NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING

POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.

 

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UE, or Union Electric Company, also known as AmerenUE, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. UE was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area located in central and eastern Missouri. This area has an estimated population of 2.8 million and includes the Greater St. Louis area. UE supplies electric service to 1.2 million customers and natural gas service to 126,000 customers.

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CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. CIPS was incorporated in Illinois in 1923 and is successor to a number of companies, the oldest of which was organized in 1902. It supplies electric and natural gas utility service to portions of central, west central and southern Illinois having an estimated population of 1.1 million in an area of 20,500 square miles. CIPS supplies electric service to 383,000 customers and natural gas service to 182,000 customers.

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Genco, or Ameren Energy Generating Company, operates a merchant electric generation business in Illinois and Missouri. Genco was incorporated in Illinois in March 2000. Genco’s coal, and natural gas and oil-fired electric generating facilities, are expected to have capacity of 3,454, 1,578, and 169 megawatts, respectively, at the time of the 2010 peak summer electrical demand.

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CILCO, or Central Illinois Light Company, also known as AmerenCILCO, operates a rate-regulated electric transmission and distribution business, a merchant electric generation business (through its subsidiary AERG), and a rate-regulated natural gas transmission and distribution business, all in Illinois. CILCO was incorporated in Illinois in 1913. It supplies electric and natural gas utility service to portions of central and east central Illinois in areas of 3,700 and 4,500 square miles, respectively, with an estimated population of 0.6 million. CILCO supplies electric service to 211,000 customers and natural gas service to 214,000 customers. AERG, a wholly owned subsidiary of CILCO, is expected to have capacity of 1,125 megawatts from its coal-fired electric generating facilities at the time of the 2010 peak summer electrical demand.

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IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. IP was incorporated in 1923 in Illinois. It supplies electric and natural gas utility service to portions of central, east central, and southern Illinois, serving a population of 1.5 million in an area of 15,000 square miles, contiguous to our other service territories. IP supplies electric service to 617,000 customers and natural gas service to 417,000 customers, including most of the Illinois portion of the Greater St. Louis area.

Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. Ameren consolidates EEI for financial reporting purposes. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. On January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% stock ownership interest in EEI to Genco through a capital contribution. See Note 14 – Related Party Transactions for additional information.

The following table presents summarized financial information of EEI (in millions):

 

For the years ended December 31,		2009			2008			2007
Operating revenues		$	303		$	520		$	427
Operating income			19			226			216
Net income			10			142			136
As of December 31,			2009			2008			2007
Current assets		$	86		$	76		$	69
Noncurrent assets			172			140			124
Current liabilities			165			93			60
Noncurrent liabilities			48			43			10

 

The financial statements of Ameren, Genco and CILCO are prepared on a consolidated basis. CIPS has no subsidiaries and therefore is not consolidated. UE had a subsidiary in 2007 (Union Electric Development Corporation), but in January 2008 this subsidiary was transferred to Ameren in the form of a stock dividend. Accordingly, UE’s financial statements were prepared on a consolidated basis for 2007 only. IP had a subsidiary in 2007 (Illinois Gas Supply Company) that was dissolved at December 31, 2007. Accordingly, IP’s financial statements were prepared on a consolidated basis for 2007 only. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.

Regulation

Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, the NRC, and FERC. In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, UE, CIPS, CILCO and IP defer certain costs as assets pursuant to actions of our rate regulators or the expected ability to recover such costs in rates charged to customers. UE, CIPS, CILCO and IP also defer certain amounts as liabilities pursuant to actions of regulators or the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See Note 2 – Rate and Regulatory Matters for additional information on regulatory assets and liabilities. Assets are also recorded as construction work in progress and property and plant, net. See Note 3 – Property and Plant, Net.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.

Allowance for Doubtful Accounts Receivable

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing and anticipated future collections environment. See Note 2 – Rate and Regulatory Matters for additional information regarding regulatory recovery of uncollectible accounts receivable by the Ameren Illinois Utilities.

 

Materials and Supplies

Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2009 and 2008:

 

		Ameren(a)			UE			CIPS			Genco			CILCO			IP
2009:
Fuel(b)		$	315		$	154		$	-		$	97		$	38		$	-
Gas stored underground			183			22			32			-			45			84
Other materials and supplies			284			170			15			35			24			28
		$	782		$	346		$	47		$	132		$	107		$	112
2008:
Fuel(b)		$	290		$	139		$	-		$	92		$	32		$	-
Gas stored underground			277			32			54			-			75			117
Other materials and supplies			275			168			16			30			24			27
		$	842		$	339		$	70		$	122		$	131		$	144

 

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

(b)	Consists of coal, oil, paint, propane, and tire chips.

 

Property and Plant

We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed specifically below, is also capitalized as a cost of our rate-regulated assets. Interest during construction is capitalized as a cost of merchant generation assets. Maintenance expenditures, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs incurred by our merchant generation operations that do not constitute legal obligations are expensed as incurred. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 – Property and Plant, Net, for additional information.

Depreciation

Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The provision for depreciation for the Ameren Companies in 2009, 2008 and 2007 generally ranged from 3% to 4% of the average depreciable cost.

Allowance for Funds Used During Construction

In our rate-regulated operations, we capitalize the allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, as is the utility industry accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and it treats such financing costs in the same manner as construction charges for labor and materials.

Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates. The following table presents the annual allowance for funds used during construction rates that were utilized during 2009, 2008, and 2007:

 

		2009			2008			2007
Ameren		6% – 10	%		1% – 7	%		6% – 7	%
UE		6			7			6
CIPS		6			1			6
CILCO		10			1			7
IP		9			5			6

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Ameren’s goodwill relates to its acquisition of IP and an additional 20% EEI ownership interest acquired in 2004 as well as its acquisition of CILCORP and Medina Valley in 2003. IP’s goodwill relates to the acquisition of IP in 2004. See Note 17 – Goodwill for additional information.

Intangible Assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s, Genco’s and CILCO’s intangible assets at December 31, 2009 and 2008, consisted of emission allowances. See also Note 15 – Commitments and Contingencies for additional information on emission allowances.

The following table presents the SO₂ and NO_x emission allowances held and the related aggregate SO₂ and NO_x emission allowance book values that were carried as intangible assets as of December 31, 2009. Emission allowances consist of various individual emission allowance certificates and do not expire. Emission allowances are charged to fuel expense as they are used in operations.

 

SO2 and NOX in tons		SO2(a)		NOX(b)		Book Value(c)
Ameren(d)		3,028,000		25,091		$	129	(e)
UE		1,610,000		13,677			35
Genco		743,000		9,258			34
CILCO (AERG)		354,000		210			1
EEI		321,000		1,946			5

 

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

(b)	Vintage is 2009.

(c)	The book value represents SO2 and NOx emission allowances for use in periods through 2039. The book value at December 31, 2008, for Ameren, UE, Genco, CILCO (AERG), and EEI was $167 million, $48 million, $49 million, $1 million, and $9 million, respectively.

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

(e)	Includes $30 million and $24 million of fair-market value adjustments recorded in connection with Ameren’s 2003 acquisition of CILCORP and Ameren’s 2004 acquisition of an additional 20% ownership interest in EEI, respectively.

The following table presents amortization expense recorded in connection with the usage of emission allowances, net of gains from emission allowance sales, for Ameren, UE, Genco and CILCO (AERG) during the years ended December 31, 2009, 2008, and 2007:

 

		2009				2008				2007
Ameren(a)(b)		$	24			$	28			$	35
UE			(5	)			(5	)			(5	)
Genco			16				25				30
CILCO (AERG)			2				(c	)			1

 

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

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

(c)	Less than $1 million.

