Ameren Consolidated 10-Q

The status of future remediation at Sauget Area 2 and compliance with the Unilateral Administrative Order is uncertain, so we are unable to predict the ultimate impact of the Sauget Area 2 site on our results of operations, financial position, or liquidity. In December 2004, the U.S. Supreme Court, in Cooper Industries, Inc., vs. Aviall Services, Inc., limited the circumstances under which potentially responsible parties could assert cost-recovery claims against other potentially responsible parties. As a result of this ruling, it is possible that UE may not be able to recover from other potentially responsible parties the costs it incurs in complying with EPA orders. Any liability or responsibility that may be imposed on UE as a result of this Sauget, Illinois, environmental matter was not transferred to CIPS as a part of UE’s May 2005 Illinois utility service territory transfer to CIPS.

In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $3 million at June 30, 2006, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.

In addition, our operations, or those 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 activities may have on our results of operations, financial position, or liquidity.

Pumped-storage Hydroelectric Facility Breach

In late May 2006, the FERC released a report by an Independent Panel of Consultants on the technical reasons for the December breach. The report cited the primary cause of the Taum Sauk breach as overtopping of the upper reservoir dam due to improperly maintained and installed water level monitors. The report stated that the monitors became loose and indicated reservoir levels lower than actual levels. In addition, the panel found emergency backup sensors proved ineffective because they were set at an elevation above the lowest points along the parapet wall on the top of the reservoir. As a result, the sensors failed their protection role because their location enabled the overtopping to occur before the probes could trigger a shutdown. The report stated that another factor contributing to the overtopping was that UE typically operated with high water levels of one foot below the top of the parapet wall, which was not enough to take into account possible mistakes in project operation. A secondary cause, the report said, was the marginally stable dumped

“dirty” (silt, sands and gravels) rockfill embankment and associated parapet wall.

The facility will remain out of service until reviews by FERC and state authorities are concluded, further analyses are completed, and input is received from key stakeholders as to how and whether to rebuild the facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through most, if not all, of 2008.

UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. UE expects the total cost for damage and liabilities resulting from the Taum Sauk incident to range from $63 million to $83 million. As of June 30, 2006, UE had paid $27 million and accrued a $36 million liability, while expensing $11 million and recording a $52 million receivable due from insurance companies. No amounts have been recognized in the financial statements relating to estimated costs to repair or rebuild the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.

As a result of this breach, UE may be subject to litigation by private parties or by state or federal authorities. Until the reviews conducted by state and federal authorities have concluded, the insurance review is completed, a decision whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.

Asbestos-related Litigation

Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 129 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of June 30, 2006, the average number of parties is 67.

The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and most former CILCO 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 CIPS and CILCO generating plants, CIPS and CILCO contractually agreed to indemnify Genco and 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 proved, typically would be shared among the named defendants.

From April 1, 2006, through June 30, 2006, seven additional asbestos-related lawsuits were filed against Ameren, UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois. Three lawsuits were dismissed and two were settled. The following table presents the status as of June 30, 2006, of the asbestos-related lawsuits that have been filed against the Ameren Companies:

			Specifically Named as Defendant
	Total^(a)		Ameren		UE		CIPS		Genco		CILCO		IP
Filed		310		31		166		125		2		36		144
Settled		95		-		48		39		-		10		48
Dismissed		143		22		92		46		2		6		63
Pending		72		9		26		40		-		20		33

(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 June 30, 2006, six 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.

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.

The ICC order approving Ameren’s acquisition of IP effective September 30, 2004, also approved a tariff rider to recover the costs of IP’s 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.

Retiree Medical Plan Litigation

In June 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, against Ameren, UE, CIPS, Genco and Ameren Services, and against our Retiree Medical Plan, and by an amended complaint, against our Group 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., alleged, among other things, that the defendants’ recent actions requiring retirees to pay a portion of their own health care premiums or increasing the premiums paid by dependents or surviving spouses of retirees violate ERISA and the Labor Management Relations Act of 1947 and constitute a breach of the defendants’ fiduciary duties. In February 2006, the U.S. Seventh Circuit Court of Appeals affirmed a district court’s granting of summary judgment in favor of the defendants. This decision is final and not subject to further appeal.

NOTE 9 - CALLAWAY NUCLEAR PLANT

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or ¹/₁₀ of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.

Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. It is assumed that the Callaway nuclear plant site will be

decommissioned based on immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2005, 2004 and 2003. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest study was filed in 2005. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally restricted. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to a regulatory asset.

NOTE 10 - 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 six months ended June 30, 2006 and 2005, is shown below for the Ameren Companies:

	Three Months						Six Months
	2006			2005			2006			2005
Ameren:^(a)
Net income	$	123		$	185		$	193		$	306
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $7, $4, $(2) and $10, respectively		11			1			(4	)		18
Reclassification adjustments for (gains) included in net income, net of taxes of $2, $1, $5 and $1, respectively		(3	)		(2	)		(8	)		(2	)
Total comprehensive income, net of taxes	$	131		$	184		$	181		$	322
UE:
Net income	$	92		$	132		$	143		$	189
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $-, $(1) and $2, respectively		1			(1	)		(1	)		3
Reclassification adjustments for (gains) included in net income, net of taxes of $1, $-, $2 and $-, respectively		(1	)		-			(3	)		-
Total comprehensive income, net of taxes	$	92		$	131		$	139		$	192

	Three Months						Six Months
		2006			2005			2006			2005
CIPS:
Net income	$	15		$	7		$	14		$	15
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(1), $(1) and $3, respectively		-			(2	)		(2	)		4
Reclassification adjustments for (gains) included in net income, net of taxes of $1, $1, $2 and $ -, respectively		(1	)		(1	)		(3	)		(1	)
Total comprehensive income, net of taxes	$	14		$	4		$	9		$	18
Genco:
Net income	$	2		$	31		$	8		$	62
Unrealized (loss) on derivative hedging instruments, net of taxes of $-, $-, $- and $ -, respectively		-			-			-			(1	)
Total comprehensive income, net of taxes	$	2		$	31		$	8		$	61
CILCORP:
Net income	$	1		$	2		$	9		$	11
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(2), $(1), $(7) and $7, respectively		(3	)		(1	)		(11	)		12
Reclassification adjustments for (gains) losses included in net income, net of taxes of $-, $-, $3 and $-, respectively		-			(1	)		(4	)		1
Total comprehensive income (loss), net of taxes	$	(2	)	$	-		$	(6	)	$	24
CILCO:
Net income	$	8		$	10		$	25		$	26
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(2), $(1), $(7), and $7, respectively		(3	)		(1	)		(11	)		11
Reclassification adjustments for (gains) included in net income, net of taxes of $-, $-, $3 and $-, respectively		-			(1	)		(4	)		-
Total comprehensive income, net of taxes	$	5		$	8		$	10		$	37
IP:
Net income	$	16		$	15		$	20		$	37
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $-, $(1) and $-, respectively		-			-			(1	)		-
Reclassification adjustments for losses included in net income, net of taxes (benefit) of $-, $-, $(1) and $-, respectively		-			-			1			-
Total comprehensive income, net of taxes	$	16		$	15		$	20		$	37

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

NOTE 11 - RETIREMENT BENEFITS

Ameren’s pension plans are funded in compliance with income tax regulations and federal funding requirements. Based on our assumptions at December 31, 2005, and assuming continuation of the recently expired federal interest rate relief beyond 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2011 at which time we would expect a required contribution of $100 million to $150 million. If federal interest rate relief is not continued in its most recent form, $200 million to $300 million may need to be funded in 2009 to 2010 based on other recent federal legislative proposals. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Ameren is considering whether to make voluntary contributions in the second half of 2006.

Ameren made a contribution to its postretirement benefit plan of $37 million in the second quarter of 2006 as compared to $35 million in the second quarter of the prior year.

The following tables present the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three months and six months ended June 30, 2006 and 2005:

	Pension Benefits^(a)
	Three Months						Six Months
	2006			2005			2006			2005
Service cost	$	15		$	14		$	31		$	29
Interest cost		43			41			86			83
Expected return on plan assets		(49	)		(45	)		(98	)		(91	)
Amortization of:
Prior service cost		3			3			5			5
Actuarial loss		10			9			21			19
Net periodic benefit cost	$	22		$	22		$	45		$	45

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

	Postretirement Benefits^(a)
	Three Months						Six Months
	2006			2005			2006			2005
Service cost	$	5		$	5		$	11		$	11
Interest cost		15			17			33			36
Expected return on plan assets		(11	)		(11	)		(23	)		(23	)
Amortization of:
Transition obligation		1			1			1			1
Prior service cost		(2	)		(1	)		(3	)		(2	)
Actuarial loss		7			9			17			19
Net periodic benefit cost	$	15		$	20		$	36		$	42

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

UE, CIPS, Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are responsible for their proportional share of the pension and postretirement costs. The following tables present the pension costs and the postretirement benefit costs incurred for the three months and six months ended June 30, 2006 and 2005:

	Pension Costs
	Three Months				Six Months
		2006		2005		2006		2005
UE	$	13	$	13	$	26	$	26
CIPS		3		3		6		6
Genco		1		2		3		4
CILCORP		3		3		5		6
CILCO		4		5		7		9
IP		2		1		4		3

	Postretirement Costs
	Three Months				Six Months
		2006		2005		2006		2005
UE	$	8	$	11	$	19	$	22
CIPS		2		3		5		6
Genco		1		1		2		2
CILCORP		1		2		4		6
CILCO		2		3		7		9
IP		3		3		7		6

NOTE 12 - SEGMENT INFORMATION

Ameren’s reportable segment Utility Operations comprises its electric generation and electric and gas transmission and distribution operations. It includes the operations of UE, CIPS, Genco, CILCORP, CILCO and IP. Ameren’s reportable segment Other consists of the parent holding company, Ameren Corporation.

The accounting policies for segment data are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data includes intersegment revenues, as well as a charge for allocating costs of administrative support services to each of the operating companies, which in each case is eliminated upon consolidation. Ameren Services allocates administrative support services based on various factors, such as head count, number of customers, and total assets.

The following table presents information about the reported revenues and net income of Ameren for the three months and six months ended June 30, 2006 and 2005:

	Utility Operations		Other			Reconciling Items^(a)			Total
Three Months 2006:
Operating revenues	$	1,982	$	-		$	(432	)	$	1,550
Net income		121		2			-			123
Three Months 2005:
Operating revenues	$	1,956	$	-		$	(372	)	$	1,584
Net income		186		(1	)		-			185
Six Months 2006:
Operating revenues	$	4,234	$	-		$	(884	)	$	3,350
Net income		192		1			-			193

Utility Operations

Other

Reconciling Items^(a)

Total

Six Months 2005:
Operating revenues	$	3,900	$	-		$	(697	)	$	3,203
Net income		311		(5	)		-			306

(a)	Elimination of intercompany revenues.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

OVERVIEW

Ameren Executive Summary

Ameren’s second quarter and first half of 2006 earnings were lower than the strong earnings achieved last year. Several factors contributed to Ameren’s decreased earnings versus the year-ago periods. Electric margins were negatively impacted by higher fuel and purchased power costs due primarily to increased coal and related transportation costs, an unplanned outage at our Callaway nuclear plant and milder winter weather. In addition, Ameren incurred additional costs of operating in the MISO Day Two Energy Market in the first six months of 2006 because MISO Day Two operations did not commence until the second quarter last year. Incremental costs resulting from the December 2005 breach of the upper reservoir at UE’s Taum Sauk hydroelectric pumped-storage plant also negatively impacted second quarter and first half 2006 earnings. Significant planned power plant outages and some unplanned outages reduced second quarter 2006 earnings as compared to the prior-year period. These factors offset increased margins from interchange sales and organic growth compared to the second quarter and first six months of last year.

