The financial statements of Ameren, Genco and CILCO were prepared on a consolidated basis. As of September 30, 2010, UE, CIPS and IP had 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.

Earnings Per Share

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

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

The following table summarizes the changes in nonvested shares for the nine months ended September 30, 2010, under the Long-term Incentive Plan of 1998 (1998 Plan), as amended, and the 2006 Omnibus Incentive Compensation Plan (2006 Plan):

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

Ameren recorded compensation expense of $4 million for each of the three months ended September 30, 2010, and 2009, and a related tax benefit of $1 million and $2 million for the three months ended September 30, 2010, and 2009, respectively. Ameren recorded compensation expense of $11 million and $12 million for each of the nine-month periods ended September 30, 2010 and 2009, respectively, and a related tax benefit of $4 million and $5 million for the nine-month periods ended September 30, 2010 and 2009, respectively. As of September 30, 2010, total compensation expense of $16 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 25 months.

Accounting Changes and Other Matters

The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact the Ameren Companies.

Variable-Interest Entities

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

Disclosures about Fair Value Measurements

In January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance requires disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also requires information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. Further, the FASB clarified guidance regarding the level of disaggregation, inputs, and valuation techniques. This guidance was effective for us as of January 1, 2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which will be effective for us as of January 1, 2011. The adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provides enhanced disclosure requirements only. See Note 7 - Fair Value Measurements for additional information.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Ameren recorded goodwill related to its acquisition of IP and an additional 20% EEI ownership interest acquired in 2004, as well as its acquisition of CILCORP and Medina Valley in 2003. IP recorded goodwill related to its acquisition by Ameren in 2004. Genco recorded goodwill related to the additional 20% EEI ownership interest acquired in 2004.

We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Ameren and Genco conducted an interim goodwill impairment test in the third quarter of 2010. That test resulted in the recognition of a noncash goodwill impairment charge at Ameren and Genco of $420 million and $65 million, respectively. See Note 15 - Goodwill and Other Asset Impairments for additional information.

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 and CILCO's intangible assets consisted of emission allowances at September 30, 2010. During the third quarter of 2010, Ameren and Genco recorded a noncash pretax impairment charge relating to SO₂ emission allowances of $68 million and $41 million, respectively. UE recorded a $23 million impairment of its SO₂ allowances by reducing a previously established regulatory liability related to the SO₂ allowances. Therefore, the UE SO₂ allowance impairment had no impact to earnings. See Note 15 - Goodwill and Other Asset Impairments for additional information about the asset impairment charges recorded during the third quarter of 2010. See Note 9 - Commitments and Contingencies for additional information on emission allowances.

The following table presents the SO

The following table presents amortization expense based on usage of emission allowances, net of gains and losses from emission allowance sales, for Ameren, UE, Genco and AERG during the three and nine months ended September 30, 2010, and 2009. The table below does not include the intangible asset impairment charges referenced above.

Excise Taxes

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

Uncertain Tax Positions

The amount of unrecognized tax benefits as of September 30, 2010, was $224 million, $154 million, $16 million, $13 million, $19 million, and $24 million for Ameren, UE, CIPS, Genco, CILCO and IP, respectively. The amount of unrecognized tax benefits as of September 30, 2010, that would impact the effective tax rate, if recognized, was $2 million, $2 million, less than $1 million, $1 million, $1 million, and less than $1 million for Ameren, UE, CIPS, Genco, CILCO and IP, respectively.

Ameren's federal income tax returns for the years 2005 through 2008 are before the Appeals Office of the Internal Revenue Service. Ameren's federal tax return is currently under U.S. federal income tax examination for the year 2009.

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 a year after formal notification to the states. Ameren's 2007 and 2008 state of Illinois income tax returns are currently under examination by the Illinois Department of Revenue.

