   22    50   31   50   31 

Genco:

                

Long-term debt (including current portion)

  $774  $808   $774  $661   $1,023  $1,069  $1,023  $1,046 

CILCORP:

        

Long-term debt (including current portion)

  $658  $655   $662  $630 

Preferred stock

   19   14    19   10 

CILCO:

                

Long-term debt (including current portion)

  $279  $309   $279  $255   $279  $313  $279  $311 

Preferred stock

   19   14    19   10    19   15   19   15 

IP:

                

Long-term debt (including current portion)

  $1,146  $1,312  $1,400  $1,326   $1,147  $1,327  $1,147  $1,295 

Preferred stock

   46   32    46   24    46   35   46   35 

 

(a)Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)Preferred stock along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.

NOTE 8 - RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K.

Illinois Electric Settlement Agreement

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over four years as part of a comprehensive program providing approximately $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities.

At September 30, 2009, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of $1 million, less than $1 million, and $1 million, respectively. Also at September 30, 2009, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of less than $1 million each. During the three and nine months ended September 30, 2009, Genco incurred charges to earnings of $2 million and $7 million, respectively, for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS - $1 million and $3 million, CILCO - less than $1 million and $1 million, IP - $1 million and $3 million, respectively), and AERG incurred charges to earnings of $1 million and $3 million, respectively (CIPS - less than $1 million and $1 million, CILCO - less than $1 million and $1 million, IP - less than $1 million and $1 million, respectively). The Ameren Illinois Utilities recorded most of the reimbursements received from Genco and AERG as electric revenue with an immaterial amount recorded as miscellaneous revenue.

Electric Power Supply Agreements

The following table presents the amount of physical gigawatthour sales under related party electric power supply agreements for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:

 

  Three Months  Nine Months  Three Months
  2009  2008  2009  2008  2010  2009

Genco sales to Marketing Company(a)

  3,389   4,276   10,347   12,217   5,437    5,321  

AERG sales to Marketing Company(a)

  1,923   1,794   4,898   5,107   1,989    1,384  

Marketing Company sales to CIPS(b)

  226   463   1,044   1,557   190    446  

Marketing Company sales to CILCO(b)

  96   222   457   702   95    208  

Marketing Company sales to IP(b)

  282   715   1,409   2,217   330    621  

 

(a)Both Genco and AERG have a power supply agreement with Marketing Company whereby Genco and AERG sell and Marketing Company purchases all the capacity and energy available from Genco’s and AERG’s generation fleets.
(b)Marketing Company contracted with CIPS, CILCO, and IP to provide power based on the results of the September 2006 Illinois power procurement auction. The values in this table reflect the physical sales volumes provided in that agreement.

Capacity Supply Agreements

CIPS, CILCO and IP, as electric load serving entities, must acquire capacity sufficient to meet their obligations to customers. In 2009,2010, the Ameren Illinois Utilities used a RFP process, administered by the IPA, to contract the necessary capacity for the period from June 1, 2009,2010, through May 31, 2012.2013. Both Marketing Company and UE were winning suppliers in the Ameren Illinois Utilities’ capacity RFP process. In April 2009,2010, Marketing Company contracted to supply capacity to the Ameren Illinois Utilities for $4$1 million, $9$2 million, and $8$3 million for the twelve months ending May 31, 2010, 2011, 2012, and 2012,2013, respectively. In April 2009,2010, UE contracted to supply capacity to the Ameren Illinois Utilities for $2 million, $2 million, andless than $1 million for the twelve months ending May 31, 2010, 2011, and 2012, respectively.

Energy Swaps

CIPS, CILCO and IP, as electric load serving entities, must acquire energy sufficient to meet their obligations to customers. In 2009, the Ameren Illinois Utilities used a RFP process, administered by the IPA, to procure financial energy swapsentire period from June 1, 2009,2010 through May 31, 2011. Marketing Company was2013.

Joint Ownership Agreement

AITC and IP have a winning supplierjoint ownership agreement to construct, own, operate, and maintain certain electric transmission assets in Illinois. Under the terms of this agreement, IP and AITC are responsible for their applicable share of all costs related to the construction, operation, and maintenance of electric transmission systems. Through this joint ownership agreement, IP has a variable interest in AITC, but IP is not the primary beneficiary. Ameren Illinois Utilities’ energy swap RFP process. In May 2009, Marketing Company entered into financial instruments that fixedis the price that the Ameren Illinois Utilities will pay for approximately 80,000 megawatthours at approximately $48 per megawatthour during the twelve months ending May 31, 2010primary beneficiary of AITC, and for approximately 89,000 megawatthours at approximately $48 per megawatthour during the twelve months ending May 31, 2011.therefore consolidates AITC.

Collateral Postings

Under the terms of the power supply agreements between Marketing Company and the Ameren Illinois Utilities, which were entered into as part of the September 2006 Illinois power procurement auction, collateral must be posted by Marketing Company under certain market conditions to protect the Ameren Illinois Utilities in the event of nonperformance by Marketing Company. The collateral postings are unilateral, meaning that Marketing Company as the supplier is the only counterparty required to post collateral. At September 30, 2009,March 31, 2010, and December 31, 2008,2009, there were no collateral postings necessary byrequired of Marketing Company related to the 2006 auction power supply agreements.

Under the terms of the 2009 Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect the Ameren Illinois Utilities in the event of nonperformance. The collateral postings are unilateral, meaning only the suppliers would be required to post collateral. Therefore, UE, as a winning supplier of capacity, and Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral. As of September 30, 2009,March 31, 2010, there were no collateral postings necessary betweenrequired of UE and the Ameren Illinois Utilities or between Marketing Company and the Ameren Illinois Utilities related to the 2009 Illinois power procurement agreements.

Generation Interconnection Agreements

In 2008, Genco and CIPS signed an agreement requiring Genco to fund the cost of certain upgrades to CIPS’ electric transmission system. At September 30, 2009, CIPS had recorded $2 million in Other Deferred Credits and Liabilities, and Genco had recorded $2 million in Other Assets. These transactions were eliminated in consolidation on Ameren’s financial statements.

In September 2009, Marketing Company and CIPS signed an agreement requiring Marketing Company to fund the cost of certain upgrades to CIPS’ electric transmission system. At September 30, 2009, CIPS had recorded $5 million in Other Deferred Credits and Liabilities for the receipt of cash in advance of construction activities. These transactions were eliminated in consolidation on Ameren’s financial statements.

Money Pools

See Note 3 - Short-term- Credit Facility Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.

CILCO Support Services

On January 1, 2009, approximately 570 Ameren Services employees who provided support services to the Ameren Illinois Utilities were transferred to CILCO (Illinois Regulated). As CILCO employees, they provide services to CIPS and IP as well as to CILCO. The cost of support services provided by CILCO to CIPS and IP, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred.

Intercompany Borrowings

Genco’s $45 million subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco maturesmatured on May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $1 million and $3 million (2008(2009 - $2 million and $6 million, respectively)million) for the three and nine months ended September 30, 2009, respectively.

CILCORP (parent company) had outstanding borrowings from Ameren of $218 million and $152 million at September 30, 2009, and DecemberMarch 31, 2008, respectively. The average interest rate on CILCORP’s borrowings from Ameren was 6.5% and 4.3% for the three and nine months ended September 30, 2009, respectively (2008 - 3.5% and 3.7%, respectively). CILCORP recorded interest expense of $4 million and $6 million for these borrowings for the three and nine months ended September 30, 2009, respectively (2008 - less than $1 million for the three and nine months periods).2010.

CILCO (AERG) had outstanding borrowings from Ameren of $334$245 million at September 30, 2009,March 31, 2010, and had no outstanding borrowings directly from Ameren of $288 million at December 31, 2008.2009. The average interest rate on CILCO’s (AERG) borrowings from Ameren was 6.5% and 5.8%6% for the three and nine months ended September 30, 2009, respectively.March 31, 2010 (2009 - 1.7%). CILCO (AERG) recorded interest expense of $6$4 million and $8 million, respectively for these borrowings for the three and nine months ended September 30, 2009.March 31, 2010 (2009 - less than $1 million).

UE

Genco (EEI) had no outstanding borrowings directly from Ameren of $109 million at September 30, 2009,March 31, 2010, and had outstanding borrowings directly from Ameren of $92$131 million at December 31, 2008.2009. The average interest rate on UE’sGenco’s (EEI) borrowings from Ameren was 0.2% and 1.2%3% for the three and nine months ended September 30, 2009 (2008March 31, 2010 (2009 - 3.5% and 3.7%, respectively)1%). UEGenco (EEI) recorded interest expense of less than $1 million for these borrowings for both the three and nine months ended September 30, 2009 (2008March 31, 2010 (2009 - less than $1 million for the three and nine-month periods)million).

The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three and nine months ended September 30, 2009March 31, 2010 and 2008.2009. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K, and the money pool arrangements discussed in Note 3 - Short-termCredit Facility Borrowings and Liquidity of this report.

 

        Three Months          Nine Months 
Agreement      UE  CIPS  Genco  CILCORP(a)  IP          UE  CIPS  Genco  CILCORP(a)  IP 

Operating Revenues:

                  

Genco and AERG power supply

  2009  $(b $(b $214   $    119   $(b      $(b $(b $654   $    317   $(b

agreements with Marketing Company

  2008  (b (b 233   99   (b       (b (b 658   252   (b

Ancillary services and capacity

  2009  2   (b (b (b (b      3   (b (b (b (b

agreements with CIPS, CILCO and IP(c)

  2008  3   (b (b (b (b       9   (b (b (b (b

Genco gas sales to Medina Valley

  2009  (b (b -   (b (b      (b (b 1   (b (b
   2008  (b (b -   (b (b       (b (b -   (b (b

Genco gas sales to distribution companies

  2009  (b (b (e (b (b      (b (b 1   (b (b
   2008  (b (b (e (b (b       (b (b 6   (b (b

CILCO support services(h)

  2009  (b (b (b 19   (b      (b (b (b 53   (b
   2008  (b (b (b (b (b       (b (b (b (b (b

Total Operating Revenues

  2009  $2   $(b $214   $    138   $(b      $3   $(b $656   $    370   $(b
   2008  3   (b 233   99   (b       9   (b 664   252   (b

Purchased Power:

                  

CIPS, CILCO and IP agreements with

  2009  $(b $32   $(b $      15   $44        $(b $110   $(b $      51   $155  

Marketing Company(d)

  2008  (b 32   (b 15   49         (b 104   (b 47   148  

Ancillary services and capacity

  2009  (b 1   (b (e 1        (b 1   (b (e 1  

agreements with UE(c)

  2008  (b 1   (b 1   1         (b 3   (b 1   5  

Ancillary services agreement with

  2009  (b -   (b -   -        (b (e (b (e (e

Marketing Company

  2008  (b 1   (b 1   2         (b 5   (b 3   8  

Executory tolling agreement with Medina

  2009  (b (b (b (f (b      (b (b (b (f (b

Valley

  2008  (b (b (b 8   (b       (b (b (b 30   (b

Total Purchased Power

  2009  $(b $33   $(b $      15   $45        $(b $111   $(b $      51   $156  
   2008  (b 34   (b 25   52         (b 112   (b 81   161  

Gas purchases for resale:

                  

Gas purchases from Genco

  2009  $-   $-   $(b $        -   $(e      $-   $-   $(b $        1   $(e
   2008  -   -   (b (e -         -   -   (b 6   -  

Operating Revenues and Purchased Power:

                  

Insurance recoveries

  2009  $-   $(b $-   $        -   $(b      $-   $(b $-   $       -   $(b
   2008  -   (b (5 (3 (b       (e (b (11 (4 (b

Other Operations and Maintenance:

                  

Ameren Services support services agreement

  2009  $31   $7   $7   $        9   $12        $96   $22   $21   $      28   $36  
   2008  35   14   7   14   21         106   42   21   42   63  

CILCO support services

  2009  (b 5   (b (b 8        (b 16   (b (b 23  
   2008  (b (b (b (b (b       (b (b (b (b (b

AFS support services agreement

  2009  2   (e (e 1   1        6   1   2   2   2  
   2008  2   (e 1   1   (e       5   1   2   2   1  

Insurance premiums(g)

  2009  1   (b (e (e (b      2   (b 1   1   (b
   2008  2   (b 1   1   (b       7   (b 3   3   (b

Total Other Operations and

  2009  $34   $12   $7   $      10   $21        $104   $39   $24   $      31   $61  

    Maintenance Expenses

  2008  39   14   9   16   21         118   43   26   47   64  

Interest Charges:

                  

Interest expense (income) from money

  2009  $-   $(e $(e $       (e $-        $-   $(e $1   $        1   $(e

pool borrowings (advances)

  2008  -   (e (e 1   (e       -   (e (e 1   (e
            Three Months 
Agreement  Income Statement Line Item      UE  CIPS  Genco  CILCO  IP 

Genco and AERG power supply

  Operating Revenues  2010  $(a $(a $264   $    92   $(a

agreements with Marketing Company

     2009   (a  (a  288   93    (a

UE ancillary services and capacity

  Operating Revenues  2010   (c  (a  (a (a  (a

agreements with CIPS, CILCO and IP

     2009   (c  (a  (a (a  (a

UE and Genco gas transportation

  Operating Revenues  2010   (c  (a  (a (a  (a

agreement

     2009   (c  (a  (a (a  (a

Genco gas sales to Medina Valley

  Operating Revenues  2010   (a  (a  1   (a  (a
      2009   (a  (a  1   (a  (a

CILCO support services(b)

  Operating Revenues  2010   (a  (a  (a 21    (a
      2009   (a  (a  (a 16    (a

Total Operating Revenues

    2010  $(c $(a $265   $  113   $(a
      2009   (c  (a  289   109    (a

UE and Genco gas transportation

  Fuel  2010  $(a $(a $(c $     (a $(a

agreement

     2009   (a  (a  (c (a  (a

CIPS, CILCO and IP agreements with

  Purchased Power  2010  $(a $23   $(a $    12   $   38  

Marketing Company

     2009   (a  41    (a 20    59  

CIPS, CILCO and IP ancillary services and

  Purchased Power  2010   (a  (c  (a (c  (c

capacity agreements with UE

     2009   (a  (c  (a (c  (c

Ancillary services agreement with

  Purchased Power  2010   (a  -    (a -    -  

Marketing Company

     2009   (a  (c  (a (c  (c

Total Purchased Power

    2010  $(a $23   $(a $    12   $   38  
      2009   (a  41    (a 22    59  

Ameren Services support services

  Other Operations and  2010  $   35   $8   $7   $      8   $   14  

agreement

  Maintenance  2009   32    7    6   10    12  

CILCO support services

  Other Operations and  2010   (a  6    (a (a  9  
   Maintenance  2009   (a  5    (a (a  7  

AFS support services agreement

  Other Operations and  2010   1    (c  1   (c  (c
   Maintenance  2009   2    (c  1   1    1  

Insurance premiums(d)

  Other Operations and  2010   1    (a  -   -    (a
   Maintenance  2009   1    (a  (c (c  (a

Total Other Operations and

    2010  $   37   $14   $8   $      8   $   23  

Maintenance Expenses

     2009   35    12    7   11    20  

Money pool borrowings (advances)

  Interest Charges  2010  $-   $-   $(c $       -   $-  
      2009   -    (c  (c 1    (c

 

(a)Amounts represent CILCORP and CILCO activity.Not applicable.
(b)Not applicable.

(c)Represents ancillary services to the Ameren Illinois Utilities for 2009 and 2008 and capacity to the Ameren Illinois Utilities in 2009.
(d)Represents power supply costs under agreements entered into as part of the Illinois September 2006 auction, the 2008 energy and capacity RFPs, and the 2009 capacity RFP.
(e)Amount less than $1 million.
(f)In January 2009, CILCO transferred the tolling agreement to Marketing Company.
(g)Represents insurance premiums paid to Energy Risk Assurance Company, an affiliate, for replacement power and property damage.
(h)Includes revenues relating to property and plant additions during the three months ended September 30, 2009 (CIPS -of $4 million at IP and $2 million at CIPS (2009 - $3 million at IP and IP - $4 million) and during the nine months ended September 30, 2009 (CIPS - $5$1 million and IP - $9 million)at CIPS).
(c)Amount less than $1 million.
(d)Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Nuclear Plant in this report.

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at September 30, 2009.March 31, 2010. The property coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year.

 

Type and Source of Coverage  Maximum Coverages Maximum Assessments for
Single Incidents
   Maximum Coverages Maximum Assessments for
Single Incidents
 

Public liability and nuclear worker liability:

      

American Nuclear Insurers

  $300(a)  $-    $375   $-  

Pool participation

   12,219(b)   118(c)    12,219(a)   118(b) 
  $12,519   $118    $12,594(c)  $118  

Property damage:

      

Nuclear Electric Insurance Ltd.

  $2,750(d)  $23    $2,750(d)  $23  

Replacement power:

      

Nuclear Electric Insurance Ltd.

  $490(e)  $9  

Nuclear Electric Insurance Ltd

  $490(e)  $9  

Energy Risk Assurance Company

  $64(f)  $-    $64(f)  $-  

 

(a)Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b)Retrospective premium under Price-Anderson. 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 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.
(c)Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(d)Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(e)Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear plant. Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter.
(f)Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear plant. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

After the terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under its policies. However, Nuclear Electric Insurance Ltd. imposed an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is unavailable, UE is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, andor liquidity.

Other Obligations

In September 2009, UE announced an agreement with a landfill owner to install CTs at a landfill site in St. Louis County, Missouri, which would generate approximately 15 MW of electricity by burning methane gas collected from the landfill. Construction of the CTs is expected to begin in 2010, and the CTs are expected to begin generating power in 2011. UE signed a 20-year supply agreement with the landfill owner to purchase methane gas. The obligation information presented below includes total estimated methane gas purchase commitments. Related design and construction commitments associated with this project are included in the Other column in the table below.

UE’s firm commitments to purchase heavy forgings for construction of a potential new nuclear power plant have materially changed from amounts previously disclosed as of December 31, 2008. Prior to June 30, 2009, UE made contractual payments to a heavy forgings manufacturer of $14 million and had remaining contractual commitments of $81 million. In July 2009, an agreement was reached with the heavy forgings manufacturer to terminate the heavy forgings contract, and $5 million of previously-made payments were retained by the manufacturer as a penalty for terminating the contract, which was charged to earnings in June 2009. The remaining $9 million of previously-made payments were retained by the manufacturer as partial payment for UE’s future purchase of other heavy equipment for installation at its existing Callaway nuclear plant. See Note 2 - Rate and Regulatory Matters for further information.

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel, and methane gas.fuel. We have also have entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

Our commitments for the procurement of nuclear fuel have materially changed from amounts previously disclosed as of December 31, 2009. The following table presents our total estimated fuel, electric capacity, and othernuclear purchase commitments at September 30, 2009. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, meter reading services, and an Ameren tax credit obligation at September 30, 2009.March 31, 2010:

 

    Coal  Natural Gas  Nuclear  Electric Capacity  Methane Gas  Other  Total 

Ameren:(a)

             

2009

  $170  $150  $35  $7   $-  $35  $397  

2010

   990   570   43   22    -   69   1,694  

2011

   872   453   24   22    1   91   1,463  

2012

   613   308   55   22    3   75   1,076  

2013

   189   193   56   22    4   57   521  

Thereafter(b)

   794   247   429   230    105   318   2,123  

Total

  $3,628  $1,921  $642  $325   $113  $645  $7,274  

UE:

             

2009

  $73  $19  $35  $7   $-  $26  $160  

2010

   530   81   43   22    -   34   710  

2011

   443   62   24   22    1   53   605  

2012

   251   48   55   22    3   43   422  

2013

   128   38   56   22    4   41   289  

Thereafter(b)

   723   65   429   230    105   206   1,758  

Total

  $2,148  $313  $642  $325   $113  $403  $3,944  

CIPS:

             

2009

  $-  $27  $-  $(c $-  $1  $28  

2010

   -   91   -   (c  -   2   93  

2011

   -   71   -   (c  -   2   73  

2012

   -   58   -   (c  -   2   60  

2013

   -   45   -   -    -   2   47  

Thereafter(b)

   -   39   -   -    -   14   53  

Total

  $-  $331  $-  $-   $-  $23  $354  

Genco:

             

2009

  $42  $3  $-  $-   $-  $-  $45  

2010

   223   8   -   -    -   2   233  

2011

   197   8   -   -    -   6   211  

2012

   162   5   -   -    -   -   167  

2013

   25   3   -   -    -   -   28  

Thereafter(b)

   -   5   -   -    -   -   5  

Total

  $649  $32  $-  $-   $-  $8  $689  

CILCORP and CILCO:

             

2009

  $13  $41  $-  $(c $-  $1  $55  

2010

   92   167   -   (c  -   3   262  

2011

   100   135   -   (c  -   3   238  

2012

   84   96   -   (c  -   3   183  

2013

   32   60   -   -    -   3   95  

Thereafter(b)

   71   104   -   -    -   21   196  

Total

  $392  $603  $-  $-   $-  $34  $1,029  

IP:

             

2009

  $-  $58  $-  $(c $-  $2  $60  

2010

   -   217   -   (c  -   10   227  

2011

   -   175   -   (c  -   11   186  

2012

   -   99   -   (c  -   11   110  

2013

   -   47   -   -    -   11   58  

Thereafter(b)

   -   34   -   -    -   77   111  

Total

  $-  $630  $-  $-   $-  $122  $752  

(a)Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)Commitments for natural gas and nuclear fuel are until 2036 and 2020, respectively.
(c)At September 30, 2009, $53 million of electric capacity contracts were executed for the Ameren Illinois Utilities, comprising less than $1 million, $26 million, $26 million, and $1 million for 2009, 2010, 2011, and 2012, respectively. Approximately 33% of the electric capacity provided under the contracts is dedicated to CIPS, 17% is dedicated to CILCO, and 50% to IP. See below for additional information.

      2010    2011    2012    2013    2014    Thereafter

Ameren

    $61    $38    $53    $56    $  119    $384 

UE

     61     38     53     56     119     384 

Ameren Illinois Utilities’ Purchased Power Agreements

In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. As a result, in the second quarter of 2009, the IPA procured electric capacity, financial energy swaps, and renewable energy credits through a RFP process on behalf of the Ameren Illinois Utilities. Electric capacity was procured in April 2009 for the period June 1, 2009, through May 31, 2012. The Ameren Illinois Utilities contracted to purchase between 800 and 3,500 MW of capacity per month at an average price of approximately $41 per MW-day over the three-year period. Financial energy swaps were procured in May 2009 for the period June 1, 2009, through May 31, 2011. The Ameren Illinois Utilities contracted to purchase approximately ten million megawatthours of financial energy swaps at an average price of approximately $36 per megawatthour. Renewable energy credits were procured in May 2009 for the period June 1, 2009, through May 31, 2010. The Ameren Illinois Utilities contracted to purchase 720,000 credits at an average price of approximately $16 per credit.

In December 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company that covers the period from June 1, 2010, through May 31, 2013. As a result, the IPA procured electric capacity through a RFP process on behalf of the Ameren Illinois Utilities. Electric capacity was procured in April 2010. The Ameren Illinois Utilities contracted to purchase between 810 and 2,190 MW of capacity per month at an average price of approximately $246 per MW-month ($8 per MW-day) over the three-year period. Starting with the 2010 RFP, electric capacity was contracted per MW-month instead of MW-day as it was in the 2009 RFP. An RFP process to procure financial energy swaps took place in early May 2010. Marketing Company was a winning bidder to enter into financial contracts with the Ameren Illinois Utilities. The Ameren Illinois Utilities are currently evaluating the results and finalizing the financial contracts. The RFP process to procure renewable energy credits will be completed during the second quarter of 2010.

The following table presents the Ameren Illinois Utilities’ commitments for these contracts at September 30, 2009:March 31, 2010:

 

    2009     2010    2011    2012     2010    2011    2012    2013 

Electric capacity

    $(a    $26    $26    $1   

Electric Capacity

    $27    $29    $8    $(a

Financial energy swaps

     39       183     56     -       127     56     -     -  

Renewable energy credits

     3       6     -     -       4     -     -     -  

 

(a)Less than $1 million.million

Illinois Electric Settlement Agreement

The Illinois electric settlement agreement provided for approximately $1 billion of funding over a four-year period that commenced in 2007 for rate relief for certain electric customers in Illinois. Electric generators in Illinois and certain Illinois electric utilities agreed to fund the settlement. The Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of $150 million, of which the following estimated contributions remained to be made as of September 30, 2009:

    Ameren  CIPS  

CILCO

(Illinois
Regulated)

  IP  Genco  

CILCO

(AERG)

 

2009

  $7.6  $1.1  $0.5  $1.6  $3.0  $1.4   

2010

   2.4   0.3   0.2   0.5   1.0   0.4  

Total

  $10.0  $1.4  $0.7  $2.1  $4.0  $1.8  

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 existing or new natural gas storage, plants, and natural gas transmission, and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, impacts to air, land and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Our activities often require complexComplex and lengthy processes as weare required to obtain approvals, permits or licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations. The more significant matters are discussed below.

Clean Air Act

Both federal and state laws require significant reductions in SO2and NOx emissions that result from burning fossil fuels. In MayMarch 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule). The federal Clean Air Interstate Rule requires generating facilities in 28 eastern states, includingwhich include Missouri and Illinois, where our generating facilities are located, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO2emissions, annual NOx emissions, and ozone season NOx emissions. The cap-and-trade program for both annual and ozone season NOx emissions went into effect on January 1, 2009. The SO2emissions cap-and-trade program is scheduled to takewent into effect inon January 1, 2010.

In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method it used to remove electric generating units from the list of sources subject to the maximum available control technologyMACT requirements under the Clean Air Act. In February 2009, the U.S. Supreme Court denied a petition for review filed by a group representing the electric utility industry. The impact of this decision is that the EPA will move forward with a MACT standard for mercury emissions and other hazardous air pollutants, such as acid

  gases. The standard is expectedIn a consent order, the EPA agreed to be available in draft form in 2010,propose the MACT regulation by March 2011 and compliancefinalize the regulation by November 2011. Compliance is expected to be required in the 2013 to 2015 timeframe.2015. We cannot predict at this time the estimated capital or operating costs for compliance with such future environmental rules.

In JulyDecember 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacatedremanded the federal Clean Air Interstate Rule. The court ruled that the regulation contained several fatal flaws, including a regional cap-and-trade program that cannot be used to facilitate the attainment of ambient air quality standards for ozone and fine particulate matter. In September 2008, the EPA, as well as several environmental groups, a group representing the electric utility industry, and the National Mining Association, all filed petitions for rehearing with the U.S. Court of Appeals. In December 2008, the U.S. Court of Appeals essentially reversed its July 2008 decision to vacate the federal Clean Air Interstate Rule. The U.S. Court of Appeals granted the EPA petition for reconsideration and remanded the ruleRule to the EPA for further action to remedy the rule’s flaws in accordance with the U.S. Court of Appeals’ July 2008 opinion in the case. The impact of the decision is that the existing Illinois and Missouri rules to implement the federal Clean Air Interstate Rule will remain in effect until the federal Clean Air Interstate Rule is revised by the EPA, at which point the Illinois and Missouri rules may be subject to change. The EPA has stated that it expects to issue a new proposed version of the Clean Air Interstate Rule in 2010 and a final version in 2011.

The state of Missouri has adopted rules to implement the federal Clean Air Interstate Rule for regulating SO2 and NOx emissions from electric generating units. The rules are a significant part of Missouri’s plan to attain existing ambient standards for ozone and fine particulates, as well as meeting the federal Clean Air Visibility Rule. The rules are expected to reduce NOxemissions by 30% and SO2 emissions by 75% by 2015. As a result of the Missouri rules, UE will manageuse allowances and install pollution control equipment. UE’s costs to comply with SO2 emission reductions required by the Clean Air Interstate Rule could increase materially if the EPA determines that existing allowances granted to sources under the Acid Rain Program cannot be used for compliance with the Clean Air Interstate Rule or if a new allowance program is mandated by revisions to the Clean Air Interstate Rule. Missouri also adopted rules to implement the federal Clean Air Mercury Rule. However, these rules are not enforceable as a result of the U.S. Court of Appeals decision to vacate the federal Clean Air Mercury Rule.

We do not believe that the court decision that vacated the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois in the near term. Under the MPS, as amended, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NOx and SO2 controls. This rule, when fully implemented, is expected to reduce mercury emissions by 90%, NOx emissions by 50%, and SO2 emissions by 70% by 2015 in Illinois. To comply with the rule, Genco and CILCO (AERG) and EEI have begun putting into serviceinstalling equipment designed to reduce mercury, NOx, and SO2emissions. Genco,In 2009, CILCO (AERG) completed the installation of a scrubber at its Duck Creek plant, and EEIGenco completed the installation of a scrubber at its Coffeen plant. Genco and CILCO (AERG) will also need to install additional pollution control equipment. Current plans include installing scrubbers for SO2reductionat Genco’s Newton plant by 2015, as well as optimizing operations of selective catalytic reduction (SCR) systems for NOx reduction at certain coal-fired plants in Illinois.

In October 2008,Genco’s Coffeen plant and CILCO (AERG)’s Edwards and Duck Creek plants. Genco CILCO (AERG) and EEI soughtis planning to revise certain requirements of the MPS. They proposed to the Illinois Pollution Control Board to lower requireduse dry sorbent injection SO2 reduction technology on all coal-fired units at the Joppa plant, rather than installing scrubbers on half of the units. Capital requirements for dry sorbent injection are lower than scrubbers. Several projects are planned to handle the solid and NOliquid wastes generated by the SOx2 emissionsscrubbers at the Duck Creek and Coffeen plants. Additional facilities and upgrades are planned at all plants to meet the 2015 mercury control requirements.

Due, in part, to operational changes and strong performance levels from pollution control equipment, Ameren’s Merchant Generation segment reduced in the first quarter of 2010 through 2020 in orderits estimated capital costs to make the proposed revisions tocomply with state air quality implementation plans, the MPS, “environmentally neutral.” In April 2009,federal ambient air quality standards including ozone and fine particulates, and the Illinois Pollution Control Board approved revisionsfederal Clean Air Visibility rule. The Merchant Generation segment’s estimated capital costs in the table below are $425 million lower compared to estimates in the MPS. After reviewForm 10-K. These estimates contain all of the known capital costs for the Merchant Generation segment to comply with existing and approval byknown emissions-related regulations as of March 31, 2010. The estimates shown in the Illinois Joint Committee on Administrative Rules, this rule amendment became finaltable below could change depending upon additional federal or state requirements, the requirements under a MACT standard, new technology, and variations in June 2009. As a result, Genco and CILCO (AERG) collectively are ablecosts of material or labor, or alternative compliance strategies, among other factors.

    2010  2011 - 2014  2015 - 2017  Total

UE(a)

  $    160  $    170 

-

 $     215  $      25 -  $      35  $     355 -  $     410

Genco

  90  565 

-

        660  80 -  90  735 -  840

CILCO (AERG)

  5  

125

 

-

        160  15 -  20  145 -  185

Ameren

  $    255  $    860 

-

 $  1,035  $    120 -  $    145  $  1,235 -  $  1,435

(a)UE’s expenditures are expected to be recoverable from ratepayers.

UE’s estimate of capital spending to defer to subsequent years an estimated $300 million of environmental capital expenditures originally scheduled for 2009 through 2011.comply with existing regulations remains consistent with its disclosure included in the Form 10-K.

In March 2008, the EPA finalized regulations that willwould lower the ambient standard for ozone. In September 2009, EPA announced its plan to revise the ozone standard to a level lower than the level set in the March 2008 regulation. The revised standard is expected to be finalized in August 2010. Illinois and Missouri have each submitted theirare required to submit recommendations to the EPA for designating nonattainment areas. A final action by the EPA to designate nonattainment areas is expected in March 2010. Stateand implementation plans will need to be submitted in 2013 unless Illinois and Missourithe states seek extensions for various requirement dates. Additional emission reductions may be required as a result of future state implementation plans. At this time, we are unable to determine the impact that state implementation plans for such state actionsregulations would have on our results of operations, financial position, orand liquidity.

The table below presents estimated capital costs that are based on current technology to comply with the federal Clean Air Interstate Rule and related state implementation plans through 2018, as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. The estimates described below could change depending upon additional federal or state requirements, the requirements under a MACT standard, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with any future rules, thereby deferring capital investment. Ameren is in the process of identifying opportunities to defer or reduce planned capital spending, including the estimates provided in the table below. In the second quarter of 2009, Merchant Generation eliminated approximately $1 billion of capital expenditures from its previous estimates for 2010 through 2013. The environmental portion of this reduction is reflected in the table below.

    2009  2010 - 2013  2014 - 2018  Total

UE(a)

  $100  $  525 - $   655  $1,525 - $1,880  $2,150 - $2,635

Genco

   275  480 -      615  215 -      310  970 -   1,200

CILCO(AERG)

   45  415 -      540  85 -      125  545 -      710

EEI

   15  40 -        55  280 -      385  335 -      455

Ameren

  $435  $1,460 - $1,865  $2,105 - $2,700  $4,000 - $5,000

(a)UE’s expenditures are expected to be recoverable in rates over time.

