Ameren response to SEC comment ltr, dated November 30, 2006

CORRESP 1 filename1.htm Ameren response to SEC comment ltr, dated November 30, 2006

Ameren Corporation	One Ameren Plaza
	1901 Chouteau Avenue
Martin J. Lyons	PO Box 66149, MC 202
Vice President & Controller	St. Louis, MO 63166-6149
	314.554.2982
	314.992.6691 fax
	mlyons@ameren.com

By EDGAR and Overnight Mail

December 13, 2006

Securities and Exchange Commission

100 F. Street, N.E.

Washington, D.C. 20549

Attention: Jim Allegretto, Senior Assistant Chief Accountant

Sarah Goldberg, Staff Accountant

Division of Corporation Finance

Re:	Ameren Corporation, File No. 1-14756

Union Electric Company, File No. 1-2967

Central Illinois Public Service Company, File No. 1-3672

Ameren Energy Generating Company, File No. 333-56594

CILCORP Inc., File No. 2-95569

Central Illinois Light Company, File No. 1-2732

Illinois Power Company, File No. 1-3004

Form 10-K for Fiscal Year Ended December 31, 2005

Filed March 7, 2006

Forms 10-Q for Fiscal Quarters Ended

March 31, 2006, June 30, 2006 and September 30, 2006

Ladies and Gentlemen:

This letter is being filed in response to comments from the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) transmitted by letter dated November 30, 2006, to Martin J. Lyons, Vice President and Controller, of Ameren Corporation (“Ameren”), Union Electric Company (“UE”), Central Illinois Public Service Company (“CIPS”), Ameren Energy Generating Company (“Genco”), CILCORP Inc. (“CILCORP”), Central Illinois Light Company (“CILCO”), and Illinois Power Company (“IP”) (each a “registrant” and collectively, the “Ameren Companies”), with respect to the above referenced 2005 Form 10-K and 2006 Form 10-Q filings.

This letter recites each Staff comment and then provides the response to that comment. All responses in this letter are provided on a supplemental basis. We use the words “our,” “we” or “us” in our responses with respect to certain information that relates to all of the Ameren Companies.

Form 10-K for Fiscal Year Ended December 31, 2005

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 33

Depreciation and Amortization, page 44

Comment: Please explain why the net sum of the UE, CIPS, Genco and CILCORP/CILCO depreciation fluctuations from 2004 to 2005 does not approximate Ameren’s increased depreciation and amortization for 2005 less the additional 9 months depreciation at IP. We presume each of the aforementioned subsidiaries is consolidated into Ameren. If our presumption is incorrect, please explain. Provide a similar analysis with respect to the relationship between Ameren’s capital expenditures and the capital expenditures of the aforementioned subsidiaries, as indicated on page 49.

Response: Depreciation fluctuations from 2004 to 2005 at UE, CIPS, Genco, CILCORP and CILCO did not total to the Ameren consolidated variance less the additional nine months of depreciation at IP because of a $6 million decrease in depreciation resulting from changes at certain nonregistrant Ameren subsidiaries and an $18 million depreciation overstatement due to a classification error in UE’s ($14 million) and CIPS’ ($4 million) 2005 income statements. This classification error was not made in Ameren’s 2005 consolidated income statement. The error at UE and CIPS was discovered, and determined to be immaterial, in the first quarter of 2006. The misclassification had no impact on net income, operating income, earnings per share, or cash flows from operations. The error resulted in a misstatement of other operations and maintenance expense of 2% and 3% at UE and CIPS, respectively, and a misstatement of depreciation and amortization of 5% and 7% at UE and CIPS, respectively, for the fiscal year ended December 31, 2005.

Total capital expenditures of UE, CIPS, Genco, CILCORP and CILCO exceeded Ameren’s consolidated capital expenditures principally because of UE’s $237 million cash purchase of combustion turbine generating facilities from Genco in 2005 as disclosed in Note 3 - Rate and Regulatory Matters and in our Management’s Discussion and Analysis of Financial Condition and Results of Operations (page 49) included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2005. This transaction between subsidiaries was appropriately eliminated in Ameren’s consolidated statement of cash flows for the fiscal year ended December 31, 2005. The remaining $18 million difference is primarily a result of capital expenditures at nonregistrant subsidiaries.