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

Genco Asset Sale

In June 2010, Genco completed a sale of 25% of its Columbia CT facility to the city of Columbia, Missouri. Genco received cash proceeds of $18 million from the sale. The city of Columbia also holds two options to purchase additional ownership interests in the facility under two existing power purchase agreements. Columbia can exercise one option, as amended, for an additional 25% of the facility at the end of 2011 for a purchase price of $14.9 million, at the end of 2014 for a purchase price of $9.5 million, or at the end of 2020 for a purchase price of $4 million. The other option can be exercised for another 25% of the facility at the end of 2013 for a purchase price of $15.5 million, at the end of 2017 for a purchase price of $9.5 million, or at the end of 2023 for a purchase price of $4 million. On an annual basis, the city of Columbia purchases a total of 72 megawatts of capacity and energy generated by the facility under the two existing purchase power agreements. If the city of Columbia exercises one of the purchase options described above, the purchase power agreement associated with that option would be terminated.

Variable-interest Entities

According to the applicable authoritative accounting guidance, an entity is considered a VIE if it does not have sufficient equity to finance its activities without assistance from variable-interest holders, or if its equity investors lack any of the following characteristics of a controlling financial interest: control through voting rights, the obligation to absorb expected losses, or the right to receive expected residual returns. The primary beneficiary of a VIE is the entity that (1) has the power to direct matters that most significantly affect the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE if they are its primary beneficiary. At September 30, 2010, and December 31, 2009, Ameren had investments in multiple affordable housing and low-income real estate development partnerships as well as an investment in a commercial real estate development partnership of $49 million and $64 million in the aggregate, respectively. Ameren has a variable interest in these investments as a limited partner. With the exception of the commercial real estate development partnership, Ameren does not own a majority interest in any partnership. Ameren receives the benefits and accepts the risks consistent with its limited partner interest in each partnership. Ameren is not the primary beneficiary of these investments because Ameren does not have the power to direct matters that most significantly impact the activities of the VIE. These investments are classified as Other Assets on Ameren's consolidated balance sheet. The maximum exposure to loss as a result of these variable interests is limited to the investments in these partnerships.

See Note 8 - Related Party Transactions for information about AIC's (previously IP's) variable interest in AITC.

Noncontrolling Interest

Ameren's noncontrolling interests comprise the 20% of EEI not owned by Ameren and the Ameren subsidiaries' outstanding preferred stock not subject to mandatory redemption not owned by Ameren. These noncontrolling interests are classified as a component of equity separate from Ameren's equity in its consolidated balance sheet. Genco's noncontrolling interest comprises the 20% of EEI not owned by Genco. This noncontrolling interest is classified as a component of equity separate from Genco's equity in its consolidated balance sheet.

A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren and Genco for the three and nine months ended September 30, 2010, is shown below:

On May 28, 2010, the MoPSC issued an order approving an increase for UE in annual revenues for electric service of approximately $230 million, including $119 million to cover higher fuel costs and lower revenue from sales outside UE's system. The revenue increase was based on a 10.1% return on equity, a capital structure composed of 51.3% common equity, and a rate base of approximately $6 billion. The rate changes became effective on June 21, 2010. The MoPSC order also included the following provisions, among other things:

In addition, the order implemented several stipulations previously agreed to by UE, the MoPSC staff, and other parties to the proceedings. One stipulation included UE's agreement to withdraw its request for an environmental cost recovery mechanism in exchange for the ability to continue recording an allowance for funds used during construction and to defer depreciation costs for pollution control equipment at the Sioux plant until the earlier of January 2012 or when the cost of that equipment is placed in customer rates. This treatment will allow UE to defer these costs as a regulatory asset, which will be amortized upon their inclusion in rates. UE will have the ability to request the implementation of an environmental cost recovery mechanism in a future rate case proceeding. Another approved stipulation allows UE to recover its portion of Ameren's September 2009 common stock issuance costs. The order also implemented the parties' agreement to prospectively include the margins on certain wholesale contracts in UE's FAC in exchange for an increase in the jurisdictional cost allocation to retail customers. In addition, the order implements the parties' agreement to a mechanism that will prospectively address the significant lost revenues UE can incur due to future operational issues at Noranda's smelter plant. This mechanism will permit UE, when a loss of service occurs at the Noranda plant, to sell the power not taken by Noranda and use the proceeds of those sales to offset the revenues lost from Noranda. UE would be allowed to keep the amount of revenues necessary to compensate UE for significant Noranda usage reductions but any excess revenues above the level necessary to compensate UE would be refunded to retail customers through the FAC. Approved stipulations also include the continued use of the regulatory tracking mechanism for pension and postretirement benefit costs and the discontinuation of the SO₂ emission allowance sales tracker among other things. The approved stipulations also resulted in the recognition of new regulatory assets. The following table reflects the pretax earnings impact realized in the second quarter of 2010 resulting from the recognition of these new regulatory assets as well as their balance at June 30, 2010, when the rate order was adopted. The amortization period on each of these new regulatory assets began on July 1, 2010.