 

Impairment of Long-lived Assets

We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value. In the period in which we determine an asset meets the held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell. In 2009, Genco recorded asset impairment charges of $6 million as a result of the termination of a rail line extension project at a subsidiary of Genco and to adjust the carrying value of an office building owned by Genco to its estimated fair value as of December 31, 2009. The charge related to the office building was based on the expected net proceeds to be generated from its sale in 2010. In addition, CILCO recorded an asset impairment charge of $1 million to adjust the carrying value of CILCO’s (AERG’s) Indian Trails generation facility’s estimated fair value as of December 31, 2009. This charge was based on the net proceeds generated from the sale of the facility in January 2010.

In 2008, asset impairment charges were recorded to adjust the carrying value of CILCO’s (AERG’s) Indian Trails and Sterling Avenue generation facilities to their estimated fair values as of December 31, 2008. CILCO recorded an asset impairment charge of $12 million related to the Indian Trails generation facility as a result of the suspension of operations by the facility’s only customer. CILCORP recorded a $2 million impairment charge related to the Sterling Avenue CT. The charge was based on the net proceeds generated from the sale of the facility in 2009.

The 2009 and 2008 asset impairment charges were recorded in Operating Expenses – Other Operations and Maintenance Expense in the applicable statements of income and were included in Merchant Generation segment results.

Investments

Ameren and UE evaluate for impairment the investments held in UE’s nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which UE believes would be recovered in electric rates paid by its customers. Accordingly, Ameren and UE recognize a regulatory asset on their balance sheets for losses on investments held in the nuclear decommissioning trust fund. See Note 9 – Nuclear Decommissioning Trust Fund Investments for additional information.

Environmental Costs

Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Estimated environmental expenditures are regularly reviewed and updated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.

Unamortized Debt Discount, Premium, and Expense

Discount, premium, and expense associated with long-term debt are amortized over the lives of the related issues.

Revenue

Operating Revenues

UE, CIPS, Genco, CILCO and IP record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period.

Trading Activities

We present the revenues and costs associated with certain energy derivative contracts designated as trading on a net basis in Operating Revenues – Electric and Other.

Nuclear Fuel

UE’s cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is based on net kilowatthours generated and sold, and that cost is charged to expense.

Purchased Gas, Power and Fuel Rate-adjustment Mechanisms

Ameren’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas and electric fuel and purchased power costs.

In UE’s, CIPS’, CILCO’s, and IP’s retail natural gas utility jurisdictions, changes in natural gas costs are generally reflected in billings to their natural gas utility customers through PGA clauses. The difference between actual natural gas costs and costs billed to customers in a given period are deferred and included in Other Current Assets or Other Current Liabilities on the balance sheet of Ameren and in Current Regulatory Assets or Current Regulatory Liabilities on the balance sheet of UE, CIPS, CILCO and IP. The deferred amounts are either billed or refunded to natural gas utility customers in a subsequent period.

In the Ameren Illinois Utilities’ retail electric utility jurisdictions, changes in purchased power costs are generally reflected in billings to their electric utility customers through pass-through rate-adjustment clauses. The difference between actual purchased power costs and costs billed to customers in a given period are deferred and included in Other Current Assets or Other Current Liabilities on the balance sheet of Ameren and in Current Regulatory Assets or Current Regulatory Liabilities on the balance sheets of CIPS, CILCO and IP. The deferred amounts are either billed or refunded to electric utility customers in a subsequent period.

In 2009, UE implemented a FAC for its retail electric jurisdiction. The FAC allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, greater or less than the amount set in base rates, subject to MoPSC prudency review. The difference between the costs of fuel incurred and the cost of fuel recovered from UE’s customers are deferred and included in Other Current Assets or Other Current Liabilities on the balance sheet of Ameren and in Current Regulatory Assets or Current Regulatory Liabilities on the balance sheet of UE. The deferred amounts are either billed or refunded to UE’s electric utility customers in a subsequent period.

Accounting for MISO Transactions

MISO-related purchase and sale transactions are recorded by Ameren, UE, CIPS, CILCO and IP using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. We record net purchases in a single hour in Operating Expenses – Purchased Power and net sales in a single hour in Operating Revenues – Electric in our statements of income. On occasion, prior period transactions will be resettled outside the routine settlement process because of a change in MISO’s tariff or a material interpretation thereof. In these cases, Ameren, UE, CIPS, CILCO and IP recognize expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated. Ameren, UE, CIPS, CILCO and IP recognize revenues associated with resettlements in accordance with authoritative guidance on revenue recognition.

Stock-based Compensation

Stock-based compensation cost is measured at the grant date based on the fair value of the award. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite service period. See Note 12 – Stock-based Compensation for additional information.

Excise Taxes

Excise taxes imposed on us are reflected on Missouri electric, Missouri natural gas, and Illinois natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses – Taxes Other Than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses – Taxes Other than Income Taxes for the years ended 2009, 2008 and 2007:

 

		2009			2008			2007
Ameren		$	168		$	172		$	166
UE			112			109			110
CIPS			15			16			15
CILCO			11			13			11
IP			30			34			30

Income Taxes

Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are calculated based on statutory tax rates.

We recognize that regulators will probably reduce future revenues for deferred tax liabilities initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded because of decreases in the statutory rate, were credited to a regulatory liability. A regulatory asset has been established to recognize the probable future recovery in rates of future income taxes resulting principally from the reversal of allowance for funds used during construction, that is, equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of the authoritative accounting provisions for income taxes.

Investment tax credits used on tax returns for prior years have been deferred for book purposes; the credits are being amortized over the useful lives of the related investment. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 13 – Income Taxes.

UE, CIPS, Genco, CILCO, and IP are parties to a tax sharing agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax sharing agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution of capital to the party receiving the benefit.

Noncontrolling Interests

Ameren’s noncontrolling interests comprise the 20% of EEI’s net assets not owned by Ameren and the preferred stock not subject to mandatory redemption of the Ameren subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet.

Earnings per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2009, 2008, and 2007. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 16,841 shares in 2008 and 35,545 shares in 2007. There were no assumed stock option conversions in 2009, as the remaining stock options were not dilutive.

Accounting Changes and Other Matters

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

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued authoritative guidance that established accounting and reporting standards for minority interests, which were recharacterized as noncontrolling interests. This guidance requires noncontrolling interests to be classified as a component of equity separate from the parent’s equity; purchases or sales of equity interests that do not result in a change in control to be accounted for as equity transactions; net income attributable to the noncontrolling interest to be included in consolidated net income in the statement of income; and upon a loss of control, the interest sold, as well as any interest retained, to be recorded at fair value, with any gain or loss recognized in earnings. We adopted the provisions of this guidance at the beginning of 2009. It applied prospectively, except for the presentation and disclosure requirements, for which it applied retroactively. See Noncontrolling Interests above for additional information.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued amended authoritative guidance that requires entities to provide greater transparency in interim and annual financial statements about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for, and how the instruments and related hedged items affect the financial position, results of operations, and cash flows of the entity. This guidance requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The adoption of this guidance, effective for us in the first quarter of 2009, did not have a material impact on our results of operations, financial position, or liquidity because it required enhanced disclosure only. See Note 7 – Derivative Financial Instruments for additional information.