Emission Allowances

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act created marketable commodities called allowances under the Acid Rain Program, the NOx Budget Trading Program, and the federal Clean Air Interstate Rule. All existing generating facilities have been allocated SO2 and NOx allowances based on past production and the statutory emission reduction goals. NOx allowances allocated under the NOx Budget Trading Program can be used for the seasonal NOx program under the federal Clean Air Interstate Rule. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances orand through the application of pollution control technology, including low-NOx burners, over-fire air systems, combustion optimization, rich-reagent injection, selective noncatalytic reduction, and selective catalytic reduction systems.

See Note 1 - Summary of Significant Accounting Policies for the SO2 and NOx emission allowances held and the related SO2 and NOx emission allowance book values that were carriedclassified as intangible assets as of September 30, 2009.March 31, 2010.

UE, Genco, and CILCO (AERG) and EEI expect to use a substantial portion of thetheir SO2 and NOx allowances for ongoing operations. Environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment, and the level of operations, will have a significant impact on the number of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO2 emissions by increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO2 allowance for every ton of SO2 that is emitted. Unless revised by the EPA as a result of the U.S. Court of Appeals’ remand, the Clean Air Interstate Rule program will requirerequires that SO2 allowances of vintages 2010 through 2014 be surrendered at a ratio of two allowances for every ton of emission. SO2 allowances with vintages of 2015 and beyond will be required to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, and CILCO (AERG), and EEI expect to install control technology designed to further reduce SO2 emissions, as discussed above.

The Clean Air Interstate Rule has both an ozone season program and an annual program for regulating NOx emissions, with separate allowances issued for each program. The Clean Air Interstate Rule ozone season program replaced the NOx Budget Trading Program beginning in 2009. Allocations for UE’s Missouri generating facilities for the years 2009 through 2014 were 11,665 tons per ozone season and 26,842 tons annually. Allocations for Genco’s generating facility in Missouri were one ton for the ozone season and three tons annually. Allocations for UE’s, Genco’s and CILCO’s (AERG), and EEI’s Illinois generating facilities for the years 2009 through2010 and 2011 were 90, 3,442,5,200, and 1,368 and 1,758 tons per ozone season, respectively, and 93, 8,300, 3,418,12,867, and 4,5643,419 tons annually, respectively.

Global Climate Change

OnIn June 26, 2009, the U.S. House of Representatives passed energy legislation entitled “The American Clean Energy and Security Act of 2009” that, if enacted, would establish an economy-wide cap-and-trade program. The overarching goal of this proposed cap-and-trade program is to reduce greenhouse gas emissions from capped sources, including coal-fired electric generation units, to a level that is 3% below 2005 levels by 2012, 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by the year 2050. The proposed legislation provides an allocation of free emission allowances and greenhouse gas offsets to utilities, as well as certain merchant coal-fired electric generators in competitive markets. This aspect of the proposed legislation would mitigate some of the cost of compliance for the Ameren Companies. However, the amount of free allowances provided declinesdecline over time and isare ultimately phased out. The proposed legislation also contains, among other things, a federal renewable energy standard of 6% by 2012 that increases over timegradually to 20% by 2020, of which up to 25% of the goalrequirement can be met by

energy efficiency. The proposed legislation also establishes performance standards for new coal plants, requires electric utilities to develop plans to support plug-in hybrid vehicles, and requires load-serving entities to reduce peak electric demand through energy efficiency and Smart Grid technologies. OnIn September 30, 2009, Senators Boxer and Kerry introduced climate change legislation entitled “The Clean Energy Jobs and American Power Act,” which isAct” was introduced in the U.S. Senate that was similar to that passed by the U.S. House of Representatives in June 2009, although withit proposes a slightly greater reduction in greenhouse gas emissions in the year 2020. Leaders2020 and grants fewer emission allowances to the electricity sector. Under both proposed pieces of legislation, large sources of CO2 emissions will be required to obtain and retire an allowance for each ton of CO2 emitted. The allowances may be allocated to the sources without cost, sold to the sources through auctions or other mechanisms, or traded among parties. “The Clean Energy Jobs and American Power Act” was voted out of committee in November 2009. In December 2009, Senators Kerry, Graham and Lieberman introduced a framework for Senate legislation in 2010. The framework lacks specifics, but reports suggest it is consistent with the U.S. Senate have indicated they hopeHouse-passed legislation except that it emphasizes the need for greater support for nuclear power and energy independence through support for clean energy and drilling for oil and natural gas.

In addition, the reduction of greenhouse gas emissions has been identified as a high priority by President Obama’s administration. Although we cannot predict the date of enactment or the requirements of any future climate change legislation or regulations, we believe it is possible that some form of federal legislation or regulations to bring this legislation beforecontrol emissions of greenhouse gases will become law during the full Senate by the end of 2009.current administration.

Potential impacts from proposedclimate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of allocatingdistributing 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 ceilingmaximum price for emission allowance purchases.allowances. As a result of our diverse fuel portfolio, our contributionemissions of greenhouse gases variesvary among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s analysis shows that if either “The American Clean Energy and Security Act of 2009” or “The Clean Energy Jobs and American Power Act” were enacted into law in their current form, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region’s reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO2 that coal emits when burned to produce electricity. As a result, economy-wide shifts favoring natural gas as a fuel source for electricelectricity generation also could affect the cost of heating for our utility customers and many industrial processes. Ameren believes that wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for electricity and natural gas.

Future initiativesIn early December of 2009, representatives from countries around the globe met in Copenhagen, Denmark, to attempt to develop an international treaty to supersede the Kyoto Protocol, which set mandatory greenhouse gas reduction requirements for participating countries. The parties were unable to reach agreement regarding mandatory greenhouse gas emissions reductions. However, certain countries, including the United States, entered into an agreement called the “Copenhagen Accord.” The Copenhagen Accord provides a mechanism for countries to make economy-wide greenhouse gas emission mitigation commitments for reducing emissions of greenhouse gases by 2020 and provides for developed countries to fund greenhouse gas emissions mitigation projects in developing countries. Any commitment under the Copenhagen Accord is subject to congressional action on climate change.

Additional requirements to control greenhouse gas emissions and address global climate change may also arise pursuant to the Midwest Greenhouse Gas Reduction Accord, an agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin and Minnesota to develop a strategy to achieve energy security and to reduce greenhouse gas emissions through a cap-and-trade mechanism. The advisory group to the Midwest governors provided draft final recommendations on the design of a greenhouse gas reduction program to the governors in June 2009. In October 2009, the Midwestern Governors Association held a forum to review some of the advisory group’s recommendations. The October 2009 forum did not yield any significant updates to the Midwest Greenhouse Gas Reduction Accord’s effort to developwork toward a cap-and-trade mechanism. The recommendations have not been endorsed or approved by the individual state governors. It is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.

In AprilWith regard to the control of greenhouse gas emissions under federal regulation, in 2007, the U.S. Supreme Court issued a decision finding that the EPA has the authority to regulate CO2 and other greenhouse gases from automobiles as “air pollutants” under the existing Clean Air Act. This decision required the EPA to determine whether greenhouse gas emissions may reasonably be anticipated to endanger public health or welfare, or, in the alternative, to provide a reasonable explanation as to why greenhouse gas emissions should not be regulated. In December 2009, in response to the decision of the U.S. Supreme Court, the EPA issued its “endangerment finding” determining that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In April 2009,2010, the EPA and the U.S. Department of Transportation issued final rules requiring car makers to meet a new greenhouse gas emission standard for model year 2012 cars. In March 2010, the EPA issued a proposed determination finding that the combination of six greenhouse gases, four of which are emitted by motor vehicle engines, formed air pollution which, through the mechanics of climate change, endangers public health and welfare. Although this “endangerment finding” is in draft form and applies only to greenhouse gas emissions from motor vehicle engines, some ofstationary sources would be subject to regulation under the greenhouse gases that are the subject of the proposed endangerment finding are produced through the combustion of fossil fuels by electric generating units. The comment period on this rulemaking is now closed. The EPA is expected to issue the final endangerment finding by the end of 2009.Clean Air Act in 2011. As a result of these actions, we will be required to consider the court ruling andemissions of greenhouse gas in any air permit application submitted by us or pending after January 1, 2011.

Recognizing the endangerment finding, it is anticipated thatdifficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA will issueannounced in September 2009 a proposed rule, byknown as the end of March 2010 to control greenhouse gas emissions from light-duty vehicles such as automobiles.

On September 30, 2009, the EPA announced a proposed“tailoring rule, that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule would require any source that emits at least 25,000 tons per year of greenhouse gases measured as CO2 equivalents (CO2e) to obtainhave an operating permit under Title V Operating Permit Program of the Clean Air Act, if it does not already have one.Act. Sources that already have an operating permit would have greenhouse gas-specific provisions added to their permits upon renewal. Currently, all Ameren power plants have operating permits that, depending on the final rule, may be requiredmodified when they are renewed to be modified to comply with the new rule. In addition, those sources would be “Major Sources” subject to the Clean Air Act’s New Source Review/Prevention of Significant Deterioration program’s requirements.address greenhouse gas emissions. The proposed tailoring rule also provides that if physical changes or changes in operation at these Major Sources thatmajor sources result in an increase in emissions of greenhouse gases over a threshold that rangesranging from 10,000 tons to 25,000 tons of CO2e, the emitters would be required to obtain a permit under the New Source Review/NSR/Prevention of Significant Deterioration program and to install the best available control technology to control greenhouse gas emissions. New Major Sourcesmajor sources also would be required to obtain such a permit and to install the best available control technology. The EPA has committed to developprovide guidance

to determine about the best available control technology for new and modified major sources of greenhouse gas emissions. The tailoring rule was published in the Federal Register on October 27, 2009, and will be subject to a 60-day public comment period. A rulehas been delayed but is expected to be finalized in early 2010, but anyMay 2010. Any federal climate change legislation that is enacted may pre-emptpreempt the proposed rule, particularly as it relates to power plant greenhouse

gas emissions. This proposed rule has no immediate impact on Ameren’s, UE’s, Genco’s or CILCO’s (AERG) generating facilities. The extent to which this proposed rule, if finalized, could have a material impact on our generating facilities depends upon future EPA guidance onguidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants, whether physical changes or change in operationoperations subject to the rule would occur at our power plants, and whether federal legislation is passed which pre-emptsthat preempts the proposed rule.rule is passed.

While the EPA has stated its intention to regulate greenhouse gas emissions from stationary sources, such as power plants, Congressional action could block that effort. Legislation has been introduced in both the U.S. House of Representatives and U.S. Senate that would block the EPA from regulating greenhouse gas emissions from both mobile and stationary sources. Separate legislation has also been introduced in both the U.S. House of Representatives and U.S. Senate that would delay the EPA’s ability to regulate greenhouse gas emissions from stationary sources for two years. The final outcome of this legislation is uncertain.

The EPA also finalized regulations in September 2009 that would require certain categories of businesses, including fossil fuel-firedfossil-fuel-fired power plants, to monitor and report their annual greenhouse gas emissions, beginning in January 2011 for 2010 emissions. CO2 emissions from fossil fuel-firedfossil-fuel-fired power plants subject to the Clean Air Act’s acid rain program have been monitored and reported for over fifteen years. Thus, this new rule covering greenhouse gas emissions is not expected to have a material effect on our operations. It will require additional reporting of greenhouse gas emissions from various gas operations and possibly other minor sources within our system.

Recent federal appellate court decisions have ruled thatconsidered the application of common law causes of action, such as nuisance, can be used to redress damages resulting from global climate change. InState of Connecticut v. American Electric Power(“AEP”), the U.S. Court of Appeals for the Second Circuit ruled in September 2009 that public nuisance claims brought by states, New York City and public land trusts could proceed and were not beyond the scope of judicial relief. Ameren’s generating plants were not named in the AEP litigation. InComer v. Murphy Oil(“Comer”), a Mississippi property owner sued a number ofseveral industrial companies, alleging that CO2 emissions created the atmospheric conditions whichthat resulted in Hurricane Katrina. The U.S. Court of Appeals for the Fifth Circuit issued a ruling in Comer in October 2009 that also permits this cause of action to proceed. Comer is seeking class action certification on behalf of similarly situated property owners. Additional legal challenges and appeals are expected in both the Comer and AEP and thecases. The rulings in these cases may spur other potential claimants to file suit against greenhouse gas emitters, including Ameren. The courts did not rule on the merits of the lawsuits, only that plaintiffs had standing and couldto pursue their claims. Under some of the versions of greenhouse gas legislation currently pending in Congress, nuisance claims could be rendered moot. We are unable to predict the outcome of lawsuits seeking damages that litigants claim are attributable to climate change and their impact on our results of operations, financial position, orand liquidity.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent we request recovery of these costs through rates, our regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations might force UE, Genco and CILCO (through AERG) and EEI as well as other similarly situated electric power generators to close some coal-fired facilities.facilities and could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’sAERG’s results of operations, financial position, orand liquidity.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Although compliance costs are unlikely in the near future, federal legislative, federal regulatory and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our coal-fired generation plants and our customers’ costs is unknown, but any impact would likely be negative. Our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, orand liquidity.

New Source ReviewNSR and Notice of Violation

The EPA has been conductingis engaged in an enforcement initiative to determine whether modificationstargeted at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review (NSR)determine whether those power plants failed to comply with the requirements orof the NSR and New Source Performance Standards (NSPS) provisions under the Clean Air Act.Act when the plants implemented modifications. The EPA’s inquiries focus on whether the best available emission control technology was orprojects performed at power plants should have been used at such power plants when major maintenance or capital improvements were performed.triggered various permitting requirements and the installation of pollution control equipment.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. It sought detailed operating and maintenance history data with respect to Genco’s Coffeen, Hutsonville, Meredosia, and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren’s Illinois coal-fired power plants. In May 2009, we completed our response to the most recent information request, but we are unable to predict the outcome of this matter.

In March 2008, AmerenJanuary 2010, UE received a requestNotice of Violation from the EPA for information pursuant to Section 114(a)alleging violations of the Clean Air Act seeking detailed operatingAct’s NSR and Title V programs. In the Notice of Violation, the EPA contends that various maintenance, history data with respect torepair and replacement projects at UE’s Labadie, Meramec, Rush Island, and Sioux coal-fired power plant facilities.facilities, dating back to the mid-1990s, triggered NSR requirements. The information request requiredEPA alleges that UE violated the Title V operating permit program by failing to provide responsesaddress such NSR requirements in its operating permits or applications for those permits. If litigation regarding this matter occurs, it could take many years to specific EPA questions regarding certain projectsresolve the underlying issues alleged in the Notice of Violation. UE believes its defenses to the allegations described in the Notice of Violation are meritorious and maintenance activitieswill defend itself vigorously; however, there can be no assurances that it will be successful in order to determine UE’s compliance with state and federal regulatory requirements. UE has completed this information request. In July 2009, the EPA issued a Section 114(a) request to certain contractors that have performed capital projects at UE’s facilities since 1987. We are unable to predict the outcome of this matter.its efforts.

ResolutionUltimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, orand liquidity of Ameren, UE, Genco AERG and EEI.CILCO (AERG). A resolution could result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties.

Clean Water Act

In July 2004, the EPA issued rules under the Clean Water Act that require cooling-water intake structures to have the best technology available for minimizing adverse environmental impacts on aquatic species. These rules pertain to all existing generating facilities that currently employ a cooling-water intake structure whose flow exceeds 50 million gallons per day. The rules may require facilities to install additional intake screenstechnology on their cooling water intakes or take other protective measures and to do extensive site-specific study and monitoring. There is also the possibility that the rules may lead to the installation of cooling towers on some of our generating facilities. On April 1, 2009, the U.S. Supreme Court ruled that the EPA can compare the costs of technology for protecting aquatic species to the benefits of that technology in establishingorder to establish the “best technology available” standards applicable to the cooling water intake structure at existing power plants under the Clean Water Act. The EPA is expected to propose revised rules in early 2010. Until the EPA reissues the rules and such rules are adopted, and until the studies on the aquatic impacts of the power plants are completed, we are unable to estimate the costs of complying with these rules. Such costs are not expected to be incurred prior to 2012. All major generation facilities at UE, Genco and CILCO (AERG) with cooling water systems could be subject to these new regulations.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. UE, CIPS, CILCO and IP have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and facilities transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS and CILCO have contractually agreed to indemnify Genco and AERG, respectively, for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of September 30, 2009,March 31, 2010, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 15, CILCO has 4,four, and IP has 25 sites. All of these sites are in various stages of investigation, evaluation, and remediation. Ameren currently anticipates thatcompletion of remediation at these sites shouldby 2015, except for a CIPS site that is expected to be completed by 2015.2017. The ICC permits each company to recover remediation and litigation costs associated with its former MGP sites from its Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costsincurred. Costs are subject to annual review by the ICC. As of September 30, 2009,March 31, 2010, estimated obligations were: CIPS - $56$43 million to $79$62 million, CILCO - less than $1 million, and IP - $100$111 million to $175$174 million. CIPS, CILCO and IP have liabilities of $56$43 million, less than $1 million, and $100$111 million, respectively, recorded to represent estimated minimum obligations, as no other amount within the range was a better estimate. In the third quarter of 2009, CIPS increased its remediation liability based on the completion of site investigations and the selection of remediated actions.

CIPS is also responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of September 30, 2009,March 31, 2010, CIPS estimated itsthat obligation at $0.5 million to $6 million. CIPS recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. IP is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of September 30, 2009,March 31, 2010, IP recorded a liability of $0.8 million to represent its best estimate of the obligation for these sites.

In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one site in Iowa. UE does not currently have in effect in Missouri a rate rider mechanism that permits recovery of remediation costs associated with MGP sites to be recovered from utility customers. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. As of September 30, 2009,March 31, 2010, UE estimated its obligation at $3 million to $5 million. UE has a liability of $3 million recorded to represent its estimated minimum obligation for its MGP sites, as no other amount within the range was a better estimate.

UE also is responsible for four waste sites in Missouri that have corporate cleanup liability as a result of federal agency mandates. UE recently concluded cleanups at two of these sites, and no further remediation actions are anticipated at those two sites. One of the remaining waste sites for which UE has corporate clean-upcleanup responsibility is a former coal tar distillery located in St. Louis, Missouri. In July 2008, the EPA issued an administrative order to UE pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. UE is the current owner of the site, but UE did not conduct any of the manufacturing operations involving coal tar or its byproducts. UE along with two other PRPs have reached an agreement with the EPA as toabout the scope of the site investigation. The investigation which will occur later this year.in 2010. As of September 30, 2009,March 31, 2010, UE estimated itsthis obligation at $2 million to $5 million. UE has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

In June 2000, the EPA notified UE and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2010. Once the EPA has selected a remedy, alternative, it will begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and all presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of September 30, 2009,March 31, 2010, UE estimated its obligation at $0.4 million to $10 million. UE has a liability of $0.4 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

In March 2008, the EPA issued an administrative order requesting that CIPS participate in a portion of an environmental cleanup of a site within Sauget Area 2 previously occupied by Clayton Chemical Company. CIPS was formerly a customer of Clayton Chemical Company, which before its dissolution was a recycler of waste solvents and oil. Other former customers of Clayton Chemical Company were issued similar orders by the EPA. Pursuant to that order, CIPS and three other PRPs agreed to install an engineered barrier on portions of the Clayton Chemical Company site. This work was concluded in the first quarter of 2009.

In December 2004, AERG submitted a plan to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have(AERG) has a liability of $1$3 million at September 30, 2009, on their consolidated balance sheetsMarch 31, 2010, for the estimated cost of the remediation effort, which involves discharging recycle-system water into the Duck Creek reservoir and the eventual closure of ash ponds in order to address these groundwater and surface water issues.

In March 2009, UE and CIPS received from the EPA “Special Notice of Liability” letters with respect to a former transformer repair facility located in Cape Girardeau, Missouri. Both companies are members of a PRP group that sent electrical equipment to the site and previously performed certain soil remediation and investigative work with respect to the site. The EPA is requesting the PRP group to investigate groundwater conditions at the site. The group is in the process of negotiating the terms under which such additional work would occur. UE and CIPS believe that the PRP group presently has adequate financial resources to cover the cost of such work without additional contributions from the companies.

In addition, ourOur operations or those of our predecessor companies involve the use, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine whether such practices will result in future environmental commitments or impact our results of operations, financial position, or liquidity.

Ash PondsManagement

There has been increased activity at both the state and federal level to examine the need forlevels regarding additional regulation of ash pond facilities and coal combustion byproducts (CCB). On May 4, 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and wastes. The EPA is considering regulatingdisposal of CCB, under the hazardous waste regulations, which could impact future disposal and handling costs at our power plant facilities. We believe it is likely thatThose proposed regulations allow for the EPA will continue to allow somecontinued beneficial use, such as recycling, of CCB without classifying themit as hazardous wastes.waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants to either close surface impoundments such as ash ponds or retrofit such facilities with liners. The EPA is considering requiringseeking public comment regarding the proposed rules before it selects a final regulatory framework for CCB. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and specifically discussed CCB as parta reason for developing the new requirements. Ameren, UE, Genco and CILCO (AERG) are currently evaluating all of itsthe proposed regulations that coal-fired power plants engage into determine whether current management of CCB, including beneficial reuse, and the mandatory closureuse of active surfacethe ash ponds should be altered. Ameren, UE, Genco and CILCO (AERG) also are evaluating the potential costs associated with compliance with the proposed regulation of CCB impoundments and landfills which could be material, if adopted. Existing landfills used for the management of CCB. In September 2009, the EPA announced that it expects to overhaul federal rules governing wastewater discharges from coal-fired power plants. It is anticipated that some form of additional regulation concerning the integrity of ash ponds, and the handling and disposal of CCB would be subject to groundwater monitoring requirements and waste may be proposed inrequirements related to the fourth quarterclosure and post-closure care of 2009. Ameren’s CCB impoundments were not identified in the EPA’s 2009 listing of 44 high hazard potential impoundments containing CCB. landfill.

In addition, the Illinois EPA has requested that UE, Genco and CILCO (AERG) and EEI establish groundwater monitoring plans for their active and inactive ash impoundments in Illinois. Genco is currently petitioningAmeren has entered into discussions with the Illinois Pollution Control Board to issueEPA about a site specific rule approving theframework for closure of anadditional ash pondponds in Illinois, including the ash ponds at itsVenice, Hutsonville, power plant. and Duck Creek, when such facilities are ultimately taken out of service. The permits for the Venice and Duck Creek ash ponds both expire in 2010. UE, Genco and CILCO (AERG) have recorded AROs, based on current laws, for the estimated costs of the retirement of their ash ponds.

At this time, we are unable to predict the outcomeeffects any such state and federal regulations might have on our results of operations, financial position, orand liquidity.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. UE settled with FERC and the Statestate of Missouri all issues associated with the December 2005 Taum Sauk incident.

UE has property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance does not cover lost electric margins and penalties paid to FERC. UE expects that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the upper reservoir, will range from $203 million to $210be approximately $205 million. As of September 30, 2009,March 31, 2010, UE had paid $203$205 million, including costs resulting from the FERC-approved stipulation and consent agreement. As of September 30, 2009,March 31, 2010, UE had recorded expenseexpenses of $35 million, primarily in prior years, for items not covered by insurance and had recorded a $168$170 million receivable for amounts recoverable from insurance companies under liability coverage. As of September 30, 2009,March 31, 2010, UE had received $99$103 million from insurance companies, which reduced the insurance receivable balance subject to liability coverage to $69$67 million.

UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of rebuilding the facility. UE expects theplant. The rebuilt Taum Sauk plant to be out of service until the spring ofbecame fully operational in April 2010. The estimated cost to rebuild the upper reservoir iswas in the range of $490 million. As of September 30, 2009,March 31, 2010, UE had recorded a $420 million receivable due from insurance companies under property insurance coverage related to the rebuilding of the facility and the reimbursement of replacement power costs. As of September 30, 2009,March 31, 2010, UE had received $362 million from insurance companies, which reduced the property insurance receivable balance as of September 30, 2009,March 31, 2010, to $58 million.

Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. In July 2009, three insurance carriers filed a petition against Ameren in the Circuit Court of St. Louis County, Missouri, seeking a declaratory judgment that the property insurance policy does not require these three insurers to indemnify Ameren for their share of the entire cost of construction associated with the facility rebuild design being utilized. The three insurers allege that they, along with the other policy participants, had presented a rebuild design that was consistent with their insurance coverage obligations and that the insurance policy doespolicies do not require these insurers to pay their share of the costs of construction associated with the design being used. These insurers have estimated a cost of approximately $214 million for their rebuild design compared to the estimated $490 million cost of the design

approved by FERC and being usedimplemented by Ameren. Ameren has filed an answer and counterclaim in the Circuit Court of St. Louis County, Missouri, (the case has recently been transferred to the Circuit Court of Franklin County, Missouri) against these insurers. The counterclaim asserts that the three insurance carriers have breached their obligations under the property insurance policies issued to Ameren and UE. Ameren seeks payment of an amounta sum to-be-determined for all amounts covered by these policies incurred in the facility rebuild, including power replacement costs, interest, and attorney’sattorneys’ fees. The insurers that are parties to the litigation represent approximately 40%, on a weighted average basis, of the property insurance policy coverage between the disputed amounts of $214 million and $490 million.

On August 31, 2009, Ameren and the property insurance carriers that are not parties to the above litigation (the “Settling Insurance Companies”) reached a settlement of any and all claims, liabilities, and obligations arising out of, or relating to, coverage under its property insurance policy, including those related to the rebuilding of the facility and the reimbursement of replacement power costs. All payments from the Settling Insurance Companies were received by UE byin September 30, 2009.

Until Ameren’s remaining insurance claims and the related litigation are resolved, among other things, we are unable to determine the total impact the breach maycould have on Ameren’s and UE’s results of operations, financial position, orand liquidity beyond those amounts already recognized. As a result of the settlement with the Settling Insurance Companies, Ameren and UE now expect to recover, through insurance, 80% to 90% of the total property insurance claim for the Taum Sauk incident. Beyond insurance, the recoverability of any Taum Sauk facility rebuild costs from customers is subject to the terms and conditions set forth in UE’s November 2007 State of Missouri settlement agreement. In that settlement, UE agreed that it would “notnot attempt to recover from rate payers…payers

costs incurred in the reconstruction…reconstruction expressly excluding, however…however, enhancements, costs incurred due to circumstances or conditions that [werewere not at that time]time reasonably foreseeable and costs that would have been incurred absent the [TaumTaum Sauk incident].”incident. Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the expected spring 2010 in-service date of the rebuilt facility. As of September 30, 2009,March 31, 2010, UE had capitalized in property and equipmentplant qualifying Taum Sauk-related costs of $59$100 million that UE believes qualify for potential recovery in electric rates under the terms of the November 2007 State of Missouri Settlement. The inclusion of such costs in UE’s electric rates is subject to review and approval by the MoPSC in a future rate case. Any amounts not recovered through insurance, in electric rates, or otherwise, could result in charges to earnings, which could be material.

Asbestos-related Litigation

Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 192 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of September 30, 2009,March 31, 2010, the average number of parties was 73.71.

The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a former parent subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO have contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of September 30, 2009:March 31, 2010:

 

Specifically Named as DefendantSpecifically Named as Defendant  Specifically Named as Defendant  
Ameren  UE  CIPS  Genco  CILCO  IP  Total(a)  UE  CIPS  Genco  CILCO  IP  Total(a)

2

  31  30  -  14  40  74

1

  27  32  9(b)  16  41  74

 

(a)Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.

As of September 30, 2009, nine asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

(b)As of March 31, 2010, nine asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

At September 30,March 31, 2009, Ameren, UE, CIPS, Genco, CILCO and IP had liabilities of $14 million, $4 million, $3 million, $- million, $2 million, and $5 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.

IP has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007,terms: 90% of cash expenditures in excess of the amount included in base electric rates are recovered by IP from a trust fund established by IP. At September 30, 2009,March 31, 2010, the trust fund balance was approximately $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.

NOTE 10 - CALLAWAY NUCLEAR PLANT

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel.fuel (the NWF fee). Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE’s last announced date of when it expects a permanent storage facility for spent fuel to be available was 2020, and the DOE continues to evaluate permanent storage alternatives. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The DOE recently submitted a motion to withdraw the Yucca Mountain Repository license application with the NRC. In anticipation of this action, the Nuclear Energy Institute (NEI) in July 2009 formally requested that DOE promptly perform the statutorily required annual fee adequacy review and immediately suspend collection of the NWF fee. The Nuclear Waste Policy Act mandates that DOE compare the revenue generated by the NWF fee with the costs of the waste disposal program and adjust the size of the NWF fee to match the cost of the program. In the past, the cost of the program reviewed by DOE for NWF fee adequacy has been the cost of constructing and operating the Yucca Mountain Repository. DOE declined to eliminate or reduce the NWF fee. As a result, NEI and the National Association of Regulatory Utility Commissioners have filed suit in federal court seeking suspension of the NWF fee due to the DOE’s motion to withdraw the application. The DOE has also announced the formation of a Blue Ribbon Commission on America’s Nuclear Future to evaluate alternatives for storage of spent nuclear fuel. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.

UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license from 2024 to 2044. If the Callaway nuclear plant’s license is extended, additional spent fuel storage will be required. UE is evaluating the installation of a dry spent fuel storage facility at its Callaway nuclear plant.

Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. It is assumed that the Callaway nuclear plant site will be decommissioned based on the immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are charged toincluded in the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2009, 2008, 2007, and 2006.2007. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest cost study was filed in September 2008 and included the minor tritium contamination discovered on the Callaway nuclear plant site, which did not result in a significant increase in the decommissioning cost estimate. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported as Nuclear Decommissioning Trust Fund in Ameren’s Consolidated Balance Sheet and UE’s Balance Sheet. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, andwith an offsetting adjustment to athe related regulatory asset or regulatory liability, as appropriate.asset.

NOTE 11 - OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders’ equity, except those resulting from transactions with common stockholders. A reconciliation of net income to comprehensive income for the three and nine months ended September 30,March 31, 2010 and 2009, and 2008, is shown below for Ameren, UE, and Genco. CIPS’, CILCO’s, and IP’s comprehensive income was composed of only their respective net income for the Ameren Companies:three months ended March 31, 2010 and 2009.

 

    Three Months  Nine Months 
    2009  2008  2009  2008 

Ameren:(a)

     

Net income

  $229   $215   $542   $581  

Unrealized net gain on derivative hedging instruments, net of taxes of $11, $89, $65 and $26, respectively

   21    157    119    46  

Reclassification adjustments for derivative (gain) included in net income, net of taxes of $15, $23, $59 and $17, respectively

   (29  (40  (106  (29

Reclassification adjustment due to implementation of FAC, net of taxes of $-, $-, $18 and $-, respectively

   -    -    (29  -  

Adjustment to pension and benefit obligation, net of taxes of $-, $-, $7 and $1, respectively

   -    -    (5  (2

Total comprehensive income, net of taxes

  $221   $332   $521   $596  

Less: Net income attributable to noncontrolling interests, net of taxes

   2    11    9    33  

Total comprehensive income attributable to Ameren Corporation, net of taxes

  $219   $321   $512   $563  

UE:

     

Net income

  $142   $99   $248   $287  

Unrealized net gain on derivative hedging instruments, net of taxes of $-, $23, $11 and $12, respectively

   -    38    17    21  

Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $2, $8 and $3, respectively

   -    (4  (13  (5

Reclassification adjustment due to implementation of FAC, net of taxes of $-, $-, $18 and $-, respectively

   -    -    (29  -  

Total comprehensive income, net of taxes

  $142   $133   $223   $303  

CIPS:

     

Net income

  $18   $7   $26   $7  

Total comprehensive income, net of taxes

  $18   $7   $26   $7  

Genco:

     

Net income

  $27   $20   $120   $140  

Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $- and $4, respectively

   -    -    -    (5

Adjustment to pension and benefit obligation, net of taxes (benefit) of $-, $-, $1 and $(2), respectively

   -    -    1    3  

Total comprehensive income, net of taxes

  $27   $20   $121   $138  

CILCORP:

     

Net income (loss)

  $29   $18   $(379 $43  

Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $- and $1, respectively

   -    -    -    (1

Adjustment to pension and benefit obligation, net of taxes of $-, $-, $- and $1, respectively

   -    -    (1  3  

Total comprehensive income (loss), net of taxes

  $29   $18   $(380 $45  

Less: Net income attributable to noncontrolling interests, net of taxes

   1    -    1    1  

Total comprehensive income (loss) attributable to CILCORP Inc., net of taxes

  $28   $18   $(379 $44  

CILCO:

     

Net income

  $37   $24   $101   $62  

Adjustment to pension and benefit obligation, net of taxes of $-, $-, $1 and $3, respectively

   -    -    1    4  

Total comprehensive income, net of taxes

  $37   $24   $102   $66  

IP:

     

Net income (loss)

  $35   $5   $62   $(2

Adjustment to pension and benefit obligation, net of taxes of $-, $-, $-, and $-, respectively

   (1  -    (1  -  

Total comprehensive income (loss), net of taxes

  $34   $5   $61   $(2
    Three Months 
    2010  2009 

Ameren:(a)

   

Net income

  $106   $145  

Unrealized net gain on derivative hedging instruments, net of taxes of $18 and $44, respectively

   28    81  

Reclassification adjustments for derivative (gain) included in net income, net of taxes of $9 and $26, respectively

   (15  (46

Reclassification adjustment due to implementation of FAC, net of taxes of $- and $18, respectively

   -    (29

Adjustment to pension and benefit obligation, net of taxes of $1 and $-, respectively

   (1  -  

Total comprehensive income, net of taxes

  $118   $151  

Less: Net income attributable to noncontrolling interests, net of taxes

   4    4  

Total comprehensive income attributable to Ameren Corporation, net of taxes

  $114   $147  

UE:

   

Net income

  $28   $22  

Unrealized net gain on derivative hedging instruments, net of taxes of $- and $11, respectively

   -    17  

Reclassification adjustments for derivative (gain) included in net income, net of taxes of $- and $8, respectively

   -    (12

Reclassification adjustment due to implementation of FAC, net of taxes of $- and $18, respectively

   -    (29

Total comprehensive income, net of taxes

  $28   $(2

Genco:

   

Net income

  $24   $55  

Reclassification adjustments for derivative (gain) included in net income, net of taxes of $- and $-, respectively

   -    -  

Adjustment to pension and benefit obligation, net of taxes of $2 and $-, respectively

   (1  1  

Total comprehensive income, net of taxes

  $23   $56  

Less: Net income attributable to noncontrolling interest, net of taxes

   1    2  

Total comprehensive income attributable to Ameren Energy Generating Company

  $22   $54  

 

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

NOTE 12 - RETIREMENT BENEFITS

Ameren’s pension and postretirement plans are funded in compliance with income tax regulations and to achieve federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Taking into consideration ourConsidering Ameren’s assumptions at December 31, 2008,2009, its estimated investment performance through September 30, 2009,March 31, 2010, and ourits pension funding policy, Ameren expects to make annual contributions of $100$75 million to $250$225 million in each of the next five years.years, with aggregate estimated contributions of $740 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.