Critical Accounting Policies, page 63

2.	Comment: With respect to your critical accounting policies, to the extent practicable, please consider providing sensitivity analyses that express the potential change in your financial statements that would result from hypothetical changes to assumptions and estimates.

Response: We will give consideration to appropriate sensitivity analyses based on hypothetical changes in assumptions and estimates for each of our critical accounting policies and prospectively supplement our disclosures to the extent practicable.

Ameren Corporation Consolidated Balance Sheet, page 75

3.	Comment: Please disclose goodwill separately from intangible assets on the balance sheet. Refer to the requirements of paragraphs 42 and 43 of SFAS 142.

Response: Separate classification on our balance sheets responsive to the Staff’s comment was added beginning with our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, and continued in our Quarterly Reports on Form 10-Q for the quarterly periods ended June 30 and September 30, 2006, and will continue to be presented in that manner.

Ameren Corporation Consolidated Statement of Income, page 74

4.	Comment: Please explain why the $10 million impairment on Ameren’s investment in a leveraged lease was reported in the line item “Other operations and maintenance.” In this regard, please tell us how income and expenses from investments are generally classified in your income statement.

Response: Ameren considered the $10 million charge to be an impairment of a leveraged lease asset recorded on its balance sheet in accordance with paragraph 45 of SFAS 13. With consideration to the requirements of Regulation S-X Rule 5-03 and SAB Topic 5.P-3, Ameren concluded the appropriate presentation of this asset impairment was as a component of income from continuing operations within Ameren's statement of income. Accordingly, Ameren classified the impairment charge within Operating Expenses - Other operations and maintenance and provided disclosure of the nature of the charge on page 119 of its Annual Report on Form 10-K for the fiscal year ended December 31, 2005. Income and expenses associated with Ameren’s leveraged lease portfolio are reported on a gross basis as components of income from continuing operations. Investments held by

Ameren generally include its leveraged lease portfolio and nuclear decommissioning trust fund. Income and expenses associated with the nuclear decommissioning trust fund are deferred as regulatory assets and/or liabilities under the guidance of SFAS 71. We classify interest from temporary cash investments and intercompany notes receivable as miscellaneous income on our income statements.

Illinois Power Company Consolidated Statement of Cash Flows, page 100

Comment: With reference to the applicable accounting literature, please tell us how you concluded it was appropriate to classify prepaid interest related to a note receivable in financing activities rather than operating activities. In doing so, please tell us in greater detail the nature of the note receivable.

Response: Ameren acquired IP on September 30, 2004, from Dynegy Inc. (“Dynegy”). Prior to Ameren’s ownership of IP, IP completed a transaction whereby it sold its electric generation assets to an affiliate in exchange for a note receivable of $2.8 billion. Prior to the Ameren acquisition, Dynegy provided liquidity to IP in 2003 and 2004 in the form of cash payments designated as the prepayment of interest on the note receivable in order to meet debt service requirements and certain working capital needs of IP. Although these payments were characterized as prepaid interest, effectively Dynegy was providing IP a short-term, zero interest, borrowing arrangement which was repaid by IP as the interest was earned on the note receivable. Management of Dynegy and IP at the time concluded that these cash flows, although characterized as the prepayment of interest, were most appropriately classified as a financing activity in IP's statement of cash flows. The rationale for this conclusion was, in part, that they believed the classification of these receipts as an operating activity would inappropriately distort IP's cash flow from operations and not provide a user of the financial statements clarity as to how IP was obtaining necessary liquidity. As interest was actually earned on the note, IP presented the effects of the earned interest on net income and the reduction of the prepaid interest liability within operating activities in the statement of cash flows, as well as a financing activity cash outflow representing the repayment of these advances and an operating activity cash inflow representing the cash receipt of interest from Dynegy. The receipt and the repayment of the prepaid interest was presented net within the financing section of IP’s cash flow statement. As a result of this cash flow statement presentation approach, positive operating cash flows were presented in the period the interest was recognized and not in the period in which short-term borrowings were advanced to IP from Dynegy.

As part of Ameren’s assessment of IP's predecessor financial statements to be included in IP’s Commission filings subsequent to the acquisition,

the appropriateness of this cash flow treatment was considered. Ameren’s and IP’s conclusion was that an alternative presentation approach likely existed for this prepaid interest activity. However, Ameren and IP believed the manner in which Dynegy and IP presented this activity on the cash flow statement captured the substance of these transactions and did not warrant a revision to the historical presentation of IP’s predecessor statement of cash flows.