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, the FASB issued authoritative guidance regarding additional disclosures related to pension and other postretirement benefit plan assets. Required additional disclosures include those related to the investment allocation decision-making process, the fair value of each major category of plan assets and the inputs and valuation techniques used to measure fair value and significant concentrations of risk within the plan assets. The adoption of this guidance, effective for us as of December 31, 2009, did not have a material impact on our results of operations, financial position, or liquidity, because it provided enhanced disclosure requirements only. See Note 11 – Retirement Benefits for additional information.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

In April 2009, the FASB issued additional authoritative guidance regarding the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for an asset or liability. The guidance, which applies to all fair value measurements, does not change the objective of a fair value measurement. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued authoritative guidance that established a new method of recognizing and reporting other-than-temporary impairments of debt securities. It contains additional annual and interim disclosure requirements related to debt and equity securities. Under the new guidance, an impairment of debt securities is other-than-temporary if (1) the entity intends to sell the security, (2) it is more likely than not that the entity will be required to sell the security before recovery of its amortized cost basis, or (3) the entity does not expect to recover the security’s entire amortized cost basis. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.

Subsequent Events

In May 2009, the FASB issued authoritative guidance that established general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity. In February 2010, the FASB issued amended guidance which was effective upon issuance. The adoption of the amended guidance did not have a material impact on our results of operations, financial position, or liquidity.

The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles

In June 2009, the FASB issued the FASB Accounting Standards Codification (the “Codification”), which is the primary source of authoritative GAAP to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification modifies the hierarchy of GAAP to include only two levels: authoritative and nonauthoritative. The Codification supersedes all non-SEC accounting and reporting standards. The adoption of the Codification, effective for us as of July 1, 2009, did not affect our results of operations, financial position, or liquidity.

Variable-Interest Entities

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

 

Disclosures about Fair Value Measurements

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

Asset Retirement Obligations

Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. Ameren, UE, Genco and CILCO have recorded AROs for retirement costs associated with UE’s Callaway nuclear plant decommissioning costs, asbestos removal, ash ponds, and river structures. In addition, Ameren, UE, CIPS, and IP have recorded AROs for the disposal of certain transformers.

Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Note 2 – Rate and Regulatory Matters.

 

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2009 and 2008:

 

		Ameren(a)(b)(c)				UE(b)				CIPS(d)				Genco(c)				CILCO				IP(d)
Balance at December 31, 2007		$	567			$	476			$	2			$	52			$	28			$	2
Liabilities settled			(3	)			(e	)			-				(1	)			(2	)			(e	)
Accretion in 2008(f)			33				27				(e	)			3				2				(e	)
Change in estimates(g)			(186	)			(186	)			-				(e	)			(e	)			-
Balance at December 31, 2008		$	411			$	317			$	2			$	54			$	28			$	2
Liabilities incurred		$	(e	)		$	-			$	-			$	-			$	(e	)		$	-
Liabilities settled			(3	)			(2	)			-				(e	)			(e	)			-
Accretion in 2009(f)			24				18				(e	)			4				2				(e	)
Change in estimates(h)			2				(2	)			(e	)			(e	)			4				(e	)
Balance at December 31, 2009		$	434			$	331			$	2			$	58			$	34			$	2

 

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

(b)	The nuclear decommissioning trust fund assets of $293 million and $239 million as of December 31, 2009 and 2008, respectively, were restricted for decommissioning of the Callaway nuclear plant.

 

(c)	Balance included $5 million in Other Current Liabilities on the balance sheet.

(d)	Balance included in Other Deferred Credits and Liabilities on the balance sheet.

(e)	Less than $1 million.

(f)	All accretion expense was recorded as an increase to regulatory assets, except for Genco and CILCO (AERG).

(g)	UE changed estimates related to its Callaway nuclear plant decommissioning costs based on a cost study performed in 2008, a change in assumptions related to plant life, and a decline in the cost escalation factor assumptions.

(h)	UE and CILCO changed estimates for asbestos removal. Additionally, CILCO changed related estimates to retirement costs for its ash ponds.

 

Variable-Interest Entities

According to authoritative accounting guidance regarding variable-interest entities (VIEs), an entity is considered a VIE if it does not have sufficient equity to finance its activities without assistance from variable-interest holders, or if its equity investors lack any of the following characteristics of a controlling financial interest: control through voting rights, the obligation to absorb expected losses, or the right to receive expected residual returns. Ameren and its subsidiaries review their equity interests, debt obligations, leases, contracts, and other agreements to determine their relationship to a VIE. We have determined that the following significant VIEs were held by the Ameren Companies at December 31, 2009:

Affordable housing partnership investments. At December 31, 2009 and 2008, Ameren had investments in multiple affordable housing and low-income real estate development partnerships as well as an investment in a commercial real estate development partnership of $64 million and $82 million in the aggregate, respectively. For these variable-interests, Ameren is a limited partner. It owns less than a 50 percent interest and receives the benefits and accepts the risks consistent with its limited partner interest. We have concluded that Ameren is not the primary beneficiary of any of the VIEs related to these investments because Ameren would not absorb a majority of the entity’s losses. These investments are classified as Other Assets on Ameren’s consolidated balance sheet. The maximum exposure to loss as a result of these variable interests is limited to the investments in these arrangements.

Coal Contract Settlement

In June 2008, Genco entered into a settlement agreement with a coal mine owner. The owner provided Genco with a lump-sum payment of $60 million in July 2008 because of the coal supplier’s premature closing of a mine and the early termination of a coal supply contract. The settlement agreement compensated Genco, in total, for higher fuel costs it incurred in 2008 ($33 million) and in 2009 ($27 million) as a result of the mine closure and contract termination.

Employee Separation and Other Charges

In the third quarter of 2009, Ameren initiated a voluntary separation program that provided eligible management employees the opportunity to voluntarily terminate their employment and receive benefits consistent with Ameren’s standard management severance program. This program was offered to eligible management employees at Ameren’s subsidiaries, including UE, CIPS, Genco, CILCO and IP. Additionally, in November 2009, Ameren initiated an involuntary separation program to reduce additional management positions under terms and benefits consistent with Ameren’s standard management severance program. Ameren recorded a pretax charge to earnings of $17 million in 2009 (UE – $8 million, CIPS – $1 million, Genco – $5 million, CILCO – $2 million, and IP – $1 million) for the severance costs related to both the voluntary and involuntary separation programs as well as for Merchant Generation staff reductions announced in the third quarter of 2009. These charges were recorded in other operations and maintenance expense in the applicable statements of income. Substantially all of this amount was paid prior to December 31, 2009. The number of positions eliminated as a result of these separation programs, including the Merchant Generation staff reductions, was approximately 300. In addition to these programs, Genco recorded a $4 million pretax charge to earnings in 2009 in connection with the retirement of two generating units at its Meredosia power plant and for related obsolete inventory.

NOTE 2 – RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In January 2009, the MoPSC issued an order approving an increase for UE in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. The rate changes necessary to implement the provisions of the MoPSC order were effective March 1, 2009. In February 2009, Noranda, UE’s largest electric customer, and the Missouri Office of Public Counsel appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Circuit Court of Cole County, Missouri. In September 2009, the Circuit Court of Pemiscot County granted Noranda’s request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. The merits of the appeal continue to be briefed by the parties. A decision is likely to be issued by the Circuit Court of Pemiscot County in the second quarter of 2010. During the stay, Noranda will pay into the court registry the contested portion of its monthly billings, approximately $0.5 million per month based on current usage levels. If UE wins the appeal, it will receive those monthly payments plus interest.