Ameren made contributions to its pension plan during the first nine months of 2009 and 2008 of $47 million and $32 million, respectively. In October 2009, Ameren made an additional $23 million contribution to its pension plan. Ameren made contributions to its postretirement benefit plans during the first nine months of 2009 and 2008 of $23 million and $22 million, respectively.

The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:

 

  Pension Benefits(a) Postretirement Benefits(a)   Pension Benefits(a) Postretirement  Benefits(a) 
  Three Months Nine Months Three Months Nine Months   Three Months Three Months 
      2009         2008         2009         2008         2009         2008         2009         2008           2010         2009         2010         2009     

Service cost

  $17   $15   $51   $44   $5   $5   $15   $14    $17   $17   $5   $5  

Interest cost

   47    46    140    139    16    17    49    52     47    47    16    17  

Expected return on plan assets

   (52  (53  (154  (159  (13  (14  (40  (43   (53  (52  (14  (13

Amortization of:

              

Transition obligation

   -    -    -    -    1    1    2    2     -    -    -    -  

Prior service cost (benefit)

   2    3    6    9    (2  (2  (6  (6   2    2    (2  (2

Actuarial loss

   6    1    18    2    2    2    6    6     5    7    2    3  

Net periodic benefit cost

  $20   $12   $61   $35   $9   $9   $26   $25    $18   $21   $7   $10  

 

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

UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:

 

  Pension Costs Postretirement Costs   Pension Costs  Postretirement Costs
  Three Months  Nine Months Three Months  Nine Months   Three Months  Three Months
      2009          2008          2009          2008         2009          2008          2009          2008           2010          2009          2010          2009    

Ameren(a)

  $20  $12  $61  $35   $9  $9  $26  $25    $18  $21  $7  $10

UE

   12   8   37   27    4   4   11   10     12   13   3   4

CIPS

   2   2   6   5    1   -   2   2     2   3   -   1

Genco

   2   1   5   4    -   -   1   1     3   2   1   1

CILCORP

   2   -   6   (2  -   2   2   2  

CILCO

   3   1   11   3    1   3   5   5     3   4   2   2

IP

   -   -   1   (2  3   3   9   10     -   1   2   3

 

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

Health Care Reform Legislation

During the first quarter of 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Bill of 2010 were enacted and signed into law (collectively, the “Act”) in the United States. The Ameren Companies provide prescription drug benefits to retiree participants. Because the benefits provided are at least actuarially equivalent to benefits available to retirees under the Prescription Drug Act, the Ameren Companies qualify for and receive federal subsidies that mitigate the cost of the benefits. Historically, the subsidies were not subject to tax, and Ameren was allowed to deduct the cost of the benefits. The Act includes a provision that disallows federal income tax deductions for retiree health care costs to the extent an employer’s postretirement health care plan receives these federal subsidies. Although this change does not take effect immediately, the Ameren Companies are required to recognize the full tax accounting impact in their financial statements in the period in which the legislation is signed into law. As a result, in the first quarter of 2010, Ameren, UE, CIPS, Genco, CILCO, and IP recorded total non-cash after-tax charges of $13 million, $5 million, $1 million, $3 million, less than $1 million, and less than $1 million to reduce deferred tax assets. The reduction of these income tax deductions is also estimated to increase Ameren’s, UE’s, CIPS’, Genco’s, CILCO’s, and IP’s total annual income tax expense by approximately $2 million to $3 million, $1 million to $2 million, less than $1 million, less than $1 million, less than $1 million, and less than $1 million, respectively. Although many of the specifics associated with the Act have not yet been addressed, it is our preliminary view that the other provisions of the Act do not have a material impact on our current financial results. We will continue to study the potential future effects of this Act as further clarity is provided.

NOTE 13 - SEGMENT INFORMATION

Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Merchant Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 -1- Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI (which in February 2008 was transferred to Resources Company through an internal reorganization).Policies. The Illinois Regulated segment for Ameren consists of the regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 -1- Summary of Significant Accounting Policies.Policies, and AITC. The Merchant Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company (until March 4, 2010, when CILCORP merged with and into Ameren), AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities.

UECILCO has one reportable segment: Missouri Regulated. The Missouri Regulated segment for UE includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s former 40% interest in EEI.

CILCORP and CILCO have two reportable segments: Illinois Regulated and Merchant Generation. The Illinois Regulated segment for CILCORP and CILCO consists of the regulated electric and gas transmission and distribution businesses of CILCO.businesses. The Merchant Generation segment for CILCORP and CILCO consists of the generation business of AERG. For CILCORP and CILCO, Other comprises minor activities not reported in the Illinois Regulated or Merchant Generation segments for CILCORP.

The following tables present information about the reported revenues and specified items included in net income of Ameren UE, CILCORP, and CILCO for the three and nine months ended September 30,March 31, 2010 and 2009, and 2008, and total assets as of September 30, 2009,March 31, 2010, and December 31, 2008.2009.

Ameren

 

Three Months  Missouri
  Regulated  
 Illinois
  Regulated  
  Merchant
  Generation  
       Other       Intersegment
Eliminations
 Consolidated   Missouri
  Regulated  
  Illinois
  Regulated  
  Merchant
  Generation  
        Other       Intersegment
Eliminations
 Consolidated

2010:

          

External revenues

  $677  $885  $354  $-   $-   $1,916 

Intersegment revenues

   5   2   74   3    (84  

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

   27   33   44   (2  -    102 

2009:

                  

External revenues

  $829   $638  $346   $2   $-   $1,815    $648  $928  $336  $4   $-   $1,916 

Intersegment revenues

   7    7   87    4    (105  -     7   8   116   4    (135  

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

   141    57   37    (8  -    227  

2008:

        

External revenues

  $865   $724  $478   $(7 $-   $2,060  

Intersegment revenues

   10    7   114    3    (134  -  

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

   98    13   108    (15  -    204  
Nine Months                     

2009:

        

External revenues

  $2,222   $2,184  $997   $12   $-   $5,415  

Intersegment revenues

   21    21   309    14    (365  -  

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

   244    97   205    (13  -    533  

2008:

        

External revenues

  $2,340   $2,487  $1,110   $(6 $-   $5,931  

Intersegment revenues

   30    30   341    11    (412  -  

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

   272    15   284    (23  -    548  

As of September 30, 2009:

        

Net income attributable to Ameren Corporation(a)

   21   25   93   2    -    141 

As of March 31, 2010:

          

Total assets

  $12,257   $7,302  $5,054   $1,226   $(2,245 $23,594    $12,073  $7,412  $4,947  $1,118   $(1,862 $23,688 

As of December 31, 2008:

        

As of December 31, 2009:

          

Total assets

  $11,524   $7,079  $4,622   $1,227   $(1,795 $22,657    $12,301  $7,344  $4,921  $1,657   $(2,433 $23,790 

 

(a)Represents net income (loss) available to common stockholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

UECILCO

 

Three Months  Missouri
  Regulated  
            Other(a)                          UE               

2009:

    

Revenues

  $836   $-   $836  

Net income(b)

   141    -    141  

2008:

    

Revenues

  $875   $-   $875  

Net income(b)

   98    -    98  
Nine Months             

2009:

    

Revenues

  $2,243   $-   $2,243  

Net income(b)

   244    -    244  

2008:

    

Revenues

  $2,370   $-   $2,370  

Net income(b)

   272    11    283  

As of September 30, 2009:

    

Total assets

  $12,257   $-   $12,257  

As of December 31, 2008:

    

Total assets

  $11,524   $-   $11,524  
Three Months  Illinois
  Regulated  
  Merchant
  Generation  
  

CILCO

      Other      

  

Intersegment

Eliminations

  

Consolidated

CILCO

2010:

         

External revenues

  $206  $92  $  $   $298 

Intersegment revenues

   -   -          

Net income(a)

   7   12          19 

2009:

         

External revenues

  $219  $92  $  $   $311 

Intersegment revenues

   -   -          

Net income(a)

   7   26          33 

As of March 31, 2010:

         

Total assets

  $1,291  $1,083  $  $   $2,374 

As of December 31, 2009:

         

Total assets

  $1,264  $1,119  $  $(1 $2,382 

 

(a)Included 40% interest in EEI through February 29, 2008.
(b)Represents net income available to the common stockholder (Ameren).

CILCORP

Three Months  Illinois
  Regulated  
  Merchant
  Generation  
  

CILCORP

      Other      

  

Intersegment

Eliminations

  

Consolidated

CILCORP

 

2009:

      

External revenues

  $133   $118   $-   $-   $251  

Intersegment revenues

   1    -    -    (1  -  

Net income(b)

   7    21    -    -    28  

2008:

      

External revenues

  $162   $102   $-   $-   $264  

Intersegment revenues

   1    -    -    (1  -  

Net income(b)

   4    14    -    -    18  
Nine Months                     

2009:

      

External revenues

  $480   $314   $-   $-   $794  

Intersegment revenues

   1    -    -    (1  -  

Goodwill impairment(a)

   (117  (345  -    -    (462

Net loss(b)

   (102  (278  -    -    (380

2008:

      

External revenues

  $590   $252   $-   $-   $842  

Intersegment revenues

   3    -    -    (3  -  

Net income(b)

   15    27    -    -    42  

As of September 30, 2009:

      

Total assets

  $1,367   $1,357   $2   $(217 $2,509  

As of December 31, 2008:

      

Total assets

  $1,402   $1,680   $2   $(219 $2,865  

(a)See Note 14 - Goodwill Impairment for further information.
(b)Represents net income (loss) available to the common stockholder (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

CILCO

Three Months  Illinois
  Regulated  
  Merchant
  Generation  
  

CILCO

      Other      

  

Intersegment

Eliminations

  

Consolidated

CILCO

 

2009:

        

External revenues

  $133  $118  $-   $-   $251  

Intersegment revenues

   1   -   -    (1  -  

Net income(a)

   7   29   -    -    36  

2008:

        

External revenues

  $162  $102  $-   $-   $264  

Intersegment revenues

   1   -   -    (1  -  

Net income(a)

   4   20   -    -    24  
Nine Months                     

2009:

        

External revenues

  $480  $314  $-   $-   $794  

Intersegment revenues

   1   -   -    (1  -  

Net income(a)

   15   85   -    -    100  

2008:

        

External revenues

  $590  $252  $-   $-   $842  

Intersegment revenues

   3   -   -    (3  -  

Net income(a)

   15   46   -    -    61  

As of September 30, 2009:

        

Total assets

  $1,294  $1,109  $-   $-   $2,403  

As of December 31, 2008:

        

Total assets

  $1,212  $1,081  $-   $1   $2,294  

(a)Represents net income (loss) available to the common stockholder (CILCORP)(CILCORP until March 4, 2010, Ameren beginning March 4, 2010); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

NOTE 14 - GOODWILL IMPAIRMENTCORPORATE REORGANIZATION

We evaluate goodwill for impairment as of October 31 of each year, or more frequently if eventsOn March 15, 2010, Ameren, CIPS, CILCO, IP, AERG and circumstances indicate that the asset might be impaired. Goodwill impairment testing isResources Company filed an application with FERC requesting certain FERC authorizations related to a two-step process.corporate reorganization. The first step involves a comparison of the estimated fair value of a reporting unitreorganization would merge CILCO and IP with its carrying amount. Ifand into CIPS (the “Merger”), after which the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, the second step is performed to measure the amount of impairment, if any.surviving corporation would be renamed “Ameren Illinois Company” (“Ameren Illinois”). The second step of the goodwill impairment test comparesreorganization would involve the implied fair valuedistribution of AERG stock from Ameren Illinois to Ameren (the “AERG distribution”) and the subsequent contribution by Ameren of the reporting unit’s goodwillAERG stock to Resources Company.

On March 15, 2010, CIPS, CILCO and IP filed with the carryingICC a notice of merger and reorganization to notify the ICC of their intent to effect the Merger and CIPS filed a notice of its intent to effect the AERG distribution. The Merger and the AERG distribution are expressly authorized by the Illinois Public Utilities Act and do not require ICC approval.

CIPS, CILCO and IP do not expect to redeem any of their outstanding long-term debt or preferred stock prior to or in connection with the Merger, with the exception of CILCO’s preferred stock and the $40 million principal amount of CIPS’ 7.61% Series 97-2 first mortgage bonds. Following the redemption of those CIPS’ mortgage bonds, CIPS intends to cause a release date to occur with respect to CIPS’ senior secured notes, causing these notes to become unsecured and CIPS’ mortgage indenture to be discharged. If the Merger is consummated, the debt and other obligations of CILCO and IP under their mortgage indentures, senior note indentures and pollution control bond agreements will become debt and obligations of Ameren Illinois, and the property owned by CILCO and IP immediately before the Merger that goodwill. was subject to the lien of one of their respective mortgage indentures will still be subject to such lien and secure the bonds outstanding under such mortgage indenture subject to the release and other provisions of such mortgage indenture.

The implied fair valuesenior secured notes of goodwill is determinedIP and CILCO will still be secured by allocating the estimated fair valuemortgage bonds held by their respective senior note trustee subject to the release and other provisions of the reporting unit to the estimated fair valuerespective senior note indenture. The debt and other obligations of its existing assetsCIPS will remain debt and liabilities in a manner similar to a purchase price allocation. The unallocated portionobligations of the estimated fair value of the reporting unit is the implied fair value of goodwill.Ameren Illinois. If the implied fair valueMerger is consummated, it is expected that Ameren Illinois will secure the CIPS senior notes with the benefit of goodwilla lien under the IP mortgage indenture so long as Ameren Illinois has outstanding other senior notes with the benefit of this lien. After the Merger, Ameren Illinois is less than the carrying amount, an impairment loss, equivalentalso expected to the difference, is recorded as a reduction of goodwill and a charge to operating expense.

The goodwill impairment test that we performed in the fourth quarter of 2008 did not result in the second step assessment; the test indicated no impairment of Ameren’s, CILCORP’s, or IP’s goodwill. However, the estimated fair values of both of CILCORP’s reporting units (Illinois Regulated and Merchant Generation) exceeded carrying values by a nominal amount. We concluded that events had occurred and circumstances had changed during the first quarter of 2009, which required us to perform an interim goodwill impairment test. The following triggering events resulted in the need for us to perform an impairment test:

A significant decline in Ameren’s market capitalization.

The continuing decline in market prices for electricity.

A decrease in observable industry market multiples.

The fair value of Ameren’s, CILCORP’s and IP’s reporting units was estimated based on a risk-adjusted, probability-weighted discounted cash flow model that considered multiple operating scenarios. Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year future cash flows, and an exit value based on observable industry market multiples. For the interim test conducted as of March 31, 2009, the discount rate used was 3.8%, based on the 20-year treasury yield. To assess the reasonableness of the estimated fair values, the sum of the estimated fair values of the Ameren reporting units is reconciled to our current market capitalization plus an estimated control premium. We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, the regulatory environment, and operating costs.

CILCORP’s Illinois Regulated reporting unit and CILCORP’s Merchant Generation reporting unit both failed step one of the March 31, 2009, impairment test, as each reporting unit’s carrying value exceeded its estimated fair value. Therefore, in order to measure the amount of any goodwill impairment in step two, we estimated individually the implied fair value of CILCORP’s Illinois Regulated goodwill and CILCORP’s Merchant Generation goodwill. We determined that the implied fair value of goodwill was less than the carrying amount of goodwill for both reporting units, indicating that CILCORP’s Illinois Regulated goodwill and CILCORP’s Merchant Generation goodwill was impaired as of March 31, 2009. Based on the results of step two of the impairment test, CILCORP recorded a noncash impairment charge of $462 million, which representedencumber substantially all of the goodwill assignedoperating property owned by CIPS immediately before the Merger with the lien of the IP mortgage indenture. On April 13, 2010, CIPS, CILCO and IP entered into a merger agreement to CILCORP’s Merchant Generation reporting unitaccomplish the Merger.

Pursuant to the merger agreement, at the effective time of $345 millionthe Merger: (i) all shares of each series of IP preferred stock outstanding immediately prior to the effective time of the Merger will be automatically converted into shares of a newly created series of Ameren Illinois preferred stock having the same payment and $117 million assignedredemption terms as the existing series of IP preferred stock, except to CILCORP’sthe extent that IP preferred shareholders exercise their dissenters’ rights in accordance with Illinois Regulated reporting unit.law; and (ii) each outstanding share of CIPS common and preferred stock will remain outstanding, except to the extent that CIPS preferred shareholders exercise their dissenters’ rights in accordance with Illinois law. Prior to the Merger, but after consenting to the Merger, Ameren will contribute to the capital of IP, without the payment of any consideration, all of the IP preferred stock owned by Ameren.

Consummation of the Merger is subject to certain customary conditions, including obtaining shareholder approval, which approval is expected to be provided by Ameren, and obtaining any required approvals from FERC. The step two test indicatedmerger agreement may be terminated at any time prior to closing upon the mutual written consent of CIPS, CILCO and IP or other specified circumstances.

We filed a request on April 21, 2010, for a private letter ruling from the Internal Revenue Service substantially to the effect that the implied fair valueAERG distribution will qualify as a generally tax-free transaction for United States federal income tax purposes. The AERG distribution is expected to occur immediately after the Merger. However, in the event that we have not received the ruling prior to the consummation of goodwill relatingthe Merger, we reserve the right to CILCORP’s Illinois Regulated reporting unit was $80 million.consummate the AERG distribution without such ruling or at a later time.

The goodwill impairment loss recorded by CILCORP was not reflected atMerger is intended to be completed on or before October 1, 2010. There can be no assurances regarding whether the consolidated Ameren level because ofMerger or the aggregation of reporting units. Ameren’s reporting units and IP’s reporting unit did not require a second step assessment;AERG distribution will be completed or as to the results of the step one tests indicated no impairment of goodwill as of March 31, 2009. However, the estimated fair values of Ameren’s Illinois Regulated reporting unit, Ameren’s Merchant Generation reporting unit, and IP’s Illinois Regulated reporting unit exceeded carrying values by a nominal amount as of March 31, 2009. The estimated fair value of Ameren’s Illinois Regulated reporting unit exceeded its carrying value by approximately $210 million, or 5% of its carrying value. The estimated fair value of Ameren’s Merchant Generation reporting unit exceeded its carrying value by approximately $35 million, or 1% of its carrying value. The estimated fair value of IP’s Illinois Regulated reporting unit exceeded its carrying value by approximately $100 million, or 4% of its carrying value. As a result, the failure in the futuretiming of any reporting unit to achieve forecasted operating results and cash flowssuch transaction or a further decline of observable industry market multiples may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge.

Ameren, CILCORP and IP will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, market prices for electricity and observable industry market multiples of their reporting units for signs of possible declines in estimated fair value and potential goodwill impairment. No triggering events were identified in the third quarter of 2009, and therefore, no interim impairment test was performed.

The following tables detail how goodwill has been assigned to the registrants’ reporting units and changes to the carrying amount of goodwill as of September 30, 2009:

Amerenaction.

 

    

Missouri

Regulated

  

Illinois

Regulated

  

Merchant

Generation

  Total(a)

Balance at December 31, 2008

  $-  $411  $420  $831

Impairment loss recorded in first quarter

   -   -   -   -

Balance at September 30, 2009

  $-  $411  $420  $831

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

CILCORP

    

Missouri

Regulated

  

Illinois

Regulated

  

Merchant

Generation

  Total 

Balance at December 31, 2008

  $-  $197   $345   $542  

Impairment loss recorded in first quarter

   -   (117  (345  (462)     

Balance at September 30, 2009

  $-  $80   $-   $80  

 

IP

 

      
    

Missouri

Regulated

  

Illinois

Regulated

  

Merchant

Generation

  Total 

Balance at December 31, 2008

  $-  $214   $-   $214  

Impairment loss recorded in first quarter

   -   -    -    -  

Balance at September 30, 2009

  $-  $214   $-   $214  

ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors contained in the Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of the various segments of our business to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole.

OVERVIEW

Ameren Executive Summary

Ameren’s earnings in the thirdfirst quarter of 20092010 of $102 million, or $0.43 per share, were higherlower than its earnings in the 2008 comparable period, while Ameren’s earnings were lower in the first nine monthsquarter of 2009 than itsof $141 million, or $0.66 per share. The decline in first quarter 2010 earnings, incompared to the 2008 comparable period. Ameren’s earnings in

year-ago quarter, was primarily the three and nine months ended September 30, 2009, wereresult of reduced by lower electricity sales in Ameren’s rate-regulated utilities and lower margins in theAmeren’s Merchant Generation segment as a result of much cooler summer weatherlower power prices and weak economic conditions. Higher interesthigher fuel and related transportation costs, higher depreciation expense employee separation programs, and financing costs, a $13 million charge for the retirementimpact on deferred taxes of two generating unitschanges in the Merchant Generation segment, among other items, also decreased earningsfederal health care laws, and an unfavorable change in 2009.net unrealized MTM activity on derivatives. Offsetting factors in the three and nine months ended September 30, 2009, included utility rate adjustments in Illinois and Missouri, lower operations and maintenance expenses, and favorable unrealized MTM activity on derivatives, among other items.

In the thirdfirst quarter of 2010 were colder winter weather and an emerging economic recovery, which resulted in higher first quarter of 2010 utility electric and natural gas sales compared with those in the year-ago quarter. Earnings also benefited from the March 1, 2009, atUE electric rate increase being in place for the entire first quarter in 2010.

At Ameren’s rate-regulated utilities, much cooler summercolder winter weather and improvement in the economic slowdowneconomy led to a 10% decrease7% increase in first-quarter 2010 kilowatthour sales to residential customers and a 3% decrease in kilowatthour sales to commercial customers, compared with sales during the year-ago quarter. These sales changes were more modest on a weather-normalized basis, with residential sales decliningfirst quarter of 2009. The impact of an estimated 2% and commercial sales declining an estimated 1%. Cooling degree-daysimproving economy was also evident in the thirdlevel of kilowatthour sales to industrial customers of Ameren’s rate-regulated utilities, especially in Illinois. Industrial sales advanced 2%, compared to sales during the first quarter of 2009, were 18% below those of the third quarter of 2008 and 23% below normal. The weak economy continued to affect kilowatthour sales by Ameren’s rate-regulated businesses to their industrial customers. These sales declined 13% from the year-ago quarter, excluding the

impact of reduced sales to Noranda.UE’s largest customer, Noranda’s smelter plant in New Madrid, Mo. Noranda’s plant sustained damage because of a power interruption on non-Ameren-owned power lines during a severe ice storm in January 2009 ice storm. Including Noranda, electric2009. Electric sales to the plant have gradually increased since that incident and have now returned to full capacity. Electric sales to industrial customers, declined 18%including Noranda, increased 10% in the thirdfirst quarter of 2009, as2010, compared with sales during the first quarter of 2009.

With respect to the year-ago quarter. Noranda announced in September 2009 that it had initiated steps to return operations, to full effective capacity. These steps include restarting the third of its three production lines. Ameren expects it will take some time for the third production line to be repaired andUE’s Taum Sauk pumped-storage hydroelectric facility returned to full capacity. Ameren expects full year 2009 electricity salesservice in April 2010. After extensive testing, the 440-megawatt plant was released for operations by FERC in early April 2010. In addition, all in-service criteria from the MoPSC were met on April 15, 2010. UE’s Callaway nuclear plant’s scheduled refueling and maintenance outage commenced on April 17, 2010, and is expected to industrial customers of Ameren’s rate-regulated utilities will be down approximately 11%, excluding Noranda. Ameren currently believes sales declines associated with industrial customers are slowing and expects growthlast 35 days, returning to service in 2010, though at a pace less than what is typical coming out oftime to serve summer demand.

The ICC issued an economic recession. On a weather-normalized basis, Ameren expects full year 2009 sales to residential and commercial customers to be down approximately 1% to 2% as compared to 2008. In 2010, Ameren expects a resumption of growthorder in residential and commercial sales, assuming a moderate economic recovery.

Ameren has rate cases pending in its Illinois and Missouri jurisdictions seeking revenue levels that reflect the significant investments made in electric and gas utility infrastructure to improve reliability, increases in costs essential to generating and delivering electricity, higher financing costs and, in Missouri, rising net fuel costs. The Ameren Illinois Utilities filed requests with the ICC in June 2009 to increase their annual revenues forUtilities’ electric and natural gas delivery services.rate cases on April 29, 2010. The currently pending requests,order, as amended, seek to increase annual revenues from electric and natural gas delivery servicecorrected by $162 million in the aggregate. In addition,ICC on May 6, 2010, authorized the Ameren Illinois Utilities have requested a rider mechanism that would permit recoveryto increase revenue by an aggregate of ICC reliability audit expenditures.$15 million annually, as calculated by the ICC. This is well below the Ameren Illinois Utilities’ revised request of $130 million and the $56 million proposed by the ICC’s administrative law judges. The Ameren Illinois Utilities estimate that theyare disappointed in the decision and are taking action to mitigate its effects. The Ameren Illinois Utilities’ responses include requesting an ICC stay of certain decisions in its order and rehearing of the rate order. The Ameren Illinois Utilities will incur distribution-related implementation costs of $15 million (CIPS - $5 million, CILCO - $3 million,also reduce planned spending to levels more closely in-line with the revenue and IP - $7 million) in 2010. If approved,related cash flow levels authorized by the rider mechanism would recover future reliability audit expenditures as well. The ICCrate order.

In Missouri, the MoPSC is expected to issue ana rate order in time for new ratesresponse to be effectiveUE’s pending electric rate increase request in earlylate May 2010. UE filedrecently revised its request to reflect updated cost levels and stipulations resolving various revenue requirement issues throughout the case. UE’s current request is $287 million. This rate increase request is driven by the significant investments UE has made in its electric infrastructure to maintain and improve the reliability of its system for its customers, consistent with customer expectations. The request also reflects the higher net fuel, operations and financing costs that UE is experiencing.

For several years, Ameren’s rate-regulated utility businesses have been earning returns on investment that are well below their authorized levels, in part, due to regulatory lag. Ameren remains committed to improving earnings to levels that represent fair returns on its regulated investments. To achieve fair returns, Ameren remains focused not only on pursuing constructive regulatory outcomes, including mechanisms that reduce regulatory lag, but also on closely aligning its spending and investment with the MoPSClevel of rates, related cash flows and returns authorized by the respective state commissions.

Ameren’s Merchant Generation segment has reduced its estimated capital costs for an annual electric revenue increase of $402 million. More than half of the request is for anticipated increasesperiod 2010 to 2014 by $435 million, compared to those disclosed in normalized net fuel costs. These increased net fuel costs would have been eligible for recoverythe Form 10-K. The Merchant Generation segment expects to fully comply with the MPS through the FAC absent this filing. As partuse of dry sorbent injection SO2 reduction technology at its overall request, UE has asked for interim rate reliefJoppa power plant and the installation of $37 million, subject to refundscrubbers at its Newton power plant by 2015. Ameren’s Merchant Generation segment announced in May 2010 that it will reduce staffing by approximately 75 positions. The reduction of these positions, coupled with interest. The MoPSC established a schedule for considering the interim increase request, and a hearingother planned spending reductions, is set for December 2009. In the overall rate case, new rates are expected to be effective in late June 2010.

Ameren is focused on delivering shareholder value in the years to come. In that regard, Ameren has taken several steps to position the Company for future success. Through the rate proceedings discussed above, Ameren is seeking to recover increased costs in Ameren’s rate-regulated businesses to narrow the gap between their earned and allowed returns. Ameren has set operating cost targets forreduce 2010 and has implemented several measures to control costs. Ameren expects its rate-regulated businesses’ 2010 nonfuel operatingother operations and maintenance expenses to be at a level consistent with that of 2008. Further, Ameren’s rate-regulated utilities have identified, and are carefully evaluating for possible elimination or deferral, approximately $1 billion of previously planned capital expenditures scheduled for the 2010 through 2013 period. Ameren expects that Merchant Generation’s nonfuel$300 million in 2010. This is approximately 10% lower than other operations and maintenance expenses will decline by 5% to 10% in 2010, as compared to the 2008 level.2009. As these recent cost cutting actions again demonstrate, Ameren remains focused on minimizing costs, both operating and capital, at its Merchant Generation also eliminated approximately $1 billion in capital expenditures from the 2010 through 2013 period, as compared to prior plans.business.

LiquidityOutlook

Ameren has taken actions in 2009is taking steps to maintain and enhance its liquidity position and credit profile. In June 2009, Ameren and certain of its subsidiaries entered into multiyear credit facility agreements that provide Ameren and its business segments with substantial borrowing capacity throughimprove the middle of 2011. These credit facilities cumulatively provide $2.1 billion of credit through July 14, 2010, thereafter reducing to $1.8795 billion through June 30, 2011, and thereafter reducing to $1.0795 billion through July 14, 2011. In September 2009, Ameren issued and sold 21.9 million shares of its common stock for net proceeds of $535 million. Ameren used the net offering proceeds to make investments inearnings from its rate-regulated utility subsidiaries inbusinesses over time by narrowing the formgap between earned and authorized returns on investments and making disciplined investments to improve reliability and promote a cleaner environment, consistent with customers’ expectations and sound energy policy. Further, Ameren continues to take actions to ensure that its Merchant Generation segment remains well-positioned during this period of capital contributions.

At September 30, 2009, Ameren, on a consolidated basis, had available liquidity, in the form of cash on handlow power prices and amounts available under its existing credit facilities, of approximately $2.2 billion, which was approximately $1 billion higher than the same time last year.benefits from an expected power price recovery.

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission, and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren and CILCORP holding companies depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.

 

UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

 

CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

 

Genco operates a merchant electric generation business in Illinois and Missouri. Genco has an 80% ownership interest in EEI.

 

CILCO is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a merchant electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business, all in Illinois.

 

IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

Ameren, through Genco, has an 80% ownership interest in EEI. Ameren and Genco consolidate EEI for financial reporting purposes. Effective January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% stock ownership interest in EEI to Genco through a capital contribution. The transfer of EEI to Genco was accounted for as a transaction between entities under common control, whereby Genco accounted for the transfer at the historical carrying value of the parent (Ameren) as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in EEI included purchase accounting adjustments relating to Ameren’s acquisition of an additional 20% ownership interest in EEI in 2004. This transfer required Genco’s prior period financial statements to be retrospectively combined for all periods presented. Consequently, Genco’s prior period consolidated financial statements reflect EEI as if it had been a subsidiary of Genco.

On April 13, 2010, CIPS, CILCO and IP entered into a merger agreement under which CILCO and IP will be merged with and into CIPS as part of a two-step corporate reorganization of Ameren. The second step of the reorganization would involve the distribution of AERG common stock to Ameren and the subsequent contribution by Ameren of the AERG common stock to Resources Company. See Note 14 - Corporate Reorganization under Part I, Item 1, of this report for additional information.

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding during the applicable period. All tabular dollar amounts are in millions, unless otherwise indicated.