Combined Notes to Financial Statements, page 102

6.	Comment: Please provide all disclosures required by paragraphs 44-47 of SFAS 142.

Response: We respectfully believe disclosure substantially responsive to the Staff’s comment and paragraphs 44-47 of SFAS 142 was included in Note 1 - Summary of Significant Accounting Policies and Note 2 - Acquisitions in our Annual Report on Form 10-K for the fiscal year ended December 31, 2005. We also believe the nature of emission allowances does not lend itself well to the reporting of accumulated amortization because as each ton of emission allowance is utilized in the power generation process, it is fully amortized. However, we will add relevant disclosure related to the amortization of emission allowances for all periods presented beginning with our Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Additionally, we will include the disclosures required by paragraphs 46 and 47 of SFAS 142 in the event we record a material impairment of our goodwill or intangible assets in the future. We have not recorded such an impairment to date.

Note 2 - Acquisitions, page 110

7.	Comment: We note the IP transaction included a fixed-price capacity power supply agreement. Please clarify whether the power supply agreement terms were at market. Additionally, if any value was ascribed to the supply agreement, it should be disclosed.

Response: The terms of the fixed-price capacity power supply agreement with Dynegy Power Marketing, Inc. (“DYPM”) included in the IP transaction were above market. We respectfully believe our disclosure included in Note 2 - Acquisitions on page 110 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2005 is responsive to the Staff’s comment regarding value ascribed to the supply agreement. We have included the relevant disclosure below for your reference:

The fair value of IP’s power supply agreements, including the fixed-price capacity power supply agreement with DYPM recorded at the acquisition date, resulted in a net liability of $109 million (December 31, 2005 - $43

million). This amount is being amortized through December 31, 2006. In addition, IP recorded a fair value adjustment, resulting in a net asset of $20 million, which was fully amortized by December 31, 2005, for IP’s power supply agreement with EEI that expired at the end of 2005.

Comment: We note you elected to treat the acquisition of IP stock as an asset acquisition for federal tax purposes. We further note the amount of goodwill for financial purposes was $326 million, net of future tax benefits. Please supplementally show us, in summary form similar to your disclosure, how you allocated the purchase price of IP to the underlying assets for tax purposes. If any goodwill was recognized for tax purposes, advise whether it is deductible for tax purposes. If no goodwill was recorded for tax purposes, please advise your basis for the disparate allocations to amortizable assets for tax versus book purposes given both are required to be made at fair value. We may have further comment.

Response: The schedule below, in summary form similar to Ameren’s 2005 Form 10-K disclosure, compares the IP purchase price allocation for book purposes and federal income tax purposes.

ILLINOIS POWER COMPANY

Purchase Price Allocation

As of 09/30/2004

(In Millions)

10-K Comparison Book vs. Tax
	Book		Tax
Current assets	$	368	$	322
Property and plant		1,962		1,951
Investments and other noncurrent assets*		370		42
Goodwill		326		-
Total fair market value of assets acquired	$	3,026	$	2,315

Current liabilities		221		284
Long-term debt, including current maturities		1,982		1,656
Accrued pension and other postretirement liabilities		244		-
Other noncurrent liabilities		211		20
Total liabilities assumed	$	2,658	$	1,960

Preferred stock assumed		13		-
Net assets acquired	$	355	$	355

*Includes $157 million of deferred tax assets in the book column.

Ameren’s reference to “net of future tax benefits” in its disclosure was intended to inform the user of the financial statements that certain deferred tax assets were established in purchase accounting as a result of book and tax purchase price allocation differences as highlighted in the footnote above.

No goodwill has been recorded for federal income tax purposes to date because a portion of the purchase price is attributable to liabilities that do not give rise to tax basis until they are settled in cash. Certain liabilities recorded for financial reporting purposes are or will be immediately deductible for tax purposes when paid and will not be allocated to assets.

As stated in Ameren’s and IP’s Commission filings, based on estimates, Ameren and IP believe that after all liabilities are settled there will be some amount of goodwill recorded for tax purposes.

