NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock 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.

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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.

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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.

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Genco, or Ameren Energy Generating Company, operates a non-rate-regulated electric generation business in Illinois and Missouri.

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

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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 has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. Ameren consolidates 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 to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren.

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.

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 August 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 six months ended June 30, 2009 and 2008. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial.

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

A summary of nonvested shares as of June 30, 2009, 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
	Shares		Weighted-average Fair Value Per Unit		Shares		Weighted-average Fair Value Per Share
Nonvested at January 1, 2009	675,977		$	43.28	213,683		$	47.46
Granted^(a)	741,738			15.52	-			-
Dividends	-			-	4,134			23.99
Forfeitures	(4,080	)		29.47	(3,645	)		48.30
Vested^(b)	(126,620	)		16.98	(82,277	)		45.15
Nonvested at June 30, 2009	1,287,015		$	29.91	131,895		$	48.92

(a)	Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in March 2009 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 2009 under the 2006 Plan was determined to be $15.52 based on Ameren’s closing common share price of $22.20 per share at March 2, 2009, and lattice simulations 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. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.24%, volatility of 21.3% to 33.1% for the peer group, and Ameren’s attainment of earnings per share of at least $2.54 during each year of the performance period.

Ameren recorded compensation expense of $3 million and $7 million for the three months ended June 30, 2009 and 2008, respectively, and a related tax benefit of $1 million and $3 million for the three months ended June 30, 2009 and 2008, respectively. Ameren recorded compensation expense of $8 million and $14 million for each of the six-month periods ended June 30, 2009 and 2008, respectively, and a related tax benefit of $3 million and $5 million for the six-month periods ended June 30, 2009 and 2008, respectively. As of June 30, 2009, total compensation expense of $15 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 22 months.

Accounting Changes and Other Matters

SFAS No. 157, Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands required disclosures about fair value measurements. We adopted SFAS No. 157 as of January 1, 2008, for financial assets and liabilities and as of January 1, 2009, for nonfinancial assets and liabilities not already reported at fair value on a recurring basis. See Note 7 - Fair Value Measurements for additional information on our adoption of SFAS No. 157.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51

In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards for minority interests, which have been recharacterized as noncontrolling interests. Under the provisions of SFAS No. 160, noncontrolling interests will be classified as a component of equity separate from the parent’s equity; purchases or sales of equity interests that do not result in a change in control will be accounted for as equity transactions; net income attributable to the noncontrolling interest will be included in consolidated net income in the statement of income; and upon a loss of control, the interest sold, as well as any interest retained, will be recorded at fair value, with any gain or loss recognized in earnings. We adopted SFAS No. 160 as of the beginning of 2009. SFAS No. 160 applies prospectively, except for the presentation and disclosure requirements, for which it applies retroactively. This standard is applicable to Ameren and CILCORP. See Noncontrolling Interest below for additional information.

SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133

In March 2008, the FASB issued SFAS No. 161, which requires enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 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. SFAS No. 161 was effective in the first quarter of 2009. The adoption of SFAS No. 161 did not have a material impact on our results of operations, financial position, or liquidity, because it provided enhanced disclosure requirements only. See Note 6 - Derivative Financial Instruments for additional information on our adoption of SFAS No. 161.

FSP SFAS No. 157-4, 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 FSP SFAS No. 157-4, which was effective for us as of June 30, 2009. FSP SFAS No. 157-4 provides additional 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 FSP SFAS No. 157-4 did not have a material impact on our results of operations, financial position, or liquidity.

FSP SFAS No. 107-1 and APB Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued FSP SFAS No. 107-1 and APB Opinion No. 28-1, which was effective for us as of June 30, 2009. It amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and APB Opinion No. 28, “Interim Financial Reporting,” 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 FSP SFAS No. 107-1 and APB Opinion No. 28-1 did not have a material impact on our results of operations, financial position, or liquidity, because it provides enhanced disclosure requirements only. See Note 7 - Fair Value Measurements for our interim reporting disclosures.

FSP SFAS No. 115-2 and SFAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued FSP SFAS No. 115-2 and SFAS No. 124-2, which establishes 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 FSP, 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. FSP SFAS No. 115-2 and SFAS No. 124-2 was effective for us as of June 30, 2009. The adoption of FSP SFAS No. 115-2 and SFAS No. 124-2 did not have a material impact on our results of operations, financial position, or liquidity.

SFAS No. 165, Subsequent Events

In May 2009, the FASB issued SFAS No. 165, effective for interim and annual reporting periods ending after June 15, 2009. SFAS No. 165 establishes 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. SFAS No. 165 was effective for us as of June 30, 2009. The adoption did not have a material impact on our results of operations, financial position, or liquidity.

SFAS No. 167, Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, which significantly changes the consolidation model for VIEs. SFAS No. 167 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 impact 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. Additionally, SFAS No. 167 changes the consideration of kick-out rights in determining if an entity is a VIE, which may cause certain additional entities to now be considered VIEs. Further, SFAS No. 167 requires an ongoing reconsideration of the primary beneficiary. It also amends the events that trigger a reassessment of whether an entity is a VIE. This standard is effective for us as of January 1, 2010. We are still determining the impact the adoption of SFAS No. 167 will have on our results of operations, financial position, and liquidity, if any.

SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of SFAS No. 162

In June 2009, the FASB issued SFAS No. 168 (the “Codification”), which will become the primary source of authoritative GAAP to be applied by nongovernmental entities. Rules 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 will supersede all non-SEC accounting and reporting standards. All other nongrandfathered, non-SEC accounting literature not included in the Codification will become nonauthoritative. The Codification was effective for us as of July 1, 2009. The adoption of the Codification will not impact our results of operations, financial position, or liquidity. The adoption of the Codification will change future referencing of authoritative accounting literature to conform to the Codification.

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 and IP’s goodwill relates to the acquisition of IP in 2004. Ameren’s and CILCORP’s goodwill relates to the acquisition of CILCORP in 2003. Ameren’s goodwill also includes an additional 20% ownership interest in EEI acquired in 2004 as well as 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 in the first quarter of 2009. See Note 14 - Goodwill Impairment for further information about CILCORP’s goodwill impairment.

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 June 30, 2009. See also Note 9 - Commitments and Contingencies for additional information on emission allowances.

The following table presents the SO₂ and NO_x emission allowances held and the related aggregate SO₂ and NO_x emission allowance book values that were carried as intangible assets at June 30, 2009. Emission allowances consist of various individual emission allowance certificates and do not have expiration dates. Emission allowances are charged to fuel expense as they are used in operations.


SO2 and NOx in tons	SO2 ^(a)	NOx ^(b)	Book Value^(c)
Ameren^(d)	3,144,000	51,267	150	^(e)
UE	1,686,000	28,633	41
Genco	764,000	15,152	42
CILCORP	360,000	2,621	34	^(f)
CILCO (AERG)	360,000	2,621	2
EEI	334,000	4,861	7

(a)	Vintages are from 2009 to 2019. Each company possesses additional allowances for use in periods beyond 2019.

(b)	Vintage is 2009.

(c)	The book value represents SO₂ and NO_x emission allowances for use in periods through 2038. The book value at December 31, 2008, for Ameren, UE, Genco, CILCORP, CILCO (AERG), and EEI was $167 million, $48 million, $49 million, $35 million, $1 million, and $9 million, respectively.

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

(e)	Includes $25 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’s acquisition of CILCORP.

The following table presents the 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 six months ended June 30, 2009 and 2008.


	Three Months					Six Months
	2009			2008		2009			2008
Ameren^(a)(b)	$	8		$	9	$	13		$	16
UE		(c	)		-		(c	)		(1	)
Genco		5			6		8			13
CILCORP^(b)		2			3		2			3
CILCO (AERG)		1			-		1			-

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

(b)	Includes allowances consumed that were recorded through purchase accounting.

(c)	Less than $1 million.

Excise Taxes

Excise taxes imposed on us are reflected on Missouri electric, Missouri gas, and Illinois gas customer bills. They are recorded gross in Operating Revenues and 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 six months ended June 30, 2009 and 2008:


	Three Months				Six Months
	2009		2008		2009		2008
Ameren	$	42	$	38	$	84	$	87
UE		30		27		53		52
CIPS		3		3		8		9
CILCORP		2		2		6		7
CILCO		2		2		6		7
IP		7		6		17		19

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2009, was $106 million, $24 million, less than $1 million, $39 million, $27 million, $27 million and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. The total unrecognized tax benefits (detriments) that would impact the effective tax rate, if recognized, for each of the respective companies was as follows: Ameren - $10 million, UE - $1 million, CIPS - $- million, Genco - ($2 million), CILCORP - less than $1 million, CILCO - less than $1 million, and IP - $- million.

Ameren remains subject to U.S. federal income tax examination by the Internal Revenue Service for years 2005, 2006 and 2007. 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 state income tax issues under examination, administrative appeals, or litigation.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits 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.

Asset Retirement Obligations

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

Noncontrolling Interest

At Ameren, noncontrolling interest comprises the 20% of EEI’s net assets that are not owned by Ameren and the preferred stock not subject to mandatory redemption of the Ameren subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. At CILCORP, noncontrolling interest comprises the preferred stock not subject to mandatory redemption of its subsidiary, CILCO. This noncontrolling interest is classified as a component of equity separate from CILCORP’s equity in CILCORP’s consolidated balance sheet. Equity changes attributable to the noncontrolling interest at Ameren included net income of $3 million and $11 million and dividends paid to the noncontrolling interest holders of $8 million and $11 million for the three months ended June 30, 2009 and 2008, respectively. Equity changes attributable to the noncontrolling interest at Ameren included net income of $7 million and $22 million and dividends paid to the noncontrolling interest holders of $16 million and $21 million for the six months ended June 30, 2009, and 2008, respectively. CILCORP had no changes in equity attributable to the noncontrolling interest for the three and six months ended June 30, 2009. For the three and six months ended June 30, 2008, equity changes attributable to the noncontrolling interest at CILCORP included net income of $1 million and $1 million, respectively, and dividends paid to the noncontrolling interest holders of $1 million and $1 million, respectively.

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 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. UE cannot predict the outcome of the court appeals.

Pending Electric Rate Case

UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service by $402 million. Included in this increase request was approximately $227 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. 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 is based on a 11.5% return on equity, a capital structure composed of 47.4% equity, a rate base for UE of $6.0 billion, and a test year ended March 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of February 28, 2010.