In June 2010, UE and other parties to the rate case filed for rehearing of certain aspects of the MoPSC order. The MoPSC denied all rate order rehearing requests filed by UE and other parties. UE appealed the return on equity included in the MoPSC decision to the Circuit Court of Cole County, Missouri. A group of industrial customers also appealed certain aspects of the MoPSC decision to the Circuit Court of Cole County, Missouri. A decision is expected to be issued by the Circuit Court in 2011.

Four of the industrial customers who appealed the MoPSC decision filed a request for a stay with the Circuit Court of Cole County, Missouri. The stay, if granted, would allow these industrial customers to prospectively deposit the contested portion of their monthly billing payments into the Cole County Circuit Court's registry. Noranda's (one of the four industrial customers) request for a stay is a continuation of their granted stay of the MoPSC's 2009 electric rate order as well as the electric rate increase granted by the MoPSC's 2010 electric rate order as it applies specifically to Noranda's electric service account. The three other industrial customers' stay request includes rate increases granted by both the MoPSC's 2009 and 2010 electric rate orders as they specifically apply to each of their electric service accounts. UE estimates the annualized contested portion of these four industrial customers' billing payments that would be deposited into the Cole County Circuit Court's registry if the stay request is granted could range from approximately $3 million to $12 million. UE expects the stay request decision by the Cole County Circuit Court to be issued in late 2010 or early 2011.

Pending Electric Rate Case

On September 3, 2010, UE filed a request with the MoPSC to increase its annual revenues for electric service by approximately $263 million. This increase request was based primarily on energy infrastructure investments, costs incurred to implement environmental controls and other costs incurred to continue system-wide reliability improvements for customers. Approximately $110 million of the request relates to recovery of the cost of installing and operating two scrubbers at UE's Sioux plant. Also included in this requested increase is a $70 million anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 28, 2010 electric rate order. Absent initiation of this general rate proceeding, 95% of this amount would have been reflected in rate adjustments implemented under UE's FAC. Capital additions relating to enhancements at the rebuilt Taum Sauk facility were also included in the increase request. The electric rate increase request is based on a 10.9% return on equity, a capital structure composed of 50.9% common equity, an aggregate electric rate base of $6.8 billion, and a test year ended March 31, 2010, with certain pro-forma adjustments through the anticipated true-up date of February 28, 2011.

As a part of its filing, UE also requested that the MoPSC approve the implementation of an infrastructure investment tracking mechanism as well as enhanced energy efficiency cost recovery. The infrastructure investment tracking mechanism would allow UE to continue recording an allowance for funds used during construction and to defer depreciation expenses for certain projects beyond their in-service dates and prior to those projects being reflected in rates, with the amounts deferred being recoverable through future rate case proceedings. The enhanced energy efficiency cost recovery provision would permit UE to recover its investments in energy efficiency programs over three years instead of six years and to offset the under-recovery of fixed costs resulting from implementation of energy efficiency measures. UE also requested continued use of its existing FAC, vegetation management and infrastructure cost tracker, and the regulatory tracking mechanism for pension and postretirement benefit costs the MoPSC previously authorized in earlier electric rate orders.

A decision by the MoPSC in this proceeding is required by the end of August 2011. UE cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, or whether any rate increase that may eventually be approved will be sufficient for UE to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

Pending Natural Gas Delivery Service Rate Case

In June 2010, UE filed a request with the MoPSC to increase its annual revenues for natural gas delivery service by approximately $12 million. The natural gas delivery service rate increase request was based on a 10.5% return on equity, a capital structure composed of 51.3% common equity, a rate base of $245 million, and a test year ended December 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of September 30, 2010.

A decision by the MoPSC in this proceeding is required by the end of May 2011. UE cannot predict the level of any natural gas delivery service rate change the MoPSC may approve, when any rate change may go into effect, 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.