Note 3 - Rate and Regulatory Matters, page 111

CT Facilities Purchases, page 112

Comment: Please explain to us in detail the original structure of the NRG Audrain acquisition transaction with Audrain County. Ensure you explain how the transaction was structured (sale/leaseback, capital/operating), the related incentives (abatement of property taxes and/or tax exempt financing cost) and how the subsequent purchase and sale agreement, which resulted in UE obtaining the benefits of the facility, resulted in UE’s ownership of a taxable industrial development revenue bond. As part of the incentives requested above, explain what if any benefit to NRG resulted from a taxable bond issuance.

Response: The original April 15, 2000, transaction between NRG Audrain Generating LLC (“NRG”), formerly known as Duke Energy Audrain, LLC and Audrain County, Missouri was entered into pursuant to Chapter 100 of the Missouri Revised Statutes. Chapter 100 provides a redevelopment incentive to abate property taxation for qualified industrial development projects.

In a Chapter 100 transaction, the industrial development company (NRG in this case) conveys fee title in an industrial property to a Missouri county, city or other tax-exempt political entity and leases it back to operate. The purpose of the sale/leaseback is to vest title to the real estate, including improvements, in an entity exempt from property taxation.

In exchange, the industrial development company (as Chapter 100 leaseback tenant) typically enters into a contract with the exempt landlord and/or various of the taxing districts with jurisdiction over the real estate, pursuant to which the company agrees to make grant payments or other payments, in lieu of taxes, for a period of years, typically 10-20 years, for some amount less than the amount otherwise payable in property taxes. Often, as further consideration for

the partial property tax abatement, the company will agree to employ a certain number of persons at the constructed facility.

The Chapter 100 sale/leaseback is also structured as a financing, in that the tax-exempt landlord will issue a bond or bonds in the principal amount necessary to finance the construction of the facility. The bonds are most often held by the industrial development company itself. Rental payments under the leaseback are equal to the amount of principal and interest then owing on the bonds, creating a circular transaction. Often rent is “paid” once per year simply by reducing the amount owing on the bond payable to the industrial development company (tenant).

In addition, at the expiration of the term of the lease, the industrial development company is obligated to take fee title back.

Pursuant to the lease agreement between Audrain County and NRG, NRG was permitted to assign all of the Chapter 100 sale/leaseback tax abatement benefits upon satisfaction of certain conditions. Similarly, the underlying bond was assignable pursuant to the trust indenture between Audrain County and the indenture trustee.

On March 28, 2006, UE took assignment of the Chapter 100 sale/leaseback benefits and the rights of NRG under the indenture, bond, and Chapter 100 lease agreement. In addition, the bond was physically delivered to UE in the principal amount of $240 million.

The underlying bond was not taxable to the bondholder and no benefit would have accrued to NRG, as the assignor of the bond and tax abatement benefits, at the March 28, 2006, assignment.

For accounting purposes, Ameren and UE recorded the sale/leaseback structure and the bond following the guidance of SFAS 98 and SFAS 115. Accordingly, Ameren and UE recorded the value of the combustion turbine generation facility as an asset equal to the cash purchase price it paid. The investment in the acquired bond and the remaining lease obligation related to the facility were recorded at fair value and were presented gross on Ameren’s and UE’s balance sheets because they did not meet the requirements for offset as contemplated in FIN 38. Ameren and UE classified the bond as held-to-maturity as defined in SFAS 115. Ameren and UE did not recognize any gain or loss in conjunction with this acquisition.

Missouri - Electric, page 113

10.

Comment: We note the August 2002 stipulation and agreement included the phase-in of $110 million of electric rate reductions, $50 million of which was retroactively effective as of April 1, 2002. Please help us understand the significance of the term “retroactively effective.” In this regard, please advise whether this term has any connection to retroactive rate making.

Response: The term "retroactively effective" reflects UE's voluntary acceptance of a retroactive rate decrease in connection with a Stipulation and Agreement (the "Stipulation") resolving a 2002 Missouri electric rate complaint case. The rate decrease resulting from the Stipulation was ordered by the Missouri Public Service Commission (“MoPSC”) in August 2002 and required UE, in order to satisfy its voluntary agreement, to apply the new rates "retroactively" to April 1, 2002. The term "retroactively effective" has no connection to the general prohibition against "retroactive ratemaking" in this case because of UE's voluntary agreement to apply the rate decrease retroactively. UE accrued for the impact of this retroactive rate decrease as a reduction of revenue in the quarter ended June 30, 2002.

