Ameren (AEE) 10-Q 10 May 10 2010 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information
	3 Months Ended Mar. 31, 2010	Apr. 30, 2010
Document Type	10-Q
Amendment Flag	false
Document Period End Date	2010-03-31
Document Fiscal Year Focus	2,010
Document Fiscal Period Focus	Q1
Trading Symbol	AEE
Entity Registrant Name	AMEREN CORP
Entity Central Index Key	0001002910
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		238,286,367

CONSOLIDATED STATEMENT OF INCOM

CONSOLIDATED STATEMENT OF INCOME (USD $)
In Millions, except Per Share data	3 Months Ended Mar. 31, 2010	3 Months Ended Mar. 31, 2009
Operating Revenues:
Electric	$1,440	$1,395
Gas	476	521
Total operating revenues	1,916	1,916
Operating Expenses:
Fuel	293	274
Purchased power	271	233
Gas purchased for resale	333	383
Other operations and maintenance	416	421
Depreciation and amortization	187	174
Taxes other than income taxes	118	110
Total operating expenses	1,618	1,595
Operating Income	298	321
Other Income and Expenses:
Miscellaneous income	22	16
Miscellaneous expense	7	4
Total other income	15	12
Interest Charges	132	118
Income Before Income Taxes	181	215
Income Taxes	75	70
Net Income	106	145
Less: Net Income Attributable to Noncontrolling Interests	4	4
Net Income Attributable to Ameren Corporation	$102	$141
Earnings per Common Share - Basic and Diluted	0.43	0.66
Dividends per Common Share	0.385	0.385
Average Common Shares Outstanding	237.6	212.7

CONSOLIDATED BALANCE SHEET

CONSOLIDATED BALANCE SHEET (USD $)
In Millions	3 Months Ended Mar. 31, 2010	12 Months Ended Dec. 31, 2009
Current Assets:
Cash and cash equivalents	$360	$622
Accounts receivable - trade (less allowance for doubtful accounts of $32 and $24, respectively)	500	424
Unbilled revenue	253	367
Miscellaneous accounts and notes receivable	319	318
Materials and supplies	635	782
Mark-to-market derivative assets	233	121
Current regulatory assets	242	110
Other current assets	116	98
Total current assets	2,658	2,842
Property and Plant, Net	17,671	17,610
Investments and Other Assets:
Nuclear decommissioning trust fund	307	293
Goodwill	831	831
Intangible assets	124	129
Regulatory assets	1,427	1,430
Other assets	670	655
Total investments and other assets	3,359	3,338
TOTAL ASSETS	23,688	23,790
Current Liabilities:
Current maturities of long-term debt	204	204
Short-term debt		20
Accounts and wages payable	427	694
Taxes accrued	94	54
Interest accrued	165	110
Customer deposits	97	101
Mark-to-market derivative liabilities	254	109
Current regulatory liabilities	87	82
Current accumulated deferred income taxes, net	93	38
Other current liabilities	219	299
Total current liabilities	1,640	1,711
Credit Facility Borrowings	630	830
Long-term Debt, Net	7,113	7,113
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	2,604	2,554
Accumulated deferred investment tax credits	92	94
Regulatory liabilities	1,340	1,338
Asset retirement obligations	435	429
Pension and other postretirement benefits	1,181	1,165
Other deferred credits and liabilities	543	496
Total deferred credits and other liabilities	6,195	6,076
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Ameren Corporation Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized - shares outstanding of 238.2 and 237.4, respectively	2	2
Other paid-in capital, principally premium on common stock	5,437	5,412
Retained earnings	2,466	2,455
Accumulated other comprehensive loss	(4)	(16)
Total Ameren Corporation stockholders' equity	7,901	7,853
Noncontrolling Interests	209	207
Total equity	8,110	8,060
TOTAL LIABILITIES AND EQUITY	$23,688	$23,790