FAC Prudence Review

Missouri law requires the MoPSC to complete prudence reviews of UE's FAC at least every eighteen months. On August 31, 2010, the MoPSC staff completed a prudence review of the FAC from March 1, 2009, to September 30, 2009. The MoPSC staff contends that UE should have included in the FAC calculation all costs and revenues associated with certain contract sales that were made due to the loss of Noranda load caused by a severe ice storm in January 2009. UE disagrees with the MoPSC staff's classification of these transactions and their inclusion in the FAC calculation. UE recognized margin associated with these contracts of $17 million during the period reviewed by the MoPSC and an additional $25 million of margin subsequent to September 30, 2009. If the MoPSC agrees with the staff position, and if the MoPSC's order were upheld by the courts on appeal, UE would be required to pass through to customers the $42 million in margin associated with these contracts. The MoPSC is expected to issue an order with respect to this prudence review in 2011. UE cannot predict the outcome of this MoPSC prudence review.

Renewable Energy Portfolio Requirement

A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio requirement must be derived from solar energy. Compliance with the renewable energy portfolio requirement can be achieved through the procurement of renewable energy or renewable energy credits. UE expects that any related costs or investments would ultimately be recovered in rates.

In July 2010, the MoPSC issued final rules implementing the state's renewable energy portfolio requirement. In addition to other concerns, UE believes the MoPSC rules are in conflict with statutory authority created by the passed ballot initiative and unnecessarily increase costs to UE's customers. Specifically, UE opposes the portion of MoPSC rules that require renewable generating facilities to either be located in Missouri or generate electricity that is delivered to Missouri. These rules limit UE's ability to comply with the solar requirement through the purchase of renewable energy credits. These contested portions of the MoPSC rules will not become effective until approved by the Missouri legislature in early 2011. Additionally, in August 2010, UE filed an appeal with the Circuit Court of Cole County, Missouri. UE is appealing the portion of the MoPSC rules creating geographical restrictions as well as the calculation of the 1% limit on customer rates. UE also filed a stay request with the Circuit Court of Cole County. If the stay request is granted, UE would not have to comply with the contested portion of the new rules until the decision on the appeal is finalized. UE cannot predict when the court will issue a ruling or the ultimate outcome of its appeal, stay request, or the legislative approval process.  

Illinois

Electric and Natural Gas Delivery Service Rate Cases

In April 2010, the ICC issued a consolidated rate order for CIPS, CILCO and IP, which was amended in May 2010, that approved a net increase in annual revenues for electric delivery service of $35 million in the aggregate and a net decrease in annual revenues for natural gas delivery service of $20 million in the aggregate. The order was based on a 9.9% to 10.3% return on equity with respect to electric delivery service and a 9.2% to 9.4% return on equity with respect to natural gas delivery service. The rate changes became effective in May 2010.

The ICC order confirmed the previously approved 80% allocation of fixed non-volumetric residential and commercial natural gas customer charges, and approved a higher percentage of recovery of fixed non-volumetric electric residential and commercial customer charges. The percentage of costs to be recovered through fixed non-volumetric electric residential and commercial customer and meter charges increased from 27% to 40%.

The ICC order also extended the amortization period of the IP integration-related regulatory asset, which was previously set to be fully amortized by December 2010. The new order extended the amortization for two years beginning in May 2010. This change will result in a pretax reduction to amortization expense of $7 million in 2010. The ICC order also created a $3 million regulatory asset, in the aggregate, for CIPS', CILCO's and IP's costs incurred in 2009 for the voluntary and involuntary separation programs. These costs are being amortized over three years beginning in May 2010.

In response to the ICC consolidated rate order, CIPS, CILCO and IP took immediate action to mitigate the financial pressures created by the rate order. CIPS, CILCO and IP each took the following actions:

On June 14, 2010, the ICC agreed to rehear three issues raised by CIPS, CILCO and IP and one issue raised by intervenors. On November 4, 2010, the ICC issued an order on the rehearing issues, which approved an increase in annual revenues of $25 million, in addition to the $15 million authorized in the ICC's May 2010 amended rate order. The November 2010 ICC rehearing order included a $4 million rate design revenue reduction, which was requested by intervenors. The overall annual delivery service revenue increase as a result of these orders is $40 million. The rate changes relating to the rehearing issues addressed in the November 2010 ICC order will become effective in early November 2010.