Pending Electric Rate Case

UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service by $402 million. Included in this increase request was approximately $227 million of anticipated increases in normalized net fuel costs in excess of the net fuel costs included in base rates previously authorized by the MoPSC in its January 2009 electric rate order, which, absent initiation of this general rate proceeding, would have been eligible for recovery through UE’s existing FAC. The balance of the increase request is based primarily on investments made to continue systemwide reliability improvements for customers, increases in costs essential to generating and delivering electricity, and higher financing costs. The initial electric rate increase request was based on an 11.5% return on equity, a capital structure composed of 47.4% equity, a rate base for UE of $6.0 billion, and a test year ended March 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of January 31, 2010. In February 2010, UE filed rebuttal testimony relating to certain positions taken by interveners in the rate case and modified its recommended return on equity to 10.8%.

UE’s initial filing included a request for interim rate relief, which would have placed into effect approximately $37 million of the requested increase prior to completion of the full rate case. In January 2010, the MoPSC denied UE’s request for interim rate relief.

As part of its filing, UE also requested that the MoPSC approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker. The environmental cost recovery mechanism, if approved, would allow UE to adjust electric rates twice each year outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with federal, state, or local environmental laws, regulations, or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews by the MoPSC. UE’s request was consistent with the environmental cost recovery rules approved by the MoPSC in April 2009. The storm restoration cost tracker would permit UE a more timely recovery of storm restoration operations and maintenance expenditures.

In addition, UE requested that the MoPSC approve the continued use of the FAC and the vegetation management and infrastructure inspection cost tracking mechanism that the MoPSC previously authorized in its January 2009 electric rate order, and the continued use of the regulatory tracking mechanism for pension and postretirement benefit costs that the MoPSC previously authorized in its May 2007 electric rate order. The UE request included the discontinuation of the SO ₂ emission allowance sales tracker.

UE’s filing with the MoPSC also seeks approval to revise the tariff under which it serves Noranda to prospectively address the significant lost revenues UE can incur due to any future operational issues at Noranda’s smelter plant in southeastern Missouri, such as the revenue losses resulting from the January 2009 storm-related power outage.

The MoPSC staff has responded to the UE request for an electric service rate increase. The MoPSC staff has recommended an increase to UE’s annual revenues of between $218 million to $251 million based on a return on equity range of 9.0% to 9.7%. Included in this recommendation was approximately $214 million of increases in normalized net fuel costs. Other parties also made recommendations through testimony filed in this case. MoPSC staff and other parties have expressed opposition to some of the requested cost recovery mechanisms as well as the proposed Noranda tariff revision.

The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by the end of June 2010. Hearings are scheduled in March 2010. UE cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, whether the cost recovery mechanisms and trackers requested will be approved or continued, or whether any rate change that may eventually be approved will be sufficient to enable UE to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.

Renewable Energy Portfolio Requirement

A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio requirement must be derived from solar energy. Compliance with the renewable energy portfolio requirement can be achieved through the procurement of renewable energy or renewable energy credits. Rules implementing the renewable energy portfolio requirement are expected to be issued by the MoPSC in 2010. UE expects that any related costs or investments would ultimately be recovered in rates. In January 2010, UE issued an RFP to solicit solar renewable energy credits and energy in 2011 to meet the solar portion of this requirement. UE is currently evaluating the responses.

 

Missouri Energy Efficiency Investment Act

In July 2009, the Missouri governor signed a law that went into effect in August 2009, which, among other things, allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. Recovery is permitted only if the program is approved by the MoPSC, results in energy savings, and is beneficial to all customers in the class for which the program is proposed. The new law could potentially, among other things, allow UE to earn a return on its energy efficiency programs equivalent to the return UE could earn with supply-side capital investments, such as new power plants.

Illinois

2008 Electric and Natural Gas Delivery Service Rate Order

On September 24, 2008, the ICC issued a consolidated order approving a net increase in annual revenues for electric delivery service of $123 million in the aggregate (CIPS – $22 million increase, CILCO – $3 million decrease, and IP – $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS – $7 million increase, CILCO – $9 million decrease, and IP – $40 million increase), based on a 10.65% return on equity with respect to electric delivery service and a 10.68% return on equity with respect to natural gas delivery service. These rate changes were effective on October 1, 2008.

In October 2008, CIPS, CILCO and IP and other parties requested that the ICC rehear certain aspects of its September 2008 consolidated order. In November 2008, the ICC denied all rate order rehearing requests filed by the Ameren Illinois Utilities and other parties. In December 2008, the Illinois attorney general appealed the rate order to the Appellate Court of Illinois, Fourth District, specifically, the ICC’s affirmation of the recovery of a certain amount of fixed costs in the customer charge. In December 2009, the Appellate Court denied the Illinois attorney general’s appeal and sustained the ICC rate order.

Pending Electric and Natural Gas Delivery Service Rate Cases

In June 2009, CIPS, CILCO and IP filed requests with the ICC to increase their annual revenues for electric delivery service. The currently pending requests, as amended, seek to increase annual revenues from electric delivery service by $115 million in the aggregate (CIPS – $38 million, CILCO – $17 million, and IP – $60 million). Additionally, the Ameren Illinois Utilities requested moving more of the electric delivery costs into the monthly non-volumetric charge, similar to the natural gas delivery rate design change approved by the ICC in 2008. The electric rate increase requests were based on an 11.3% to 11.7% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.3 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010.

 

CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service. The currently pending requests, as amended, seek to increase annual revenues for natural gas delivery service by $15 million in the aggregate (CIPS – $6 million, CILCO – $2 million, and IP – $7 million). The natural gas rate increase requests were based on a 10.8% to 11.2% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010.

The ICC staff has responded to the filed requests by the Ameren Illinois Utilities. The ICC staff has recommended, as amended, a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $57 million in the aggregate (CIPS – $21 million increase, CILCO – $5 million increase, and IP – $31 million increase) and a net decrease in revenues for natural gas delivery service of $11 million in the aggregate (CILCO – $6 million decrease and IP – $5 million decrease). The ICC staff position was based on a 10.1% to 10.4% return on equity for electric delivery service and a 9.4% to 9.6% return on equity for natural gas delivery service. Other parties also made recommendations through testimony filed in the electric and natural gas delivery service rate cases.

In February 2010, administrative law judges issued a consolidated proposed order, which included a recommended revenue increase for electric delivery service for the Ameren Illinois Utilities of $66 million in the aggregate (CIPS – $26 million increase, CILCO – $6 million increase, and IP – $34 million increase) and a recommended revenue net decrease for natural gas delivery service of $10 million in the aggregate (CIPS – $1 million increase, CILCO – $ 6 million decrease, and IP – $5 million decrease). The ICC is not bound by the proposed order issued by the administrative law judges.

The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by May 2010. The Ameren Illinois Utilities cannot predict the level of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, or whether any rate changes that may eventually be approved will be sufficient to enable the Ameren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the rate changes go into effect.

2007 Illinois Electric Settlement Agreement

In 2007, key stakeholders in Illinois agreed to avoid rate rollback and freeze legislation that would impose a tax on electric generation. These stakeholders wanted to address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement included a comprehensive rate relief and customer assistance program. The 2007 Illinois Electric Settlement Agreement provided approximately $1 billion of funding from 2007 to 2010 for rate relief for certain electric customers in Illinois, including approximately $488 million for customers of the Ameren Illinois Utilities. Pursuant to the 2007 Illinois Electric Settlement Agreement, the Ameren Illinois Utilities, Genco, and CILCO (AERG) agreed to make aggregate contributions of $150 million over the four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS – $21 million; CILCO – $11 million; IP – $28 million), $62 million from Genco, and $28 million from CILCO (AERG). See Note 15 –Commitments and Contingencies for information on the remaining contributions to be made as of December 31, 2009.