UE’s filing includes a request for interim rate relief which, if approved, would place into effect approximately $37 million of the requested increase on October 1, 2009, subject to refund with interest based on the final outcome of the rate proceeding. The amount of this interim increase request reflects the increased revenue requirement associated with rate base additions made by UE between October 2008 and May 2009.

As part of its filing, UE also requested 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.

UE’s filing with the MoPSC also seeks approval to revise the tariff under which it serves Noranda, UE’s largest electric customer, to prospectively address the significant lost revenues UE can incur due to Noranda’s operational issues at its smelter plant in southeastern Missouri, like 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 authorized 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 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. 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 2009 Energy Efficiency Legislation

In July 2009, the Missouri governor signed a law that takes effect August 28, 2009, that, 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 as opposed to the current model of cost recovery.

Illinois

Pending Electric and Natural Gas Delivery Service Rate Cases

CIPS, CILCO and IP filed requests with the ICC in June 2009 to increase their annual revenues for electric delivery service by $181 million in the aggregate (CIPS - $51 million, CILCO - $28 million, and IP - $102 million). In supplemental testimony filed in July 2009, CIPS, CILCO, and IP revised their requests to an increase in annual revenues for electric delivery service of $176 million in the aggregate (CIPS - $50 million, CILCO - $28 million, and IP - $98 million). The electric rate increase requests are based on an 11.75% to 12.25% 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.

CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service by $45 million in the aggregate (CIPS - $11 million, CILCO - $9 million, and IP - $25 million). In supplemental testimony filed in July 2009, CIPS, CILCO, and IP revised their requests to an increase in annual revenues for natural gas delivery service of $43 million in the aggregate (CIPS - $11 million, CILCO - $9 million, and IP - $23 million). The natural gas rate increase requests are based on an 11.25% to 11.6% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010.

The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by May 2010. The Ameren Illinois Utilities cannot predict the level of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, or whether any rate changes that may eventually be approved will be sufficient to enable 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 June 30, 2009, of $6 million, $1 million, less than $1 million, $1 million, $3 million, and $1 million, respectively (quarter ended June 30, 2008 - $11 million, $1 million, $1 million, $2 million, $5 million, and $2 million, respectively) and during the six months ended June 30, 2009, of $12 million, $2 million, $1 million, $2 million, $5 million, and $2 million, respectively (six months ended June 30, 2008 - $22 million, $3 million, $2 million, $4 million, $9 million, and $4 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 Utilities in the second quarter of 2009. See Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies for further information about the results of the RFPs.

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 systems 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 $20 million of capital costs and an estimated $60 million of cumulative operations and maintenance expenses for the 2009 through 2013 timeframe in order to implement the recommendations. The Ameren Illinois Utilities requested recovery for 2009 and 2010 costs in the electric delivery service rate cases filed in June 2009, and they will seek recovery of the remainder of these costs in future rate cases.

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 beginning with 2008 and prospectively. During 2008, the Ameren Illinois Utilities under collected approximately $25 million (CIPS - $5 million, CILCO - $4 million, and IP - $16 million). The Ameren Illinois Utilities plan to file with the ICC in August 2009 electric and gas rate adjustment clause tariffs to recover bad debt expense not recovered in 2008 and to adjust rates to recover the differential thereafter. The ICC has up to 180 days from the date of filing to approve, or approve as modified, the filed tariffs. Upon ICC approval of the rate adjustment clause tariffs, 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.

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 is 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 current 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 June 30, 2009, UE had capitalized approximately $65 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. However, UE cannot at this time predict which option will ultimately be selected, whether any or all of its investment in this project will be realized or whether there will be a material impact on UE’s and Ameren’s results of operations. If all efforts are permanently abandoned with respect to the future construction of a new nuclear unit in Missouri, 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.

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. 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 rehearing request will have a material effect on their results of operations, financial position, or liquidity.

NOTE 3 - SHORT-TERM BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash and 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. These facilities, as described below, cumulatively provide $2.1 billion of credit through July 14, 2010, reducing to $1.8795 billion through June 30, 2011, and 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 as stated 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, commercial paper liquidity support 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 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 under (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 June 30, 2009, under the 2009 Multiyear Credit Agreements, 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
June 30, 2009:
Average daily borrowings outstanding during 2009	$	293		$	376		$	17		$	686
Outstanding short-term debt at period end		429			407			-			836
Weighted-average interest rate during 2009		1.14	%		1.14	%		1.04	%		1.14	%
Peak short-term borrowings during 2009^(b)	$	484		$	457		$	50		$	940
Peak interest rate during 2009		5.50	%		5.50	%		1.11	%		5.50	%


Supplemental Agreement ($150 million)							Ameren (Parent)			UE			Genco			Total
June 30, 2009:
Average daily borrowings outstanding during 2009							$	(c	)	$	(c	)	$	-		$	1
Outstanding short-term debt at period end								56			53			-			109
Weighted-average interest rate during 2009								5.50	%		5.50	%		-			5.50	%
Peak short-term borrowings during 2009^(b)							$	56		$	53		$	-		$	109
Peak interest rate during 2009								5.50	%		5.50	%		-			5.50	%

2009 Illinois Credit Agreement ($800 million)				Ameren (Parent)			CIPS			CILCO (Parent)			IP			Total
June 30, 2009:
Average daily borrowings outstanding during 2009				$	-		$	-		$	-		$	-		$	-
Outstanding short-term debt at period end					-			-			-			-			-
Weighted-average interest rate during 2009					-			-			-			-			-
Peak short-term borrowings during 2009^(b)				$	-		$	-		$	-		$	-		$	-
Peak interest rate during 2009					-			-			-			-			-

2007 $500 Million Credit Facility (Terminated)	CIPS			CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
June 30, 2009:
Average daily borrowings outstanding during 2009	$	-		$	9		$	-		$	-		$	59		$	68
Outstanding short-term debt at period end		-			-			-			-			-			-
Weighted-average interest rate during 2009		-			1.81	%		-			-			1.42	%		1.47	%
Peak short-term borrowings during 2009^(b)	$	-		$	50		$	-		$	-		$	100		$	135
Peak interest rate during 2009		-			1.81	%		-			-			3.25	%		3.25	%

2006 $500 Million Credit Facility (Terminated)	CIPS			CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
June 30, 2009:
Average daily borrowings outstanding during 2009	$	5		$	49		$	-		$	-		$	96		$	150
Outstanding short-term debt at period end		-			-			-			-			-			-
Weighted-average interest rate during 2009		2.02	%		1.88	%		-			-			1.34	%		1.54	%
Peak short-term borrowings during 2009^(b)	$	62		$	50		$	-		$	-		$	151		$	263
Peak interest rate during 2009		2.02	%		3.29	%		-			-			2.72	%		3.29	%

(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 simultaneous peak short-term borrowings under all facilities during the first six months of 2009 were $1.0 billion.

(c)	Amount less than $1 million.

Based on outstanding borrowings under the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement (including reductions for $11 million of letters of credit issued under the 2009 Multiyear Credit Agreement), the available amounts under the facilities at June 30, 2009, were $344 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 2.07% and 2.10% during the three and six months ended June 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 2.00% and 1.98% during the three and six months ended June 30, 2009, respectively. 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-term 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 (as defined below) 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.

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 June 30, 2009, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2009 Multiyear Credit Agreements, were 54%, 54% 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 June 30, 2009, 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 54%, 45%, 46%, and 47%, respectively. In addition, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 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 June 30, 2009 was 4.4 to 1. Failure to satisfy these capitalization 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 then 65% of consolidated total capitalization pursuant to a calculation defined in the term loan agreement. As of June 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 53%.

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 June 30, 2009, management believes that the Ameren Companies were in compliance with their credit facilities and term loan agreement 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 June 30, 2009. 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 six months ended June 30, 2009, was 0.2% and 0.2%, respectively (2008 - 2.8% and 3.5%, respectively).

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 June 30, 2009, 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 six months ended June 30, 2009, was 1.1% and 1.1%, respectively (2008 - 3.1% and 3.8%, respectively).

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 six months ended June 30, 2009.

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 0.8 million new shares of common stock valued at $19 million and 1.9 million new shares valued at $47 million in the three and six months ended June 30, 2009, respectively.

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 will be used to provide such amounts, by way of a capital contribution, loan or otherwise to CILCORP, to permit CILCORP to repay its outstanding 8.70% senior notes due October 15, 2009.

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 $0.5 million and $1 million (2008 - $2 million and $3 million) for the three and six months ended June 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 outstanding 8.70% senior notes due 2009 ($123.755 million aggregate principal amount) and its 9.375% senior bonds due 2029 ($210.565 million aggregate principal amount). In April 2009, CILCORP terminated the tender offer and the consent solicitation related to the 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.

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.

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 June 30, 2009, at an assumed interest 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
UE	³2.0	2.1	$	279	³2.5	28.4	$	769
CIPS	³2.0	2.8		128	³1.5	1.7		47
CILCO	³2.0^(d)	8.6		215	³2.5	109.1		50	^(e)
IP	³2.0	2.7		939	³1.5	1.4		-

(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 $110 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 six months ended June 30, 2009, CILCO had earnings equivalent to at least 31% of the principal amount of all mortgage bonds outstanding.

(e)	See Note 3 - Short-term Borrowings and Liquidity for a discussion regarding the restriction on the issuance of preferred stock by CILCO under the 2009 Illinois Credit Agreement.

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 June 30, 2009.