CONSOLIDATED BALANCE SHEET (Par

CONSOLIDATED BALANCE SHEET (Parenthetical) (USD $)
In Millions, except Per Share data	Mar. 31, 2010	Dec. 31, 2009
Accounts receivable - trade, allowance for doubtful accounts	$32	$24
Common stock, par value	0.01	0.01
Common stock, shares authorized	400	400
Common stock, shares outstanding	238.2	237.4

CONSOLIDATED STATEMENT OF CASH

CONSOLIDATED STATEMENT OF CASH FLOWS (USD $)
In Millions	3 Months Ended Mar. 31, 2010	3 Months Ended Mar. 31, 2009
Cash Flows From Operating Activities:
Net income	$106	$145
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market gain on derivatives	(31)	(51)
Depreciation and amortization	190	176
Amortization of nuclear fuel	13	12
Amortization of debt issuance costs and premium/discounts	9	4
Deferred income taxes and investment tax credits, net	70	32
Other	(9)	(1)
Changes in assets and liabilities:
Receivables	37	130
Materials and supplies	148	185
Accounts and wages payable	(177)	(245)
Taxes accrued	40	29
Assets, other	(32)	29
Liabilities, other	11	100
Pension and other postretirement benefits	30	36
Counterparty collateral, net	(23)	(41)
Taum Sauk costs, net of insurance recoveries	(1)	(24)
Net cash provided by operating activities	381	516
Cash Flows From Investing Activities:
Capital expenditures	(289)	(424)
Nuclear fuel expenditures	(23)	(3)
Purchases of securities - nuclear decommissioning trust fund	(60)	(203)
Sales of securities - nuclear decommissioning trust fund	56	200
Purchases of emission allowances		(2)
Other	(1)
Net cash used in investing activities	(317)	(432)
Cash Flows From Financing Activities:
Dividends on common stock	(91)	(82)
Capital issuance costs		(3)
Dividends paid to noncontrolling interest holders	(2)	(8)
Short-term and credit facility borrowings, net	(220)	(177)
Issuances:
Common stock	20	28
Long-term debt		349
Generator advances for construction received (refunded), net	(33)	21
Net cash provided by (used in) financing activities	(326)	128
Net change in cash and cash equivalents	(262)	212
Cash and cash equivalents at beginning of year	622	92
Cash and cash equivalents at end of period	$360	$304

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	3 Months Ended Mar. 31, 2010
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	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. Amerens primary assets are the common stock of its subsidiaries. Amerens 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 Amerens common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Amerens 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, 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. Ameren and Genco consolidate EEI for financial reporting purposes. Effective January1, 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. Amerens historical cost basis in EEI included purchase accounting adjustments relating to Amerens acquisition of an additional 20% ownership interest in EEI in 2004. This transfer required Gencos prior period financial statements to be retrospectively combined for all periods presented. Consequently, Gencos prior period consolidated financial statements reflect EEI as if it had been a subsidiary of Genco. The financial statem

RATE AND REGULATORY MATTERS

RATE AND REGULATORY MATTERS
	3 Months Ended Mar. 31, 2010
RATE AND REGULATORY MATTERS	NOTE 2 - RATE AND REGULATORY MATTERS Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict theultimate 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 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 $287 million. Included in this increase request is approximately $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. 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 a 10.8% return on equity, a capital structure composed of 51.3% equity, a rate base of $6 billion, and a test year ended March31, 2009, with certain pro-forma adjustments through the true-up date of January31, 2010. As part of its original filing, UE also requested that the MoPSC approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker. 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 staffs recommendation, as amended, is to increase UEs annual 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 effective date of the final rate order. Those stipulations include UEs 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 agreed to prospec