In Illinois, we are moving into a critical stage as the scheduled September 2006 power procurement auction fast approaches, the Illinois delivery service rate cases come to a close, and the Illinois fall legislative session commences in November. In delivery services rate filings made in late December 2005, CIPS, CILCO and IP requested a total combined annual electric revenue increase of approximately $200 million. In June 2006, the ICC staff filed rebuttal testimony recommending increases in revenues for electric delivery services for the Ameren Illinois utilities aggregating $120 million. The Illinois attorney general also filed rebuttal testimony, which we estimate would result in revenue increases aggregating approximately $100 million. The ICC has until November of this year to issue a final decision in these cases. As a result of the potential increases to ratepayers from these requested increases and the transition to market-based power costs, there have been two pieces of legislation proposed in Illinois. One proposal includes a potential extension of the rate freeze through 2010, which we believe is without legal merit. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power or other costs from their electric customers in a timely manner could result in material adverse consequences for these companies and Ameren. Following the introduction of the rate freeze proposal, a second separate and constructive piece of legislation was introduced, which authorized the issuance of securitization bonds. This approach has the effect of spreading over the life of the bonds, a period of up to 10 years, the potentially significant initial electric rate increase for residential customers that would otherwise be necessary to pay the power procurement costs on a current basis. In June 2006, CIPS, CILCO and IP filed a proposal with the ICC for a rate increase phase-in and revenue securitization plan for residential customers similar to the securitization legislation that was introduced that would result in deferral of power supply costs for 2007 and 2008.

In early July, UE filed requests with the MoPSC to increase base rates for electric service by $361 million and to increase base rates for gas service by $11 million. The primary drivers of the requested electric increase were significant investments in critical energy infrastructure, as well as significantly higher operating expenses. In conjunction with the filing of the electric rate case in Missouri, UE, CIPS and Genco mutually agreed to terminate the JDA on December 31, 2006. We expect a decision from the MoPSC on both filings by June 2007.

On July 19, 2006 and July 21, 2006, UE’s, CIPS’ and IP’s service territories were hit by severe storms, which included tornados, that resulted in the loss of power to approximately 700,000 customers combined. Through the dedication of a work force of 5,200 people, including our employees, contractors and utility workers from 13 states, we restored service to all of our customers within nine days. The full financial impact of these storms has not yet been determined, but UE, CIPS and IP have incurred unanticipated costs, and the loss of electric margins as a result of these devastating storms.

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935, until that act was repealed effective February 8, 2006. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s subsidiaries, which are separate, independent legal entities with separate businesses, assets and liabilities, operate rate-regulated electric generation, transmission and distribution

businesses, rate-regulated natural gas transmission and distribution businesses and non-rate-regulated electric generation businesses in Missouri and Illinois, as discussed below. Dividends on Ameren’s common stock depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. 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 subsidiaries.

·	UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Before May 2, 2005, UE also operated those businesses in Illinois.

·	CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

·	Genco operates a non-rate-regulated electric generation business in Illinois and Missouri.

·	CILCO, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric and natural gas transmission and distribution business and a primarily non-rate-regulated electric generation business (through its subsidiary, AERG), in Illinois.

·	IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on weighted-average diluted common shares outstanding during the applicable period. All tabular dollar amounts are in millions, unless otherwise indicated.

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 affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. Approximately 85% of Ameren’s 2005 revenues were directly subject to state and federal regulation. This regulation 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 and with the expiration of Genco’s and AERG’s supply contracts with CIPS and CILCO at the end of 2006, these companies’ and Ameren’s earnings will be subject to increased volatility. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do not currently 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. Since rates for UE, CIPS, CILCO and IP are regulated, cost decreases or increases will not be immediately reflected in rates. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risks and other risks inherent in our businesses. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Ameren’s net income decreased to $123 million, or 60 cents per share, in the second quarter of 2006 from $185 million, or 93 cents per share, in the second quarter of 2005. Ameren’s net income decreased $113 million to $193 million, or 94 cents per share, for the six months ended June 30, 2006, compared to earnings of $306 million, or $1.55 per share, in the first six months of 2005. Earnings were negatively impacted for the three-month and six-month periods by increased fuel and purchased power costs, milder weather, lower prices for interchange sales, an unscheduled outage at UE’s Callaway nuclear plant in the second quarter of 2006, costs associated with an upper reservoir breach in December 2005 at UE’s Taum Sauk plant and incremental costs of operating in the MISO Day Two Energy Market. Decreased availability of coal-fired power plants also reduced second quarter 2006 earnings as compared to the prior-year period. Additionally, an increase in the number of common shares outstanding in the current year periods reduced Ameren’s earnings per share. Increased margins on interchange sales at EEI and organic growth partially offset the impact of these unfavorable items on current year earnings.

Because it is 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 six months ended June 30, 2006 and 2005:

	Three Months					Six Months
	2006			2005		2006		2005
Net income (loss):
UE^(a)	$	90		$	130	$	140	$	186
CIPS		15			7		13		14
Genco^(a)		2			31		8		62
CILCORP^(a)		1			2		9		11
IP		16			15		19		36
Other^(b)		(1	)		-		4		(3	)
Ameren net income	$	123		$	185	$	193	$	306

(a)	Includes earnings from market-based interchange power sales that provided the following contributions to net income for the three-month and six-month periods, respectively:

UE: 2006 - $14 million, $34 million

2005 - $25 million, $46 million

Genco: 2006 - $3 million, $10 million

2005 - $15 million, $27 million

CILCORP: 2006 - $5 million, $12 million

2005 - $4 million, $9 million

(b)	Includes earnings from non-rate-regulated operations and a 40% interest in EEI held by Resources Company, corporate general and administrative expenses, and intercompany eliminations.

Electric Operations

The following table presents the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power costs, for the three months and six months ended June 30, 2006, as compared with the year-ago periods. We consider electric and interchange margins useful measures to analyze the change in profitability of our electric operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, electric and interchange margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months	Ameren^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	(16	)	$	(8	)	$	(2	)	$	-		$	(2	)	$	(2	)	$	(4	)
Growth and other (estimate)		(23	)		(5	)		19			(2	)		2			3			7
Interchange revenues		10			(26	)		(7	)		(26	)		(2	)		(2	)		-
Total	$	(29	)	$	(39	)	$	10		$	(28	)	$	(2	)	$	(1	)	$	3
Fuel and purchased power change:
Fuel:
Generation and other	$	15		$	6		$	-		$	13		$	-		$	2		$	-
Price		(21	)		(14	)		-			(4	)		(3	)		(3	)		-
Purchased power		(33	)		(2	)		(8	)		(21	)		7			7			(6	)
Total	$	(39	)	$	(10	)	$	(8	)	$	(12	)	$	4		$	6		$	(6	)
Net change in electric margins	$	(68	)	$	(49	)	$	2		$	(40	)	$	2		$	5		$	(3	)
Six Months
Electric revenue change:
Effect of weather (estimate)	$	(30	)	$	(14	)	$	(7	)	$	-		$	(3	)	$	(3	)	$	(6	)
Growth and other (estimate)		(6	)		(6	)		64			13			7			8			16
Interchange revenues		96			15			(15	)		(19	)		(7	)		(7	)		-
Total	$	60		$	(5	)	$	42		$	(6	)	$	(3	)	$	(2	)	$	10
Fuel and purchased power change:
Fuel:
Generation and other	$	-		$	3		$	-		$	4		$	-		$	1		$	-
Price		(47	)		(30	)		-			(14	)		(3	)		(3	)		-
Purchased power		(108	)		(31	)		(39	)		(68	)		14			14			(26	)
Total	$	(155	)	$	(58	)	$	(39	)	$	(78	)	$	11		$	12		$	(26	)
Net change in electric margins	$	(95	)	$	(63	)	$	3		$	(84	)	$	8		$	10		$	(16	)

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

Ameren

Ameren’s electric margin decreased by $68 million, or 7%, and $95 million or 6%, for the three months and six months ended June 30, 2006, compared with the same periods in 2005. Ameren’s decrease in electric margins was impacted by:

unfavorable weather conditions as evidenced by an 8% decline in cooling degree-days for both the three months and six months ended June 30, 2006 and an 11% decrease in heating degree-days for the six months ended June 30, 2006, compared with the same periods in 2005. In addition, spring storms caused an unscheduled plant outage in the first quarter of 2006;

·	incremental fees of $6 million levied by FERC in the first quarter of 2006, upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant;

·	a 14% increase in both the second quarter and first half of 2006 in coal and transportation prices resulting from increased global demand for coal;

·	MISO Day Two Energy Market costs, which were comparable in the second quarter and $21 million higher for the six months ended June 30, 2006, compared with the same periods in 2005;

·	the unavailability of UE’s Taum Sauk hydroelectric plant totaling an estimated $4 million and $10 million in the second quarter and first half of 2006;

·	an unscheduled outage at UE’s Callaway nuclear plant, which reduced electric margins by an estimated $20 million, and planned and unplanned outages at certain of UE’s and Genco’s coal-fired plants, primarily in the second quarter of 2006;

·	lower wholesale margins of approximately $6 million and $12 million in the second quarter and first half of 2006 at Marketing Company as a result of the expiration of several large contracts in 2005; and

·	reduced transmission revenues due primarily to a decrease in Marketing Company’s non-service territory load for UE, CIPS, CILCORP, CILCO and IP.

The decrease in Ameren’s electric margins was partially offset by:

·	an increase in margins on interchange sales of $13 million or 17%, and $62 million or 42%, over the prior three and six month periods primarily because of the increased sale of power from EEI resulting from the expiration of its affiliate cost-based sales contract on December 31, 2005; and

·	sales to Noranda, which added approximately $11 million and $17 million in electric margins at UE for the second quarter and first six months of 2006, respectively.

UE’s electric margin decreased by $49 million, or 9%, and $63 million, or 7%, for the three months and six months ended June 30, 2006, compared to the same periods in 2005. The decrease in electric margins was due to:

·	unfavorable weather conditions as evidenced by a 10% decline in cooling degree-days for both the second quarter and the first half of the year and a 10% decrease in heating degree-days for the six months ended June 30, 2006 compared with the same period in 2005;

·	the transfer of UE’s Illinois service territory on May 2, 2005 to CIPS, which resulted in lost margins compared to the prior periods, totaling $6 million for the second quarter and $24 million for the first half of 2006;

lower margins on interchange sales as a result of power plant unavailability. However, margins on interchange sales benefited from the January 2006 amendment of the JDA. The MoPSC-required and FERC-approved change in the JDA methodology to base the allocation of third-party short-term power sales of excess generation on generation output instead of load requirements, effective January 10, 2006, resulted in $5 million and $14 million in incremental margins on interchange sales for UE for the three months and six months ended June 30, 2006, respectively.

·	an 11% and 14% increase in coal and related transportation prices for the second quarter and first six months of 2006, compared with the same periods in 2005;

·	incremental fees of $6 million levied by FERC in the first quarter of 2006 for generation benefits provided to UE’s Osage hydroelectric plant;

·	the unavailability of UE’s Taum Sauk hydroelectric plant;

·	unscheduled outages at UE’s Callaway nuclear plant and certain of its coal-fired plants primarily in the second quarter of 2006 compared with the same period in 2005;

·	MISO Day Two Energy Market costs, which were comparable for the three months ended June 30, 2006, and $14 million higher for the six months ended June 30, 2006, compared with the same periods in 2005; and

·	the expiration of a cost-based power supply contract with EEI on December 31, 2005.