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) if at the time of dividend declaration, there shall not remain to the credit of earned surplus account (after deducting the amount of such dividends) 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 include provisions that require the companies to maintain certain debt service coverage and/or debt-to-capital ratios in order for the companies 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 June 30, 2009:


	Required Interest Coverage Ratio		Actual Interest Coverage Ratio	Required Debt-to- Capital Ratio		Actual Debt-to- Capital Ratio
Genco ^(a)	³1.75	^(b)	5.7	£60	%	50	%
CILCORP^(c)	³2.2		4.1	£67	%	40	%

(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 June 30, 2009, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BB+, Ba2, 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 June 30, 2009, 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 six months ended June 30, 2009 and 2008:


	Three Months						Six Months
	2009			2008			2009			2008
Ameren:^(a)
Miscellaneous income:
Interest and dividend income	$	7		$	13		$	15		$	25
Allowance for equity funds used during construction		8			5			14			11
Other		2			1			4			2
Total miscellaneous income	$	17		$	19		$	33		$	38
Miscellaneous expense:
Other	$	(7	)	$	(8	)	$	(11	)	$	(13	)
Total miscellaneous expense	$	(7	)	$	(8	)	$	(11	)	$	(13	)
UE:
Miscellaneous income:
Interest and dividend income	$	7		$	10		$	14		$	18
Allowance for equity funds used during construction		7			5			13			11
Other		1			-			1			-
Total miscellaneous income	$	15		$	15		$	28		$	29
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(4	)	$	(4	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(4	)	$	(4	)


	Three Months						Six Months
	2009			2008			2009			2008
CIPS:
Miscellaneous income:
Interest and dividend income	$	1		$	2		$	3		$	5
Other		1			1			2			1
Total miscellaneous income	$	2		$	3		$	5		$	6
Miscellaneous expense:
Other	$	-		$	(2	)	$	(1	)	$	(2	)
Total miscellaneous expense	$	-		$	(2	)	$	(1	)	$	(2	)
Genco:
Miscellaneous income:
Other	$	-		$	1		$	-		$	1
Total miscellaneous income	$	-		$	1		$	-		$	1
CILCORP:
Miscellaneous income:
Interest income	$	-		$	1		$	-		$	1
Total miscellaneous income	$	-		$	1		$	-		$	1
Miscellaneous expense:
Other		(1	)		(2	)		(2	)		(2	)
Total miscellaneous expense	$	(1	)	$	(2	)	$	(2	)	$	(2	)
CILCO:
Miscellaneous income:
Interest income	$	-		$	1		$	-		$	1
Total miscellaneous income	$	-		$	1		$	-		$	1
Miscellaneous expense:
Other		(2	)		(1	)		(3	)		(1	)
Total miscellaneous expense	$	(2	)	$	(1	)	$	(3	)	$	(1	)
IP:
Miscellaneous income:
Interest income	$	-		$	2		$	-		$	4
Allowance for equity funds used during construction		1			-			1			-
Other		-			1			1			2
Total miscellaneous income	$	1		$	3		$	2		$	6
Miscellaneous expense:
Other	$	-		$	(2	)	$	(1	)	$	(3	)
Total miscellaneous expense	$	-		$	(2	)	$	(1	)	$	(3	)

(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, electricity, and emission allowances. Price fluctuations in natural gas, fuel, electricity, and emission allowances 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 fuel and natural gas inventories, emission allowances or purchased power 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 June 30, 2009:


	Quantity
Commodity	NPNS Contracts^(a)		Cash Flow Hedges^(b)		Other Derivatives^(c)		Derivatives Subject to Regulatory Deferral^(d)
Coal (in tons)
Ameren^(e)	89,119,000		(f	)	(f	)	(f	)
UE	49,242,000		(f	)	(f	)	(f	)
Genco	19,155,000		(f	)	(f	)	(f	)
CILCORP/CILCO	10,401,000		(f	)	(f	)	(f	)
Natural gas (in mmbtu)
Ameren^(e)	194,941,000		(f	)	6,278,000		118,342,000
UE	26,451,000		(f	)	(f	)	18,189,000
CIPS	33,563,000		(f	)	(f	)	19,186,000
Genco	1,665,000		(f	)	4,390,000		(f	)
CILCORP/CILCO	57,903,000		(f	)	868,000		29,372,000
IP	75,197,000		(f	)	(f	)	51,595,000
Heating oil (in gallons)
Ameren^(e)	(f	)	(f	)	186,018,000		42,588,000
UE	(f	)	(f	)	(f	)	42,588,000
Power (in megawatthours)
Ameren^(e)	84,887,000		5,961,000		31,006,000		13,339,000
UE	3,921,000		(f	)	232,000		3,795,000
CIPS	(f	)	(f	)	(f	)	12,813,000
CILCORP/CILCO	(f	)	(f	)	(f	)	6,600,000
IP	(f	)	(f	)	(f	)	19,413,000
SO₂ emission allowances (in tons)
Ameren	(f	)	(f	)	2,000		(f	)
Genco	(f	)	(f	)	2,000		(f	)

(a)	Contracts through 2013, 2015, and 2035 for coal, natural gas, and power, respectively.

(b)	Contracts through 2011 for power.

(c)	Contracts through 2009, 2012, 2012, and 2009 for natural gas, heating oil, power, and SO₂ emission allowances, respectively.

(d)	Contracts through 2013, 2012, and 2012 for natural gas, heating oil and power, respectively.

(e)	Includes amounts from Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

(f)	Not applicable.

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133), 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 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 under SFAS No. 133. We also consider whether gains and losses resulting from such derivatives qualify for deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). 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.

Contracts that qualify for fair value hedge accounting 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. In addition, the underlying exposure being hedged in a fair value hedge relationship is similarly treated. The net effect to the statement of income in a fair value hedge relationship is equal to the change in fair value of the derivative instrument offset by the change in the value of the underlying.

Contracts that qualify for deferral under SFAS No. 71 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 or 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 under SFAS No. 133, or deferral accounting under SFAS No. 71. 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 June 30, 2009:


	Balance Sheet Location	Ameren^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Derivative assets designated as hedging instruments under SFAS No. 133
Commodity contracts:
Power	MTM derivative assets	$	66		$	-		$	(b	)	$	(b	)	$	(b	)	$	(b	)
	Other assets		7			-			-			-			-			-
	Total assets	$	73		$	-		$	-		$	-		$	-		$	-
Derivative liabilities designated as hedging instruments under SFAS No. 133
Commodity contracts:
Power	MTM derivative liabilities	$	1		$	(b	)	$	-		$	(b	)	$	-		$	-
	Total liabilities	$	1		$	-		$	-		$	-		$	-		$	-
Derivative assets not designated as hedging instruments under SFAS No. 133
Commodity contracts:
Natural gas	MTM derivative assets	$	2		$	-		$	(b	)	$	(b	)	$	(b	)	$	(b	)
Heating oil	MTM derivative assets		28			3			(b	)		(b	)		(b	)		(b	)
	Other assets		57			16			-			-			-			-
Power	MTM derivative assets		181			28			(b	)		(b	)		(b	)		(b	)
	Other current assets		-			-			-			-			-			-
	Other assets		21			-			1			-			1			2
	Total assets	$	289		$	47		$	1		$	-		$	1		$	2
Derivative liabilities not designated as hedging instruments under SFAS No. 133
Commodity contracts:
Natural gas	MTM derivative liabilities	$	102		$	(b	)	$	18		$	(b	)	$	21		$	39
	Other current liabilities		-			16			-			-			-			-
	Other deferred credits and liabilities		34			5			8			-			6			15
Heating oil	MTM derivative liabilities		21			(b	)		-			(b	)		-			-
	Other deferred credits and liabilities		19			-			-			-			-			-
Power	MTM derivative liabilities		109			(b	)		3			(b	)		1			4
	MTM derivative liabilities – affiliates		(b	)		(b	)		37			(b	)		17			47
	Other current liabilities		-			7			-			-			-			-
	Other deferred credits and liabilities		5			-			88			-			45			133
SO₂ emission allowances	MTM derivative liabilities		1			-			-			(b	)		-			-
	Other current liabilities		-			-			-			1			-			-
	Total liabilities	$	291		$	28		$	154		$	1		$	90		$	238

(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 June 30, 2009:


	Ameren^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Cumulative gains (losses) deferred in accumulated OCI:
Power forwards^(b)	$	69		$	-		$	-		$	-		$	-		$	-
Interest rate swaps^(c)(d)		(10	)		-			-			(10	)		-			-
Cumulative gains (losses) deferred in regulatory assets or liabilities:
Natural gas swaps and futures contracts^(e)		(128	)		(22	)		(27	)		-			(26	)		(53	)
Financial contracts^(f)		16			21			(126	)		-			(63	)		(182	)
Heating oil options and swaps^(g)		(5	)		(5	)		-			-			-			-

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

(b)	Represents the MTM value for the hedged portion of electricity price exposure through August 2011, including current gains of $55 million at Ameren as of June 30, 2009.

(c)

Includes a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at June 30, 2009, was $2 million. Over the next twelve months, $0.7 million of the gain will be amortized.

(d)

Includes a loss associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco’s April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at June 30, 2009 was a loss of $12 million. Over the next twelve months, $1.4 million of the loss will be amortized.

(e)

Represents losses associated with natural gas swaps and futures contracts. The swaps and futures contracts are a partial hedge of natural gas requirements through October 2013 at UE and CIPS, through March 2013 at CILCO and through March 2014 at IP as of June 30, 2009. Current losses deferred as regulatory assets include $16 million, $19 million, $21 million, and $39 million at UE, CIPS, CILCO and IP, respectively, as of June 30, 2009.

(f)

Represents gains (losses) associated with financial contracts. The financial contracts are a partial hedge of power price exposure through December 2010 at UE and December 2012 at CIPS, CILCO, and IP. Current gains deferred as regulatory liabilities include $24 million at UE as of June 30, 2009. Current losses deferred as regulatory assets include $7 million, $39 million, $18 million, and $51 million at UE, CIPS, CILCO and IP, respectively, as of June 30, 2009.

(g)

Represents losses on heating oil options and swaps at UE. The options and swaps are a partial hedge of our transportation costs for coal through December 2012. Current gains deferred as regulatory liabilities include $2 million at UE as of June 30, 2009. Current losses deferred as regulatory assets include $11 million at UE as of June 30, 2009.

