AMERENENERGY GENERATING CO - 10-Q Quarterly Report

In July 2004, the FERC issued an order approving Ameren’s acquisition of IP and Dynegy’s interest in EEI. The principal conditions of the FERC’s approval were that IP join the Midwest ISO prior to closing the transaction and that 125 megawatts of EEI’s power be sold to a non-affiliate of Ameren. The Missouri Office of Public Counsel and a group of electric industrial customers of UE, both intervenors in the FERC proceeding, have requested the FERC to reconsider its order deferring to the MoPSC on the question of whether UE should be required to preserve its current entitlement to the output of EEI’s Joppa power plant facility. These appeals, which are pending, did not impede the completion of the acquisition on September 30, 2004. IP joined the Midwest ISO on September 30, 2004.

On September 22, 2004, the ICC issued an order approving Ameren’s acquisition of IP. The order contains several important provisions including the following:

The order requires IP to submit quarterly reports in 2005 and 2006 on certain milestones regarding IP’s progress in achieving an estimated $33 million in annual synergies by the beginning of 2007, and provides for adjustments in IP’s next electric and gas rate cases if IP fails to achieve those milestones.
After 2006, IP will recover over four years through rates $67 million in reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP.
The order approves 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 will be recovered by IP from a $20 million trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy; 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.


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The order provides IP with the ability to declare and pay $80 million of dividends on its common stock in 2005 and $160 million of dividends on its common stock cumulatively through 2006, provided IP has achieved an investment grade credit rating from S&P or Moody’s. If, however, IP’s principal amount of mortgage bonds 11.50% Series due 2010 are not eliminated by December 31, 2006, IP may not thereafter declare or pay common dividends without seeking authority from the ICC.
Ameren commits to cause an aggregate of at least $750 million principal amount of IP’s long-term debt, including IP’s principal amount of mortgage bonds 11.50% Series due 2010, to be redeemed, repurchased or retired on or before December 31, 2006. Ameren will contribute a substantial amount of common equity into IP for this purpose and will cause IP’s common equity to total capitalization ratio to range between 50% to 60% by December 31, 2006.
IP will establish a dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities consistent with achieving and maintaining a common equity to total capitalization ratio between 50% to 60%.
Ameren will commit IP to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership.
IP employees, retirees and those retirees’ surviving dependents will remain in their current IP benefit plans or be moved into appropriate Ameren benefit plans, and IP will honor all existing labor agreements.

On September 27, 2004, the SEC issued an order under the PUHCA approving Ameren’s acquisition of IP without material conditions.

Intercompany Transfer of Electric Generating Facilities and Illinois Service Territory

As a part of the settlement of the Missouri electric rate case in 2002, UE committed to making certain infrastructure investments from January 1, 2002 through June 30, 2006 of $2.25 billion to $2.75 billion, including the addition of 700 megawatts of generation capacity. The new capacity requirement is expected to be satisfied by the addition in 2002 of 240 megawatts and the proposed transfer from Genco to UE, at net book value (approximately $240 million), of approximately 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois. In July 2004, the FERC approved the generation transfer, but the transfer remains subject to receipt of SEC approval under the PUHCA. Approval by the ICC is not required contingent upon prior approval and execution of UE’s transfer of its Illinois public utility operations to CI PS as discussed below. Approval by the MoPSC is not required in order for this transfer of generating capacity to occur. However, the MoPSC has jurisdiction over UE’s ability to recover the cost of the transferred generating facilities from its electric customers in its rates. As part of the settlement of the Missouri electric rate case in 2002, UE is subject to a rate moratorium providing for no changes in its electric rates before June 30, 2006, subject to certain statutory and other exceptions.

In May 2003, UE announced its plan to limit its public utility operations to the state of Missouri and to discontinue operating as a public utility subject to ICC regulation. UE is seeking to accomplish this by transferring its Illinois-based electric and natural gas businesses, including its Illinois-based distribution assets and certain of its transmission assets, at net book value, to CIPS. In 2003, UE’s Illinois electric and gas service territory generated revenues of $155 million and had a net book property and plant value of approximately $125 million at September 30, 2004. UE's electric generating facilities and a certain minor amount of its electric transmission facilities in Illinois would not be part of the transfer. UE proposes to transfer approximately one-half of the assets directly to CIPS in co nsideration for a CIPS subordinated promissory note, and approximately one-half of the assets by means of a dividend in kind to Ameren followed by a capital contribution by Ameren to CIPS. The transfer was approved by the FERC in December 2003. In September 2004, the ICC authorized the transfer of UE’s Illinois-based natural gas utility business. The ICC had previously authorized the transfer of UE’s Illinois-based electric utility business to CIPS in 2000. As discussed below, the MoPSC, by an order issued in October 2004, approved the transfer subject to various conditions. The transfer of UE's Illinois-based utility businesses will also require the approval of the SEC under the provisions of the PUHCA. A filing seeking approval of both the transfer of UE’s Illinois-based utility businesses and Genco’s CTs was made with the SEC in October 2003. If completed, the transfers will be accounted for at book value with no gain or loss recognition, which is appropriate treatment for transactions of this type by two entities under common control.

After the completion of hearings and submission of briefs, on October 6, 2004, the MoPSC issued an order, effective October 16, 2004, approving UE's transfer of its Illinois-based utility businesses to CIPS subject to various


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conditions. The principal conditions included in the order would prevent UE from recovering in rates costs related to certain pre-transfer generation-related liabilities and require amendments to the joint generation dispatch agreement among UE, Genco and CIPS. On October 15, 2004, UE filed an application for rehearing requesting the MoPSC to rehear or in the alternative, clarify its order. See Note 8 - Related Party Transactions for a discussion of an amendment to the joint dispatch agreement, which was proposed to address concerns raised before the MoPSC in this proceeding. This Note also discusses the conditions with respect to the joint dispatch agreement imposed by the MoPSC in its October 6, 2004, order.

We are unable to predict the ultimate outcome of these regulatory proceedings or the timing of the final decisions of the various agencies.

Federal - Electric Transmission

Regional Transmission Organization

In December 1999, the FERC issued Order 2000 requiring all utilities subject to FERC jurisdiction to state their intentions for joining a RTO. The MoPSC issued an order in early 2004 authorizing UE to participate in the Midwest ISO for a five year period, with participation after that period subject to further approvals by the MoPSC. Subsequently, the FERC issued a final order allowing UE’s and CIPS’ participation in the Midwest ISO. Under these orders, the MoPSC continues to set the transmission component of UE’s rates to serve its bundled retail load. CILCO is already a member of the Midwest ISO and transferred functional control of its transmission system to the Midwest ISO prior to our acquisition of CILCO. Genco does not own transmission assets, but pays the Midwest ISO to use the transmission system to transmit power from the Genco generating plants.

On May 1, 2004, functional control, but not ownership, of the UE and CIPS transmission systems was transferred to the Midwest ISO through GridAmerica LLC. On September 30, 2004, prior to the completion of Ameren’s acquisition of IP as required by the FERC’s order approving the acquisition, IP transferred functional control, but not ownership, of its transmission system to the Midwest ISO. The transfer had no accounting impact to UE, CIPS and IP because they continue to own the transmission system assets. The participation by UE, CIPS and IP in the Midwest ISO is expected to increase annual costs by $10 million to $25 million in the aggregate and could result in a decrease in annual revenues of between $5 million and $15 million in the aggregate based on the Midwest ISO’s tariff structure. However, a ccess to the Midwest ISO market could provide UE, Genco and CILCO an opportunity to sell more, and higher margin, excess power. UE, CIPS, CILCO and IP may also be required to expand their transmission systems according to decisions made by the Midwest ISO rather than their internal planning process.

As a part of the transfer of functional control of UE’s and CIPS’ transmission systems to the Midwest ISO, Ameren received $26 million, which represented the refund of the $13 million exit fee paid by UE and the $5 million exit fee paid by CIPS, which were expensed when they left the Midwest ISO in 2001, plus $1 million interest on the exit fees and the reimbursement of $7 million that was invested in the proposed Alliance RTO. These refunds resulted in after-tax gains of approximately $11 million, $8 million and $3 million for Ameren, UE and CIPS, respectively, which were recorded in other operations and maintenance expenses during the quarter ended June 30, 2004. As part of the transfer of functional control of IP’s transmission system to the Midwest ISO, at the end of September 2004, IP also received a refund of its Midwest ISO exit fee and RTO development costs. This refund was provided to Dynegy pursuant to the terms of the stock purchase agreement covering Ameren’s acquisition of IP.

Through orders issued during late 2003 and early 2004, the FERC had ordered the elimination of regional through-and-out rates assessed by the Midwest ISO on transmission service between the Midwest ISO and PJM regions, to be effective May 1, 2004. However, in March 2004, the FERC accepted an agreement among affected transmission owners that retains the regional through-and-out rates until December 1, 2004, and provides for continued negotiations aimed at developing a long-term transmission pricing structure to eliminate seams between the PJM and Midwest ISO regions based on specified pricing principles. Until the long-term transmission pricing structure has been established, UE, CIPS, CILCO and IP cannot predict the ultimate impact that such structure will have on their costs and revenues.

In March 2004, the Midwest ISO tendered for filing at the FERC a proposed Open Access Transmission and Energy Markets Tariff (the “Energy Markets Tariff”), which is intended to supercede its existing OATT. The Energy Markets Tariff establishes rates, terms and conditions necessary for implementation of a centralized security-constrained


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economic dispatch platform supported by a day-ahead and real-time energy market design, including Locational Marginal-Cost Pricing and Financial Transmission Rights for transmission service within the Midwest ISO region. The Energy Markets Tariff also establishes market monitoring and mitigation procedures and codifies existing resource adequacy requirements placed on Midwest ISO members by their states or applicable RRO. The Midwest ISO initially proposed to make the Energy Markets Tariff effective on December 1, 2004, subject to its ability to implement the Energy Markets Tariff. However, implementation of the Energy Markets Tariff is now expected to be effective on March 1, 2005. On August 6, 2004, the FERC accepted the Mi dwest ISO’s Energy Markets Tariff subject to further compliance filings. On November 8, 2004, the FERC issued an order denying the requests for rehearing that were filed by a number of Midwest ISO stakeholders including Ameren. However, a final order from the FERC on the compliance filings made by the Midwest ISO in response to the FERC's August 6 order is still pending. At this time, Ameren is unable to determine the full impact that the Energy Markets Tariff will have until further information is available regarding the implementation of the Energy Markets Tariff.

Until UE, CIPS, CILCO and IP achieve some degree of operational experience participating in the Midwest ISO, we are unable to predict the ultimate impact that such participation or ongoing RTO developments at the FERC or other regulatory authorities will have on our financial position, results of operations or liquidity.

New Market Power Analysis Screen Order

In an order issued in April 2004, the FERC replaced the Supply Margin Assessment Screen previously used to review applications by sellers of electricity at wholesale for authorization to sell power at market-based rates with two alternative measures of market power: (a) an uncommitted pivotal supplier analysis and (b) an uncommitted market share analysis which is to be prepared on a seasonal basis. If an applicant passes both screens, a rebuttable presumption will exist that it lacks generation market power. If the applicant fails either screen, a rebuttable presumption will exist that it has market power. Under such circumstances, the applicant may either seek to rebut the presumption by preparing a delivered price test (identifying the amount of economic capacity from neighboring areas that can be delivered to t he control area) or propose mitigation measures. Unless some other mitigation measure is adopted, the applicant’s authority to sell power at market-based rates in areas in which it has market power will be revoked, and the applicant will be required to sell at cost-based rates in those areas.

UE, Genco, CIPS, CILCO, AERG, Development Company, Marketing Company and Medina Valley currently have authorization from the FERC to continue to sell power at market-based rates. However, the FERC indicated in its April 2004 order that it would apply the new market analysis screens to pending and future market-based rate applications, including three-year market-based rate reviews. All of the aforementioned Ameren entities currently have three-year market-based rate reviews pending at the FERC.

As required, these Ameren companies will file an updated market power analysis with FERC in December 2004. This updated analysis will include the results of FERC’s new screens. These companies will apply the new screens both on the basis of individual control area markets and also on the basis of the entire Midwest ISO footprint. We understands that the individual control area analyses will be applicable for a limited time until Midwest ISO implements its "Day 2" markets, now scheduled for March 1, 2005, and that the Midwest ISO footprint analyses will be applicable after that time. We expects that UE and AERG it will fail one of the new screens, the wholesale market share screen, in the UE/CIPS and CILCO control areas, respectively, but pass it in all other control areas and pass the other new screen measure, the pivotal supplier screen, in all of the individual control areas that we are required to study. We further anticipates that we will pass both screen measures for the larger market consisting of the entire Midwest ISO footprint. We are unable to anticipate how or when FERC will respond to any screen failure by an Ameren company for the interim period before the start of Midwest ISO Day 2 markets. Further, until we have finalized our updated analysis, we are unable to predict how the FERC will resolve a number of related issues, including resolution of evidence available to rebut any screen results indicating a failure, and resolution of any proposed mitigation measures. Finally, we are unable to predict the ultimate impact the new screens will have on our ability to sell power at market-based rates.

Illinois Gas

In June 2004, IP filed with the ICC seeking authority to raise its natural gas delivery rates by approximately $40 million annually. In August 2004, IP filed supplemental testimony, which revised the requested rate increase to approximately $36 million annually. Testimony on this matter was filed by the ICC staff in early November 2004, and hearings are scheduled for January 2005. If approved by the ICC, new rates are expected to go into effect in Spring 2005. In the order approving Ameren's acquisition of IP, the ICC prohibits IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond IP's pending request for a gas delivery rate increase.


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NOTE 4 - SHORT-TERM BORROWINGS AND LIQUIDITY

Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities generally within 1 to 45 days. As of September 30, 2004, certain Ameren subsidiaries had short-term borrowings totaling $30 million, $28 million of which was borrowed by EEI. The average short-term borrowings for Ameren and its subsidiaries were $16 million for the nine months ended September 30, 2004, with a ighted-average interest rate of 1.8%. Peak short-term borrowings for Ameren and its subsidiaries were $44 million for the nine months ended September 30, 2004, with an interest rate of 1.7%. UE, CIPS, Genco, CILCORP and CILCO had no external short-term borrowings as of September 30, 2 004 and CIPS, Genco, CILCORP and CILCO had no external short-term borrowings at December 31, 2003. At December 31, 2003, Ameren on a consolidated basis and UE had short-term borrowings outstanding, which totaled $161 million and $150 million, respectively. At the completion of the acquisition of IP on September 30, 2004, IP had no external short-term borrowings outstanding.

In July 2004, Ameren entered into two new credit agreements for a total of $700 million in revolving credit facilities to be used for general corporate purposes, including support of Ameren and UE commercial paper programs. The $700 million in new facilities includes a $350 million three-year revolving credit facility and a $350 million five-year revolving credit facility. These new credit facilities replaced Ameren’s existing $235 million 364-day revolving credit facility, which matured on July 14, 2004, and a $130 million multi-year revolving credit facility, which would have matured in July 2005. In September 2004, an existing Ameren $235 million multi-year revolving facility, which matures in July 2006, was amended and restated to accommodate Ameren’s acquisition of IP and to conform with its two cre dit agreements entered into in July 2004.

At September 30, 2004, certain of the Ameren Companies had committed bank credit facilities totaling $1,164 million, all of which were available for use, subject to applicable regulatory short-term borrowing authorizations, by UE, CIPS, CILCO, IP and Ameren Services through a utility money pool arrangement. In addition, $935 million of the $1,164 million was available for use, subject to applicable regulatory short-term borrowing authorizations, by Ameren directly, and by most of the non rate-regulated affiliates including, but not limited to, Resources Company, Genco, Marketing Company, AFS, AERG and Ameren Energy, through a non state-regulated subsidiary money pool agreement. We have money pool agreements with and among our subsidiaries to coordinate and provide for certain short-term cash and working capital re quirements. Separate money pools are maintained between rate-regulated and non rate-regulated entities. On September 30, 2004, our utility money pool agreement was amended to add IP as a party. Also, on September 30, 2004, a unilateral borrowing agreement was entered into between Ameren, IP and Ameren Services, which enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money pool agreement may not exceed $500 million pursuant to authorization from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreement. See Note 8 - Related Party Transactions for further discussion of the money pool arrangements and the unilateral borrowing agreement. The committed bank credit facilities are used to support our commercial paper programs under which there were no amounts outstanding at September 30, 2004 (December 31, 2003 - $150 milli on). Access to our credit facilities for any of Ameren’s subsidiaries is subject to reduction based on use by affiliates.

In April 2004, UE renewed, for an additional one-year term, its $75 million 364-day revolving facility that was due to expire that month.

EEI also has two committed bank credit agreements totaling $45 million with maturities through June 2005. At September 30, 2004, $28 million was borrowed and outstanding under these credit facilities.

Borrowings under Ameren’s non state-regulated subsidiary money pool agreement by Genco, Development Company and Medina Valley, each an “exempt wholesale generator,” are considered investments for purposes of the 50% SEC aggregate investment limitation. Based on Ameren’s aggregate investment in these “exempt wholesale generators” as of September 30, 2004, the maximum permissible borrowings under Ameren’s non state-regulated subsidiary money pool pursuant to this limitation for these entities were $508 million.


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Indebtedness Provisions and Other Covenants

Certain of the Ameren Companies’ bank credit agreements contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets and merge with other entities. Certain of these credit agreements also contain a provision that limits Ameren’s, UE’s, CIPS’, and CILCO’s total indebtedness to 60% of total capitalization pursuant to a calculation defined in the related agreement. As of September 30, 2004, the ratio of total indebtedness to total capitalization (calculated in accordance with this provision) for each of Ameren, UE, CIPS and CILCO was 52%, 43%, 51% and 44%, respectively. From and after March 31, 2005, IP's total indebtedness will also be limited by this provision. In addition, certain of these credit agreements contain indebtedness cross-defa ult provisions and material adverse change clauses which could trigger a default under these facilities in the event that any of Ameren’s subsidiaries (subject to the definition in the underlying credit agreements), other than certain project finance subsidiaries, defaults in indebtedness in excess of $50 million. The credit agreements also require us to meet minimum ERISA funding rules.

None of the Ameren Companies’, IP’s or EEI's credit agreements or financing agreements contain credit rating triggers. A $100 million CILCO bank term loan containing a credit ratings trigger was repaid in February 2004. At September 30, 2004, the Ameren Companies, IP and EEI were in compliance with their credit agreement provisions and covenants.

NOTE 5 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

In February 2004, Ameren issued, pursuant to an August 2002 SEC Form S-3 shelf registration statement, 19.1 million shares of its common stock at $45.90 per share for net proceeds of $853 million. This issuance substantially depleted all of the capacity under the August 2002 shelf registration statement. In June 2004, the SEC declared effective a Form S-3 shelf registration statement filed by Ameren covering the offering from time to time of up to $2 billion of various types of securities including long-term debt, trust preferred securities and equity securities. In July 2004, Ameren issued, pursuant to the June 2004 Form S-3 shelf registration statement, 10.9 million shares of its common stock at $42.00 per share for net proceeds of $445 million. The proceeds from both these offerings were used to pay the cash po rtion of the purchase price for our acquisition of IP and Dynegy's 20% interest in EEI and, as described below, are expected to be used to reduce IP debt assumed as part of the acquisition and to pay any related premiums. See Note 2 - Acquisitions for further information.

Ameren may sell all, or a portion of the remaining securities registered under the June 2004 shelf registration statement if warranted by market conditions and capital requirements. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder. At October 31, 2004, the amount remaining under the June 2004 shelf registration statement was $1.5 billion.

In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of six million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares or treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus. For the nine months ended September 30, 2004, Ameren issued 1.8 million new common shares valued at approximately $84 million under its DRPlus and its 401(k) plans to be used for general corporate purposes.

The purchase of IP on September 30, 2004, included the assumption of IP debt and preferred stock at closing of approximately $1.8 billion. The assumed debt and preferred stock included $936 million of mortgage bonds, $509 million of pollution control indebtedness supported by mortgage bonds, $352 million of TFNs issued by IP SPT and $13 million of preferred stock. Upon acquisition, total IP debt was increased to fair value by approximately $191 million which included early debt redemption premiums. The adjustment to the fair value of each debt series is being amortized over its remaining life, or to the expected redemption date, to interest expense.


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including, the redemption date. Ameren made an equity contribution of $250 million into IP to provide funds for this purpose and to satisfy indenture provisions related to the equity clawback. Also in October 2004, IP made a cash tender offer for any and all of the remaining outstanding mortgage bonds 11.50% Series due 2010 bonds ($357.5 million in aggregate principal amount). The purchase price will be determined, as described in the offer to purchase, in accordance with standard market practice by reference to a yield of 50 basis points over the yield on the 2.625% U.S. Treasury Note due November 15, 2006, on the price determination date, scheduled for November 18, 2004. The tender offer is scheduled to expire on November 22, 2004. This tender offer is also intended to satisfy IP’s indenture obligation to of fer to purchase the bonds resulting from the change of control of IP upon its acquisition by Ameren. Any such bonds tendered will be purchased with cash contributed as equity to IP by Ameren.

In addition, in October 2004, IP called for redemption on December 1, 2004, the following indebtedness: (i) all $65.6 million principal amount of its outstanding 7.50% Series due 2025 mortgage bonds at a redemption price of 103.105% of the principal amount plus accrued interest and (ii) all $84.2 million principal amount of the Illinois Development Finance Authority’s Pollution Control Refunding Revenue Bonds, 1994 7.40% Series B due 2024 at a redemption price of 102% of the principal amount plus accrued interest. This indebtedness will be redeemed with cash contributed as equity to IP by Ameren.

UE had a lease agreement, which was scheduled to expire on August 31, 2031, that provided for the financing of a portion of its nuclear fuel that was processed for use or was consumed at UE’s Callaway nuclear plant. In February 2004, UE terminated this lease with a final payment of $67 million.

In February and March 2004, in connection with the delivery of bond insurance policies to secure the environmental improvement and pollution control revenue bonds (Series 1991, 1992, 1998A, 1998B, 1998C, 2000A, 2000B and 2000C) previously issued by the Missouri Environmental Authority, UE delivered separate series of its first mortgage bonds (which are subject to fallaway provisions, as defined in the related financing agreements, similar to those included in its first mortgage bonds which secure UE’s senior secured notes) to secure its respective obligations under the existing loan agreements with the Missouri Environmental Authority relating to such environmental improvement and pollution control revenue bonds. As a result, the environmental improvement and poll ution control revenue bonds were rated Aaa, AAA and AAA by Moody’s, S&P and Fitch, respectively.

In May 2004, UE issued, pursuant to the September 2003 SEC Form S-3 shelf registration statement, $104 million of 5.50% senior secured notes due May 15, 2014, with interest payable semi-annually on May 15 and November 15 of each year beginning in November 2004. UE received net proceeds of $103 million, which were used along with other funds to redeem its $100 million 7% first mortgage bonds due 2024.

In September 2004, UE issued, pursuant to the September 2003 SEC Form S-3 shelf registration statement, $300 million of 5.10% senior secured notes due October 1, 2019, with interest payable semi-annually on April 1 and October 1 of each year beginning in April 2005. UE received net proceeds of approximately $298 million, which were used to repay short-term debt temporarily incurred to fund the maturity of UE’s $188 million 6.875% first mortgage bonds on August 1, 2004 and to repay other short-term debt which consisted of borrowings under the utility money pool arrangement.

UE may sell all, or a portion of, the remaining securities registered under the September 2003 shelf registration statement if warranted by market conditions and capital requirements. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder. At October 31, 2004, the amount remaining under the September 2003 shelf registration statement was $396 million.

CILCORP

In May 2004, CILCORP repurchased $15 million in principal amount of its 9.375% senior bonds and in July 2004, repurchased an additional $2 million in principal amount of these bonds. In conjunction with these debt repurchases, the fair value adjustment on these bonds was reduced by $5 million for the nine months ended September 30, 2004.


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The amortization related to debt fair value adjustments recorded in connection with the CILCORP acquisition for the three month and nine month periods ended September 30, 2004, was $2 million (2003 - $2 million) and $6 million (2003 - $5 million), respectively, and was recorded in interest expense in the Consolidated Statements of Income for Ameren and CILCORP.

CILCO

In February 2004, CILCO repaid its secured bank term loan totaling $100 million with available cash and borrowings from the utility money pool. In July 2004, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for 2004.

EEI

In June 2004, EEI repaid its $40 million 7.61% bank term loan due 2004 with proceeds received from EEI’s credit facilities.

Amortization of Interest-related Costs

The following table presents the amortization of debt issuance costs, fair value adjustments and any premium or discounts included in interest expense for the Ameren Companies for the three months and nine months ended September 30, 2004 and 2003, respectively:

	Three Months					Nine Months
	2004			2003		2004		2003
Ameren^(a)(c)		$	5	$	5	$	15	$	13
UE			2		1		4		3
CIPS			1		1		1		1
Genco			-		-		1		1
CILCORP^(b)(c)			2		3		6		6
CILCO			1		-		1		-

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(b)	January 2003 predecessor amounts were zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

(c)	In conjunction with the acquisition of CILCORP in 2003, CILCORP’s long-term debt was adjusted to fair value.