The decrease in UE’s electric margins for the three months and six months ended June 30, 2006, compared with the same periods in 2005, was partially offset by sales to Noranda.

CIPS

CIPS’ electric margin increased by $2 million, or 3%, for the three months and $3 million, or 3%, for the six months

ended June 30, 2006, compared to the same periods in 2005, primarily because of:

·	the transfer to CIPS of UE’s Illinois service territory on May 2, 2005 which generated an incremental margin of $4 million in the second quarter and $16 million in the first half of 2006; and

·	customers switching back to CIPS from Marketing Company because tariff rates were below market rates for power.

CIPS’ increase in electric margin was reduced by increased MISO Day Two Energy Market costs, totaling $2 million for the six months ended June 30, 2006, compared with the same period in 2005. Unfavorable weather conditions as evidenced by a 13% decrease in heating degree-days also lowered CIPS’ electric margins for the six months ended June 30, 2006, compared with the same period in 2005.

Due to the expiration of CIPS’ cost-based power supply agreement with EEI in December 2005, where CIPS sold its entitlements under the agreement to Marketing Company, both interchange revenues and purchased power expenses decreased $7 million and $15 million for the three months and six months ended June 30, 2006.

Genco

Genco’s electric margin decreased by $40 million, or 31%, and $84 million, or 33%, for the three months and six months ended June 30, 2006, compared with the same periods in 2005, primarily because of:

·	lower wholesale margins as Genco purchased higher-cost power from affiliates and third parties to serve a greater load, primarily to supply power to serve the Illinois service territory transferred to CIPS in May 2005;

·	an 11% increase in coal and transportation prices for the three months and six months ended June 30, 2006, compared with the same periods in 2005;

·	a scheduled outage in the second quarter of a major coal-fired unit;

·	lower margins on interchange sales for the three months and six months ended June 30, 2006, compared with the same periods in 2005 primarily because of reduced power plant availability and a $5 million and $14 million reduction due to the amendment of the JDA between UE and Genco; and

·	higher emission allowance utilization costs.

Genco’s decrease in electric margins was reduced by an increase in revenues due to the May 2005 transfer of UE’s Illinois service territory to CIPS. Genco supplies CIPS’ power requirements through a power supply agreement with Marketing Company.

CILCORP and CILCO

For the three and six month periods ended June 30, 2006, CILCORP’s electric margin increased by $2 million, or 3%, and $8 million, or 7%, respectively, and CILCO’s electric margin increased $5 million, or 8%, and $10 million, or 8%, respectively, as compared to the same periods in 2005 primarily because of:

·	lower purchased power costs due to improved power plant availability;

·	decreases in emission allowance utilization expenses of $2 million and $3 million for the three and six month periods, respectively; and

·	increases in margins on interchange sales of $1 million and $5 million in the three and six month periods, respectively.

The increase in electric margins was reduced by higher MISO Day Two Energy Market costs and unfavorable weather conditions as evidenced by an 18% decrease in cooling degree-days for both the three and six month periods and an 8% decrease in heating degree-days for the six months ended June 30, 2006.

IP’s electric margin decreased by $3 million, or 3%, for the three months and $16 million, or 9%, for the six months ended June 30, 2006, compared with the same periods in 2005 primarily because of:

·	increased purchased power costs as a result of the expiration of its cost-based power supply agreement with EEI on December 31, 2005, and increased purchased power prices; and

·	unfavorable weather conditions including a 12% decrease in heating degree-days for the six months ended June 30, 2006.

The decrease in IP’s electric margins in the three months and six months ended June 30, 2006, was reduced by an increase in revenues as a result of customers switching back to IP because tariff rates were below market rates for power.

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 six months ended June 30, 2006, compared with the year-ago periods. We consider gas margin to be a useful measure of the change in profitability of our gas utility operations between periods. The table below complements the financial information we provide in accordance with GAAP. However, gas margin may not be a presentation defined under GAAP. Our presentation may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

	Three Months		Six Months
Ameren^(a)	$	-	$	(6)
UE		(3)		(8)
CIPS		2		2
CILCORP		(1)		(4)
CILCO		(2)		(5)
IP		2		5

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

Ameren

Ameren’s gas margin was comparable for the three months but decreased by $6 million, or 3%, for the six months ended June 30, 2006, over the same periods in 2005.

Ameren’s decrease in gas margin for the six months ended June 30, 2006, compared with the same period in 2005 was primarily due to mild weather conditions as evidenced by an 11% decrease in heating degree-days. Residential and commercial gas volume sales decreased 11% and 10%, respectively, for the six months ended June 30, 2006, compared with the same period in 2005. The decrease in gas margin was reduced by, among other things, the effect of an IP rate increase effective in May 2005 that added revenues of $6 million in the first half of 2006.

Ameren’s gas margin was positively impacted in the second quarter over the same period in 2005 by the effect of IP’s rate increase that added revenues of $2 million. The increase in gas margin was offset in part by mild weather conditions that reduced gas margins as heating degree-days were 16% below a mild 2005 second quarter.

UE’s gas margin decreased by $3 million, or 23%, for the three months and $8 million, or 19%, for the six months ended June 30, 2006, compared with the same periods in 2005. UE’s decrease in gas margins for the three months ended June 30, 2006, compared with the same period in 2005, was due to mild weather conditions, as evidenced by a 22% decrease in heating degree-days. UE’s decrease in gas margins for the six months ended June 30, 2006, compared with the same period in 2005, was due to the transfer of UE’s Illinois service territory to CIPS in May 2005, which reduced gas margins by $3 million, and mild weather conditions, as evidenced by a 10% decrease in heating degree-days in UE’s service territory. Residential and commercial gas sales decreased 39% and 22%, respectively, for the three months and 26% and 19%, respectively, for the six months ended June 30, 2006, compared with the same periods in 2005.

CIPS

CIPS’ gas margin increased by $2 million or 17%, for the three months and $2 million or 5%, for the six months ended June 30, 2006, as compared with the same periods in 2005 primarily because of the transfer to CIPS of UE’s Illinois service territory in May 2005. The increase in gas margin was reduced by extremely mild weather as evidenced by a 13% decrease in heating degree-days for the six months ended June 30, 2006, as compared with the same period in 2005.

CILCORP and CILCO

CILCORP’s and CILCO’s gas margins decreased by $1 million, or 6%, and $2 million, or 11%, respectively, for the three months and $4 million, or 8%, and $5 million, or 10%, respectively, for the six months ended June 30, 2006, over the same periods in 2005. This decrease was primarily as a result of mild weather conditions as heating degree-days in the six months ended June 30, 2006, were 8% below the number of days in the six months ended June 30, 2005 in CILCO’s service territory.

IP’s gas margin increased by $2 million, or 7%, for the three months and $5 million, or 6%, for the six months ended June 30, 2006, over the same periods in 2005, primarily because of a rate increase effective in May 2005 that added revenues of $2 million and $6 million, respectively. This increase was reduced by extremely mild weather conditions as evidenced by a 12% decrease in heating degree-days in the first half of 2006 as compared with the year-ago period in IP’s service territory. Residential and commercial gas sales decreased 9% and 7%, respectively, for the three months and 11% and 13%, respectively, for the six months ended June 30, 2006, compared with the same periods in 2005.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Variations in other operations and maintenance expenses at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months and six months - Other operations and maintenance expenses increased $19 million and $22 million primarily because of $10 million of costs in the second quarter of 2006 related to the December 2005 reservoir breach at UE’s Taum Sauk plant, losses on sales of leveraged lease assets in the second quarter of 2006 that increased other operations and maintenance expenses by $7 million, higher power plant maintenance expenses due to the timing of maintenance outages, an increase in legal fees for environmental issues and general litigation, and increased transmission and distribution expenses. Reducing the impact of these items in the second quarter of 2006 was a reduction in bad debt expense.

Three months - Other operations and maintenance expenses increased $3 million primarily because of incremental costs related to the Taum Sauk plant incident along with increased legal fees. Reducing the impact of these unfavorable items were reduced labor and employee benefit costs.

Six months - Other operations and maintenance expenses decreased $7 million primarily because of the transfer of UE’s Illinois service territory to CIPS in May 2005, which resulted in a decrease in other operations and maintenance expenses of $7 million. Additionally, lower injuries and damages expenses due in part to the settlement of claims and decreased labor and employee benefit costs resulted in a reduction in other operations and maintenance expenses. Reducing the impact of these favorable items were increased legal fees and additional costs related to the Taum Sauk plant incident.

CIPS

Three months - Other operations and maintenance expenses were comparable between periods.

Six months - Other operations and maintenance expenses increased $6 million because of the transfer of UE’s Illinois service territory to CIPS in May 2005, which resulted in an increase in other operations and maintenance expenses of $7 million.

Genco

Three months and six months - Other operations and maintenance expenses increased $9 million and $3 million primarily because of higher maintenance expenses as a result of increased power plant maintenance outages in the current year periods.

CILCORP and CILCO

Three months and six months - Other operations and maintenance expenses increased $9 million and $8 million at CILCORP, and $12 million and $9 million at CILCO, primarily as a result of losses on sales of leveraged lease assets in the second quarter of 2006. The losses on leveraged leases in other operations and maintenance expenses were partially offset by a tax benefit reflected in income taxes.

Three months - Other operations and maintenance expenses were comparable between periods.

Six months - Other operations and maintenance expenses increased $18 million primarily because of higher transmission and distribution, information technology, bad debt and rental expenses.

Depreciation and Amortization

Variations in depreciation and amortization expenses at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months - Depreciation and amortization expenses increased $5 million primarily because of capital additions.

Six months - Depreciation and amortization expenses increased $13 million primarily as a result of capital additions and the impairment of an intangible asset associated with the CILCORP acquisition.

Three months and six months - Depreciation and amortization expenses increased $5 million and $9 million, respectively, primarily because of capital additions, a portion of which were related to new steam generators and turbine rotors installed during the refueling and maintenance outage at the Callaway nuclear plant in the prior year. Additionally, depreciation increased $1 million and $3 million, respectively, in the three months and six months ended June 30, 2006, due to CTs transferred to UE from Genco in May 2005. Reducing the impact of these increases was a reduction of depreciation due to the transfer of property to CIPS in the Illinois service territory transfer in May 2005.

CIPS

Three months - Depreciation and amortization expenses were comparable between periods.

Six months - Depreciation and amortization expenses increased $3 million primarily because of depreciation on property transferred to CIPS from UE in the prior-year Illinois service territory transfer along with capital additions.

CILCORP

Three months - Depreciation and amortization expenses were comparable between periods.

Six months - Depreciation and amortization expenses increased $5 million primarily because of the impairment of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.

Three months - Depreciation and amortization expenses were comparable between periods.

Six months - Depreciation and amortization expenses decreased $3 million primarily because of write-offs of software in the prior year.

Genco and CILCO

Three months and six months - Depreciation and amortization expenses were comparable between periods.

Taxes Other Than Income Taxes

Variations in taxes other than income taxes at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months - Taxes other than income taxes decreased $5 million primarily because of lower payroll taxes.

Six months - Taxes other than income taxes increased $17 million primarily as a result of higher gross receipts taxes and higher property taxes, primarily at Genco.