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

We believe that entering into master trading and netting agreements mitigates the level of financial loss resulting 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 gas and electric contract, (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association - a standardized contract for the purchase and sale of wholesale power, and (3) 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 reviewed our individual counterparties and categorized 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 June 30, 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
Ameren^(a)	$	639	$	14	$	48	$	177	$	31	$	206	$	18	$	82	$	1,215
UE		70		10		9		32		-		36		-		-		157
CIPS		-		-		-		1		-		-		-		-		1
Genco		-		3		1		3		-		-		4		-		11
CILCORP/CILCO		-		1		-		3		-		-		-		-		4
IP		-		-		-		3		-		-		1		-		4

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

The following table presents the amount of cash collateral held from counterparties, as of June 30, 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

(a)	Represents amounts held by Marketing Company. As of June 30, 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. Other collateral consisted of letters of credit in the amount of $39 million and $1 million held by Ameren and UE, respectively, as of June 30, 2009. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2009:


	Affiliates		Coal Producers		Electric Utilities		Financial Companies		Commodity Marketing Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Retail Companies		Total
Ameren^(a)	$	617	$	1	$	19	$	130	$	15	$	157	$	16	$	81	$	1,036
UE		70		1		8		29		-		35		-		-		143
CIPS		-		-		-		-		-		-		-		-		-
Genco		-		-		1		-		-		-		3		-		4
CILCORP/CILCO		-		-		-		1		-		-		-		-		1
IP		-		-		-		-		-		-		1		-		1

(a)	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 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 June 30, 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 required to be posted with counterparties, based on the net liability position as allowed under the master trading and netting agreements, if the credit risk-related contingent features underlying these agreements were triggered on June 30, 2009, and 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)
Ameren^(c)	$	693	$	116	$	386
UE		162		14		143
CIPS		57		26		28
Genco		50		-		45
CILCORP/CILCO		82		26		48
IP		135		48		55

(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 (loss) for the three months ended June 30, 2009, associated with derivative instruments designated as cash flow hedges:


Derivatives in SFAS No. 133 Cash Flow Hedging Relationship	Amount of Gain (Loss) Recognized in OCI on Derivative^(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 Derivative^(c)	Amount of Gain (Loss) Recognized in Income on Derivative^(c)
Ameren:^(d)
Power	$	1	Operating Revenues - Electric	$	(23	)	Operating Revenues - Electric	$	(4	)
Interest rate^(e)		-	Interest Charges		(f	)	Interest Charges		-
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 (loss) for the six months ended June 30, 2009, associated with derivative instruments designated as cash flow hedges:


Derivatives in SFAS No. 133 Cash Flow Hedging Relationship	Amount of Gain (Loss) Recognized in OCI on Derivative^(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 Derivative^(c)	Amount of Gain (Loss) Recognized in Income on Derivative^(c)
Ameren:^(d)
Power	$	47		Operating Revenues -Electric	$	(63	)	Operating Revenues - Electric	$	(16	)
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.

Fair Value Hedges

During the third quarter ended September 30, 2008, UE entered into foreign currency forward contracts to fix the amount of U.S. dollars UE would pay for future equipment deliveries denominated in euros. Subsequently, UE entered into an agreement with a supplier to terminate a purchase commitment related to those equipment deliveries. Therefore, the payments previously required under the commitment will not be incurred. As a result, all foreign currency forward contracts and fair value hedges were discontinued, resulting in less than a $1 million impact on earnings, during the second quarter ended June 30, 2009.

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments under SFAS No. 133 for the three months ended June 30, 2009:


	Derivatives Not Designated as Hedging Instruments under SFAS No. 133	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
Ameren^(a)	Natural gas (generation)	Operating Expenses - Fuel	$	1
	Natural gas (resale)	Operating Revenues - Gas		(2	)
	Heating oil	Operating Expenses - Fuel		15
	Power	Operating Revenues - Electric		(5	)
		Total	$	9
Genco	Heating oil	Operating Expenses - Fuel		9
CILCORP/CILCO	Natural gas (resale)	Operating Revenues - Gas	$	(2	)
	Heating oil	Operating Expenses - Fuel		3
		Total	$	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 under SFAS No. 133 for the six months ended June 30, 2009:


	Derivatives Not Designated as Hedging Instruments under SFAS No. 133	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
Ameren^(a)	Natural gas (generation)	Operating Expenses - Fuel	$	4
	Natural gas (resale)	Operating Revenues - Gas		-
	Heating oil	Operating Expenses - Fuel		39
	Power	Operating Revenues - Electric		29
		Total	$	72
UE	Natural gas (generation)	Operating Expenses - Fuel	$	4
	Heating oil	Operating Expenses - Fuel		25
	Power	Operating Revenues - Electric - excluding off-system		(2	)
	Power	Operating Revenues - Electric - off-system		1
		Total	$	28
Genco	Heating oil	Operating Expenses - Fuel	$	8
CILCORP/CILCO	Natural gas (resale)	Operating Revenues - Gas	$	-
	Heating oil	Operating Expenses - Fuel		3
		Total	$	3

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

Derivatives Subject to Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for deferral under SFAS No. 71 for the three months ended June 30, 2009:


	Derivatives Subject to Regulatory Deferral	Amount of Gain or (Loss) Recognized in Regulatory Assets or Regulatory Liabilities on Derivative
Ameren^(a)	Natural gas	$	74
	Heating oil		22
	Power		(22	)
	Total	$	74
UE	Natural gas	$	9
	Heating oil		22
	Power		(17	)
	Total	$	14
CIPS	Natural gas	$	14
	Power		3
	Total	$	17
CILCORP/CILCO	Natural gas	$	18
	Power		2
	Total	$	20
IP	Natural gas	$	33
	Power		9
	Total	$	42

(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 deferral under SFAS No. 71 for the six months ended June 30, 2009:


	Derivatives Subject to Regulatory Deferral	Amount of Gain or (Loss) Recognized in Regulatory Assets or Regulatory Liabilities on Derivative
Ameren^(a)	Natural gas	$	(10	)
	Heating oil		(5	)
	Power		16
	Total	$	1
UE	Natural gas	$	(6	)
	Heating oil		(5	)
	Power		21
	Total	$	10
CIPS	Natural gas	$	1
	Power		(70	)
	Total	$	(69	)
CILCORP/CILCO	Natural gas	$	(1	)
	Power		(34	)
	Total	$	(35	)
IP	Natural gas	$	(4	)
	Power		(97	)
	Total	$	(101	)

(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 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 by 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 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, under SFAS No. 71. 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 pre-tax 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, the Ameren Illinois Utilities entered into financial contracts with Marketing Company. These financial contracts are derivative instruments being accounted for as cash flow hedges at Marketing Company while they are being accounted for as derivatives subject to regulatory deferral at 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 for the Ameren Illinois Utilities and OCI at 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

SFAS No. 157 provides a framework for measuring fair value for all assets and liabilities that are measured and reported at fair value. The Ameren Companies adopted SFAS No. 157 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 SFAS No. 157 for financial assets and liabilities at January 1, 2008, and for nonfinancial assets and liabilities at January 1, 2009, was not material. SFAS No. 157 defines fair value 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 risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. SFAS No. 157 also establishes 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 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. We value Level 3 instruments 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 review 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 SFAS No. 157. 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.

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). SFAS No. 157 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 $5 million in losses in the second quarter of 2009 related to valuation adjustments for counterparty default risk. At June 30, 2009, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $(3) million, less than $1 million, $10 million, $7 million, and $25 million for Ameren, UE, CIPS, 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 June 30, 2009:


		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^(b)		2		103		257		362
	Nuclear Decommissioning Trust Fund^(c)		189		56		3		248
UE	Derivative assets		-		8		39		47
	Nuclear Decommissioning Trust Fund^(c)		189		56		3		248
CIPS	Derivative assets^(b)		-		-		1		1
Genco	Derivative assets^(b)		-		-		-		-
CILCORP/CILCO	Derivative assets^(b)		-		-		1		1
IP	Derivative assets^(b)		-		-		2		2
Liabilities:
Ameren^(a)	Derivative liabilities^(b)	$	9	$	51	$	232	$	292
UE	Derivative liabilities^(b)		-		2		26		28
CIPS	Derivative liabilities^(b)		-		-		154		154
Genco	Derivative liabilities^(b)		-		-		1		1
CILCORP/CILCO	Derivative liabilities^(b)		-		-		90		90
IP	Derivative liabilities^(b)		-		-		238		238

(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:


		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^(b)		1		19		234		254
	Nuclear Decommissioning Trust Fund^(c)		164		81		2		247
UE	Derivative assets		-		14		36		50
	Nuclear Decommissioning Trust Fund^(c)		164		81		2		247


		Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
CIPS	Derivative assets^(b)		-		-		-		-
Genco	Derivative assets^(b)		-		-		-		-
CILCORP/CILCO	Derivative assets^(b)		-		-		-		-
IP	Derivative assets^(b)		-		-		-		-
Liabilities:
Ameren^(a)	Derivative liabilities^(b)	$	9	$	6	$	219	$	234
UE	Derivative liabilities^(b)		-		3		31		34
CIPS	Derivative liabilities^(b)		-		-		84		84
Genco	Derivative liabilities^(b)		-		-		1		1
CILCORP/CILCO	Derivative liabilities^(b)		4		-		55		59
IP	Derivative liabilities^(b)		-		-		134		134

(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) 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 June 30, 2009:


					Realized and Unrealized Gains (Losses)								Total Realized			Purchases,								Change in Unrealized Gains (Losses)
		Beginning Balance at April 1, 2009			Included in Earnings^(a)		Included In OCI			Included in Regulatory Assets/ Liabilities			and Unrealized Gains (Losses)			Issuances, and Other Settlements, Net		Net Transfers Into (Out of) Level 3			Ending Balance at June 30, 2009			Related to Assets/ Liabilities Still Held at June 30, 2009
Other current assets	Ameren	$	2		$	-	$	-		$	-		$	-		$	-	$	-		$	2		$	-
Net derivative	Ameren	$	1		$	35	$	(24	)	$	34		$	45		$	22	$	(43	)	$	25		$	13
contracts	UE		(6	)		-		5			16			21			3		(5	)		13			7
	CIPS		(170	)		-		(10	)		(4	)		(14	)		31		-			(153	)		(4	)
	Genco		(2	)		-		-			-			-			1		-			(1	)		-
	CILCORP/CILCO		(108	)		5		(5	)		(5	)		(5	)		24		-			(89	)		1
	IP		(277	)		-		(16	)		5			(11	)		52		-			(236	)		5
Nuclear	Ameren	$	-		$	-	$	-		$	-		$	-		$	3	$	-		$	3		$	-
Decommissioning Trust Fund	UE		-			-		-			-			-			3		-			3			-