Indenture Provisions and Other Covenants

UE’s indenture agreements and articles of incorporation include covenants and provisions related to the issuance of first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. For the 12 months ended September 30, 2004, UE had a coverage ratio of 8.1 times the annual interest charges on the first mortgage bonds outstanding, which would permit UE to issue an additional $3.8 billion of first mortgage bonds at an assumed interest rate of 7%. For the issuance of additional preferred stock, earnings coverage of at least 2.5 times the annual dividend on preferred stock outstanding and to be issued is required under UE’s articles of incorporation. For the 12 months ended September 30, 2004, UE had a coverage ratio of 66.1 times the annual dividend requirement on preferred stock outstanding, which would permit UE to issue an additional $2.1 billion in preferred stock at an assumed dividend rate of 7%. The ability to issue such securities in the future will depend on such coverage ratios at that time.

In addition, UE’s mortgage indenture contains certain provisions which 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 the payment of common dividends, except for those dividends payable in common stock, leaving $1.7 billion of free and unrestricted retained earnings at September 30, 2004.

CIPS

CIPS’ indenture agreements and articles of incorporation include covenants which must be complied with in order to issue first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds, earnings coverage


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of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required except in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. For the 12 months ended September 30, 2004, CIPS had a coverage ratio of 3.77 times the annual interest charges for one year on the aggregate amount of first mortgage bonds outstanding and, subsequently, the most restrictive test under the indenture agreements would allow CIPS to issue an additional $126 million of first mortgage bonds. For the issuance of additional preferred stock, earnings coverage of 1.5 times annual interest charges on all long-term debt outstanding and the annual preferred stock dividends is required under CIPS’ articles of incorporation. For the 12 months ended September 30, 2004, CIPS had a coverage ratio of 2.08 times the sum of the annual interest charges and dividend requirements on all long-term debt and preferred stock outstanding as of Septemb er 30, 2004, and consequently had the availability to issue $188 million of preferred stock, assuming a dividend rate of 7%. The ability to issue such securities in the future will depend on such coverage ratios at that time.

Genco

Genco’s senior note indenture includes provisions that require it to maintain a senior debt service coverage ratio of at least 1.75 to 1 (for both the prior four fiscal quarters and projected next succeeding four six-month periods) in order to pay dividends or to make payments of principal or interest under certain subordinated indebtedness excluding amounts payable under its intercompany note payable to CIPS. For the 12 months ended September 30, 2004, this ratio was 4.47 to 1. In addition, the indenture also restricts Genco from incurring any additional indebtedness, with the exception of certain permitted indebtedness as defined in the indenture, unless its senior debt service coverage ratio equals at least 2.5 to 1 for the most recently ended four fiscal quarters and its senior debt to total capital ratio would not exceed 60%, both after giving effect to the additional indebtedness on a pro-forma basis. This debt incurrence restriction is disregarded in the event certain rating agencies reaffirm the ratings of Genco after considering the additional indebtedness. As of September 30, 2004, Genco’s senior debt to total capital ratio was 50%.

CILCORP

Covenants in CILCORP's indenture governing its $475 million (original issuance amount) senior notes and bonds require CILCORP to maintain a debt to capital ratio of no greater than 0.67 to 1 and an interest coverage ratio of at least 2.2 to 1 in order to make any payment of dividends or intercompany loans to affiliates other than to its direct and indirect subsidiaries, including CILCO. However, in the event CILCORP is not in compliance with these tests, CILCORP may only make such 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. For the 12 months ended September 30, 2004, CILCORP's debt to capital ratio was 0.58 to 1 and its interest coverage ratio was 2.1 to 1, calculated in accordance with applicable provision s of this indenture. At September 30, 2004, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BBB+, Baa2 and BBB+, respectively. The common stock of CILCO is pledged as security to the holders of these senior notes and bonds.

IP’s indenture agreements and articles of incorporation include covenants and provisions related to the issuance of first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds based on property additions, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. For the 12 months ended September 30, 2004, IP had a coverage ratio of 1.5 times the annual interest charges on the first mortgage bonds outstanding, which would not permit IP to issue any additional first mortgage bonds based on property additions. However, as of September 30, 2004, IP had the ability to issue $569 million of bonds based upon retired bond capacity, for which no earnings coverage test is requir ed. For the issuance of additional preferred stock, earnings coverage of at least 1.5 times the annual dividend on preferred stock outstanding and to be issued is required under IP’s articles of incorporation. For the 12 months ended September 30, 2004, IP had a coverage ratio of 1.1times the annual dividend requirement on preferred stock outstanding, which would not permit IP to issue any additional preferred stock. The ability to issue such securities in the future will depend on such tests at that time.

IP’s indenture governing its mortgage bonds 11.50% Series due 2010 contain triggering event provisions that would give the holders of at least 25% in principal amount of these bonds then outstanding the right to require IP to redeem the bonds, if IP takes certain actions defined in the bond indenture as restricted payments, incurrence of indebtedness and issuance of preferred stock, dividend and other payment restrictions affecting subsidiaries, and repurchase at the option of bondholders due to asset sales. These triggering events have been suspended with the upgrade to an investment grade credit rating of IP’s long-term debt after completion of Ameren’s acquisition of IP and will remain non-applicable


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as long as IP maintains an investment grade credit rating. Triggering events remain in effect on IP’s ability to incur liens, to merge, consolidate or sell assets, provide subsidiary guarantees, and engage in sale and leaseback transactions and certain business activities as defined in the indenture. See discussion of IP’s redemption and tender offer activities with respect to these bonds under "Ameren" above.

The IP SPT TFNs contain restrictions, which prohibit IP LLC from making any loan or advance to or certain investments in any other person. Also, as long as the TFNs are outstanding, the IP SPT shall not, directly or indirectly, pay any dividend or make any distribution (by reduction of capital or otherwise) to any owner of a beneficial interest in the IP SPT.

See Note 3 - Rate and Regulatory Matters for restrictions on IP’s ability to declare and pay common stock dividends imposed by the ICC order approving Ameren’s acquisition of IP.

Off-Balance Sheet Arrangements

At September 30, 2004, neither Ameren nor any of its subsidiaries had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. Neither Ameren nor any of its subsidiaries expects to engage in any significant off-balance sheet financing arrangements in the near future.

NOTE 6 - OTHER INCOME AND DEDUCTIONS

The following table presents Other Income and Deductions for each of the Ameren Companies for the three months and nine months ended September 30, 2004 and 2003:

	Three Months						Nine Months
	2004			2003			2004			2003
Ameren:^(a)
Miscellaneous income:
Interest and dividend income	$	5		$	1		$	10		$	3
Allowance for equity funds used during construction		2			1			6			1
Other		1			2			4			12
Total miscellaneous income	$	8		$	4		$	20		$	16
Miscellaneous expense:
Minority interest in subsidiary	$	(1	)	$	(1	)	$	(4	)	$	(6	)
Other		-			(2	)		(2	)		(8	)
Total miscellaneous expense	$	(1	)	$	(3	)	$	(6	)	$	(14	)
UE:
Miscellaneous income:
Interest and dividend income	$	1		$	1		$	3		$	1
Equity in earnings of subsidiary		1			1			4			6
Allowance for equity funds used during construction		2			1			6			1
Gain on disposition of property		1			-			1			-
Other		-			2			-			6
Total miscellaneous income	$	5		$	5		$	14		$	14
Miscellaneous expense:
Other	$	(1	)	$	(2	)	$	(6	)	$	(5	)
Total miscellaneous expense	$	(1	)	$	(2	)	$	(6	)	$	(5	)
CIPS:
Miscellaneous income:
Interest and dividend income	$	6		$	7		$	19		$	21
Total miscellaneous income	$	6		$	7		$	19		$	21
Miscellaneous expense:
Other	$	-		$	-		$	(1	)	$	(2	)
Total miscellaneous expense	$	-		$	-		$	(1	)	$	(2	)


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Three Months

Nine Months

2004

2003

2004

2003

Genco:
Miscellaneous income:
Other	$	1		$	-		$	-		$	-
Total miscellaneous income	$	1		$	-		$	-		$	-
CILCORP:^(b)
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(4	)	$	(3	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(4	)	$	(3	)
CILCO:
Miscellaneous expense:
Other	$	(1	)	$	(2	)	$	(4	)	$	(3	)
Total miscellaneous expense	$	(1	)	$	(2	)	$	(4	)	$	(3	)

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(b)	January 2003 predecessor amounts were zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS

Cash Flow Hedges

The following table presents balances in certain accounts for cash flow hedges as of September 30, 2004:

	Ameren			UE		CIPS		Genco			CILCORP^(a)		CILCO
Balance Sheet:
Other assets	$	56		$	10	$	11	$	7		$	25	$	25
Other deferred credits and liabilities		7			6		-		1			-		-
Accumulated OCI income/(loss):
Power forwards^(b)		(1	)		-		-		(1	)		-		-
Interest rate swaps^(c)		5			-		-		5			-		-
Gas swaps and futures contracts^(d)		43			6		10		-			24		24
Call options^(e)		4			4		-		-			-		-

(a)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

(b)	Represents the mark-to-market loss for the hedged portion of electricity price exposure for periods generally less than one year. Certain contracts designated as hedges of electricity price exposure have terms up to three years.

(c)	Represents 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.

(d)	Represents a gain associated with natural gas swaps and futures contracts. The swaps are a partial hedge of natural gas requirements through March 2008.

(e)	Represents the mark-to-market gain of a call option to purchase coal that is accounted for as a cash flow hedge. This option to purchase coal expires in July 2005.

The pre-tax net gain or loss on power forward derivative instruments included in Operating Revenues - Electric at Ameren, UE and Genco, which represented the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, as well as the reversal of amounts previously recorded in OCI due to transactions going to delivery or settlement, was a $2 million loss for Ameren, $1 million loss for UE and $1 million loss for Genco for the quarter ended September 30, 2004 (2003 - less than $1 million gain for Ameren, less than $1 million gain for UE, less than $1 million gain for Genco), and was less than $1 million loss for Ameren, UE and Genco for the nine months ended September 30, 2004 (2003 - less than $1 million loss for Ameren, UE, and Genco).

Other Derivatives

The following table represents for the three months and nine months ended September 30, 2004 and 2003, the net change in market value of option transactions, which are used to manage positions in SO₂ allowances, coal, heating oil and electricity or power. Certain of these transactions are treated as non-hedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The net change in the market value of SO₂ options is


	44

recorded in Operating Revenues - Electric, while the net change in the market value of coal, heating oil and electricity or power options is recorded as Operating Expenses - Fuel and Purchased Power.

Gains (Losses)^(a)	Three Months					Nine Months
	2004		2003			2004			2003
SO₂ options:
Ameren^(b)	$	4	$	-		$	2		$	1
UE		4		(1	)		(2	)		(1	)
CIPS		-		-			-			-
Genco		-		1			4			2
CILCORP^(c)		-		-			-			-
CILCO		-		-			-			-

(a)	Coal, power and heating oil option gains and losses were less than $1 million for the periods shown above.

(b)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(c)	January 2003 predecessor amounts were zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

NOTE 8 - RELATED PARTY TRANSACTIONS

The Ameren Companies and IP 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, 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 Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2003 and see Note 2 - Acquisitions under Part 1, Item 1 of th is report for futher information regarding Ameren's additional 20% ownership in EEI. Below are updates to several related party transactions.

Electric Power Supply Agreements

Under two electric power supply agreements, Genco is obligated to supply to Marketing Company, and Marketing Company, in turn, is obligated to supply to CIPS, all of the energy and capacity needed by CIPS to offer service for resale to its native load customers at rates specified by the ICC and to fulfill CIPS’ other obligations under all applicable federal and state tariffs or contracts. The agreement between Genco and Marketing Company can be terminated by either party upon at least one year’s notice, but could not have previously been terminated prior to December 31, 2004. On October 18, 2004, the FERC issued an order accepting a July 2004 filing seeking the extension of the CIPS-Marketing Company agreement and thus allowing the agreement to extend until the end of 2006.

In October 2003, in conjunction with CILCO’s transfer to AERG of substantially all of its generating assets, AERG entered into an electric power supply agreement with CILCO to supply CILCO with sufficient power to meet its native load requirements. AERG and CILCO agreed to extend the power supply agreement through December 31, 2006. Unlike the CIPS-Marketing Company agreement described in the preceding paragraph, FERC approval was not required for such an extension to become effective.

In the event that any of the parties to these agreements is unable to satisfy its obligations thereunder, either to purchase or deliver power, the counterparties would be forced to find alternative purchasers or suppliers for the energy, as appropriate, thus exposing them to market price risk.

Interconnection Agreements

UE, CIPS and IP are parties to an interconnection agreement for the use of their respective transmission lines and other facilities for the distribution of power. In addition, CILCO and IP are parties to a similar interconnection agreement. These agreements can be terminated by either party with three years notice.


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Joint Dispatch Agreement

UE and Genco jointly dispatch electric generation under an amended joint dispatch agreement. Under the agreement, each affiliate is required to serve its load requirements from its own generation first, and then allow access to any available generation to its affiliate. The joint dispatch agreement can be terminated by either party by giving one year’s notice. To address concerns raised before the MoPSC in the proceeding relating to the transfer of UE’s Illinois-based utility businesses to CIPS (see Note 3 - Rate and Regulatory Matters), UE offered to seek to amend the joint dispatch agreement so as to provide UE with a larger share of the margins on short term sales of power from the combined generation of UE and Genco. In particular, UE offered to use its best efforts to obtain all required regulatory approvals for such an amendment, but only if the MoPSC concluded that this was a necessary condition for its approval of the transfer of UE’s Illinois-based utility businesses. If made, such an amendment is expected to provide to UE additional annual margins ranging from approximately $7 million to $24 million for UE’s share of short term power sales. Such an amendment is expected to result in a corresponding reduction in Genco’s margins from its share of short term power sales. However, this reduction is expected to be offset by margins received from additional power sales by Genco (through Marketing Company) to CIPS to serve the transferred UE Illinois-based electric utility business. Also as part of the proceeding before the MoPSC, UE offered to study alternatives to the current use of incremental costs to price system energy transfers under the joint dispatch agreement between UE and Genco, if the MoPSC concluded that this was a necessary condition for its approval.

On October 6, 2004, the MoPSC issued an Order effective October 16, 2004, approving the transfer of UE’s Illinois-based utility businesses to CIPS subject to various conditions. Among these conditions, the MoPSC requires UE to make two amendments to the joint dispatch agreement. First, UE must amend the agreement, as offered by UE, so as to provide UE with a larger share of the margins on short term sales of power from the combined generation of UE and Genco. Second, the MoPSC requires UE to amend the agreement so as to price the system energy transfers to Genco at market prices, rather than prices based on incremental costs as the joint dispatch agreement currently provides. On October 15, 2004, UE filed an application for rehearing of the October 6 order requesting that the MoPSC rehear or in the alternative, clarify its decision to impose these and other conditions as a part of approving the transfer of UE’s Illinois utility business. See Note 3 - Rate and Regulatory Matters for further information.

As a result of the foregoing, there is uncertainty as to the terms of the joint dispatch agreement and also as to its duration. The termination of the agreement, or modifications to it, could have a material effect on UE or Genco. Modifications to, or termination of, the agreement would not have an immediate impact on Ameren due to UE’s Missouri electric rate moratorium, which ends June 30, 2006.

Support Services Agreements

Costs of support services provided by Ameren Services, Ameren Energy and AFS to their affiliates, including wages, employee benefits, professional services and other expenses are based on, or are an allocation of, actual costs incurred. Effective September 30, 2004, IP was added to the support services agreements with Ameren Services and AFS.

Money Pools

Through the utility money pool, the pool participants can access committed credit facilities at Ameren, which totaled $935 million at September 30, 2004. These facilities are in addition to UE’s $154 million, CIPS’ $15 million and CILCO’s $60 million in committed credit facilities which are also available to the utility money pool participants. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent the pool participants have surplus funds or other external sources are used to increase the available amounts. The average interest rate for borrowing under the utility money pool for the three months ended September 30, 2004, was 1.47% (2003 - 1.02%) and for the nine months e nded September 30, 2004 and 2003, was 1.17%. On September 30, 2004, the utility money pool agreement was amended to add IP as a participant.

At September 30, 2004, $935 million was available through the non state-regulated subsidiary money pool, excluding additional funds available through surplus cash balances. The average interest rate for borrowing under the non state-regulated subsidiary money pool for the three and nine months ended September 30, 2004 and 2003 was 8.84%.

CILCORP has been granted authority by the SEC under the PUHCA to borrow up to $250 million directly from Ameren in a separate arrangement unrelated to the money pools.


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On September 30, 2004, in conjunction with the completion on that date of Ameren’s acquisition of IP, a unilateral borrowing agreement was entered into between Ameren, IP and Ameren Services which enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money pool agreement may not exceed $500 million pursuant to authorization from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreement.

Intercompany Promissory Notes

As of September 30, 2004, Genco has affiliate notes payable of $324 million and $34 million to CIPS and Ameren, respectively, which, by their current terms, have final payments of principal and interest due on May 1, 2005. In November 2004, Genco made a $75 million principal prepayment under its note payable to CIPS. The note payable to CIPS was issued in conjunction with the transfer of its electric generating assets and related liabilities to Genco. Genco and CIPS expect to renew or modify the CIPS note to extend the principal maturity, which could include continued amortization of the principal amount. Such extension could require regulatory approval. Genco and Ameren are currently evaluating various alternatives with respect to the note payable to Ameren. In the event the maturities of these notes are not extended or restructured, whether due to not obtaining the necessary regulatory approvals or otherwise, Genco may need to access other financing sources to meet the maturity obligation to the extent it does not have cash available from its operating cash flows. Such sources of financing could include borrowings under the non state-regulated subsidiary money pool, or infusion of equity capital or new direct borrowings from Ameren, all subject to applicable regulatory financing authorizations and provisions in Genco’s senior note indenture.

The following tables present the impact of related party transactions on UE’s Consolidated Statement of Income and Consolidated Balance Sheet, based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the year ended December 31, 2003:

Statement of Income	Three Months				Nine Months
	2004		2003		2004		2003
Operating revenues from affiliates:
Power supply agreement with EEI	$	5	$	4	$	7	$	5
Joint dispatch agreement with Genco		31		23		89		79
Agency agreement with Ameren Energy		46		44		141		155
Interconnection agreement with IP		-		-		1		1
Gas transportation agreement with Genco		-		-		-		1
Total operating revenues	$	82	$	71	$	238	$	241
Fuel and purchased power expenses from affiliates:
Power supply agreements:
EEI	$	15	$	15	$	47	$	43
Marketing Company		2		2		7		7
Joint dispatch agreement with Genco		13		13		37		31
Agency agreement with Ameren Energy		22		19		59		55
Total fuel and purchased power expenses	$	52	$	49	$	150	$	136
Other operating expenses:
Support service agreements:
Ameren Services	$	37	$	40	$	113	$	126
Ameren Energy		1		3		1		5
AFS		1		1		3		5
Total other operating expenses	$	39	$	44	$	117	$	136
Interest expense:
Borrowings related to money pool	$	1	$	-	$	2	$	2


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Balance Sheet	September 30, 2004		December 31, 2003
Assets:
Miscellaneous accounts and notes receivable	$	16	$	28
Liabilities:
Accounts payable and wages payable	$	34	$	46
Borrowings from money pool		189		-

CIPS

The following tables present the impact of related party transactions on CIPS’ Statement of Income and Balance Sheet, based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the year ended December 31, 2003:

Statement of Income	Three Months				Nine Months
	2004		2003		2004		2003
Operating revenues from affiliates:
Power supply agreements:
Marketing Company	$	8	$	7	$	24	$	22
CILCO		-		6		-		8
Total operating revenues	$	8	$	13	$	24	$	30
Fuel and purchased power expenses from affiliates:
Power supply agreements:
Marketing Company	$	77	$	90	$	220	$	243
EEI		8		7		24		22
Total fuel and purchased power expenses	$	85	$	97	$	244	$	265

Other operating expenses:
Support service agreements:
Ameren Services	$	12	$	13	$	36	$	42
AFS		1		-		1		1
Total other operating expenses	$	13	$	13	$	37	$	43
Interest income:
Note receivable from Genco	$	5	$	7	$	18	$	21

Balance Sheet	September 30, 2004		December 31, 2003
Assets:
Miscellaneous accounts and notes receivable	$	9	$	10
Promissory note receivable from Genco^(a)		324		373
Tax receivable from Genco^(b)		152		162
Liabilities:
Accounts payable and wages payable	$	42	$	43
Borrowings from money pool		61		121

(a)	Amount includes current portion of $49 million as of December 31, 2003 and $324 million as of September 30, 2004.

(b)	Amount includes current portion of $12 million as of December 31, 2003 and $11 million as of September 30, 2004.


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Genco

The following tables present the impact of related party transactions on Genco’s Statement of Income and Balance Sheet, based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the year ended December 31, 2003:

Statement of Income	Three Months				Nine Months
	2004		2003		2004		2003
Operating revenues from affiliates:
Power supply agreements:
Marketing Company	$	190	$	177	$	531	$	477
EEI		2		3		3		4
Joint dispatch agreement with UE		13		13		37		31
Agency agreement with Ameren Energy		23		19		72		73
Operating lease with Development Company		3		3		8		8
Total operating revenues	$	231	$	215	$	651	$	593
Fuel and purchased power expenses from affiliates:
Joint dispatch agreement with UE	$	31	$	23	$	89	$	79
Agency agreement with Ameren Energy		9		9		22		28
Gas transportation agreement with UE		-		1		-		1
Total fuel and purchased power expenses	$	40	$	33	$	111	$	108
Other operating expenses:
Support service agreements:
Ameren Services	$	4	$	5	$	12	$	14
Ameren Energy		-		2		1		3
AFS		1		1		2		2
Total other operating expenses	$	5	$	8	$	15	$	19
Interest expense:
Borrowings related to money pool	$	4	$	4	$	10	$	12
Note payable to CIPS		5		7		18		21
Note payable to Ameren		1		1		2		2

Balance Sheet	September 30, 2004		December 31, 2003
Assets:
Miscellaneous accounts and notes receivable	$	84	$	78
Liabilities:
Accounts payable and wages payable		22		22
Interest payable		22		7
Promissory note payable to CIPS^(a)		324		373
Promissory note payable to Ameren^(b)		34		38
Tax payable to CIPS^(c)		152		162
Borrowings from money pool		79		124

(a)	Amount includes current portion of $49 million as of December 31, 2003 and $324 million as of September 30, 2004.

(b)	Amount includes current portion of $4 million as of December 31, 2003 and $34 million as of September 30, 2004.


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CILCORP

The following tables present the impact of related party transactions on CILCORP’s Consolidated Statement of Income and Consolidated Balance Sheet, based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the year ended December 31, 2003:

Statement of Income^(a)(b)	Three Months				Nine Months
	2004		2003		2004		2003
Operating revenues from affiliates:
Gas supply and services agreement with Medina Valley	$	-	$	3	$	-	$	12
Total operating revenues	$	-	$	3	$	-	$	12
Fuel and purchased power expenses from affiliates:
Executory tolling agreement with Medina Valley	$	6	$	7	$	23	$	22
Power purchase agreement with CIPS		-		6		-		8
Total fuel and purchased power expenses	$	6	$	13	$	23	$	30
Other operating expenses:
Support services agreements:
Ameren Services	$	12	$	6	$	37	$	7
AFS		-		-		1		1
Total other operating expenses	$	12	$	6	$	38	$	8
Interest expense:
Note payable to Ameren	$	1	$	-	$	3	$	-
Borrowings related to money pool		1		-		3		-

(a)	2003 amounts include January 2003 predecessor information which included $2 million in operating revenues and $3 million in purchased power associated with the executory tolling agreement with Medina Valley.

(b)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

Balance Sheet^(a)	September 30, 2004		December 31, 2003
Assets:
Miscellaneous accounts and notes receivable	$	8	$	8
Liabilities:
Accounts payable	$	19	$	16
Note payable to Ameren		56		46
Borrowings from money pool		191		145

(a)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

CILCO

The following tables present the impact of related party transactions on CILCO’s Consolidated Statement of Income and on the Consolidated Balance Sheet, based primarily on the various agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the year ended December 31, 2003:

Statement of Income	Three Months				Nine Months
	2004		2003		2004		2003
Fuel and purchased power expenses from affiliates:
Executory tolling agreement with Medina Valley	$	6	$	7	$	23	$	22
Power purchase agreement with CIPS		-		6		-		8
Total fuel and purchased power expenses	$	6	$	13	$	23	$	30
Other operating expenses:
Support services agreements:
Ameren Services	$	11	$	6	$	35	$	7
AFS		1		-		1		1
Total other operating expenses	$	12	$	6	$	36	$	8
Interest expense:
Borrowings related to money pool	$	2	$	-	$	4	$	-


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Balance Sheet	September 30, 2004		December 31, 2003
Assets:
Miscellaneous accounts and notes receivable	$	8	$	6
Liabilities:
Accounts payable	$	18	$	23
Borrowings from money pool		193		149

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Reference is made to Note 15 - Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2003.