Three months - Taxes other than income taxes were comparable between periods.

Six months - Taxes other than income taxes increased $4 million primarily as a result of higher gross receipts taxes.

CIPS

Three months - Taxes other than income taxes were comparable between periods.

Six months - Taxes other than income taxes increased $6 million primarily as a result of higher gross receipts and excise taxes.

Genco

Three months - Taxes other than income taxes were comparable between periods.

Six months - Taxes other than income taxes increased $8 million primarily because of higher property taxes due to an $8 million tax settlement that was received in the first quarter of 2005 that did not recur in 2006.

CILCORP and CILCO

Three months - Taxes other than income taxes were comparable between periods.

Six months - Taxes other than income taxes increased $2 million and $3 million at CILCORP and CILCO, respectively, primarily as a result of higher excise taxes.

Three months and six months - Taxes other than income taxes were comparable between periods.

Other Income and Expenses

Variations in other income and expenses at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months and six months - Miscellaneous income decreased $2 million and $5 million primarily as a result of lower capitalization of equity funds used during construction in the current year periods. Miscellaneous expense decreased $5 million and $6 million primarily due to the write-off of unrecoverable natural gas costs in the prior year as noted below.

Three months - Other income and expenses were comparable between periods.

Six months - Miscellaneous income decreased $5 million primarily as a result of lower capitalization of equity funds used during construction in the current year period. Miscellaneous expense was comparable between periods.

CIPS

Three months and six months - Miscellaneous income was comparable between periods. Miscellaneous expense decreased $4 million and $3 million primarily as a result of the write-off of unrecoverable natural gas costs in the prior year.

CILCORP

Three and six months - Miscellaneous income was comparable between periods. Miscellaneous expense decreased $2 million and $3 million primarily as a result of the write-off of unrecoverable natural gas costs in the prior year.

Three months - Other income and expenses were comparable between periods.

Six months - Miscellaneous income decreased $2 million primarily as a result of lower capitalization of equity funds used during construction and reduced investment income in the current year period. Miscellaneous expense was comparable between periods.

Genco and CILCO

Three months and six months - Other income and expenses were comparable between periods.

Interest

Variations in interest expense at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months and six months - Interest expense increased $3 million and $5 million primarily because of items noted below at the various Ameren Companies, partially offset by a reduction in interest expense resulting from the repurchase and retirement of Ameren’s $95 million of senior notes in February 2005.

Three months and six months - Interest expense increased $10 million and $20 million primarily because of the issuances of $300 million of senior secured notes in July 2005 and $260 million of senior secured notes in December 2005 along with increased short-term borrowings resulting from the purchase of CTs in the first quarter of 2006.

Genco

Three months and six months - Interest expense decreased $4 million and $10 million primarily because of the maturity of $225 million of senior notes in November 2005.

CIPS, CILCORP, CILCO and IP

Three months and six months - Interest expense was comparable between periods.

Income Taxes

Variations in income tax expense at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months and six months - Income taxes decreased primarily because of lower pretax income along with items noted below at the various Ameren Companies.

Three months and six months - Income taxes decreased primarily because of lower pretax income, partially offset by permanent tax items.

CIPS

Three months and six months - Income taxes decreased in the second quarter of 2006, despite higher pretax income, due to a favorable federal audit settlement. Income taxes decreased in the six months ended June 30, 2006, primarily because of lower pretax income and the favorable audit settlement.

Genco

Three months and six months - Income taxes decreased primarily because of lower pretax income.

CILCORP and CILCO

Three months and six months - Income taxes decreased primarily because of lower pretax income and a tax benefit related to leveraged lease sales.

Three months and six months - Income tax expense was comparable between periods for the three months. Income tax expense decreased in the six months of 2006 primarily because of lower pretax income.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO and IP) 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 for Ameren. For operating cash flows, Genco principally relies on sales to an affiliate under a contract expiring at the end of 2006 and sales to other wholesale and industrial customers under short and long-term contracts. Commencing in 2007, Genco and AERG intend to sell power previously sold under existing contracts through new contracts obtained through the Illinois power procurement auction or other contracts executed with wholesale and retail customers. The amount of power that Genco and its affiliates may supply to CIPS, CILCO and IP through the Illinois power procurement auction is limited to 35% of CIPS’, CILCO’s and IP’s annual load. In addition, each of the Ameren Companies plans to use short-term borrowings to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at June 30, 2006, for UE, Genco, CILCORP, CILCO and IP. The Ameren Companies will discretionarily reduce their short-term borrowings with cash from operations or with long-term borrowings.

The following table presents net cash provided by (used in) operating, investing and financing activities for the six months ended June 30, 2006 and 2005:

	Net Cash Provided By Operating Activities						Net Cash Provided By (Used In) Investing Activities						Net Cash Provided By (Used In) Financing Activities
	2006		2005		Variance		2006		2005		Variance		2006		2005		Variance
Ameren^(a)	$	570	$	749	$	(179)	$	(746)	$	(531)	$	(215)	$	131	$	(260)	$	391
UE		227		353		(126)		(511)		(492)		(19)		265		92		173
CIPS		79		96		(17)		(23)		-		(23)		(55)		(97)		42
Genco		55		132		(77)		(56)		102		(158)		2		(235)		237
CILCORP		106		55		51		-		(64)		64		(86)		5		(91)
CILCO		113		77		36		(42)		(67)		25		(51)		(11)		(40)
IP		86		149		(63)		(83)		8		(91)		(2)		(157)		155

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

Cash Flows from Operating Activities

Ameren’s cash from operations decreased in the first six months of 2006, as compared with the first six months of 2005, due primarily to decreases in electric and gas margins as discussed in Results of Operations above. Also contributing to the decrease was cash used during the first six months of 2006 for payment of 2005 year-end accruals including real estate and property taxes, annual incentive compensation that was more than it was a year ago because of increased 2005 earnings relative to performance targets, and trade payables that were higher than normal due to an unusually cold December 2005 and higher natural gas prices. The cash benefit from reduced natural gas inventories that resulted in the first quarter of 2006 due to the end of the winter heating season was offset in the second quarter as a result of increased volume and per unit prices of coal inventory purchases because of the alleviation of the coal supply issues experienced in the 2005 period and higher market prices for coal in the 2006 period. Reducing the negative impacts was the collection of higher-than-normal trade receivables caused by cold December 2005 weather during the winter heating season. The cash impact from trade receivables was more significant in the current period due to higher gas prices and colder December weather in 2005 as compared with the year-ago period.

At UE, cash from operating activities decreased in 2006 due to lower electric and gas margins and cash used for working capital changes that primarily included increased payments of year-end accruals in the first six months of 2006 as compared with the year-ago period as discussed above for Ameren. Also contributing to the decrease were increased income tax payments of $49 million compared to the year-ago period.

At CIPS, the negative cash effect of higher other operations and maintenance expenses and taxes other than income was partially offset by higher electric and gas margins, as discussed in Results of Operations. However, increased working capital investment also contributed to the decrease in cash from operations in the 2006 period as compared to the year ago period. The most significant change in working capital was a $35 million increase in income tax payments compared to the year-ago period. Partially offsetting this use of cash was an increase in collections of trade receivables as a result of colder December 2005 weather and higher gas prices compared to the year-ago period.

Genco’s cash from operating activities in the first six months of 2006 decreased compared to the 2005 period primarily because of lower operating margins as discussed in

Results of Operations. Interest payments were lower in the 2006 period due to decreased debt outstanding.

Cash from operating activities increased for CILCORP and CILCO in the six months ended June 30, 2006, compared with the same period of 2005 primarily because of higher electric margins as discussed in Results of Operations and an increase in collections of trade receivables as a result of colder December 2005 weather and higher gas prices compared to the year-ago period. Partially offsetting these positive effects on cash were higher other operations and maintenance expenses as discussed in Results of Operations. In addition, income tax payments increased $12 million for CILCO and decreased $3 million for CILCORP.

IP’s cash from operations decreased in the six months ended June 30, 2006, compared with the 2005 period due to lower electric margins and higher other operations and maintenance expenses as discussed above in Results of Operations. Also contributing to IP’s decreased operating cash flows in 2006 were income taxes paid of $6 million in the 2006 period as compared with income tax refunds of $9 million in the year-ago period, and cash used during the first six months of 2006 for payment of 2005 year-end accruals including real estate and property taxes, annual incentive compensation that was more than it was a year ago due to increased 2005 earnings relative to performance targets, and trade payables that were higher than normal due to an unusually cold December 2005 and higher natural gas prices.

Cash Flows from Investing Activities

Ameren’s increase in cash used in investing activities was primarily because of UE’s purchases of a 640-megawatt CT facility from affiliates of NRG Energy, Inc., and 510-megawatt and 340-megawatt CT facilities from subsidiaries of Aquila, Inc. for a total of $292 million. The CT purchases are intended to meet UE’s increased generating capacity needs and provide UE with additional flexibility in determining future base-load generating capacity additions.

Excluding CT purchases, Ameren’s capital expenditures decreased $36 million in the first six months of 2006 as compared with the year-ago period primarily because fewer capital resources were allocated to other projects due to the planned CT acquisitions. Excluding the CTs purchased from Genco and an additional $25 million used to purchase CT equipment from Development Company in the 2005 period, UE’s capital expenditures were only $26 million less in the first six months of 2006 as compared with the year-ago period. In addition, emission allowance purchases decreased $54 million in the first six months of 2006 compared to the first six months of 2005. The sale of leveraged lease investments provided an $11 million benefit to Ameren’s cash from investing activities as discussed below.

CIPS’ increase in cash used in investing activities for the six months ended June 30, 2006, over the 2005 period was due to a $16 million increase in capital expenditures. Also negatively impacting CIPS’ investing cash flow was an $18 million reduction in proceeds from CIPS’ note receivable from Genco in the 2006 period as compared with the 2005 period. The decrease in proceeds from Genco resulted from the May 1, 2005 amendment and restatement of the note. Partially offsetting these negative effects was an $11 million reduction of advances to the money pool in 2006 as compared with 2005. The increased capital expenditures resulted partly from CIPS’ expansion of its service territory because of its acquisition of UE’s Illinois utility operations in May 2005. CIPS’ capital expenditures were for projects to improve the reliability of its electric and gas transmission and distribution systems.

Genco had a net use of cash in investing activities for the first six months of 2006 compared to a net source of cash during the same period in 2005. This was due primarily to the 2005 transfer of two CTs to UE in 2005 for $241 million. Genco’s capital expenditures were lower for the six months ended June 30, 2006, compared with the 2005 period because 2005 included expenditures due to an extended planned outage at one of its power plants. Purchases of emission allowances were $45 million less in the first six months of 2006 compared to the first six months of 2005.

CILCORP’s cash from investing activities benefited from the repayment of Resources Company’s note payable of $42 million that originated from the 2005 transfer of leveraged leases from CILCORP to Resources Company. In addition, a subsidiary of CILCORP and CILCO generated cash from investing activities of $11 million in the six months ended June 30, 2006, from the sale of its remaining leverage lease investments. Emission allowance purchases were $9 million less in the first six months of 2006 compared to the first six months of 2005.

IP had a net use of cash in investing activities for the first six months of 2006 compared to a net source of cash in the prior-year period primarily because of the absence in the six month period ended June 30, 2006, of proceeds received in the first six months of 2005 from repayments received for advances made to the money pool in prior periods. In addition, capital expenditures increased $22 million over the year-ago period due to increased projects to maintain the reliability of IP’s electric and gas transmission and distribution systems.

See Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a further discussion of future environmental capital investment estimates.

We continually review our generation portfolio and expected power needs. As a result, we could modify our plans for generation capacity, which could include changing the

times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity may be purchased, among other things. Any changes that we may 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

Cash from financing activities increased for Ameren in the first six months of 2006 from the year-ago period, primarily because of net short-term debt proceeds of $204 million, which were used to partially fund UE’s CT acquisitions, compared to net short-term debt repayments of $256 million in the year-ago period. Ameren’s cash from financing activities also increased from long-term debt issuances of $232 million at CIPS, CILCO and IP in 2006, which was significantly more than Ameren’s 2005 long-term debt issuances of $85 million. In addition, long-term debt redemptions, repurchases, and maturities decreased by $151 million in 2006, compared to the same period in 2005. Cash from stock proceeds was significantly less in the 2006 period because proceeds in the 2005 period included the issuance of 7.4 million shares of common stock related to the settlement of a stock purchase obligation in Ameren’s adjustable conversion-rate equity security units.

UE’s cash from financing activities increased for the six months ended June 30, 2006, as compared with the 2005 period, primarily because of a $284 million increase in net short-term debt proceeds in 2006 compared to combined net money pool and short-term debt proceeds of $143 million in the 2005 period, which resulted in a $141 million benefit in the 2006 period. In addition, $67 million was received from CIPS in payment of its intercompany note, and dividend payments decreased $51 million, both of which benefited cash from financing activities in the 2006 period as compared with the 2005 period. Net cash from financing activities was partially used to fund the CT acquisitions.

CIPS’ cash used in financing activities decreased for the six months ended June 30, 2006, as compared with the 2005 period, because of a $66 million decrease in payments to the money pool in the 2006 period. A $16 million increase in dividends to Ameren negatively impacted CIPS’ cash from financing activities in 2006 as compared to the year-ago period. CIPS’ second quarter issuance of $61 million of long-term debt had a minor net impact on cash from financing activities because the proceeds were used to repay CIPS’ outstanding balance on the intercompany note payable to UE that was originally issued with the transfer of UE’s Illinois service territory to CIPS in 2005.

Genco had net cash proceeds from financing activities for the first six months of 2006, compared to a net use of cash for the same period last year. This is primarily due to Genco having $57 million in net borrowings from the money pool in the 2006 period, compared to net repayments of $116 million in the prior year period. In addition, lower intercompany note payments of $52 million in the 2006 period, and a $50 million capital contribution received in 2006 from Ameren also benefited Genco’s financing cash flows. Partially offsetting these positive effects on cash was a $37 million increase in dividend payments in the 2006 period as compared with the 2005 period.

CILCORP’s and CILCO’s cash from financing activities benefited from CILCO’s long-term debt issuances that generated $96 million in the 2006 period, as compared with no long-term debt issuances in the 2005 period. However, this benefit in the 2006 period was completely offset by the absence in 2006 of a $101 million capital contribution received in the 2005 period. In addition, in 2006, CILCORP used cash of $12 million for open market debt repurchases as compared with $6 million of cash used for repurchases in the 2005 period. CILCORP’s repayments of $30 million on its note payable to Ameren reduced its financing cash flow by $52 million as compared with the year-ago period because the 2005 period included borrowings on this note that provided CILCORP with cash.

Also contributing to CILCORP’s and CILCO’s increase in cash used in financing activities for the six months ended June 30, 2006, as compared with the year-ago period, were increased common stock dividends of $20 million and $30 million at CILCORP and CILCO, respectively, in the 2006 period as compared with the 2005 period. In addition, net increases in cash for money pool repayments of $7 million and $4 million at CILCORP and CILCO, respectively, also negatively impacted cash in the 2006 period.

IP’s cash used in financing activities decreased for the six months ended June 30, 2006, as compared with the 2005 period, primarily because of lower redemptions and repurchases of long-term debt of $67 million and the absence in the 2006 period of $40 million of common stock dividend payments made in the 2005 period. IP’s 2006 cash from financing activities also benefited from the issuance of $75 million of long-term debt as compared with no long-term debt proceeds in the year-ago period. A portion of the 2006 long-term debt proceeds were used to repay short-term debt consisting of borrowings under Ameren’s utility money pool.

Short-term Borrowings and Liquidity

For additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements, see Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report.

The following table presents the committed bank credit facilities of the Ameren Companies and AERG as of June 30, 2006, and July 14, 2006:

Credit Facility	Expiration		Amount Committed		Amount Available
Ameren:
Multiyear revolving^(a)(b)		July 2010	$	1,150	$	756
Multiyear revolving^(c)		July 2006		350		350
CIPS, CILCORP, CILCO, IP and AERG:
Multiyear revolving^(d)		January 2010		500		500

(a)	Ameren Companies may access this credit facility through intercompany borrowing arrangements.

(b)

UE and Genco are also direct borrowers under this facility. CIPS, CILCO and IP were also direct borrowers under this agreement until July 13, 2006. See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for discussion of the amendment of this facility.

(c)	This credit facility was terminated on July 14, 2006.

(d)

This credit facility was entered into on July 14, 2006. The maximum amount available to each borrower, including for issuance of letters of credit, is limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million and AERG - $200 million. The ability of CIPS, CILCO, and IP to borrow under this facility is subject to the receipt of necessary regulatory approvals. See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for discussion of the new credit facility.

In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At June 30, 2006, Ameren had $51 million of cash and cash equivalents.

With the repeal of PUHCA 1935 in February 2006, the issuance of short-term debt securities by Ameren’s utility subsidiaries is now subject to approval by FERC under the Federal Power Act. In March 2006, FERC issued an order authorizing these subsidiaries to issue short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion; CIPS - $250 million; and CILCO - $250 million. This authorization was effective as of April 1, 2006, and terminates on March 31, 2008.

Genco is also authorized by FERC in its March 2006 order to have up to $300 million of short-term debt outstanding at any time. IP, AERG and EEI have unlimited short-term debt authorization from FERC.

With the repeal of PUHCA 1935 in February 2006, the issuance of short-term debt securities by Ameren and CILCORP, which was previously subject to SEC approval under PUHCA 1935, is no longer subject to approval by any regulatory body.

Long-term Debt 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 (net of any issuance discounts and including any redemption premiums) for the six months ended June 30, 2006 and 2005, for the Ameren Companies. For additional information, see Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.

			Six Months
	Month Issued, Redeemed, Repurchased or Matured		2006		2005
Issuances
Long-term debt
UE:^(a)
5.00% Senior secured notes due 2020		January	$	-	$	85
CIPS:
6.70% Senior secured notes due 2036		June		61		-
CILCO:
6.20% Senior secured notes due 2016		June		54		-
6.70% Senior secured notes due 2036		June		42		-
IP:
6.25% Senior secured notes due 2016		June		75		-
Total Ameren long-term debt issuances			$	232	$	85

			Six Months
	Month Issued, Redeemed, Repurchased or Matured		2006		2005
Common stock
Ameren:
7,402,320 Shares at $46.61^(b)	May	$	-	$	345
DRPlus and 401(k)^(c)	Various		57		57
Total common stock issuances		$	57	$	402
Total Ameren long-term debt and common stock issuances		$	289	$	487
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
Senior notes due 2007^(d)	February	$	-	$	95
CIPS:
7.05% First mortgage bonds due 2006	June		20		-
6.49% First mortgage bonds due 2005	June		-		20
CILCORP:
9.375% Senior notes due 2029	March/April		12		-
8.70% Senior notes due 2009	May		-		6
IP:
6.75% First mortgage bonds due 2005	March		-		70
Notes payable to IP SPT
5.54% Series due 2007	Various		54		-
5.38% Series due 2005	Various		-		46
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	86	$	237

(a)	Ameren’s and UE’s long-term debt increased $240 million as a result of the first quarter leasing transaction related to UE’s purchase of a 640-megawatt CT facility located in Audrain County, Missouri. No capital was raised as a result of UE’s assumption of the lease obligations.

(b)	Shares issued upon settlement of the purchase contracts, which were a component of the adjustable conversion-rate equity security units.

(c)	Includes issuances of common stock of 1.1 million shares during the six months ended June 30, 2006, under DRPlus and 401(k) plans.

(d)	Component of the adjustable conversion-rate equity security units.

The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of June 30, 2006:

	Effective Date		Authorized Amount		Issued		Available
Ameren		June 2004	$	2,000	$	459	$	1,541
UE		October 2005		1,000		260		740
CIPS		May 2001		250		211		39

Ameren also has approximately 4.0 million shares of common stock available for issuance under various other SEC effective registration statements applicable to its DRPlus and 401(k) plans as of June 30, 2006.

Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. 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.

Indebtedness Provisions and Other Covenants

See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for a discussion of the covenants and provisions contained in Ameren’s bank credit facilities and applicable cross-default provisions. Also see Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

At June 30, 2006, the Ameren Companies were in compliance with their credit facility, indenture, and articles of incorporation provisions and covenants.

We consider access to short-term and long-term capital markets 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 affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), 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 events might increase our cost of capital or adversely affect our ability to access the capital markets.

Dividends

Dividends paid by Ameren to shareholders during the first six months of 2006 totaled $260 million, or $1.27 per share (2005 - $253 million or $1.27 per share).

UE paid preferred stock dividends of approximately $1 million on May 15, 2006. CIPS paid preferred stock dividends of approximately $1 million on June 30, 2006. CILCO paid preferred stock dividends of less than $1 million on July 3, 2006. IP paid preferred stock dividends of approximately $1 million on August 1, 2006. The next preferred dividends are payable on August 15, 2006, September 29, 2006, October 2, 2006 and November 1, 2006 for UE, CIPS, CILCO and IP, respectively.

See Note 3 - Short-term Borrowings and Liquidity and Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements, articles of incorporation and an ICC order that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At June 30, 2006, none of these circumstances existed and as a result, the Ameren Companies were allowed to pay dividends.

On July 14, 2006, CIPS, CILCORP, CILCO, IP, and AERG entered into a new $500 million credit facility which limits a borrower to capital stock dividend payments of $10 million per year if the borrower has a below investment-grade senior unsecured credit rating as defined in the new facility. With respect to AERG, which currently is not rated, the dividend restriction will not apply if its consolidated total debt to consolidated operating cash flow pursuant to a calculation defined in the facility is less than or equal to 3.0 to 1. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured credit rating to below investment-grade causing it to be subject to this dividend payment limitation. The other borrowers are not currently limited in their dividend payments by this provision of the new credit facility. See Note 3 - Short-term Borrowings and Liquidity under Part I, Item 1, of this report.

The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the six months ended June 30, 2006 and 2005.

	Six Months
	2006		2005
UE	$	84	$	135
CIPS		25		9
Genco		71		34
CILCORP^(a)		50		30
IP		-		40
Nonregistrants		30		5
Dividends paid by Ameren	$	260	$	253

(a)	CILCO paid dividends of $50 million and $20 million for the six months ended June 30, 2006 and 2005, respectively.

Contractual Obligations

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 Annual Report on Form 10-K for the fiscal year ended December 31, 2005. See Note 11 - Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

Subsequent to December 31, 2005, obligations related to the procurement of coal and natural gas changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $4,327 million, $1,654 million, $471 million, $642 million, $645 million, $645 million and $622 million, respectively, as of June 30, 2006. Total other obligations at June 30, 2006, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $4,799 million, $1,929 million, $601 million, $642 million, $757 million, $757 million and $803 million, respectively.