Illinois - Electric, page 115

11.

Comment: We note that Illinois electric rates are frozen through 2007, with a possible rate freeze extension for several additional years. In light of this fact, the recent political support for an extension of the rate freeze period and the history of declining/flat rates in Illinois, please describe your consideration of the continued applicability of SFAS 71 in Illinois. In doing so, please specifically address how you believe your current regulated rates are currently designed to recover your specific costs of providing service as discussed in paragraph 5(b) of SFAS 71. Tell us the test period and the date of your last rate case for each utility operating in the State of Illinois. Indicate how the last rate case has been updated for major cost changes in the cost structure of the related utility. We may have further comment.

Response: Ameren wholly owns three Illinois rate-regulated electric and gas distribution utilities, CIPS, CILCO and IP (collectively, the “Ameren Illinois Utilities”). Electric customers of the Ameren Illinois Utilities today have the option of paying a “bundled” tariff that covers energy and delivery costs of service or a “delivery service” tariff that covers just delivery costs allowing the customer to procure energy from an alternative supplier. Currently, on average, 100%, 92% and 59% of the Ameren Illinois Utilities’ residential, commercial, and industrial customers, respectively, pay a bundled tariff based on consumption.

The current bundled tariffs offered by the Ameren Illinois Utilities were initially established as follows by the Illinois Commerce Commission (“ICC”):

Bundled Rate Case Data

	Filing Date	Test Year	Date of Order
CIPS	April 24, 1991	1992	March 19, 1992
IP	March 19, 1991	1992	February 11, 1992
CILCO	August 6, 1981	1982	July 1, 1982

In 1987, the bundled rates for CILCO were adjusted downward to reflect the impact of the Tax Reform Act of 1986. In addition, CIPS issued refunds associated with the Tax Reform Act of 1986 as a result of a 1992 settlement in an ICC proceeding covering the period dating back to 1986. Then, in 1997, the state legislature amended the Illinois Public Utilities Act providing for deregulation of electric generation during a “mandatory transition period.” As a result of the deregulation legislation, each of the Ameren Illinois Utilities applied the provisions of SFAS 101 in the fourth quarter of 1997 to the electric generation portion of their businesses. The mandatory transition period is set to expire December 31, 2006.

Major provisions of the 1997 amendment to the Illinois Public Utilities Act included the following:

Reductions in residential electric rates at varying percentages and dates depending upon the individual utility’s size (based upon customers served) and rates relative to Midwest average rates. The Ameren Illinois Utilities experienced the following rate reductions during the mandatory transition period: 5% for CIPS, 15% for IP and 2% for CILCO in August 1998, 2% for CILCO in October 2000, 1% for CILCO in October 2002, and 5% for IP in May 2002.

·	Gradual consumer access to competitive generation beginning in October of 1999 for the state’s largest energy consumers with eventual access granted to all customers by May 2002.

Continued cost-based rate regulation based upon earnings caps and floors, continuation of fuel adjustment clauses at the discretion of the utilities, and continued filing of financial information with the Federal Energy Regulatory Commission (“FERC”) and ICC consistent with the FERC uniform system of accounts. The earnings cap and floor were set as follows:

Ø	Half of excess earnings from the Illinois jurisdiction for the years 1998 through 2006 are required to be refunded to UE’s, CIPS’, CILCO’s and IP’s Illinois customers. Excess earnings are defined by the 1997 amendment to the Illinois Public Utilities Act as the portion of the two-

year average annual rate of return on common equity in excess of 1.5% of the two-year average of the Index. The current Index is defined as the sum of the average for the 12 months ended September 30 of the monthly yields of the Treasury long-term average rate plus 7% for CIPS, 11% for CILCO and 7% for IP.

Ø	The ability to seek a rate increase if the two-year average return on common equity falls below the Treasury long-term average rate (i.e. an earnings floor) based on FERC Form 1 financial statements.

·	Departing customers are obligated to pay applicable transition charges to enable the utility to recover stranded costs with respect to that customer.