RESULTS OF OPERATIONS

Earnings Summary

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Merchant Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil for fuel in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery service businesses, purchased power cost recovery mechanisms for our Illinois electric delivery service businesses, and a FAC for our Missouri electric utility business. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, for a discussion of UE’s pending electric rate casescase in Missouri as well as the combined electric and natural gas delivery service rate order issued in April 2010 for the Ameren Illinois including UE’s request for approval to implement an environmental cost recovery mechanism and to continue its FAC.Utilities. Fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems and the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Net income attributable to Ameren Corporation increaseddecreased to $227$102 million, or $1.04 per share, in the third quarter of 2009, from $204 million, or 9743 cents per share, in the thirdfirst quarter of 2008.2010, from $141 million, or 66 cents per share, in the first quarter of 2009. Net income attributable to Ameren Corporation in the thirdMerchant Generation segment declined by $49 million from the same period in 2009, while net income attributable to Ameren Corporation in the first quarter of 20092010 increased in the Illinois Regulated and Missouri Regulated segments by $44$8 million and $43$6 million, respectively, from the prior-year period, while net income attributable to Ameren Corporationperiod.

Compared with the first quarter of 2009, first quarter 2010 earnings were negatively affected primarily by the following items:

lower realized electric margins in the Merchant Generation segment decreased by $71 million fromlargely due to lower realized revenue per megawatthour sold and higher fuel and related transportation costs (24 cents per share);

higher dilution along with higher financing costs as a result of both incremental borrowings and higher interest rates (7 cents per share);

a charge for the same periodimpact on deferred taxes of changes in 2008.federal health care laws (6 cents per share);

unfavorable net unrealized MTM activity on energy-related transactions (5 cents per share); and

Net income attributable

increased depreciation and amortization expenses primarily due to Ameren Corporation decreased to $533 million, or $2.48the impact of the January 2009 MoPSC electric rate order for UE and capital additions at the Merchant Generation segment (4 cents per share, inshare).

Compared with the first nine monthsquarter of 2009, from $548 million, or $2.61 per share, infirst quarter 2010 earnings were favorably affected primarily by the first nine months of 2008. Net income attributable to Ameren Corporation increased in the Illinois Regulated segment by $82 million in the first nine months of 2009 compared with the prior-year period, while net income attributable to Ameren Corporation in the Missouri Regulated and Merchant Generation segments decreased by $28 million and $79 million, respectively, from the same period in 2008.

Earnings were negatively impacted in the third quarter and first nine months of 2009 as compared with the same periods in 2008 by:following items:

 

the favorable impact on electric and natural gas margins atin our rate-regulated businesses of higher net fuel costs at UE and lower demand (exclusive of weather impacts)impacts and higher sales to Noranda discussed below), partially caused by the emerging economic recovery, among other things (3 cents per share and 38 cents per share, respectively);

higher dilution and financing costs (12 cents per share and 21 cents per share, respectively);

unfavorable weather conditions (estimated at 12 cents per share and 10 cents per share, respectively);

increased depreciation and amortization expense (3 cents per share and 9 cents per share, respectively);

reduced sales to Noranda because of an extended storm-related outage (3 cents per share and 9 cents per share, respectively);

increased expense related to workforce reductions through voluntary and involuntary separation programs as well as other charges (6 cents per share for each period); and

increased taxes other than income taxes primarily because of higher property taxes (2 cents per share and 4 cents per share, respectively).

Earnings were favorably impacted in the third quarter and first nine months of 2009 as compared with the same period in 2008 by:

higher electric and natural gas delivery service rates, effective October 1, 2008, in the Illinois Regulated segment pursuant to an ICC consolidated rate order for CIPS, CILCO and IP (14 cents per share and 40 cents per share, respectively)share);

 

higher electric rates, effective March 1, 2009, in the Missouri Regulated segment pursuant to athe 2009 MoPSC electric rate order (16 cents per share and 31 cents per share, respectively);

decreased plant operations and maintenance expense (1 cent per share and 13 cents per share, respectively);

favorable net unrealized MTM activity on derivatives (13 cents per share and 5 cents per share, respectively); and

the reduced impact in 2009 of the electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the Illinois electric settlement agreement (1 cent per share and 4 cents per share, respectively).

In addition to the above items affecting both periods, earnings were negatively impacted in the third quarter of 2009 as compared with the third quarter of 2008 by lower electric margins in the Merchant Generation segment (7 cents per share).

In addition to the above items affecting both periods, earnings were favorably impacted in the third quarter of 2009 as compared with the third quarter of 2008 by the redesigned seasonal natural gas delivery service rates at the Ameren Illinois Utilities (4 cents per share). These redesigned delivery service rates impacted quarterly earnings but did not materially impact annual results.

In addition to the above items affecting both periods, earnings were negatively impacted in the first nine months of 2009 as compared with the first nine months of 2008 by:

the absence in 2009 of a settlement agreement reached with a coal mine owner that reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation incurred in 2008 and expected to be incurred in 2009 due to the premature closure of an Illinois mine at the end of 2007 (18 cents per share);

 

the absence in 2009impact of storm costs recorded as a regulatory asset as a result of an accounting order issued by the MoPSC (4colder winter weather conditions on energy demand (estimated at 3 cents per share); and

 

increased distribution system reliability expenditureshigher sales to Noranda as its smelter plant in southeast Missouri gradually returned to full capacity by end of the quarter after a January 2009 severe ice storm significantly reduced the plant’s capacity (3 cents per share).

The cents per share information presented above is based on average shares outstanding in the thirdfirst quarter of 2009. For further details regarding the first quarter 2010 earnings, including explanations of Margins, Other Operations and first nine monthsMaintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Interest Charges, and Income Taxes, see the major headings in Results of 2008.Operations below.

Because it is a holding company, net income and cash flows attributable to Ameren Corporation are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORPCILCO and IP. The following table presents the contribution by Ameren’s principal subsidiaries to net income attributable to Ameren Corporation for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:

 

  Three Months  Nine Months   Three Months
      2009         2008          2009         2008           2010          2009    

Net income (loss):

      

Net income:

    

UE

  $141   $98  $244   $283(a)   $27  $21

CIPS

   17    6   24    5     9   6

Genco

   27    20   120    140     23   53

CILCORP

   28    18   (380)(b)   42  

CILCO

   19   33

IP

   34    4   60    (4   18   13

Other(c)(a)

   (20  58   465(b)   82     6   15

Net income attributable to Ameren Corporation

  $227   $204  $533   $548    $102  $141

 

(a)Includes earnings from a 40% interest in EEI through February 29, 2008.
(b)Includes goodwill impairment loss of $462 million offset by intercompany elimination in Other as no impairment was recognized at the consolidated Ameren level. See Note 14 - Goodwill Impairment under Part I, Item 1, of this report for additional information.
(c)Includes earnings from EEI, other merchant generation operations, as well as corporate general and administrative expenses, and intercompany eliminations. Includes a 40% interest in EEI through February 29, 2008, and an 80% interest in EEI since that date.

Below is a table of income statement components by segment for the three and nine months ended September 30, 2009March 31, 2010 and 2008:2009:

 

    Missouri
Regulated
  Illinois
Regulated
  Merchant
Generation
  

Other /
Intersegment

Eliminations

  Total 

Three Months 2009:

      

Electric margin

  $636   $260   $224   $(3 $1,117  

Gas margin

   11    69    -    (1  79  

Other revenues

   1    -    -    (1  -  

Other operations and maintenance

   (229  (117  (86  10    (422

Depreciation and amortization

   (90  (55  (34  (6  (185

Taxes other than income taxes

   (72  (26  (7  1    (104

Other income and (expenses)

   13    -    1    (1  13  

Interest expense

   (61  (37  (34  (2  (134

Income taxes

   (67  (36  (28  (4  (135

Net income (loss)

   142    58    36    (7  229  

Noncontrolling interest and preferred dividends

   (1  (1  1    (1  (2

Net income (loss) attributable to Ameren Corporation

   141    57    37    (8  227  

Three Months 2008:

      

Electric margin

  $570   $234   $315   $(23 $1,096  

Gas margin

   10    50    -    (1  59  

Other revenues

   1    -    -    (1  -  

Other operations and maintenance

   (234  (154  (79  11    (456

Depreciation and amortization

   (83  (55  (27  (8  (173

Taxes other than income taxes

   (69  (24  (6  1    (98

Other income and (expenses)

   15    3    (1  (4  13  

Interest expense

   (51  (34  (24  (4  (113

Income taxes

   (60  (5  (61  13    (113

Net income (loss)

   99    15    117    (16  215  

Noncontrolling interest and preferred dividends

   (1  (2  (9  1    (11

Net income (loss) attributable to Ameren Corporation

   98    13    108    (15  204  

Nine Months 2009:

      

Electric margin

  $1,581   $676   $770   $(13 $3,014  

Gas margin

   52    252    -    (1  303  

Other revenues

   3    4    -    (7  -  

Other operations and maintenance

   (665  (406  (248  25    (1,294

Depreciation and amortization

   (266  (162  (93  (20  (541

Taxes other than income taxes

   (200  (90  (21  -    (311

Other income and (expenses)

   37    3    1    (6  35  

Interest expense

   (171  (118  (82  (5  (376

Income taxes

   (123  (58  (121  14    (288

Net income (loss)

   248    101    206    (13  542  

Noncontrolling interest and preferred dividends

   (4  (4  (1  -    (9

Net income (loss) attributable to Ameren Corporation

   244    97    205    (13  533  

Nine Months 2008:

      

Electric margin

  $1,606   $600   $911   $(40 $3,077  

Gas margin

   55    239    -    (4  290  

Other revenues

   1    -    -    (1  -  

Other operations and maintenance

   (689  (462  (250  40    (1,361

Depreciation and amortization

   (246  (165  (81  (21  (513

Taxes other than income taxes

   (189  (91  (20  -    (300

Other income and (expenses)

   40    10    -    (12  38  

Interest expense

   (142  (106  (74  (9  (331

Income taxes

   (160  (5  (177  23    (319

Net income (loss)

   276    20    309    (24  581  

Noncontrolling interest and preferred dividends

   (4  (5  (25  1    (33

Net income (loss) attributable to Ameren Corporation

   272    15    284    (23  548  

    Missouri
  Regulated  
  Illinois
  Regulated  
  Merchant
  Generation  
  

Other /
  Intersegment  

Eliminations

        Total       

Three Months 2010:

      

Electric margin

  $439   $217   $227   $(7 $876  

Gas margin

   29    114    -    -    143  

Other revenues

   -    -    -    -    -  

Other operations and maintenance

   (218  (139  (73  14    (416

Depreciation and amortization

   (92  (54  (36  (5  (187

Taxes other than income taxes

   (68  (41  (8  (1  (118

Other income and (expenses)

   19    (1  -    (3  15  

Interest charges

   (59  (38  (34  (1  (132

Income taxes

   (22  (24  (31  2    (75

Net income (loss)

   28    34    45    (1  106  

Noncontrolling interest and preferred dividends

   (1  (1  (1  (1  (4

Net income (loss) attributable to Ameren Corporation

  $27   $33   $44   $(2 $102  

Three Months 2009:

      

Electric margin

  $411   $193   $287   $(3 $888  

Gas margin

   27    111    -    -    138  

Other revenues

   1    4    -    (5  -  

Other operations and maintenance

   (216  (136  (78  9    (421

Depreciation and amortization

   (86  (53  (28  (7  (174

Taxes other than income taxes

   (62  (39  (7  (2  (110

Other income and (expenses)

   11    1    -    -    12  

Interest charges

   (53  (41  (25  1    (118

Income taxes

   (11  (14  (54  9    (70

Net income

   22    26    95    2    145  

Noncontrolling interest and preferred dividends

   (1  (1  (2  -    (4

Net income attributable to Ameren Corporation

  $21   $25   $93   $2   $141  

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins in the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008.2009. 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. 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.

 

Three Months  Ameren(a) UE CIPS Genco CILCORP CILCO IP   Ameren(a) UE CIPS Genco CILCO IP 

Electric revenue change:

               

Effect of weather (estimate)

  $(39 $(25 $(3 $-   $(4 $(4 $(7  $12   $10   $1   $-   $-   $1  

Regulated rates:

               

Changes in base rates

   88    55    7    -    (1  (1  27     25    23    -    -    -    2  

Noranda sales

   (15  (15  -    -    -    -    -     11    11    -    -    -    -  

Illinois pass-through power costs

   (86  -    (15  -    (24  (24  (47

Merchant Generation sales price changes

   25    -    -    40    13    13    -  

Illinois pass-through power supply costs

   (30  -    (13  -    (4  (13

Sales price changes, including hedging effect

   (38  -    -    (26  (12  -  

Off-system revenues

   (36  (36  -    -    -    -    -     (55  (55  -    -    -    -  

Illinois electric settlement agreement, net of

reimbursement

   3    -    -    1    -    -    1  

Net MTM gains (losses)

   (91  4    -    -    -    -    -  

Generation output, load and other

   (98  (20  1    (67  (11  (11  (11

FAC net over-recovery in 2009

   13    13    -    -    -    -  

2007 Illinois Electric Settlement Agreement, net of reimbursement

   5    -    1    2    1    1  

Net unrealized MTM gains (losses)

   9    (1  -    (1  -    -  

Weather-normalized sales and other

   93    27    8    (3  10    8  

Total electric revenue change

  $(249 $(37 $(10 $(26 $(27 $(27 $(37  $45   $28   $(3 $(28 $(5 $(1

Fuel and purchased power change:

               

Fuel:

               

Generation and other

  $59   $26   $-   $27   $(2 $(1 $-  

Lower net MTM losses

   110    59    -    29    7    7    -  

Production volume and other

  $(24 $  (10 $-   $(1 $(12 $-  

FAC net under-recovery in 2010

   50    50    -    -    -    -  

Net unrealized MTM (losses) gains

   (27  (29  -    3    -    -  

Price

   (14  -    -    (4  (2  (2  -     (18  -    -    (13  (5  -  

Purchased power

   29    18    5    -    16    16    12     (68  (11  -    (1  1    1  

Illinois pass-through power costs

   86    -    15    -    24    24    47  

Illinois pass-through power supply costs

   30    -    13    -    4    13  

Total fuel and purchased power change

  $270   $103   $20   $52   $43   $44   $59    $(57 $-   $13   $(12 $(12 $14  

Net change in electric margin

  $21   $66   $10   $26   $16   $17   $22  

Natural gas margin change:

        

Changes in base rates

  $9   $-   $1   $-   $(2 $(2 $10  

Illinois seasonal rate redesign

   12    -    3    -    3    3    6  

Capitalization of non-recoverable gas costs

   (5  -    (1  -    -    -    (4

Net MTM losses

   3    -    -    -    3    3    -  

Other

   1    1    1    -    1    1    (1

Net change in natural gas margin

  $20   $1   $4   $-   $5   $5   $11  
Nine Months                                     

Electric revenue change:

        

Effect of weather (estimate)

  $(31 $(19 $(2 $-   $(4 $(4 $(6

Regulated rates:

        

Changes in base rates

   193    108    17    -    (2  (2  70  

Noranda sales

   (42  (42  -    -    -    -    -  

Illinois pass-through power costs

   (184  -    (41  -    (57  (57  (86

Merchant Generation sales price changes

   101    -    -    119    52    52    -  

Off-system revenues

   (116  (116  -    -    -    -    -  

Illinois electric settlement agreement, net of

reimbursement

   11    -    1    5    3    3    2  

Net MTM losses

   (62  (5  -    -    -    -    -  

Generation output, load and other

   (225  (36  (6  (136  (28  (28  (14

Total electric revenue change

  $(355 $(110 $(31 $(12 $(36 $(36 $(34

Fuel and purchased power change:

        

Fuel:

        

Generation and other

  $32   $13   $-   $(10 $8   $8   $-  

Increased net MTM gains

   43    25    -    8    3    3    -  

Price

   (39  -    -    (14  (3  (3  -  

Purchased power

   72    47    10    -    37    37    12  

Illinois pass-through power costs

   184    -    41    -    57    57    86  

Total fuel and purchased power change

  $292   $85   $51   $(16 $102   $102   $98  

Net change in electric margin

  $(63 $(25 $20   $(28 $66   $66   $64  

Net change in electric margins

  $(12 $28   $10   $(40 $(17 $13  

Natural gas margin change:

               

Effect of weather (estimate)

  $(5 $-   $(1 $-   $(1 $(1 $(3  $3   $1   $1   $-   $-   $1  

Changes in base rates

   34    -    7    -    (7  (7  34  

Capitalization of non-recoverable gas costs

   (5  -    (1  -    -    -    (4

Net MTM losses

   3    -    -    -    3    3    -  

Other

   (14  (3  (3  -    (3  (3  (6

Net change in natural gas margin

  $13   $(3 $2   $-   $(8 $(8 $21  

Net unrealized MTM losses

   (2  -    -    -    (2  -  

Weather-normalized sales and other

   4    1    1    -    1    1  

Net change in natural gas margins

  $5   $2   $2   $-   $(1 $2  

 

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

Ameren

Ameren’s electric margin increaseddecreased by $21$12 million, or 2%1%, in the third quarter of 2009 compared with the year-ago period, but decreased by $63 million, or 2%, in the ninethree months ended September 30, 2009,March 31, 2010, compared with the same period in 2008. Electric margins were unfavorably impacted2009. The following items had an unfavorable impact on Ameren’s electric margins:

Margins decreased by $60 million at the Merchant Generation segment, primarily because of reductions in higher-margin sales including the 2006 auction power supply agreements, and lower market prices, which resulted in fewer opportunities for economic power sales.

In the first quarter of 2009, the reversal of previously unrealized losses to regulatory assets resulted in the threerecognition of a $30 million net MTM gain on energy and nine months ended September 30,fuel-related contracts at UE. After the implementation of UE’s FAC on March 1, 2009, (except where a specific period is referenced), as compared to the year-ago periods, by:favorable or unfavorable impact of UE’s net MTM gains or losses, no longer impact electric margins. See Note 7 - Derivative Financial Instruments under Part II, Item 8, of the Form 10-K for additional information.

 

Higher net fuel expense at UE (as defined in UE’s FAC) of $56$10 million for the nine months ended September 30, 2009, although net fuel expense was $8 million lower in the third quarter of 2009.

Unfavorable net unrealized MTM activity at the Merchant Generation segment on energy transactions primarily related to nonqualifying hedges of changes in market prices for electricity ($95 million and $57 million, respectively).

Higher fuel expense at Genco as a result of its June 2008 settlement agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a coal supply contract, which compensated Genco, in total, for higher fuel costs it incurred throughout 2008 and is incurring throughout 2009. Because the entire settlement was recorded in earnings in the second quarter of 2008, Ameren’s earnings in the first nine months of 2009 were comparatively lower than they otherwise would have been.

Excluding the impact of the June 2008 settlement agreement, Merchant Generation segment fuel prices increased by an additional 4% and 5%, respectively.

Reduced sales by UE to Noranda due to an extended severe storm-related outage, which lowered electric revenues ($15 million and $42 million, respectively). See Outlook for further information on the Noranda plant outage.

Unfavorable weather conditions, as evidenced by an 18% and 5% decrease in cooling degree-days, respectively ($39 million and $31 million, respectively).

Excluding the impact of UE’s reduced sales to Noranda, lower weather-normalized end-use retail sales volumes (5% and 4%, respectively), which were largely a result of the economic slowdown ($11 million and $26 million, respectively).

Decreased power plant utilization primarily because of lower market prices resulting in fewer opportunities for economic sales and transmission congestion limiting the period when power could be sold. Ameren’s baseload coal-fired generating plants’ equivalent availability factors were 86% in the first nine months of 2009 and 2008; however, the average capacity factor was 71% in the first nine months of 2009 compared with 77% in the same period in 2008.

Reduced Callaway nuclear plant availability due to a 12-day unplanned outagefavorable interchange margin in the first quarter of 2009 which decreased electric marginprior to the FAC becoming effective on March 1, 2009. Net fuel expense at UE is total fuel and purchased power offset by $7 million foroff-system revenues and the nine months ended September 30,FAC over-recovery in 2009.

13% higher fuel prices in the Merchant Generation segment primarily due to higher commodity and transportation costs associated with new contracts.

The following items had a favorable impact on Ameren’s electric margins were favorably impacted infor the three and nine months ended September 30, 2009 (except where a specificMarch 31, 2010, compared with the same period is referenced), as compared to the year-ago periods, by:in 2009:

 

Higher electric rates at UE, effective March 1, 2009, ($55which increased margins by $23 million, and $108 million, respectively) and at the Ameren Illinois Utilities,IP, effective October 1, 2008, ($33which increased margins by $2 million as residential electric delivery rates were adjusted to recover the full increase of the 2008 ICC rate order.

Excluding the impact of UE’s increased sales to Noranda, higher weather-normalized end-use retail sales volume of 4% in Ameren’s rate-regulated utilities largely due to improved economic conditions, which increased margins by $19 million.

Higher wholesale sales margins at UE of $13 million because of additional customers and $85 million, respectively).higher-priced wholesale sales contracts.

 

Favorable net unrealized MTM activity at UE on energy and fuel-related transactions ($63 million and $20 million, respectively). Margin was favorably impacted during the nine months ended September 30, 2009, because UE reversed and deferredweather conditions, as regulatory assets previously recorded net MTM losses of $42 million on energy and fuel-related transactionsevidenced by a 9% increase in the first quarter of 2009 when these costs became probable of recovery because of the FAC. See Note 6 - Derivative Financial Instruments under Part I, Item I, of this report, for additional information.heating degree-days, which increased margins by $12 million.

 

Favorable netNet unrealized MTM activity at the Merchant Generation segment (primarily at Marketing Company) of $13 million on energy and fuel-related transactions primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts through 2012 ($43 million and $12 million, respectively).transactions.

 

The repricingIncreased UE sales of wholesale and retail electric power supply agreements and financial swaps settling at higher margins at Merchant Generation.

Higher UE wholesale sales margins because of additional customers and higher-priced wholesale sales contracts ($6$11 million and $16 million, respectively).to Noranda in 2010 as its smelter plant gradually returned to full capacity after a January 2009 severe storm significantly reduced the plant’s capacity.

 

The recovery of power supply costs incurred by the Ameren Illinois Utilities, including an increase in Supply Cost Adjustment (SCA) factors as approvedA $5 million reduction in the 2008 ICC electric rate order ($1 million and $10 million, respectively).

The reduced impact of the 2007 Illinois electric settlement agreement ($3 million and $11 million, respectively).Electric Settlement Agreement.

Ameren’s natural gas marginmargins increased by $20 million, or 34%, and $13$5 million, or 4%, infor the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008. Gas margins were favorably impacted in the three and nine months ended September 30, 2009 (except where2009. The following items had a specific period is referenced), as compared to the year-ago periods, by:favorable impact on Ameren’s natural gas margins:

 

The Ameren Illinois Utilities’ net gas delivery service rate increase, effective October 1, 2008 ($9 million and $34 million, respectively).1% higher weather-normalized sales volumes, which increased margins by $4 million.

 

The redesigned seasonal gas delivery service rates at the Ameren Illinois Utilities, effective October 1, 2008 ($12 million in the three months ended September 30, 2009). These redesigned delivery service rates impact quarterly earnings comparisons but are not expected to materially impact annual margin.

The absence of net unrealized MTM losses at CILCO in 2009 on natural gas swaps ($3 million and $3 million, respectively).

Ameren’s gas margins were unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

UnfavorableFavorable weather conditions, as evidenced by a 7% reduction9% increase in heating degree-days, that decreased marginwhich increased margins by $5$3 million.

Ameren’s natural gas margins were unfavorably impacted by net unrealized MTM gains of $2 million at CILCO on natural gas swaps in the nine months ended September 30, 2009.

10% lower weather-normalized sales volumes, largely a result of the economic slowdown, that decreased margin by $10 million in the nine months ended September 30, 2009.

The absence of non-recoverable purchased gas costs that were capitalized in accordance with the September 2008 ICC gas rate order, resulting in a one-time increase in margin of $5 million in the three and nine months ended September 30, 2008.

Missouri Regulated (UE)

UE’s electric marginmargins increased by $66$28 million, or 12%7%, infor the third quarter of 2009 compared with the year-ago period, but decreased by $25 million, or 2%, in the ninethree months ended September 30, 2009,March 31, 2010, compared with the same period in 2008.2009. The following items had a favorable impact on UE’s electric margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

Higher net fuel expense at UE (as defined in UE’s FAC) of $56 million for the nine months ended September 30, 2009, although net fuel expense was $8 million lower in the third quarter of 2009.

Reduced sales to Noranda due to an extended severe storm-related outage, which lowered electric revenues ($15 million and $42 million, respectively). See Outlook for further information on the Noranda plant outage.

Unfavorable weather conditions, due to a mild winter and a 13% decrease in cooling degree-days in the third quarter of 2009 ($25 million and $19 million, respectively).

Excluding the impact of UE’s reduced sales to Noranda, lower weather-normalized end-use retail sales volumes (4% and 3%, respectively), largely a result of the economic slowdown ($12 million and $24 million, respectively).

Reduced Callaway nuclear plant availability due to a 12-day unplanned outage in the first quarter of 2009, which decreased electric margin by $7 million for the nine months ended September 30, 2009.

UE’s electric margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:margins:

 

Higher electric rates, effective March 1, 2009, ($55 million and $108 million, respectively).

Favorable net unrealized MTM activity at UE on energy and fuel-related transactions ($63 million and $20 million, respectively). Electric margin was favorably impacted during the nine months ended September 30, 2009, because UE reversed and deferred as regulatory assets previously recorded net MTM losses of $42 million on energy and fuel-related transactions in the first quarter of 2009 when these costs became probable of recovery because of the FAC. See Note 6 - Derivative Financial Instruments under Part I, Item I, of this report, for additional information.which increased margins by $23 million.

 

Higher wholesale sales marginmargins of $13 million due to additional customers and higher-priced wholesale sales contracts ($6contracts.

Increased sales of $11 million and $16 million, respectively).to Noranda in 2010, as its smelter plant gradually returned to full capacity after a January 2009 severe storm significantly reduced the plant’s capacity. See Outlook for additional information on the Noranda plant outage.

Favorable weather conditions, as evidenced by a 12% increase in heating degree-days, which increased margins by $10 million.

Excluding the impact of increased sales to Noranda, 2% higher weather-normalized end-use retail sales volumes largely due to improved economic conditions, which increased margins by $6 million.

The following items had an unfavorable impact on UE’s gas margin increased by $1 million, or 10%, inelectric margins:

In the thirdfirst quarter of 2009, compared with the year-ago period but decreasedreversal of previously unrealized losses to regulatory assets resulted in the recognition of a $30 million net MTM gain on energy and fuel-related contracts. After the implementation of UE’s FAC on March 1, 2009, the favorable or unfavorable impact of net MTM gains or losses, no longer impact electric margins. See Note 7 - Derivative Financial Instruments under Part II, Item 8, of the Form 10-K for additional information.

Higher net fuel expense of $10 million due to favorable interchange sales in the first quarter of 2009 prior to the FAC becoming effective on March 1, 2009. Net fuel expense at UE is total fuel and purchased power offset by $3off-system revenues and the FAC over-recovery in 2009.

UE’s natural gas margins increased by $2 million, or 5%7%, infor the ninethree months ended September 30, 2009,March 31, 2010, compared with the same period in 2008. The decrease in gas margin was2009, primarily because of favorable weather conditions, as evidenced by a 7% decrease12% increase in weather-normalized sales volumes for the nine months ended September 30, 2009.heating degree-days in 2010, which increased margins by $1 million.

Illinois Regulated

Illinois Regulated’s electric marginmargins increased by $26$24 million, or 11%12%, and $76 million, or 13%, infor the three and nine months ended September 30, 2009, respectively,March 31, 2010, compared with the same periodsperiod in 2008.2009. Illinois Regulated’s natural gas marginmargins increased by $19$3 million, or 38%3%, and $13 million, or 5%, infor the three and nine months ended September 30, 2009,March 31, 2010, compared with the year-ago periods.same period in 2009. The Ameren Illinois Utilities have a cost recovery mechanism for power purchased on behalf of their customers. These pass-through power costs do not affect margins; however, the electric revenues and offsetting purchased power costs fluctuate primarily because of customer switching and usage. See below for explanations of electric and natural gas margin variances for the Illinois Regulated segment.

CIPS

CIPS’ electric marginmargins increased by $10 million, or 14%17%, and $20 million, or 10%, in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008. Electric margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

Higher electric delivery service rates, effective October 1, 2008 ($7 million and $17 million, respectively).

The recovery of power supply costs incurred, including an increase in the SCA factors as approved in the 2008 ICC electric rate order ($3 million in the nine months ended September 30, 2009).

The reduced impact of the Illinois electric settlement agreement ($1 million in the nine months ended September 30, 2009).

CIPS’ electric margin was unfavorably impacted in the three and nine months ended September 30, 2009, as compared to the year-ago periods, by:

Lower net transmission margin primarily related to reduced transmission service rates that were based on lower transmission costs in the prior year ($1 million and $5 million, respectively).

Unfavorable weather as evidenced by a 19% and 5% decrease in cooling degree-days, respectively ($3 million and $2 million, respectively).

CIPS’ gas margin increased by $4 million, or 33%, and $2 million, or 4%, in the three and nine months ended September 30, 2009, compared with the year-ago periods. Gas margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

The redesigned seasonal gas delivery service rates, effective October 1, 2008 ($3 million for the three months ended September 30, 2009).March 31, 2010, compared with the same period in 2009. The redesigned delivery service rates have anfollowing items had a favorable impact on quarterly earnings comparisons but are not expectedelectric margins:

5% higher weather-normalized sales volumes largely due to materially impact annual margin.improved economic conditions, which increased margins by $4 million.

 

The gas delivery service rate increase, effective October 1, 2008, which increased gas margin ($1 million and $7 million, respectively.)

CIPS’ gas margin was unfavorably impacted in the three and nine months ended September 30, 2009, (except where a specific period is referenced) compared to year-ago periods by:

The absence of non-recoverable purchased gas costs that were capitalized in accordance with the September 2008 ICC gas rate order, resulting in a one-time increase in margin of $1 million in the three and nine months ended September 30, 2008.

UnfavorableFavorable weather conditions, as evidenced by an 8% reductiona 12% increase in heating degree-days, decreased marginwhich increased margins by $1 million during the nine months ended September 30, 2009.million.

 

4% lower weather-normalized sales volumesA $1 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.

CIPS’ natural gas margins increased by $2 million, or 8%, for the first ninethree months of 2009, largelyended March 31, 2010, compared with the same period in 2009. This was primarily due to favorable weather conditions, as evidenced by a result of the economic slowdown,12% increase in heating degree-days, which decreased marginincreased margins by $1 million.

CILCO (Illinois Regulated)

The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin infor the three and nine months ended September 30, 2009, asMarch 31, 2010, compared with the same periodsperiod in 2008:2009:

 

  Three Months Nine Months   Three Months 

CILCO (Illinois Regulated)

  $(5 $(7  $1  

CILCO (AERG)

   22    73     (18

Total change in electric margin

  $17   $66    $(17

CILCO’s (Illinois Regulated) electric margin decreasedmargins increased by $5$1 million, or 11%4%, and $7 million, or 6%, infor the three and nine months ended September 30, 2009,March 31, 2010, compared with the year-ago periods. CILCO’s (Illinois Regulated)same period in 2009. The following items had a favorable impact on electric margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:margins:

 

Lower electric delivery service rates, effective October 1, 2008 ($2 million in the nine months ended September 30, 2009).9% higher weather-normalized sales volumes largely due to improved economic conditions, which increased margins by $1 million.

 

UnfavorableA $1 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.

Favorable weather conditions, as evidenced by a 34% and 24% decrease3% increase in coolingheating degree-days, respectively ($4which increased margins by less than $1 million.

See Merchant Generation below for an explanation of CILCO’s (AERG) change in electric margin for the three months ended March 31, 2010, as compared with the same period in 2009.

CILCO’s (Illinois Regulated) natural gas margins decreased $1 million, and $4or 4%, for the three months ended March 31, 2010, compared with the same period in 2009. This was primarily due to net unrealized MTM gains of $2 million respectively).on natural gas swaps in 2009.

IP

IP’s electric margins increased by $13 million, or 13%, for the three months ended March 31, 2010, compared with the same period in 2009. The following items had a favorable impact on electric margins:

 

11% lower4% higher weather-normalized sales volumes primarily in the lower-margin industrial customer sector, largely a result of thedue to improved economic slowdown ($1 million for the nine months ended September 30, 2009).conditions, which increased margins by $5 million.

CILCO’s (Illinois Regulated) electric margin was favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared with year-ago periods by:

The recovery of power supply costs incurred of $2 million, including an increase in the SCA factors, as approved in the 2008 ICC electric rate order of $1 million in the nine months ended September 30, 2009.order.

 

The reduced impact of the Illinois electric settlement agreement of $1 million for the nine months ended September 30, 2009.

See Merchant Generation below for an explanation of CILCO’s (AERG) change in electric margin in the three and nine months ended September 30, 2009, as compared with the same periods in 2008.

CILCO’s (Illinois Regulated) gas margin increased by $5 million, or 42%, in the third quarter of 2009 compared with the year-ago period but decreased by $8 million, or 12%, in the nine months ended September 30, 2009, compared with the same period in 2008. CILCO’s gas margins were unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

Lower gasHigher delivery service rates, effective October 1, 2008, ($2which increased margins by $2 million and $7 million, respectively).as residential electric delivery rates were adjusted to recover the full increase of the 2008 ICC rate order.