Credit Ratings

On July 26, 2006, Moody’s downgraded the principal credit ratings of certain of the Ameren Companies as presented in the following table:

	From	To
UE:
Secured debt	A1	A2
Unsecured debt	A2	A3
Commercial paper	P-1	P-2
CIPS:
Secured debt	A3	Baa2
Unsecured debt	Baa1	Baa3
CILCORP:
Unsecured debt	Baa3	Ba1
CILCO:
Secured debt	A3	Baa1
Unsecured debt	Baa1	Baa2

Moody’s confirmed the credit ratings of Ameren and IP, and Genco was unaffected. Following these actions, Moody’s review for possible downgrade was removed and replaced with a negative outlook for Ameren, CIPS, CILCORP, CILCO and IP, and a stable outlook was assigned to UE and Genco.

According to Moody’s, the downgrade of UE was principally because of the following factors:

·	Weaker financial metrics due to higher operating costs and large capital expenditures for environmental compliance that are not currently being recovered from customers.

·	The likelihood that if the operating cash flow for Ameren’s Illinois utilities declines, Ameren may need to rely on UE and Ameren’s unregulated operations for a larger share of upstreamed dividends to meet parent company obligations.

According to Moody’s, the downgrade of CIPS, CILCORP and CILCO was principally because of the following factors:

·	A difficult political and regulatory environment in Illinois associated with the recovery of higher purchased power costs by electric utilities commencing January 1, 2007.

·	Moody’s expectation that the outcome in Illinois will involve a material regulatory deferral of recovery of higher power procurement costs.

There have been no other changes to the Ameren Companies’ credit ratings since the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005.

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital. It may also increase the cost of borrowing and fuel and power supply, among other things, resulting in a negative impact on earnings. For example, if at June 30, 2006, the Ameren Companies had a sub-investment-grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could have been required to post collateral for certain trade obligations amounting to $129 million, $15 million, $6 million, $6 million, $15 million, $15 million, or $70 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease with credit ratings. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

OUTLOOK

Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2006 and beyond:

On July 19, 2006 and July 21, 2006, UE’s, CIPS’ and IP’s service territories were hit by severe storms, which included tornados, that resulted in the loss of power to approximately 700,000 customers combined. Through the dedication of a work force of 5,200, including our employees, contractors and utility workers from 13 states, we restored service to all of our customers within nine days. The full financial impact of these storms has not yet been determined, but UE, CIPS and IP have incurred unanticipated costs and the loss of electric margins as a result of these devastating storms.

Revenues

·	By the end of 2006, electric rates for Ameren’s operating subsidiaries will have been fixed or declining for periods ranging from 15 years to 25 years. In 2006, electric rate adjustment moratoriums and power supply contracts expire in Ameren’s regulatory jurisdictions.

In July 2006, UE, CIPS and Genco mutually consented to terminate the JDA on December 31, 2006. Upon termination of the JDA, Genco will no longer receive the margins on sales that were supplied with power from UE. However, Genco will still have access to its own generation and expects to be able to sell this power at higher average prices than this power was sold for in 2005 because of the expiration of its power supply contract with CIPS and the expiration of contracts to supply other wholesale and retail customers on or before December 31, 2006. Ameren’s and UE’s earnings will be affected by the termination of the JDA when UE’s rates are adjusted by the MoPSC. UE’s requested electric rate increase filed in July 2006 is net of the decrease in its revenue requirement resulting from increased margins expected to result from the termination of the JDA. Termination of the JDA will require acceptance by FERC. See Note 2 - Rate and Regulatory Matters and Note 7 -

Related Party Transactions to our financial statements under Part I, Item 1, of this report for a further discussion of the JDA.

In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through an auction. This approval is subject to court appeal. Power supplied by Genco and AERG to CIPS and CILCO, respectively, have been subject to below-market-priced contracts. Most of Genco’s other wholesale and retail electric power supply agreements also expire during 2006 and substantially all of these are below market prices for similar contracts in 2006. Genco currently expects to generate approximately 17.5 million megawatthours of power in 2007. By 2007, only 5.2 million megawatthours of power covered by wholesale and retail electric power supply agreements that were in effect in 2005 will remain outstanding. These agreements have an average embedded selling price of $36 per megawatthour. All other power supply agreements in effect in 2005 will expire by the end of 2006 and any available generation in 2007 will be sold at prevailing market prices. AERG currently expects to generate approximately 7.0 million megawatthours of power in 2007 compared to 5.9 million megawatthours of power that was generated in 2005 at an average cost of approximately $15 per megawatthour. In 2005, this power was sold principally to CILCO at an average price of $32 per megawatthour. In addition, AERG sold 1 million net megawatthours of power in the interchange market at an average price of $38 per megawatthour in 2005. In 2007, all of AERG’s power will be sold at prevailing market prices.

Ameren expects the average residential electric rates for CIPS, CILCO and IP to increase significantly following the expiration of a rate freeze at the end of 2006. The amount of the increase will depend on outcomes for CIPS’, CILCO’s and IP’s pending electric delivery services revenue increase requests to the ICC and power supply costs that result from the proposed Illinois power procurement auction, among other things.

Certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties have sought and continue to seek various methods, including rate freeze legislation, to block the power procurement auction and/or the recovery of related costs for power supply resulting from the auction through rates to customers. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren. CIPS, CILCO and IP are willing to work with stakeholders to ease the burden of higher energy prices on residential customers through a rate increase phase-in plan, as long as such plan allows for the full and timely recovery of costs and does not adversely impact credit ratings. In March 2006, legislation was introduced in the Illinois House of Representatives that would allow the deferral of a portion of the power procurement costs and would authorize the ICC to permit a utility with fewer than one million retail customers to form special purpose finance vehicles to issue securitization bonds to recover the deferred costs, with interest. CIPS, CILCO and IP each have less than one million retail customers. In June 2006, CIPS, CILCO and IP filed a rate increase phase-in and revenue securitization plan with the ICC that was based on this proposed legislation that would relate to the deferral of power supply costs for 2007 and 2008.

The Ameren Illinois utilities filed proposed new tariffs with the ICC in December 2005 that would increase annual revenues from electric delivery services, effective January 2, 2007, by $156 million (CIPS - $14 million, CILCO - $33 million, IP - $109 million) per year commencing in 2007 and an additional $46 million (CILCO - $10 million, IP - $36 million) per year commencing in 2008. In June 2006, the ICC staff filed rebuttal testimony recommending increases in revenues for electric delivery services for the Ameren Illinois utilities aggregating $120 million (CIPS - $1 million, CILCO - $30 million and IP - $89 million). In April 2006, the Illinois attorney general and CUB recommended net increases in revenues for electric delivery services of $71 million for the Ameren Illinois utilities (CIPS - $7 million decrease, CILCO - $19 million increase and IP - $59 million increase). In subsequent testimony, the Illinois attorney general accepted certain of the Ameren Illinois utilities’ positions increasing the estimated aggregate recommended revenue increase to $100 million. Other parties also made recommendations in the case. The ICC has until November 2006 to render a decision in these rate cases. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

In July 2006, UE filed requests with the MoPSC for an increase in electric rates of $361 million and in natural gas delivery rates of $11 million. The MoPSC staff and other stakeholders will review UE’s rate adjustment requests and, after their analyses, may also make recommendations as to rate adjustments. Generally, a proceeding to change rates in Missouri could take up to 11 months. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

·	We expect continued economic growth in our service territory to benefit energy demand in 2006 and beyond, but higher energy prices could result in reduced demand from consumers.

·	UE, Genco and CILCO are seeking to raise the equivalent availability and capacity factors of their power plants through a process improvement program.

·	Very volatile power prices in the Midwest affect the amount of revenues UE, Genco and CILCO (through AERG) can generate by marketing power into the

wholesale and interchange markets and influence the cost of power we purchase in the interchange markets.

·	On April 1, 2005, the MISO Day Two Energy Market began operating. The MISO Day Two Energy Market presents an opportunity for increased power sales from UE, Genco and CILCO power plants and improved access to power for UE, CIPS, CILCO and IP.

Fuel and Purchased Power

In 2005, 86% of Ameren’s electric generation (UE - 80%, Genco - 96%, CILCO - 99%) was supplied by its coal-fired power plants. About 88% of the coal used by these plants (UE - 96%, Genco - 67%, CILCO - 77%) was delivered by railroads from the Powder River Basin in Wyoming. In May 2005, the joint Burlington Northern-Union Pacific rail line in the Powder River Basin suffered two derailments due to unstable track conditions. As a result, the Federal Rail Administration placed slow orders, or speed restrictions, on sections of the line until the track could be made safe. Because of the railroad delivery problems, UE, Genco and CILCO received only about 90% to 95% of scheduled deliveries of Powder River Basin coal in 2005. The impact of the coal delivery issues on inventory levels was exacerbated by warm summer weather and high power prices, which caused UE, Genco and CILCO plants to run more and to burn record amounts of coal. Maintenance on the rail lines into the Powder River Basin is continuing in 2006, but is expected to have less of an impact on deliveries than in 2005. Further disruptions in coal deliveries could cause UE, Genco and CILCO to pursue a strategy that could include reducing sales of power during low-margin periods, utilizing higher-cost fuels to generate required electricity and purchasing power.

Ameren’s coal and related transportation costs are expected to increase 10% to 15% in 2006 and an additional 15% to 20% in 2007. In addition, power generation from higher-cost gas-fired plants is expected to increase in the next few years. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk for information about the percentage of fuel and transportation requirements that are price-hedged for 2006 through 2010.

The MISO Day Two Energy Market resulted in significantly higher MISO-related costs in 2005. In part, these higher charges were due to volatile summer weather patterns and related loads. In addition, we attribute some of these higher charges to the relative infancy of the MISO Day Two Energy Market, suboptimal dispatching of power plants, and price volatility. We will continue to optimize our operations and work closely with MISO to ensure that the MISO Day Two Energy Market operates more efficiently and effectively in the future.

In July 2005, a new law was enacted that enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. Detailed rules for the fuel and purchased power cost recovery mechanism are expected to be effective in the second half of 2006. We are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted. As part of its electric rate case filing in July 2006, UE requested the use of the fuel, purchased power, and environmental cost recovery mechanisms.

Other Costs

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. The incident is being investigated by FERC and state authorities. The facility will remain out of service until reviews by FERC and state authorities are concluded, further analyses are completed, and input is received from key stakeholders as to how and whether to rebuild the facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through most, if not all, of 2008. UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. UE expects the total cost for damage and liabilities resulting from the Taum Sauk incident to range from $63 million to $83 million. As of June 30, 2006, UE had paid $27 million and accrued a $36 million liability, while expensing $11 million, and recording a $52 million receivable due from insurance companies. No amounts have been recognized in the financial statements relating to estimated costs to repair or rebuild the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE may be subject to litigation by private parties or by state or federal authorities. Until the reviews conducted by state and federal authorities have concluded, the insurance review is completed, a decision whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.

·	UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in 2007. During an outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of

excess power available for sale decreases, versus non-outage years.

Over the next few years, we expect rising employee benefit costs as well as higher insurance and security costs associated with additional measures we have taken, or may need to take, at UE’s Callaway nuclear plant and our other facilities. Insurance premiums may also increase as a result of the Taum Sauk incident.

·	We are currently undertaking cost reduction and control initiatives associated with the strategic sourcing of purchases and streamlining of all aspects of our business.