The Ameren Illinois Utilities believe that it was the intent of the legislature during the mandatory transition period to allow electric customers the ability to begin migrating to competition, allow utilities to restructure their operations in order to facilitate competition and at the same time continue to monitor the financial health of the utilities and provide a means for adjusting rates using traditional cost of service methods should rates be judged to be too high or too low as indicated by returns on equity above or below normative bands.

Under Ameren’s ownership of the Ameren Illinois Utilities, with one limited exception, each company achieved returns on equity above the floor established in the 1997 amendment to the Illinois Public Utilities Act. This illustrates that the Ameren Illinois Utilities were collecting rates during the mandatory transition period that provided recovery of the costs they were incurring plus providing a return on equity. In 2003, CIPS’ two-year average return on common equity was 4.75% compared to a floor of 5.23% primarily as a result of unfavorable weather conditions and an unusual charge for a voluntary retirement plan. From 1998 to 2003, UE made refunds to Illinois customers as required by the amended Illinois Public Utilities Act. UE’s Illinois electric and natural gas transmission and distribution assets were transferred to CIPS in May, 2005.

During the mandatory transition period the ICC established electric delivery service rates for each of the Ameren Illinois Utilities for those customers that chose an alternative power supplier and also ordered subsequent rate increases and decreases to their delivery service rates. A summary of those cases is provided below:

Delivery Service Case Data

CIPS

Filing Date	Test Year Ending	Date of Order	Increase in Revenue Requirement
March 1, 1999	Sept. 30, 1998	August 25, 1999	(a)
December 15, 2000	1999	December 11, 2001	9.7%
December 27, 2005	2004	November 21, 2006	20.0%

IP
Filing Date	Test Year Ending	Date of Order	Increase in Revenue Requirement
March 5, 1999	1997	August 25, 1999	(a)
June 1, 2001	2000	March 28, 2002	10.7%
December 27, 2005	2004	November 21, 2006	39.1%

CILCO
Filing Date	Test Year Ending	Date of Order	Increase in Revenue Requirement
March 5, 1999	1997	August 25, 1999	(a)
October 3, 2001	2000	March 28, 2002	5.2%
December 27, 2005	2004	November 21, 2006	25.1%

UE (b)
Filing Date	Test Year Ending	Date of Order	Decrease in Revenue Requirement
March 1, 1999	Sept. 30, 1998	August 25, 1999	(a)
December 15, 2000	1999	December 11, 2001	(2.6%)

(a)

Initial delivery service rates established

(b)

In May 2005, UE’s Illinois electric and natural gas transmission and distribution assets were transferred to CIPS.

In each of these cases the ICC examined the Ameren Illinois Utilities’ cost of service and, using traditional rate-making methods, set cost-based rates. The economic impacts of the ICC’s findings in those cases support the regulatory assets and liabilities recognized by the individual Ameren Illinois Utilities.

Additionally, we believe the fact that the ICC granted IP future rate recovery for costs incurred in connection with Ameren’s acquisition of IP provides additional evidence of the ongoing regulatory oversight of the design and level of rates as contemplated by SFAS 71.

Beginning January 2, 2007, we believe that all electric customers of the Ameren Illinois Utilities will be required to move to the delivery service tariff and either pay an energy charge to the Ameren Illinois Utilities (representing a pass-through of actual market-based energy costs) or procure power from an alternative supplier. The Ameren Illinois Utilities expect customers’ combined cost of electricity (for those taking delivery and energy services) to be 40 to 55% higher than the bundled tariff rates paid today due primarily to the relatively high cost of energy in the wholesale markets relative to the energy costs embedded in their bundled rates. The Ameren Illinois Utilities believe that this new rate structure, which has been approved by the ICC, will go into effect despite political discussion around the possibility of freezing rates at the present bundled tariff level. Further, the Ameren Illinois Utilities believe a rate freeze extension would be unlawful and that the probability of the rate freeze being extended beyond January 1, 2007, is remote.

The Ameren Illinois Utilities conclusion, based upon consideration of the factors above, and the requirements for application of SFAS 71, as set forth in paragraph 5, is that it remains applicable. While the bundled rates currently being paid by many customers were originally set 15 to 25 years ago, the rates have been adjusted and remain subject to adjustment by the ICC based on changes in cost of service and resulting returns on equity outside of a normative range. Further, beginning January 2, 2007, we believe that it is probable that all customers will begin paying electric rates resulting from very recent rate cases that are based on each utility’s specific costs of providing service.