 

UnfavorableA $1 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.

Favorable weather conditions, as evidenced by a 4% reductionan 8% increase in heating degree-days, that decreased marginwhich increased margins by $1 million during the nine months ended September 30, 2009.million.

16% lower weather-normalized sales volumes for the first nine months of 2009, largely a result of the economic slowdown (less than $1 million in the nine months ended September 30, 2009).

CILCO’sIP’s natural gas margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared with year-ago periods by:

The absence of net realized MTM losses at CILCO in 2009 on natural gas swaps ($3increased by $2 million, and $3 million, respectively).

The redesigned seasonal gas delivery service rates, effective October 1, 2008 ($3 millionor 3%, for the three months ended September 30, 2009). These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margin.

IP

IP’s electric margin increased by $22 million, or 19%, and $64 million, or 21%, in the three and nine months ended September 30, 2009, respectively,March 31, 2010, compared with the same periodsperiod in 2008. IP’s electric margin2009. This was favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as comparedprimarily due to the year-ago periods, by:

Higher electric delivery service rates, effective October 1, 2008 ($27 million and $70 million, respectively).

The reduced impact of MISO settlements in the prior year ($6 million and $4 million, respectively).

The recovery of power supply costs incurred, including an increase in the SCA factors as approved in the 2008 ICC electric rate order ($1 million and $6 million, respectively).

The reduced impact of the Illinois electric settlement agreement ($1 million and $2 million, respectively).

IP’s electric margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

7% and 6%, respectively, lower weather-normalized sales volumes, largely a result of the economic slowdown, primarily in the lower-margin industrial customer sector ($7 million and $8 million, respectively).

Unfavorablefavorable weather conditions, as evidenced by a 22% and 10% decrease in cooling degree-days, respectively ($7 million and $6 million, respectively).

IP’s gas margin increased by $11 million, or 41%, and $21 million, or 18%, in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008. IP’s gas margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to year-ago periods, by:

Higher gas delivery service rates, effective October 1, 2008 ($10 million and $34 million, respectively).

The redesigned seasonal gas delivery service rates, effective October 1, 2008, ($6 million for the three months ended September 30, 2009). These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margin.

IP’s gas margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

8% lower weather-normalized sales volumes, largely a result of the economic slowdown, that reduced margin by $5 million in the nine months ended September 30, 2009.

Unfavorable weather conditions, as evidenced by a 6% reductionincrease in heating degree-days, that decreased marginwhich increased margins by $3 million in the nine months ended September 30, 2009.$1 million.

The absence of non-recoverable purchased gas costs that were capitalized in accordance with the September 2008 ICC gas rate order, resulting in a one-time increase in margin of $4 million in the three and nine months ended September 30, 2008.

Merchant Generation

Merchant Generation’s electric marginmargins decreased by $91$60 million, or 29%, and $141 million, or 15%21%, in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008.

Genco

Genco’s electric margin increased by $26 million, or 24%, in the third quarter of 2009 compared with the year-ago period, but decreased by $28 million, or 6%, in the nine months ended September 30, 2009,March 31, 2010, compared with the same period in 2008. 2009.

Genco

Genco’s electric margin was unfavorably impacted indecreased by $40 million, or 22%, for the three and nine months ended September 30, 2009 (except where a specificMarch 31, 2010, compared with the same period is referenced), as compared to the year-ago periods, by:

Higher fuel expense as a result of Genco’s June 2008 settlement agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a coal supply contract, which compensated Genco, in total, for higher fuel costs it incurred throughout 2008 and is incurring throughout 2009. Because the entire settlement was recorded in earnings in the second quarter of 2008, Genco’s earnings in the first nine months of 2009 were comparatively lower than they otherwise would have been.

Excluding theThe following items had an unfavorable impact of the June 2008 settlement agreement, Genco’s fuel prices increased 2% for the nine months ended September 30, 2009.on electric margins:

 

Lower revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company, due to a smaller pool of money to allocate, which was driven by reductions in higher-margin sales, including the 2006 auction power supply agreements, and lower market prices. Genco was allocated a lower percentage of revenues from the pool in 2010 compared with 2009 because of lower reimbursable expenses and lower generation relative to AERG in accordance with the Genco PSA, partially offset by financial swaps settling at higher margins and new higher-priced wholesale and retail electric power supply agreements.PSA.

 

Decreased power plant utilization13% higher fuel prices primarily due to lower market prices resulting in fewer opportunitieshigher commodity and transportation costs associated with new contracts.

Genco’s electric margins were favorably affected for economic sales and transmission congestion limiting the period when power could be sold. In addition, one of Genco’s coal-fired power plants experienced a transformer fire in September 2009 resulting in two units being out of service for a period of time. This contributed to a reduction in Genco’s baseload coal-fired generating plants’ equivalent availability factor to 81% in the third quarter of 2009three months ended March 31, 2010, compared with 87% in the same period in 2008. Genco’s average capacity factor also decreased to 59% in the third quarter of 2009 compared with 75% in the comparable period in 2008. Genco’s baseload coal-fired generating plants’ equivalent availability factor was 85% in the first nine months of 2009 compared with 83% in the same period in 2008; however, the average capacity factor was 61% in the first nine months of 2009 compared with 72% in the same period in 2008.

Genco’s electric margin was favorably impacted in the three and nine months ended September 30, 2009, as compared to the year-ago periods, by:

 

Favorable netA $2 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.

Net unrealized MTM activity of $2 million on energy and fuel-related transactions primarily relating to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts through 2012 ($29 million and $8 million, respectively).transactions.

 

Lower emission allowance costs due tobecause of lower prices and reduced generation ($2 million and $7 million, respectively).increased margins by $1 million.

 

The reduced impactIncreased power plant utilization. Genco’s base load coal-fired generating plants’ average capacity factor increased to 72% in 2010, compared with 71% in 2009, despite a decrease in Genco’s equivalent availability factor to 84% in 2010, compared with 87% in 2009. Both factors were impacted by the timing of the Illinois electric settlement agreement ($1 million and $5 million, respectively).plant outages.

CILCO (AERG)

AERG’s electric margin increaseddecreased by $22$18 million, or 36%, and $73 million, or 45%25%, in the three and nine months ended September 30, 2009, respectively,March 31, 2010, compared with the same period in 2008. AERG’s2009. The following items had an unfavorable impact on electric margin was favorably impacted in the three and nine months ended September 30, 2009, as compared to the year-ago periods, by:margins:

 

HigherLower revenues allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company, due to financial swaps settling at higher margins and new higher-priced wholesale and retail electrica smaller pool of money to allocate, which was driven by reductions in higher-margin sales, including the 2006 auction power supply agreements.

Favorable net unrealized MTM activity on fuel-related transactions primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts through 2012 ($7 million and $3 million, respectively).

Lower oil consumption resulting from fewer plant start-ups and lower prices in 2009 ($2 million and $3 million, respectively).

The reduced impact of the Illinois electric settlement agreement ($1 million and $2 million, respectively).

AERG’s electric margin was unfavorably impacted in the three and nine months ended September 30, 2009, as compared to the year-ago periods, by decreased power plant availability due, in part, to a planned plant outageagreements, and lower market prices. However, AERG was allocated a greater percentage of revenues from the pool in 2010 compared with 2009 because of higher reimbursable expenses and higher generation relative to Genco in accordance with the AERG PSA.

25% higher fuel prices primarily due to higher commodity and transportation costs associated with new contracts.

AERG’s baseloadelectric margins were favorably impacted by increased power plant utilization, as AERG’s base load coal-fired generating plants’ average capacity factor increased to 81% in 2010, compared with 58% in 2009. AERG’s equivalent availability and average capacityfactor increased to 87% in 2010, compared with 63% in 2009. Both factors were 75% and 67%, respectively,favorably impacted by fewer plant outages in the first nine months of 2009, compared with 79% and 72%, respectively, in the same period in 2008.2010.

Other Merchant Generation

Electric margin from Ameren’s other Merchant Generation operations, primarily from EEI and Marketing Company, decreased by $139$2 million, or 94%, and $186 million, or 64%6%, in the three and nine months ended September 30, 2009, respectively. Other Merchant Generation electric margins were unfavorably impacted, asMarch 31, 2010, compared with the year-ago periods, by:

same period in 2009. The impact of the economic slowdown, which lowered power demanddecrease was primarily due to higher MISO and sales prices. The average sales price for power decreasedother costs, partially offset by 29% and 23%, respectively.

Unfavorablefavorable net unrealized MTM activity (mostlyof $11 million on energy-related transactions at Marketing Company) on energy and fuel-related transactions primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts through 2012 and that related to nonqualifying hedges of changes in market prices for electricity ($86 million and $56 million, respectively).Company.

Higher fuel prices at EEI (27% and 23%, respectively) due to an increase in transportation costs.

Decreased power plant utilization due primarily to plant outages. EEI’s baseload coal-fired generating plant’s equivalent availability and average capacity factors were 84% and 77%, respectively, in the first nine months of 2009, compared with 90% and 89%, respectively, in the same period in 2008.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Three months - Other operations and maintenance expenses decreased $34$5 million in the first three months of 2010, compared with the same period in 2009. The absence of major storms in UE’s service territory, as had occurred in the first quarter of 2009, resulted in a decrease of $11 million. BadAdditionally, a reduction in bad debt expense declined $26of $7 million, primarily as a result of the impact of the Illinois bad debt rate adjustment mechanism that became effective in July 2009 (see Note 2 - Ratelower accounts receivable balances due to decreased gas costs, and Regulatory Matters under Part I, Item 1, of this report for further information). Additionally, other operations and maintenance expenses decreased $14 million because of a favorable change of $3 million in unrealized net MTM adjustments between periods resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans. Reducing the benefit of these items were severance costs of $17.5 million for employee separation programs recognized in the third quarter of 2009. See Note 1 - Summary of Significant Accounting Policies under Part 1, Item 1, of this report for additional information.

Nine months - Other operations and maintenance expenses decreased $67 million primarily because of reductions in plant maintenance costs of $52 million, reduced bad debt expense of $39 million, including the impact of the Illinois bad debt rate adjustment mechanism, a $25 million favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans, resulted in decreased other operations and lower injuries and damages expenses of $14 million.maintenance expenses. Reducing the benefit of these items were employee severancewas an increase in plant maintenance costs of $17.5 million recognized in 2009, as noted above, higher labor costs of $17 million and increased storm repair expenditures of $10 million. In the second quarter of 2009, a $5 million charge was incurred for the termination of a heavy forgings contract associated with efforts to build a new nuclear unit at UE’s Callaway nuclear power plant. Also in the second quarter of 2009, $5 million of expense was recognized for the termination of a rail line extension project at a subsidiary of Genco. In the second quarter of 2008, other operations and maintenance expenses were reduced by a MoPSC accounting order, which resulted in UE recording a regulatory asset of $13 million for costs relatedas a result of scheduled plant outages and higher distribution system reliability expenditures of $6 million due to 2007 storms that had previously been expensed; no similar item occurred in 2009.increased tree trimming activities.

Variations in other operations and maintenance expenses in Ameren’s CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008,2009, were as follows:

Missouri Regulated (UE)

Three months - Other operations and maintenance expenses decreased $5 million primarily because of a favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans, and reduced plant maintenance costs. Reducing the benefit of these items were severance costs for employee separation programs recognized in 2009, as discussed above.

Nine months - Other operations and maintenance expenses decreased $24 million primarily because of lower plant maintenance costs, reduced employee benefit costs, lower injuries and damages expenses, and a favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans. Reducing the benefit of these items were employee severance costs in 2009, higher labor costs, the charge incurred for the termination of the heavy forgings contract, and the absence of the MoPSC storm cost accounting order, as occurred in the prior year, which reduced other operations and maintenance expenses as described above. Additionally, storm repair expenditures were higher in the first nine months of 2009 as a result of ice storms at the beginning of the year.

Illinois Regulated

Three and nine months - Other operations and maintenance expenses decreased $37 million and $56 million, respectively, in the Illinois Regulated segment as discussed below.

CIPS

Three and nine months - Other operations and maintenance expenses decreased $9 million in both periods primarily because of reduced bad debt expense, including the impact of the Illinois bad debt rate adjustment mechanism. Increased storm repair expenditures mitigated this benefit in the nine-month period.

CILCO (Illinois Regulated)

Three and nine months - Other operations and maintenance expenses increased $16 million and $53 million, respectively, primarily because of higher labor and employee benefit costs. These increases were primarily a result of work performed on behalf of CIPS and IP as discussed below.

At the beginning of 2009, approximately 570 employees were transferred from Ameren Services to CILCO (Illinois Regulated), which resulted in an increase in other operations and maintenance expenses at CILCO (Illinois Regulated) in the 2009 periods. These CILCO (Illinois Regulated) employees also provide support services to CIPS and IP. CILCO (Illinois Regulated) records reimbursements from CIPS and IP for work performed by its employees on their behalf as Operating Revenues - Support Services - Affiliates on its statement of income, which increased $19 million and $53 million in the three and nine months ended September 30, 2009, respectively. Intercompany revenue and expenses associated with these transactions are eliminated in consolidation within the Illinois Regulated segment. See Note 8 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for further information on CILCO (Illinois Regulated) support services.

Reducing the unfavorable effect of the above items in both periods was a reduction in bad debt expense, including the impact of the Illinois bad debt rate adjustment mechanism.

IP

Three and nine months - Other operations and maintenance expenses decreased $23 million and $33 million, respectively, because of a reduction in bad debt expense, including the impact of the Illinois bad debt rate adjustment mechanism.

Merchant Generation

Three and nine months - Other operations and maintenance expenses increased $7 million in the Merchant Generation segment in the third quarter of 2009 compared with the third quarter of 2008, as discussed below. Other operations and maintenance expenses were comparable between periods as the absence of major storms in the first nine monthsquarter of 2009 with the same period in 2008.2010 was offset by increased plant maintenance costs as a result of scheduled plant outages.

GencoIllinois Regulated

Three months - Other operations and maintenance expenses increased $6 million primarily because of employee severance costs in 2009,were comparable between periods, as discussed above.below.

Nine months - Other operations and maintenance expenses decreased $6 million primarily because of lower plant maintenance costs. Employee severance costs recognized in the third quarter of 2009 and expenses recognized in the second quarter of 2009 for termination of the rail line extension project, as noted above, mitigated these benefits.

CIPS

CILCO (AERG)

Three months - Other operations and maintenance expenses were comparable between periods.

Nine months - CILCO (Illinois Regulated)

Other operations and maintenance expenses were comparable between periods as a reduction in bad debt expense of $3 million, as described above, was offset by increases in various other operation and maintenance expenses.

IP

Other operations and maintenance expenses increased $5 million, primarily because of higher distribution system reliability expenditures due to increased tree trimming activities.

Merchant Generation

Other operations and maintenance expenses decreased $5 million in the Merchant Generation segment, as discussed below.

Genco

Other operations and maintenance expenses decreased $5 million, primarily because of lower plant maintenance costs.labor costs due to reduced headcount.

EEICILCO (AERG)

Three and nine months - Other operations and maintenance expenses increased $3 million and $8 million, respectively, primarily because of higher plant maintenance costs.

CILCORP (parent company only)

Three and nine months - Other operations and maintenance expenses were comparable between periods.

Goodwill Impairment Loss

In the first quarter of 2009, CILCORP recognized a non-cash goodwill impairment charge of $462 million. See Note 14 - Goodwill Impairment under Part I, Item 1, of this report for additional information.

Depreciation and Amortization

Ameren

Ameren’s depreciation and amortization expenses increased $12 million and $28$13 million in the three and nine months ended September 30, 2009, respectively,March 31, 2010, compared with the same periodsperiod in 2008,2009, because of items noted below at the Ameren Companies.

Variations in depreciation and amortization expenses in Ameren’s CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008,2009, were as follows:

Missouri Regulated (UE)

Three and nine months - Depreciation and amortization expenses increased $7$6 million, and $20 million, respectively, primarily because of capital additions.additions and amortization of regulatory assets that resulted from UE’s electric rate case in 2009.

Illinois Regulated

Three and nine months - Depreciation and amortization expenses were comparable between periods in the Illinois Regulated segment in the third quarter of 2009 with the third quarter of 2008. Depreciation and amortization expenses decreased $3 million in the first nine months of 2009 compared with the same period in 2008. As part of the consolidated electric and natural gas rate order issued by the ICC in September 2008, the ICC changed plant asset useful lives, effective October 1, 2008, which resulted in reductions in depreciation expense at CIPS, and CILCO (Illinois Regulated), and an increase in depreciation expense at IP. Capital additions partially offset the benefit of the rate order at CIPS and CILCO (Illinois Regulated) and further increased depreciation and amortization expenses at IP. The net effect of the above items was a reduction in depreciation and amortization expenses at CILCO (Illinois Regulated) of $5 million and $17 million and an increase at IP of $3 million and $12 million in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008. Depreciation and amortization expenses at CIPS were comparable between periods.

Merchant Generation

Three and nine months - Depreciation and amortization expenses increased $7$8 million and $12 million, respectively, in the Merchant Generation segment, as discussed below.

Genco and CILCO (AERG)

Depreciation and amortization expenses increased $5 million and $2 million at Genco and CILCO (AERG), respectively, primarily because of capital additions at CILCO (AERG) and $3 million of expense recorded by Gencoincreased depreciation rates resulting from depreciation studies performed in the thirdfirst quarter of 2009 for the retirement of two generation units at its Meredosia power plant. Depreciation and amortization expenses were comparable at CILCORP (parent company only) and EEI between periods.2009.

Taxes Other Than Income Taxes

Ameren

Ameren’s taxes other than income taxes increased $6 million and $11$8 million in the three and nine months ended September 30, 2009, respectively,March 31, 2010, compared with the same periodsperiod in 2008,2009, primarily because of higher property taxes. Higher payrolland gross receipts taxes, also contributed to the increase in taxes other than income taxes in the nine-month period.as discussed below.

Variations in taxes other than income taxes in Ameren’s CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008,2009, were as follows:

Missouri Regulated (UE)

Three and nine months - Taxes other than income taxes increased $3$6 million, and $11 million, respectively, primarily because of higher property and gross receipts taxes. Higher payrollProperty taxes also contributed to the increaseincreased primarily because of higher assessed tax rates in Missouri. Gross receipts taxes other than income taxes in the nine-month period.were higher primarily as a result of increased sales.

Illinois Regulated

Three and nine months - Taxes other than income taxes were comparable between periods in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated), and IP.

Merchant Generation

Three and nine months - Taxes other than income taxes were comparable between periods in the Merchant Generation segment and at Genco and CILCO (AERG), CILCORP (parent company only), and EEI..

Other Income and Expenses

Ameren

Other income and expenses were comparableincreased $3 million in the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008. Miscellaneous expense decreased as expenses associated with energy efficiency and customer assistance programs under the Illinois electric settlement agreement were lower in the current year periods. Additionally, in the third quarter of 2008, Ameren made a contribution to its charitable trust, with no similar contribution in 2009. However, miscellaneous income declined2009, primarily because of reduced interest income, mitigating the above benefits.higher allowance for funds used during construction at UE.

Variations in other income and expenses in Ameren’s CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008,2009, were as follows:

Missouri Regulated (UE)

ThreeOther income and nineexpenses increased $8 million in the three months - ended March 31, 2010, compared with the same period in 2009, primarily because of higher allowance for funds used during construction associated with a project to install a scrubber at one of UE’s coal-fired power plants.

Illinois Regulated

Other income and expenses were comparable between periods.

Illinois Regulated

Three and nine months - Other income and expenses were comparableperiods in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated), and IP in the third quarter of 2009 with the same period in 2008. Other income and expenses decreased $7 million in the Illinois Regulated segment, and decreased at both CIPS and IP, in the nine months ended September 30, 2009, compared with the same period in 2008, primarily because of lower interest income. Other income and expenses at CILCO (Illinois Regulated) were comparable in the nine-month periods of the current and prior years.IP.

Merchant Generation

Three and nine months - Other income and expenses were comparable between periods in the Merchant Generation segment and at Genco and CILCO (AERG), CILCORP (parent company only), and EEI..

Interest Charges

Ameren

Ameren’s interest expensecharges increased $21 million and $45$14 million in the three and nine months ended September 30, 2009, respectively,March 31, 2010, compared with the same periodsperiod in 2008,2009, because of items noted below at the Ameren Companies.Companies and because of the issuance of $425 million of senior notes at Ameren in May 2009.

Variations in interest expensecharges in Ameren’s CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008,2009, were as follows:

Missouri Regulated (UE)

Three months - Interest expensecharges increased $10$6 million, primarily because of the issuance of $350 million of senior secured notes in March 2009 and fees recognized for new credit facilities entered into in the second quarter of 2009.

Nine months - Interest expense increased $29 million. Interest expense increased primarily because of the issuance of $350 million, $450 million and $250 million of senior secured notes in March 2009, June 2008 and April 2008, respectively. The recognitionamortization of fees related to new credit facilities entered into in the second quarter of 2009 also increased interest expense. Additionally, interest expense increasedcharges.

Illinois Regulated

Interest charges decreased $3 million in the first nine months of 2009, as compared with the prior-year period,Illinois Regulated segment, primarily because of favorable income tax settlements initems discussed below.

CIPS and CILCO (Illinois Regulated)

Interest charges were comparable between periods.

IP

Interest charges decreased $3 million, primarily because of the first quarter of 2008. The maturity of $148$250 million of first mortgage bonds in May 2008 and refinancing of auction rate environmental improvement revenue bonds in the 2008 period mitigated the impact of the above items.

Illinois Regulated

Three and nine months - Interest expense increased $3 million and $12 million, respectively, in the Illinois Regulated segment as discussed below.

CIPS

Three and nine months - Interest expense was comparable between periods.

CILCO (Illinois Regulated)

Three and nine months - Interest expense increased $3 million and $7 million, respectively, primarily because of the issuance of senior secured notes of $150 million in December 2008, at a higher rate than the short-term debt it refinanced.

IP

Three months - Interest expense was comparable between periods.

Nine months - Interest expense increased $4 million primarily because of the issuance of senior secured notes of $400 million and $337 million in October 2008 and April 2008, respectively. The unfavorable effect of the debt issuances was mitigated as the proceeds from the senior secured notes were used to refinance auction-rate pollution control revenue refunding bonds, which bore default rates ranging from 12% to 18%, and to reduce short-term borrowings.June 2009.

Merchant Generation

Three and nine months - Interest expensecharges increased $10$9 million and $8 million, respectively, in the Merchant Generation segment as discussed below.

Genco

Three months - Interest expense was comparable between periods.

Nine months - Interest expensecharges increased $3 million, primarily because of the issuance of $300$250 million of senior unsecured notes in April 2008,November 2009, partially reduced by lower short-term borrowings. Efforts to reduce, defer, and cancel capital expenditures have resulted in reduced borrowing as Genco has had sufficient cash to meet working capital needs.

CILCO (AERG)

Three and nine months - Interest expensecharges increased $6$4 million, in both the quarter and year-to-date periods primarily because of increased intercompany borrowings.

CILCORP (parent company only) and EEI

Three and nine months - Interest expense was comparable between periods at CILCORP (parent company only) and EEI.borrowings to provide cash needed for operations.

Income Taxes

The following table presents effective income tax rates by segment for the three months ended March 31, 2010 and 2009:

    Three Months 
    2010  2009 

Ameren

  41 33

Missouri Regulated

  44   33  

Illinois Regulated

  41   35  

Merchant Generation

  41   36  

Ameren

Three months - Ameren’s effective tax rate in the thirdfirst quarter of 20092010 was higher than the effective tax rate for the same period in the prior year, due to variations discussed below.

Nine months - Ameren’s effective tax rateyear. Legislation was passed in the first nine monthsquarter of 2009 was lower than2010 that results in retiree health care costs no longer being deductible for tax purposes to the effective tax rateextent an employer’s postretirement health care plan receives federal subsidies that provide retiree prescription drug benefit equivalent to Medicare prescription drug benefits. See Note 12 - Retirement Benefits under Part I, Item 1, of this report for additional information on the same period inimpact of the prior year, due toenactment of health care legislation. Other variations are discussed below.

Variations in effective tax rates for Ameren’s CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009,March 31, 2010, compared with the same periodsperiod in 2008,2009, were as follows:

Missouri Regulated (UE)

Three and nine months - TheUE’s effective tax rate in both periods was lowerhigher, primarily because of higherthe change in tax treatment of retiree health care costs, along with the decreased impact of favorable net amortization of property-related regulatory assets and liabilities.liabilities and permanent items on higher pretax book income.

Illinois Regulated

The effective tax rate for the thirdfirst quarter and first nine months of 20092010 was higher than the effective tax rate for the same periodsperiod in 20082009 in the Illinois Regulated segment, because of items detailed below.

CIPS and CILCO (Illinois Regulated)

Three and nine months - The effective tax rate in both periods was higherincreased, primarily because of the change in tax treatment of retiree health care costs, along with the decreased impact of favorable net amortization of property-related regulatory assets and liabilities, investment tax credit amortization, and permanent items on higher pretax book income.

CILCO (Illinois Regulated)IP

Three months - The effective tax rate was comparable between periods.

Merchant Generation

The effective tax rate for the first quarter of 2010 was higher than the effective tax rate for the same period in 2009 in the Merchant Generation segment, because of items detailed below.

Genco

The effective tax rate increased, primarily because of the decreased impactchange in tax treatment of permanent items, net amortization of property-related regulatory assets and liabilities, and amortization of investment tax credit on higher pretax book income.retiree health care costs.

Nine months - The effective tax rate was lower primarily because of the increased impact of permanent benefits from company-owned life insurance.CILCO (AERG)

IP

Three months - The effective tax rate was higher primarily because of the impact of permanent items and the net amortization of property-related regulatory assets and liabilities on higher pretax book income.

Nine months - The effective tax rate was lower, primarily because of the impact of permanent items and the net amortization of property-related regulatory assets and liabilities on pretax book income during the 2009 period as compared to a pretax book loss in the same period in 2008.

Merchant Generation

The effective tax rate for the third quarter and first nine months of 2009 was higher than the effective tax rate for the same periods in 2008 in the Merchant Generation segment because of items detailed below.

Genco

Three and nine months - The effective tax rate in both periods was higher primarily because of the impact of production activity deductions, along with changes to reserves for uncertain tax positions.

CILCO (AERG)

Threepositions and nine months - The effective tax rate was lower primarily because of the increased impact ofInternal Revenue Code Section 199 production activity deductions.

CILCORP (parent company only)

Three months - The effective tax rate was lower primarily because of the effect of permanent itemsdeductions on lower pretax book income.income, partially offset by the change in tax treatment of retiree health care costs.

Nine months - The effective tax rate was lower primarily because of the effect of the goodwill impairment loss of $462 million, which was a permanent item, on a pretax book loss.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated) and IP) continue to be thea principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial, and industrial classes and a commodity mix of natural gas and electric service provide a reasonably predictable source of cash flows for Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG rely on power sales to Marketing Company, which sold power through the September 2006 Illinois power procurement auction, financial contracts that were part of the 2007 Illinois electric settlement agreement,Electric Settlement Agreement and various power procurement processes in the 2008non-rate-regulated Illinois RFP process for energy and capacity that was used pursuant to the Illinois electric settlement agreement, and the 2009 RFP process for capacity and energy administered by the IPA.market. Marketing Company is also sellingsells power through other primarily market-based contracts with wholesale and retail customers. In addition to using cash flows from operating activities, the Ameren Companies use available cash, credit facilities, money pool, or other short-term borrowings from affiliates to support normal operations and other temporary capital requirements. The use of operating cash flows and credit facility or short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at September 30, 2009,March 31, 2010, for Genco CILCORP, and CILCO. The Ameren Companies may reduce their credit facility or short-term borrowings with cash from operations or discretionarily with long-term borrowings, or in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies expect to incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and natural gas utility infrastructure to improve overall system reliability. Ameren intends to finance those capital expenditures and investments with a blend of equity and debt so that it maintains a capital structure in its rate-regulated businesses containingof approximately 50% to 55% equity. We expect to make equity issuances in the future consistent with this objective, as well as to address any unanticipated events, should the need arise. We plan to implement our long-term financing plans for debt, equity, or equity-linked securities in order to appropriately finance our operations appropriately, meet scheduled debt maturities, and maintain financial strength and flexibility.

In 2008, the global capital and credit markets experienced extreme volatility, which continued into 2009. See Outlook for a discussion of the implications of this volatility for our industry as a whole, including the Ameren Companies, and how we addressed these issues.

The following table presents net cash provided by (used in) operating, investing and financing activities for the ninethree months ended September 30, 2009March 31, 2010 and 2008:2009:

 

  

Net Cash Provided By

Operating Activities

 

Net Cash (Used In)

Investing Activities

 

Net Cash Provided By

(Used In) Financing Activities

   Net Cash Provided By
(Used In) Operating Activities
 

Net Cash (Used In)

Investing Activities

 Net Cash Provided By
(Used In) Financing Activities
 
  2009 2008 Variance 2009 2008 Variance 2009 2008 Variance   2010 2009 Variance 2010 2009 Variance 2010 2009 Variance 

Ameren(a)

  $1,746   $1,253   $493   $(1,345 $(1,501 $156   $70   $99   $(29  $381   $516   $(135 $    (317 $    (432 $115   $(326 $128   $(454

UE

   680    555    125    (705  (794  89    254    54    200     34    (1  35    (190  (220  30    (56  248    (304

CIPS

   160    80    80    (41  (26  (15  (110  (66  (44   37    69    (32  (19  (18  (1  (8  (51  43  

Genco

   208    209    (1  (218  (230  12    11    21    (10   103    118    (15  (81  (83  2    (22  (35  13  

CILCORP

   201    108    93    (127  (222  95    37    108    (71

CILCO

   211    120    91    (128  (221  93    28    95    (67   72    52    20    (12  (58  46    (50  41    (91

IP

   351    120    231    (83  (139  56    (140  25    (165   34    117    (83  (49  (64  15    (56  76    (132

 

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

Cash Flows from Operating Activities

Ameren’s cash from operating activities increaseddecreased in the first ninethree months of 2010 compared with the first three months of 2009. The following items contributed to the decrease in cash from operating activities during the first three months of 2010, compared with the same period in 2009:

A reduction in cash collected in 2010 from receivables originating from revenues earned in 2009 compared with the year-ago period. At December 31, 2009, trade receivables and unbilled revenues were $142 million less than they were at December 31, 2008, primarily because of milder weather and lower natural gas commodity costs billed to our customers during the fourth quarter of 2009, compared with 2008.

Collections from customers, primarily in Illinois, utilizing our budget billing payment option decreased by $19 million from the prior-year period as the over-collected balance generated in 2009 reduced collections in 2010.

A $15 million increase in interest payments primarily due to UE’s senior secured notes issued in March 2009, which required an interest payment in 2010, but did not in 2009.

A decrease in natural gas costs over-recovered from customers under the PGA.

A $12 million increase in coal and transportation payments largely because of price increases.

A $12 million increase in property tax payments caused primarily by higher assessed tax rates in Missouri.

A $10 million one-time donation for customer assistance programs required by the 2009 Illinois energy legislation and approved by the ICC in February 2010.

At Ameren, the following items partially offset the decrease in cash from operating activities during the first ninethree months of 2008. Operating2010, compared with the same period in 2009:

A $23 million increase in cash from operating activities associated with the December 2005 Taum Sauk incident resulted in a $204 million increase in cash during the first nine months of 2009, compared with the same period in 2008.incident. The 20092010 increase was a result of a $78 million increase in insurance recoveries received as well as a $126$37 million reduction in cash payments partially offset by a $14 million reduction in insurance recoveries compared with 2009.

Improved collection results, primarily at the Ameren Illinois Utilities, as more utility customers were current on their bills as of March 31, 2010, compared with March 31, 2009.

An $18 million net reduction in collateral posted with counterparties due, in part, to UE’s net reduction in collateral postings, discussed below.

A $15 million decrease in major storm restoration costs.

An $11 million decrease in funding required under the terms of the 2007 Illinois Electric Settlement Agreement.

A net income tax refund of $5 million in 2010, compared with a net income tax payment of $5 million in 2009.

UE’s cash from operating activities increased in the first three months of 2010 compared with the prior-year period. See Note 9 - Commitments and Contingencies under Part I, Item I, of this report for information about the Taum Sauk property insurance settlement agreement with all but three of the property insurance carriers and the related settlement payment received during thefirst three months ended September 30,of 2009. Other factors contributingThe following items contributed to the increase in cash from operating activities during the first ninethree months of 2009,2010, compared with the same period in 2008, included a $189 million decrease in the cost of2009:

Higher electric and natural gas purchased for inventories because of lower prices, a decrease in income tax payments, net of refunds, of $146 million, a $66 million net reduction in collateral posted with suppliers due in part to improved credit ratings, an increase in electric costs over-recovered from Illinois customers under cost recovery mechanisms, and a $31 million increase in customer advances for construction. Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included lower electric margins as discussed in Results of Operations a $38 million increase in interest payments, a $16 million increase in pension and postretirement plan contributions, a $15 million increase in cash payments for major storm restoration costs, an increase in annual incentive compensation payments, and an $8 million increase in payments to a real estate development partnership. The price of natural gas has declined during 2009 compared withincluding the increases experienced during 2008. These pricing fluctuations were the principal causebenefits of the net working capital decrease associated with accounts and wages payable.