Capital Expenditures

See Note 3 - Rate and Regulatory Matters for information regarding Ameren’s capital expenditure commitment with respect to IP, which was included in the ICC order approving Ameren’s acquisition of IP.

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at September 30, 2004:

Type and Source of Coverage	Maximum Coverages	Maximum Assessments for Single Incidents
Public liability:
American Nuclear Insurers	$ 300	$ -
Pool participation	10,461	101^(a)
	$ 10,761^(b)	$ 101
Nuclear worker liability:
American Nuclear Insurers	$ 300^(c)	$ 4
Property damage:
Nuclear Electric Insurance Ltd.	$ 2,750^(d)	$ 21
Replacement power:
Nuclear Electric Insurance Ltd.	$ 490^(e)	$ 7

(a)

Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended (Price-Anderson). This is subject to retrospective assessment with respect to loss from an incident at any U.S. reactor, payable at $10 million per year. Price-Anderson expired in August 2002 and the temporary extension expired December 31, 2003. Until Price-Anderson is renewed, its provisions continue to apply to existing nuclear plants.

(b)	Limit of liability for each incident under Price-Anderson.

(c)	Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation.

(d)	Includes premature decommissioning costs.

(e)	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.

Price-Anderson limits the liability for claims from an incident involving any licensed U.S. nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years based on the Consumer Price Index. Utilities owning 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.

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 not available, we self-insure the risk. Although we have no reason to anticipate a serious nuclear incident, if one did occur, it could have a material, but indeterminable, adverse effect on our financial position, results of operations or liquidity.


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Leases

The following table presents our December 31, 2003 lease obligations, which have been updated to include IP lease obligations subsequent to September 30, 2004:

	Total		2004		2005 - 2006		2007 - 2008		Thereafter
Ameren:^(a)
Capital leases^(b)	$	167	$	70	$	7	$	8	$	82
Operating leases^(c)		211		24		39		31		117
Total lease obligations	$	378	$	94	$	46	$	39	$	199
UE:
Capital leases^(b)	$	167	$	70	$	7	$	8	$	82
Operating leases^(c)		128		9		19		18		82
Total lease obligations	$	295	$	79	$	26	$	26	$	164
CIPS:
Operating leases^(c)	$	-	$	-	$	-	$	-	$	-
Genco:
Operating leases^(c)	$	42	$	2	$	5	$	4	$	31
CILCORP:
Operating leases^(c)	$	9	$	2	$	3	$	2	$	2
CILCO:
Operating leases^(c)	$	9	$	2	$	3	$	2	$	2

(a)	Includes amounts for registrant and non-registrant Ameren subsidiaries, including IP, and intercompany eliminations.

(b)	See Note 6 - Long-term Debt and Equity Financings under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2003 for further discussion.

(c)

Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The amounts for these items are included in the 2004, 2005 - 2006 and 2007 - 2008 columns. Amounts for after 5 years are not included in the total amount due to the indefinite periods. The estimated obligation for after 5 years is $2 million annually for both the real estate leases and the railroad licenses.

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. In addition, we have entered into various long-term commitments for the purchase of electricity. For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2003.

As of September 30, 2004, the commitments for the procurement of coal have increased from what was previously disclosed as of December 31, 2003. The following table presents the total estimated coal purchase commitments at September 30, 2004:

	2004		2005		2006		2007		2008		Thereafter^(a)
Ameren^(b)	$	754	$	665	$	553	$	395	$	353	$	201
UE		384		347		275		184		160		71
CIPS		-		-		-		-		-		-
Genco		189		176		163		130		124		99
CILCORP		93		61		46		33		28		12
CILCO		93		61		46		33		28		12

(a)	Commitments for coal are until 2010.

(b)	Includes amounts for registrant and non-registrant Ameren subsidiaries and intercompany eliminations.

As a result of Ameren’s acquisition of IP on September 30, 2004, the commitments and contingencies of IP are now included in Ameren’s other obligations. IP’s other obligations include IP’s contracts on six interstate pipeline companies for firm transportation and storage services for natural gas. These contracts have varying expiration dates ranging from 2004 to 2012, for a total cost of approximately $73 million. IP also enters into obligations for the reservation of natural gas supply. These obligations generally range in duration from one to twelve months and require IP to compensate the


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provider for capacity charges. The cost of the agreements are $73 million. As part of the terms of Ameren’s acquisition of IP, IP entered into a power purchase agreement with a Dynegy affiliate that will be effective for 2005 and 2006. As a result of this agreement and an agreement that expires on December 31, 2004, IP’s obligations for purchased power are approximately $354 million. Expected purchases by IP under the Purchase Power Agreement with AmerGen, which expires in December 2004, are approximately $71 million.

IP has decommissioning obligations of approximately $5 million, payable in the fourth quarter of 2004, associated with its former Clinton nuclear plant. Other obligations also include decontamination and decommissioning charges associated with IP’s use of a DOE facility that enriched uranium for the Clinton nuclear plant. IP was assessed an amount to be paid over fifteen years that would be used to pay for the DOE’s decontamination and decommissioning of its facility. The remaining obligation is approximately $2 million and the final payment is due in 2006.

Environmental Matters

Clean Air Act

The EPA issued a rule in October 1998 requiring 22 eastern states and the District of Columbia to reduce emissions of NO_x in order to reduce ozone in the eastern United States. Among other things, the EPA’s rule establishes an ozone season, which runs from May through September, and a NO_x emission budget for each state, including Illinois. The EPA rule requires states to implement controls sufficient to meet their NO_x budget by May 31, 2004. In the spring of 2004, the EPA issued similar rules for Missouri. The compliance date for the Missouri rules is May 1, 2007.

As a result of these requirements, impacted Ameren Companies have installed a variety of NO_x control technologies on power plant boilers over the past several years. The following table presents our future estimated capital expenditures to comply with the final NO_x regulations in Missouri between 2005 and 2008:

Ameren	$160 million to $180 million
UE	$160 million to $180 million
CIPS	-
Genco	-
CILCORP	-
CILCO	-

In mid-December 2003, the EPA issued proposed regulations with respect to SO₂ and NO_x emissions (the “Clean Air Interstate Rule”) and mercury emissions from coal-fired power plants. The new rules, if adopted, will require significant additional reductions in these emissions from UE, Genco and CILCO power plants in phases, beginning in 2010. The rules are currently under a public review and comment period and may change before b eing issued as final. The following table presents preliminary estimated capital costs based on current technology on the Ameren systems to comply with theClean Air Interstate Rule and mercuryrules, as proposed:

	By 2010	2011 - 2015
Ameren	$1.1 billion to $1.4 billion	$375 million to $510 million
UE	$660 million to $860 million	$175 million to $230 million
CIPS	-	-
Genco	$280 million to $370 million	$160 million to $220 million
CILCORP^(a)	$110 million to $150 million	$40 million to $60 million
CILCO	$110 million to $150 million	$40 million to $60 million

(a)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.


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EPA Notice of Violation and Complaint Regarding Former IP Power Plant

IP and DMG are the subject of a Notice of Violation (NOV) from the EPA and a complaint filed in 1999 by the United States in the U.S. District Court for the Southern District of Illinois (Court) alleging violations of the Clean Air Act and certain related federal and Illinois regulations. Similar notices and complaints were filed against other owners of coal-fired power plants in what we refer to as the Utility Enforcement Initiative. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at the three Baldwin Power Station generating units formerly owned by IP constituted “major modifications” under the Prevention of Significant Deterioration (PSD) regulations, the New Source Performance Standard (NSPS) regulations and the applicable Illinois regulat ions, and that the defendants failed to obtain required operating permits under the applicable Illinois regulations. When activities which are not otherwise exempt result in an increase in annual emissions that exceed the amount deemed significant under the PSD regulations, those activities are considered “major modifications.” When activities meeting this definition occur, the Clean Air Act and related regulations generally subject those activities to PSD review and permit requirements and require that the generating facilities where the activities occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment.

DMG, the current owner of the Baldwin Power Station, acquired the generating facility as a result of Dynegy’s acquisition of IP in 2000. With Ameren’s acquisition of IP on September 30, 2004, DMG and IP are no longer affiliated. DMG has significantly reduced emissions of SO₂ and NO_X at the Baldwin Power Station since 1999 by converting from high to low sulfur coal, and installing selective catalytic reduction equipment. However , the EPA may seek in the litigation to require the installation of the “best available control technology,” or the equivalent, at the Baldwin Power Station which could require significant capital expenditures. The EPA also has the authority to seek civil penalties for the alleged violations at the rate of up to $27,500 per day for each violation.

In February 2003, the Court granted IP’s and DMG’s joint motion for partial summary judgment based on the five-year statute of limitations. As a result, the EPA is not permitted to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Court’s ruling also precludes monetary civil penalties for a portion of the claims under the NSPS regulations and the applicable Illinois regulations. IP believes that it has meritorious defenses against the remaining claims. The trial to resolve claims of liability was conducted in June 2003 and closing arguments occurred in September 2003. Ameren cannot predict when a decision will be rendered by the Court on the liability phase of the litigation. If the Court finds liability, a damages trial will then be conducted.

Pursuant to the terms of the stock purchase agreement covering Ameren’s acquisition of IP from Dynegy, Dynegy agreed to fully indemnify Ameren and IP in the event of an adverse ruling and in any settlement arising from or out of this litigation. To secure payment of the indemnification obligations of Dynegy, Ameren, pursuant to the terms of the stock purchase agreement, has deposited $100 million of the cash portion of the purchase price into an escrow account with the funds to be released to Dynegy on the sooner of (i) December 31, 2010, (ii) the date on which the senior unsecured debt of Dynegy Holdings Inc., a Dynegy subsidiary, achieves an investment grade rating from S&P or Moody’s or (iii) the occurrence of specified events relating to contingent environmental liabilities associated with IP 6;s former generating facilities, including the Baldwin Power Station. Ameren cannot predict the ultimate outcome of this litigation or whether Dynegy will be able to satisfy its indemnification obligations under the stock purchase agreement in the event IP is found to be liable. Ameren also cannot provide any assurance that the escrow arrangement will fully secure Dynegy’s indemnification obligations if such obligations are triggered.

In August 2003 two significant decisions were handed down in other cases that are part of the Utility Enforcement Initiative. The district court in United States vs. Ohio Edison applied the EPA’s narrow interpretation of the “routine maintenance, repair and replacement” exclusion, which defines it with respect to what is routine for the specific unit where the projects occurred, while the court in United States vs. Duke Energy Company rejected the EPA’s narrow interpretation, holding that the exclusion should be defined relative to what is routine for the particular industry. The Duke court also held that the hours and conditions of a unit’s operations must be held constant when measuring emissions increases. Under this rationale, an increase in maximum hourly emissions is required before activities would be considered “major modifications.” Ameren is unable to predict the significance of these cases to the Baldwin Power Station litigation as they are pending in other jurisdictions and are not binding authority.


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The EPA previously requested information, which has been provided, concerning activities at DMG’s Vermilion, Wood River and Hennepin plants, all formerly owned by IP. Although the EPA could eventually commence enforcement actions based on activities at these plants, we are unable to assess the likelihood of any such additional EPA enforcement actions. In the event enforcement actions are initiated against IP as a result of its prior ownership of these plants, Ameren and IP intend to rely upon the indemnification provisions of the stock purchase agreement with Dynegy and the escrow agreement if it is in effect at the time.

Clean Water Act

In July 2004, the EPA issued rules under the Clean Water Act that require that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. These rules pertain to existing generating facilities that currently employ a cooling water intake structure whose flow exceeds 50 million gallons per day. The rules may require us to install additional intake screens or other protective measures, as well as extensive site specific study and monitoring requirements. There is also the possibility that the rules may lead to the installation of cooling towers on some of our facilities. Our compliance costs associated with conducting field studies and installing fish collection systems t o determine the aquatic impact of our intake structures will be in the range of a few million dollars over the next few years. These studies will determine what, if any, additional technology must be applied at nine of our existing power plants. At this time, we are unable to estimate the costs of complying with these rules, but they could be material. Such costs will not be incurred prior to 2008.

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 fault, legality of original disposal, or ownership of a disposal site. Each of UE and CIPS has been identified by the federal or state governments as a potentially responsible party at several contaminated sites. Several of these sites involve facilities which were transferred by CIPS to Genco in May 2000 and were transferred by CILCO to AERG in October 2003. As part of each transfer, the transferor (CIPS or CILCO) has contractually agreed to indemnify the transferee (Genco or AERG) for remediation costs associated with pre-existing environmental contamination at the transferred sites.

CIPS, CILCO, UE and IP own or are otherwise responsible for 13, four, one and 25 former MGP sites in Illinois, respectively. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2010. The ICC permits each company to recover remediation and litigation costs associated with their former MGP sites located in Illinois from their Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred and are subject to annual reconciliation review by the ICC. The total costs deferred, net of recoveries from insurers and through environmental adjustment rate riders, at September 30, 2004, wer e $26 million, $2 million, $1 million and $46 million for CIPS, CILCO, UE and IP, respectively.

In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. Unlike in Illinois, UE does not have in effect in Missouri a rate rider mechanism which permits remediation costs associated with MGP sites to be recovered from utility customers, and UE does not have any retail utility operations in Iowa. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site and the environmental risk), and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. UE has recorded a $12 million liability as of September 30, 2004, representing its estimated minimum obligation. At this time, we are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.

In October 2002, CILCO submitted a corrective action plan to the Illinois Environmental Protection Agency (Illinois EPA) in accordance with permit conditions to address ground water issues associated with the recycle pond and ash ponds at the Duck Creek power plant facility. In January 2003, the Illinois EPA accepted portions of the plan but rejected other portions. Additional discussions with the Illinois EPA will be necessary to develop an acceptable plan. CILCORP and CILCO both have a liability of $8 million at December 31, 2003, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort to treat and discharge the recycle system water in order to address these ground water issues. Future CILCO capital expenditures at Duck Creek will include construction of a dry flyash


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collection system, a landfill and a new pond. CILCO estimates future capital expenditures for the indicated activities could range from $19 million to $25 million by 2008.

In addition, our operations, or that of our predecessor companies, involve the use, disposal and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these actions may have on our financial position, results of operations or liquidity.

Emission Credits

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. The Clean Air Act and NO_x Budget Trading Program created marketable commodities called allowances. Each allowance gives the ow ner the right to emit one ton of SO₂ or NO_x. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities having excess allowances or from allowance banks. Our generating facilities comply with the SO₂ limits through the use and purchase of allowances, the use of low sulfur fuels or through the application of pollution control technology. The NO_x Budget Trading Program limits emissions of NO_x during the ozone season (May through September). The NO_x Budget Trading Program applies to all electric generating units in Illinois beginning in 2004 and in the eastern third of Missouri beginning in 2007. 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 and selective catalytic reduction (SCR) systems.

As of September 2004, UE, Genco, CILCO and EEI held 1.7 million, 0.5 million, 0.3 million and 0.3 million tons, respectively, of SO₂ emission allowances for use between 2004 and 2012. Each company possesses additional allowances for use in periods beyond 2012. As of September 30, 2004, UE, Genco, CILCO and EEI Illinois facilities expect to hold 290, 26,200, 8,300 and 8,600 tons, respectively, of NO_X emission allowances with vintages from 2004 to 2007. The Illinois Environmental Protection Agency is still determining some NO_x emission allowances allocations for this period and 2008. UE, Genco and CILCO expect to use a substantial portion of the SO₂ and NO_x allowances for ongoing operations. Allocations of NO_x allowances for Missouri facilities are pending the finalization of rules by Missouri regulators. New environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment and level of operations will have a significant impact on the amount of allowances actually required for ongoing operations.

Asbestos-Related Litigation

Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits which have been filed by certain plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The number of total defendants named in each case is significant with as many as 235 parties named in a case to as few as five. However, the average number of parties is 65 in the cases that were pending as of September 30, 2004.

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. In the case of CIPS, its former plants are now owned by Genco, and in the case of CILCO, most of its former plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the generating plants, the transferor (CIPS or CILCO) has contractually agreed to indemnify the transferee (Genco or AERG) for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if pro ved, typically would be shared among the named defendants.


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From July 1, 2004 through September 30, 2004, 12 additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois, 13 lawsuits were dismissed and six were settled. The following table presents the status as of September 30, 2004, of the asbestos-related lawsuits that have been filed against the Ameren Companies and IP:

		Specifically Named as Defendant
	Total^(a)	Ameren	UE	CIPS	Genco	CILCO	IP
Filed	242	18	138	85	2	17	109
Settled	56	-	34	20	-	2	26
Dismissed	97	8	57	29	-	3	44
Pending	89	10	47	36	2	12	39

(a)

Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants. As of September 30, 2004, four 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.

As of September 30, 2004, four 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.

Ameren, UE, CIPS, Genco, CILCO and IP believe that the final disposition of these proceedings will not have a material adverse effect on their financial position, results of operations or liquidity. See Note 3 - Rate and Regulatory Matters - IP Acquisition for information on the ICC’s approval of a tariff rider through which asbestos-related litigation claims will be allowed to be recovered from IP’s electric customers, subject to certain terms, commencing in 2007.

Other Matters

Enron Litigation Settlement

In May 2001, CILCO and Enron Power Marketing, Inc. (EPMI), a subsidiary of Enron Corporation (Enron), entered into a master agreement for electric purchases and sales, which covered energy transactions scheduled for deliveries during the period of 2001 to 2003. In November 2001, EPMI demanded that CILCO post $28 million in collateral based on mark-to-market exposure of open transactions. Also in November 2001, CILCO notified EPMI that events of default had occurred under the master agreement and pursuant to the termination provisions of the master agreement declared the master agreement terminated effective December 20, 2001. Enron and EPMI filed Chapter 11 bankruptcy petitions in December 2001 in the U.S. Bankruptcy Court f or the Southern District of New York. In December 2002, EPMI filed a complaint against AES, Constellation New Energy, Inc., formerly known as AES New Energy Inc., and CILCO in the U.S. Bankruptcy Court seeking $31 million. As a result of court ordered mediation of this matter, a settlement agreement was reached among the parties and approved by the Bankruptcy Court on September 30, 2004. This settlement agreement and court order settles the outstanding claims by requiring CILCO to pay $20.9 million to an Enron subsidiary. This settlement payment was made during October 2004. The payment also settles an unrelated dispute between CILCO and another Enron subsidiary, Enron North America Corporation (ENA) over ENA’s failure to deliver natural gas to CILCO pursuant to transactions entered into in May and October 2001. AES, in conjunction with its sale of CILCORP to Ameren in 2003, agreed to indemnify Ameren against the after-tax cost of all liabilities, which includes the settlement payment, legal fees a nd expenses, incurred by CILCO relating to the Enron claim. Ameren assigned its indemnification rights to CILCO. The indemnification payment from AES to CILCO also took place in October 2004. As a result, this settlement will have no earnings impact on Ameren, CILCORP or CILCO.

Labor-related Matters

On June 18, 2003, 20 retirees and surviving spouses of retirees of various Ameren companies (the plaintiffs) filed a complaint in the U.S. District Court, Southern District of Illinois (the District Court), against Ameren, UE, CIPS, Genco and Ameren Services, and against our Retiree Medical Plan (the defendants). The retirees were members of various local labor unions of the IBEW and the IUOE. The complaint, referred to as Barnett, et al. vs. Ameren Corporation, et al., alleges the following:

the labor organizations which represented the plaintiffs have historically negotiated retiree medical benefits with the defendants and that pursuant to the negotiated collective bargaining agreements and other negotiated documents, the plaintiffs are guaranteed medical benefits at no cost or at a fixed maximum cost during their retirement;


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Ameren has unilaterally announced that, beginning in 2004, retirees must pay a portion of their own healthcare premiums and either an increasing portion of their dependents’ premiums or newly imposed dependents’ premiums, and that surviving spouses will be paying increased amounts for their medical benefits;
the defendants’ actions deprive the plaintiffs of vested benefits and thus violate ERISA and the Labor Management Relations Act of 1947, and constitute a breach of the defendants’ fiduciary duties; and
the defendants are estopped from changing the plan benefits. (This allegation was subsequently dropped from the amended complaints referred to below).

The plaintiffs filed the complaint on behalf of themselves, other similarly situated former non-management employees and their surviving spouses who retired from January 1, 1992 through October 1, 2002, and on behalf of all subsequent non-management retirees and their surviving spouses whose medical benefits are reduced or are threatened with reduction. The plaintiffs seek to have this lawsuit certified as a class action, seek injunctive relief and declaratory relief, seek actual damages for any amounts they are made to pay as a result of the defendants’ actions, and seek payment of attorney fees and costs. In response to the District Court’s ruling on the defendants’ motions to dismiss various counts of the complaint, a second amended complaint was filed on December 15, 2003, clarifying some of the allegations, and adding the Ameren Group Medical Plan as a defendant. In April 2004, the District Court granted the defendants’ motion to dismiss one of the counts brought in connection with the amended complaint which alleges the defendants breached their fiduciary duties under ERISA. In July 2004, the District Court denied the plaintiffs’ motion to certify this lawsuit as a class action and in September 2004, the Seventh Circuit Court of Appeals denied the plaintiffs’ application to appeal the District Court’s decision. In August 2004, the defendants filed a motion for summary judgment, which is pending before the District Court. We are unable to predict the outcome of this lawsuit or the impact of the outcome on our financial position, results of operations or liquidity.

Certain employees of CILCO are represented by the IBEW. These employees comprise 4% of Ameren’s workforce. The labor agreement covering these employees expired June 30, 2004, and was automatically extended through August 29, 2004. CILCO submitted a last, best and final offer to the employees’ collective bargaining unit on August 25, 2004, at which time it was agreed that the labor agreement would extend through September 30, 2004. The principal issues of the labor negotiations include work rules and CILCO’s proposal to change the employee medical benefits program to require employees to pay for a portion of their benefit coverage. On September 29, 2004, the last, best and final offer was rejected. On October 6, 2004, CILCO informed the employees’ collective bargaining unit that CILCO would impl ement, effective October 11, 2004, the economic and noneconomic portions of CILCO’s August 25, 2004 offer. The employees are currently working without a contract and under the terms of the August 25, 2004, offer. On October 18, 2004, most of the employees participated in a one-day work stoppage regarding a work rule grievance. We cannot predict what further action, if any, the collective bargaining unit will take or the response of Ameren’s other union represented employees to any action by its employees. We are unable to determine what, if any, impact these labor matters could have on our financial condition, results of operations or liquidity. Labor agreements covering the remaining UE, CIPS, IP and Genco employees represented by the IBEW and the IUOE expire in June 2006 and June 2007, respectively.

Leveraged Leases

Ameren owns interests in assets which have been financed as leveraged leases. One of these leveraged leases is a $10 million investment at September 30, 2004, in an aircraft leased to Delta Air Lines. Delta Air Lines reported significant operating losses and disclosed in its Form 10-Q filing for the three months ended June 30, 2004, that the company would need to seek to restructure its costs under Chapter 11 of the U.S. Bankruptcy Code if the company cannot achieve a competitive cost structure, regain sustained profitability and access the capital markets under acceptable terms. Ameren could lose all or a portion of its investment in the Delta Air Lines lease in the event of a bankruptcy or default by Delta Air Lines or any voluntary restructuring of the lease. As of September 30, 2004, Delta Air Lines was curren t in its lease payments related to this lease.


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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 from its Callaway nuclear plant. Electric utility rate s charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. UE has sufficient storage capacity at its Callaway nuclear plant until 2019 and 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 over the life of the plant, based on an assumed 40-year life, ending with expiration of the plant’s operating license in 2024. The Callaway nuclear plant site is assumed to be decommissioned based on immediate dismantlement method and removal from service. Decommissioning costs, including decontamination, dismantling and site restoration, are estimated to be $536 million in current year dollars and are expected to escalate approximately 3.5% per year through the end of decommissioning activity in 2033. Decommissioning costs are charged to cost of services used to establish electric rates for UE’s customers and amounted to approximately $7 million in each of the years 2003, 2002 and 2001. Every three years, the MoPSC and ICC require UE to file updated cost studies for decommissioning its Callaway nuclear plant, and electric rates may be adjusted at such times to reflect changed estimates. The latest studies were filed in 2002. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. Fund earnings are expected to average a pproximately 8.6% annually through the date of decommissioning. If the assumed return on trust assets is not earned, we believe 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 in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally restricted 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 the regulatory asset recorded in connection with the adoption of SFAS No. 143. Upon the completion of UE’s transfer of its Illinois electric and gas utility businesses to CIPS, which is subject to t he receipt of regulatory approvals, the assets and liabilities related to the Illinois portion of the decommissioning trust fund will be transferred to Missouri. See Note 3 - Rate and Regulatory Matters for further information.