Note 6 - Long-Term Debt and Equity Financings, page 124

Ameren, page 127

12.	Comment: Please disclose the effect of the $191 million adjustment to total IP debt on results of operations for the next five years. Refer to Instruction 2 to Rule 11-02 of Regulation S-X for analogous guidance.

Response: Disclosure responsive to the Staff’s comment will be added beginning with our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

Note 11 - Retirement Benefits, page 136

13.	Comment: With respect to your postretirement benefits, we note that you include the estimated increase in future compensation as an actuarial assumption. Please explain to us how postretirement benefits are contingent on future salaries.

Response: A salary increase assumption is required to project retiree life insurance amounts for a very small number of active union-represented employees for the postretirement benefit valuation.

Note 15 - Commitments and Contingencies, page 150

Leases, page 151

14.

Comment: Please revise your presentation of capital lease future minimum lease payments to include separate deductions from the total for the amount representing executory costs, including any profit thereon, and for the amount of the imputed interest necessary to reduce the net minimum lease payments to present value. See paragraph 16(a)(ii) of SFAS 13.

Response: Disclosure responsive to the Staff’s comment related to imputed interest will be added beginning with our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

Item 9A. Controls and Procedures, page 163

(a) Evaluation of Disclosure Controls and Procedures, page 163

15.

Comment: You state that your certifying officers concluded that your disclosure controls and procedures were effective in “timely alerting them to any material information relating to such registrant that is required in such registrant’s reports filed or submitted to the SEC under the Exchange Act, and are effective in ensuring that information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.” In future filings, please revise your conclusion to include the full definition of disclosure controls and procedures as outlined in Exchange Act Rule 13a-15(e) rather than the summarized definition you include now. In this regard, please revise to state, if true, whether the same officers concluded the controls and procedures were effective to “ensure that information required to be disclosed by [you] in the reports that [you] file or submit under the Act is accumulated and communicated to [your] management, including [your] principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.” Additionally, please confirm to us that your conclusion regarding effectiveness would not change had this statement been included in this filing and Forms 10-Q for fiscal quarters ended March 31, 2006, June 30, 2006 and September 30, 2006.

Response: The paragraph under “Item 9A. Controls and Procedures” following the heading “(a) Evaluation of Disclosure Controls and Procedures” will be revised in future filings, if true, to read as follows:

As of [the end of the period covered by this report], evaluations were performed, under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

Each registrant hereby confirms that the conclusions of its principal executive officer and principal financial officer would not have changed had the above statement been included in the Form 10-K for the fiscal year ended December 31, 2005, and the Form 10-Qs for the fiscal quarters ended March 31, June 30, and September 30, 2006.

16.

Comment: We note your disclosure that there have been no changes in your internal control over financial reporting during the most recent fiscal quarter “except that in the fourth quarter of 2005, [you] completed the implementation of a new fixed-asset application system.” In future filings, please avoid using qualifying language such as “except that…” and instead state clearly whether there have or have not been any changes in your internal control over financial reporting. Refer to Item 308(c) of Regulation S-K.

Response: In future filings, we will avoid the use of qualifying language in our disclosure of whether there have been any changes in internal control over financial reporting and will clearly state whether or not there have been any changes in internal control over financial reporting.

Exhibits 31 and 32

17.	Comment: In future filings, please provide separate Section 302 and Section 906 certifications for each registrant.

Response: We will provide separate Section 302 and Section 906 certifications for each registrant beginning with our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

Form 10-Q for Fiscal Quarter Ended September 30, 2006

Ameren Corporation Consolidated Statement of Cash Flows, page 10

18.

Comment: We note you reclassified emission allowance purchases and sales from operating activities to investing activities in your statement of cash flows to make prior periods conform to the change in classification in 2006. However, it appears you always classified your emission allowances as intangible assets on the balance sheet. In this regard, please tell us why you did not previously classify emission allowance purchases and sales as investing activities in your statement of cash flows. We believe this would be consistent with paragraph 16(c) and 17(c) of SFAS 95 based on your balance sheet classification of the related asset. Lastly, please explain to us why you did not treat the reclassification from operating activities to investing activities as a correction of an error via amendment to Form 10-K.