Capital Expenditures

The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2006 and 2016, Ameren expects that certain Ameren Companies will be required to invest between $2.7 billion and $3.4 billion to retrofit their power plants with pollution control equipment. More stringent state regulations could increase these costs. These investments will also result in higher ongoing operating expenses. Approximately 50% of this investment will be in Ameren’s regulated UE operations, and therefore it is expected to be recoverable from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on whether market prices for power adjust as a result of this increased investment.

In March 2006, UE completed the purchase of three gas-fired CT facilities with a capacity of nearly 1,500 megawatts in transactions valued at $292 million. The purchase of these facilities is designed to meet UE’s increased generating capacity needs and to provide additional flexibility in determining future baseload generating capacity additions. UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. At this time, UE does not expect to require new baseload generation capacity until at least 2015. However, due to the significant time required to plan, acquire permits for and build a baseload power plant, UE is actively studying future plant alternatives, including those utilizing coal or nuclear power.

Affiliate Transactions

Due to a MoPSC order issued in conjunction with the transfer of UE’s Illinois service territory to CIPS, UE, CIPS, and Genco amended the JDA effective in January 2006. If such an amendment had been in effect in 2005, we believe it would have resulted in a transfer of electric margins from Genco to UE of $35 million to $45 million based on certain assumptions and historical results. On July 7, 2006, UE, CIPS and Genco mutually consented to waive the one-year termination notice requirement and agreed to terminate the JDA on December 31, 2006. As a result of the termination of the JDA, UE and Genco will no longer have the obligation to provide power to each other. UE will retain the power it was transferring under the JDA to Genco at incremental cost and be able to sell any excess power it has at market prices. Genco will no longer receive the margins on sales that it made, which were supplied with power from UE. Termination of the JDA will require acceptance by FERC. Ameren’s and UE’s earnings will be affected by the termination of the JDA when UE’s rates are adjusted by the MoPSC. See Risk Factors under Part II, Item 1A and Note 2 - Rate and Regulatory Matters and Note 7 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for a discussion of the modification to the JDA ordered by the MoPSC and the effects of terminating the JDA.

On December 31, 2005, a power supply agreement with EEI for UE, CIPS (which resold its entitlement to Marketing Company) and IP expired. Power supplied under the agreement by EEI to UE, Marketing Company and IP was priced at EEI’s cost-based rates. Power previously supplied under this agreement to UE, Marketing Company and IP is being sold at market prices in 2006, which are above EEI’s cost-based rates and will continue to be sold at market prices in 2007. However, in 2006, UE, Genco (which supplies Marketing Company) and IP are replacing power previously received from EEI either through the use of their own higher-cost generation or higher-cost power purchases. In 2005, EEI generated 7.9 million megawatthours of power. UE, CIPS (which resold the power to Marketing Company) and IP purchased 3.0 million, 2.0 million and 1.2 million megawatthours, respectively, from EEI at an average price of $20 per megawatthour. The remaining generation was sold to EEI’s minority owner. The expiration of this agreement and the resulting decrease in UE’s margins and increase in its revenue requirement were reflected in UE’s July 2006 request to the MoPSC to increase electric rates.

Recent Acquisitions

·	Ameren, CILCORP, CILCO and IP expect to focus on realizing integration synergies associated with these acquisitions, including utilizing more economical fuels at CILCORP and CILCO and reducing administrative and operating expenses at IP.

Other

·	In August 2005, President George W. Bush signed into law the Energy Policy Act of 2005. This legislation includes several provisions that affect the Ameren Companies, including the repeal of PUHCA 1935 (under

which Ameren was registered) effective in February 2006, and tax incentives for investments in pollution control equipment, electric transmission property, clean coal facilities, and natural gas distribution lines. The Energy Policy Act of 2005 also extends the Price-Anderson nuclear plant liability provisions under the Atomic Energy Act of 1954.

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

REGULATORY MATTERS

See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates, commodity prices and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset.

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 nonfinancial or nonquantifiable. Such risks, principally business, legal and operational risks, are not part of 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.

Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005. See Item 7A under Part II of the 2005 Form 10-K for a more detailed discussion of our market risks.

Interest Rate Risk

We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at June 30, 2006:

	Interest Expense		Net Income^(a)
Ameren	$	13	$	(8)
UE		8		(5)
CIPS		(b)		(b)
Genco		3		(2)
CILCORP		2		(1)
CILCO		1		(1)
IP		4		(2)

(a) Calculations are based on an effective tax rate of 38%.

(b) Less than $1 million.

The model does not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act 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, this 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 who make up our customer base. At June 30, 2006, no nonaffiliated customer represented greater than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE, Genco, AERG, IP and Marketing Company may have credit exposure associated with interchange purchase and sale activity with nonaffiliated companies. At June 30, 2006, UE’s, Genco’s, AERG’s, IP’s and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange purchases and sales was less than $1 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 that 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 before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $27 million at June 30, 2006.

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement plans are dependent on a number of factors, including the rate of return on plan assets. To the extent the value of plan assets declines, the effect would be reflected in net income and OCI, and in the amount of cash required to be contributed to the plans.

Commodity Price Risk

We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements to regulated and nonregulated electric customers. Most of Genco’s and AERG’s electric power sales agreements expire during 2006. EEI’s cost-based power supply agreements for nearly all of its power expired at the end of 2005. EEI has an agreement to sell 100% of its capacity and energy to Marketing Company through December 31, 2015. EEI currently does not expect to hedge for price risk a significant portion of its available megawatthours. Genco and AERG may participate jointly in the September 2006 Illinois power procurement auction through Marketing Company. Genco and AERG will also seek to sell power forward to wholesale, municipal and industrial customers as has been its past practice. Ultimately, Genco and AERG will seek to hedge for price risk the majority of available megawatthours for 2007 by December 31, 2006. We also attempt to mitigate financial risks through structured risk management programs and policies, which include structured forward-hedging programs and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts).

CIPS, CILCO and IP have electric rate freezes in Illinois through January 1, 2007, and power supply contracts in place through December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through a September 2006 auction. The approved framework also allows for full cost recovery of power through a rate mechanism. UE’s electric rate freeze in Missouri expired June 30, 2006. In July 2006, UE filed for an increase in electric rates, including a request for a fuel and purchased power cost recovery mechanism. UE is also exposed to price risk on its interchange sales. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for further information.

The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own virtually no generation, that are price-hedged over the remainder of 2006 through 2010:

	2006		2007		2008 - 2010
Ameren:
Coal		100%		95%		58%
Coal transportation		100		95		60
Nuclear fuel		100		100		70
Natural gas for generation		66		12		2
Natural gas for distribution^(a)		(a)		33		7
UE:
Coal		100%		95%		54%
Coal transportation		100		99		79
Nuclear fuel		100		100		70
Natural gas for generation		43		5		1
Natural gas for distribution^(a)		(a)		22		5
CIPS:
Natural gas for distribution^(a)		(a)		40%		15%
Purchased power^(b)		100		-		-
Genco:
Coal		100%		92%		69%
Coal transportation		100		95		39
Natural gas for generation		100		12		2
CILCORP/CILCO:
Coal		100%		97%		56%
Coal transportation		100		69		44
Natural gas for distribution^(a)		(a)		37		6
Purchased power^(b)		100		-		-

2006

2007

2008 - 2010

IP:
Natural gas for distribution^(a)	(a)	30%	5%
Purchased power^(b)	90	-	-

(a)

Represents the percentage of natural gas price-hedged for the peak winter season of November through March. The year 2006 represents the period January 2006 through March 2006 and therefore is non-applicable for this report. The year 2007 represents November 2006 through March 2007. This continues each successive year through March 2010.

(b)	Beginning in 2007, CIPS, CILCO and IP are expected to purchase all electric capacity and energy through a power procurement auction process approved by the ICC. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a discussion of this matter.

The following table shows how our total fuel expense might increase and how our net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the remainder of 2006 through 2010:

	Coal				Transportation
	Fuel Expense		Net Income^(a)		Fuel Expense		Net Income^(a)
Ameren	$	8	$	(5)	$	10	$	(6)
UE		5		(3)		3		(2)
Genco		2		(1)		4		(2)
CILCORP/CILCO		1		(1)		2		(1)

(a)	Calculations are based on an effective tax rate of 38%.

In the event of a significant change in coal prices, UE, Genco and CILCO would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources. As discussed in Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report, Missouri legislation has been approved that could mitigate the impact of increased fuel cost at Ameren and UE through UE’s ability to recover these increases in rates.

See Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information regarding the long-term commitments for the procurement of coal, natural gas and nuclear fuel.

Fair Value of Contracts

Most of our commodity contracts qualify for treatment as normal purchases and normal sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three months and six months ended June 30, 2006. The sources used to determine the fair value of these contracts were active quotes, other external sources, and other modeling and valuation methods. All of these contracts have maturities of less than four years.

	Ameren^(a)		UE		CIPS		Genco		CILCORP/ CILCO		IP
Three Months
Fair value of contracts at beginning of period, net	$	30	$	(3)	$	6	$	-	$	24	$	2
Contracts realized or otherwise settled during the period		(14)		(2)		(2)		1		(5)		(1)
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		27		3		-		-		(1)		1
Fair value of contracts outstanding at end of period, net	$	43	$	(2)	$	4	$	1	$	18	$	2
Six Months
Fair value of contracts at beginning of period, net	$	69	$	(5)	$	12	$	-	$	50	$	(2)
Contracts realized or otherwise settled during the period		(26)		(4)		(5)		1		(9)		(2)
Changes in fair values attributable to changes in valuation technique and assumptions		-		-		-		-		-		-
Fair value of new contracts entered into during the period		1		1		-		-		-		-
Other changes in fair value		(1)		6		(3)		-		(23)		6
Fair value of contracts outstanding at end of period, net	$	43	$	(2)	$	4	$	1	$	18	$	2

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

ITEM 4. CONTROLS AND PROCEDURES.

(a)	Evaluation of Disclosure Controls and Procedures

As of June 30, 2006, the principal executive officer and principal financial officer of each of the Ameren Companies have evaluated the effectiveness of the design and operation of each registrant’s disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Upon making that evaluation, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are 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.

(b)	Change in Internal Controls

There has been no change in the Ameren Companies’ internal control over financial reporting 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.

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve sub-stantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.

Note 2 - Rate and Regulatory Matters, Note 7 - Related Party Transactions and Note 8 - 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 1A. RISK FACTORS.

The Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005, includes a detailed discussion of our risk factors. The information presented below updates and should be read in conjunction with the risk factors and information disclosed in that Form 10-K.

The electric and gas rates that certain Ameren Companies are allowed to charge in Missouri and Illinois are largely set through 2006 and are currently the subject of various rate case proceedings. The outcome of these rate case proceedings, along with other actions of lawmakers and regulators that can significantly adversely affect our prospective earnings, liquidity, or business activities, are largely outside our control.

The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, or liquidity of the Ameren Companies. Our industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse impact on our businesses including our results of operations, financial position, or liquidity.

As a part of the settlement of UE’s Missouri electric rate case in August 2002, UE was subject to a rate moratorium that prohibited changes in its electric rates in Missouri before July 1, 2006. Furthermore, as part of the settlement of UE’s Missouri gas rate case, which was approved by the MoPSC in January 2004, UE agreed to make no changes in its gas delivery rates prior to July 1, 2006, with certain exceptions. With the expiration of these electric and gas rate moratoriums, UE filed in July 2006 requests with the MoPSC for an increase in electric rates of $361 million and an $11 million increase in natural gas delivery rates. The MoPSC staff and other stakeholders will review UE’s rate adjustment requests and, after their analyses, may also make recommendations as to electric

and gas rate adjustments. A decision from the MoPSC is expected no later than June 2007.