(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 six months ended June 30, 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			Net Transfers Into (Out of) Level 3			Ending Balance at June 30, 2009			Related to Assets/ Liabilities Still Held at June 30, 2009
Other current assets	Ameren	$	6		$	-		$	-		$	-		$	-		$	-		$	(4	)	$	2		$	-
Net derivative	Ameren	$	15		$	52		$	57		$	(52	)	$	57		$	7		$	(54	)	$	25		$	(32	)
contracts	UE		5			-			37			(3	)		34			(8	)		(18	)		13			(4	)
	CIPS		(84	)		-			(10	)		(108	)		(118	)		49			-			(153	)		(91	)
	Genco		(1	)		(1	)		-			-			(1	)		1			-			(1	)		-
	CILCORP/CILCO		(55	)		(19	)		(5	)		(47	)		(71	)		37			-			(89	)		(52	)
Nuclear	Ameren	$	2		$	-		$	-		$	-		$	-		$	1		$	-		$	3		$	-
Decommissioning Trust Fund	UE		2			-			-			-			-			1			-			3			-

(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 June 30, 2008:


				Realized and Unrealized Gains (Losses)								Total Realized		Purchases,								Change in Unrealized Gains (Losses)
		Beginning Balance at April 1, 2008		Included in Earnings			Included In OCI			Included in Regulatory Assets/ Liabilities		and Unrealized Gains (Losses)		Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3			Ending Balance at June 30, 2008		Related to Assets/ Liabilities Still Held at June 30, 2008
Net derivative	Ameren	$	59	$	87		$	(25	)	$	109	$	171	$	(29	)	$	1		$	202	$	122
contracts	UE		15		8			3			12		23		2			(a	)		40		18
	CIPS		58		-			-			56		56		(2	)		-			112		56
	Genco		1		4			(a	)		-		4		(1	)		-			4		4
	CILCORP/CILCO		40		(1	)		-			42		41		(4	)		-			77		42
	IP		102		-			-			97		97		(4	)		-			195		101
Nuclear	Ameren	$	2	$	-		$	-		$	-	$	-	$	(1	)	$	-		$	1	$	-
Decommissioning Trust Fund	UE		2		-			-			-		-		(1	)		-			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 six months ended June 30, 2008:


				Realized and Unrealized Gains (Losses)								Total Realized		Purchases,								Change in Unrealized Gains (Losses)
		Beginning Balance at January 1, 2008		Included in Earnings			Included In OCI			Included in Regulatory Assets/ Liabilities		and Unrealized Gains (Losses)		Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3			Ending Balance at June 30, 2008		Related to Assets/ Liabilities Still Held at June 30, 2008
Net derivative	Ameren	$	19	$	93		$	(59	)	$	178	$	212	$	(19	)	$	(10	)	$	202	$	75
contracts	UE		3		10			10			19		39		(3	)		1			40		14
	CIPS		38		-			-			75		75		(1	)		-			112		66
	Genco		1		4			(a	)		-		4		(1	)		-			4		4
	CILCORP/CILCO		21		(1	)		(a	)		62		61		(5	)		-			77		54
	IP		55		-			-			140		140		(a	)		-			195		132
Nuclear	Ameren	$	5	$	-		$	-		$	-	$	-	$	(4	)	$	-		$	1	$	-
Decommissioning Trust Fund	UE		5		-			-			-		-		(4	)		-			1		-

(a)	Less than $1 million.

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 between Level 2 and 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 June 30, 2009 and 2008. 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 and liabilities, Note 14 - Goodwill Impairment details the inputs to the valuation of goodwill, which is considered a Level 3 asset, and the impairment charge recorded related to CILCORP’s goodwill. CILCORP’s goodwill is measured at fair value on a nonrecurring basis and was impaired during the first quarter of 2009. The following table sets forth, by level within the fair value hierarchy, CILCORP’s goodwill as of June 30, 2009:

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)	In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” 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 preferred stock at June 30, 2009:


	Carrying Amount		Fair Value
Ameren:^(a)
Long-term debt and capital lease obligations (including current portion)	$	7,450	$	7,363
Preferred stock		195		121
UE:
Long-term debt and capital lease obligations (including current portion)	$	4,026	$	3,950
Preferred stock		113		75
CIPS:
Long-term debt (including current portion)	$	421	$	411
Preferred stock		50		25
Genco:
Long-term debt (including current portion)	$	774	$	710
CILCORP:
Long-term debt (including current portion)	$	660	$	664
Preferred stock		19		13
CILCO:
Long-term debt (including current portion)	$	279	$	292
Preferred stock		19		13
IP:
Long-term debt (including current portion)	$	1,146	$	1,181
Preferred stock		46		29

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

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 June 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 June 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 six months ended June 30, 2009, Genco incurred charges to earnings of $3 million and $5 million, respectively, for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS - $1 million and $2 million, CILCO - less than $1 million and $1 million, IP - $1 million and $2 million, respectively), and AERG incurred charges to earnings of $1 million and $2 million, respectively (CIPS - less than $1 million and $1 million, CILCO - less than $1 million for both periods, 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 six months ended June 30, 2009 and 2008:


	Three Months		Six Months
	2009	2008	2009	2008
Genco sales to Marketing Company^(a)	3,494	3,529	6,958	7,941
AERG sales to Marketing Company^(a)	1,591	1,610	2,975	3,313
Marketing Company sales to CIPS^(b)	372	472	818	1,094
Marketing Company sales to CILCO^(b)	153	223	361	480
Marketing Company sales to IP^(b)	506	698	1,127	1,502

(a)	Genco and Marketing Company, and AERG and Marketing Company have power supply agreements 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, the Ameren Illinois Utilities used a RFP process, administered by the IPA, to contract the necessary capacity for the period from June 1, 2009, through May 31, 2012. Both Marketing Company and UE were winning suppliers in the Ameren Illinois Utilities’ capacity RFP process. In April 2009, Marketing Company contracted to supply capacity to the Ameren Illinois Utilities for $4 million, $9 million, and $8 million for the twelve months ending May 31, 2010, 2011, and 2012, respectively. In April 2009, UE contracted to supply capacity to the Ameren Illinois Utilities for $2 million, $2 million, and $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 swaps from June 1, 2009, through May 31, 2011. Marketing Company was a winning supplier in the Ameren Illinois Utilities’ energy swap RFP process. In May 2009, Marketing Company entered into financial instruments that fixed 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, 2010 and for approximately 89,000 megawatthours at approximately $48 per megawatthour during the twelve months ending May 31, 2011.

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 June 30, 2009, and December 31, 2008, there were no collateral postings by 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 posting 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 June 30, 2009, there were no collateral postings between 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 Agreement

In 2008, Genco and CIPS signed an agreement requiring Genco to fund the construction costs of upgrades to CIPS’ transmission system. At June 30, 2009, CIPS had recorded $2 million in Other Deferred Credits and Liabilities and Genco had recorded $2 million in Accounts Receivable - Affiliates. These transactions were eliminated in consolidation on Ameren’s financial statements.

Money Pools

See Note 3 - Short-term 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 subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco matures on May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $1 million and $3 million (2008 - $2 million and $4 million) for the three and six months ended June 30, 2009, respectively.

CILCORP (parent company) had outstanding borrowings from Ameren of $210 million and $152 million at June 30, 2009, and December 31, 2008, respectively. The separate unilateral borrowing agreement between CILCORP and Ameren, entered into in March 2009, was repaid during the second quarter with no borrowings outstanding at June 30, 2009. The average interest rate on all of the Ameren borrowings was 3.6% and 2.6% for the three and six months ended June 30, 2009, respectively (2008 - 3.1% and 3.8%, respectively). CILCORP recorded interest expense of $1 million and $2 million for these borrowings for the three and six months ended June 30, 2009, respectively (2008 - less than $1 million for the three and six months periods).

CILCO (AERG) had outstanding borrowings from Ameren of $346 million at June 30, 2009. The separate unilateral borrowing agreement between CILCO (AERG) and Ameren, entered into in March 2009, was repaid during the second quarter with no borrowings outstanding at June 30, 2009. The average interest rate on all of the Ameren borrowings was 4.4% and 4.3% for the three and six months ended June 30, 2009, respectively. CILCO (AERG) recorded interest expense of $2 million and $2 million, respectively for these borrowings for the three and six months ended June 30, 2009.

UE had no outstanding borrowings directly from Ameren at June 30, 2009, and had outstanding borrowings directly from Ameren of $92 million at December 31, 2008. During the second quarter, UE did not have any borrowings from Ameren. The average interest rate on UE’s borrowings from Ameren was 1.4% for the six months ended June 30, 2009 (2008 - 3.8%). UE recorded interest expense of less than $1 million for these borrowings for the six months ended June 30, 2009 (2008 - less than $1 million for the six-month period).

The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three and six months ended June 30, 2009 and 2008. 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-term Borrowings and Liquidity of this report.


		Three Months													Six Months
Agreement		UE			CIPS			Genco			CILCORP^(a)	IP			UE			CIPS			Genco			CILCORP^(a)	IP
Operating Revenues:
Genco and AERG power supply	2009	$	(b	)	$	(b	)	$	218		$105	$	(b	)	$	(b	)	$	(b	)	$	440		$198	$	(b	)
agreements with Marketing Company	2008		(b	)		(b	)		199		70		(b	)		(b	)		(b	)		425		153		(b	)

Ancillary services and capacity	2009		(e	)		(b	)		(b	)	(b)		(b	)		1			(b	)		(b	)	(b)		(b	)
agreements with CIPS, CILCO and IP^(c)	2008		3			(b	)		(b	)	(b)		(b	)		6			(b	)		(b	)	(b)		(b	)

Genco gas sales to Medina Valley	2009		(b	)		(b	)		(e	)	(b)		(b	)		(b	)		(b	)		1		(b)		(b	)
	2008		(b	)		(b	)		-		(b)		(b	)		(b	)		(b	)		-		(b)		(b	)

CILCO support services^(h)	2009		(b	)		(b	)		(b	)	18		(b	)		(b	)		(b	)		(b	)	34		(b	)
	2008		(b	)		(b	)		(b	)	(b)		(b	)		(b	)		(b	)		(b	)	(b)		(b	)

Genco gas sales to distribution	2009		(b	)		(b	)		1		(b)		(b	)		(b	)		(b	)		1		(b)		(b	)
companies	2008		(b	)		(b	)		5		(b)		(b	)		(b	)		(b	)		5		(b)		(b	)
Total Operating Revenues	2009	$	(e	)	$	(b	)	$	219		$123	$	(b	)	$	1		$	(b	)	$	442		$232	$	(b	)
	2008		3			(b	)		204		70		(b	)		6			(b	)		430		153		(b	)

Purchased Power:
CIPS, CILCO and IP agreements with	2009	$	(b	)	$	37		$	(b	)	$16	$	52		$	(b	)	$	78		$	(b	)	$36	$	111
Marketing Company^(d)	2008		(b	)		31			(b	)	15		46			(b	)		72			(b	)	32		99