Response: Prior to July 1, 2005, Ameren accounted for emission allowance transactions on an inventory model. Consistent with that model, Ameren classified emission allowances as other assets on its consolidated balance sheet and presented cash flows related to these transactions as operating activities within its statement of cash flows. During the third quarter of 2005, Ameren exchanged a quantity of certain vintage year emission allowances for a quantity of different vintage year emission allowances with various third parties. No cash was included in these exchange transactions. Also in conjunction with third quarter 2005 financial reporting, we were required to adopt SFAS 153. Based on their consultations with the FASB staff in October and November 2005, which were driven in part as a result of our third quarter 2005 exchange transactions, our independent auditors advised us that emission allowance exchange transactions were subject to the requirements of SFAS 153 and should be accounted for on a fair value basis. Accordingly, we concluded that fair value accounting was appropriate. Further, applying the requirements of SFAS 153 to these exchange transactions also resulted in our change of accounting policy to the intangible model for emission allowances. We disclosed these exchange transactions, the accounting applied and the related gain in our Form 10-Q for the quarterly period ended September 30, 2005. We

did not obtain a preferability letter in connection with this accounting change because we did not believe it constituted a material change in accounting. This change primarily resulted in the reclassification of approximately $250 million from materials and supplies to other intangible assets. We further highlight our understanding that the Staff of the Commission subsequently expressed their view to the FASB staff and our independent auditors that both the inventory and the intangible models were acceptable emission allowance accounting policies under current GAAP. Accordingly, we have continued to apply the intangible model as we had previously elected.

In connection with our change in accounting from the inventory to the intangible model, we concluded that operating activity classification for cash flows related to emission purchase and sale transactions remained appropriate. In reaching this conclusion, we considered 1) the guidance of SFAS 95, paragraph 24, which recognizes that “certain cash receipts and payments may have aspects of more than one class of cash flows," 2) our conclusion that paragraphs 22 and 23 of SFAS 95 best described the nature of these transactions, 3) our operational practices with respect to emission allowances, and 4) our view of predominant industry practice at that time. As a result, our emission allowance purchases and sales activity for the period July 1, 2005 to March 31, 2006, was classified as operating activities in our statement of cash flows included in the applicable Form 10-Qs and Form 10-K filed with the Commission during that period.

During the second quarter of 2006, we concluded that classification of emission allowance purchases and sales as an investing activity, primarily referring to the guidance of paragraphs 16 and 17 of SFAS 95, was a more preferable presentation and aligned more closely with our application of the intangible model. In reaching this conclusion, we viewed this as a change from one acceptable cash flow classification policy to another acceptable cash flow classification policy. During our consideration of this conclusion, we noted the lack of specific guidance with respect to accounting for emission allowances as well as our view that SFAS 95 contemplates the possibility of this type of classification change based on modified views. This change did not constitute the correction of an error. We reflected this change in our financial statement presentation for the second quarter 2006 and revised the prior period to conform to our current presentation. We followed this same presentation approach for the third quarter ended 2006 and will do so as well in our 2006 Annual Report on Form 10-K for all financial statement periods presented. For the years ended December 31, 2003, 2004 and 2005, we purchased $2 million, $9 million and $92 million of emission allowances, respectively, and sold $32 million, $35 million and $22 million of emission allowances, respectively.

Form 8-K Filed, August 3, 2006

19.	Comment: We note your presentation of 2006 non-GAAP earnings guidance. In accordance with Regulation G, please reconcile this non-GAAP measure to the most comparable measure calculated in accordance with GAAP.

Response: The impact of the severe storms occurring on July 19 and 21, 2006 were excluded from Ameren’s updated 2006 earnings guidance because reliable cost estimates were not available on August 3, 2006, the date this information was furnished pursuant to the Form 8-K.

In connection with this response to the Staff’s comments, the registrants each acknowledge:

•	such registrant is responsible for the adequacy and accuracy of the disclosure in the registrant’s filings;
•	Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to such registrant’s filings; and
•	such registrant may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

If you have any questions concerning responses to these comments, please contact the undersigned at (314) 554-2982 or Bruce Steinke at (314) 554-2574.

Very truly yours,

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Vice President and Controller

Ameren Corporation

Union Electric Company

Central Illinois Public Service Company

Ameren Energy Generating Company

CILCORP Inc.

Central Illinois Light Company

Illinois Power Company