UE’s cash from operating activities increased in the first nine months of 2009 compared with the first nine months of 2008. TheMoPSC electric rate increase was primarily due to a $204effective March 1, 2009.

A $23 million increase in cash from operating activities associated with the December 2005 Taum Sauk incident as discussed aboveabove.

A $17 million net reduction in collateral posted with counterparties due in part to the absence in 2010 of collateral posted on a foreign currency swap position that was closed in June 2009.

The absence of $9 million of major storm restoration costs as no major storm occurred during 2010.

A $5 million reduction in coal and transportation payments as tons purchased decreased.

At UE, the following items partially offset the increase in cash from operating activities during the first three months of 2010, compared with the same period in 2009:

A net income tax payment of $22 million in 2010, compared with a $203net income tax refund of $15 million in 2009 primarily due to higher pretax book income in the current period.

A $12 million increase in property tax payments caused primarily by higher assessed tax rates in Missouri.

A $10 million increase in interest payments primarily due to the senior secured notes issued in March 2009, which required an interest payment in 2010, but did not in 2009.

A $2 million increase in payments associated with the Callaway nuclear plant refueling and maintenance outage that is currently underway.

CIPS’ cash from operating activities decreased in the first three months of 2010 compared with the first three months of 2009. The following items contributed to the decrease in cash from operating activities during the first three months of 2010, compared with the same period in 2009:

A reduction in cash collected in 2010 from receivables originating from revenues earned in 2009 compared with the year-ago period. At December 31, 2009, trade receivables and unbilled revenues were $51 million less than they were at December 31, 2008, primarily because of milder weather and lower natural gas commodity costs billed to our customers during the fourth quarter of 2009, compared with 2008.

Collections from customers utilizing our budget billing payment option decreased by $6 million from the prior-year period as the over-collected balance generated in 2009 reduced collections in 2010.

A $9 million increase in income tax payments, net of refunds. Other factors contributingrefunds primarily due to higher pretax book income.

A $2 million one-time donation for customer assistance programs required by the 2009 Illinois energy legislation and approved by the ICC in February 2010.

At CIPS, the following items partially offset the decrease in cash from operating activities during the first three months of 2010, compared with the same period in 2009:

Higher electric and natural gas margins as discussed in Results of Operations.

An increase in electric commodity costs over-recovered from customers under cost recovery mechanisms.

Improved collection results as more utility customers were current on their bills as of March 31, 2010, compared with March 31, 2009.

A $4 million decrease in major storm restoration costs.

A $3 million decrease in funding required under the terms of the 2007 Illinois Electric Settlement Agreement.

A $4 million over-collection through its environmental adjustment rate riders, which is a $3 million increase over the prior-year period.

Genco’s cash from operating activities decreased in the first three months of 2010 compared with the first three months of 2009. The following items contributed to the decrease in cash from operating activities during the first three months of 2010, compared with the same period in 2009:

A $44 million reduction in receipts from Marketing Company under the Genco PSA.

A $9 million increase in coal and transportation payments, primarily at EEI, where both the price and tons purchased increased.

At Genco, the following items partially offset the decrease in cash from operating activities during the first three months of 2010, compared with the same period in 2009:

A $29 million reduction in income taxes paid primarily due to lower pretax book income.

A $1 million reduction in funding required by the 2007 Illinois Electric Settlement Agreement.

CILCO’s cash from operating activities increased in the first three months of 2010 compared with the first three months of 2009. The following items contributed to the increase in cash from operating activities during the first ninethree months of 2009,2010, compared with the same period in 2008, included2009:

A net income tax refund of $2 million in 2010, compared with a $21net income tax payment of $23 million decrease in 2009.

The absence in 2010 of $12 million of payments under the cost of natural gas inventories because of lower prices and antolling agreement with Medina Valley. CILCO transferred the tolling agreement to Marketing Company in January 2009.

A $10 million increase in gasreceipts at AERG from Marketing Company under the AERG PSA due to improved plant performance.

An $8 million increase in receipts that originated from services provided to CIPS ($4 million) and IP ($4 million) in December 2009 under the CILCO support services agreement.

An increase in electric commodity costs over-recovered from customers under cost recovery mechanisms.

Improved collection results as more utility customers were current on their bills as of March 31, 2010, compared with March 31, 2009.

A $2 million decrease in funding required under the PGA. Factors reducingterms of the 2007 Illinois Electric Settlement Agreement.

At CILCO, the following items partially offset the increase in cash from operating activities during the first ninethree months of 2009,2010, compared with the same period in 2008, included the collection of an $85 million affiliate receivable2009:

A reduction in 2008 that did not occurcash collected in 2010 from receivables originating from revenues earned in 2009 compared with the year-ago period. At December 31, 2009, trade receivables and unbilled revenues were $45 million less than they were at December 31, 2008, primarily because of milder weather and lower electric and natural gas margins as discussed in Results of Operations, a $42 million increase in interest payments, a $7 million increase in major storm restorationcommodity costs and a $7 million increase in pension and other postretirement plan contributions.

CIPS’ cash from operating activities increased inbilled to our customers during the first nine monthsfourth quarter of 2009, compared with the first nine months of 2008. Factors contributing to the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $34 million decrease in the cost of natural gas purchased for inventories because of lower prices, a $32 million net reduction in collateral posted with suppliers due in part to improved credit ratings, an increase in electric costs over-recovered from customers under cost recovery mechanisms, higher

Lower electric margins as discussed in Results of Operations, and a $4 million decrease in interest payments. Further, as discussed in Note 8 - Related Party Transactions under Part 1, Item 1, of this report, in September 2009, CIPS received $5 million from Marketing Company for the costs of upgrades to CIPS’ electric transmission system. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $17 million increase in income tax payments, net of refunds and aOperations.

A decrease in natural gas costs over-recovered from customers under the PGA.

Genco’s

An $8 million increase in coal and transportation payments at AERG where both the price and quantity of tons purchased increased.

A $2 million one-time donation for customer assistance programs required by the 2009 Illinois energy legislation and approved by the ICC in February 2010.

IP’s cash from operating activities decreased in the first ninethree months of 2009 was comparable2010 compared with the first ninethree months of 2008. Factors contributing2009. The following items contributed to a decrease in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included lower margins as discussed in Results of Operations, a $24 million increase in income tax payments, net of refunds, and a $7 million increase in interest payments. The 2008 operating cash flows were augmented with the receipt of a $60 million lump-sum payment from a coal mine owner for the early termination of a coal supply contract. Factors offsetting the decrease in cash from operating activities during the first ninethree months of 2009,2010, compared with the same period in 2008, included less2009:

A reduction in cash used for fuel purchases as coal inventory levels increasedcollected in 2008 but were held constant2010 from receivables originating from revenues earned in 2009 a favorable change in an affiliate’s accounts receivable balance,compared with the year ago period. At December 31, 2009, trade receivables and an $8unbilled revenues were $88 million reduction in funding required byless than they were at December 31, 2008, primarily because of milder weather and lower natural gas commodity costs billed to our customers during the Illinois electric settlement agreement.

CILCORP’s and CILCO’s cash from operating activities increased in the first nine monthsfourth quarter of 2009, compared with 2008.

Collections from customers utilizing our budget billing payment option decreased by $9 million from the first nine months of 2008. Factors contributingprior-year period as the over-collected balance generated in 2009 reduced collections in 2010.

An $8 million net increase in collateral posted with counterparties due in part to changes in power positions associated with the increaseIllinois power procurement process.

A decrease in electric commodity costs over-recovered from customers under cost recovery mechanisms.

A $6 million one-time donation for customer assistance programs required by the 2009 Illinois energy legislation and approved by the ICC in February 2010.

At IP, the following items partially offset the decrease in cash from operating activities during the first ninethree months of 2009,2010, compared with the same period in 2008, included a $60 million decrease in the cost of natural gas purchased for inventories because of lower prices, a $19 million net reduction in collateral posted with suppliers due in part to improved credit ratings, an increase in natural gas costs over-recovered from customers under the PGA, and higher electric margins as discussed in Results of Operations. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007.

2009:

Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $40 million increase in income tax payments, net of refunds, for CILCORP and a $43 million increase for CILCO, more cash used for the purchase of coal as inventory levels increased at AERG because of lower-than-expected output, a $5 million increase in pension and other postretirement plan contributions, and an increase in annual incentive compensation payments.

IP’s cash from operating activities increased in the first nine months of 2009 compared with the first nine months of 2008. Factors contributing to the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included higherHigher electric and natural gas margins as discussed in Results of Operations, a $74Operations.

Improved collection results as more utility customers were current on their bills as of March 31, 2010, compared with March 31, 2009.

A $5 million decrease in the cost of natural gas purchased for inventories because of lower prices, a $42 million net decrease in collateral posted with suppliers due in part to improved credit ratings, and an increase in natural gas cost over-recovered from customersfunding required under the PGA. Additionally, more cash was collected in 2009 from receivables, becauseterms of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included2007 Illinois Electric Settlement Agreement.

An $8 million over-collection through its environmental adjustment rate riders, which is a $34$3 million increase in income tax payments, net of refunds, and a $13 million increase in interest payments.over the prior-year period.

Cash Flows from Investing Activities

Ameren’sAmeren used less cash used for investing activities decreased duringin the first ninethree months of 20092010 compared with the first ninethree months of 2008. The decrease was primarily driven2009. Net cash used for capital expenditures decreased in 2010 as a result of efforts to reduce, defer or cancel capital expenditure programs in light of economic conditions. Additionally, costs associated with power plant scrubber projects decreased from 2009 as a result of the completion of projects in our Merchant Generation segment. These reductions in capital expenditures were partially offset by a $114 million decreasean increase in nuclear fuel expenditures.costs related to the timing of purchases.

UE’s cash used in investing activities decreased during of the first ninethree months of 2009,2010, compared with the same period in 2008,2009, principally because of a $114$51 million decrease in nuclear fuel expenditures.capital expenditures related to a $36 million reduction of capital expenditures to repair severe storm damage, as well as other reductions, deferrals or cancellations of capital expenditure programs. Partially offsetting this decrease was a $43$20 million increase in capitalnuclear fuel expenditures primarily as a resultrelated to the timing of increased storm restoration expenditures and Taum Sauk rebuild expenditures.purchases.

CIPS’ cash used in investing activities during the first ninethree months of 2010 and the first three months of 2009 increased compared with the same period in 2008. The $18 million increase inconsist of capital expenditures wasrelated to the resultmaintenance and reliability of increased storm restorationthe transmission and distribution system. These expenditures during the 2009 period.were comparable between periods.

Genco’s cash used in investing activities decreased in the first ninethree months of 2009 compared2010 was comparable with the same period in 2008, principally because2009. Net cash used for capital expenditures decreased by $41 million primarily as a result of the completion of a $13 million decrease inpower plant scrubber project. The cash savings related to efforts to reduce, defer or cancel capital expenditure programs enabled Genco to contribute net money pool advances.advances of $41 million during the 2010 period.

CILCORP’s and CILCO’s cash used in investing activities decreased in the first ninethree months of 2009,2010, compared with the same period in 2008, primarily2009, as a result of a $95$44 million decrease in capital expenditures because of reduced spending related tothe completion of a power plant scrubber project at AERG. Capital expenditures related to the maintenance and reliability of the transmission and distribution system at CILCO were comparable between periods.

IP’s cash used in investing activities decreased in the first ninethree months of 2009,2010, compared with the same period in 2008,2009, principally as a result of the returnadvances to AITC for construction under a joint ownership agreement, primarily related to ongoing independent power producer transmission projects, and funding of money pool advances.advances during the 2009 period. Capital expenditures related to the maintenance and reliability of the transmission and distribution system increased $7 million in the first three months of 2010, compared with the same period in 2009, as the result of timing of payments.

Capital Expenditures

Ameren has identified approximately $2 billionDuring the first quarter of opportunities to reduce planned2010, Ameren’s Merchant Generation segment reduced its estimated capital spending for 2010 through 2013, ascosts by $435 million, compared to earlier plans. Approximately $1 billion ofthose disclosed in its Form 10-K. The reduction in estimated capital expenditures were eliminated fromcosts primarily related to a $420 million reduction in estimated costs to comply with state air quality implementation plans, the MPS, federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. Merchant Generation’s previous estimates for this period. Ameren’s rate-regulated businesses have identified,could change depending upon additional federal or state requirements, the requirements under a MACT standard, new technology, and are evaluating for possible eliminationvariations in costs of material or deferral, approximately $1 billionlabor, or alternative compliance strategies, among other factors. These estimates in the table below contain all of previously plannedMerchant Generation’s known capital expenditures.costs to comply with existing and known emissions-related regulations as of March 31, 2010.

The following table provides estimates as of March 31, 2010 of capital expenditures that are expected to be incurred by the Ameren Companies from 20092010 through 2013,2014, including construction expenditures, capitalized interest for our Merchant Generation business and allowance for funds used during construction for our rate-regulated utility businesses, and estimated expenditures for compliance with environmental standards. Although $2 billion of opportunities have been identified to reduce planned capital spendingThe reduced estimates for 2010 through 2013,Ameren’s Merchant Generation segment described above are reflected in the table below only reflects the approximately $1 billion of planned capital expenditures eliminated in the Merchant Generation business.below.

 

  2009  2010 - 2013 Total   2010 2011 - 2014 Total 

UE

  $835  $3,335-  $4,435   $4,170-  $5,270    $695   $2,565-  $3,465   $3,260-  $4,160  

CIPS

   90   350-   475    440-   565     95    340-   460    435-   555  

Genco

   315   515-   675    830-   990     115    590-   950    705-   1,065  

CILCO (Illinois Regulated)

   75   250-   340    325-   415     60    250-   340    310-   400  

CILCO (AERG)

   70   420-   550    490-   620     5    130-   175    135-   180  

IP

   220   715-   960    935-   1,180     175    670-   910    845-   1,085  

EEI

   50   40-   65    90-   115  

Other

   60   75-   100    135-   160     50    125-   170    175-   220  

Ameren(a)

  $  1,715  $  5,700-  $  7,600   $  7,415-  $  9,315    $  1,195   $  4,670-  $  6,470   $  5,865-  $  7,665  

 

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

See Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for a discussion of future environmental capital expenditure estimates.

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.

Cash Flows from Financing Activities

Ameren’s cash provided by financing activities decreased in the first nine months of 2009 compared with the first nine months of 2008 primarily because of a $674 million increase in short-term debt repayments, a $563 million decrease in proceeds from the issuance of long-term debt, and a $55 million increase in capital issuance costs. During the first ninethree months of 2010, Ameren used existing cash and credit facility borrowings to fund its working capital needs, fund $91 million of common stock dividends and repay $33 million of net generator advances for construction related to ongoing independent power producer transmission projects. Comparatively, during the first three months of 2009, Ameren issued $775$350 million of senior debtsecured notes and used the proceeds to repayreduce short-term borrowingsdebt and by waypay $82 million of acommon stock dividends. In addition, Ameren received $21 million of net advances from generators in the first quarter of 2009.

Efforts to reduce, defer and cancel capital contributionexpenditures enabled UE to CILCORP, permitted CILCORPuse existing cash to repayfund its outstanding senior notes on their October 15, 2009 due date. Comparatively,working capital

needs during the first nine monthsquarter of 2008, Ameren’s subsidiaries2010. During the first quarter of 2009, UE issued $1.3 billion$350 million of senior debtsecured notes and used the proceeds to repurchase, redeem, and fund maturities of $823 million of long-term debt, reduce short-term debt and fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO, and IP. Ameren’s capital issuance costsreduce borrowings under an intercompany note with Ameren. Common stock dividends increased in$6 million during the first ninethree months of 2009 as compared to the prior-year period because of $40 million in banking fees associated with the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement and $17 million of capital issuance costs associated with Ameren’s September 2009 common stock issuance, partially offset by a decrease in capital issuance costs associated with long-term debt. Mitigating the decrease in cash from financing activities was a $573 million decrease in long-term debt redemptions, a $510 million increase in net proceeds from the issuance of common stock, and a $152 million decrease in common stock dividends. In September 2009, Ameren received $552 million in gross proceeds from the issuance of its common stock. The proceeds were used to fund equity contributions to its rate-regulated utility subsidiaries. An additional $65 million of common stock was issued through Ameren’s DRPlus and benefit plans. The decrease in dividends paid on Ameren common stock was the result of the reduction of the quarterly dividend rate.

UE’s net cash provided by financing activities increased in the first nine months of 2009,2010 compared with the same periodfirst three months of the prior year, primarily because of a $436 million capital contribution from Ameren funded by the proceeds of Ameren’s September 2009 common stock issuance, a $378 million decrease in redemptions of long-term debt, and a $23 million decrease in common stock dividend payments. The proceeds from the capital contribution were primarily used to reduce outstanding short-term borrowings.

These benefits in cash from financing activities were partially offset by a $350 million decrease in long-term debt issuances, a $169 million increase in short-term debt repayments and a $109 million increase in repayments under an intercompany borrowing arrangement with Ameren.2009.

CIPS’ net cash used in financing activities increaseddecreased during the ninethree months ended September 30, 2009,March 31, 2010, compared with the first ninethree months of 2008.2009. This change was primarily a result of CIPS using existing cash to meet its working capital needs and fund $8 million in common stock dividends. During the first three months of 2009, CIPS used existing cash to fund a net reduction in short-term debt and money pool borrowings. Additionally, CIPS paid dividends of $12 million to Ameren in 2009 and had a $3 million increase in debt issuance costs as a result of the banking fees associated with the 2009 Illinois Credit Agreement. Benefiting the 2009 period was a $13 million capital contribution from Ameren.

Genco’s cash provided byused in financing activities decreased during the ninethree months ended September 30, 2009,March 31, 2010, compared with the ninethree months ended September 30, 2008,March 31, 2009, primarily as a result of a $300$29 million decrease in long-term debt issuances. Benefits to cash during the 2009 period included a net $100 million increase in short-term borrowings, compared with net repayments of $100 million during the 2008 period, and an $84 million decreasereduction in common stock dividends.

CILCORP’s cash provideddividends paid by EEI. Efforts to reduce, defer and cancel capital expenditures have resulted in reduced Genco financing activities decreased during the nine months ended September 30, 2009, compared with the same period in 2008, primarily as a result of the change in CILCORP’s money pool borrowings, a $198 million increase in repayments of short-term borrowings and a $14 million increase inGenco has been able to use existing cash to meet working capital issuance costs, as a result of banking fees associated with the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. During the 2009 period, CILCORP repaid a net $98 million to the money pool compared with net borrowings of $171 million in the 2008 period. Partially offsetting these decreases were increased intercompany borrowings that were used to reduce CILCORP’s short-term debt and outstanding money pool borrowings, compared with the 2008 period, and a $36 million capital contribution received from Ameren in 2009.needs.

CILCO’s cash provided by financing activities decreased during the first nine monthsquarter of 2009 compared with the year-ago period, primarily as a result of the change2010 resulted in CILCO’s money pool borrowings, $196 million increase in repayments of short-term borrowings, and a $7 million increase in capital issuance costs as a result of banking fees associated with the 2009 Illinois Credit Agreement. During the 2009 period CILCO repaid a net $98 million to the money pool compared with receiving $171 million of net borrowings in the 2008 period. Cash from financing activities benefited from a $334 million increase in intercompany borrowings from Ameren during the first nine months of 2009, a $36 million capital contribution from CILCORP and a $35 million decrease in redemptions of long-term debt and preferred stock.

IP had a net use of cash, fromwhile such activities generated positive cash flows during the first quarter of 2009. During 2010, CILCO used existing cash to fund its working capital needs and fund a net repayment of intercompany borrowings with Ameren. During the first three months of 2009, CILCO used money pool borrowings and intercompany borrowings to meet its working capital needs and to repay short-term borrowings.

IP’s financing activities during the first nine monthsquarter of 2009, compared with2010 resulted in a net sourceuse of cash, while such activities generated positive cash flows during the first nine monthsquarter of 2008, primarily as a result of a $336 million decrease in long-term debt issuances, a $129 million decrease in net short-term debt borrowings, and a $5 million increase in debt issuance costs.2009. During the 2009 period, these decreases to cash from financing activities were offset by a $141 million decrease in redemptions and maturities of long-term debt, including IP SPT, and a $119 million capital contribution received from Ameren. During 2009,2010, IP used existing cash to fund the current maturity of its 7.50% mortgage bonds and to pay $7 million for banking fees associated with the 2009 Illinois Credit Agreement. Comparatively, during the nine months ended September 30, 2008, IP issued of $337working capital needs, fund $21 million of senior secured notes to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds, which had adjusted to higher rates as a result of the collapse of the auction-rate securities market, and to fund debt maturities and common stock dividends.dividends, and repay $34 million of net generator advances. During 2009, IP received $19 million of net generator advances related to ongoing independent power producer transmission projects, and a $58 million capital contribution from Ameren. The capital contribution was made to ensure IP maintained a capital structure of approximately 50% to 55% to equity.

Short-termCredit Facility Borrowings and Liquidity

ExternalThe liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, typically consist ofor drawings under committed bank credit facilities. See Note 3 - Short-termCredit Facility Borrowings and Liquidity under Part I, Item 1, of this report for additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.

The following table presents the various committed bank credit facilities of Ameren and the Ameren Companies, and their availability, as of September 30, 2009:March 31, 2010:

 

Credit Facility  Expiration Amount Committed Amount Available   Expiration Amount Committed Amount Available 

Ameren, UE and Genco:

        

2009 multiyear revolving(a)(b)

  July 2011   $1,300   $874(d) 

2009 Multiyear credit agreements(a)(b)

  July 2011   $1,300   $655(c) 

Ameren, CIPS, CILCO and IP:

        

2009 multiyear revolving(c)

  June 2011    800    800  

2009 Illinois credit agreements

  June 2011    800    800  

 

(a)The Ameren Companies may access thisthese credit facilityfacilities through intercompany borrowing arrangements.
(b)Includes the 2009 Multiyear Credit Agreement and the 2009 Supplemental Credit Agreement. The 2009 Supplemental Credit Agreement will terminate in July 2010 with all commitments and all outstanding amounts being consolidated with those under the 2009 Multiyear Credit Agreement and the combined maximum amount available to all borrowers being $1.0795 billion with the UE and Genco Borrowing Sublimits remaining the same and Ameren’s changing to $1.0795 billion. The combined maximum amount available to each borrower under both of the agreements at September 30, 2009, including for the issuance of letters of credit, was limited as follows: Ameren - $1.15 billion, UE - $500 million, and Genco - $150 million.
(c)The maximum amount available to each borrower under this facility at September 30, 2009, including for the issuance of letters of credit, was limited as follows: Ameren - $300 million, CIPS - $135 million, CILCO - $150 million, and IP - $350 million.
(d)In addition to amounts drawn on these facilities, the amount available is further reduced by standby letters of credit issued under the facilities. The amount of such letters of credit at September 30, 2009,March 31, 2010, was $11$15 million.

On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. See Note 3 - Short-term Borrowings and Liquidity under Part I, Item I, of this report for additional information.

Since CILCORP and AERG are not borrowers under the 2009 Illinois Credit Agreement, CILCORP and AERG expect to meet their external liquidity needs through borrowings under the Ameren non-state-regulated money pool arrangements or other liquidity arrangements.

In addition to committed credit facilities, a furtherAnother source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At September 30, 2009,March 31, 2010, Ameren (on a consolidated basis), UE, CIPS, Genco, CILCORP (on a consolidated basis), CILCO, and IP had $563 million, $229 million, $9 million, $3 million, $111 million, $111 million, and $178 million, respectively, of cash and cash equivalents.equivalents totaling $360 million, $55 million, $38 million, $6 million, $98 million, and $119 million, respectively.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2008,2010, FERC issued an order authorizing the issuance of short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion, CIPS - $250$300 million, and CILCO - $250 million. The authorization was effective as of April 1, 2008,2010, and terminates on March 31, 2010.2012. IP has unlimited short-term debt authorization from FERC.

Genco was authorized by FERC in its March 20082010 order to have up to $500 million of short-term debt outstanding at any time. AERG and EEI have unlimited short-term debt

authorization from FERC. On April 27, 2010, Genco filed an application with FERC requesting unlimited debt issuance authorization.

The issuance of short-term debt securities by Ameren and CILCORP (parent) 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 facilities or other short-term borrowing arrangements.

Long-term Debt and Equity

The following table presents the issuances of common stock and the issuances redemptions, repurchases and maturities of long-term debt and preferred stock (net of any issuance discounts and including any redemption premiums) for the ninethree months ended September 30,March 31, 2010 and 2009, and 2008, for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report.

 

    

Month Issued, Redeemed,

Repurchased or Matured

  Nine Months 
      2009  2008 

Issuances

            

Long-term debt

     

Ameren:

     

8.875% Senior unsecured notes due 2014

  May  $423   $-  

UE:

     

6.00% Senior secured notes due 2018

  April   -    250  

6.70% Senior secured notes due 2019

  June   -    449  

8.45% Senior secured notes due 2039

  March   349    -  

Genco:

     

7.00% Senior unsecured notes due 2018

  April   -    300  

IP:

     

6.25% Senior secured notes due 2018

  April   -    336  

Total Ameren long-term debt issuances

     $772   $1,335  

Common stock

     

Ameren:

     

21,850,000 shares at $25.25

  September  $552   $-  

DRPlus and 401(k)

  Various   65    107  

Total common stock issuances

     $617   $107  

Total Ameren long-term debt and common stock issuances

     $1,389   $1,442  

Redemptions, Repurchases and Maturities

            

Long-term debt

     

UE:

     

2000 Series B environmental improvement bonds due 2035

  April  $-   $63  

2000 Series A environmental improvement bonds due 2035

  May   -    64  

2000 Series C environmental improvement bonds due 2035

  May   -    60  

1991 Series environmental improvement bonds due 2020

  May   -    43  

6.75% Series first mortgage bonds due 2008

  May   -    148  

CIPS:

     

2004 Series pollution control bonds due 2025

  April   -    35  

CILCO:

     

2004 Series pollution control bonds due 2039

  April   -    19  

IP:

     

Series 2001 Non-AMT bonds due 2028

  May   -    112  

Series 2001 AMT bonds due 2017

  May   -    75  

1997 Series A pollution control bonds due 2032

  May   -    70  

1997 Series B pollution control bonds due 2032

  May   -    45  

1997 Series C pollution control bonds due 2032

  June   -    35  

Note payable to IP SPT:

     

5.65% Series due 2008

  Various   -    54  

7.50% Series mortgage bond due 2009

  June   250    -  

Preferred stock

            

CILCO:

     

5.83% Series

  July  $-   $16  

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

     $250   $839  
    

Month Issued

  Three Months 
      2010  2009 

Issuances

            

Long-term debt

     

UE:

     

8.45% Senior secured notes due 2039

  March  $-   $349  

Total Ameren long-term debt issuances

     $-   $349  

Common stock

     

Ameren:

     

DRPlus and 401(k)

  Various  $20   $28  

Total common stock issuances

     $20   $28  

Total Ameren long-term debt and common stock issuances

     $20   $377  

In November 2008, Ameren, as a well-known seasoned issuer, along with CIPS, Genco, CILCO and IP, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in November 2011. In June 2008, UE, as a well-known seasoned issuer, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2011.

The following table presents information with respect to the Form S-3 shelf registration statements filed and effective for certain Ameren Companies as of September 30, 2009:March 31, 2010:

 

    

Effective

Date

  

Authorized

Amount

Ameren(a)

  November 2008  Not Limited 

UE(b)

  June 2008  Not Limited 

CIPS(a)

  November 2008  Not Limited 

Genco(a)

  November 2008  Not Limited 

CILCO(a)

  November 2008  Not Limited 

IP(a)

  November 2008   Not Limited 

(a)In November 2008, Ameren, as a well-known seasoned issuer, along with CIPS, Genco, CILCO and IP, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in November 2011.
(b)In June 2008, UE, as a well-known seasoned issuer, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2011.

In September 2009, Ameren issued and sold 21.9 million shares of its common stock at $25.25 per share, for proceeds of $535 million, net of $17 million of issuance costs. Ameren used the net offering proceeds to make investments in its rate-regulated utility subsidiaries in the form of capital contributions as follows: UE - $436 million, CIPS - $13 million, CILCO - $25 million, and IP - $61 million.

In July 2008, Ameren filed a Form S-3 registration statement with the SEC authorizing the offering of six million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus.

Ameren is also currently selling newly issued shares of its common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan, Ameren issued a total of 0.70.8 million new shares of common stock valued at $18 million and 2.6 million new shares of common stock valued at $65$20 million in the three and nine months ended September 30, 2009, respectively.March 31, 2010.

Ameren, UE, CIPS, Genco, CILCO and IP may sell all or a portion of the securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

See Note 3 - Short-term Borrowings and Liquidity under Part I, Item 1, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. See Note 4 - Short-termCredit Facility Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a discussion of covenants and provisions contained in the Prior $1.15 Billion Credit Facility, the 2009 $20 million term loan agreementour bank credit facilities and in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

At September 30, 2009,March 31, 2010, the Ameren Companies were in compliance with their credit facility, term loan agreement,facilities, indenture, and articles of incorporation provisions and covenants.

We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However,

events beyond our control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.

Dividends

Ameren paid to its stockholders common stock dividends totaling $247$91 million, or 1.15538.5 cents per share, during the first ninethree months of 2009 (20082010 (2009 - $399$82 million or $1.90538.5 cents per share). On April 27, 2010, Ameren’s board of directors declared a quarterly common stock dividend of 38.5 cents per share payable on June 30, 2010, to stockholders of record on June 9, 2010.

See Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report and Note 4 - Short-termCredit Facility Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At September 30, 2009,March 31, 2010, none of these circumstances existed at the Ameren Companies and, as a result, theythe Ameren Companies were allowed to pay dividends.

UE, CIPS, Genco, CILCO IP and GencoIP as well as other certain 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 dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, CIPS, CILCO and IP may not pay any dividend on their respective stock, unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless CIPS, CILCO or IP has specific authorization from the ICC.

The following table presents common stock dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the ninethree months ended September 30, 2009March 31, 2010 and 2008:2009:

 

  Nine Months   Three Months 
  2009 2008   2010 2009 

UE

  $170   $193    $58   $52  

CIPS

   12    -     8    -  

Genco

   -    84     -    23  

CILCO

   4    -  

IP

   -    45     21    -  

Nonregistrants

   65    77     -    7  

Dividends paid by Ameren

  $247   $399    $91   $82  

Contractual Obligations

For a complete listing of our obligations and commitments, see Other Obligations in Note 9 - Commitments and Contingencies under Part I, Item 1 and Contractual Obligations under Part II, Item 7 of this report, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. Also see10-K, and Other Obligations in Note 9 - Commitments and Contingencies under Part I, Item 1, of this report. See Note 12 - Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

Subsequent to DecemberAt March 31, 2008,2010, total other obligations related to the procurement of coal, natural gas, nuclear fuel, methane gas, and electric capacity materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $6,629were $6,511 million, $3,541 million, $331$313 million, $681$1,055 million, $995 million, $995$972 million, and $630$618 million, respectively. Total other obligations, including commitments for the purchase of equipment and the unrecognized tax benefits, at September 30, 2009,March 31, 2010, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $645$832 million, $403$498 million, $23 million, $8$81 million, $34 million, $34$63 million, and $122$116 million, respectively.

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over four years as part of a comprehensive program providing approximately $1 billion of funding for rate relief to certain Illinois customers, including customers of the Ameren Illinois Utilities. Of this $150 million, $60 million will come from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco, and $28 million from AERG. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended September 30, 2009, of $6 million, $1 million, $1 million, $1 million, $3 million, and $1 million, respectively (quarter ended September 30, 2008 - $10 million, $2 million, less than $1 million, $2 million, $4 million, and $2 million, respectively) and during the nine months ended September 30, 2009, of $18 million, $3 million, $1 million, $4 million, $7 million, and $3 million, respectively (nine months ended September 30, 2008 - $32 million, $5 million, $2 million, $6 million, $13 million, and $6 million, respectively) under the terms of the Illinois electric settlement agreement. At September 30, 2009, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $10 million, $3 million, $2 million, and $5 million, respectively. See Outlook and Note 2 - Rate and Regulatory Matters under Part I, Item 1 of this report for additional information regarding the Illinois electric settlement agreement.