CREDIT FACILITY BORROWINGS AND

CREDIT FACILITY BORROWINGS AND LIQUIDITY
	3 Months Ended Mar. 31, 2010
CREDIT FACILITY BORROWINGS AND LIQUIDITY	NOTE 3 - CREDIT FACILITY BORROWINGS AND LIQUIDITY The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, or drawings under committed bank credit facilities. The following table summarizes the borrowing activity and relevant interest rates as of March31, 2010, under the 2009 Multiyear Credit Agreement, the 2009 Supplemental Credit Agreement, and the 2009 Illinois Credit Agreement (excluding letters of credit issued): 2009 Multiyear Credit Agreement ($1.15 billion) Ameren (Parent) UE Genco Total March31, 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 March31, 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 March31, 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 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 three months of 2010 were $905 million. Based on outstanding borrowings under the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement (including reductions for $15 million of letters of credit issued under the 2009 Multiyear Credit Agreement), the available amounts under the facilities at March31, 2010, were $655 million and $800 million, respectively. Indebtedness Provisions and Other Covenants The information below presents a summary of the Ameren Companies compliance with indebtedness provision

LONG-TERM DEBT AND EQUITY FINAN

LONG-TERM DEBT AND EQUITY FINANCINGS
	3 Months Ended Mar. 31, 2010
LONG-TERM DEBT AND EQUITY FINANCINGS	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 0.8million new shares of common stock valued at $20 million in the three months ended March31, 2010. In February 2010, CILCORP completed a covenant defeasance of its remaining outstanding 9.375% senior bonds due 2029 by depositing approximately $2.7 million in U.S. government obligations and cash with the indenture trustee. This deposit will be used 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 CILCO securing these bonds 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. UEs, CIPS, CILCOs and IPs 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 March31, 2010, at an assumed interest rate of 7% and dividend rate of 8%. RequiredInterest Coverage Ratio(a) ActualInterest CoverageRatio Bonds Issuable(b) RequiredDividend Coverage Ratio(c) ActualDividend Coverage Ratio PreferredStock Issuable UE 2.0 3.0 $ 1,424 2.5 45.7 $ 1,283 CIPS 2.0 4.6 356 1.5 2.1 140 CILCO 2.0(d) 7.2 214 2.5 139.6 50 (e) IP 2.0 3.9 1,213 1.5 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 $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 companys 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

OTHER INCOME AND EXPENSES

OTHER INCOME AND EXPENSES
	3 Months Ended Mar. 31, 2010
OTHER INCOME AND EXPENSES	NOTE 5 - OTHER INCOME AND EXPENSES The following table presents Other Income and Expenses for each of the Ameren Companies for the three months ended March31, 2010 and 2009: Three Months 2010 2009 Ameren:(a) Miscellaneous income: Allowance for equity funds used during construction $ 13 $ 6 Interest income on industrial development revenue bonds 7 7 Interest and dividend income 1 1 Other 1 2 Total miscellaneous income $ 22 $ 16 Miscellaneous expense: Donations $ 2 $ 3 Other 5 1 Total miscellaneous expense $ 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.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS
	3 Months Ended Mar. 31, 2010
DERIVATIVE FINANCIAL INSTRUMENTS	NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS We use derivatives principally to manage the risk of changes in market prices for natural gas, 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 coal, natural gas, and uranium 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 March31, 2010, and December31, 2009: Quantity (in millions) NPNS Contracts(a) Cash Flow Hedges(b) Other Derivatives(c) DerivativesthatQualifyfor RegulatoryDeferral(d) Commodity 2010 2009 2010 2009 2010 2009 2010 2009 Coal (in tons) Ameren(e) 74 115 (f ) (f ) (f ) (f ) (f ) (f ) UE 41 81 (f ) (f ) (f ) (f ) (f ) (f ) Genco 17 17 (f ) (f ) (f ) (f ) (f ) (f ) CILCO 7 8 (f ) (f ) (f ) (f ) (f ) (f ) Natural gas (in mmbtu) Ameren(e) 149 165 (f ) (f ) 55 28 174 136 UE 20 22 (f ) (f ) (g ) 5 25 21 CIPS 25 28 (f ) (f ) (f ) (f ) 29 22 Genco (f ) (f ) (f ) (f ) 5 7 (f ) (f ) CILCO 45 50 (f ) (f ) (f ) (f ) 46 36 IP 59 66 (f ) (f ) (f ) (f ) 74 57 Heating oil (in gallons) Ameren(e) (f ) (f ) (f ) (f ) 83 94 107 117 UE (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) 71 76 29 32 33 22 33 36 UE 3 4 (f ) (f ) (g ) (g ) 5 4 CIPS (f ) (f ) (f ) (f ) (f ) (f