Ancillary services and capacity	2009		(b	)		(e	)		(b	)	(e)		(e	)		(b	)		(e	)		(b	)	(e)		(e	)
agreements with UE^(c)	2008		(b	)		1			(b	)	(e)		2			(b	)		2			(b	)	1		3

Ancillary services agreement with	2009		(b	)		-			(b	)	-		-			(b	)		(e	)		(b	)	(e)		(e	)
Marketing Company	2008		(b	)		1			(b	)	1		1			(b	)		3			(b	)	2		4

Executory tolling agreement with	2009		(b	)		(b	)		(b	)	(f)		(b	)		(b	)		(b	)		(b	)	(f)		(b	)
Medina Valley	2008		(b	)		(b	)		(b	)	9		(b	)		(b	)		(b	)		(b	)	22		(b	)
Total Purchased Power	2009	$	(b	)	$	37		$	(b	)	$16	$	52		$	(b	)	$	78		$	(b	)	$36	$	111
	2008		(b	)		33			(b	)	25		49			(b	)		77			(b	)	57		106


		Three Months													Six Months
Agreement		UE			CIPS			Genco			CILCORP^(a)	IP			UE			CIPS			Genco			CILCORP^(a)	IP

Gas purchases for resale
Gas purchases from Genco	2009	$	-		$	-		$	(b	)	$1	$	(e	)	$	-		$	-		$	(b	)	$1	$	(e	)
	2008		-			-			(b	)	5		-			-			-			(b	)	5		-
Operating Revenues and Purchased Power:
Insurance recoveries	2009	$	-		$	(b	)	$	-		$-	$	(b	)	$	-		$	(b	)	$	-		$-	$	(b	)
	2008		-			(b	)		(e	)	(1)		(b	)		(e	)		(b	)		(6	)	(1)		(b	)

Other Operations and Maintenance:
Ameren Services support services	2009	$	33		$	8		$	8		$9	$	12		$	65		$	15		$	14		$19	$	24
agreement	2008		36			15			7		15		22			71			28			14		28		42

CILCO support services	2009		(b	)		6			(b	)	(b)		8			(b	)		11			(b	)	(b)		15
	2008		(b	)		(b	)		(b	)	(b)		(b	)		(b	)		(b	)		(b	)	(b)		(b	)

AFS support services agreement	2009		2			(e	)		1		(e)		(e	)		4			1			2		1		1
	2008		1			1			(e	)	1		1			3			1			1		1		1

Insurance premiums^(g)	2009		(e	)		(b	)		(e	)	(e)		(b	)		1			(b	)		1		(e)		(b	)
	2008		2			(b	)		1		1		(b	)		5			(b	)		2		2		(b	)

Total Other Operations and	2009	$	35		$	14		$	9		$9	$	20		$	70		$	27		$	17		$20	$	40
Maintenance Expenses	2008		39			16			8		17		23			79			29			17		31		43
Interest Charges:
Interest expense (income) from money	2009	$	-		$	(e	)	$	(e	)	$(e)	$	(e	)	$	-		$	(e	)	$	1		$1	$	(e	)
pool borrowings (advances)	2008		-			(e	)		(e	)	(e)		(e	)		-			(e	)		(e	)	(e)		(e	)

(a)	Amounts represent CILCORP and CILCO activity.

(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 June 30, 2009 (CIPS - $2 million, and IP - $2 million) and during the six months ended June 30, 2009 (CIPS - $3 million and IP - $5 million).

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 these 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 June 30, 2009. 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
Public liability and nuclear worker liability:
American Nuclear Insurers	$	300	^(a)	$	-
Pool participation		12,219			118	^(b)
	$	12,519	^(c)	$	118
Property damage:
Nuclear Electric Insurance Ltd.	$	2,750	^(d)	$	22
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 the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.

(c)

Limit of liability for each incident under Price-Anderson. 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 a nuclear plant. Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter.

(f)

Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 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. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

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

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

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. We have also 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 coal have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated coal purchase commitments at June 30, 2009:


	2009		2010		2011		2012		2013		Thereafter
Ameren^(a)	$	344	$	967	$	802	$	562	$	178	$	635
UE		177		530		435		242		120		564
Genco		64		186		132		110		6		-
CILCORP/CILCO		27		104		105		94		47		71

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

Our commitments for the procurement of natural gas have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated natural gas purchase commitments at June 30, 2009:


	2009		2010		2011		2012		2013		Thereafter
Ameren^(a)	$	280	$	492	$	406	$	254	$	152	$	282
UE		45		77		59		45		35		31
CIPS		53		85		69		56		44		32
Genco		8		8		8		5		3		8
CILCORP/CILCO		58		120		117		71		47		190
IP		109		197		152		75		25		21

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

Our commitments for the procurement of nuclear fuel have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated nuclear fuel procurement commitments at June 30, 2009:


	2009		2010		2011		2012		2013		Thereafter
Ameren	$	35	$	60	$	18	$	56	$	58	$	431
UE		35		60		18		56		58		431

Our commitments for the purchase of electric capacity have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated electric capacity commitments at June 30, 2009:


	2009		2010		2011		2012		2013		Thereafter
Ameren	$	10	$	22	$	22	$	22	$	22	$	230
UE		10		22		22		22		22		230

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 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 contract. See Note 2 - Rate and Regulatory Matters for further information.

Ameren Illinois Utilities’ Purchased Power Agreements

The IPA procured capacity through a RFP process on behalf of the Ameren Illinois Utilities 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. As a result, the Ameren Illinois Utilities’ commitments for the purchase of electric capacity as of June 30, 2009, was $27 million, $26 million, $26 million and $1 million for 2009, 2010, 2011, and 2012, respectively.

Additionally, the IPA procured financial energy swaps through a RFP process on behalf of the Ameren Illinois Utilities 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. As a result, the Ameren Illinois Utilities’ commitments for the purchase of financial energy swaps as of June 30, 2009 was $112 million, $183 million, and $56 million for 2009, 2010, and 2011, respectively.

The IPA procured renewable energy credits through a RFP process on behalf of the Ameren Illinois Utilities which resulted in the Ameren Illinois Utilities contracting to purchase 720,000 credits at an average price of approximately $16 per credit, for the period June 1, 2009 through May 31, 2010. As a result, the Ameren Illinois Utilities’ commitments for the purchase of renewable energy credits as of June 30, 2009 were $6 million and $5 million for 2009 and 2010, respectively.

Illinois Electric Settlement Agreement

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


	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2009^(a)	$	14.4	$	2.1	$	1.0	$	2.8	$	5.9	$	2.6
2010^(a)		1.9		0.3		0.1		0.4		0.8		0.3
Total	$	16.3	$	2.4	$	1.1	$	3.2	$	6.7	$	2.9

(a)	Estimated.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations. The more significant matters are discussed below.

Clean Air Act

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. In May 2005, the EPA issued regulations with respect to SO₂ and NO_x 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, including Missouri and Illinois where our generating facilities are located, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO₂ emissions, annual NO_x emissions, and ozone season NO_x emissions. The cap-and-trade program for both annual and ozone season NO_x emissions went into effect on January 1, 2009. The SO₂ emissions cap-and-trade program is scheduled to take effect in 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 technology 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 expected to be available in draft form in 2010, and compliance is expected to be required in the 2013 to 2015 timeframe. We cannot predict at this time the estimated capital costs for compliance with such future environmental rules.

In July 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated 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 rule 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 early 2010 and a final version in 2011.

The state of Missouri has adopted state rules to implement the federal Clean Air Interstate Rule for regulating SO₂ and NO_x 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 NO_x emissions 30% and SO₂ emissions 75% by 2015. As a result of the Missouri rules, UE will manage 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 state rules to implement the federal Clean Air Mercury Rule. However, those state 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, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NO_x and SO₂ controls. This rule, when fully implemented, is expected to reduce mercury emissions 90%, NO_x emissions 50%, and SO₂ emissions 70% by 2015 in Illinois. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. Genco, AERG and EEI will also need to install additional pollution control equipment. Current plans include installing scrubbers for SO₂ reduction as well as optimizing operations of selective catalytic reduction (SCR) systems for NO_x reduction at certain coal-fired plants in Illinois.

In October 2008, Genco, CILCO (AERG) and EEI submitted a request for a variance from the MPS to the Illinois Pollution Control Board. In preparing this request, Genco, CILCO (AERG) and EEI worked with the Illinois EPA and agreed to control SO₂ and NO_x emissions to lower levels between 2010 and 2020 in order to make the variance proposal “environmentally neutral.” In January 2009, the Illinois Pollution Control Board denied the variance request on procedural grounds. Genco, CILCO (AERG) and EEI filed a motion for reconsideration in February 2009. With the Illinois EPA’s concurrence, they then sought to amend the MPS within a pending rulemaking pertaining to technical amendments of the underlying mercury regulations. In April 2009, the Illinois Pollution Control Board approved the revisions to the MPS within that rulemaking. After review and approval by the Illinois Joint Committee on Administrative Rules, this rule amendment became final in June 2009. As a result, Genco and AERG collectively are able to defer to subsequent years an estimated $300 million of environmental capital expenditures originally scheduled for 2009 through 2011.

In March 2008, the EPA finalized regulations that will lower the ambient standard for ozone. Illinois and Missouri have each submitted their recommendations to the EPA for designating nonattainment areas. A final action by the EPA to designate nonattainment areas is expected in March 2010. State implementation plans will need to be submitted in 2013 unless Illinois and Missouri 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 such state actions would have on our results of operations, financial position, or 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. Non-rate-regulated Generation has 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 NO_x emissions that result from burning fossil fuels. The Clean Air Act created marketable commodities called allowances under the Acid Rain Program, the NO_x Budget Trading Program, and the federal Clean Air Interstate Rule. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. NO_x allowances allocated under the NO_x Budget Trading Program can be used for the seasonal NO_x 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 NO_x limits through the use and purchase of allowances or through the application of pollution control technology, including low-NO_x 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 NO_x emission allowances held and the related SO₂ and NO_x emission allowance book values that were carried as intangible assets as of June 30, 2009.