Credit Ratings

The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P and Fitch effective on the date of this report:

 

    Moody’s  S&P  Fitch 

Ameren:

    

Issuer/corporate credit rating

  Baa3   BBB BBB

Senior unsecured debt

  Baa3   BB BBB

UE:

    

Issuer/corporate credit rating

  Baa2   BBB BBB

Secured debt

  A3   BBB   A  

CIPS:

    

Issuer/corporate credit rating

  Baa3   BBB BBB

Secured debt

  Baa1   BBB BBB

Senior unsecured debt

  Baa3   BBB BBB  

Genco:

    

Issuer/corporate credit rating

  -   BBB BBB

Senior unsecured debt

  Baa3   BBB BBB

CILCORP:

Issuer/corporate credit rating

-BBBBBB

Senior unsecured debt

Ba1BBBBB

CILCO:

    

Issuer/corporate credit rating

  Baa3   BBB BBB  

Secured debt

  Baa1   BBB A

IP:

    

Issuer/corporate credit rating

  Baa3   BBB BBB

Secured debt

  Baa1   BBB   BBB

Moody’s Ratings Actions

On January 29, 2009, Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and IP and changed their rating outlooks to stable from positive. According to Moody’s, the change in the rating outlooks of these four companies was based on the near-term expiration of the 2007 and 2006 $500 million credit facilities in January 2010 and related liquidity concerns. Moody’s also on January 29, 2009, affirmed the ratings of Ameren and UE with a stable outlook based on the January 2009 MoPSC electric rate order approving a rate increase and a FAC for UE. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for a discussion of the rate order issued by the MoPSC in January 2009.

On February 16, 2009, Moody’s affirmed the ratings of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP with a stable outlook. The affirmation reflected Moody’s view that Ameren’s announcement to reduce its common stock dividend by 39% was a conservative, prudent, and credit positive action that will conserve cash and support financial coverage metrics. Moody’s stated that the more conservative dividend payout should also help facilitate the renewal of Ameren Companies’ credit facilities that expire in 2010. They stated the dividend reduction should continue to reduce reliance on the credit facilities going forward and will likely be

viewed favorably by lenders considering renewing or entering into new facilities with Ameren and its subsidiaries, which is important considering currently constrained credit market conditions. According to Moody’s, the stable outlook on Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP reflected recently constructive rate case outcomes at UE, CIPS, CILCO and IP, including the approval of a FAC at UE; the improving regulatory environments for investor-owned utilities in Illinois and Missouri; and Moody’s expectation that financial and cash flow coverage metrics should remain adequate to maintain current rating levels. In addition, Moody’s noted that the recent dividend reduction is supportive of the stable ratings outlooks and provides Ameren and its subsidiaries additional cushion at current rating levels.

On July 1, 2009, Moody’s stated that the successful execution of new two-year bank credit facilities is supportive of the credit quality of Ameren and its utility subsidiaries. However, Moody’s did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.

On August 3, 2009, Moody’s upgraded the majority of senior secured debt ratings of investment-grade regulated utilities by one notch. Senior secured debt ratings at UE were upgraded from Baa1 to A3 and were upgraded at CIPS and IP from Baa3 to Baa2. Moody’s stated the rating action widens the notching between most senior secured debt ratings and senior unsecured debt ratings of investment-grade regulated utilities to two notches from one previously. Moody’s noted the wider notching is based on its analysis of the history of regulated utility defaults, which indicates that regulated utilities have defaulted at a lower rate and experienced lower loss given default rates than nonfinancial, nonutility corporate issuers.

On August 13, 2009, Moody’s upgraded the ratings of CIPS, CILCORP, CILCO and IP. Issuer/corporate credit ratings at CIPS, CILCO and IP were upgraded from Ba1 to Baa3. CILCORP’s senior unsecured debt rating was upgraded from Ba2 to Ba1, and the corporate family rating, probability of default rating, and all loss given default ratings of CILCORP were withdrawn as a result of CILCORP’s return to investment grade rating. Moody’s also upgraded the senior secured debt ratings at CIPS, CILCO and IP from Baa2 to Baa1. Moody’s cited the execution of new bank credit facilities and an improved political and regulatory environment in Illinois as the basis for the return to investment grade status of the issuer/corporate ratings. Moody’s also affirmed the ratings of Ameren, UE and Genco and assigned a stable outlook for Ameren and all of its rated subsidiaries.

S&P Ratings Actions

On February 25, 2009,2010, S&P assigned improved business risk profiles to CIPS, CILCO, and IP. S&P changed the profiles of CIPS and IP from “strong” to “excellent” and the profile of CILCO from “satisfactory” to “strong”.

On April 30, 2010, S&P stated that it viewed the reduction in Ameren’s common stock dividend as credit supportive. S&P did not make any changes in Ameren’s or its subsidiaries’ credit ratings or outlooks as a result of this action. S&P raised the business profile of UE to “excellent” from “strong” to reflect the January 2009 electric rate order issued by the MoPSC, whichICC on April 29, 2010, to increase the Ameren Illinois Utilities’ base rates by $5 million in the aggregate was not conducive to credit quality. However, S&P viewed as constructive.also commented that any immediate rating or outlook revision in reaction to the order would be premature. S&P loweredindicated that it will continue to evaluate the business profilesignificance of CILCOthe order and monitor the Ameren Illinois Utilities’ ability to “satisfactory” from “strong” reflecting S&P’s concerns regarding large capital expenditures needed to meet environmental compliance standards, while relying on falling market prices, due to the economic recession, for recovery.manage their regulatory risk.

Fitch Ratings Actions

On February 17, 2009,January 22, 2010, Fitch statedannounced new guidelines that the reduction in Ameren’s common stock dividend and other cost-cutting measures will be favorable to bondholders and credit quality. Fitch did not make any changes in Ameren’s oraffect its subsidiaries’ ratings or outlooks as a result of this action.

On March 9, 2009, Fitch lowered the credit ratings of UE by one notch as follows: issuer rating to BBB+, senior secured debt to A, subordinated debt to BBB+,deferrable coupon hybrid securities and preferred stock to BBB+.for utility issuers. Under these new guidelines, Fitch will rate these securities two notches below the issuer’s senior unsecured debt ratings. Under prior guidelines, these securities were rated one notch below the issuer’s senior unsecured debt ratings. The rating outlook was changed to stable. Fitch stated that these downgradesratings for UE, CIPS, CILCO and IP’s preferred stock, and for UE’s 7.69% subordinated deferrable interest debentures, were because of deteriorating financial measures over the past several years and the expectation that they will not improve materially without further rate support. They noted the financial deterioration is primarily due to increasing fuel and operating costs and a large capital expenditure program.

On July 31, 2009, Fitch affirmed the credit rating of Genco and changed its rating outlook to negative from stable. Additionally, Fitch affirmed the credit ratings of Ameren with a stable outlook. According to Fitch, the change in the credit rating outlook of Genco was based on the unfavorable outlook for wholesale energy prices and the sensitivity of the company’s largely coal-fired generating fleet to greenhouse gas and other environmental regulations. According to Fitch, the affirmation of Ameren’s credit ratings and stable outlook reflects the significant earnings and cash flow contribution derived from regulated utilities, the beneficial impact of recent rate increases in Illinois and Missouri, the savings generatedaffected by the February 2009 dividend reduction, and recent steps taken to maintain liquidity, including the renewal of bank credit facilities.this industry-wide methodology change.

Collateral Postings

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and natural gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, at September 30, 2009,March 31, 2010, were $49$136 million, $12$14 million, $8$13 million, $3 million, $3$23 million, and $17$57 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively. The amount of collateral external counterparties posted with Ameren was $14$19 million at September 30, 2009.March 31, 2010. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3” from S&P or Moody’s, respectively) at September 30, 2009,March 31, 2010, could have resulted inrequired Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $413$257 million, $157$89 million, $26$23 million, $53$29 million, $63 million, $63$43 million, and $45$42 million, respectively.

In addition, changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than September 30, 2009,March 31, 2010, levels in the next twelve months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $169$54 million, $88$25 million, $- million, $- million, $17 million, $17$2 million, and $- million, respectively. If market prices were 15% lower than September 30, 2009,March 31, 2010, levels in the next twelve months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $351$274 million, $201$129 million, $12$15 million, $- million, $82 million, $82$49 million, and $41$40 million, respectively.

The cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

OUTLOOK

Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2009for the remainder of 2010 and beyond.

Economy and Capital and Credit Markets

In 2008 and 2009, global capital and credit markets experienced extreme volatility, which continued into 2009.volatility. While these markets have improved, during 2009, the availability and cost of capital and economic activity continue to be significantly impacted. Wewe believe that these events have several continuing implications for our industry as a whole, including Ameren. They include the following:

 

 

Access to Capital Markets and Cost of Capital - The extreme disruption in the capital markets in 2008 and 2009 limited the ability of many companies, including the Ameren Companies, to freely access the capital and credit markets to support their operations and to refinance debt. Ameren and Ameren’s regulated utilities haveits subsidiaries continued to have access to the capital markets as evidenced by Ameren’s, CILCO’s, IP’s, and UE’s saleduring the period. The cost of debt securities in late 2008 and 2009, as well as Ameren’s common stock offering in September 2009. Thisthis access has beenwas at commercially acceptable but higher interest rates in the case of the issuance of certain debt securities. Ameren’ssecurities in 2008 and 2009. During 2010, we have observed improved access to capital in the U.S. capital and credit markets and lower interest rates on new issuances of investment grade debt securities compared with 2008 and 2009. A future disruption in the capital markets for its Merchant Generation subsidiaries may be more difficultcould limit our ability to access the capital markets, which access our business depends on, and costly. Ameren currently plans to issue up to approximately $500 million of debt at its Merchant Generation subsidiaries by the end of 2010.result in increased financing costs.

 

 

Credit Facilities - On June 30, 2009, Ameren and certain of its subsidiaries successfully reached definitive multiyear credit facility agreements. These facilities cumulatively provide $2.1 billion of credit through July 14, 2010, thereafter reducing to $1.8795 billion through June 30, 2011, and thereafter reducing to $1.0795 billion through July 14, 2011. The costs of these credit facilities are significantly

higher than the costs of the facilities they replaced. The costs to enter into the multiyear credit facility agreements were $40 million in the aggregate (UE - $11 million, CIPS - $3 million, Genco - $4 million, CILCORP - $14$5 million, CILCO - $7 million, and IP - $7 million). The costs will be amortized over the term of the facilities. In addition, borrowing rates under the facilities increased meaningfully,significantly, including, in the case of Ameren, from LIBOR plus 0.5%, under the prior credit facilities, to LIBOR plus 2.75%.

 

 

Economic Conditions - The current weakWeak economic conditions have resulted in weakerreduced power and commodity markets, weaker customer sales growth or sales contraction,prices, particularly with respect to industrial sales, and higher financing costs, and the impairment of goodwill at CILCORP, among other things. Weak economic conditions also expose the Ameren Companies to greater risk of default by counterparties, potentially higher bad debt expenses, and the risk of possible impairment of goodwill and long-lived assets, among other things. Due to a significant decline in Ameren’s market capitalization,Based on the decline in market prices for electricity, and a decrease in observable industry market multiples, CILCORP’s Illinois Regulated and CILCORP’s Merchant Generation reporting units recorded a non-cashresults of the annual goodwill impairment chargetest completed as of $462 million, in the aggregate, in the first quarter of 2009. Ameren’s reporting units and IP’s reporting unit did not require an impairment of goodwill in the first quarter of 2009. However,October 31, 2009, the estimated fair valuesvalue of Ameren’s Illinois Regulated reporting unit, Ameren’s Merchant Generation reporting unit and IP’s Illinois Regulated reporting unit exceeded theirits carrying valuesvalue by a nominal amounts as of March 31, 2009. As a result, theamount. The failure in the future of this reporting unit, or any reporting unit, to achieve forecasted operating results and cash flows or a further decline of observable industry market multiples may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge. Ameren, CILCORP and IPAlthough we are unable to predict when the U.S. economy will continue to monitorfully recover from the actual and forecasted operating results, cash flows, market capitalization, market prices for electricity and observable industry market multiples of their reporting units for signs of possible declineseconomic downturn, economic conditions in estimated fair value and potential goodwill impairment. No triggering events were identifiedour service territory have improved in the third quarter of 2009, and therefore, no interim impairment test was performed.2010 resulting in higher weather-normalized end-use retail sales volume at Ameren’s rate-regulated utilities. We are unable to predict the ultimate impact of the weak economy on our results of operations, financial position, or liquidity.

 

Investment Returns - The disruption in the capital markets, coupled with weak global economic conditions, has adversely affected financial markets. As a result, we experienced lower than assumedlower-than-expected investment returns in 2008 in our pension and postretirement benefit plans. These lowerDuring 2009, the actual return on investment of the pension plan assets was equal to the expected investment return while the actual return on investment of postretirement benefit assets exceeded the expected return. Lower returns will increase our future pension and postretirement expenses and pension funding levels. Our future expenses and funding levels will also be affected by future investment returns and future discount rate levels. Based on Ameren’s assumptions at December 31, 2008, estimated investment performance through September 30, 2009, and reflecting Ameren’s pension funding policy, Ameren expects to make annual contributions of $100 million to $250 million in each of the next five years. During 2009, the actual return on investment of the pension plan assets was lower than the expected investment return while the actual return on investment of postretirement benefit assets exceeded the expected return.

 

 

Operating and Capital Expenditures - The Ameren Companies will continue to make significant levels of investments and incur expenditures for their electric and natural gas utility infrastructure in order to improve overall system reliability, comply with environmental regulations, and improve plant performance. However, dueduring both 2008 and 2009, in response to the significant level of disruption and uncertainties in the capital and credit markets and weak economic conditions that reduced power prices and to help our customers with their future energy costs, we have identified approximately $2 billion of opportunities to reduce Ameren consolidatedsignificantly reduced our planned capital expenditures for 2010 through 2013, as compared to earlier plans.2014. In ouraddition, during the first quarter of 2010, Ameren’s Merchant Generation business, we have eliminated approximately $1 billion ofsegment reduced its estimated planned capital expenditures from our previous estimatesby an additional $435 million for this period. In our rate-regulated businesses, we have identified and are evaluating projects that may be eliminated or deferred2010 through 2014 compared to help our customers manage their energy costs and further strengthen our financial profile. We arethose disclosed in the Form 10-K. Ameren also reviewing plannedtook steps to control operations and maintenance expenditures across our organization, but especially in the Merchant Generation business and business support functions. We areexpenditures. Ameren is managing power plant outages and labor costs, among other things. We expect that actions being takenIn addition to address coststhe operations and maintenance expenditure reductions announced in the prior year, in May 2010, Ameren’s Merchant Generation segment will result in 2010 nonfuel operations and maintenance expenses that are 5% to 10% lower than 2008 levels. Our rate-regulated businesses are also evaluating opportunitiesannounced the reduction of 75 full-time positions effective during the second quarter of 2010. The reduction of these positions, coupled with other planned spending reductions, is expected to reduce 2010 nonfuelother operations and maintenance expenses to a level thatapproximately $300 million in 2010. This is currently expected to be consistent with their 2008 levels of nonfuelapproximately 10% lower than other operations and maintenance expenses.expenses in 2009. Any expenditure control initiatives will be balanced against a continued long-term commitment to invest in our electric and natural gas infrastructure to provide safe, reliable electric and natural gas delivery services to our customers; to meet federal and state environmental, reliability, and other regulations; and the need to maintain a solid overall liquidity and credit ratings profile to meet our operating, capital, and financing needs under challenging capital and credit market conditions.needs.

 

 

Liquidity - At September 30, 2009,March 31, 2010, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $2.2$1.8 billion, which was approximately $1$0.1 billion highermore than the same time last year.available liquidity at March 31, 2009.

Dividend - In February 2009, Ameren’s board of directors reduced Ameren’s common stock dividend. At the time of the board of directors’ decision, this dividend reduction was consistent with an annual dividend level that would allow Ameren to retain approximately $215 million of cash annually, which would provide incremental funds to enhance reliability to meet our customers’ expectations; satisfy federal and state environmental requirements; reduce our reliance on dilutive equity and high cost debt financings; and enhance our access to the capital and credit markets.

We believe that our liquidity is adequate given our expected operating cash flows, capital expenditures, and related financing plans (including accessing our existing credit facilities) will provide the necessary liquidity to meet our operating, investing, and financing needs for at least the next year.. However, there can be no assurance that significant changes in economic conditions, further disruptions in the capital and credit markets, or other unforeseen events will not materially impactaffect our ability to execute our expected operating, capital or financing plans.

Current Capital Expenditure Plans

 

Between 20092010 and 2018,2017, Ameren expects that certain Ameren Companies will be required to invest between $4.0 billion and $5.0up to $1.45 billion, in the aggregate, to retrofit theirits coal-fired power plants with pollution control equipment in compliance with emissions-related environmental laws and regulations. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50% of this investment is expected to be in our Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers. The recoverability of amounts expended in Merchant Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for coal-fired generators.

Approximately 30% of this investment is expected to be in our Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers, subject to prudency reviews. Regulatory lag may materially impact the timing of such recovery and, therefore, our cash flows and related financing needs. The recoverability of amounts expended in Merchant Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for coal-fired generators.

 

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gasesemissions would result in significant increases in capital expenditures and operating costs. Excessive costs to comply with future legislation or regulations might force Ameren and other similarly situated electric power generators to close some coal-fired facilities. Investments to control carbon emissions at Ameren’s coal-fired power plants to comply with future legislation or regulations would significantly increase future capital expenditures and operations and maintenance expenses.expenses, which if excessive could result in the closures of coal-fired power plants, impairment of assets, or otherwise materially adversely affect Ameren’s results of operations, financial position, and liquidity.

 

UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. UE’s integrated resource plan filed with the MoPSC in February 2008 included the expectation that new baseload generation capacity would be required in the 2018 to 2020 timeframe.time frame. Due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE continues to study future plant alternatives, including energy efficiency programs that could help defer new plant construction. In its pending electric rate case filed in July 2009, UE announced severalintroduced multiple energy efficiency programs.programs in 2009. The goal of these recently announced and future UE energy efficiency programs is to reduce electric usage by 540 megawatts by 2025, which is the equivalent of a medium-sizedmedium-size coal-fired power plant.

In July 2008, UE filed an application with the NRC for a combined construction and operating license for a potential new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri nuclear plant site. UE also signed contracts for COLA services. In June 2009, UE requested the NRC suspend the review of the COLA and all activities related to the COLA.

UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE is due towill file with the MoPSC in 2011.

 

In July 2008, UE filed an application with the NRC for a combined construction and operating license for a new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. In June 2009, UE requested the NRC suspend review of the COLA and all activities related to the COLA. As of September 30, 2009,March 31, 2010, UE had capitalized approximately $68$67 million as construction work in progress related to the COLA. The incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned with respect to the future construction of a new nuclear unit or management concludes it is probable the costs incurred will be disallowed in rates, it is possible that a charge to earnings could be recognized in a future period.

UE intends to submit a license extension application with the NRC to extend its existing Callaway nuclear plant’s operating license by 20 years so that the operating license will expire in 2044. UE cannot predict whether or when the NRC will approve the license extension.

 

Over the next few years, we expect to make significant investments in our electric and natural gas infrastructure and to incur increased operations and maintenance expenses to improve overall system reliability. We are projecting higher laborcommitted to synchronizing our operations and material costs for thesemaintenance spending and capital expenditures.investments within our rate-regulated businesses with the revenue and related cash flow levels provided by our regulators. We expect these costs or investments at our rate-regulated businesses to be ultimately recovered in rates, subject to prudency reviews by regulators, although rate case outcomes and regulatory lag could materially impact the timing of such recovery and, therefore, our cash flows, and related financing needs.needs and the timing in which we are able to proceed with these projects. We are projecting higher labor and material costs for these capital expenditures.

Ameren is evaluating opportunities to expand its transmission assets. New transmission projects have the potential to reduce congestion, improve reliability, and facilitate movement of renewable energy, typically generated in remote areas, to population centers where demand is at its highest.

 

Increased investments for environmental compliance, reliability improvement, and new baseload capacity will result in higher depreciation and financing costs.

Revenues

 

The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. Rising costs, including labor, material, depreciation and financing costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, are expected. Ameren, UE, CIPS, CILCO and IP anticipate regulatory lag until their requests to increase rates to continue to recover such costs on a timely basis are granted by state regulators. Ameren, UE, CIPS, CILCO and IP expect more frequentto file rate cases will be necessary in the future.frequently. UE has agreed notcurrently expects to file a natural gas deliveryand electric rate case before March 15,cases in 2010.

 

In current and future rate cases, UE, CIPS, CILCO and IP will continue to seek cost recovery and tracking mechanisms from their state regulators to reduce the effects of regulatory lag.

 

In July 2009, a new law became effective in Illinois that allows electric and natural gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their rates. The legislation provides utilities the ability to adjust their rates annually through a rate adjustment mechanism that applies to 2008 and subsequent years. During 2008, the Ameren Illinois Utilities incurred approximately $25 million more of bad debt expense (CIPS - $5 million, CILCO - $4 million, and IP - $16 million) than it recovered through rates. In August 2009, the Ameren Illinois Utilities filed withOn April 29, 2010, the ICC electric and natural gas rate adjustment clause tariffs to recover bad debt expense not recoveredissued a consolidated order approving a net increase in 2008 and to make corresponding rate adjustments beginning in 2010. The ICC has until February 2010 to approve, or approve as modified, the filed tariffs. Upon ICC approval of the rate adjustment clause tariffs filed in August 2009, the Ameren Illinois Utilities will be required to make a one-time donation of $10 million (CIPS - $3 million, CILCO - $2 million, and IP - $5 million) for customer assistance programs. The amount of the required one-time donation and the impact of the recovery of 2008 bad debt expenses were reflected in earnings during the third quarter of 2009.

CIPS, CILCO, and IP filed requests with the ICC in June 2009 to increase their annual revenues for electric and natural gas delivery services. The currently pending requests, as amended, seek to increase annual revenues from electric delivery service by $136of $32 million in the aggregate (CIPS - $41 million, CILCO - $22 million, and IP - $73 million). The electric rate increase requests are based on an 11.3% to 11.7% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.4 billion, and a test year ended December 31, 2008, with certain known and

 

measurable adjustments through May 2010. The Ameren Illinois Utilities have requested a rider mechanism that would permit all distribution-related costs incurred to implement reliability recommendations submitted to the ICC by the Liberty Consulting Group to be reflected in electric rates outside of general rate proceedings. The Ameren Illinois Utilities estimate that they will incur distribution-related implementation costs of $15$17 million (CIPS - $5 million,increase, CILCO - $3$1 million increase, and IP - $7 million)$14 million increase) and a net decrease in 2010. CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service. The currently pending requests, as amended, seek to increase annual revenues for natural gas delivery service by $26of $27 million in the aggregate (CIPS - $7$3 million decrease, CILCO - $6$9 million decrease, and IP - $13 million). The natural gas rate increase requests are$15 million decrease), based on a 10.8%9.9% to 11.2%10.3% return on equity a capital structure composed of 44%with respect to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion,electric delivery service and a test year ended December 31, 2008,9.2% to 9.4% return on equity with certain known and measurable adjustments throughrespect to natural gas delivery service. These rate changes became effective on May 6, 2010. On May 6, 2010, the ICC amended the April 2010 rate order to correct a technical error in the calculation of cash working capital, which resulted in an additional increase in annual revenues totaling $10 million in the aggregate. The ICC staff recommended in their testimony filed in September 2009consolidated rate order, as amended, approves a net increase in annual revenues for electric delivery service for the Ameren Illinois Utilities of $49$35 million in the aggregate (CIPS - $16$18 million increase, CILCO - $6$2 million increase, and IP - $26 million)$15 million increase) and a net decrease in annual revenues for natural gas delivery service of $4$20 million in the aggregate (CIPS - $1$2 million increase,decrease, CILCO - $3$7 million decrease, and IP - $2$11 million decrease). The ICC proceedingsrate changes relating to the proposed electricerror correction will become effective May 12, 2010. In response to the ICC consolidated rate order and natural gas delivery serviceamended rate changesorder, the Ameren Illinois Utilities intend to take immediate action to address the financial pressures created on the respective companies. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report. The Ameren Illinois Utilities filed a motion to stay certain decisions in the ICC order on May 7, 2010, and will take place overseek a periodrehearing. The Ameren Illinois Utilities may subsequently appeal the ICC rate order. The Ameren Illinois Utilities cannot predict if their requests for an ICC stay of up to 11 months, andcertain decisions and/or rehearing are granted or, in the event the requests are denied by the ICC, in such proceedings are required by May 2010.whether court appeals will be filed and their ultimate outcome.

The ICC order confirmed the previously approved 80% allocation of fixed non-volumetric residential and commercial natural gas customer charges, and approved a higher percentage of recovery of fixed non-volumetric electric residential and commercial customer charges. The percentage of costs to be recovered through fixed non-volumetric electric residential and commercial customer and meter charges increased from 27% to 40%. This increase will impact quarterly results of operations and cash flows, but is not expected to have any impact on annual margins.

The ICC issued a consolidated order in September 2008 approving a net increase in annual revenues for electric delivery service. These rate changes were effective on October 1, 2008. The Ameren Illinois Utilities made a pledge to keep the overall residential electric bill increase resulting from these rate changes during the first year to less than 10% for each utility. As a result, IP did not recover approximately $10 million in revenue during the first year the electric delivery service rates were in effect. IP was able to recover the full amount of the ICC-approved rate increase beginning October 1, 2009. As a result, IP recognized a $2 million increase in electric margins during the first three months of 2010. IP expects to earn an additional $6 million during the remainder of 2010.

Ameren FERC jurisdictional electric transmission rates are updated on June 1 of each year. Based on preliminary transmission rate calculations that will become effective on June 1, 2010, the Ameren Illinois Utilities anticipate additional revenues of between $15 million and $18 million over the last seven months of 2010 compared to the same period in 2009. The increase is due, in part, to a significant increase in transmission assets placed into service during 2009, as well as higher equity levels as a result of Ameren’s capital contributions to CIPS, CILCO and IP in 2009.

 

UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service. The currently pending request, as amended, seeks to increase annual revenues from electric service by $402$287 million. Included in this increase request wasis approximately $227$118 million of anticipated increases in normalized net fuel costs in excess of the net fuel costs included in base rates previously authorized by the MoPSC in its January 2009 electric rate order which, absent initiationorder. The balance of this general rate proceeding, would have been eligiblethe increase request is based primarily on investments made to continue system wide reliability improvements for recovery through UE’s existing FAC.customers, increases in costs essential to generating and delivering electricity, and higher financing costs. The electric rate increase request, as amended, is based on an 11.5%a 10.8% return on equity, a capital structure composed of 47.4%51.3% equity, a rate base for UE of $6.0$6 billion, and a test year ended March 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of January 31, 2010. Following Ameren’s September 2009 common stock issuance, UE receivedThe MoPSC staff’s recommendation, as amended, is to increase UE’s annual revenues by $165 million based on a capital contribution from Amerenreturn on equity of $436 million9.35%. Included in September 2009. UE expects to true-up its capital structure in the electric rate case to reflect this capital contribution, among other things. UE’s filing included a request for interim rate relief, which would place into effectrecommendation was approximately $37$107 million of increases in normalized net fuel costs. UE, MoPSC staff, and other parties have agreed to several stipulations resolving various revenue requirement issues, which have been approved by the requested increase prior to completionMoPSC and will be implemented with the effective date of the fullfinal rate case. The amountorder. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this interim increase request reflected the increased revenue requirement associated with rate base additions made by UE between October 2008 and May 2009. The MoPSC has scheduled an evidentiary hearing in December 2009 to deliberate UE’s request for interim rate relief.report. The MoPSC proceeding relating to the proposed electric service rate changes (except for the request for interim rate relief as discussed above) will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by the end of June 2010.

 

As part of its filing, UE also requested that the MoPSC to approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker as well as the continued use of the FAC and the vegetation management and infrastructure inspection cost tracking mechanism that the MoPSC previously authorized in its January 2009 electric rate order. The environmental cost recovery mechanism, if approved, would allow UE to periodically adjust electric rates outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with

federal, state or local environmental laws, regulations or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews of the MoPSC. The storm restoration cost tracker would permit UE a more timely recovery of storm restoration operations and maintenance expenditures.

The MoPSC issued an electric rate order in January 2009 approving an increase in annual electric revenues of approximately $162 million. New rates were effective March 1, 2009. In addition, pursuant to the accounting order issued by the MoPSC in April 2008, the rate order concluded that the $25 million of operations and maintenance expenses incurred as a result of a severe ice storm in January 2007 should be amortized and recovered over a five-year period starting March 1, 2009. The MoPSC also allowed recovery of $12 million of costs associated with a March 2007 FERC order that resettled costs among MISO market participants. UE recorded a regulatory asset for these costs at December 31, 2008, which will be amortized and recovered over a two-year period beginning March 1, 2009.

 

In the MoPSCits electric rate order issued in January 2009, the MoPSC approved UE’s implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism. The FAC allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, abovegreater or belowless than the amount set in base rates, subject to MoPSC prudency review.reviews. The vegetation management and infrastructure inspection cost tracking mechanism provides for the tracking of expenditures that are greater or less than amounts

provided for in UE’s annual revenues for electric service in a particular year, subject to a 10% limitation on increases in any one year. The tracked amounts may be reflected in rates set in future rate cases.

Even though Taum Sauk was not available to generate electricity for off-system revenues during 2009, UE included $19 million in the calculation of the FAC as if Taum Sauk had generated off-system revenues. Therefore, UE’s customers received the benefit of Taum Sauk’s historical off-system revenues even though the plant was not operational. Upon Taum Sauk’s return to service, which occurred in April 2010, UE’s earnings and cash flows from operations will increase since the adjustment factor will be eliminated from the FAC calculation. Taum Sauk is expected to increase UE’s 2010 margins by $16 million.

 

UE provides power to Noranda’s smelter plant in New Madrid, Missouri, which has historically used approximately four million megawatthours of power annually, making Noranda UE’s single largest customer. As a result of a major wintersevere ice storm in January 2009, Noranda’s smelter plant experienced a power outage related to non-UE lines deliveringthat deliver power to the substation serving the plant. Electric sales to Noranda statedhave gradually increased since the storm and, in its Annual Report on Form 10-K forMarch 2010, the year ended December 31, 2008, that the outage affected approximately 75% of the smelter plant’s capacity. In a September 30, 2009, press release, Noranda stated that its smelter plant had initiated steps to return operationswas restored to full capacity. These steps include restarting the third ofAs a result, UE expects its three production lines. Ameren expects it will take some time for the third production line to be repaired and returned to full capacity. To the extent UE’s sales to Noranda are reduced, UE’s margins may be reduced. UE estimates its electric margin from sales to Noranda was $11will increase by approximately $40 million and $30 million lower during the third quarter and first nine months, respectively, of 2009,in 2010 compared with the same periods in 2008, as a result of the outage.2009. The parties to UE’s July 2009pending electric rate case filing with the MoPSC seeks approvalhave agreed to revise the tariff under which it serves Noranda toa mechanism that will prospectively address the significant lost revenues UE cancould incur due to any future operational issues at Noranda’s smelter plant in southeastern Missouri, likesoutheast Missouri. The agreement will permit UE, when a significant loss of service occurs at the revenue losses resultingNoranda plant, to sell the power not taken by Noranda and use the proceeds of those sales to offset the revenues lost from Noranda. UE will be allowed to keep the January 2009 storm-related power outage. The tariff change thatamount of revenues necessary to compensate UE is proposingfor significant Noranda usage reductions but any excess revenues above the level necessary to compensate UE would permit itbe refunded to collect from Norandaretail customers through the revenue authorizedFAC. This stipulation was approved by the MoPSC in this rate case regardlessand will be implemented with the effective date of the level at which the Noranda plant is operating at prospectively. If the plant is operating at levels less than the levels assumed in rates, Noranda would receive a credit reflecting any revenues received by UE from energy sales resulting from the decrease in actual energy sales to Noranda. The result would be that UE is able to recover its costs without impacting other customers regardless of Noranda’s actual energy use.final order.

The Illinois electric settlement agreement reached in 2007 provided approximately $1 billion over a four-year period that began in 2007 to fund rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Funding for the settlement is coming from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco, and AERG agreed to fund an aggregate of $150 million, of which the following estimated contributions remained to be made at September 30, 2009:

          Ameren              CIPS        

CILCO

(Illinois

      Regulated)      

        IP              Genco        

CILCO

      (AERG)      

 

2009

  $7.6   $1.1   $0.5   $1.6   $3.0   $1.4  

2010

   2.4    0.3    0.2    0.5    1.0    0.4  

Total

  $10.0   $1.4   $0.7   $2.1   $4.0   $1.8  

 

As part of the 2007 Illinois electric settlement agreement,Electric Settlement Agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at then-relevant market prices. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy. Under the terms of the 2007 Illinois electric settlement agreement,Electric Settlement Agreement, these financial contracts are deemed prudent, and the Ameren Illinois Utilities are permitted full recovery of their costs in rates.

 

Volatile power prices in the Midwest can affect the amount of revenues Ameren, Genco and CILCO (through AERG) and EEI generate by marketing power into the wholesale and spot markets and can influence the cost of power purchased in the spot markets. Spot power prices in the MISO were lower during the third quarter and during the first nine months ofin 2009 compared with the same periodsthan in 2008 and willcontinued to decline in the first quarter of 2010. Spot market prices can be significantly impactedaffected by any prospect of global economic recovery, among other things.