The Ameren Illinois Utilities, Genco, and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding under the 2007 Illinois Electric Settlement Agreement in a manner corresponding with the timing of the funding. As a result, Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the year ended December 31, 2009, of $25 million, $3 million, $2 million, $5 million, $10 million, and $5 million, respectively (year ended December 31, 2008 – $42 million, $6 million, $3 million, $8 million, $17 million, and $8 million, respectively) under the terms of the 2007 Illinois Electric Settlement Agreement.

Other electric generators and utilities in Illinois agreed to contribute $851 million to the comprehensive rate relief and customer assistance program. Contributions by the other electric generators (the generators) and utilities to the comprehensive program are subject to funding agreements. Under these agreements, at the end of each month, the Ameren Illinois Utilities send a bill, due in 30 days, to the generators and utilities for their proportionate share of that month’s rate relief and assistance. If any escrow funds have been provided by the generators, these funds will be drawn upon before reimbursement is sought from the generators. At December 31, 2009, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $10 million, $3 million, $2 million, and $5 million, respectively. See Note 14 – Related Party Transactions for information on the impact of intercompany settlements.

The 2007 Illinois Electric Settlement Agreement provided that if before August 1, 2011, legislation is enacted in Illinois freezing or reducing retail electric rates, or imposing or authorizing a new tax, special assessment, or fee on the generation of electricity, then the remaining commitments under the 2007 Illinois Electric Settlement Agreement would expire, and any funds set aside in support of the commitments would be refunded to the utilities and Generators.

Power Procurement

As part of the 2007 Illinois Electric Settlement Agreement, the reverse auction used for power procurement in Illinois was discontinued. However, one-third of the existing supply contracts from the September 2006 reverse power procurement auction remain in place through May 2010. A new competitive power procurement process led by the IPA, which was established as a part of the 2007 Illinois Electric Settlement Agreement, was implemented beginning in January 2009. In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products that the IPA procured on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 31, 2014. The IPA procured capacity, energy swaps, and renewable energy credits through an RFP process on behalf of the Ameren Illinois Utilities in the second quarter of 2009. See Note 14 – Related Party Transactions and Note 15 – Commitments and Contingencies for additional information about the Ameren Illinois Utilities’ purchased power agreements.

In December 2009, the ICC approved a plan for procurement of electric power for the Ameren Illinois Utilities and Commonwealth Edison Company for the period June 1, 2010, through May 31, 2015. The IPA will procure energy swaps, capacity and renewable energy credits and long-term renewable supply. The exact dates of each procurement event have not been determined. Following successful completion of the proposed 2010 procurement events, the Ameren Illinois Utilities will have sufficient capacity and energy hedges in place for 100% of their expected supply obligation for the period June 2010 through May 2011, 70% of their expected supply obligation for the period June 2011 through May 2012, and 44% of their expected supply obligations for the period June 2012 through May 2013. The Ameren Illinois Utilities will also have sufficient renewable energy credits to satisfy the 2010 planning year requirement along with 20-year renewable supply contracts consisting of 600,000 megawatthours per year of renewable energy power and credits with deliveries beginning June 1, 2012.

Also as part of the 2007 Illinois Electric Settlement Agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices. See Note 7 – Derivative Financial Instruments and Note 14 – Related Party Transactions for additional information on these financial contracts.

ICC Reliability Audit

In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on the Ameren Illinois Utilities’ transmission and distribution systems and reliability following the July 2006 wind storms and a November 2006 ice storm. In October 2008, Liberty Consulting Group presented the ICC with a final report containing recommendations for the Ameren Illinois Utilities to improve their systems and their response to emergencies. The ICC directed the Ameren Illinois Utilities to present to the ICC a plan to implement Liberty Consulting Group’s recommendations. The plan was submitted to the ICC in November 2008. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. The Ameren Illinois Utilities expect they could incur an estimated $20 million ($15 million for distribution and $5 million for transmission) of capital costs and an estimated $66 million ($50 million for distribution and $16 million for transmission) of cumulative operations and maintenance expenses for the 2010 through 2013 time frame in order to implement the recommendations.

In December 2009, the Ameren Illinois Utilities requested ICC approval of a rider mechanism to recover the distribution-related costs associated with the Liberty Consulting Group’s recommendations. This request replaced a previous request for a rider mechanism, which had been part of the pending electric delivery rate cases. There is no statutory date by which the ICC must act, and no schedule is currently in place for this request.

The Ameren Illinois Utilities have committed to implement various audit recommendations, as outlined in their November 2008 plan. However, in order to fulfill that commitment in a timely manner, they must be able to synchronize the timing of their distribution-implementation expenditures with the recognition of those costs in rates. Without the necessary funding or a rider mechanism to recover the distribution costs, the Ameren Illinois Utilities may defer some of the projects until the distribution costs can be recovered either in base rates or through some other cost recovery mechanism.

Transmission-related costs, as incurred, will be recoverable through FERC’s ratemaking proceedings.

Illinois 2009 Energy Legislation

In July 2009, a new law became effective in Illinois that, among other things, established new energy efficiency targets for Illinois natural gas utilities, developed a percentage of income payment plan for low-income utility customers, and allowed electric and natural gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their base rates. In February 2010, the ICC approved the Ameren Illinois Utilities’ electric and natural gas rate adjustment tariffs to recover bad debt expense not recovered in base rates. The tariffs provide utilities the ability to adjust their base rates annually through a rate adjustment mechanism that applies to 2008 and subsequent years. Upon ICC approval of the rate adjustment tariffs in February 2010, the Ameren Illinois Utilities made a one-time $10 million donation (CIPS – $2 million, CILCO – $2 million, and IP – $6 million) for customer assistance programs, as required by the legislation. The amount of the required one-time donation and the impact of the net recovery of 2008 and 2009 bad debt expenses were reflected in 2009 earnings.

Federal

Regional Transmission Organization

UE, CIPS, CILCO and IP are transmission-owning members of MISO, which is a FERC-regulated RTO that provides transmission tariff administration services for electric transmission systems. In early 2004, UE received authorization from the MoPSC to participate in MISO for a five-year period, with further participation subject to approval by the MoPSC. The MoPSC required UE to file a study evaluating the costs and benefits of its participation in MISO prior to the end of the five-year period. The MoPSC also directed UE to enter into a service agreement with MISO to provide transmission service to UE’s bundled retail customers. The service agreement’s primary function was to ensure that the MoPSC continued to set the transmission component of UE’s rates to serve its bundled retail load. Among other things, the service agreement provided that UE would not pay MISO for transmission service to UE’s bundled retail customers. FERC approved the service agreement in the form that was acceptable to the MoPSC.

Due to changes to MISO’s allocation of transmission revenues to transmission owners, UE believed it should have received incremental annual transmission revenues of $60 million as of February 2008 in accordance with its service agreement with MISO. Numerous transmission owners in MISO, along with MISO itself as the tariff administrator, filed with FERC in December 2007 requesting changes to the MISO tariff to prevent UE from collecting these additional transmission revenues. In December 2007, UE filed a protest to these proposed MISO tariff changes, calling them unauthorized and improper in light of the MoPSC’s requirement for the service agreement between UE and MISO discussed above. In February 2008, FERC issued an order accepting the tariff changes proposed by MISO and by certain transmission owners in MISO. In March 2008, UE filed a request with FERC for a rehearing of its order. In April 2008, FERC suspended UE’s request for rehearing to allow time for further consideration by FERC. UE is unable to predict if or when FERC may issue a further order in this proceeding.