NOTE 11 - STOCKHOLDERS’ EQUITY

Outstanding Shares of Common Stock

The following table reconciles the outstanding shares of Ameren common stock for the three months and nine months ended September 30, 2004 and 2003:

	Three Months Ended		Nine Months Ended
	2004	2003	2004	2003
Shares outstanding at beginning of period	183.3	161.7	162.9	154.1
Shares issued	11.5	0.6	31.9	8.2
Shares outstanding at end of period	194.8	162.3	194.8	162.3

Paid-In Capital

Ameren received net proceeds of $1.3 billion from the issuance of shares of its common stock in February and July 2004. In addition, during the nine months ended September 30, 2004, Ameren, pursuant to registration statements filed with the SEC, issued a total of 1.8 million new shares of common stock valued at $84 million under its DRPlus and 401(k) plans. Ameren’s paid-in capital decreased $9 million due to the cashless exercise of stock options by its employees in the first nine months of 2004. See Note 5 - Long-term Debt and Equity Financings for further information.


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UE's paid-in capital increased by $13 million as of September 30, 2004, to reflect a contribution received from Ameren as a result of the parent holding company's allocation of its income tax benefit.

Genco’s paid-in capital increased by $75 million as of September 30, 2004 as compared to December 31, 2003, as a result of a capital contribution from its parent that was used in Noovember 2004 to prepay a portion of the note due to CIPS.

CILCO’s paid-in capital increased by $75 million as of September 30, 2004, as compared to December 31, 2003, as a result of a capital contribution from its parent that was used to reduce short-term borrowings.

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 shareholders. A reconciliation of net income to comprehensive income for the three months and nine months ended September 30, 2004 and 2003 is shown below for the Ameren Companies:

	Three Months Ended					Nine Months Ended
	2004		2003			2004		2003
Ameren:^(a)
Net income	$	232	$	275		$	447	$	486
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $3, $(1), $15, $(3)		10		(3	)		16		(8	)
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $(2), $-, $(1), $1		5		-			1		(2	)
Total comprehensive income, net of taxes	$	247	$	272		$	464	$	476
UE:
Net income	$	182	$	225		$	349	$	400
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $(1), $3, $(2)		2		-			5		(2	)
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $-, $-, $-, $-		-		-			-		(1	)
Total comprehensive income, net of taxes	$	184	$	225		$	354	$	397
CIPS:
Net income	$	23	$	26		$	41	$	31
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $2, $-, $4, $(1)		2		(1	)		6		(3	)
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $-, $-, $-, $-		1		-			-		-
Total comprehensive income, net of taxes	$	26	$	25		$	47	$	28

Genco:
Net income	$	29	$	17		$	75		$	65
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(1), $-, $(1), $-		-		(1	)		(1	)		(1	)
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $-, $-, $-, $-		-		-			(1	)		-
Total comprehensive income, net of taxes	$	29	$	16		$	73		$	64
CILCORP:^(b)
Net income (loss)	$	2	$	11		$	2		$	23
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $6, $-, $7, $(1)		7		(3	)		12			(4	)
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $(1), $-, $-, $-		2		-			-			-
Total comprehensive income, net of taxes	$	11	$	8		$	14		$	19


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Three Months Ended

Nine Months Ended

2004

2003

2004

2003

CILCO:
Net income	$	9	$	15		$	18		$	55
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $6 $-, $8, $(1)		7		(3	)		13			(4	)
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $-, $-, $-, $-		1		-			(1	)		-
Total comprehensive income, net of taxes		17	$	12			30		$	51

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(b)	2003 amounts include January 2003 predecessor information, which was zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

NOTE 12 - PENSION AND OTHER POSTRETIREMENT BENEFITS

Ameren’s pension plans are funded in compliance with income tax regulations and federal funding requirements. Based on our assumptions at December 31, 2003, in order to maintain minimum funding levels for Ameren’s pension plans, we expected to be required under ERISA to fund an average of approximately $115 million annually from 2005 through 2008, assuming the passage of a law which would be retroactive to January 1, 2004, to extend the temporary interest rate relief. In the third quarter of 2004, we used available cash to make a contribution of $295 million, with available cash, to our defined benefit retirement plans. This contribution will, among other things, provide cost savings to us by eliminating the need to pay insurance premiums to the Pension Benefit Guarantee Corporation. In light of this con tribution and the acquisition of IP, future required contributions are now expected to aggregate $400 million to be paid in 2008 and 2009. These amounts are estimates and may change based on actual stock market performance, changes in interest rates, and any changes in government regulations.

The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts in the first nine months of 2004 and 2003:

	2004		2003
Ameren^(a)	$	295	$	25
UE		186		18
CIPS		33		4
Genco		29		3
CILCORP^(b)		41		-
CILCO		41		-

(a)	Includes amounts for Ameren registrant and non-registrant subsidiaries

(b)	CILCORP consolidates CILCO and therefore included CILCO amounts in its balances.

The following table presents Ameren’s net periodic benefit costs (and the components of those costs) for pension and other postretirement benefits for the three months and nine months ended September 30, 2004 and 2003:

	Pension Benefits												Postretirement Benefits
	Three Months						Nine Months						Three Months						Nine Months
	2004			2003			2004			2003			2004			2003			2004			2003
Service cost	$	10		$	9		$	31		$	28		$	3		$	3		$	10		$	9
Interest cost		33			32			96			98			13			15			41			45
Expected return on plan assets		(30	)		(31	)		(89	)		(95	)		(7	)		(8	)		(23	)		(24	)
Amortization cost:
Transition obligation		-			-			-			-			1			1			3			3
Prior service cost		3			2			9			6			(1	)		(1	)		(3	)		(3	)
Losses		6			2			18			6			7			8			24			25
Net periodic benefit cost	$	22		$	14		$	65		$	43		$	16		$	18		$	52		$	55


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Ameren adopted FSP SFAS 106-2 during the second quarter of 2004, retroactive to January 1, 2004, which resulted in the recognition of a federal subsidy for postretirement benefit costs related to prescription drug benefits. See Note 1 - Summary of Significant Accounting Policies. The effect of this subsidy was a reduction of various components of Ameren’s, and principally UE’s, net periodic postretirement benefit costs for the second and third quarters of 2004. Interest costs and amortization losses were each reduced by $1 million and $5 million for the three and nine months ended September 30, 2004, respectively. Partially offsetting the nine-month amounts was a reduction in the expected return on plan assets of $2 million. The impact of the subsidy on the expected return on plan assets for the third qu arter of 2004 was minimal. The subsidy-related reduction in Ameren’s, and principally UE’s, accumulated postretirement benefit obligation was $71 million.

UE, CIPS, Genco, CILCORP and CILCO are participants in Ameren’s plans and are responsible for their proportional share of the pension benefit costs. The following table presents the pension costs incurred for the three months and nine months ended September 30, 2004 and 2003:

	Three Months				Nine Months
	2004		2003		2004		2003
Ameren^(a)	$	22	$	14	$	65	$	43
UE		15		9		40		27
CIPS		3		2		9		5
Genco		2		1		6		4
CILCORP^(b)		2		2		8		5
CILCO		4		5		13		12

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries.

(b)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

UE, CIPS, Genco, CILCORP and CILCO are participants in Ameren’s plans and are responsible for their proportional share of the postretirement benefit costs. The following table presents the postretirement costs incurred for the three months and nine months ended September 30, 2004 and 2003:

	Three Months				Nine Months
	2004		2003		2004		2003
Ameren^(a)	$	16	$	18	$	52	$	55
UE		10		13		31		39
CIPS		2		2		7		6
Genco		1		-		3		2
CILCORP^(b)		3		3		8		7
CILCO		5		5		14		12

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries.

(b)	Includes predecessor information for January 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

In conjunction with our acquisition of IP, employees of IP have transferred into the Ameren defined benefit and postretirement benefit plans. As such, we have assumed obligations for pension and postretirement benefits, adjusted to fair value, and net of assets transferred to Ameren plans, of approximately $137 million and $102 million, respectively, as of September 30, 2004.


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NOTE 13 - SEGMENT INFORMATION

As discussed in the Ameren Companies combined Form 10-K for the fiscal year ended December 31, 2003, Ameren’s two reportable segments are: (1) Utility Operations, which generates electricity and transmits and distributes gas and electricity and (2) Other, which is comprised of the parent holding company, Ameren Corporation. The operations of IP and the additional 20% ownership interest in EEI will be included in Ameren’s Utility Operations segment.

The table below presents segment information about the reported revenues and net income of Ameren for the three months and nine months ended September 30, 2004 and 2003:

	Utility Operations		Other			Reconciling Items^(a)			Total
Three months 2004:
Operating revenues	$	1,615	$	-		$	(298	)	$	1,317
Net income		247		(15	)		-			232
Three months 2003:
Operating revenues	$	1,648	$	-		$	(295	)	$	1,353
Net income		275		-			-			275
Nine months 2004:
Operating revenues	$	4,563	$	-		$	(878	)	$	3,685
Net income		459		(12	)		-			447
Nine months 2003:^(b)
Operating revenues	$	4,383	$	-		$	(826	)	$	3,557
Net income		496		(10	)		-			486

(a)	Elimination of intercompany revenues.

(b)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.


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ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

OVERVIEW

Executive Summary

Ameren had solid operational performance during the third quarter and first nine months of 2004 and benefited from weather-adjusted demand growth in our service territory and solid margins on excess power sales. However, Ameren earnings per share were down from the prior year periods. This decrease was principally due to unusual gains related to an accounting change and settlement of a dispute with a supplier in the prior year, extremely mild summer weather in 2004, a refueling and maintenance outage at UE’s Callaway nuclear plant in the second quarter of 2004 and greater common shares outstanding as a result of prefunding the acquisition of IP and an additional 20% interest in EEI with approximately $1.3 billion of equity.

The IP acquisition was completed on September 30, 2004, and was a major milestone for Ameren. Completing this acquisition, valued at $2.3 billion, in just eights months permits us to turn our attention to integrating IP’s operations with Ameren’s, realizing the expected synergies and related earnings from the acquisition, and improving IP’s financial condition. Immediately following the announcement of the completion of the transaction, the three major credit rating agencies increased IP’s credit ratings to investment grade, recognizing the actions we had already taken, and plans we have, to strengthen IP’s financial condition. Ameren and IP have already begun this process by calling for redemption, in October 2004, $193 million of IP’s high-cost 11.5% mortgage bonds pursuant to the bonds’ equity clawback provisions. In addition, IP is tendering for the remaining $357 million of IP’s 11.5% mortgage bonds and called $147.8 million in additional debt.

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses and non rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part I, Item 1 of this report for a detailed description of our principal operating subsidiaries. Also, see the Glossary of Terms and Abbreviations.

UE, also known as Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business and a rate-regulated natural gas distribution business in Missouri and Illinois.
CIPS, also known as Central Illinois Public Service Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
Genco, also known as Ameren Energy Generating Company, operates a non rate-regulated electric generation business in Illinois and Missouri.
CILCO, also known as Central Illinois Light Company, is a subsidiary of CILCORP (a holding company) and was acquired on January 31, 2003. It operates a rate-regulated electric transmission and distribution business, a primarily non rate-regulated electric generation business and a rate-regulated natural gas distribution business in Illinois.
IP, also known as Illinois Power Company, was acquired on September 30, 2004. It operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. See Note 2 - Acquisitions to our financial statements under Part 1, Item 1 of this report for further information.

The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the periods ended September 30, 2004 do not reflect IP’s results. However,


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IP’s financial position at September 30, 2004, and the acquisition-related activity were included in Ameren’s Consolidated Balance Sheet at September 30, 2004, and Consolidated Statement of Cash Flows for the nine months ended September 30, 2004. Results of CILCORP and CILCO reflected in Ameren’s consolidated financial statements include the period from January 31, 2003, when these companies were acquired. See Note 2 - Acquisitions for further information. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

In addition to presenting results of operations and earnings amounts in total, certain information is expressed in cents per share. These amounts reflect factors that directly impact Ameren’s earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on Ameren’s earnings. All references in this report of earnings per share are on the basis of diluted shares.

IP Acquisition

On September 30, 2004, Ameren completed the acquisition of all the common stock and 662,924 shares of preferred stock of Decatur, Illinois-based IP and a 20% ownership interest in EEI from Dynegy and its subsidiaries. Ameren acquired IP to complement its existing Illinois gas and electric operations. The purchase included IP's rate-regulated electric and natural gas transmission and distribution business serving approximately 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part I, Item 1 of this report for further information on the presentation of the results of IP in Ameren’s consolidated financial statements. For a discussion of the regulatory agency approvals granted in connection with this acquisition, see Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report.

The total transaction value was approximately $2.3 billion, including the assumption of approximately $1.8 billion of IP debt and preferred stock and consideration, including transaction costs, of $451 million in cash, net of $51 million cash acquired, which, under the terms of the stock purchase agreement, is subject to a final working capital adjustment. Ameren placed $100 million of the cash portion of the purchase price in a six-year escrow pending resolution of certain contingent environmental obligations of IP and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy. See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1 of this report for information on a pending IP environmental matter to which the indemnification and escrow applies. In a ddition, this transaction included a fixed price capacity power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from a subsidiary of Dynegy. The contract was marked to fair value at closing. This agreement is expected to supply about 70% of IP’s electric customer requirements during those two years. IP is currently in the final stages of soliciting bids to supply the remaining 30% of its power needs in 2005 and 2006. This solicitation is expected to be completed by the end of 2004. In the event that any of these suppliers are unable to supply the electricity required by these agreements, IP would be forced to find alternative suppliers to meet is load requirements thus exposing IP to market price risk, which could have a material impact on Ameren's results of operation.. Existing power supply agreements expire on December 31, 2004.

Ameren’s financing plan for funding this acquisition included the issuance of new Ameren common stock. Ameren issued an aggregate of approximately 30 million common shares in February 2004 and July 2004, which generated net proceeds of about $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and are expected to be used to reduce IP debt assumed as part of this transaction and to pay any related premiums. See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1 of this report for information on redemptions and a tender offer instituted with respect to certain IP bonds after the acquisition.

Ameren expects the acquisition of IP to be accretive to earnings in the first two years of ownership based on a variety of assumptions related to power prices, interest rates and synergies, among other things. In November, Ameren and IP announced that they were offering a voluntary separation opportunity to certain groups of IP employees, or approximately 950 of Ameren’s total 9,300 employees. The program is voluntary and offers an enhanced separation benefit and extended medical and dental benefits. Employees must make a decision by December 20, 2004 and will leave the company throughout 2005 based on business needs. The offering of this voluntary separation opportunity is consistent w ith Ameren’s plan for the integration of IP and conditions in the ICC order for the realization of administrative synergies from the acquisition. Costs of the separation are expected to be deferred as a regulatory asset, which is also consistent with the ICC order.


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RESULTS OF OPERATIONS

Earnings Summary

Our results of operations and financial position are affected by many factors. Weather, economic conditions and the actions of key customers or competitors can significantly impact the demand for our services. Our results are also affected by seasonal fluctuations caused by winter heating and summer cooling demand. With approximately 85% of Ameren’s revenues directly subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the price we charge for our services. Our non rate-regulated sales are subject to market conditions for power. We principally utilize coal, nuclear fuel, natural gas and oil in our operations. The prices for these commodities can fluctuate significantly due to the world economic and political environment, weather, supply and demand l evels and many other factors. We do not have fuel or purchased power cost recovery mechanisms in Missouri or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms in each state for our gas delivery businesses. The electric rates for UE are set through June 2006, and are set for CIPS, CILCO and IP through the end of 2006 such that cost decreases or increases will not be immediately reflected in rates. In addition, the gas delivery rates for UE in Missouri are set through June 2006. Fluctuations in interest rates impact our cost of borrowing and pension and postretirement benefits. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems and the level of purchased power cost, operating and administrative costs and capital investment are key factors that we seek to control in order to optimize our results of operations, cash flows and financial position.

Ameren’s net income decreased $43 million to $232 million, or $1.20 per share, in the third quarter of 2004 from $275 million, or $1.70 per share, in the third quarter of 2003. Net income in the third quarter of 2003 included an after-tax gain of $31 million or 19 cents per share related to the settlement of a dispute over coal mine reclamation issues with a coal supplier. This gain primarily represented a return of coal costs accumulated by a coal supplier for reclamation of a coal mine that principally supplied a UE power plant.

Excluding this after-tax gain, Ameren’s third quarter 2004 net income decreased $12 million, or 31 cents per share, from the third quarter of 2003. The decrease in net income was primarily due to abnormally mild summer weather in our service territory in 2004, as compared to 2003, and increased employee benefit costs. Ameren’s earnings per share were additionally reduced due to increased shares outstanding in 2004 as compared to the prior year. The higher shares outstanding were primarily due to common stock offerings in February 2004 and July 2004 to prefund the IP acquisition. Partially offsetting these reductions to income were organic growth in our service territory due to a recovering economy and increased margins on interchange sales due to greater availability of low-cost generation as a result of weather-reduced demand and higher prices.

Ameren’s net income decreased to $447 million, or $2.44 per share for the nine months ended September 30, 2004 compared to year-ago earnings of $486 million, or $3.02 per share. In the first nine months of 2003, net income included the after-tax gain from the settlement of the coal mine reclamation issues of $31 million or 19 cents per share as referenced above and a net cumulative effect gain of $18 million or 11 cents per share associated with the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” The net SFAS No. 143 gain resulted principally from the elimination of non-legal obli gation costs of removal for non rate-regulated assets from accumulated depreciation.

The following table presents the net cumulative effect after-tax gain recorded at each of the Ameren Companies upon adoption of SFAS No. 143:

Net Cumulative Effect After-Tax Gain
Ameren^(a)	$	18
UE		-
CIPS		-
Genco		18
CILCORP^(b)		4
CILCO		24

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(b)	Represents predecessor information recorded in January 2003 prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.


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Excluding the gains on the adoption of SFAS No. 143 and the settlement of the coal mine reclamation dispute in the prior year, Ameren’s net income increased $10 million for the first nine months of 2004 as compared to the same period in 2003. The change in net income was primarily due to organic growth in revenues, increased interchange margins, increased revenues from sales of emission credits, lower labor costs, the Midwest ISO refund of previously paid exit fees upon UE’s and CIPS’ re-entry into the Midwest ISO in the second quarter of 2004 and results of CILCORP being included for an additional month in 2004. Partially offsetting these increases to income were extremely mild 2004 summer weather conditions, increased fuel and purchased power and other operations and maintenance costs as a result of UE’s Callaway nuclear plant refueling and maintenance outage in the second quarter of 2004 and higher employee benefit costs. Increased common shares outstanding reduced Ameren’s earnings per share for the first nine months of 2004, as compared to the same period in 2003.

As a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries, UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the three months and nine months ended September 30, 2004 and 2003. IP was acquired on September 30, 2004, and did not make any contribution to net income or cash flows for the three and nine months ended September 30, 2004 and 2003.

	Three Months						Nine Months
	2004			2003			2004			2003
Net income:
UE^(a)	$	181		$	224		$	345		$	396
CIPS		22			25			39			29
Genco^(a)		29			17			75			65
CILCORP^(b)		2			11			2			14
Other^(c)		(2	)		(2	)		(14	)		(18	)
Ameren net income	$	232		$	275		$	447		$	486

(a)

Includes earnings from interchange sales by Ameren Energy that provided approximately $14 million and $46 million of UE’s net income in the three and nine months ended September 30, 2004, respectively, (2003 - three months - $11 million; nine months - $44 million) and approximately $6 million and $23 million of Genco’s net income in the three and nine months ended September 30, 2004, respectively (2003 - three months - $5 million; nine months - $23 million).

(b)	Excludes net income prior to the acquisition date of January 31, 2003. January 2003 predecessor amount was $9 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

(c)	Includes corporate general and administrative expenses, transition costs associated with the CILCORP acquisition, and other non rate-regulated operations.

Electric Operations

The following table presents the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power, for the three months and nine months ended September 30, 2004, from the comparable periods in 2003. We consider electric margin to be a useful measure to analyze the change in profitability of our electric operations between periods and have included the below analysis as a complement to our financial information provided in accordance with GAAP. However, electric margin may not be a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP information we are providing.

The variation for Ameren reflects the contribution from CILCORP for the January 2004 period as a separate line item, which allows other margin components to be comparable year over year as we owned CILCORP for only eight months in the first nine months of 2003. The variations in CILCORP and CILCO electric margins are for the three months and nine months ended September 30, 2004, as compared to the same periods in 2003.

	Ameren^(a)			UE			CIPS			Genco		CILCORP^(b)			CILCO
Three Months
Electric revenue change:
Effect of weather (estimate)	$	(58	)	$	(40	)	$	(12	)	$	-	$	(5	)	$	(5	)
Growth and other (estimate)		30			14			4			12		(60	)		(60	)
Rate reductions		(10	)		(10	)		-			-		-			-
Interchange revenues		17			11			(2	)		4		2			2
EEI		(11	)		-			-			-		-			-
Total	$	(32	)	$	(25	)	$	(10	)	$	16	$	(63	)	$	(63	)


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Ameren^(a)

CIPS

Genco

CILCORP^(b)

CILCO

Fuel and purchased power change:
Fuel:
Generation and other	$	6		$	2		$	-	$	2		$	(2	)	$	4
Price		9			7			-		2			-			-
Purchased power		(19	)		(7	)		11		(7	)		51			51
EEI		10			-			-		-			-			-
Total	$	6		$	2		$	11	$	(3	)	$	49		$	55
Net change in electric margins	$	(26	)	$	(23	)	$	1	$	13		$	(14	)	$	(8	)

Nine Months
Electric revenue change:
CILCORP - January 2004	$	49		$	-		$	-		$	-		$	-		$	-
Effect of weather (estimate)		(39	)		(26	)		(11	)		-			(2	)		(2	)
Growth and other (estimate)		107			64			(1	)		55			(151	)		(151	)
Rate reductions		(27	)		(27	)		-			-			-			-
Interchange revenues		15			(1	)		(1	)		6			15			15
EEI		(24	)		-			-			-			-			-
Total	$	81		$	10		$	(13	)	$	61		$	(138	)	$	(138	)
Fuel and purchased power change:
CILCORP - January 2004	$	(26	)	$	-		$	-		$	-		$	-		$	-
Fuel:
Generation and other		(13	)		9			-			(17	)		(13	)		(4	)
Price		(7	)		(6	)		-			(1	)		7			7
Purchased power		(34	)		(17	)		20			(5	)		118			115
EEI		4			-			-			-			-			-
Total	$	(76	)	$	(14	)	$	20		$	(23	)	$	112		$	118
Net change in electric margins	$	5		$	(4	)	$	7		$	38		$	(26	)	$	(20	)

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(b)	Includes predecessor information for January 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

Ameren

Ameren’s electric margin decreased $26 million for the three months ended September 30, 2004, but increased $5 million for the nine months ended September 30, 2004, compared to the same periods in 2003. Excluding the additional month of CILCORP results in the current year, electric margin decreased $18 million for the nine months ended September 30, 2004. The decrease in electric margin for the three months ended September 30, 2004, was primarily attributable to extremely mild summer weather in 2004, as compared to 2003, and rate reductions. Weather, rate reductions, increased fuel and purchased power due to the Callaway refueling outage in the second quarter of 2004 and higher fuel costs contributed to the decrease in electric margins in the first nine months of 2004 as compared to the year-ago period. These reductions were partially offset by organic growth due to improved economic conditions in the three and nine months ended September 30, 2004, and increased interchange margins in the third quarter of 2004. Sales of emission credits increased $3 million in the third quarter and $9 million for the first nine months of 2004, as compared to 2003.

According to the National Weather Service, summer weather in Ameren’s service territory was the seventh mildest in the past 109 years. Cooling degree days in 2004 in our service territory were approximately 20% below both normal conditions and the prior year quarter, resulting in a decrease in weather-sensitive residential sales of 9% and slightly lower commercial sales in the current year quarter. For the nine months ended September 30, 2004, warmer winter weather in the first quarter of 2004 also resulted in unfavorable weather conditions. Heating degree days were approximately 9% less in the first three months of 2004 in our service territory, compared to the same period in 2003, and approximately 6% less than normal conditions. Industrial sales decreased 4% in the third quarter of 2004 primarily due to th e expiration of low margin power supply contracts to customers outside of our core service territory. Absent the loss of these contracts, industrial sales grew approximately 2% in the third quarter of 2004. Industrial sales were up slightly for the nine months ended September 30, 2004, as compared to 2003, but were up 4%, excluding the expiring customer contracts.


	68

Rate reductions resulting from the 2002 UE electric rate case settlement in Missouri negatively impacted electric revenues during the current year periods. Annual reductions of $50 million, $30 million and $30 million were effective April 1, 2002, April 1, 2003 and April 1, 2004, respectively.