With few scheduled maintenances outages in 2010 through 2012, the Merchant Generation segment expects to have available generation from its coal-fired plants of 35 million megawatthours in each year. However, the Merchant Generation segment’s actual generation levels will be significantly impacted by market prices for power in those years, among other things.

 

The availability and performance of Genco’s, AERG’s and EEI’s electric generation fleet can materially impactaffect their revenues. The Merchant Generation segment expects to generate 2729 million megawatthours of power from its coal-fired plants in 20092010 (Genco - 1314 million, AERG - 7 million, EEI - 78 million) based on expected power prices in 2009.prices. Should power prices rise more than expected, in the remainder of 2009 or in future years, the Merchant Generation segment has the capacity and availability to sell more generation.

With few scheduled outages in 2010 and 2011, the Merchant Generation segment expects to have available generation of 35 million megawatthours in each year. However, the Merchant Generation segment’s actual generation levels in 2010 and 2011 will be significantly impacted by market prices for power in those years, among other things.

 

The marketing strategy for the Merchant Generation segment is to optimize generation output in a low risk manner to minimize volatility of earnings and cash flow, while seeking to capitalize on its low-cost generation fleet to provide solid, sustainable returns. To accomplish this strategy, the Merchant Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Merchant Generation’s expected output by 80% to 90% for the following year, 50% to 70% for two years out, and 30% to 50% for three years out. As of September 30, 2009,March 31, 2010, Marketing Company had sold 100%hedged approximately 26 million megawatthours of Merchant Generation’s expected 20092010 generation, at an average price of $54$47 per megawatthour. For 2010,2011, Marketing Company had hedged approximately 2419 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $48 per megawatthour. For 2011,2012, Marketing Company had hedged approximately 1713 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $53 per megawatthour. Marketing Company has also entered into capacity-only sales contracts for 2010, 2011, and 2012, resulting in expected capacity-only revenues related to these contracts of $65 million, $45 million, and $15 million, respectively. Any unhedged sales will be exposed to relevant market prices at the time of the sale.

of $50 per megawatthour. Marketing Company has also entered into capacity-only sales contracts for 2010 and 2011 resulting in expected capacity-only revenues related to these contracts of $65 million and $45 million, respectively. Any unhedged sales will be exposed to relevant market prices at the time of the sale.

 

The development of ancillary services anda capacity marketsmarket in MISO could increase the electric margins of Genco AERG and EEI. Ancillary services are services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider’s system.AERG. A capacity requirement obligates a load serving entity to acquire capacity sufficient to meet its obligations.

MISO’s regional wholesale ancillary services market began in January 2009. MISO continues to refine its treatment of capacity supply and obligations, but development of a true capacity market could still be several years away.

acquire capacity sufficient to meet its obligations. MISO continues to refine its treatment of capacity supply and obligations, but development of a true capacity market could still be several years away.

 

Current and future energy efficiency programs developed by UE, CIPS, CILCO and IP and others could result in reduced demand for our electric generation and our electric and natural gas transmission and distribution services. Our regulated operations will seek a regulatory framework that allows either a return on these programs or recovery of their costs.

Fuel and Purchased Power

 

In 2008, 85%2009, 83% of Ameren’s electric generation (UE - 77%75%, Genco - 99%, AERG - 99%100%, EEI - 100%) was supplied by coal-fired power plants. About 96% of the coal used by these plants (UE - 97%96%, Genco - 98%99%, AERG - 77%89%, EEI - 100%) was delivered by rail from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have occasionally been restricted because of rail maintenance, weather, and derailments. As of September 30, 2009,March 31, 2010, coal inventories for UE, Genco, AERG and EEIthe Ameren Companies were at targeted levels. However, Merchant Generation is targeting a reduction in its coal inventories below historical levels by the end of 2010 in order to increase liquidity. Disruptions in coal deliveries could cause UE, Genco AERG and EEIAERG to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, andor purchasing power from other sources.

 

Genco is incurring incremental fuel costs in 2009 to replace coal from an Illinois mine that was prematurely closed by its owner at the end of 2007. A settlement agreement reached with the coal mine owner in June 2008 fully reimbursed Genco, in the form of a lump-sum payment of $60 million, for increased costs for coal and transportation that it incurred in 2008 ($33 million) and expects to incur in 2009 ($27 million). The entire settlement was recorded in 2008 earnings, so Ameren’s and Genco’s earnings in 2009 will be lower than they otherwise would have been.

The annual NOx trading program under the federal Clean Air Interstate Rule was reinstated by the U.S. Court of Appeals for the District of Columbia in December 2008. At this time, Genco believes it has sufficient NOx allowances to meet 2009 obligations under the annual NOx trading program. AERG may not have sufficient NOx allowances to meet forecasted 2009 obligations under the annual NOx trading program. The costs of these allowances would depend on market prices at the time these allowances are purchased. AERG currently estimates that it could incur additional fuel expense in 2009 of $0.5 million to purchase additional NOx allowances to comply with the program.

Ameren’s fuel costs (including transportation) are expected to increase in 20092010 and beyond. As of September 30, 2009,March 31, 2010, the average cost of Merchant Generation’s baseload hedged fuel costs, which include coal, transportation, diesel fuel surcharges, and other charges, had increased from an average cost ofwas approximately $20.25 per megawatthour in 2009 to approximately $23.25$22.50 per megawatthour in 2010, and $25.50 per megawatthour in 2011.2011, and $26.50 per megawatthour in 2012. See Item 3 - 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 20092010 through 2013.2014.

Other Costs

 

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. UE settled with the FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. UE has property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance does not cover lost electric margins andor penalties paid to FERC. UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of rebuilding the facility. UE expects theplant. The rebuilt Taum Sauk plant to be out of service until the spring ofbecame fully operational in April 2010. The estimated cost to rebuild the upper reservoir iswas in the range of $490 million. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. In July 2009, three insurance carriers filed a petition against Ameren in the Circuit Court of St. Louis County, Missouri, seeking a declaratory judgment that the property insurance policy does not require these three insurers to indemnify Ameren for their share of the entire cost of construction associated with the facility rebuild design being utilized.used. The three insurers allege that they, along with the other policy participants, presented a rebuild design that was consistent with their insurance coverage obligations and that the insurance policies do not require these insurers to pay their share of the costs of construction associated with the design being used. These insurers have estimated a cost of approximately $214 million for their rebuild design compared to the estimated $490 million cost of the design approved by FERC and implemented by Ameren. Ameren has filed an answer and counterclaim in the Circuit Court of St. Louis County, Missouri, against these insurers. The counterclaim asserts that the three insurance carriers have breached their obligations under the property insurance policies issued to Ameren and UE. The insurers that are parties to the litigation represent approximately 40%, on a weighted averageweighted-average basis, of the property insurance policy coverage between the disputed amounts of $214 million and $490 million. On August 31, 2009, Ameren and the property insurance carriers that are not parties to the above litigation reached a settlement of any and all claims, liabilities, and obligations arising out of, or relating to, coverage under its property insurance policy, including those related to the rebuilding of the facility and the reimbursement of replacement power costs. All payments from the Settling Insurance Companies were received by UE by September 30, 2009. Until Ameren’s remaining insurance claims and the related litigation are resolved, among other things, we are unable to determine the total impact the breach maycould have on Ameren’s and UE’s results of operations, financial position, orand liquidity beyond those amounts already recognized. As a result of the settlement with the Settling Insurance Companies, Ameren and UE now expect to recover, through insurance, 80% to 90% of the total property insurance claim for the Taum Sauk incident. Beyond insurance, the recoverability of any Taum Sauk facility rebuild costs from customers is subject to the terms and conditions set forth in UE’s November 2007 State of Missouri settlement agreement. Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the expected spring 2010 in-service date of the rebuilt facility. As of March 31, 2010, UE had capitalized in property and plant qualifying Taum Sauk-related costs of $100 million that UE believes qualify for potential recovery in electric rates under the terms of the November 2007 State of Missouri Settlement. The inclusion of such costs in UE’s electric rates is subject to review and approval by the MoPSC in a future rate case. Any amounts not recovered through insurance, in electric rates, or otherwise, could result in charges to earnings, which could be material. See Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for further discussion of Taum Sauk matters.

- - Commitments and Contingencies under Part I, Item 1, of this report for further discussion of Taum Sauk matters.

UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage in the spring ofcommenced on April 17, 2010, and is expected to last 35 days. During a scheduled outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, versuscompared with non-outage years.

On February 20, 2009, the Illinois Supreme Court handed down its decision inExelon Corporation v. The Department of Revenue, which concluded that an electric utility in Illinois qualifies for the Illinois investment tax credit. In July 2009, the Illinois Supreme Court denied a petition for rehearing filed by the Illinois Department of Revenue and modified its decision to make it prospective only. In September 2009, the Illinois Supreme Court denied a petition for rehearing filed by Exelon. The Ameren Companies do not expect the decision to have a material impact on their results of operations, financial position or liquidity.

 

Over the next few years, we expect rising employee benefit costs, as well as higher insurance premiums as a result of insurance market conditions and loss experience, among other things.

In the spring of 2009, Genco discussed with several parties the possible sale of three smaller plants. Those discussions did not result in offers that Genco found acceptable. In the third quarter of 2009, Genco announced operational changes and staff reductions at each of those three generating facilities. The affected three plants were the primarily coal-fired Meredosia plant, the natural gas-fired combined cycle Grand Tower plant, and the coal-fired Hutsonville plant. Genco will retire two of the four units at its Meredosia plant. The retirement resulted in a $4 million pretax charge to earnings during the third quarter of 2009. The Grand Tower plant will be operated seasonally from May through September with a very limited staff to maintain the plant in the other months. As a result of the staff reductions at these three plants as well as the workforce staff reductions through the voluntary and involuntary separation programs discussed in Results of Operations, Genco plans to reduce its workforce by approximately 80 positions. See Note 1 - Summary of Significant Accounting Policies under Part 1, Item 1, of this report for additional information.

Other

 

A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio standard.requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio standardrequirement must be derived from solar energy. Compliance with the renewable energy portfolio standardrequirement can be achieved through the procurement of renewable energy or renewable energy credits. Rules implementing the renewable energy portfolio standardrequirement are expected to be issued by the MoPSC in 2009.2010. UE expects that any related costs or investments would ultimately be recovered in rates.

 

Recently, theThe U.S. Congress has consideredis considering legislation that would require additional government regulation of derivative and OTC transactions and that wouldcould expand collateral requirements. Legislation of this nature, if finalized and signed into law by the President, could reduce the effectiveness of hedging, increasing the volatility of earnings, and could require increased collateral postings.

 

Resources Company, as partIn 2010, President Obama signed into law a health care reform bill that makes several fundamental changes to the U.S. health care system. In March 2010, Ameren recorded a $13 million charge relating to the taxation of an internal reorganization, isthe Medicare Part D subsidy. The Ameren Companies are currently evaluating the transferlong-term effects of this reform and the health care benefits they currently offer their employees and retirees. Until that review is completed, Ameren is unable to estimate the effects of the new law on its 80% stock ownership interest in EEI to Genco, through a capital contribution, that could take place later this year or in 2010.results of operations, financial position and liquidity.

 

UEAmeren and Genco are evaluating alternative operational modes for the Ameren Illinois Utilities applied for three grantsMeredosia and Hutsonville plants.

In an attempt to improve access to capital, reduce financing costs, and enhance administrative efficiencies, among other things, in April 2010, CIPS, CILCO and IP entered into a merger agreement under DOE’s Smart Grid Investment Program, which is partCILCO and IP will be merged with and into CIPS. As a result of the American Recoverymerger, in addition to the rate-regulated businesses of CILCO and Reinvestment ActIP, CIPS will also acquire CILCO’s merchant electric generation business, AERG. As one of 2009. In October 2009,a series of transactions that have been or will be taken to consolidate Ameren’s merchant electric generation businesses, following the DOE notified UE andeffective time of the merger, CIPS will distribute all of its shares of AERG common stock to Ameren Illinois Utilities that they were not awarded a grant.with the subsequent contribution by Ameren of the AERG common stock to Resources Company. See Note 14 - Corporate Reorganization under Part I, Item 1, of this report for additional information.

The above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, or liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s 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 I, Item 1, of this report.

 

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.

Our risk management objective is to optimize our physical generating assets and 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.

Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Form 10-K. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risks.

Interest Rate Risk

We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in annual net income that would result if interest rates on variable-rate debt outstanding at March 31, 2010 were to increase by 1% on variable-rate debt outstanding at September 30, 2009::

 

  Interest Expense Net Income(a)   Interest Expense Net  Income(a) 

Ameren(b)

  $7   $(4  $9   $(6

UE

   2    (1   2    (1

CIPS

   (c  (c   (c  (c

Genco

   1    (1   1    (1

CILCORP

   6    (3

CILCO

   3    (2   2    (2

IP

   (c  (c   (c  (c

 

(a)Calculations are based on an effective tax rate of 38%.
(b)Includes intercompany eliminations.
(c)Less than $1 million

The estimated changes above do not consider the potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 6 - Derivative Financial Instruments under Part I, Item 1, of this report for information on the potential loss on counterparty exposure as of September 30, 2009.March 31, 2010.

Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivable 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 September 30, 2009,March 31, 2010, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. UE and the Ameren Illinois Utilities continue to monitor the impact of increasing rates and a weak economic environment on customer collections. UE and the Ameren Illinois Utilities make adjustments to their allowance for doubtful accounts as deemed necessary, to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company may have credit exposure associated with interchange or wholesale purchase and sale activity with nonaffiliated companies. At September 30, 2009,March 31, 2010, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties was $4$2 million, net of collateral (2008(2009 - $1 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures, or option contracts, and we monitor counterparty exposure associated with our leveraged lease. We estimate our credit exposure to MISO associated with the MISO Day Two Energy and Operating Reserves Market to be $13$35 million at September 30, 2009 (2008March 31, 2010 (2009 - $64$33 million).

The Ameren Illinois Utilities will be exposed to credit risk in the event of nonperformance by the parties contributing to the Illinois comprehensive rate relief and assistance programs under the Illinois electric settlement agreement. The agreement provided $488 million in rate relief over a four-year period that commenced in 2007. Under funding agreements among the parties contributing to the rate relief and assistance programs, the Ameren Illinois Utilities will bill the participating generators at the end of each month, for their proportionate share of that month’s rate relief and assistance, which is due in 30 days, or drawn from the funds provided by the generators’ escrow. See Note 2 - Rate and Regulatory Matters under Part I, Item 1 of this report for additional information.

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. To the extent the value of plan assets declines, the effect would be reflected in net income and OCI or regulatory assets, and in the amount of cash required to be contributed to the plans.

Commodity Price Risk

We are exposed to changes in market prices for electricity, emission allowances, fuel, and natural gas. UE’s, Genco’s AERG’s and EEI’sAERG’s risks of changes in prices for power sales are partially hedged through sales agreements. Genco AERG and EEIAERG also seek to sell power forward to wholesale, municipal, and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through structured risk management programs and policies, which include forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco AERG and EEIAERG is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

The following table presents how Ameren’s cumulative net income might decrease if power prices were to decrease by 1% on unhedged economic generation for the remainderremaining three quarters of 20092010 through 2012:2014:

 

  Net Income(a)   Net  Income(a) 

Ameren(b)

  $(15  $(24

UE

   (7   (7

Genco

   (4   (15

CILCO (AERG)

   (1   (4

EEI

   (4

 

(a)Calculations are based on an effective tax rate of 38%.
(b)Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities, which can generate additional returns through portfolio management and trading activities. All of this activity is performed within a controlled risk management process. We establish value at risk (VaR) and stop-loss limits that are intended to prevent any material negative financial impact.

We manage risks associated with changing prices of fuel for generation using techniques similar techniques asto those used to manage risks associated with changing market prices for electricity. Most UE, Genco AERG and EEIAERG fuel supply contracts are physical forward contracts. Genco AERG and EEIAERG do not have the ability to pass through higher fuel costs to their customers for electric operations. Prior to March 2009, UE did not have this ability either except through a general rate proceeding. As a part of the January 2009 MoPSC electric rate order, UE was granted permission to put a FAC in place, which became effective March 1, 2009. The FAC allows UE to recover directly from its electric customers 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review. Thus, UE remains exposed to 5% of changes in its fuel and purchased power costs, net of off-system revenues. UE, is seeking authorization from the MoPSC in its pending electric rate case to continue use of the FAC. See Note 2 - RateGenco and Regulatory Matters under Part I, Item 1 of this report for additional information. UE, Genco, AERG and EEI have entered into long-term contracts with various suppliers to purchase coal to manage their exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Price and volumetric risk mitigation is accomplished primarily through periodic bid procedures, whereby the amount of coal purchased is determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. UE, Genco AERG and EEIAERG generally purchase coal up to five years in advance, but we may purchase coal beyond five years to take advantage of favorable opportunitiesdeals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.

Transportation costs for coal and natural gas can represent a significant portion of fuel costs. UE, Genco AERG and EEIAERG typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and the gas-fired generation units of UE Genco, AERG and EEIGenco are regulated by FERC through approved tariffs governing the rates, terms, and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by the Ameren Companies include rights to extend the contracts prior to the termination of the primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.

The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs, and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own no generation, that are price-hedged over the remainder of 2009, 2010 and 2011 through 2013,2014, as of September 30, 2009.March 31, 2010. The projected required supply of these commodities could be significantly impactedaffected by changes in our assumptions for such matters as customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.

 

        2009             2010       2011 - 2013         2010             2011       2012 - 2014 

Ameren:

        

Coal

  100 97 30  100 71 15

Coal transportation

  100   100   61    100   93   39  

Nuclear fuel

  100   100   89    100   99   71  

Natural gas for generation

  100   26   -    68   15   -   

Natural gas for distribution(a)

  85   45   18    58   35   14  

Purchased power for Illinois Regulated(b)

  100   82   35    68   55   16  

UE:

        

Coal

  100 97 29  100 72 14

Coal transportation

  100   100   63    100   100   43  

Nuclear fuel

  100   100   89    100   99   71  

Natural gas for generation

  100   43   -    78   15   -   

Natural gas for distribution(a)

  86   47   25    56   36   19  

CIPS:

        

Natural gas for distribution(a)

  84 40 15  55 32 12

Purchased power(b)

  100   82   35    68   55   16  

Genco:

    

Coal

  100 97 32

Coal transportation

  100   100   46  

Natural gas for generation

  100   -   -  

CILCORP/CILCO:

    

Coal (AERG)

  100 96 34

Coal transportation (AERG)

  100   100   79  

Natural gas for distribution(a)

  85   47   18  

Purchased power(b)

  100   82   35  

IP:

    

Natural gas for distribution(a)

  86 46 17

Purchased power(b)

  100   82   35  

EEI:

    

Coal

  100 96 29

Coal transportation

  100   100   67  

          2010              2011        2012 - 2014 

Genco:

    

Coal

  100 69 15

Coal transportation

  100   79   27  

Natural gas for generation

  100   35   -   

CILCO:

    

Coal (AERG)

  100 70 18

Coal transportation (AERG)

  100   100   56  

Natural gas for distribution(a)

  52   37   15  

Purchased power(b)

  68   55   16  

IP:

    

Natural gas for distribution(a)

  62 34 12

Purchased power(b)

  68   55   16  

 

(a)Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2009 represents November 2009 through March 2010. The year 2010 represents November 2010 through March 2011. The year 2011 represents November 2011 through March 2012. This continues each successive year through March 2014.2015.
(b)Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. Larger customers are purchasing power from the competitive markets. See Note 2 - Rate and Regulatory Matters and Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for a discussion of the Illinois power procurement process and for additional information on the Ameren Illinois Utilities’ purchased power commitments.

The following table shows how our cumulative fuel expense might increase and how our cumulative 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 period 20092010 through 2013.2014.

 

  Coal Transportation   Coal Transportation 
  

Fuel

Expense

 

Net

Income(a)

 

Fuel

Expense

 

Net

Income(a)

   

Fuel

Expense

  

Net

Income(a)

 

Fuel

Expense

  

Net

Income(a)

 

Ameren(b)

  $14   $(9 $11   $(7  $19  $(12 $17  $(11

UE

   8    (5  5    (3   10   (7  7   (5

Genco

   3    (2  4    (3   7   (4  9   (5

CILCORP

   1    (1  1    (c

CILCO (AERG)

   1    (1  1    (c   2   (1  1   (1

EEI

   2    (1  1    (1

 

(a)Calculations are based on an effective tax rate of 38%.
(b)Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(c)Amount less than $1 million.

In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. Ameren utilizes a combination of swaps and purchased call options to price cap and price hedge this exposure. If diesel fuel costs were to increase or decrease by $0.25/gallon, Ameren’s fuel expense could increase or decrease by $14$8 million annually for 20092010 (UE - $8$3 million, Genco - $3$4 million, AERG - $1 million and EEI - $2 million). As of September 30, 2009,March 31, 2010, Ameren had a price cap for 100%approximately 94% of expected fuel surcharges in 2009.2010.

In the event of a significant change in coal prices, UE, Genco, AERG and EEIAERG would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources.

With regard to exposure for commodity price risk for nuclear fuel, UE has both fixed-priced and base-price-with- escalation agreements, or itagreements. It also uses inventories that provide some price hedge to fulfill its Callaway nuclear plant needs for uranium, conversion, enrichment, and fabrication services. There is no fuel reloading scheduled for 2009 or 2012. UE has price hedges for 92%84% of itsthe 2010 to 20132014 nuclear fuel requirements.

Nuclear fuel market prices remain subject to an unpredictable supply and demand environment. UE has continued to follow a strategy of managing inventory of nuclear fuel as an inherent price hedge. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have some market-price-related component. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway nuclear plant, at prices which cannot now be accurately predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have limited financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if they are available.

See Note 9 - Commitments and Contingencies under Part I, Item 1 of this report for further information regarding the long-term commitments for the procurement of coal, natural gas, and nuclear fuel.

Fair Value of Contracts

Most of our commodity contracts that meet the definition of derivatives qualify for treatment as NPNS. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel,coal, diesel, electricity, FTRs,uranium, and emission allowances. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the

three and nine months ended September 30, 2009.March 31, 2010. We use various methods to determine the fair value of our contracts. In accordance with authoritative guidance for fair value hierarchy levels, our sources used to determine the fair value of these

contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years. See Note 7 - Fair Value Measurements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.

 

    Ameren(a)  UE  CIPS  Genco  

CILCORP/

CILCO

  IP 
Three Months Ended September 30, 2009                   

Fair value of contracts at beginning of period, net

  $70   $19   $(153 $(1 $(89 $(236

Contracts realized or otherwise settled during the period

   40    8    12    -    14    24  

Changes in fair values attributable to changes in valuation technique and assumptions

   -    -    -    -    -    -  

Fair value of new contracts entered into during the period

   (6  (4  (1  -    2    1  

Other changes in fair value

   (36  (6  (19  -    (14  (40

Fair value of contracts outstanding at end of period, net

  $68   $17   $(161 $(1 $(87 $(251

  Ameren(a) UE CIPS Genco 

CILCORP/

CILCO

 IP 
Nine Months Ended September 30, 2009              
Three Months Ended March 31, 2010  Ameren(a) UE CIPS Genco CILCO IP 

Fair value of contracts at beginning of period, net

  $20   $16   $(84 $(1 $(59 $(134  $17   $    16   $    (155 $21   $(75 $    (247

Contracts realized or otherwise settled during the period

   52    (9  42    1    48    81     3    1    12    (1  6    21  

Changes in fair values attributable to changes in valuation technique and assumptions

   -    -    -    -    -    -     -     -     -     -     -     -   

Fair value of new contracts entered into during the period

   51    20    (3  -    2    (6   5    2    (2  2    (2  (3

Other changes in fair value

   (55  (10  (116  (1  (78  (192   (80  (5  (73  (3  (59  (123

Fair value of contracts outstanding at end of period, net

  $68   $17   $(161 $(1 $(87 $(251  $(55 $    14   $    (218 $19   $(130 $    (352

 

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

The following table presents maturities of derivative contracts as of September 30, 2009,March 31, 2010, 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

   

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

  $(11 $(2 $-   $-   $(13  $-    $(8 $(2 $-   $(10

Level 2(a)

   30    -    -    -    30     29    -     -     -    29  

Level 3(b)

   25    26    -    -    51     (50  (16  (8  -    (74

Total

  $44   $24   $-   $-   $68    $(21 $(24 $(10 $-   $(55

UE:

            

Level 1

  $(3 $(2 $-   $-   $(5  $(4 $(4 $(2 $-   $(10

Level 2(a)

   5    -    -    -    5     9    -     -     -    9  

Level 3(b)

   8    9    -    -    17     5    11    (1  -    15  

Total

  $10   $7   $-   $-   $17    $10   $7   $(3 $-   $14  

CIPS:

            

Level 1

  $(1 $-   $-   $-   $(1  $-    $(1 $-    $-   $(1

Level 2(a)

   -    -    -    -    -     -     -     -     -    -   

Level 3(b)

   (49  (99  (12  -    (160   (93  (123  (1  -    (217

Total

  $(50 $(99 $(12 $-   $(161  $(93 $(124 $(1 $-   $(218

Genco:

            

Level 1

  $-   $-   $-   $-   $-    $(1 $(1 $-    $-   $(2

Level 2(a)

   -    -    -    -    -     -     -     -     -    -   

Level 3(b)

   (1  -    -    -    (1   11    10    -     -    21  

Total

  $(1 $-   $-   $-   $(1  $10   $9   $-    $-   $19  

CILCORP/CILCO:

      

CILCO:

      

Level 1

  $-   $-   $-   $-   $-    $(1 $(1 $-    $-   $(2

Level 2(a)

   -    -    -    -    -     -     -     -     -    -   

Level 3(b)

   (30  (51  (6  -    (87   (55  (71  (2  -    (128

Total

  $(30 $(51 $(6 $-   $(87  $(56 $(72 $(2 $-   $(130

IP:

            

Level 1

  $-   $1   $-   $-   $1    $(3 $(2 $-    $-   $(5

Level 2(a)

   -    -    -    -    -     -     -     -     -    -   

Level 3(b)

   (82  (151  (19  -    (252   (144  (199  (4  -    (347

Total

  $(82 $(150 $(19 $-   $(251  $(147 $(201 $(4 $-   $(352

 

(a)Principally fixed price forfixed-price vs. floating OTCover-the-counter power swaps, power forwards, and fixed price forfixed-price vs. floating OTCover-the-counter natural gas swaps.
(b)

Principally coal and SO2 optionpower forward contract values based on a Black-Scholes model that includes information from external sources and our estimates. AlsoLevel 3 also includes interruptible power forward and option contract values based on our estimates.

ITEM 4 and ITEM 4T. CONTROLS AND PROCEDURES.

 

(a)Evaluation of Disclosure Controls and Procedures

As of September 30, 2009,March 31, 2010, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information

required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

 

(b)Change in Internal Controls

There has been no change in any of 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, each of their internal control over financial reporting.

PART II. OTHER INFORMATION

 

ITEM 1.LEGAL PROCEEDINGS.

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.

For additional information onMaterial legal and administrative proceedings seediscussed in Note 2 - Rate and Regulatory Matters, and Note 9 - Commitments and Contingencies under Part I, Item 1, of this report.report and incorporated herein by reference, include the following:

 

rate adjustment proceedings for UE pending before the MoPSC;

rehearing of the ICC electric and natural gas consolidated rate order issued in April 2010;

FERC proceedings, including a dispute between MISO and PJM regarding the calculation of certain charges;

UE’s Notice of Violation related to NSR and NSR investigations at Genco, AERG and EEI;

remediation matters associated with MGP and waste disposal sites of the Ameren Companies;

litigation associated with the breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility; and

asbestos-related litigation associated with UE, CIPS, Genco, CILCO and IP.

ITEM 1A.RISK FACTORS.

There have been no material changes to the risk factors disclosed in Part I, Item 1A. Risk Factors in the Form 10-K.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

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

July 1 - July 31, 2009

  -  $-  -  -

August 1 - August 31, 2009

  2,407   26.35  -  -

September 1 - September 30, 2009

  -   -  -  -

Total

  2,407  $26.35  -  -
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

January 1 - January 31, 2010

  23,278  27.71  -  -

February 1 - February 28, 2010

  19,365  24.71  -  -

March 1 - March 31, 2010

  -  -  -  -

Total

  42,643  26.35  -  -

 

(a)Included in AugustJanuary were 2,40723,128 shares of Ameren common stock purchased by Ameren in an open-market transactiontransactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards. The remaining shares of Ameren common stock were purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance units. Included in February were 19,365 shares of Ameren common stock purchased by Ameren from employee participants to satisfy participants’ tax obligations incurred by the release of restricted shares of Ameren common stock under Ameren’s Long-term Incentive Plan of 1998 and to satisfy Ameren’s obligation in February and March to distribute shares of common stock for vested performance share units held by employees whose employment terminated.units. Ameren does not have any publicly announced equity securities repurchase plans or programs.

None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the period from JulyJanuary 1, 20092010 to September 30, 2009.March 31, 2010.

ITEM 6.EXHIBITS.

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:

Material ContractsPlan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

10.1  2.1  

Ameren
Companies

CIPS

CILCO

IP

 *Ameren’s Deferred CompensationAgreement and Plan of Merger, dated as amendedof April 13, 2010, among CIPS, CILCO and restated effective JanuaryIPAnnex A to Part I, File No. 333-166095

Instruments Defining the Rights of Security Holders

  4.1

Ameren

CIPS

Second Supplemental Indenture to the CIPS Indenture, dated as of March 1, 2010  October 14, 2009 Form 8-K, Exhibit 10.1,4.17, File No. 1-14756
10.2Ameren
Companies
*First Amendment, dated October 12, 2009, to the Second Amended and Restated Ameren Change of Control Severance PlanOctober 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756333-166095

Statement re: Computation of Ratios

12.1  Ameren Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges   
12.2  UE UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements   
12.3  CIPS CIPS’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements   
12.4  Genco Genco’s Statement of Computation of Ratio of Earnings to Fixed Charges   
12.5  CILCORPCILCORP’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.6CILCO CILCO’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements   
12.712.6  IP IP’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements   

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  UE Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE   
31.4  UE Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE   
31.5  CIPS Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CIPS   
31.6  CIPS Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CIPS   
31.7  Genco Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco   
31.8  Genco Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco   
31.9  CILCORPCILCO Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORPCILCO   

Exhibit Designation  Registrant(s) Nature of Exhibit  Previously Filed as Exhibit to:
31.10  CILCORPRule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCORP
31.11CILCORule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO
31.12CILCO Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO   
31.1331.11  IP Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of IP   
31.1431.12  IP Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of IP   

Section 1350 Certifications

32.1  Ameren Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren   
32.2  UE Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of UE   
32.3  CIPS Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CIPS   
32.4  Genco Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco   
32.5  CILCORPCILCO 

Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCORP

32.6CILCOSection 1350 Certification of Principal

Executive Officer and Principal Financial Officer of CILCO

   
32.732.6  IP Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of IP   

XBRL - Related Documents

101.INS**  Ameren XBRL Instance Document   
101.SCH**  Ameren XBRL Taxonomy Extension Schema Document   
101.CAL**  Ameren XBRL Taxonomy Extension Calculation Linkbase Document   
101.LAB**  Ameren XBRL Taxonomy Extension Label Linkbase Document   
101.PRE**  Ameren XBRL Taxonomy Extension Presentation Linkbase Document   

 

*Management compensatory plan or arrangement.
**Attached as Exhibit 101 to this report is the following financial information from Ameren’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009,March 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statement of Income for the three and nine months ended September 30,March 31, 2010 and 2009, and 2008, (ii) the Consolidated Balance Sheet at September 30, 2009,March 31, 2010, and December 31, 2008,2009, (iii) the Consolidated Statement of Cash Flows for the ninethree months ended September 30,March 31, 2010 and 2009, and 2008, and (iv) the Combined Notes to the Financial Statements for the ninethree months ended September 30, 2009,March 31, 2010, tagged as blocks of text. These Exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.

SIGNATURES

Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

 

AMEREN CORPORATION
(Registrant)
/s/ Martin J. Lyons, Jr.
     Martin J. Lyons, Jr.
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
UNION ELECTRIC COMPANY
(Registrant)
/s/ Martin J. Lyons, Jr.
     Martin J. Lyons, Jr.
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(Registrant)
/s/ Martin J. Lyons, Jr.
     Martin J. Lyons, Jr.
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
AMEREN ENERGY GENERATING COMPANY
(Registrant)
/s/ Martin J. Lyons, Jr.
     Martin J. Lyons, Jr.
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)

CILCORP INC.
(Registrant)
/s/ Martin J. Lyons
     Martin J. Lyons
Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
CENTRAL ILLINOIS LIGHT COMPANY
(Registrant)
/s/ Martin J. Lyons, Jr.
     Martin J. Lyons, Jr.
Senior Vice President and Chief Financial Officer (Principal
(Principal Financial and Accounting Officer)
ILLINOIS POWER COMPANY
(Registrant)
/s/ Martin J. Lyons, Jr.
     Martin J. Lyons, Jr.
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)

Date: November 9, 2009May 10, 2010

 

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