Federal

Seams Elimination Cost Adjustment

Pursuant to a series of FERC orders, FERC put Seams Elimination Cost Adjustment (SECA) charges into effect on December 1, 2004, subject to refund and hearing procedures. The SECA charges were a transition mechanism in place from December 1, 2004, to March 31, 2006, to compensate transmission owners in MISO and PJM for revenues lost when FERC eliminated the regional through-and-out rates previously applicable to transactions crossing the border between MISO and PJM. The SECA charge was a nonbypassable surcharge payable by load-serving entities in proportion to the benefit they realized from the elimination of the regional through-and-out rates as of December 1, 2004.

The MISO transmission owners (including UE, CIPS, CILCO and IP) and the PJM transmission owners separately filed their proposed SECA charges in November 2004, as compliance filings pursuant to FERC order. During the transition period of December 1, 2004, to March 31, 2006, Ameren, UE, CIPS and IP received net revenues from the SECA charges of $10 million, $3 million, $1 million, and $6 million, respectively. CILCO's net SECA charges were less than $1 million.

A FERC administrative law judge issued an initial decision in August 2006, recommending that FERC reject both of the SECA compliance filings (the filing for SECA charges made by the transmission owners in the MISO and the filing for SECA charges made by the transmission owners in PJM). Numerous parties filed briefs on exceptions and briefs opposing exceptions with respect to the initial decision.

Both before and after the initial decision, various parties (including UE, CIPS, CILCO and IP as part of the group of MISO transmission owners) had filed numerous bilateral or multiparty settlements. FERC has continued to approve settlements and to date, has not rejected any settlement proposals. The adjustments to Ameren's SECA revenues associated with these settlements have already been recognized.

In May 2010, FERC issued its Order on Initial Decision, reversing in part and upholding in part the initial decision. With minor exceptions, FERC upheld the analytical approach taken by the MISO transmission owners, including the calculation of lost revenues for Ameren and the other MISO transmission owners. FERC ordered the MISO transmission owners and the PJM transmission owners to make compliance filings to reflect certain limited adjustments to the SECA lost revenue calculations that FERC found appropriate and necessary. MISO and PJM transmission owners made separate compliance filings in August 2010. Based on these compliance filings, the May 2010 FERC Order and the numerous settlements previously approved by FERC, Ameren does not believe the outcome of the proceedings will have a material effect on UE's or AIC's results of operations, financial position, or liquidity.

MISO and PJM Dispute Resolution

During 2009, MISO and PJM discovered an error in the calculation quantifying certain transactions between the RTOs. The error, which originated in April 2005, at the initiation of the MISO Energy and Operating Reserves Market, was corrected prospectively in June 2009. Since discovering the error, MISO and PJM worked jointly to estimate its financial impact on the respective markets. MISO and PJM are in agreement about the methodology used to recalculate the market flows occurring from June 2007 to June 2009 for the resettlement due from PJM to MISO estimated at $65 million. MISO and PJM are not in agreement about the methodology used to recalculate the market flows occurring from April 2005 to May 2007, nor are they in agreement about the resettlement amount for that period of time. Attempts to resolve this dispute through FERC's dispute resolution and settlement process were not successful. In early March 2010, MISO filed complaints with FERC against PJM seeking a $130 million resettlement, plus interest, of the contested transactions. In April 2010, PJM filed a complaint with FERC against MISO alleging MISO violated the market-to-market coordination process for certain transactions between the two RTOs. PJM's complaint states it is entitled to at least $25 million from MISO for amounts improperly paid as a result of MISO's alleged process violation. The Ameren Companies may receive or pay a to-be-determined portion of any resettlement amount due between the RTOs. No prospective refund or payment has been recorded related to this matter. Until FERC issues an order or a settlement has been reached, we cannot predict the ultimate impact of these proceedings on Ameren's, UE's, AIC's and Genco's results of operations, financial position, or liquidity.

Pumped-storage Hydroelectric Facility Relicensing

In June 2008, UE filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The existing FERC license expired on June 30, 2010. On July 2, 2010, UE received a license extension that allows Taum Sauk to continue operations until FERC issues a new license. UE is currently conducting studies using current field data as required by the relicensing process. The studies are expected to be completed and submitted to FERC in 2011. A FERC order is expected after a review of the studies is completed; however, we cannot predict the ultimate outcome of the order.