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS
	3 Months Ended Mar. 31, 2010
FAIR VALUE MEASUREMENTS	NOTE 7 - FAIR VALUE MEASUREMENTS Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to 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. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels: Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including U.S. treasury securities and listed equity securities, such as those held in UEs 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 UEs 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. 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 developm

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS
	3 Months Ended Mar. 31, 2010
RELATED PARTY TRANSACTIONS	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 Amerens financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item8 of the Form 10-K. Electric Power Supply Agreements The following table presents the amount of physical gigawatthour sales under related party electric power supply agreements for the three months ended March31, 2010 and 2009: ThreeMonths 2010 2009 Genco sales to Marketing Company(a) 5,437 5,321 AERG sales to Marketing Company(a) 1,989 1,384 Marketing Company sales to CIPS(b) 190 446 Marketing Company sales to CILCO(b) 95 208 Marketing Company sales to IP(b) 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 Gencos and AERGs 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 2010, the Ameren Illinois Utilities used a RFP process, administered by the IPA, to contract capacity for the period from June1, 2010, through May31, 2013. Both Marketing Company and UE were winning suppliers in the Ameren Illinois Utilities capacity RFP process. In April 2010, Marketing Company contracted to supply capacity to the Ameren Illinois Utilities for $1 million, $2 million, and $3 million for the twelve months ending May31, 2011, 2012, and 2013, respectively. In April 2010, UE contracted to supply capacity to the Ameren Illinois Utilities for less than $1 million for the entire period from June1, 2010 through May31, 2013. Joint Ownership Agreement AITC and IP have a joint 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 is the primary beneficiary of AITC, and 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, colla

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES
	3 Months Ended Mar. 31, 2010
COMMITMENTS AND CONTINGENCIES	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, Item8 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 UEs Callaway nuclear plant at March31, 2010. The property coverage and the nuclear liability coverage must be renewed on October1 and January1, respectively, of each year. Type and Source of Coverage MaximumCoverages MaximumAssessmentsfor Single Incidents Public liability and nuclear worker liability: American Nuclear Insurers $ 375 $ - Pool participation 12,219 (a) 118 (b) $ 12,594 (c) $ 118 Property damage: Nuclear Electric Insurance Ltd. $ 2,750 (d) $ 23 Replacement power: Nuclear Electric Insurance Ltd $ 490 (e) $ 9 Energy Risk Assurance Company $ 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. (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 nucl

CALLAWAY NUCLEAR PLANT

CALLAWAY NUCLEAR PLANT
	3 Months Ended Mar. 31, 2010
CALLAWAY NUCLEAR PLANT	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, or 1/ 10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent 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. 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 DOEs motion to withdraw the application. The DOE has also announced the formation of a Blue Ribbon Commission on Americas Nuclear Future to evaluate alternatives for storage of spent nuclear fuel. The delayed availability of the DOEs 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 plants operating license from 2024 to 2044. If the Callaway nuclear plants 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 plants 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 plants 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 included in the costs of service used to establish electric rates for UEs customers. These costs amounted to $7 million in each of the years 2009, 2008, and 2007. Every t

OTHER COMPREHENSIVE INCOME

OTHER COMPREHENSIVE INCOME
	3 Months Ended Mar. 31, 2010
OTHER COMPREHENSIVE INCOME	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 months ended March31, 2010 and 2009, is shown below for Ameren, UE, and Genco. CIPS, CILCOs, and IPs comprehensive income was composed of only their respective net income for the three months ended March31, 2010 and 2009. ThreeMonths 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.