Interchange margins increased $5 million for the three months ended September 30, 2004, compared to the same period in 2003, due to increased availability of low-cost generation resulting from reduced demand from native load customers due to the mild summer weather. Despite the weather, the current year quarter also benefited from higher power prices as natural gas prices contributed to increased power prices. Average realized power prices on interchange sales increased to approximately $31 per megawatthour in the third quarter of 2004 from approximately $29 per megawatthour in the third quarter of 2003. The third quarter of 2004, Ameren’s base load coal-fired electric generating plants’ average capacity factors were approximately 81%, despite the extremely mild weather, and equivalent avail ability factors were approximately 95%, which were comparable to the prior year period. Interchange margins were comparable for the nine months ended September 30, 2004, compared to the same period in the prior year, as there was little variance in average power prices for the nine-month periods.

Ameren’s fuel and purchased power decreased $6 million in the quarter ended September 30, 2004, but increased $50 million, excluding the additional month of CILCORP, in the nine months ended September 30, 2004, compared to the same periods in 2003. The decrease in the third quarter of 2004 was due primarily to lower fuel costs as a result of increased availability of lower cost generation due to milder weather. The increase in the nine-month period was primarily due to increased power purchases necessitated by the Callaway refueling outage and increased fuel prices.

UE’s electric margin decreased $23 million for the three months ended September 30, 2004, as compared to the same period in 2003. Electric margin decreased $4 million for the first nine months of 2004 compared to the same period in 2003. Residential sales decreased 10% during the third quarter of 2004 due to the extremely mild summer weather, partially offset by organic growth. Rate reductions from the 2002 rate case settlement negatively impacted electric revenues during the current year periods. Interchange margins increased $3 million for the three months ended September 30, 2004, compared to the same period in 2003, and were comparable for the nine-month periods. Sales of emission credits increased $3 million in the current quarter and $18 million for the firs t nine months of 2004, as compared to 2003.

Third quarter 2004 fuel and purchased power were comparable to the prior year in the third quarter, but increased $14 million for the first nine months of 2004 primarily due to increased purchased power (approximately $24 million) resulting from the Callaway refueling outage during the second quarter of 2004, as well as an unplanned outage at the Callaway plant during the first quarter of 2004, partially offset by decreased demand due to mild summer weather conditions in the third quarter of 2004.

CIPS

CIPS’ electric margin was comparable for the third quarter periods of 2004 and 2003. Electric margin increased $7 million for the nine months ended September 30, 2004, as compared to the same period in 2003. The increase in electric margin for the nine month period in 2004 was primarily attributable to reduced purchased power costs as a result of customers switching to Marketing Company and the eliminating of the negative margin associated with one of these customers. Revenues decreased also due to customers switching, as well as unfavorable weather conditions, partially offset by organic growth.

Genco

Genco’s electric margin increased $13 million for the three months and $38 million for the nine months ended September 30, 2004, as compared to the same periods in 2003. Increases in electric margin were primarily attributable to an increase in wholesale margins due to sales to new customers coupled with increased use of lower cost generation that was available as a result of fewer power plant outages in 2004. The increase in wholesale margin was in addition to an increase in interchange margins due to higher power prices and more lower cost power available for sale in the third quarter of 2004 due to the mild weather. Interchange margins were comparable for the three and nine months ended September 30, 2004, as compared to the same periods in 2003.


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CILCORP and CILCO

Electric margin decreased $14 million at CILCORP and $8 million at CILCO for the three months ended September 30, 2004, and decreased $26 million at CILCORP and $20 million at CILCO for the nine months ended September 30, 2004, as compared to the same periods in 2003. Decreases in electric margin versus 2003 were primarily attributable to reduced revenues due to two large CILCO industrial customers switching to Marketing Company in July and October 2003 and transfers of other non rate-regulated customers to Marketing Company (three months - $50 million; nine months - $135 million), along with the extremely mild summer weather conditions. Fuel and purchased power also decreased for the three months and nine months ended September 30, 2004, as compared to the same periods in 2003 due to customers switching within th e Ameren Companies.

Gas Operations

The following table presents the favorable (unfavorable) variations in gas margins, defined as gas revenues less gas purchased for resale, for the three months and nine months ended September 30, 2004, from the comparable periods in 2003. We consider gas margin to be a useful measure to analyze the change in profitability of our gas operations between periods and have included the table below as a complement to our financial information provided in accordance with GAAP. However, gas margin may not be a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP information we are providing.

	Three Months			Nine Months
Ameren^(a)	$	-		$	29
UE		1			7
CIPS		-			5
Genco		-			-
CILCORP^(b)		(1	)		3
CILCO		(1	)		1

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(b)	Includes predecessor information for January 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

Gas margins at Ameren, UE, CIPS, CILCORP and CILCO increased during the nine months ended September 30, 2004, primarily due to delivery rate increases, partially offset by milder winter weather conditions. Ameren’s margin also increased $13 million due to the additional month of CILCORP results in the current year. Excluding the additional month of CILCORP in the current year, Ameren’s sales were down 5% for the nine months ended September 30, 2004, as a result of the mild winter weather conditions.

The following table presents the effect of gas delivery rate increases on revenues for the three months and nine months ended September 30, 2004, from the comparable periods in 2003:

	Three Months		Nine Months
Ameren	$	6	$	21
UE		2		8
CIPS		1		6
Genco		-		-
CILCORP		3		7
CILCO		3		7


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Operating Expenses and Other Statement of Income Items

The following table presents the favorable (unfavorable) variations in operating and other expenses for the three months and nine months ended September 30, 2004, from the comparable period in 2003:

	Ameren^(a)			UE			CIPS			Genco			CILCORP^(b)			CILCO
Three Months
Other operations and maintenance	$	(12	)	$	1		$	4		$	4		$	(15	)	$	(12	)
Coal contract settlement		(51	)		(51	)		-			-			-			-
Depreciation and amortization		(4	)		(2	)		-			-			-			-
Taxes other than income taxes		6			-			-			-			5			5
Other income and deductions		6			1			(1	)		1			-			1
Interest		7			-			-			-			2			(2	)
Income taxes		31			30			(7	)		(6	)		14			11

Nine Months
Other operations and maintenance	$	(55	)	$	(28	)	$	12		$	(3	)	$	(34	)	$	(27	)
Coal contract settlement		(51	)		(51	)		-			-			-			-
Depreciation and amortization		(10	)		(7	)		-			(1	)		9			5
Taxes other than income taxes		7			(4	)		2			2			12			12
Other income and deductions		12			(1	)		(1	)		-			(1	)		(1	)
Interest		12			-			2			4			1			1
Income taxes		31			37			(17	)		(12	)		19			16

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. Includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(b)	Includes predecessor information for January 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

Other Operations and Maintenance

Ameren’s other operations and maintenance expenses increased $12 million for the three months and $55 million for the nine months ended September 30, 2004, as compared to the same periods in 2003. The additional month of CILCORP results included in the nine months ended September 30, 2004, accounted for $15 million of other operations and maintenance expense compared to the same period in 2003, which included only eight months of CILCORP results.

Expenses at Ameren and UE increased during the nine-month period of 2004 primarily due to increased power plant maintenance expenses as a result of the outage at UE’s Callaway nuclear plant during the second quarter of 2004. The outage lasted 64 days and resulted in incremental maintenance costs of approximately $40 million. Refueling outages occur approximately every 18 months and typically include the replacement of fuel and the performance of maintenance and inspections. The last refueling outage occurred in the fall of 2002. In addition to the Callaway nuclear plant outage expenses, employee benefit costs were higher at Ameren and UE during both the quarter and the nine months ended September 30, 2004, primarily due to increased pension costs. The adoption in the second quarter of 2004, retroactive to January 1, 2004, of FASB Staff Position SFAS No. 106-2 resulted in the recognition of nontaxable federal subsidies expected to be provided under the Medicare Prescription Drug, Improvement and Modernization Act, which partially offset employee benefit cost increases in the third quarter and first nine months of 2004. See Note 1 - Summary of Significant Accounting Policies and Note 12 - Pension and Other Postretirement Benefits to our financial statements under Part I, Item 1 of this report for further information. Expenses at Ameren, UE and CIPS were reduced during the nine-month period of 2004 from the refund to UE and CIPS of previously paid exit fees upon our re-entry into the Midwest ISO. Lower labor costs in the current year at Ameren and UE also partially offset the above increases to other operations and maintenance expenses for the three and nine months ended September 30, 2004.

CIPS’ other operations and maintenance expenses decreased in the nine months ended September 30, 2004, as compared to the same periods in 2003, primarily due to CIPS’ portion of the Midwest ISO exit fee refund referenced above and lower labor costs. Other operations and maintenance expenses at CIPS decreased for the third quarter of 2004, as compared to the same period in the prior year, due to decreased labor costs.


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Other operations and maintenance expenses at Genco increased in the nine months ended September 30, 2004, as compared to the same period in 2003, primarily due to increased employee benefit costs, partially offset by lower labor costs. Other operations and maintenance expenses at Genco decreased for the third quarter of 2004, as compared to the same period in the prior year, due to decreased power plant maintenance expenses as a result of fewer plant outages and lower labor costs.

CILCORP’s and CILCO’s other operations and maintenance expenses increased in the three months and nine months ended September 30, 2004, as compared to the same periods in 2003, primarily due to higher employee benefit costs and the settlement of its litigation claim with Enron Power Marketing, Inc. which resulted in a net increase to other operations and maintenance expenses of approximately $8 million. AES indemnified Ameren, and Ameren assigned the indemnification to CILCORP and CILCO for the $13 million after-tax cost of the $21 million claim settlement. As a result, other operations and maintenance expenses in the third quarter of 2004 reflects the net cost of $8 million while income taxes reflect a tax benefit of $8 million, resulting in no net income statement effect. See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1of this report for further information. Partially offsetting these increases to other operations and maintenance expenses were reduced labor costs in the current year.

Coal Contract Settlement

Ameren and UE recorded a coal contract settlement gain of $51 million ($31 million after taxes) in the third quarter of 2003. This gain primarily represented a return of coal costs plus accrued interest accumulated by a coal supplier for reclamation of a coal mine that principally supplied a UE power plant. This mine reclamation is substantially complete. In August 2003, UE entered into a settlement agreement with the coal supplier to return the accumulated reclamation funds, which are being paid to UE ratably through December 2004.

Depreciation and Amortization

Ameren’s and UE’s depreciation and amortization expenses increased for the three months and nine months ended September 30, 2004, due to capital additions. Depreciation and amortization expenses at Ameren also increased for the first nine months of 2004 due to inclusion of the additional month of CILCORP expenses of $6 million.

Depreciation and amortization expenses at CIPS and Genco in the third quarter and first nine months of 2004 were comparable to the same periods in 2003.

Depreciation and amortization expenses at CILCORP and CILCO decreased in the nine months ended September 30, 2004, as compared to the same periods in 2003, primarily due to a lower balance of depreciable property resulting from property retirements exceeding capital additions. Depreciation and amortization expenses at CILCORP and CILCO were comparable in the third quarter of 2004 to the same period in 2003.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased at Ameren in the three and nine months ended September 30, 2004, as compared to the same periods in 2003, primarily due to decreased gross receipts taxes.

UE’s taxes other than income taxes increased in the nine months ended September 30, 2004, as compared to the same period in 2003, primarily due to higher gross receipts and property taxes in 2004. Taxes other than income taxes were comparable in the third quarter of 2004 to the same period in 2003.

Taxes other than income taxes decreased at CIPS and Genco in the nine months ended September 30, 2004, as compared to the same period in 2003, primarily due to reduced property taxes in 2004. Taxes other than income taxes were comparable at CIPS and Genco in the third quarter of 2004 to the same period in 2003.

Taxes other than income taxes decreased at CILCORP and CILCO in the third quarter and nine months ended September 30, 2004, as compared to 2003, primarily due to reduced gross receipts taxes as a result of customers switching to Marketing Company.


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Other Income and Deductions

Ameren’s other income and deductions increased in the third quarter and first nine months of 2004, as compared to the same periods in 2003, primarily due to increased interest income as a result of investing the proceeds from Ameren’s February and July 2004 equity offerings.

Other income and deductions at UE, CIPS, Genco, CILCORP and CILCO were comparable in the third quarter and first nine months of 2004 to the same periods in 2003.

See Note 6 - Other Income and Deductions to our financial statements under Part I, Item 1of this report for further information.

Interest

Interest expense decreased at Ameren in the third quarter and first nine months of 2004, as compared to the same periods in 2003, primarily due to the redemption of Ameren floating rate notes at the end of 2003, as well as redemptions of long-term debt during 2003 at its subsidiaries as noted below.

UE’s interest expense was comparable in the third quarter and first nine months of 2004 to the same periods in 2003.

Interest expense decreased at CIPS in the first nine months of 2004, as compared to the same periods of 2003, primarily due to the maturity or redemption of an aggregate of $90 million principal amount of first mortgage bonds in the second quarter of 2003. Interest expense at CIPS was comparable in the third quarter of 2004 to the same period in 2003.

Genco’s interest expense was reduced in the third quarter and first nine months of 2004, as compared to the same periods of 2003, primarily due to a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren along with decreased borrowings from Ameren’s non state-regulated subsidiary money pool. The balance of intercompany notes to CIPS and Ameren was $358 million at September 30, 2004, as compared to $411 million at both September 30, 2003, and December 31, 2003, and $462 million at December 31, 2002.

Interest expense decreased at CILCO in the first nine months of 2004, as compared to the same periods of 2003, primarily due to the redemption of an aggregate of $175 million principal amount of long-term debt primarily in the second quarter of 2003 and the first quarter of 2004. Interest expense increased at CILCO in the third quarter of 2004, as compared to the same periods of 2003, primarily due to increased borrowings from Ameren’s non state-regulated subsidiary money pool.

Interest expense decreased at CILCORP in the three and nine months ended September 30, 2004, due to redemptions of debt at CILCO as mentioned above and repurchases of an aggregate of $71 million principal amount of CILCORP debt.

Income Taxes

Income tax expense was lower at Ameren for the first nine months and third quarter of 2004, as compared to the same periods in 2003, due to lower pre-tax income combined with a lower effective tax rate. The effective tax rate was reduced primarily due to the recording of the expected nontaxable federal Medicare subsidy in the third quarter and first nine months of 2004, the exercising of stock options by our employees in the current year, and a tax benefit of approximately $8 million related to CILCO’s settlement of its litigation claim with Enron Power Marketing, Inc.

Income tax expense increased at CIPS in the third quarter and first nine months of 2004, as compared to the same periods in 2003, primarily due to higher pre-tax income in the current year periods and an Illinois tax settlement in the third quarter of 2003, which resulted in reduced income taxes in the prior year periods. Income tax expense increased at Genco in the third quarter and first nine months of 2004, as compared to the same periods in 2003, primarily due to higher pre-tax income in the current year periods. Income tax expense decreased at UE primarily due to lower pre-tax income in 2004 and the recording of the expected nontaxable federal Medicare subsidy. Income tax expense decreased at CILCORP and CILCO primarily due to a tax benefit of approximately $8 million as a result of CILCO’s settlement of its litigation claim with Enron Power Marketing, Inc. and otherwise lower pre-tax income in 2004.


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LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows. In addition, we plan to utilize short-term debt to support normal operations and other capital requirements.

The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2004 and 2003:

	Net Cash Provided By (Used In) Operating Activities							Net Cash Provided By (Used In) Investing Activities									Net Cash Provided By (Used In) Financing Activities
	2004		2003		Variance			2004			2003			Variance			2004			2003			Variance
Ameren^(a)	$	736	$	852	$	(116	)	$	(977	)	$	(938	)	$	(39	)	$	777		$	(442	)	$	1,219
UE		529		486		43			(381	)		(308	)		(73	)		(150	)		(172	)		22
CIPS		79		102		(23	)		17			26			(9	)		(108	)		(128	)		20
Genco		115		125		(10	)		(37	)		(39	)		2			(80	)		(87	)		7
CILCORP^(b)		100		75		25			(91	)		(64	)		(27	)		(11	)		(34	)		23
CILCO		84		100		(16	)		(94	)		(67	)		(27	)		7			(52	)		59

(a)	Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(b)	2003 amounts include January 2003 predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

Cash Flows from Operating Activities

Cash flows provided by operating activities decreased for Ameren, CIPS, Genco and CILCO and increased for UE and CILCORP for the nine months ended September 30, 2004 compared to the same period in 2003. Cash flows provided by operating activities for all Ameren Companies were negatively impacted by the incremental cash contributions made to Ameren’s pension plan, as discussed below, during the first nine months of 2004, compared to the same period in 2003. In September 2004, all Ameren Companies received a partial tax refund totaling $55 million (UE - $22 million, CIPS - $6 million, Genco - $4 million, CILCORP - $14 million, CILCO - $9 million) for the cash pension contributions made in 2004 that were applied retroactively to the 2003 tax return. In addition, the pension contribution resulted in a lower third quarter 2004 tax payment.

Decreased earnings for the nine months ended September 30, 2004, compared to the same period in 2003, negatively impacted cash flows provided by operating activities for Ameren, UE, Genco, CILCORP and CILCO. The decrease in earnings resulted principally from the extremely mild summer weather in 2004 compared to the same period in 2003. Higher fuel prices, rate reductions and increased costs due to the Callaway refueling outage also led to the decrease in earnings at Ameren and UE. Cash flows provided by operating activities benefited from cash received by Ameren and UE of $28 million, related to UE’s settlement in 2003 of a dispute over mine reclamation issues with a coal supplier. Increased revenues from the sale of emission credits, primarily att ributed to UE a refund of exit fees for costs incurred related to entering a RTO totaling $8 million (UE - $7 million, CIPS - $1 million) and $26 million (UE - $13 million, CIPS - $5 million) received for an exit fee previously paid to the Midwest ISO, positively impacted the cash flows from operations for Ameren, UE and CIPS.

Pension Funding

Based on our assumptions at December 31, 2003, and in order to maintain minimum funding levels for Ameren’s pension plan, we expected to be required under ERISA to fund an average of approximately $115 million annually from 2005 through 2008 assuming the passage of a law which would be retroactive to January 1, 2004, to extend the temporary interest rate relief. In September 2004, we used available cash to make a contribution of $295 million to our defined benefit retirement plans. This contribution will, among other things, provide cost savings to us from eliminating the need to pay insurance premiums to the Pension Guarantee Trust Corporation and will mitigate future benefit cost increases. In light of this contribution and the acquisition of IP, future required contributions are now expected to

aggregate $400 million to be paid in 2008 and 2009. These amounts are estimates and may change based on actual stock market performance, changes in interest rates, and any changes in government regulations. See Note 12 - Pension and Other Postretirement Benefits to our financial statements under Part 1, Item 1of this report for further detail.

Cash Flows from Investing Activities

Cash flows used in investing activities increased for all Ameren Companies with the exception of Genco for the nine months ended September 30, 2004 as compared to the same period in 2003. Ameren’s increase in cash used in investing activities was primarily due to $451 million in cash paid for the acquisition of IP and the 20% interest in EEI in 2004 compared to $489 million for the cash paid for the acquisitions of CILCORP and Medina Valley in early 2003. Excluding the acquisition costs described above, Ameren’s cash flows used in investing activities increased for the nine months ended September 30, 2004 comp ared to the same period in 2003 due to higher construction expenditures at UE, CILCORP and CILCO.

UE’s construction expenditures for the nine months ended September 30, 2004 primarily included replacement of condenser bundles and low pressure rotor equipment, and other upgrades, completed during the refueling and maintenance outage at UE’s Callaway nuclear plant. In addition, UE’s construction expenditures included upgrades at other UE power plants and expenditures for new transmission and distribution lines. CILCORP’s and CILCO’s construction expenditures were also primarily related to power plant upgrades that were made in order for CILCO’s non rate-regulated subsidiary, AERG, to have more flexibility in future fuel supply for power generation. Cash flows provided by investing activities for CIPS decreased for the nine months ended September 30, 2004, compared to the same period in 2003, primarily due to lower cash receipts related to CIPS’ intercompany note receivable with Genco in the first nine months of 2004, which totaled $49 million compared to $62 million in the first nine months of 2003. Genco’s decrease in cash flows used in investing activities primarily resulted from reduced construction expenditures in the first nine months of 2004 as compared to the same period in 2003. Genco’s construction expenditures in 2004 included costs primarily associated with the replacement of a turbine generator at one of its power plants.

In conjunction with the acquisition of IP on September 30, 2004, we committed to make $275 million to $325 million in energy infrastructure expenditures for IP over the next two years through 2006.

We continually review our generation portfolio and expected electrical needs, and as a result, we could modify our plan for generation capacity, which could include the timing of when certain assets will be added to, or removed from, our portfolio, the type of generation asset technology that will be employed, or whether capacity may be purchased, among other things. Any changes that we plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.

Cash Flows from Financing Activities

Ameren

Ameren’s cash flows from financing activities increased for the nine months ended September 30, 2004, as compared to the same period in 2003. In February 2004, Ameren received net proceeds of $853 million from the issuance of 19.1 million common shares. This issuance substantially depleted all of the capacity under Ameren’s August 2002 SEC Form S-3 shelf registration statement. In June 2004, the SEC declared effective a Form S-3 shelf registration statement filed by Ameren covering the offering from time to time of up to $2 billion of various forms of securities including long-term debt, trust preferred securities and equity securities. In July 2004, Ameren issued, pursuant to the June 2004 Form S-3 shelf registration statement, 10.9 million shares of its common stock that generated net proceeds of $445 million. The proceeds from these common share issuances were used to pay the cash portion of the purchase price for Ameren’s acquisition of IP and Dynegy’s 20% interest in EEI. During the first nine months of 2004, these proceeds were temporarily used to repay a $100 million bank term loan at CILCO, repay short term debt of approximately $181 million, and invested in short-term investments. Following the acquisition, Ameren intends to contribute at least $750 million to IP in the form of an equity contribution, $250 million of which was contributed in October 2004. These proceeds will be used by IP to retire debt through the end of 2006, which is discussed below. The proceeds from Ameren’s common stock issuances in the first quarter of 2003 were used to fund a portion of the acquisitions of CILCORP in January 2003 and Medina Valley in February 2003. See Note 2 - Acquisitions and Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1 of this rep ort for further information. In

addition, Ameren’s increase in cash flows from financing activities was due to a decrease in redemptions, repurchases and maturities of short-term debt, long-term debt and preferred stock totaling $582 million in the first nine months of 2004 compared to $917 million in the same period in 2003.

The increase in cash flows from financing activities at Ameren described above was partially offset by the redemption and termination of UE’s nuclear fuel lease, totaling $67 million in the first nine months of 2004, compared to $38 million in the same period in 2003. Due to the increase in the number of common shares outstanding, Ameren’s dividend payments on common stock increased during the nine months ended September 30, 2004, compared to the same period in 2003, which also caused a decrease in Ameren’s cash flows provided by financing activities.

UE’s cash flows used in financing activities decreased for the nine months ended September 30, 2004, as compared to the same period in 2003. In 2004, cash provided by borrowings from the utility money pool arrangement of $189 million and long-term debt issuances of $404 million were used for repurchases of short-term and long-term debt and the nuclear fuel lease termination payment. The lease agreement, which was scheduled to expire on August 31, 2031, provided for the financing of a portion of UE’s nuclear fuel that was processed for use or was consumed at UE’s Callaway nuclear plant. UE’s decrease in cash flows used in financing activities was partially offset by an increase in dividend payments made to Ameren.

CIPS

CIPS’ cash flows used in financing activities decreased for the nine months ended September 30, 2004, principally due to $60 million of repayments to the utility money pool arrangement in 2004 compared to $23 million of borrowings from the money pool arrangement in 2003. The net decrease in cash provided by the money pool arrangement in 2004 was partially offset by a decrease in redemptions of long-term debt in the first nine months of 2004, compared to the same period in 2003, and reduced dividend contributions to Ameren, which totaled $46 million in the first nine months of 2004, compared to $54 million in the same period of 2003.

Genco

Genco’s cash flows used in financing activities decreased for the nine months ended September 30, 2004, as compared to the same period in 2003, primarily due to increased repayments to the money pool arrangement and increased dividend payments to Ameren totaling $102 million in 2004 compared to $36 million in 2003. The increase in repayments to the money pool arrangement was primarily offset by a capital contribution totaling $75 million received indirectly from Ameren in the third quarter of 2004. The capital contribution received by Genco in the third quarter of 2004 will be for Genco’s prepayment of $75 million of the principal amount outstanding under its intercompany note payable to CIPS.