The ICC order approving Ameren’s acquisition of IP prohibited IP from filing for any increase in gas delivery rates effective before January 1, 2007, beyond IP’s then-pending request for a gas delivery rate increase. In addition, a provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. This Illinois legislation also requires that 50% of the earnings from each respective jurisdiction in excess of certain levels be refunded to CIPS’, CILCO’s and IP’s Illinois customers through 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through an auction and related tariffs. This approval is subject to a pending court appeal. In addition, certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties have sought and continue to seek to block the power procurement auction and/or the recovery, through rates to customers, of related costs for power supply resulting from the auction. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren, including a significant drop in credit ratings (possibly to below investment-grade status), a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, impaired customer service, job losses, and financial insolvency.

The Illinois legislature held hearings in 2005 and 2006 regarding the framework for retail rate determination and power procurement. In February 2006, legislation was introduced in the Illinois House of Representatives that would extend the electric rate freeze in Illinois through 2010. CIPS, CILCO and IP strongly believe that an extension of the electric rate freeze in Illinois would not be in the best interests of any of the Ameren Illinois utilities or their customers and have been working with key stakeholders in Illinois to develop a constructive rate increase phase-in plan for residential customers to address the potential significant increases in customer rates for the Ameren Illinois utilities beginning in 2007. We believe that a rate increase phase-in plan would need to allow for deferral of a portion of the power procurement costs, with provision for full and timely recovery of all deferred costs in a manner that would not result in further reductions in credit ratings from December 31, 2005 levels. We believe a rate increase phase-in plan, providing for deferral of costs with certainty of full and timely recovery of any deferred costs, would require legislation in Illinois. In March 2006, legislation was introduced in the Illinois House of Representatives that would allow the deferral of a portion of the power procurement costs and would authorize the ICC to permit a utility with fewer than one million retail customers to form special purpose finance vehicles to issue securitization bonds to recover the deferred costs, with interest. CIPS, CILCO and IP each have less than one million retail customers. Securitization would allow these special purpose vehicles to issue debt securities and use the proceeds to pay the utilities immediately upon issuance of the bonds for the deferred power costs for which the utilities did not receive reimbursement from customers during a phase-in deferral period. Customers would fund, through dedicated charges included on their electric bills, a future payment stream that would be used to service the securitized debt. In effect, through these charges utility customers would pay in the future for power used, but not paid for, during a phase-in deferral period. This approach has the effect of spreading over the life of the bonds, a period of up to 10 years, the potentially significant initial electric rate increase for residential customers that would otherwise be necessary to pay the power procurement costs on a current basis. If passed, this legislation would assist our Ameren Illinois utilities in maintaining their financial integrity while allowing them to recover costs from customers over a longer term. We cannot predict what actions, if any, the Illinois legislature may ultimately take. In June 2006, the Ameren Illinois utilities filed with the ICC a rate increase phase-in and revenue securitization plan for residential customers similar to the legislation outlined above that would relate to the deferral of power and supply cost for 2007 and 2008. Legislation would be needed for this plan to become effective. In July 2006, the Illinois attorney general filed a motion with the ICC to dismiss this plan. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren.

Ameren, CIPS, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies and alternatives to address these Illinois electric issues. There can be no assurance that Ameren and the Ameren Illinois utilities will prevail over the stated opposition by certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois utilities are considering will be successful.

In December 2005, the Ameren Illinois utilities filed proposed new tariffs with the ICC that would increase annual revenues from electric delivery services, effective January 2, 2007, based on a proposed residential rate phase-in plan, by $156 million (CIPS - $14 million, CILCO -

$33 million, IP - $109 million) per year commencing in 2007 and an additional $46 million (CILCO - $10 million, IP - $36 million) per year commencing in 2008. In June 2006, the ICC staff filed rebuttal testimony recommending increases in revenues for electric delivery services for the Ameren Illinois utilities aggregating $120 million (CIPS - $1 million, CILCO - $30 million and IP - $89 million). In April 2006, the Illinois attorney general recommended increases in revenues for electric delivery services aggregating $71 million for the Ameren Illinois utilities (CIPS - $7 million decrease, CILCO - $19 million increase and IP - $59 million increase). In subsequent testimony, the Illinois attorney general accepted certain of the Ameren Illinois utilities’ positions increasing the estimated aggregate recommended revenue increase to $100 million. Other parties also made recommendations in the case. The ICC has until November 2006 to render a decision in these rate cases.

As a part of the settlement of UE’s Missouri electric rate case in 2002, UE made a commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments from January 1, 2002 through June 30, 2006. Ameren also committed IP to make between $275 million and $325 million in energy infrastructure investments 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 in Missouri and CIPS’, CILCO’s and IP’s rate freezes mean that capital expenditures will not become recoverable in rates and will not earn a return until the resolution of the current rate case proceedings for UE, CIPS, CILCO and IP. In addition, without appropriate and timely rate relief, any new energy infrastructure investment could result in increased financing requirements for UE, CIPS, CILCO and IP. This could have a material impact on our results of operations, financial position, or liquidity.

The Ameren Companies do not currently have, in either Missouri or Illinois, a rate adjustment clause for their electric operations that would allow them to recover the costs for purchased power or increased fuel costs from customers. Therefore, insofar as we have not hedged our fuel and power costs, we are exposed to changes in fuel and power prices to the extent that fuel for our electric generating facilities and power to supply customers must be purchased on the open market. In its Missouri electric rate case filed in July 2006, UE requested a fuel and purchased power cost recovery mechanism.

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, FERC has been mandating changes in the regulatory framework for transmission-owning public utilities such as UE, CIPS, CILCO and IP.

Principally because of rate reductions and moratoriums, increased costs and investments have caused decreased returns in Ameren’s utility businesses. Ameren expects many of its operating expenses to continue to rise and further expects to continue to make significant investment in its energy infrastructure, which is the principal factor underlying its pending rate increase requests with the MoPSC and the ICC. We cannot predict the outcome of these proceedings. In addition, in response to competitive, economic, political, legislative and

regulatory pressures, in connection with the resolution of our current rate case proceedings, or otherwise, we may be subject to further rate moratoriums, rate refunds, limits on rate increases or rate reductions, including phase-in plans. Any or all of these could have a significant adverse effect on our results of operations, financial position, or liquidity.

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

The following table presents Ameren Corporation’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
April 1 - April 30, 2006		1,551	$	50.47		-		-
May 1 - May 31, 2006		428		49.87		-		-
June 1 - June 30, 2006		2,700		50.44		-		-
Total		4,679	$	50.40		-		-

(a)

Included in April was 1 share of Ameren common stock purchased to satisfy an employee’s tax obligation incurred with the vesting of a performance share unit and share distribution under Ameren’s Long-term Incentive Plan of 1998 upon the employee’s death. Included in May were 428 shares of Ameren common stock purchased in connection with the satisfaction of employee tax obligations incurred by the release of restricted shares of Ameren common stock under the Long-term Incentive Plan of 1998. The remaining shares of Ameren common stock were purchased in open-market transactions in satisfaction of Ameren’s obligation 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.

None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the April 1 to June 30, 2006 period.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Ameren

At Ameren’s annual meeting of shareholders held on May 2, 2006, the following matters were presented to the meeting for a vote and the results of such voting are as follows:

Item (1) Election of 11 directors (comprising Ameren’s full Board of Directors) to serve until the next annual meeting of shareholders in 2007.

Name	For	Withheld	Broker Non-Votes^(a)
Susan S. Elliott	170,433,601	3,399,101	-
Gayle P.W. Jackson	170,555,732	3,276,970	-
James C. Johnson	170,503,619	3,329,083	-
Richard A. Liddy	169,543,114	4,289,588	-
Gordon R. Lohman	169,700,926	4,131,776	-
Richard A. Lumpkin	169,743,607	4,089,095	-
Charles W. Mueller	170,429,775	3,402,927	-
Douglas R. Oberhelman	169,918,926	3,913,776	-
Gary L. Rainwater	170,153,917	3,678,785	-
Harvey Saligman	169,812,589	4,020,113	-
Patrick T. Stokes	170,012,820	3,819,882	-

(a) Broker shares included in the quorum but not voting on the item.

Item (2) Ameren proposal regarding approval of the 2006 Omnibus Incentive Compensation Plan.

For	Against	Abstain	Broker Non-Votes^(a)
113,160,592	11,497,749	3,295,718	65,213,786

(a) Broker shares included in the quorum but not voting on the item.

Item (3) Ameren proposal regarding ratification of the appointment of PricewaterhouseCoopers LLP as Ameren’s independent auditors for the fiscal year ending December 31, 2006.

For	Against	Abstain	Broker Non-Votes^(a)
167,748,938	2,015,561	1,822,316	21,553,105

(a)	Broker shares included in the quorum but not voting on the item.

Item (4) Shareholder proposal requesting an evaluation of a 20-year extension of UE’s Callaway nuclear plant operating license.

For	Against	Abstain	Broker Non-Votes^(a)
9,084,767	106,585,670	12,364,615	65,132,792

(a)	Broker shares included in the quorum but not voting on the item.

At UE’s annual meeting of shareholders held on May 2, 2006, the following individuals (comprising UE’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Daniel F. Cole, Richard J. Mark, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David A. Whiteley. Each individual received 102,123,834 votes for election and no withheld votes or broker non-votes.

CIPS

At CIPS’ annual meeting of shareholders held on May 2, 2006, the following individuals (comprising CIPS’ full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David A. Whiteley. Each individual received 25,452,373 votes for election and no withheld votes or broker non-votes.

CILCO

At CILCO’s annual meeting of shareholders held on May 2, 2006, the following individuals (comprising CILCO’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David A. Whiteley. Each individual received 13,563,871 votes for election and no withheld votes or broker non-votes.

At IP’s annual meeting of shareholders held on May 2, 2006, the following individuals (comprising IP’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David A. Whiteley. Each individual received 23,662,924 votes for election and no withheld votes or broker non-votes.

GENCO and CILCORP

The information called for by this item is omitted in reliance on General Instruction H(1)(a) and (b) of Form 10-Q.

ITEM 6. EXHIBITS.

(a) Exhibits. The documents listed below are being filed on behalf of Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP as indicated.

Exhibit Designation	Registrant(s)	Nature of Exhibit
Material Contracts
10.1	Ameren Companies	June 9, 2006 Revised Schedule 1 to Amended and Restated Ameren Corporation Change of Control Severance Plan previously filed as Exhibit 10.5 to February 16, 2006 Form 8-K
Statement re: Computation of Ratios

12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	UE	UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	CIPS	CIPS’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.4	Genco	Genco’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.5	CILCORP	CILCORP’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.6	CILCO	CILCO’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.7	IP	IP’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements

Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-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 CIPS CILCORP CILCO IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE, CIPS, CILCORP, CILCO and IP
31.4	UE CIPS Genco CILCORP CILCO IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE, CIPS, Genco, CILCORP, CILCO and IP
31.5	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco

Exhibit Designation

Registrant(s)

Nature of Exhibit

Section 1350 Certifications
32.1	Ameren UE CIPS CILCORP CILCO IP	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren, UE, CIPS, CILCORP, CILCO and IP
32.2	Genco	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco

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