As required by the MoPSC, UE filed a study in November 2007 with the MoPSC evaluating the costs and benefits of UE’s participation in MISO. UE’s filing noted a number of uncertainties associated with the cost-benefit study, including issues associated with the UE-MISO service agreement and MISO revenue allocation, as discussed above. In June 2008, a stipulation and agreement among UE, the MoPSC staff, MISO and other parties to the proceeding was filed with the MoPSC, which provided for UE’s continued, conditional MISO participation through April 30, 2012. The stipulation and agreement gives UE the right to seek permission from the MoPSC for early withdrawal from MISO if UE determines that sufficient progress toward mitigating some of the continuing uncertainties respecting its MISO participation is not being made. The MoPSC issued an order, effective September 19, 2008, approving the stipulation and agreement. If UE were to withdraw from MISO in the future, it might need to obtain FERC approval and to meet conditions imposed by FERC, in addition to obtaining MoPSC’s approval.

Seams Elimination Cost Adjustment

Pursuant to a series of FERC orders, FERC put Seams Elimination Cost Adjustment (SECA) charges into effect on December 1, 2004, subject to refund and hearing procedures. The SECA charges were a transition mechanism in place for 16 months, from December 1, 2004, to March 31, 2006, to compensate transmission owners in MISO and PJM for revenues lost when FERC eliminated the regional through-and-out rates previously applicable to transactions crossing the border between MISO and PJM. The SECA charge was a nonbypassable surcharge payable by load-serving entities in proportion to the benefit they realized from the elimination of the regional through-and-out rates as of December 1, 2004. The MISO transmission owners (including UE, CIPS, CILCO and IP) and the PJM transmission owners filed their proposed SECA charges in November 2004, as compliance filings pursuant to FERC order. A FERC administrative law judge issued an initial decision in August 2006, recommending that FERC reject both of the SECA compliance filings (the filing for SECA charges made by the transmission owners in the MISO and the filing for SECA charges made by the transmission owners in PJM). Several parties filed rehearing requests of this initial decision. There is no date scheduled for FERC to act on the initial decision. Both before and after the initial decision, various parties (including UE, CIPS, CILCO and IP as part of the group of MISO transmission owners) filed numerous bilateral or multiparty settlements. To date, FERC has approved many of the settlements and has rejected none of the settlements. Neither the MISO transmission owners, including UE, CIPS, CILCO and IP, nor the PJM transmission owners have been able to settle with all parties. During the transition period of December 1, 2004, to March 31, 2006, Ameren, UE, CIPS, and IP received net revenues from the SECA charges of $10 million, $3 million, $1 million, and $6 million, respectively. CILCO’s net SECA charges were less than $1 million. In December 2009, a party that has not settled its SECA charges filed with the U.S. Court of Appeals for the District of Columbia Circuit seeking an order directing the FERC to resolve the SECA matters. In response to this filing, in January 2010, FERC agreed to issue an order on the SECA initial decision and rehearing requests by the end of May 2010. While we cannot predict the ultimate outcome of the SECA proceedings, we do not believe the outcome of the proceedings will have a material effect on UE’s, CIPS’, CILCO’s and IP’s costs and revenues.

FERC Order – MISO Charges

In May 2007, UE, CIPS, CILCO and IP filed with the U.S. Court of Appeals for the District of Columbia Circuit an appeal of FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the appeal in abeyance until the end of the continuing proceedings at FERC regarding these costs. Other MISO participants also filed appeals. On August 10, 2007, UE, CIPS, CILCO, and IP filed a complaint with FERC regarding the MISO tariff’s allocation methodology for these same MISO operational charges. In November 2007, FERC issued two orders relative to these allocation matters. One of these orders addressed requests for rehearing of prior orders in the proceedings, and one concerned MISO’s compliance with FERC’s orders to date in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s clarification or rehearing of its November 2007 order regarding MISO’s compliance with FERC’s orders. UE, CIPS, CILCO and IP maintained that MISO was required to reallocate certain of MISO’s operational costs among MISO market participants, which would result in refunds to UE, CIPS, CILCO and IP retroactive to April 2006. On November 7, 2008, FERC issued an order granting the request for clarification. FERC directed MISO to reallocate certain MISO operational costs among MISO participants and provide refunds for the period April 2006 to August 2007 (“November 7, 2008 Clarification Order”). On November 10, 2008, FERC granted further relief requested in the complaints filed by UE, CIPS, CILCO, IP and others regarding further reallocation for these MISO operational charges and directed MISO to calculate refunds for the period from August 10, 2007, forward (“November 10, 2008 Complaint Order”).

Several parties to these proceedings protested MISO’s proposed implementation of these refunds, requested rehearing of FERC’s orders and, in some cases, appealed FERC’s orders to the courts. In March 2009, MISO began resettling its markets to provide refunds as FERC directed retroactive from August 10, 2007. In May 2009, FERC issued an order that upheld most of the conclusions of the November 10, 2008 Complaint Order but changed the effective date for refunds such that certain operational costs will be allocated among MISO market participants beginning November 10, 2008, instead of August 10, 2007. In June 2009, UE, CIPS, CILCO and IP filed for rehearing of the May 2009 order regarding the change to the refund effective date. This rehearing request is pending.

With respect to the November 7, 2008 Clarification Order, in June 2009 FERC issued an order dismissing rehearing requests of such clarification order and waiving refunds of amounts billed that were included in the MISO charge, under the assumption that there was a rate mismatch for the period April 25, 2006, through November 4, 2007. UE, CIPS, CILCO and IP filed a request for rehearing in July 2009. This rehearing request is pending.

With respect to the two rehearing requests discussed above, UE, CIPS, CILCO and IP do not believe that the ultimate resolution of either request will have a material effect on their results of operations, financial position, or liquidity.

MISO and PJM Dispute Resolution

During 2009, MISO and PJM discovered an error in the calculation quantifying certain transactions between the RTOs. The error, which originated in April 2005, at the initiation of the MISO Energy and Operating Reserves Market was corrected prospectively in June 2009. Since discovering the error, MISO and PJM have worked jointly to estimate its financial impact on the respective markets. MISO and PJM are in agreement about the methodology used to recalculate the market flows occurring from June 2007 to June 2009 for the resettlement due from PJM to MISO estimated at $65 million. MISO and PJM are not in agreement about the methodology used to recalculate the market flows occurring from April 2005 to May 2007, nor are they in agreement about the resettlement amount. To resolve this issue, MISO and PJM have agreed to participate in FERC’s dispute resolution and settlement process in order to determine a resettlement amount for the entire period from April 2005 to June 2009. In October 2009, an administrative law judge was appointed as mediator, and multiple settlement conferences were held at FERC in late 2009 and early 2010. A final settlement between MISO and PJM, if and when reached, will probably require filings to be made by PJM and MISO with FERC. Ameren and its subsidiaries may receive a to-be-determined portion of the resettlement amount due from PJM to MISO. No prospective refund has been recorded related to this matter. Until a settlement has been reached and approved by FERC, we cannot predict the ultimate impact of these proceedings on Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.

UE Power Purchase Agreement with Entergy Arkansas, Inc.