UE, Genco, CILCO and EEI expect to use a substantial portion of the SO₂ and NO_x 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 require that SO₂ allowances of vintages 2010 through 2014 be surrendered at a ratio of two allowances for every ton of emission. SO₂ allowances with vintages of 2015 and beyond will be required to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, AERG, and EEI expect to install control technology designed to further reduce SO₂ emissions, as discussed above.

The Clean Air Interstate Rule has both an ozone season program and an annual program for regulating NO_x emissions, with separate allowances issued for each program. The Clean Air Interstate Rule ozone season program replaced the NO_x Budget Trading Program beginning in 2009. Both sets of allowances for the years 2009 through 2014 were issued by the Missouri Department of Natural Resources in December 2007. Allocations for UE’s Missouri generating facilities were 11,665 tons per ozone season and 26,842 tons annually. Allocations for Genco’s generating facility in Missouri were one ton for the ozone season and three tons annually. Both sets of allowances for the years 2009 through 2011 were issued by the Illinois EPA in April 2008. Allocations for UE’s, Genco’s, AERG’s, and EEI’s Illinois generating facilities were 90, 3,442, 1,368, and 1,758 tons per ozone season, respectively, and 93, 8,300, 3,418, and 4,564 tons annually, respectively.

Global Climate

On 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. However, the amount of free allowances provided declines over time and is ultimately phased out. The proposed legislation also contains, among other things, a federal renewable energy standard of 6% by 2012 and 20% by 2020, of which up to 25% of the goal 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. Leaders in the U.S. Senate have indicated they are developing climate change legislation that they hope to bring before the full Senate in the fall of 2009.

Potential impacts from proposed legislation could vary, depending upon proposed CO₂ emission limits, the timing of implementation of those limits, the method of allocating allowances, the degree to which offsets are allowed and available, and provisions for cost containment measures, such as a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO₂, a principal greenhouse gas. Ameren’s analysis shows that if The American Clean Energy and Security Act of 2009 were enacted into law in its current form, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region’s reliance on electricity generated by coal-fired power plants. 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 electric 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 initiatives regarding greenhouse gas emissions and global warming may also be subject to the activities 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. These 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.

With regard to greenhouse gas regulation under existing law, in April 2007, the U.S. Supreme Court issued a decision that the EPA has the authority to regulate CO₂ and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. This decision was a result of a Bush Administration ruling denying a waiver request by the state of California to implement such regulations. The Supreme Court sent the case back to the EPA to conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” In April 2009, the EPA issued a proposed determination finding that the combination of six greenhouse gases 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 of the greenhouse gases that are the subject of the proposed endangerment finding are produced by the combustion of fossil fuels by electric generating units. The comment period on this rulemaking is now closed. It is anticipated that the endangerment finding could enable states to regulate greenhouse gas emissions from automobiles. It could also set in motion the process of establishing emission limitations for power plants and other industrial sources of greenhouse gasses. This endangerment finding is expected to be final by the end of 2009. However, specific regulations governing power plants and other sources would be developed in subsequent rulemakings and may be preempted by federal legislative actions.

The EPA also proposed regulations in April 2009 that would require businesses, including fossil-fuel fired electric generators, to monitor and report their greenhouse gas emissions beginning January 2010. It is anticipated that these proposed regulations, if adopted, would supplement the existing emission monitoring and reporting requirements that are applicable to our facilities.

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. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI as well as other similarly situated electric power generators to close some coal-fired facilities. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.

The impact on us of future initiatives related to greenhouse gas emissions and global warming is unknown. Although compliance costs are unlikely in the near future, federal legislative, federal regulatory and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of regulation of greenhouse gas emissions will eventually be implemented. 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, or liquidity.

New Source Review

The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review (NSR) requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were performed.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. 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, Ameren received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to UE’s Labadie, Meramec, Rush Island, and Sioux facilities. The information request required UE to provide responses to specific EPA questions regarding certain projects and maintenance activities 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.

Resolution of these matters could have a material adverse impact on the future results of operations, financial position, or liquidity of Ameren, UE, Genco, AERG and EEI. 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 screens or other protective measures and to do extensive site-specific study and monitoring. There is also the possibility that the rules may lead to the installation of cooling towers on some of our generating facilities. On April 1, 2009, the U.S. Supreme Court ruled that the EPA can compare costs for existing power plants to use the best available technology to protect aquatic species against environmental benefits in enforcing 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 the studies on 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.

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 for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of June 30, 2009, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 15, CILCO 4, and IP 25 sites. All of these sites are in various stages of investigation, evaluation and remediation. Ameren currently anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with its former MGP sites from its Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costs are subject to annual review by the ICC. As of June 30, 2009, estimated obligations were: CIPS - $17 million to $28 million, CILCO - $1 million, IP - $97 million to $161 million. CIPS, CILCO and IP have liabilities of $17 million, $1 million, and $97 million, respectively, recorded to represent estimated minimum obligations, as no other amount within the range was a better estimate.

CIPS is also responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of June 30, 2009, CIPS estimated its 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 June 30, 2009, IP recorded a liability of $1 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 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 June 30, 2009, 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, most 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.

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.

Sauget Area 2 investigations overseen by the EPA are largely completed, and the results along with recommendations for appropriate remediation activities will be submitted to the EPA later this year. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of June 30, 2009, 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 July 2008, the EPA issued an administrative order to UE pertaining to a former coal tar distillery operated by Koppers Company or its predecessor and successor companies. UE is the current owner of the site but 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 to the scope of the site investigation, which will occur later this year. As of June 30, 2009, UE estimated its 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 December 2004, AERG submitted a comprehensive conceptual 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 a liability of $1 million at June 30, 2009, on their consolidated balance sheets 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 and 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, our operations or those of our predecessor companies involve the use, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine whether such practices will result in future environmental commitments or impact our results of operations, financial position, or liquidity.

Ash Ponds

There has been increased activity at both the state and federal level to examine the need for additional regulation of ash pond facilities and coal combustion byproducts (CCB) or wastes. The EPA is considering regulating CCBs under the hazardous waste regulations, which could impact future disposal and handling costs at our facilities. Ameren received and responded to an information collection request from the EPA in March 2009. The EPA sent the information collection request to numerous electric generators in the country. The EPA is considering requiring as part of its proposed regulations that coal-fired power plants engage in the mandatory closure of surface impoundments used for the management of CCB. It is anticipated that some form of additional regulation concerning the integrity of ash ponds and the handling and disposal of CCB or waste may be proposed by the fourth quarter 2009. Ameren’s CCB impoundments were not identified in EPA’s recent listing of 44 high hazard potential impoundments containing CCBs. In addition, the Illinois EPA has requested that UE, Genco, CILCO (AERG) and EEI establish groundwater monitoring plans for their active and inactive ash impoundments in Illinois. Genco is currently petitioning the Illinois Pollution Control Board to issue a site specific rule approving the closure of an ash pond at its Hutsonville power plant. At this time, we are unable to predict the outcome any such state and federal regulations might have on our results of operations, financial position, or 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 State of Missouri all issues associated with the December 2005 Taum Sauk incident. In December 2008, the Department of the Army, Corps of Engineers filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the U.S. District Court in Cape Girardeau, Missouri, claimed that Clearwater Lake in southeastern Missouri was damaged by sediment from the Taum Sauk breach. In April 2009, in response to the Corps of Engineers’ motion, the court dismissed the lawsuit without prejudice to the Corps of Engineers’ right to refile the lawsuit. UE cannot predict whether the lawsuit will be refiled.

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 $220 million. As of June 30, 2009, UE had paid $201 million, including costs resulting from the FERC-approved stipulation and consent agreement. UE accrued a $2 million liability while expensing $35 million for items not covered by insurance and recorded a $168 million receivable due from insurance companies under liability coverage. As of June 30, 2009, UE has received $95 million from insurance companies, which reduced the insurance receivable balance subject to liability coverage to $73 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 the Taum Sauk plant to be out of service through early 2010. The estimated cost to rebuild the upper reservoir is in the range of $480 million. As of June 30, 2009, 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 June 30, 2009, UE has received $208 million from insurance companies, which reduced the property insurance receivable balance as of June 30, 2009, to $212 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 does 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 $480 million cost of the design approved by FERC and being used by Ameren. Ameren disagrees with the position of these insurers and intends to defend its position. 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 $480 million. We are unable to predict the timing or outcome of this litigation, or its possible effect on UE’s results of operations, financial position or liquidity. Despite this litigation, discussions to settle claims under the property policy are ongoing with these insurance carriers and other insurance carriers not parties to the litigation.

Until the insurance review is completed and the litigation is resolved, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized. At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the facility, and the cost of replacement power (up to $8 million annually), will be recovered through insurance. Any amounts not recovered through insurance 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 June 30, 2009, the average number of parties was 73.

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 June 30, 2009:


Specifically Named as Defendant
Ameren	UE	CIPS	Genco	CILCO	IP	Total^(a)
2	32	32	-	14	41	75

(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 June 30, 2009, seven 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 June 30, 2009, Ameren, UE, CIPS, CILCO and IP had liabilities of $14 million, $5 million, $3 million, $1 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, 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 June 30, 2009, 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, or ¹/₁₀ of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available before 2020. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.

Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. It is assumed that the Callaway nuclear plant site will 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 to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2008, 2007 and 2006. 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. The 2008 study 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. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to a regulatory asset or regulatory liability, as appropriate.