As of September 30, 2004, Genco had affiliate notes payables of $324 million and $34 million to CIPS and Ameren, respectively, which, by their current terms, have final payments of principal and interest due on May 1, 2005. In November 2004, Genco made a $75 million principal prepayment under its note payable to CIPS. The note payable to CIPS was issued in conjunction with the transfer of its electric generating assets and related liabilities to Genco. Genco and CIPS expect to renew or modify the CIPS note to extend the principal maturity, which could include continued amortization of the principal amount. However, such extension could require regulatory approval. Genco and Ameren are currently evaluating various alternatives with respect to the note payable to Ameren. In the event the maturities of these notes ar e not extended or restructured, whether due to not obtaining the necessary regulatory approvals or otherwise, Genco may need to access other financing sources to meet the maturity obligation to the extent it does not have cash available from its operating cash flows. Such sources of financing could include borrowings under the non state-regulated subsidiary money pool, or infusion of equity capital or new direct borrowings from Ameren, all subject to applicable regulatory financing authorizations and provisions in Genco’s senior note indenture.

CILCORP

CILCORP’s cash flows used in financing activities decreased for the nine months ended September 30, 2004, as compared to the same period in 2003. The decrease was primarily due to a $75 million capital contribution from Ameren and a decrease in repurchases of long-term debt. Borrowings from the utility money pool arrangement, temporarily funded by Ameren’s issuance of common stock in February 2004, were the primary source of funds for the repayment of CILCO’s $100 million secured bank term loan. Dividends were $18 million in 2004 compared to $10 million in 2003.

CILCO

CILCO’s cash flows from financing activities increased for the nine months ended September 30, 2004, as compared to the same period in 2003, primarily due to reduced dividend contributions made to CILCORP in 2004, compared to 2003, and a $75 million capital contribution received indirectly from Ameren in the third quarter of 2004 . CILCO’s increase in cash flows from financing activities was offset by reduced borrowings from the utility money pool arrangement in 2004, compared to the same period in 2003. The proceeds borrowed by CILCO under the utility money pool arrangement, along with available cash in the first quarter of 2004 were used to repay CILCO’s $100 million bank term loan facility.

Short-term Borrowings and Liquidity

Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities generally within 1 to 45 days. As of September 30, 2004, certain Ameren subsidiaries had short-term borrowings totaling $30 million, $28 million of which were borrowed by EEI. The average short-term borrowings for Ameren and its subsidiaries were $16 million for the nine months ended September 30, 2004, with a weighted-average interest rate of 1.8%. Peak short-term borrowings for Ameren and its subsidiaries were $44 million for the nine months ended September 30, 2004, with an interest rate of 1.7%. UE, CIPS, Genco, CILCORP and CILCO had no external short-term borrowings as of September 30, 2004 and CIPS, Genco, CILCORP and CILCO had no external short-term borrowings at December 31, 2003. At December 31, 2003, Ameren on a consolidated basis and UE had short-term borrowings outstanding, which totaled $161 million and $150 million, respectively. At the completion of the acquisition of IP on September 30, 2004, IP had no external short-term borrowings outstanding.

In July 2004, Ameren entered into two new credit agreements for a total of $700 million in revolving credit facilities to be used for general corporate purposes, including support of Ameren and UE commercial paper programs. The $700 million in new facilities includes a $350 million three-year revolving credit facility and a $350 million five-year revolving credit facility. These new credit facilities replaced Ameren’s existing $235 million 364-day revolving credit facility, which matured on July 14, 2004, and a $130 million multi-year revolving credit facility, which would have matured in July 2005. In September 2004, an existing Ameren $235 million multi-year revolving credit facility, which matures in July 2006, was amended and restated to accommodate Ameren’s acquisition of IP and to conform with its two credit agreements entered into in July 2004.

At September 30, 2004, certain of the Ameren Companies had committed bank credit facilities totaling $1,164 million, all of which were available for use, subject to applicable regulatory short-term borrowing authorizations, by UE, CIPS, CILCO, IP and Ameren Services through a utility money pool arrangement. In addition, $935 million of the $1,164 million was available for use, subject to applicable regulatory short-term borrowing authorizations, by Ameren directly, and by most of the non rate-regulated affiliates including, but not limited to, Resources Company, Genco, Marketing Company, AFS, AERG and Ameren Energy, through a non state-regulated subsidiary money pool agreement. We have money pool agreements with and among our subsidiaries to coordinate and provide for certain short-term cash and working capital re quirements. Separate money pools are maintained between rate-regulated and non rate-regulated entities. On September 30, 2004, our utility money pool agreement was amended to add IP as a party. Also, on September 30, 2004, a unilateral borrowing agreement was entered into between Ameren, IP and Ameren Services, which enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money pool agreement may not exceed $500 million pursuant to authorizations from the ICC and the SEC, under the PUHCA. Ameren Services is responsible for operation and administration of the agreement. See Note 8 - Related Party Transactions to our financial statements under Part 1, Item 1, of this report for further discussion of the money pool arrangements and the unilateral borrowing agreement. The committed bank credit facilities are used to support our commercial paper programs under

which no amounts were outstanding at September 30, 2004 (December 31, 2003 - $150 million). Access to our credit facilities for any of Ameren’s subsidiaries is subject to reduction based on use by affiliates.

The following table presents the various committed credit facilities of the Ameren Companies and EEI as of September 30, 2004:

Credit Facility	Expiration	Amount Committed	Amount Available
Ameren:^(a)
Multi-year revolving	July 2006	$ 235	$ 235
Multi-year revolving	July 2007	350	350
Multi-year revolving	July 2009	350	350
UE:
Various 364-day revolving	through July 2005	154	154
CIPS:
Two 364-day revolving	through July 2005	15	15
CILCO:
Three 364-day revolving	through August 2005	60	60
EEI:
Two bank credit facilities	through June 2005	45	17
Total		$ 1,209	$ 1,181

(a)	CILCORP and Genco may access the credit facilities through intercompany borrowing arrangements.

In addition to committed credit facilities, a further source of liquidity for the Ameren Companies is available cash and cash equivalents.

Ameren and UE are authorized by the SEC under the PUHCA to have up to an aggregate of $1.5 billion and $1 billion, respectively, of short-term unsecured debt outstanding at any time. In addition, CIPS, CILCORP and CILCO each have PUHCA authority to have up to an aggregate of $250 million each of short-term unsecured debt outstanding at any time. IP has PUHCA authority to have up to an aggregate of $500 million of short-term unsecured debt outstanding at any time. Genco is authorized by the FERC to have up to $300 million of short-term debt outstanding at any time.

Long-term Debt, Preferred Stock and Equity

The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt and preferred stock for the nine months ended September 30, 2004 and 2003. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1 of this report.

		Nine Months Ended September 30,
	Month Issued, Redeemed, Repurchased or Matured	2004		2003
Issuances
Long-term debt
UE:
5.10% Senior secured notes due 2019	September	$	300	$	-
5.50% Senior secured notes due 2014	May		104		-
4.75% Senior secured notes due 2015	April		-		114
5.50% Senior secured notes due 2034	March		-		184
5.10% Senior secured notes due 2018	July		-		200
Total Ameren and subsidiary long-term debt issuances		$	404	$	498
Common stock, gross proceeds
Ameren:
6,325,000 Shares at $40.50	January	$	-	$	256
19,063,181 Shares at $45.90	February		875		-
10,925,000 Shares at $42.00	July		459
DRPlus and 401(k)^(a)	Various		84		80
Total Ameren common stock issuances		$	1,418	$	36
Total Ameren and subsidiary long-term debt and common stock issuances		$	1,822	$	834

			Nine Months Ended September 30,
	Month Issued, Redeemed, Repurchased or Matured		2004		2003
Redemptions, Repurchases and Maturities
Long-term debt
UE:
6.87% First mortgage bonds due 2004	August	$	188	$	-
7.00% First mortgage bonds due 2024	June		100		-
8 ¼% First mortgage bonds due 2022	April		-		104
8.00% First mortgage bonds due 2022	May		-		85
7.65% First mortgage bonds due 2003	July		-		100
7.15% First mortgage bonds due 2023	August		-		75
CIPS:
6.99% Series 97-1 first mortgage bonds due 2003	March	$	-	$	5
6 3/8% Series Z first mortgage bonds due 2003	April		-		40
7 1/2% Series X first mortgage bonds due 2007	April		-		50
CILCORP:
9.375% Senior bonds due 2029	Various		23		-
8.70% Senior notes due 2009	September
CILCO:
Secured bank term loan	February	$	100	$	-
6.82% First mortgage bonds due 2003	February		-		25
8.20% First mortgage bonds due 2022	April		-		65
7.80% Two series of first mortgage bonds due 2023	April		-		10
Hallock bank loan due through 2004	August				3
Kickapoo bank loan due through 2004	August				2
EEI:
2000 bank term loan due 2004	June	$	40	$	-
Medina Valley:
Secured term loan due 2019	June	$	-	$	36

Preferred Stock
CILCO:
5.85% Series	July	$	1	$	1
Total Ameren and subsidiary long-term debt and preferred stock redemptions, repurchases and maturities		$	452	$	649

(a)	Includes issuances of common stock of 1.8 million shares in the first nine months of 2004 and 1.9 million shares in the first nine months of 2003 under our DRPlus and in connection with our 401(k) plans.

Ameren

In February 2004, Ameren issued, pursuant to an August 2002 SEC Form S-3 shelf registration statement, 19.1 million shares of its common stock at $45.90 per share for net proceeds of $853 million. This issuance substantially depleted all of the capacity under the August 2002 shelf registration statement. In June 2004, the SEC declared effective a Form S-3 shelf registration statement filed by Ameren covering the offering from time to time of up to $2 billion of various types of securities including long-term debt, trust preferred securities and equity securities. In July 2004, Ameren issued, pursuant to the June 2004 Form S-3 shelf registration statement, 10.9 million shares of its common stock at $42.00 per share for net proceeds of $445 million. The proceeds from bot h these offerings were used to pay the cash portion of the purchase price for our acquisition of IP and Dynegy's 20% interest in EEI and, as described below, are expected to be used to reduce IP debt assumed as part of the acquisition and to pay any related premiums. See Note 2 - Acquisitions to our financial statements under Part I, Item 1 of this report for further information.

prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder. At October 31, 2004, the amount remaining under the June 2004 shelf registration statement was $1.5 billion.

The purchase of IP on September 30, 2004, included the assumption of IP debt and preferred stock at closing of approximately $1.8 billion. The assumed debt and preferred stock included $936 million of first mortgage bonds, $509 million of pollution control indebtedness supported by mortgage bonds, $352 million of TFNs issued by IP SPT and $13 million of preferred stock. Upon acquisition, total IP debt was increased to fair value by approximately $191 million, which included early debt redemption premiums. The adjustment to the fair value of each debt series is being amortized over its remaining life or to the expected redemption date, to interest expense.

In October 2004, pursuant to an equity clawback provision of the related bond indenture, IP unconditionally called for redemption on November 15, 2004, $192.5 million in principal amount of its mortgage bonds 11.50% Series due 2010 at a price equal to $1,115 per $1,000 principal amount of bonds, together with accrued and unpaid interest to the redemption date. Ameren made an equity contribution of $250 million into IP to provide funds for this purpose and to satisfy indenture provisions related to the equity clawback. Also in October 2004, IP made a cash tender offer for the remaining mortgage bonds 11.50% Series due 2010 ($357.5 million in aggregate principal amount). The purchase price will be determined, as described in the offer to purchase, in accordance with standard market practice by reference to a yield of 50 basis points over the yield on the 2.625% U.S. Treasury Note due November 15, 2006, on the price determination date, scheduled for November 18, 2004. The tender offer is scheduled to expire on November 22, 2004. This tender offer is also intended to satisfy IP’s indenture obligation to offer to purchase the bonds resulting from the change of control of IP with its acquisition by Ameren. Any such bonds tendered will be purchased with cash contributed as equity to IP by Ameren.

UE issued securities totaling $404 million in 2004, pursuant to its September 2003 SEC Form S-3 shelf registration statement with the amount of securities remaining available for issuance at September 30, 2004, under such registration statement, totaling $396 million.

Indebtedness Provisions, Other Covenants and Off-Balance Sheet Arrangements

See Note 4 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1 of this report for a discussion of the indebtedness provisions contained in certain of the Ameren Companies’ bank credit facilities. Also see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1 of this report for a discussion of off-balance sheet arrangements and of the covenants and provisions contained in certain of the Ameren Companies’ and IP’s indenture agreements and articles of incorporation.

At September 30, 2004, the Ameren Companies, IP and EEI were in compliance with the provisions and covenants of their credit agreements, indentures and articles of incorporation.

We rely on the short-term and long-term capital markets as a significant source of funding for capital requirements not satisfied by our operating cash flows. Our inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain or grow our businesses. Based on our current credit ratings, we believe that we will continue to have access to the capital markets. However, events beyond

our control may create uncertainty in the capital markets such that our cost of capital would increase and/or our ability to access the capital markets would be adversely affected. All of the Ameren Companies and IP expect to fund maturities of long-term debt and contractual obligations through a combination of cash flow from operations and external financing.

Dividends

The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s Board of Directors. Ameren’s Board of Directors has not set specific targets or payout parameters when declaring common stock dividends. However, the Board considers various issues including Ameren’s historic earnings and cash flow, projected earnings, cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics and overall business considerations. Dividends paid by Ameren to stockholders during the first nine months of 2004 totaled $356 million, or $1.905 per share (2003 - $308 million or $1.905 per share). On October 8, 2004, Ameren declared a quarterly d ividend of 63.5 cents, payable December 31, 2004, to shareholders of record on December 8, 2004.

IP’s Board of Directors declared quarterly preferred stock dividends totaling $1 million payable November 1, 2004, to shareholders of record on October 11, 2004.

Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, provide restrictions on the Ameren Companies’ and IP’s payment of dividends. Ameren would experience restrictions on dividend payments if it were to defer contract adjustment payments on its equity security units. UE would experience restrictions on dividend payments if it were to extend or defer interest payments on its subordinated debentures. CIPS has provisions restricting dividend payments based on ratios of common stock to total capitalization along with provisions related to certain operating expenses and accumulations of earned surplus. Genco’s indenture includes restrictions which prohibit making any dividend paym ents if debt service coverage ratios are below a defined threshold. CILCORP has restrictions in the event leverage ratio and interest coverage ratio thresholds are not met or if CILCORP’s senior long-term debt does not have specified ratings as described in its indenture. CILCO has restrictions on dividend payments relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock and amounts to be set aside for any sinking fund retirement of its 5.85% Series preferred stock. In its approval of the acquisition of IP by Ameren, the ICC issued an order which restricts the payment of dividends on its common stock to $80 million in 2005 and $160 million cumulatively through 2006, provided IP has achieved an investment grade credit rating from S&P or Moody’s. If IP’s mortgage bonds 11.50% Series due 2010 are not eliminated by December 31, 2006, IP may not thereafter declare or pay common dividends without seeking authority from the ICC. In additi on, in accordance with the order issued by the ICC, IP will establish a dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities consistent with achieving and maintaining a common equity to total capitalization ratio between 50% and 60%.

The following table presents dividends paid directly or indirectly to Ameren by its subsidiaries for the nine months ended September 30, 2004 and 2003:

	Nine Months Ended September 30,
	2004		2003
UE	$	230	$	224
CIPS		46		54
Genco		57		22
CILCORP (parent company only)^(a)		-		(34	)
CILCO		10		44
Non-registrants		13		-
Dividends paid to Ameren	$	356	$	310

(a)	Indicates funds retained from CILCO dividend.

Contractual Obligations

The following table presents our December 31, 2003 contractual obligations, which have been updated to include IP contractual obligations subsequent to September 30, 2004. In addition, our other obligations were only updated for any material changes since December 31, 2003. For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2003. See Note 12 - Pension and

Other Postretirement Benefits to our financial statements under Part I, Item 1 of this report for information regarding expected minimum funding levels for our pension plan.

	Total		2004		2005 - 2006		2007 - 2008		Thereafter
Ameren^(a):
Long-term debt and capital lease obligations^(b)	$	6,449	$	263	$	466	$	783	$	4,937
Short-term debt		31		31		-		-		-
Interest payments^(c)		4,624		316		762		645		2,901
Operating leases^(d)		211		24		39		31		117
Other obligations^(e)		4,266		1,279		1,914		842		231
Total cash contractual obligations^(f)	$	15,581	$	1,913	$	3,181	$	2,301	$	8,186
UE:
Long-term debt and capital lease obligations	$	2,154	$	88	$	6	$	156	$	1,904
Short-term debt		-		-		-		-		-
Interest payments^(c)		1,496		99		182		175		1,040
Operating leases^(d)		128		9		19		18		82
Other obligations^(e)		1,736		501		751		403		81
Total cash contractual obligations^(f)	$	5,514	$	697	$	958	$	752	$	3,107
CIPS:
Long-term debt	$	486	$	20	$	20	$	15	$	431
Short-term debt		-		-		-		-		-
Interest payments		425		31		59		56		279
Operating leases^(d)		-		-		-		-		-
Other obligations^(e)		174		79		89		6		-
Total cash contractual obligations^(f)	$	1,085	$	130	$	168	$	77	$	710
Genco:
Long-term debt	$	700	$	-	$	225	$	-	$	475
Short-term debt		-		-		-		-		-
Interest payments		769		56		92		78		543
Operating leases^(d)		42		2		5		4		31
Other obligations^(e)		936		205		365		262		104
Total cash contractual obligations^(f)	$	2,447	$	263	$	687	$	344	$	1,153
CILCORP:
Long-term debt^(b)	$	641	$	-	$	16	$	50	$	575
Short-term debt		-		-		-		-		-
Interest payments		730		47		93		86		504
Operating leases^(d)		9		2		3		2		2
Other obligations^(e)		494		209		200		71		14
Total cash contractual obligations^(f)	$	1,874	$	258	$	312	$	209	$	1,095
CILCO:
Long-term debt	$	138	$	-	$	16	$	50	$	72
Short-term debt		-		-		-		-		-
Interest payments		98		9		17		10		62
Operating leases^(d)		9		2		3		2		2
Other obligations^(e)		494		209		200		71		14
Total cash contractual obligations^(f)	$	739	$	220	$	236	$	133	$	150

(a)	Includes amounts for registrant and non-registrant Ameren subsidiaries, including IP, and intercompany eliminations.

(b)	Includes fair market value adjustments of long-term debt for IP and CILCORP totaling $191 million and $85 million, respectively.

(c)	The variable rate debt has been calculated using the interest rate as of September 30, 2004.

(d)

Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The $2 million annual obligation for these items is included in the 2004, 2005 - 2006 and 2007 - 2008 columns. Amounts for more than 5 years are not included in the total amount due to the indefinite periods.

(e)	Represents purchase contracts for coal, gas, nuclear fuel and electric capacity for the Ameren Companies. Also includes power purchase agreements, contracts for firm transportation and storage services for natural gas, gas purchase commitments and decommissioning obligations at IP.

(f)	Routine short-term purchase order commitments are not included.

Credit Ratings

On July 30, 2004, S&P affirmed its A- long-term corporate credit ratings on Ameren, UE, CIPS, Genco, CILCORP and CILCO and removed the ratings from CreditWatch with negative implications. The A-2 short-term credit for Ameren and UE were not on CreditWatch. The outlook is negative for the long-term ratings.

On July 8, 2004, Moody’s confirmed Ameren’s A3 senior unsecured debt and bank loan ratings along with its A3 issuer rating. Moody’s outlook for these ratings is stable. This rating action concluded the review of Ameren's long-term ratings that was initiated on February 4, 2004 in connection with Ameren's agreement to purchase IP from Dynegy. Ameren's Prime-2 rating for short term debt, including commercial paper, was not under review, and was affirmed.

On October 1, 2004, S&P raised it corporate credit rating on IP from B to A- as a result of the completed acquisition of IP by Ameren. At the same time, S&P removed the rating from CreditWatch with positive implications and assigned a negative outlook to the rating. Also on this date, Moody’s upgraded the senior secured debt rating of IP from Ba3 to Baa3 also as a result of the closing of the acquisition. Moody’s has a stable outlook assigned to this rating. The new ratings assigned to IP by S&P and Moody’s are investment grade.

Any adverse change in the Ameren Companies’ or IP’s credit ratings may reduce their access to capital and/or increase the costs of borrowings resulting in a negative impact on earnings. At September 30, 2004, if the Ameren Companies were to receive a sub-investment grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP and CILCO could have been required to post collateral for certain trade obligations amounting to $57 million, $21 million, $-, $4 million, $1 million and $1 million, respectively. In addition, the cost of borrowing under our credit facilities would increase or decrease based on credit ratings. A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratin gs are subject to revision or withdrawal at any time by the assigning rating organization.

OUTLOOK

We expect the following industry-wide trends and company-specific issues to impact earnings in 2004 and beyond:

Economic conditions, which principally impact native load demand, particularly from our industrial customers, were weak for the past few years, but have improved in 2003 and 2004.
Ameren, UE, CIPS and IP have historically achieved weather-adjusted growth in their native electric residential and commercial load of approximately 2% per year and expect this trend to continue for at least the next few years.
Electric rates in UE’s, CIPS’, CILCO’s and IP’s Illinois service territories are legislatively fixed through January 1, 2007. An electric rate case settlement in UE’s Missouri service territory has resulted in annual reductions of $50 million, $30 million and $30 million on April 1, 2002, April 1, 2003, and April 1, 2004, respectively. In addition, electric rates in Missouri cannot change prior to July 1, 2006, subject to certain exclusions outlined in UE’s rate settlement.
The ICC conducted workshops in 2004 seeking input from interested parties on the framework for retail rate determination and the framework for generation procurement by customers after the current Illinois rate freeze ends in 2006. We actively participated in these workshops and supported a framework that would have all regulated Illinois electric transmission and distribution companies bid out their native load requirements for generation through an auction process. We have also supported a structure that provides for recovery from customers of the generation costs resulting from that auction. We expect the ICC to issue a report on the workshop process later this year, but we do not believe the ICC will make decisions on the final regulatory structure until sometime in 2005, after Ameren and other comp anies submit filings detailing their post-2006 plans.
Power prices in the Midwest impact the amount of revenues UE, Genco and CILCO can generate by marketing any excess power into the interchange markets. Power prices in the Midwest also impact the cost of power we purchase in the interchange markets. There continues to be overcapacity in peaking generation in the Midwest. However, power prices increased in 2004 and 2003 relative to 2002, due in part to higher prices for natural gas.
We expect to see increases in both the commodity cost of coal and transportation costs based on current market trends. In 2005 and 2006, we expect these increases to approximate two to three percent per year based on the fixed prices embedded in our contracts.

Increased expenses associated with rising employee benefit costs and higher insurance and security costs associated with additional measures UE has taken, or may have to take, at its Callaway nuclear plant and other operating plants related to world events.
UE’s Callaway nuclear plant will have a refueling outage in the fall of 2005. Refueling outages occur approximately every 18 months and typically include the replacement of fuel and the performance of maintenance and inspections. Routine refueling outages have historically lasted 30 - 35 days. If inspections discover items requiring additional maintenance, the outage period could be longer, and cost significantly more, than expected. UE’s fall 2005 refueling outage is expected to last 70 - 75 days and is expected to be higher in cost due to the installation of new steam generator units and turbine rotors.
In January 2004, the MoPSC approved a settlement with UE authorizing an annual gas delivery rate increase of approximately $13 million, which went into effect on February 15, 2004. The settlement provides that gas delivery rates cannot change prior to July 1, 2006, subject to certain exclusions. In October 2003, the ICC issued orders awarding CILCO an increase in annual gas delivery rates of $9 million and awarding CIPS and UE increases in annual gas delivery rates of $7 million and $2 million, respectively which went into effect in November 2003. IP has filed with the ICC for a $36 million gas rate increase. The ICC must make a decision by May 2005. In the order approving Ameren's acquisition of IP, the ICC prohibits IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond IP's pending request for a gas delivery rate increase.
Ameren, UE, CIPS and IP will incur higher ongoing operational costs and may lose some revenue as a result of participating in the Midwest ISO. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for additional information.
Ameren, CILCORP and CILCO expect to realize further CILCORP integration synergies associated with reduced overhead expenses and lower fuel costs.
Ameren expects the acquisition of IP to be accretive to earnings in the first two years of ownership based on a variety of assumptions related to power prices, interest rates and expected synergies, among other things.

In the ordinary course of business, we evaluate strategies to enhance our financial position, results of operations and liquidity. These strategies may include potential acquisitions, divestitures, and opportunities to reduce costs or increase revenues, and other strategic initiatives in order to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed, as well as the impact these initiatives may have on our future financial position, results of operations or liquidity; however, the impact could be material.

RISK FACTORS

Ameren may not be able to successfully integrate IP into its other businesses or achieve the benefits it anticipates.

Ameren cannot assure you that it will be able to successfully integrate IP with its other businesses. The integration of IP with its other businesses will present significant challenges and, as a result, Ameren may not be able to operate the combined company as effectively as expected. Ameren may also fail to achieve the anticipated benefits of the acquisition as quickly or as cost effectively as anticipated or may not be able to achieve those benefits at all. Ameren expects that this acquisition will be accretive to earnings per share. This expectation is based on important assumptions, including assumptions related to expected financing arrangements, interest rates, market prices for power and synergies, which may ultimately be incorrect. As a result, if Ameren is unable to integrate its businesses effectively o r achieve the benefits anticipated, our financial position, results of operations and liquidity may be materially adversely affected.