In July 2007, FERC issued a series of orders addressing a complaint filed by the Louisiana Public Service Commission (LPSC) against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates. The complaint alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing UE for additional charges under a 165-megawatt power purchase agreement, and UE paid these charges. Additional charges continued during the remainder of the term of the power purchase agreement, which expired on August 31, 2009. Although UE was not a party to the FERC proceedings that gave rise to these additional charges, UE has intervened in related FERC proceedings. UE also filed a complaint with FERC against Entergy and Entergy Services, Inc. in April 2008 to challenge the additional charges. In September 2008, the presiding FERC administrative law judge issued an initial decision finding that Entergy’s allocation of such additional charges to UE was just and reasonable. In January 2010, FERC issued an opinion reversing the administrative law judge’s initial decision and ruling that Entergy may not pass additional charges to UE. In February 2010, Entergy filed a request for rehearing of the January 2010 opinion. UE has recorded the additional charges related to the July 2007 order, but has not recorded any prospective refund. UE is unable to predict how or when the FERC will rule on the motions. Therefore, UE is unable to predict whether FERC ultimately will order Entergy to refund to UE the additional charges.

 

Additionally, LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy Services, Inc. to the U.S. Court of Appeals for the District of Columbia. In April 2008, that court ordered further FERC proceedings regarding the LPSC complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the retroactive impact of these issues could have a financial impact on UE. UE is unable to predict how FERC will respond to the court’s decisions. UE estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005, although FERC’s ruling in January 2010, discussed above, assuming it is upheld after any rehearings or appeals, likely will prevent FERC from ordering UE to pay any amounts retroactively. Based on existing facts and circumstances, UE believes that the likelihood of incurring this $25 million expense is not probable. Thus no liability has been recorded as of December 31, 2009. UE plans to participate in any proceeding that FERC initiates to address the court’s decisions.

Nuclear Combined Construction and Operating License Application

In July 2008, UE filed an application with the NRC for a combined construction and operating license for a new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. UE also signed contracts for COLA-related services and certain long lead-time nuclear-unit related equipment (heavy forgings).

In early 2009, the Missouri Clean and Renewable Energy Construction Act was separately introduced in both the Missouri Senate and House of Representatives. One purpose of these bills was to allow the MoPSC to authorize utilities to recover the costs of financing and tax payments associated with a new generating plant while that plant is being constructed. Recovery of actual construction costs still would not begin until a plant goes into service. UE believes legislation allowing timely recovery of financing costs during construction must be enacted in order for it to build a new nuclear unit to meet its baseload generation capacity needs. However, passage of this or other legislation was not a commitment or guarantee that UE would build a new nuclear unit.

In April 2009, senior management of UE announced that they had asked the legislative sponsors of the Missouri Clean and Renewable Energy Construction Act to withdraw the bills from consideration by the Missouri General Assembly. UE believed that the legislation being considered in the Missouri Senate in its then proposed form would not provide UE with the financial and regulatory certainty it needed to pursue the project. As a result, UE announced that it was suspending its efforts to build a new nuclear unit at its existing Missouri nuclear plant site. In June 2009, UE requested the NRC suspend review of the COLA and all activities related to the COLA. The contract for COLA-related services was amended in December 2009 in several respects, including changes to the termination provisions in light of UE’s decision to suspend its efforts to build a new nuclear unit. UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE will file with the MoPSC in 2011.

As of December 31, 2009, UE had capitalized approximately $69 million as construction work in progress related to the COLA. The incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned or management concludes it is probable the cost incurred will be disallowed in rates, it is possible that a charge to earnings could be recognized in a future period.

Prior to June 30, 2009, UE made contractual payments to the heavy forgings manufacturer of $14 million and had remaining contractual commitments of $81 million. In July 2009, when an agreement was reached with the heavy forgings manufacturer to terminate the heavy forgings procurement agreement, $5 million in previous payments was retained by the manufacturer as a penalty for terminating the contract. That amount was charged to earnings in June 2009.

Pumped-storage Hydroelectric Facility Relicensing

In June 2008, UE filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The current FERC license expires on June 30, 2010. Approval and relicensure are expected in 2012. Operations are permitted to continue under the current license while the application for relicensing is pending.

 

Regulatory Assets and Liabilities

In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, UE, CIPS, CILCO and IP defer certain costs pursuant to actions of regulators or based on the expected ability to recover such costs in rates charged to customers. UE, CIPS, CILCO and IP also defer certain amounts pursuant to actions of regulators or based on the expectation that such amounts will be returned to customers in future rates. The following table presents our regulatory assets and regulatory liabilities at December 31, 2009 and 2008:

 

		Ameren(a)			UE			CIPS			CILCO			IP
2009:
Current regulatory assets:
Under-recovered FAC(b)(c)		$	39		$	39		$	-		$	-		$	-
Under-recovered Illinois electric power costs(b)(d)			5			-			2			2			1
Under-recovered PGA(b)(d)			4			-			4			-			-
MTM derivative assets(e)			62			24			53			27			85
Total current regulatory assets(f)		$	110		$	63		$	59		$	29		$	86
Noncurrent regulatory assets:
Pension and postretirement benefit costs(g)		$	659		$	288		$	75		$	93		$	203
Income taxes(h)			280			272			5			1			2
Asset retirement obligation(i)			36			31			2			1			2
Callaway costs(b)(j)			55			55			-			-			-
Unamortized loss on reacquired debt(b)(k)			56			26			5			5			20
Recoverable costs – contaminated facilities(l)			150			-			47			-			103
IP integration(m)			17			-			-			-			17
Recoverable costs – debt fair value adjustment(n)			6			-			-			-			6
MTM derivatives assets(o)			49			10			103			57			164
SO2 emission allowances sale tracker(p)			16			16			-			-			-
FERC-ordered MISO resettlements – March 2007(q)			7			7			-			-			-
Vegetation management and infrastructure inspection(r)			7			7			-			-			-
Storm costs(s)			27			27			-			-			-
Demand-side costs(t)			15			15			-			-			-
Reserve for workers’ compensation liabilities(u)			15			9			3			-			3
Bad debt rider(v)			30			-			7			4			19
Other(w)			5			2			1			1			1
Total noncurrent regulatory assets		$	1,430		$	765		$	248		$	162		$	540
Current regulatory liabilities:
Over-recovered FAC(x)		$	10		$	10		$	-		$	-		$	-
Over-recovered Illinois electric power costs(d)			44			-			7			17			20
Over-recovered PGA(d)			13			4			2			4			3
MTM derivative liabilities(y)			15			11			1			2			1
Total current regulatory liabilities(z)		$	82		$	25		$	10		$	23		$	24
Noncurrent regulatory liabilities:
Income taxes(aa)		$	160		$	141		$	10		$	9		$	-
Removal costs(bb)			1,084			716			231			199			86
Emission allowances(cc)			35			35			-			-			-
Vegetation management and infrastructure inspection(dd)			2			2			-			-			-
MTM derivative liabilities(ee)			14			12			-			1			1
Bad debt rider(ff)			2			-			1			-			1
Pension and postretirement benefit costs tracker(gg)			41			41			-			-			-
Total noncurrent regulatory liabilities		$	1,338		$	947		$	242		$	209		$	88
2008:
Current regulatory assets:
Under-recovered Illinois electric power costs(b)(d)		$	2		$	-		$	1		$	-		$	1
Under-recovered PGA(b)(d)			1			-			1			-			-
MTM derivative assets(e)			79			10			30			24			57
Total current regulatory assets(f)		$	82		$	10		$	32		$	24		$	58
Noncurrent regulatory assets:
Pension and postretirement benefit costs(g)		$	936		$	410		$	107		$	125		$	294
Income taxes(h)			255			248			6			-			1
Asset retirement obligation(i)			65			60			2			1			2
Callaway costs(b)(j)			58			58			-			-			-
Unamortized loss on reacquired debt(b)(k)			63			30			5			5			23
Recoverable costs – contaminated facilities(l)			97			-			18			8			71
IP integration(m)			33			-			-			-			33
Recoverable costs – debt fair value adjustment(n)			10			-			-			-			10
MTM derivative assets(o)			39			6			52			30			78
SO2 emission allowances sale tracker(p)			13			13			-			-			-
FERC-ordered MISO resettlements - March 2007(q)			12			12			-			-			-
Vegetation management and infrastructure inspection(r)			9			9			-			-			-
Storm costs(s)			33			33			-			-			-
Demand-side costs(t)			4			4			-			-			-
Reserve for workers’ compensation liabilities(u)			15			9			3			-			3
Other(w)			11			5			2			2			2
Total noncurrent regulatory assets		$	1,653		$	897		$	195		$	171		$	517
Current regulatory liabilities:
Over-recovered Illinois electric power costs(d)		$	22		$	-		$	6		$	10		$	6
Over-recovered PGA(d)			42			2			14			9			17
Total current regulatory liabilities(z)		$	64		$	2		$	20		$	19		$	23
Noncurrent regulatory liabilities:
Income taxes(aa)		$	180		$	154		$	14		$	12		$	-
Removal costs(bb)			1,018			675			220			194			76
Emission allowances(cc)			47			47			-			-			-
Pension and postretirement benefit costs tracker(gg)			41			41			-			-			-
MISO resettlements(hh)			5			5			-			-			-
Total noncurrent regulatory liabilities		$	1,291		$	922		$	234		$	206		$	76