Commercial Paper Borrowings

The 2010 Credit Agreements are used to support Ameren's and UE's commercial paper programs. Ameren may at its discretion use any of the 2010 Credit Agreements to support its commercial paper program, subject to its applicable sublimit. At September 30, 2010, Ameren had $125 million of commercial paper outstanding, which reduced the available amounts under these facilities. During the three months ended September 30, 2010, Ameren had average daily commercial paper borrowings outstanding of $94 million with a weighted-average interest rate of 0.96%. The peak short-term borrowings and peak interest rate during the three months ended September 30, 2010, were $216 million and 1.10%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants.

The 2010 Credit Agreements contain conditions to borrowings and issuances of letters of credit similar to those contained in the 2009 Multiyear Credit Agreement and the 2009 Illinois Credit Agreement, 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. See Note 4 - Credit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions in the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. In addition, solely as it relates to borrowings under the 2010 Illinois Credit Agreement, it is a condition precedent to any such borrowing that, at the time of and after giving effect to such borrowing, the borrower will not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 2010 Credit Agreements also contain nonfinancial covenants similar to those contained in the 2009 Multiyear Credit Agreement and the 2009 Illinois Credit Agreement, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities. The 2010 Illinois Credit Agreement, however, expressly permitted the consummation of the AIC Merger and the transfer of AERG to Ameren.

The 2010 Credit Agreements require each of Ameren, UE, AIC and Genco to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of September 30, 2010, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 50%, 47%, 54%, 40%, 35% and 44%, for Ameren, UE, Genco, CIPS, CILCO and IP, respectively. These ratios include the effect of the goodwill and other asset impairment charges for Ameren and Genco recorded in the third quarter of 2010. See Note 15 - Goodwill and Other Asset Impairments for additional information. In addition, under the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, as applicable. Ameren's ratio as of September 30, 2010 was 5.1 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

The 2010 Credit Agreements contain default provisions that are similar to those contained in the 2009 Multiyear Credit Agreement and the 2009 Illinois Credit Agreement, as applicable. However, UE and Genco are no longer borrowers within the same credit agreement, as they were under the 2009 Multiyear Credit Agreement, and a default by one such subsidiary borrower will not trigger a default by the other under the applicable 2010 Credit Agreements. Defaults under the 2010 Credit Agreements apply separately to each borrower; provided, however, that a default by UE, AIC or Genco under any of the 2010 Credit Agreements will also constitute a default by Ameren under such agreement. Defaults include a cross default with respect to a borrower under the applicable 2010 Credit Agreements to the occurrence of a default by such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $25 million in the aggregate. Any default of Ameren under any 2010 Credit Agreement that exists solely as a result of a default by UE, AIC or Genco thereunder will not constitute a default under any other 2010 Credit Agreement while Ameren is otherwise in compliance with all of its obligations under such other 2010 Credit Agreement. Further, a default at the Ameren level under any 2010 Credit Agreement does not trigger a default by UE, AIC or Genco under such agreement.

The $20 Million Facility requires Ameren to maintain consolidated indebtedness of not more than 65% of its consolidated capitalization pursuant to a defined calculation set forth in the agreement. As of September 30, 2010, Ameren's consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility was 50%. Failure by Ameren to satisfy this covenant would constitute an immediate default under the $20 Million Facility but, given the size of the facility, would not trigger an Ameren default under any of the 2010 Credit Agreements or Ameren's indenture.

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

Money Pools

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

Utility

Through the utility money pool, the pool participants may access the committed credit facilities. See discussion above for amounts available under the facilities at September 30, 2010. UE and AIC 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 2010 Credit Agreements.

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 2010 Credit Agreements through a non-state-regulated subsidiary money pool agreement. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and nine months ended September 30, 2010, was 0.34% and 0.65%, respectively (2009 - 2.2% and 1.5%, 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 nine months ended September 30, 2010.

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 $2 billion of free and unrestricted retained earnings at September 30, 2010.

AIC's articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus.

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

Off-Balance-Sheet Arrangements

At September 30, 2010, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

NOTE 5 - OTHER INCOME AND EXPENSES

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