The electric and gas rates that certain of the Ameren Companies and IP are allowed to charge in Missouri and Illinois are largely set through 2006. This “rate freeze,” along with other actions of regulators, can significantly affect our earnings, liquidity and business activities and are largely outside our control.

The rates that certain of the Ameren Companies and IP are allowed to charge for their services are the single most important item influencing the financial position, results of operations and liquidity of the Ameren Companies and IP. We are highly regulated and the regulation of the rates that we charge our customers is determined, in large part, outside of our control by governmental organizations, including the MoPSC, the ICC and the FERC. We are also subject to regulation by the SEC under the PUHCA. Decisions made by these regulators could have a material impact on our financial position, results of operations and liquidity.

As a part of the settlement of UE’s Missouri electric rate case in 2002, UE is subject to a rate moratorium providing for no changes in its electric rates in Missouri before July 1, 2006, subject to limited statutory and other exceptions. A rate reduction of $30 million went into effect on April 1, 2004, which is the last portion of the $110 million rate reduction included in the stipulation entered into as part of the settlement of the Missouri electric rate case. In addition, as a provision of the Illinois legislation related to the restructuring of the Illinois electric industry, a rate freeze is in effect in Illinois until January 1, 2007. This Illinois legislation also contains a provision requiring that earnings from the Illinois jurisdiction in excess of certain levels be shared equally with UE’s, CIPS’, CILCO’s and IP’s Illinois customers through 2006. Furthermore, as part of the settlement of UE’s Missouri gas rate case, which was approved by the MoPSC on January 13, 2004, UE agreed to a rate moratorium providing for no changes in its gas delivery rates prior to July 1, 2006, subject to certain exceptions (the increased rates approved as part of the settlement became effective on February 15, 2004). Also, in the order approving Ameren’s acquisition of IP, the ICC prohibits IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond IP’s pending request for a gas delivery rate increase. The ICC conducted workshops seeking input from interested parties on the framework for retail rate determination and the framework for generation procurement by customers after the current Illinois rate freeze ends in 2006. We believe the ICC will make a decision on these matters in 2005.

As a part of the settlement of UE’s Missouri electric rate case in 2002, UE also undertook to use commercially reasonable efforts to make critical energy infrastructure investments of $2.25 billion to $2.75 billion from January 1, 2002 through June 30, 2006, including, among other things, the addition of more than 700 megawatts of new generation capacity (240 megawatts of which was added in 2002) and the replacement of steam generators at UE’s Callaway nuclear plant. The amount of energy infrastructure investment through June 2006, described in the settlement is consistent with UE’s previously disclosed estimate of construction expenditures UE expects to make over the same time period. Ameren also committed IP to make between $275 million and $325 million in energy infrastructure inve stments over its first two years of ownership in conjunction with the ICC’s approval of Ameren’s acquisition of IP. UE’s agreement to a rate moratorium and IP’s rate freeze will result in these capital expenditures not becoming recoverable in rates, or earning a return, before July 1, 2006 for UE, and January 1, 2007, for IP. Therefore, UE’s and IP’s undertakings with respect to making energy infrastructure investments and funding new programs, coupled with the rate reductions and rate moratoriums described above, could result in increased financing requirements for UE or IP and thus have a material impact on our liquidity.

The Ameren Companies and IP do not have the benefit of a fuel adjustment clause in either Missouri or Illinois for their electric operations that would allow them to recover increased fuel and power costs from customers. Therefore, to the extent that we have not hedged our fuel and power costs, we are exposed to changes in fuel and power prices to the extent fuel for our electric generating facilities and power must be purchased on the open market in order for us to serve our customers.

Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation. At the federal level, the FERC has been mandating changes in the regulatory framework in which transmission-owning public utilities, such as UE, CIPS, CILCO and IP operate. In Missouri, restructuring bills have been introduced in the past, but no legislation has been passed. In Illinois, where with the completion of the acquisition of IP, over 50% of Ameren’s electric revenues are derived, the Illinois Customer Choice Law provides for electric utility restructuring and retail direct access. Retail direct access, which allows customers to choose their electric generation supplier, was first offered to Illinois residential customers on May 1, 2002. Although reta il direct access in Illinois has not had a negative effect on Ameren’s revenues or liquidity, we expect competitive forces in the electric supply segment of our business to continue to increase.

The potential negative consequences associated with further electric industry restructuring in our service territories, if it occurs, could be significant and could include the impairment and writedown of certain assets, including generation related plant and net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expenses.

We are not able to predict what rate treatment certain of the Ameren Companies and IP will receive following the expiration of the rate moratorium in each of Missouri and Illinois. Some of the factors which influence rates are largely outside our control. In response to competitive, economic, political, legislative and /or regulatory pressures we may have to agree to further rate moratoriums, rate refunds or rate reductions, any and all of which could have a significant adverse affect on our earnings, liquidity and business activities.

Increased federal and state environmental regulation could require UE, Genco and CILCO to incur large capital expenditures and increase operating costs.

Approximately 65% of Ameren’s generating capacity is coal-fired. The balance is nuclear, gas-fired, hydro and oil-fired. The EPA has recently issued proposed regulations with respect to SO₂, NO_x and mercury emissions from coal-fired power plants. These new rules, if adopted, would require significant additional reductions in these emissions from our power plants in phases, beginning in 2010. The rules are currently under a public re view and comment period, and may change before being issued as final late in 2004 or early 2005. Preliminary estimates of capital costs based on current technology on the Ameren systems to comply with the SO₂, NO_x and mercury rules, as proposed, range from $1.1 billion to $1.4 billion by 2010, with an additional $375 million to $510 million by 2015.

In addition, Illinois has developed a NO_x control regulation for utility generating plant boilers consistent with an EPA program aimed at reducing ozone levels in the eastern United States. In the spring of 2004, the EPA issued similar rules for Missouri. Ameren and UE currently estimate that the remaining capital expenditures could range from $160 million to $180 million between 2005 and 2008 in order to comply with the final NO_x regulations in Missouri. This estimate includes the assumption that these rules will require the installation of selective catalytic reduction technology on some units, as well as additional controls.

We are unable to predict the ultimate effect of any new environmental regulations, guidelines, enforcement initiatives or legislation on our financial position, results of operations or liquidity. Any of these factors would add significant pollution control costs to UE’s, Genco’s and CILCO’s generating assets and, therefore, could also increase financing requirements for some of the Ameren Companies. While costs incurred by UE would be eligible for recovery in rates, subject to MoPSC or ICC approval, as applicable, there is no similar mechanism for recovery of costs by Genco or CILCO in Illinois.

UE’s, CIPS’, CILCO’s and IP’s participation in a RTO could increase costs, reduce revenues and reduce UE’s, CIPS’, CILCO’s and IP’s control over their transmission assets.

On May 1, 2004, functional control of the UE and CIPS transmission systems was transferred to the Midwest ISO through GridAmerica LLC. On September 30, 2004, prior to the completion of Ameren’s acquisition of IP as required by the FERC order approving the acquisition, IP transferred functional control of its transmission system to the Midwest ISO. The participation by UE, CIPS and IP in the Midwest ISO is expected to increase annual costs by $10 million to $25 million in the aggregate and could result in a decrease in annual revenues of between $5 million and $15 million in the aggregate. UE, CIPS, CILCO and IP may also be required to expand their transmission systems according to decisions made by a RTO rather than their internal planning process. In addition, we are unable to determine the full impact of the Midwest ISO’s Energy Markets Tariff accepted by the FERC in August 2004 (discussed in Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report) until further information is available regarding the implementation of the Energy Markets Tariff.

The inability of UE, CIPS, CILCO and IP to recover “through and out” transmission revenues could result in a material net revenue reduction.

Through orders issued during late 2003 and early 2004, the FERC had ordered the elimination of regional through-and-out rates assessed by the Midwest ISO that involved transmission service between the Midwest ISO and PJM regions to be effective May 1, 2004. However, on March 19, 2004, the FERC accepted an agreement among affected transmission owners that retains the regional through-and-out rates until December 1, 2004, and provides for continued negotiations aimed at developing a long-term transmission pricing structure to eliminate seams between the PJM and Midwest ISO regions based on specified pricing principles. Until the long-term transmission pricing structure has been established, UE, CIPS, CILCO and IP cannot predict the ultimate impact that such structure will have on their costs and revenues.

The substance and implementation of standard market design rules by the FERC is uncertain and may adversely affect the way in which UE, CIPS, CILCO and IP operate their transmission assets.

On July 31, 2002, the FERC issued its standard market design NOPR. The NOPR proposes a number of changes to the way the current wholesale transmission service and energy markets are operated. Specifically, the NOPR proposes that all jurisdictional transmission facilities be placed under the control of an independent transmission provider (similar to a RTO), proposes a new transmission service tariff that provides a single form of transmission service for all users of the transmission system including bundled retail load, and proposes a new energy market and congestion management system that uses locational marginal pricing as its basis. In our initial comments on the NOPR, which were filed at the FERC on November 15, 2002, we expressed our concern with the potential impact of the proposed rules in their current form on the cost and reliability of service to retail customers. We also proposed that certain modifications be made to the proposed rules in order to protect transmission owners from the possibility of trapped transmission costs that might not be recoverable from ratepayers as a result of inconsistent regulatory policies. We filed additional comments on the remaining sections of the NOPR during the first quarter of 2003.

In April 2003, the FERC issued a “white paper” reflecting comments received in response to the NOPR. More specifically, the white paper indicated that the FERC will not assert jurisdiction over the transmission rate component of bundled retail service and will insure that existing bundled retail customers retain their existing transmission rights and retain rights for future load growth in its final rule. Moreover, the white paper acknowledged that the final rule will provide the states with input on resource adequacy requirements, allocation of firm transmission rights, and transmission planning. The FERC also requested input on the flexibility and timing of the final rule’s implementation.

Although issuance of the final rule is uncertain and its implementation schedule is still unknown, the Midwest ISO is in the process of implementing a separate market design similar to the proposed market design in the NOPR. In July 2003, the Midwest ISO filed with the FERC a revised OATT codifying the terms and conditions under which it will implement the new market design. Thereafter, on October 17, 2003, the Midwest ISO filed a motion to withdraw its revised OATT. On October 29, 2003, the FERC issued a series of orders granting the motion for withdrawal of the revised OATT and providing guidance to be followed by the Midwest ISO in developing a new energy market design in the future. In March 2004, the Midwest ISO tendered for filing at the FERC a proposed Energy Markets Tariff, which is intended to supercede its existing OATT (see Note 3 - Rate and Regulatory Matters to our financial statements under Item I, Part 1 of this report). In August 2004, the FERC accepted the Midwest ISO’s Energy Market Tariff subject to further compliance filings. On November 8, 2004, the FERC issued an order denying the requests for rehearing that were filed by a number of Midwest ISO stakeholders including Ameren. However, a final order from the FERC on the compliance filings made by the Midwest ISO in response to the FERC's August 6 order is still pending. Until the FERC issues a final rule and the Midwest ISO finalizes its new market design, we are unable to predict the ultimate impact of the NOPR or the Midwest ISO new market design on our future financial position, results of operations or liquidity.

The market-based rate authority currently held by UE, CIPS, Genco, CILCO, AERG, Development Company, Marketing Company and Medina Valley could be partially revoked as a result of FERC’s new market power analysis screen order.

that it has market power. Under such circumstances, the applicant may either seek to rebut the presumption by preparing a delivered price test (identifying the amount of economic capacity from neighboring areas that can be delivered to the control area) or propose mitigation measures. Unless some other mitigation measure is adopted, the applicant’s authority to sell power at market-based rates in areas in which it has market power will be revoked, and the applicant will be required to sell at cost-based rates in those areas.

UE, Genco, CIPS, CILCO, AERG, Development Company, Marketing Company and Medina Valley currently have authorization from the FERC to continue to sell power at market-based rates. However, the FERC indicated in its April order that it would apply the new market analysis screens to pending and future market-based rate applications, including three-year market-based rate reviews. All of the aforementioned Ameren entities currently have three-year market-based rate reviews pending at the FERC.

As required, these Ameren companies will file an updated market power analysis with FERC in December 2004. This updated analysis will include the results of FERC’s new screens. These companies will apply the new screens both on the basis of individual control area markets and also on the basis of the entire Midwest ISO footprint. We understands that the individual control area analyses will be applicable for a limited time until Midwest ISO implements its "Day 2" markets, now scheduled for March 1, 2005, and that the Midwest ISO footprint analyses will be applicable after that time. We expects that UE and AERG will fail one of the new screens, the wholesale market share screen, in the UE/CIPS and CILCO control areas, respectively, but pass it in all other control areas and, as wel l, pass the other new screen measure, the pivotal supplier screen, in all of the individual control areas that we are required to study. We further anticipates that we will pass both screen measures for the larger market consisting of the entire Midwest ISO footprint. We are unable to anticipate how or when FERC will respond to any screen failure by an Ameren company for the interim period before the start of Midwest ISO Day 2 markets. Further, until we have finalized our updated analysis, we are unable to predict how the FERC will resolve a number of related issues, including resolution of evidence available to rebut any screen results indicating a failure, and resolution of any proposed mitigation measures. Finally, we are unable to predict the ultimate impact the new screens will have on our ability to sell power at market-based rates.

Increasing costs associated with our defined benefit retirement plans, healthcare plans and other employee related benefits may adversely affect our results of operations, liquidity and financial position.

The Ameren Companies made cash contributions totaling $25 million and $31 million to defined benefit retirement plans during 2003 and 2002, respectively. In addition, a minimum pension liability was recorded at December 31, 2002, which resulted in an after-tax charge to OCI and a reduction in stockholders’ equity for Ameren of $102 million. At December 31, 2003, the minimum pension liability was reduced, resulting in OCI of $46 million and an increase in stockholders’ equity. In the third quarter of 2004, we made a contribution of $295 million to our pension plans. In light of this contribution and the acquisition of IP, future required contributions over the period from 1005 to 2008 are now expected to aggregate $400 million to be paid in 2008 and 2009. This amount is an estimate and may change based on actual stock market performance, changes in interest rates, and any pertinent changes in government regulations, each of which could also result in a requirement to record an additional minimum pension liability.

In addition to the costs of our retirement plans, the costs to us of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, healthcare plans and other employee benefits may adversely affect our results of operations, liquidity or financial position.

UE’s, Genco’s and CILCO’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

UE, CILCO, Genco, AERG, Medina Valley and EEI own and operate coal, nuclear, gas-fired, hydro and oil-fired generating facilities constituting approximately 14,800 megawatts (net) of installed capability. Operation of electric generating facilities involves certain risks which can adversely affect energy output and efficiency levels. Included among these risks are:

increased prices for fuel and fuel transportation as existing contracts expire,
facility shutdowns due to a breakdown or failure of equipment or processes,
longer than anticipated maintenance outages,

disruptions in the delivery of fuel and lack of adequate inventories,
labor disputes,
inability to comply with regulatory or permit requirements,
disruptions in the delivery of electricity,
increased capital expenditures requirements, including those due to environmental regulation,
operator error, and
unusual or adverse weather conditions, including catastrophic events such as fires, explosions, floods or other similar occurrences affecting electric generating facilities.

A substantial portion of Genco’s and AERG’s generating capacity is committed under affiliate contracts which expire over the next several years.

Genco and AERG have several electric power supply agreements under which Genco and AERG directly or indirectly supply the full requirements of CIPS and CILCO, including the following:

Under two electric power supply agreements, Genco is obligated to supply to Marketing Company, and Marketing Company, in turn, is obligated to supply to CIPS, all of the energy and capacity needed by CIPS to offer service for resale to its native load customers and to fulfill CIPS’ other obligations under all applicable federal and state tariffs or contracts. Any power not used by CIPS is sold by Marketing Company under various long-term wholesale and retail contracts. The agreement between CIPS and Marketing Company will expire on December 31, 2006. The agreement between Genco and Marketing Company can be terminated by either party upon at least one year’s notice, but may not be terminated prior to December 31, 2004
AERG has an electric power supply agreement with CILCO to supply it sufficient power to meet its native load requirements. This agreement expires on December 31, 2006.

Midwest power markets have experienced high levels of new capacity development over the last several years, which, in part, contributed to soft long-term power prices in this region. Owners of generating capacity in the Midwest are actively seeking markets for their energy and capacity and have asked our regulators to closely scrutinize power supply arrangements among our subsidiaries when we have sought approval to enter into them. It cannot be predicted whether obtaining extensions on other long-term replacement power sale contracts for the energy and capacity currently committed under these agreements when they expire will be successful. To the extent Genco or AERG cannot secure extensions or other long-term replacement power sale contracts for the energy and capacity currently committed under these agreements, our generating subsidiaries and Marketing Company will face competition from other power suppliers in the Midwest and will be exposed to price risk.

Genco participates with UE in an agreement to jointly dispatch its generating facilities with those of UE, which thereby produces benefits and efficiencies for both generating parties. Pending or future federal and state regulatory proceedings and policies may evolve in ways that could impact Genco’s ability to continue to participate in these affiliate transactions on current terms. For example, as a result of the MoPSC conditional order approving the transfer of UE’s Illinois-based utility business, rehearing or clarification of which is currently being sought by UE, there is uncertainty as to the terms of the joint dispatch agreement and also as to its duration. The termination of the agreement, or modifications to it, could have a material adverse effect on UE or Genco.

Genco’s and CILCO’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk.

As owners of non rate-regulated electric generating facilities, Genco (4,800 megawatts) and CILCO through AERG (1,100 megawatts), its subsidiary, will not have any recovery of their costs or any specified rate of return set by a regulatory body. Of these non rate-regulated electric generating facilities, approximately 3,300 megawatts are currently under full requirements contracts with our affiliates, including the contracts referred to in the immediately preceding risk factor. The remainder of the generating capacity must compete for the sale of energy and capacity. UE is currently seeking regulatory approval of the transfer by Genco to it of approximately 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, with the result that those CTs will no longer be non rate-regulated.

To the extent electric capacity generated by these facilities is not under contract to be sold, either now or in the future, the revenues and results of operations of these non rate-regulated subsidiaries will generally depend on the prices that they can obtain for energy and capacity in Illinois and adjacent markets. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:

the current and future market prices for natural gas, fuel oil and coal,
current and forward prices for the sale of electricity,
the extent of additional supplies of electric energy from current competitors or new market entrants,
the pace of deregulation in our market area and the slowing expansion of deregulated markets,
the regulatory and pricing structures developed for Midwest energy markets as they continue to evolve and the pace of development of regional markets for energy and capacity outside of bilateral contracts,
future pricing for, and availability of, transmission services on transmission systems, the effect of RTOs, development and export energy transmission constraints, which could limit the ability to sell energy in markets adjacent to Illinois,
the rate of growth in electricity usage as a result of population changes, regional economic conditions and the implementation of conservation programs, and
climate conditions prevailing in the Midwest market from time to tim

UE’s ownership and operation of a nuclear generating facility creates business, financial and waste disposal risks.

UE owns the Callaway nuclear plant, which represents approximately 14% of UE’s generation capability. Therefore, UE is subject to the risks of nuclear generation, which include the following:

the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials,
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE’s nuclear operations or those of others in the United States,
uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate,
increased public and governmental concerns over the adequacy of security at nuclear power plants,
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives (UE’s facility operating license for the Callaway nuclear plant expires in 2024), and
costly and extended outages from scheduled or unscheduled maintenance.

The NRC has broad authority under federal law to impose licensing and safety related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE’s. In addition, although UE has no reason to anticipate a serious nuclear incident at its plant, if an incident did occur, it could harm UE’s results of operations or financial position. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nucl ear unit.

Operating performance at UE’s Callaway nuclear plant has recently resulted in unscheduled plant outages and the extension of Callaway’s scheduled refueling and maintenance outage in 2004. In addition, Ameren and UE have incurred significant unanticipated replacement power and maintenance costs. As a result, the operating performance at UE’s Callaway nuclear plant has declined as compared to its past operating performance and the operating performance of other nuclear plants in the United States. Ameren and UE are actively working to address factors leading to the decline in Callaway’s operating performance, including management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance and overall organizational effectiveness. However, A meren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Efforts taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material effect on the financial position, results of operations and cash flows of Ameren and UE.

Our energy risk management strategies may not be effective in managing fuel and electricity pricing risks, which could result in unanticipated liabilities to us or increased volatility of our earnings.

We are exposed to changes in market prices for natural gas, fuel, electricity and emission credits. Prices for natural gas, fuel, electricity and emission credits may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We utilize derivatives such as forward contracts, futures contracts, options and swaps to manage these risks. We attempt to manage our exposure from these activities through enforcement of established risk limits and risk management procedures. We cannot assure you that these strategies will be successful in managing our pricing risk, or that they will not result in net liabilities to us as a result of future volatility in these markets.

In addition, although we routinely enter into contracts to offset our positions (i.e., to hedge our exposure to the risks of demand, market effects of weather and changes in commodity prices), we do not always hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. As a result, to the extent the commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater open positions than we would prefer at a given time. To the extent that open positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position.

We are exposed to risk that counterparties which owe us money, energy or other commodities or services will not be able to perform their obligations. The possibility that certain counterparties may fail to perform their obligations has increased due to financial difficulties, in some cases brought on by improper or illegal accounting and business practices, affecting some participants in the industry. Should the counterparties to these arrangements (which include an agreement pursuant to which a subsidiary of Dynegy is obligated to supply electricity to IP during 2005 and 2006) fail to perform, we might be forced to honor the underlying commitment at then-current market prices. In such event we might incur losses in addition to amounts, if any, already paid to the counterparties.

Our businesses are dependent on our ability to successfully access the capital markets. We may not have access to sufficient capital in the amounts and at the times needed.

We rely on access to short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and grow our businesses. Based on our current credit ratings, we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets such that our cost of capital would increase or our ability to access the capital markets would be adversely affected.

REGULATORY MATTERS

See Note 3 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1 of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk represents the risk of changes in value of a physical contract or a financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates. The following discussion of our risk management activities includes “forward-looking” statements that involve risks and uncertainties. Actual results could differ materially from those projected in the “forward-looking” statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal and operational risks and are not represented in the following discussion.

Our risk management objective is to optimize our physical generating assets within prudent risk parameters. Our risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers.

Interest Rate Risk

We are exposed to market risk through changes in interest rates associated with:

·	long-term and short-term variable-rate debt;

·	fixed-rate debt;

·	commercial paper; and

·	auction-rate long-term debt.

We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates.

The following table presents the estimated increase or decrease in our annual interest expense and net income if interest rates were to change by 1% on variable rate debt outstanding at September 30, 2004:

	Interest Expense		Net Income^(a)
Ameren^(b)	$	6	$	(4	)
UE		6		(4	)
CIPS		1		-
Genco		1		(1	)
CILCORP^(c)		3		(2	)
CILCO		2		(1	)

(a)	Calculations are based on an effective tax rate of 36%.

(b)	Includes amounts for Ameren registrant and non-registrant subsidiaries and intercompany eliminations.

(c)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

The model does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in our financial structure.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. On all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.

Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables, executory contracts with market risk exposures and leveraged lease investments. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups comprising our customer base. No non-affiliated customer represents greater than 10%, in the aggregate, of our accounts receivable. Ameren’s revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE and Genco have credit exposure associated with accounts receivables from nonaffiliated companies for interchange sales. At September 30, 2004, UE’s, Genco’s and Marketing Company’s combined credit exposure to non-investment grade counte rparties related to interchange sales was $4 million, net of collateral. We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program, which involves daily exposure reporting to senior management, master trading and netting agreements, and credit support such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition prior to entering into sales, forwards, swaps, futures or option contracts and monitor counterparty exposure associated with our leveraged leases.

Equity Price Risk

Our costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rate of return on plan assets, discount rate, the rate of increase in healthcare costs and contributions made to the plans. The market value of our plan assets was affected by declines in the equity market for 2000 through 2002 for the pension and postretirement plans. As a result, a minimum pension liability was recorded

at December 31, 2002, which resulted in a charge to OCI and a reduction in stockholders’ equity. At December 31, 2003, the minimum pension liability was reduced resulting in OCI of $46 million and an increase in stockholders’ equity. The minimum pension liability has not changed as of September 30, 2004.

The amount of the pension liability as of September 30, 2004, was the result of asset returns, interest rates and our contributions to the plans during 2003. In future years, the liability recorded, the costs reflected in net income or OCI, or cash contributions to the plans could increase materially without a recovery in equity markets in excess of our assumed return on plan assets of 8.5%. If the fair value of the plan assets were to grow and exceed the accumulated benefit obligations in the future, the recorded liability would then be reduced and a corresponding amount of equity would be restored, net of taxes.