 

(a)	Includes intercompany eliminations.

(b)	These assets earn a return.

(c)	Under-recovered fuel costs for the accumulation periods from June 2009 through September 2009 and October 2009 through December 2009. Recovery of the earlier accumulation period will begin in February 2010 while the recovery of the later accumulation period will begin in June 2010.

(d)	Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.

(e)	Current portion of deferral of commodity-related derivative MTM losses, as well as the current portion of the MTM losses on financial contracts entered into by the Ameren Illinois Utilities with Marketing Company. See Illinois – Power Procurement Plan discussion above for additional information.

(f)	Included in Current Regulatory Assets on the balance sheet of UE, CIPS, CILCO and IP and in Other Current Assets on the balance sheet of Ameren.

(g)	These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets), and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 11 – Retirement Benefits for additional information.

(h)	Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 – Income Taxes for amortization period.

 

(i)	Recoverable costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.

(j)

UE’s Callaway nuclear plant operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant’s current operating license through 2024.

(k)	Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.

(l)

The recoverable portion of accrued environmental site liabilities, primarily collected from electric and natural gas customers through ICC-approved cost recovery riders in Illinois. The period of recovery will depend on the timing of actual expenditures. See Note 15 – Commitments and Contingencies for additional information.

(m)	Reorganization costs related to the integration and restructuring of IP into the Ameren system. Pursuant to the ICC order approving Ameren’s acquisition of IP, these costs are recoverable in rates through 2010.

(n)	A portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP. This portion is being amortized over the remaining life of the related debt, beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007.

(o)	Deferral of commodity-related derivative MTM losses, as well as the MTM losses on financial contracts entered into by the Ameren Illinois Utilities with Marketing Company. See Illinois – Power Procurement Plan discussion above for additional information.

(p)

A regulatory tracking mechanism for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2 discounts received under such contracts, as approved in a MoPSC order. In its pending rate case, UE requested the discontinuation of this tracker.

(q)

Costs associated with a March 2007 FERC order that resettled costs among MISO market participants. The costs were previously charged to expense but were recorded as a regulatory asset. They will be amortized over a two-year period beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order.

(r)

A regulatory tracking mechanism for the difference between the level of vegetation management and infrastructure inspection costs incurred by UE and the level of such costs built into electric rates. UE’s vegetation management and infrastructure inspection costs from January 1, 2008, through February 28, 2009, exceeded the amount allowed in base rates. The excess costs incurred between January 1, 2008, through September 30, 2008, are being amortized over three years, beginning on March 1, 2009, as approved by the January 2009 MoPSC electric rate order. The amortization period for the excess costs incurred from October 1, 2008, through February 28, 2009, will be determined in UE’s pending electric rate case.

(s)

Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. The 2006 storm costs are being amortized over five years, beginning on June 4, 2007. The 2008 storm costs are being amortized over five years, beginning on March 1, 2009. In addition, the balance includes January 2007 ice storm costs that UE will recover as a result of a MoPSC accounting order issued in April 2008. These costs will be amortized over five years, beginning on March 1, 2009, as approved by the January 2009 MoPSC electric rate order.

(t)	Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. These costs are being amortized over ten years, beginning on March 1, 2009, as approved by the January 2009 MoPSC electric rate order.

(u)	Reserve for workers’ compensation claims.

(v)

A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by the Ameren Illinois Utilities and the level of such costs built into electric and natural gas rates. The under-recovery relating to 2008 will be recovered from customers from March 2010 through December 2010. The under-recovery relating to 2009 will be recovered from customers from June 2010 through May 2011.

(w)

Includes costs related to the Ameren Illinois Utilities’ November 2007 electric and natural gas delivery service rate cases. The costs associated with the Ameren Illinois Utilities’ electric delivery service rate cases are being amortized over a three-year period; the costs associated with the Ameren Illinois Utilities’ natural gas delivery service rate cases are being amortized over a five-year period, as approved in the 2008 ICC rate order. In addition, the balance includes funding for low-income weatherization and other miscellaneous items.

(x)	Over-recovered fuel costs for the accumulation period from March 2009 through May 2009. Customer refunds began in October 2009 and will continue through September 2010.

(y)	Current portion of deferral of commodity-related derivative MTM gains.

(z)	Included in Current Regulatory Liabilities on the balance sheet of IP and in Other Current Liabilities on the balance sheets of Ameren, UE, CIPS and CILCO.

(aa)	Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 – Income Taxes for amortization period.

(bb)	Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated operations. See discussion in Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.

(cc)	The deferral of gains on emission allowance vintage swaps UE entered into during 2005. This gain will be amortized through February 2011.

(dd)

A regulatory tracking mechanism for the difference between the level of vegetation management and infrastructure inspection costs incurred by UE and the level of such costs built into electric rates. This over-recovery relates to the period March 1, 2009, through December 31, 2009. The amortization period for this over-recovery will be determined in a future UE electric rate case.

(ee)	Deferral of commodity-related derivative MTM gains.

(ff)	A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by the Ameren Illinois Utilities and the level of such costs built into electric and natural gas rates. The over-recovery relating to 2009 will be refunded to customers June 2010 through May 2011.

(gg)	A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by UE under GAAP and the level of such costs built into electric rates effective June 4, 2007, as approved in a MoPSC order.

(hh)	A portion of UE’s expected refund relating to MISO resettlements associated with the November 2008 FERC orders. See Federal – FERC Order – MISO Charges discussion above for additional information.

UE, CIPS, CILCO and IP continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatory assets are written off to earnings when it is no longer probable that such amounts will be recovered through future revenues. To the extent that payments of regulatory liabilities are no longer probable, the amounts are credited to earnings.