RETIREMENT BENEFITS

RETIREMENT BENEFITS
	3 Months Ended Mar. 31, 2010
RETIREMENT BENEFITS	NOTE 12 - RETIREMENT BENEFITS Amerens 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. Considering Amerens assumptions at December31, 2009, its estimated investment performance through March31, 2010, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $225 million in each of the next five 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. The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three months ended March31, 2010 and 2009: Pension Benefits(a) Postretirement Benefits(a) Three Months Three Months 2010 2009 2010 2009 Service cost $ 17 $ 17 $ 5 $ 5 Interest cost 47 47 16 17 Expected return on plan assets (53 ) (52 ) (14 ) (13 ) Amortization of: Transition obligation - - - - Prior service cost (benefit) 2 2 (2 ) (2 ) Actuarial loss 5 7 2 3 Net periodic benefit cost $ 18 $ 21 $ 7 $ 10 (a) Includes amounts for Ameren registrant and nonregistrant subsidiaries. UE, CIPS, Genco, 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 months ended March31, 2010 and 2009: Pension Costs Postretirement Costs Three Months Three Months 2010 2009 2010 2009 Ameren(a) $ 18 $ 21 $ 7 $ 10 UE 12 13 3 4 CIPS 2 3 - 1 Genco 3 2 1 1 CILCO 3 4 2 2 IP - 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

SEGMENT INFORMATION

SEGMENT INFORMATION
	3 Months Ended Mar. 31, 2010
SEGMENT INFORMATION	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 UEs business as described in Note 1- Summary of Significant Accounting 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- Summary of Significant Accounting Policies, and AITC. The Merchant Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company (until March4, 2010, when CILCORP merged with and into Ameren), AERG, and Marketing Company. The category called Other primarily includes Ameren parent company activities. CILCO has two reportable segments: Illinois Regulated and Merchant Generation. The Illinois Regulated segment for CILCO consists of the regulated electric and gas transmission and distribution businesses. The Merchant Generation segment for CILCO consists of the generation business of AERG. The following tables present information about the reported revenues and specified items included in net income of Ameren and CILCO for the three months ended March31, 2010 and 2009, and total assets as of March31, 2010, and December31, 2009. Ameren Three Months 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 $ 648 $ 928 $ 336 $ 4 $ - $ 1,916 Intersegment revenues 7 8 116 4 (135 ) - Net income attributable to Ameren Corporation(a) 21 25 93 2 - 141 As of March31, 2010: Total assets $ 12,073 $ 7,412 $ 4,947 $ 1,118 $ (1,862 ) $ 23,688 As of December31, 2009: Total assets $ 12,301 $ 7,344 $ 4,921 $ 1,657 $ (2,433 ) $ 23,790 (a) Represents net income (loss) available to common stockholders; 100% of CILCOs preferred stock dividends are included in the Illinois Regulated segment. CILCO 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 -

CORPORATE REORGANIZATION

CORPORATE REORGANIZATION
	3 Months Ended Mar. 31, 2010
CORPORATE REORGANIZATION	NOTE 14 - CORPORATE REORGANIZATION On March15, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company filed an application with FERC requesting certain FERC authorizations related to a two-step corporate reorganization. The first step of the reorganization would merge CILCO and IP with and into CIPS (the Merger), after which the surviving corporation would be renamed Ameren Illinois Company (Ameren Illinois). The second step of the reorganization would involve the distribution of AERG stock from Ameren Illinois to Ameren (the AERG distribution) and the subsequent contribution by Ameren of the AERG stock to Resources Company. On March15, 2010, CIPS, CILCO and IP filed with the ICC 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 CILCOs 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 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 senior secured notes of IP and CILCO will still be secured by the mortgage bonds held by their respective senior note trustee subject to the release and other provisions of the respective senior note indenture. The debt and other obligations of CIPS will remain debt and obligations of Ameren Illinois. If the Merger is consummated, it is expected that Ameren Illinois will secure the CIPS senior notes with the benefit of a 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 also expected to encumber substantially all of the operating property owned by CIPS immediately before the Merger with the lien of the IP mortgage indenture. On April13, 2010, CIPS, CILCO and IP entered into a merger agreement to accomplish the Merger. Pursuant to the merger agreement, at the effective time of the 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