Commodity Price Risk

The Ameren Companies and IP are exposed to changes in market prices for natural gas, fuel and electricity to the extent they cannot be recovered through rates. For a more detailed discussion of our commodity price risk, see Commodity Price Risk under Part II, Item 7A of the Ameren Companies’ combined Form 10-K for the fiscal year ended December 31, 2003. In addition, see Risk Factors under Part 1, Item 2 of this report for further information on commodity price risks. Below are details relating to IP’s power purchase agreements and tables presenting the percentage of fuel that is price-hedged and the effects a material change in price will have on our coal costs not currently covered under fixed-price contracts as of September 30, 2004.

IP has contracts with AmerGen and DMG to supply power via purchase power agreements that expire at the end of 2004. Should power acquired under these agreements be insufficient to meet IP’s load requirements, it will have to buy power at current market prices. The purchased power agreement with DMG obligates DMG to provide power up to the reservation amount, and at the same prices, even if DMG has individual units unavailable at various times. The purchased power agreement with AmerGen does not obligate AmerGen to acquire replacement power for us in the event of a curtailment or shutdown at the Clinton Power Station. Under a Clinton shutdown scenario, to the extent IP exceeds its capacity reservation with DMG, it will have to buy power at current market prices. Such purchases would expose IP to commodity price risk. As discussed in Ameren Companies combined Form 10-K, the retail electric rates are frozen in Illinois until January 1, 2007.

As part of the sale transaction with Ameren, DMG and IP entered into a fixed price power capacity supply agreement for our annual purchase in 2005 and 2006 of 2,800 megawatts of electricity. This agreement is expected to supply 70% of our electric customer requirements during those two years. Additionally, IP is in the final stages of soliciting bids to supply the remaining 30% of its power needs for 2005 and 2006. This solicitation is expected to be completed by the end of 2004. If IP is unable to sufficiently contract for all of its power and energy needs, or if any of the parties to these agreements are unable to satisfy their oblig ations thereunder for any reason, either to purchase or deliver power, IP or Ameren could be required to satisfy IP’s needs through open market purchases thus exposing IP or Ameren to commodity price risk. Any additional costs could not be passed on to ratepayers until at least the end of the rate freeze in Illinois.

The following table presents the percentages of the required supply of coal for our coal-fired power plants, nuclear fuel and natural gas for our CTs and distribution, as appropriate, which are price-hedged for the remainder of 2004 through 2008:

	2004	2005	2006 - 2008
Ameren:
Coal	100%	92%	60%
Nuclear fuel	100	100	32
Natural gas for generation	65	25	5
Natural gas for distribution	33	19	5
UE:
Coal	100%	92%	57%
Nuclear fuel	100	100	32
Natural gas for generation	63	8	4
Natural gas for distribution	26	15	5

2004

2005

2006 - 2008

CIPS:
Natural gas for distribution	25%	21%	10%
Genco:
Coal	100%	96%	70%
Natural gas for generation	100	18	24
CILCORP:^(a)
Coal	100%	85%	58%
Natural gas for distribution	45	28	9
CILCO:
Coal	100%	85%	58%
Natural gas for distribution	45	28	9

(a)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

The following table presents the estimated increase or decrease in our total fuel expense and net income if coal costs were to change by 1% on any requirements currently not covered by fixed-price contracts for the remainder of 2004 through 2008:

	Fuel Expense		Net Income^(a)
Ameren^(b)	$	5	$	3
UE		3		2
CIPS		-		-
Genco		1		1
CILCORP^(c)		1		-
CILCO		1		-

(a)	Calculations are based on an effective tax rate of 36%.

(b)	Includes amounts for Ameren registrant and non-registrant subsidiaries.

(c)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

Fair Value of Contracts

Most of our commodity contracts qualify for treatment as normal purchases and normal sales. However, we utilize derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel and electricity cause:

·	an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices;
·	market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory under firm commitment; and
·	actual cash outlays for the purchase of these commodities to differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are dictated by risk management policies and include forward contracts, futures contracts, options and swaps. We continually assess our supply and delivery commitment positions against forward market prices and internally-forecasted forward prices and modify our exposure to market, credit and operational risk by entering into various offsetting transactions. In general, we believe these transactions serve to reduce our price risk. See Note 7 - Derivative Financial Instruments to our financial statements under Part I, Item 1 of this report for further information.

The following table presents the favorable (unfavorable) changes in the fair value of all contracts marked-to-market during the three months and nine months ended September 30, 2004:

	Ameren^(a)			UE			CIPS			CILCORP^(b)			CILCO
Three Months
Fair value of contracts at beginning of period, net	$	24		$	(2	)	$	6		$	12		$	12
Contracts realized or otherwise settled during the period		-			-			-			-			-
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		-			-			-			-			-
Other changes in fair value		25			5			5			13			13
Fair value of contracts outstanding at end of period, net	$	49		$	3		$	11		$	25		$	25
Nine Months
Fair value of contracts at beginning of period, net	$	12		$	(1	)	$	1		$	6		$	6
Contracts realized or otherwise settled during the period		(5	)		1			(1	)		(3	)		(2	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-
Fair value of new contracts entered into during the period		-			-			-			-			-
Other changes in fair value		42			3			11			22			21
Fair value of contracts outstanding at end of period, net	$	49		$	3		$	11		$	25		$	25

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

(b)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

The following table presents maturities of contracts as of September 30, 2004:

Sources of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years		Total Fair Value^(a)
Ameren:
Prices actively quoted	$	29		$	16		$	-		$	-	$	45
Prices provided by other external sources^(b)		(1	)		-			-			-		(1	)
Prices based on models and other valuation methods^(c)		10			(3	)		(2	)		-		5
Total	$	38		$	13		$	(2	)	$	-	$	49

UE:
Prices actively quoted	$	3		$	3		$	-		$	-	$	6
Prices provided by other external sources^(b)		(1	)		-			-			-		(1	)
Prices based on models and other valuation methods^(c)		4			(3	)		(3	)		-		(2	)
Total	$	6		$	-		$	(3	)	$	-	$	3
CIPS:
Prices actively quoted	$	7		$	4		$	-		$	-	$	11
Prices provided by other external sources^(b)		-			-			-			-		-
Prices based on models and other valuation methods^(c)		-			-			-			-		-
Total	$	7		$	4		$	-		$	-	$	11

Sources

Fair Value

Maturity Less than

1 Year

Maturity

1-3

Years

Maturity

4-5

Years

Maturity in Excess of

5 Years

Total

Fair

Value^(a)

CILCORP:^(d)
Prices actively quoted	$	15	$	9	$	1	$	-	$	25
Prices provided by other external sources^(b)		-		-		-		-		-
Prices based on models and other valuation methods^(c)		-		-		-		-		-
Total	$	15	$	9	$	1	$	-	$	25
CILCO:
Prices actively quoted	$	15	$	9	$	1	$	-	$	25
Prices provided by other external sources^(b)		-		-		-		-		-
Prices based on models and other valuation methods^(c)		-		-		-		-		-
Total	$	15	$	9	$	1	$	-	$	25

(a)	Contracts of less than $11 million were with non-investment-grade rated counterparties.

(b)	Principally power forwards based on a published survey of settled forward pricing and natural gas swap valuations based on NYMEX prices for over-the-counter contracts.

(c)	Principally coal and SO₂ option values based on a Black-Scholes model that includes information from external sources and our estimates. Also includes power forward contract values based on our estimates.

(d)	CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures

As of September 30, 2004, the principal executive officer and principal financial officer of each Registrant have evaluated the effectiveness of the design and operation of such Registrant’s disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Based upon that evaluation, the principal executive officer and principal financial officer of each such Registrant have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to such Registrant, which is required to be included in such Registrant’s reports filed or submitted with the SEC under the Exchange Act.

(b) Change in Internal Controls

There has been no change in the Registrants’ internal control over financial reporting that occurred during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

Note 3 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1 of this report contain information on legal and administrative proceedings which are incorporated by reference under this item.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Ameren’s purchases of equity securities reportable under Item 703 of Regulation S-K:

Period	(a) Total Number of Shares (or Units) Purchased^(a)	(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31, 2004	-	$ -	-	-
August 1 - August 31, 2004	55,462	45.81	-	-
September 1 - September 30, 2004	4,342	46.34	-	-
Total	59,804	$ 45.85	-	-

(a) These shares of Ameren common stock were purchased by Ameren in open-market transactioins in satisfaction of Ameren’s obligations upon the exercise by employees of options issued under

Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.

CILCO’s purchases of equity securities reportable under Item 703 of Regulation S-K:

Period	(a) Total Number of Shares (or Units) Purchased^(a)	(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31, 2004	11,000	$ 100.00	-	-
August 1 - August 31, 2004	-	-	-	-
September 1 - September 30, 2004	-	-	-	-
Total	11,000	$ 100.00	-	-

(a)	CILCO redeemed these shares of its 5.85% Class A preferred stock to satisfy the mandatory sinking fund redemption requirement for this series of preferred stock for 2004. CILCO does not have any publicly announced equity securities repurchase plans or programs.

None of the other Registrants purchased equity securities reportable under Item 703 of Regulation S-K during the July 1 to September 30, 2004, period.

ITEM 6. EXHIBITS.

(a) Exhibits. The documents listed below are being filed on behalf of Ameren, UE, CIPS, Genco, CILCORP and CILCO (collectively the “Ameren Companies”).

Exhibit Designation	Registrant(s)	Nature of Exhibit
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1	Ameren	Amendment No. 4, dated as of September 24, 2004, to Stock Purchase Agreement, dated as of February 2, 2004, by and between Dynegy and certain of its subsidiaries and Ameren
Bylaws
3.1	Genco	Bylaws of Genco as amended October 8, 2004
3.2	CILCORP	Bylaws of CILCORP as amended October 8, 2004
Material Contracts
10.1	Ameren	Escrow Agreement among Illinova Corporation, Ameren and JPMorgan Chase Bank, as escrow agent, dated September 30, 2004
10.2	Ameren CIPS Genco	Power Supply Agreement between CIPS and Marketing Company, as amended November 5, 2004
Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	UE	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE

31.4	UE	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE
31.5	CIPS	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CIPS
31.6	CIPS	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CIPS
31.7	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco
31.8	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco
31.9	CILCORP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORP
31.10	CILCORP	Rule13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCORP
31.11	CILCO	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO
31.12	CILCO	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer of Ameren
32.2	Ameren	Section 1350 Certification of Principal Financial Officer of Ameren
32.3	UE	Section 1350 Certification of Principal Executive Officer of UE
32.4	UE	Section 1350 Certification of Principal Financial Officer of UE
32.5	CIPS	Section 1350 Certification of Principal Executive Officer of CIPS
32.6	CIPS	Section1350 Certification of Principal Financial Officer of CIPS
32.7	Genco	Section 1350 Certification of Principal Executive Officer of Genco
32.8	Genco	Section 1350 Certification of Principal Financial Officer of Genco
32.9	CILCORP	Section 1350 Certification of Principal Executive Officer of CILCORP
32.10	CILCORP	Section 1350 Certification of Principal Financial Officer of CILCORP
32.11	CILCO	Section 1350 Certification of Principal Executive Officer of CILCO
32.12	CILCO	Section 1350 Certification of Principal Financial Officer of CILCO

SIGNATURES

Pursuant to the requirements of the Exchange Act, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

	AMEREN CORPORATION
	(Registrant)

	/s/ Martin J. Lyons
	Martin J. Lyons
	Vice President and Controller
	(Principal Accounting Officer)




	UNION ELECTRIC COMPANY
	(Registrant)

	/s/ Martin J. Lyons
	Martin J. Lyons
	Vice President and Controller
	(Principal Accounting Officer)




	CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
	(Registrant)

	/s/ Martin J. Lyons
	Martin J. Lyons
	Vice President and Controller
	(Principal Accounting Officer)




	AMEREN ENERGY GENERATING COMPANY
	(Registrant)

	/s/ Martin J. Lyons
	Martin J. Lyons
	Vice President and Controller
	(Principal Accounting Officer)

	CILCORP INC.
	(Registrant)

	/s/ Martin J. Lyons
	Martin J. Lyons
	Vice President and Controller
	(Principal Accounting Officer)




	CENTRAL ILLINOIS LIGHT COMPANY
	(Registrant)

	/s/ Martin J. Lyons
	Martin J. Lyons
	Vice President and Controller
	(Principal Accounting Officer)


Date: November 9, 2004

	Exact Name of Registrant as specified in its charter;
Commission	State of Incorporation;	IRS Employer
File Number	Address and Telephone Number	Identification No.

1-14756	Ameren Corporation	43-1723446
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

1-2967	Union Electric Company	43-0559760
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

1-3672	Central Illinois Public Service Company	37-0211380
	(Illinois Corporation)
	607 East Adams Street
	Springfield, Illinois 62739
	(217) 523-3600

333-56594	Ameren Energy Generating Company	37-1395586
	(Illinois Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

2-95569	CILCORP Inc.	37-1169387
	(Illinois Corporation)
	300 Liberty Street
	Peoria, Illinois 61602
	(309) 677-5230

1-2732	Central Illinois Light Company	37-0211050
	(Illinois Corporation)
	300 Liberty Street
	Peoria, Illinois 61602
	(309) 677-5230

Ameren Corporation	Yes	(X)	No	( )
Union Electric Company	Yes	( )	No	(X)
Central Illinois Public Service Company	Yes	( )	No	(X)
Ameren Energy Generating Company	Yes	( )	No	(X)
CILCORP Inc.	Yes	( )	No	(X)
Central Illinois Light Company	Yes	( )	No	(X)

Ameren Corporation	Common stock, $.01 par value - 194,796,533

Union Electric Company	Common stock, $5 par value, held by Ameren Corporation (parent company of the Registrant) - 102,123,834

Central Illinois Public Service Company	Common stock, no par value, held by Ameren Corporation (parent company of the Registrant) - 25,452,373

Ameren Energy Generating Company	Common stock, no par value, held by Ameren Energy Development Company (parent company of the Registrant and indirect subsidiary of Ameren Corporation) - 2,000

CILCORP Inc.	Common stock, no par value, held by Ameren Corporation (parent company of the Registrant) - 1,000

Central Illinois Light Company	Common stock, no par value, held by CILCORP Inc. (parent company of the Registrant and subsidiary of Ameren Corporation) - 13,563,871

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions, except per share amounts)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
Operating Revenues:
Electric	$	1,237		$	1,269		$	3,182		$	3,101
Gas		78			82			498			450
Other		2			2			5			6
Total operating revenues		1,317			1,353			3,685			3,557
Operating Expenses:
Fuel and purchased power		330			336			890			814
Gas purchased for resale		47			51			335			316
Other operations and maintenance		314			302			956			901
Coal contract settlement		-			(51	)		-			(51	)
Depreciation and amortization		136			132			398			388
Taxes other than income taxes		77			83			231			238
Total operating expenses		904			853			2,810			2,606
Operating Income		413			500			875			951
Other Income and (Deductions):
Miscellaneous income		8			4			20			16
Miscellaneous expense		(1	)		(3	)		(6	)		(14	)
Total other income and (deductions)		7			1			14			2
Interest Charges and Preferred Dividends:
Interest		62			69			192			204
Preferred dividends of subsidiaries		3			3			8			8
Net interest charges and preferred dividends		65			72			200			212
Income Before Income Taxes and Cumulative Effect of Change
in Accounting Principle		355			429			689			741
Income Taxes		123			154			242			273
Income Before Cumulative Effect of Change in Accounting
Principle		232			275			447			468
Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes of $-, $-, $- and $12		-			-			-			18
Net Income	$	232		$	275		$	447		$	486
Earnings per Common Share - Basic and Diluted:
Income before cumulative effect of change
in accounting principle	$	1.20		$	1.70		$	2.44		$	2.91
Cumulative effect of change in accounting
principle, net of income taxes		-			-			-			0.11
Earnings per Common Share - Basic and Diluted	$	1.20		$	1.70		$	2.44		$	3.02

Dividends per Common Share	$	0.635		$	0.635		$	1.905		$	1.905
Average Common Shares Outstanding		193.5			161.8			183.5			160.7

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

AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except per share amounts)

	September 30,			December 31,
	2004			2003
ASSETS
Current Assets:
Cash and cash equivalents	$	647		$	111
Accounts receivables - trade (less allowance for doubtful
accounts of $14 and $13, respectively)		466			326
Unbilled revenue		265			221
Miscellaneous accounts and notes receivable		51			126
Materials and supplies, at average cost		605			487
Other current assets		108			46
Total current assets		2,142			1,317
Property and Plant, Net		13,052			10,920
Investments and Other Non-Current Assets:
Investments in leveraged leases		140			152
Nuclear decommissioning trust fund		219			212
Goodwill and other intangibles, net		979			574
Other assets		448			332
Total investments and other non-current assets		1,786			1,270
Regulatory Assets		784			729
TOTAL ASSETS	$	17,764		$	14,236


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	263		$	498
Short-term debt		31			161
Accounts and wages payable		320			480
Taxes accrued		357			103
Other current liabilities		403			215
Total current liabilities		1,374			1,457
Long-term Debt, Net		6,164			4,070
Preferred Stock of Subsidiary Subject to Mandatory Redemption		20			21
Deferred Credits and Other Non-Current Liabilities:
Accumulated deferred income taxes, net		1,616			1,853
Accumulated deferred investment tax credits		142			151
Regulatory liabilities		945			824
Asset retirement obligations		431			413
Accrued pension and other postretirement benefits		726			699
Other deferred credits and liabilities		305			190
Total deferred credits and other non-current liabilities		4,165			4,130
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		196			182
Minority Interest in Consolidated Subsidiaries		13			22
Commitments and Contingencies (Note 9)
Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized -
shares outstanding of 194.8 and 162.9, respectively		2			2
Other paid-in capital, principally premium on common stock		3,924			2,552
Retained earnings		1,945			1,853
Accumulated other comprehensive loss		(27	)		(44	)
Other		(12	)		(9	)
Total stockholders’ equity		5,832			4,354
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	17,764		$	14,236


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

		Page
Glossary of Terms and Abbreviations		5

Forward-looking Statements		9

PART I.	Financial Information

ITEM 1.	Financial Statements (Unaudited)

	Ameren Corporation
	Consolidated Statement of Income	10
	Consolidated Balance Sheet	11
	Consolidated Statement of Cash Flows	12

	Union Electric Company
	Consolidated Statement of Income	13
	Consolidated Balance Sheet	14
	Consolidated Statement of Cash Flows	15

	Central Illinois Public Service Company
	Statement of Income	16
	Balance Sheet	17
	Statement of Cash Flows	18

	Ameren Energy Generating Company
	Statement of Income	19
	Balance Sheet	20
	Statement of Cash Flows	21

	CILCORP Inc.
	Consolidated Statement of Income	22
	Consolidated Balance Sheet	23
	Consolidated Statement of Cash Flows	24

	Central Illinois Light Company
	Consolidated Statement of Income	25
	Consolidated Balance Sheet	26
	Consolidated Statement of Cash Flows	27


ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	64

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	91

ITEM 4.	Controls and Procedures	96

PART II.	Other Information

ITEM 1.	Legal Proceedings	97

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	97

ITEM 6.	Exhibits	98

SIGNATURES		99

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)

	Nine Months Ended
	September 30,
	2004			2003


Cash Flows From Operating Activities:
Net income	$	447		$	486
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle		-			(18	)
Depreciation and amortization		398			388
Amortization of nuclear fuel		21			25
Amortization of debt issuance costs and premium/discounts		8			8
Deferred income taxes, net		52			30
Deferred investment tax credits, net		(9	)		(9	)
Coal contract settlement		28			(45	)
Pension contribution		(295	)		(25	)
Other		29			(8	)
Changes in assets and liabilities, excluding the effects of the acquisitions:
Receivables, net		21			17
Materials and supplies		(32	)		(69	)
Accounts and wages payable		(192	)		(171	)
Taxes accrued		257			167
Assets, other		(86)			(8	)
Liabilities, other		89			84
Net cash provided by operating activities		736			852

Cash Flows From Investing Activities:
Construction expenditures		(547	)		(457	)
Acquisitions, net of cash acquired		(451	)		(489	)
Nuclear fuel expenditures		(7	)		(2	)
Other		28			10
Net cash used in investing activities		(977	)		(938	)

Cash Flows From Financing Activities:
Dividends on common stock		(356	)		(308	)
Capital issuance costs		(40	)		(13	)
Redemptions, repurchases, and maturities:
Nuclear fuel lease		(67	)		(38	)
Short-term debt		(130	)		(268	)
Long-term debt		(451	)		(648	)
Preferred stock		(1	)		(1	)
Issuances:
Common stock		1,418			336
Long-term debt		404			498
Net cash provided by (used in) financing activities		777			(442	)

Net change in cash and cash equivalents		536			(528	)
Cash and cash equivalents at beginning of year		111			628
Cash and cash equivalents at end of period	$	647		$	100

Cash Paid During the Periods:
Interest	$	187		$	189
Income taxes, net		20			156


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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF CASH FLOWS
(Unaudited) (In millions)


	Nine Months Ended
	September 30,
	2004			2003

Cash Flows From Operating Activities:
Net income	$	41		$	31
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		39			39
Amortization of debt issuance costs and premium/discounts		1			1
Deferred income taxes, net		(11	)		(11	)
Deferred investment tax credits, net		(1	)		(1	)
Pension contribution		(33	)		(4	)
Other		6			(3	)
Changes in assets and liabilities:
Receivables, net		14			18
Materials and supplies		(13	)		(16	)
Accounts and wages payable		(7	)		23
Taxes accrued		22			2
Assets, other		(12	)		9
Liabilities, other		33			14
Net cash provided by operating activities		79			102

Cash Flows From Investing Activities:
Construction expenditures		(32	)		(36	)
Intercompany note receivable - Genco		49			62
Net cash provided by investing activities		17			26

Cash Flows From Financing Activities:
Dividends on common stock		(46	)		(54	)
Dividends on preferred stock		(2	)		(2	)
Repayments to money pool		(60	)		-
Redemptions, repurchases, and maturities:
Long-term debt		-			(95	)
Borrowings from money pool		-			23
Net cash used in financing activities		(108	)		(128	)

Net change in cash and cash equivalents		(12	)		-
Cash and cash equivalents at beginning of year		16			17
Cash and cash equivalents at end of period	$	4		$	17

Cash Paid During the Periods:
Interest	$	19		$	23
Income taxes, net		11			18


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

AMEREN ENERGY GENERATING COMPANY
BALANCE SHEET
(Unaudited) (In millions, except shares)

	September 30,			December 31,
	2004			2003
ASSETS
Current Assets:
Cash and cash equivalents	$	-		$	2
Accounts receivable		93			88
Materials and supplies, at average cost		90			90
Other current assets		3			4
Total current assets		186			184
Property and Plant, Net		1,743			1,774
Other Non-Current Assets		19			19
TOTAL ASSETS	$	1,948		$	1,977


LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Accounts and wages payable	$	45		$	75
Borrowings from money pool		79			124
Current portion of intercompany notes payable - CIPS and Ameren		358			53
Current portion of intercompany tax payable - CIPS		11			12
Taxes accrued		36			30
Other current liabilities		36			23
Total current liabilities		565			317
Long-term Debt, Net		698			698
Intercompany Notes Payable - CIPS and Ameren		-			358
Deferred Credits and Other Non-Current Liabilities:
Accumulated deferred income taxes, net		115			99
Accumulated deferred investment tax credits		12			13
Intercompany tax payable - CIPS		141			150
Accrued pension and other postretirement benefits		1			19
Other deferred credits and liabilities		3			2
Total deferred credits and other non-current liabilities		272			283
Commitments and Contingencies (Note 9)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized - 2,000 shares outstanding		-			-
Other paid-in capital		225			150
Retained earnings		189			170
Accumulated other comprehensive (loss) income		(1	)		1
Total stockholder's equity		413			321
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	1,948		$	1,977


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

Current assets	$	375
Property and plant		1,967
Investments and other non-current assets		396
Goodwill		302
Total assets acquired		3,040
Current liabilities		219
Long-term debt, including current maturities		1,979
Other non-current liabilities		452
Total liabilities assumed		2,650
Preferred stock assumed		13
Net assets acquired	$	377

For the periods ended September 30,	Three Months				Nine Months
	2004		2003		2004		2003
Operating revenues	$	1,696	$	1,729	$	4,844	$	4,702
Income before cumulative effect of change in accounting
principle		281		317		550		558
Cumulative effect of change in account principle, net of
taxes		-		-		-		16
Net income	$	281	$	317	$	550	$	574
Earnings per share - basic	$	1.45	$	1.65	$	2.84	$	3.01
- diluted		1.45		1.65		2.84		3.01

Current assets	$	323
Property and plant		1,162
Investments and other non-current assets		154
Specifically-identifiable intangible assets		6
Goodwill		560
Total assets acquired		2,205
Current liabilities		189
Long-term debt, including current maturities		937
Other non-current liabilities		521
Total liabilities assumed		1,647
Preferred stock assumed		41
Net assets acquired	$	517