NOTE 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 six months ended June 30, 2009 and 2008, is shown below for the Ameren Companies:


	Three Months						Six Months
	2009			2008			2009			2008
Ameren:^(a)
Net income	$	168		$	217		$	313		$	366
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $9, $(27), $53 and $(63), respectively		17			(48	)		98			(111	)
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $17, $(3), $43 and $(6), respectively		(31	)		5			(77	)		11
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, $3, $7 and $1, respectively		(5	)		(4	)		(5	)		(2	)
Total comprehensive income, net of taxes		149			170			300			264
Less: Net income attributable to noncontrolling interests, net of taxes		3			11			7			22
Total comprehensive income attributable to Ameren Corporation, net of taxes	$	146		$	159		$	293		$	242
UE:
Net income	$	84		$	124		$	106		$	188
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(4), $11 and $(11), respectively		-			(6	)		17			(17	)
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $1, $8 and $1, respectively		-			(2	)		(13	)		(1	)
Reclassification adjustment due to implementation of FAC, net of taxes of $-, $-, $18 and $-, respectively		-			-			(29	)		-
Total comprehensive income, net of taxes	$	84		$	116		$	81		$	170
CIPS:
Net income (loss)	$	1		$	(3	)	$	8		$	-
Total comprehensive income (loss), net of taxes	$	1		$	(3	)	$	8		$	-
Genco:
Net income	$	46		$	74		$	93		$	120
Unrealized net gain on derivative hedging instruments, net of taxes of $-, $4, $- and $-, respectively		-			6			-			-
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $4, $- and $4, respectively		-			(5	)		-			(5	)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $-, $-, $- and $(2), respectively		-			-			1			3
Total comprehensive income, net of taxes	$	46		$	75		$	94		$	118
CILCORP:
Net income (loss)	$	24		$	5		$	(408	)	$	25
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 $1, $2, $1 and $1, respectively		(1	)		3			(1	)		3
Total comprehensive income (loss), net of taxes	$	23		$	8		$	(409	)	$	27
Less: Net income attributable to noncontrolling interests, net of taxes		-			1			-			1
Total comprehensive income (loss) attributable to CILCORP Inc., net of taxes	$	23		$	7		$	(409	)	$	26
CILCO:
Net income	$	31		$	12		$	64		$	38
Adjustment to pension and benefit obligation, net of taxes of $1, $2, $1 and $2, respectively		1			4			1			4
Total comprehensive income, net of taxes	$	32		$	16		$	65		$	42
IP:
Net income (loss)	$	13		$	(10	)	$	27		$	(7	)
Total comprehensive income (loss), net of taxes	$	13		$	(10	)	$	27		$	(7	)

(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 our assumptions at December 31, 2008, estimated investment performance through June 30, 2009, and our pension funding policy, Ameren expects to make annual contributions of $90 million to $250 million in each of the next five years. These amounts are estimates. They 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 a contribution to its pension plan of $24 million in the second quarter of 2009. A pension contribution was not made in the first half of 2008. In July 2009, Ameren made a $23 million contribution to its pension plan. Additionally, Ameren made contributions to its postretirement benefit plans during the second quarter 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 six months ended June 30, 2009 and 2008:


	Pension Benefits^(a)												Postretirement Benefits^(a)
	Three Months						Six Months						Three Months						Six Months
	2009			2008			2009			2008			2009			2008			2009			2008
Service cost	$	17		$	14		$	34		$	29		$	5		$	4		$	10		$	9
Interest cost		46			46			93			93			16			16			33			35
Expected return on plan assets		(50	)		(53	)		(102	)		(106	)		(14	)		(15	)		(27	)		(29	)
Amortization of:
Transition obligation		-			-			-			-			1			1			1			1
Prior service cost (benefit)		2			3			4			6			(2	)		(2	)		(4	)		(4	)
Actuarial loss		5			-			12			1			1			-			4			4
Net periodic benefit cost	$	20		$	10		$	41		$	23		$	7		$	4		$	17		$	16

(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 six months ended June 30, 2009 and 2008:


	Pension Costs										Postretirement Costs
	Three Months					Six Months					Three Months					Six Months
	2009		2008			2009		2008			2009		2008			2009		2008
Ameren^(a)	$	20	$	10		$	41	$	23		$	7	$	4		$	17	$	16
UE		12		10			25		19			3		-			7		6
CIPS		1		1			4		3			-		1			1		2
Genco		2		2			3		3			1		-			1		1
CILCORP		2		(2	)		4		(4	)		1		(1	)		2		(2	)
CILCO		4		-			8		2			2		-			4		2
IP		-		(3	)		1		(2	)		3		4			6		7

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

NOTE 13 - SEGMENT INFORMATION

Ameren has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI (which in February 2008 was transferred to Resources Company through an internal reorganization). The Illinois Regulated segment for Ameren consists of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 - Summary of Significant Accounting Policies. The Non-rate-regulated Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities.

UE has one reportable segment: Missouri Regulated. The Missouri Regulated segment for UE includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s former 40% interest in EEI.

CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and CILCO consists of the regulated electric and gas transmission and distribution businesses of CILCO. The Non-rate-regulated Generation segment for CILCORP and CILCO consists of the generation business of AERG. For CILCORP and CILCO, Other comprises parent company activity and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.

The following tables present information about the reported revenues and specified items included in net income of Ameren, UE, CILCORP, and CILCO for the three and six months ended June 30, 2009 and 2008, and total assets as of June 30, 2009, and December 31, 2008.

Ameren


Three Months	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation		Other			Intersegment Eliminations			Consolidated
2009:
External revenues	$	745	$	618		$	315	$	6		$	-		$	1,684
Intersegment revenues		7		6			106		6			(125	)		-
Net income (loss) attributable to Ameren Corporation^(a)		82		15			75		(7	)		-			165
2008:
External revenues	$	760	$	717		$	314	$	(1	)	$	-		$	1,790
Intersegment revenues		11		12			96		4			(123	)		-
Net income (loss) attributable to Ameren Corporation^(a)		122		(14	)		98		-			-			206

Six Months
2009:
External revenues	$	1,393	$	1,546		$	651	$	10		$	-		$	3,600
Intersegment revenues		14		14			222		10			(260	)		-
Net income (loss) attributable to Ameren Corporation^(a)		103		40			168		(5	)		-			306
2008:
External revenues	$	1,475	$	1,763		$	632	$	1		$	-		$	3,871
Intersegment revenues		20		23			228		8			(279	)		-
Net income (loss) attributable to Ameren Corporation^(a)		174		2			176		(8	)		-			344
As of June 30, 2009:
Total assets	$	11,999	$	7,069		$	4,985	$	1,385		$	(2,248	)	$	23,190
As of December 31, 2008:
Total assets	$	11,524	$	7,079		$	4,622	$	1,227		$	(1,795	)	$	22,657

(a)	Represents net income (loss) available to common stockholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

UE


Three Months	Missouri Regulated		Other^(a)		UE
2009:
Revenues	$	752	$	-	$	752
Net income^(b)		82		-		82
2008:
Revenues	$	771	$	-	$	771
Net income^(b)		122		-		122

Six Months
2009:
Revenues	$	1,407	$	-	$	1,407
Net income^(b)		103		-		103
2008:
Revenues	$	1,495	$	-	$	1,495
Net income^(b)		174		11		185
As of June 30, 2009:
Total assets	$	11,999	$	-	$	11,999
As of December 31, 2008:
Total assets	$	11,524	$	-	$	11,524

(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			Non-rate-regulated Generation			CILCORP Other		Intersegment Eliminations			Consolidated CILCORP
2009:
External revenues	$	128		$	104		$	-	$	-		$	232
Intersegment revenues		-			-			-		-			-
Net income^(b)		1			23			-		-			24
2008:
External revenues	$	162		$	71		$	-	$	-		$	233
Intersegment revenues		2			(1	)		-		(1	)		-
Net income(loss)^(b)		(1	)		5			-		-			4

Six Months
2009:
External revenues	$	347		$	196		$	-	$	-		$	543
Intersegment revenues		-			-			-		-			-
Goodwill impairment^(a)		(117	)		(345	)		-		-			(462	)
Net loss^(b)		(109	)		(299	)		-		-			(408	)
2008:
External revenues	$	428		$	150		$	-	$	-		$	578
Intersegment revenues		2			-			-		(2	)		-
Net income^(b)		11			13			-		-			24
As of June 30, 2009:
Total assets	$	1,324		$	1,342		$	2	$	(203	)	$	2,465
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			Non-rate-regulated Generation			CILCO Other		Intersegment Eliminations			Consolidated CILCO
2009:
External revenues	$	128		$	104		$	-	$	-		$	232
Intersegment revenues		-			-			-		-			-
Net income^(a)		1			30			-		-			31
2008:
External revenues	$	162		$	71		$	-	$	-		$	233
Intersegment revenues		2			(1	)		-		(1	)		-
Net income (loss)^(a)		(1	)		12			-		-			11

Six Months
2009:
External revenues	$	347		$	196		$	-	$	-		$	543
Intersegment revenues		-			-			-		-			-
Net income^(a)		8			56			-		-			64
2008:
External revenues	$	428		$	150		$	-	$	-		$	578
Intersegment revenues		2			-			-		(2	)		-
Net income^(a)		11			26			-		-			37
As of June 30, 2009:
Total assets	$	1,251		$	1,108		$	-	$	-		$	2,359
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); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

NOTE 14 - GOODWILL IMPAIRMENT

We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Goodwill impairment testing is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, the second step is performed to measure the amount of impairment, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and liabilities in a manner similar to a purchase price allocation. The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss, equivalent to the difference, is recorded as a reduction of goodwill and a charge to operating expense.

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 Non-rate-regulated 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 twenty-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.

As a result of the interim impairment test as of March 31, 2009, CILCORP’s Illinois Regulated reporting unit and CILCORP’s Non-rate-regulated Generation reporting unit both failed step one 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 Non-rate-regulated 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 Non-rate-regulated Generation goodwill was impaired as of March 31, 2009. Based on the results of step two, CILCORP recorded a noncash impairment charge of $462 million, which represented all of the goodwill assigned to CILCORP’s Non-rate-regulated Generation reporting unit of $345 million and $117 million assigned to CILCORP’s Illinois Regulated reporting unit. The step two test indicated that the implied fair value of goodwill relating to CILCORP’s Illinois Regulated reporting unit was $80 million.

The goodwill impairment recorded at CILCORP was not reflected at the consolidated Ameren level because of the aggregation of reporting units. Ameren’s reporting units and IP’s reporting unit did not require a second step assessment; 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 Non-rate-regulated 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 Non-rate-regulated 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 future of 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 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 second 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 June 30, 2009:

Ameren


	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation			Total^(a)
Balance at December 31, 2008	$	-	$	411		$	420		$	831
Impairment loss recorded in first quarter		-		-			-			-
Balance at June 30, 2009	$	-	$	411		$	420		$	831
(a) Includes amounts for Ameren registrants and nonregistrant subsidiaries. CILCORP
	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation			Total
Balance at December 31, 2008	$	-	$	197		$	345		$	542
Impairment loss recorded in first quarter		-		(117	)		(345	)		(462	)
Balance at June 30, 2009	$	-	$	80		$	-		$	80
IP
	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation			Total
Balance at December 31, 2008	$	-	$	214		$	-		$	214
Impairment loss recorded in first quarter		-		-			-			-
Balance at June 30, 2009	$	-	$	214		$	-		$	214