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, which does business as Ameren Missouri, 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 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 127,000 customers.

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AIC, or Ameren Illinois Company, which does business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. AIC was created by the merger of CILCO and IP with and into CIPS. CIPS was incorporated in Illinois in 1923 and is successor to a number of companies, the oldest of which was organized in 1902. AIC supplies electric and natural gas utility service to portions of central and southern Illinois having an estimated population of 3 million in an area of 40,000 square miles. AIC supplies electric service to 1.2 million customers and natural gas service to 811,000 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, natural gas and oil-fired electric generating facilities, are expected to have capacity of 3,437, 1,553, and 169 megawatts, respectively, at the time of the 2011 peak summer electrical demand.

 

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 and AIC defer certain costs as assets pursuant to actions of rate regulators or the expected ability to recover such costs in rates charged to customers. UE and AIC also defer certain amounts as liabilities pursuant to actions of rate 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. In addition, other costs that UE and AIC expect to recover from customers are also recorded as construction work in progress and property and plant, net. See Note 3 – Property and Plant, Net.

 

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, 2010 and 2009:

 

 

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 2010, 2009 and 2008:

 

		2010				2009				2008
Ameren			8% - 9%				6% - 9%				3% - 7%
UE			8				6				7
AIC			9				9				3

 

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. As of December 31, 2010, Ameren's and AIC's goodwill related to its acquisition of IP in 2004 and its acquisition of CILCORP in 2003.

We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Ameren and Genco conducted an interim goodwill impairment test in the third quarter of 2010. That test resulted in the elimination of all goodwill associated with the Merchant Generation segment at Ameren ($420 million) and Genco ($65 million). This goodwill was associated with the acquisition of CILCORP and Medina Valley in 2003 and an additional 20% interest in EEI in 2004. See Note 17 –Goodwill and Other Asset Impairments for additional information.

Intangible Assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren's, UE's and Genco's intangible assets at December 31, 2010, and 2009, consisted of emission allowances. During 2010, Ameren and Genco recorded a noncash pretax impairment charge relating to SO₂ emission allowances of $68 million and $41 million, respectively. UE recorded a $23 million impairment of its SO₂ emission allowances by reducing a previously established regulatory liability related to the SO₂ emission allowances, which had no impact to earnings. See Note 17 – Goodwill and Other Asset Impairments for additional information about the asset impairment charges recorded during 2010. 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 recorded as intangible assets at December 31, 2010. 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.

 

 

The following table presents amortization expense recorded in connection with the use of emission allowances, net of gains and losses from emission allowance sales, for Ameren, UE and Genco during the years ended December 31, 2010, 2009, and 2008. The table below does not include the intangible asset impairment charges referenced above.

 

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. 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.

 

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. See Note 2 – Rate and Regulatory Matters for the regulatory assets and liabilities recorded at December 31, 2010, and 2009, related to the rate-adjustment mechanisms discussed below.

In UE's and AIC'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 as regulatory assets or liabilities. The deferred amounts are either billed or refunded to natural gas utility customers in a subsequent period.

In AIC's 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 as regulatory assets or liabilities. The deferred amounts are either billed or refunded to electric utility customers in a subsequent period.

UE has an FAC that 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 differences between the cost of fuel incurred and the cost of fuel recovered from UE's customers are deferred as regulatory assets or liabilities. 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 and AIC 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 and AIC recognize expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated.

 

Accounting Changes and Other Matters

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

Variable-Interest Entities

In June 2009, the FASB issued amended authoritative guidance that significantly changes the consolidation rules for VIEs. The guidance requires an enterprise to qualitatively assess the determination of the primary beneficiary of a VIE and 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 as of January 1, 2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which was effective for us as of January 1, 2011. The adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provides enhanced disclosure requirements only. See Note 8 – Fair Value Measurements for additional information.

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 and Genco 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 and AIC 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 2010 and 2009:

 

 

Genco Asset Sale

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

Employee Separation and Other Charges

In 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, AIC and Genco. Additionally, in 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, AIC – $3 million, Genco – $5 million) for the severance costs related to both the voluntary and involuntary separation programs as well as for Merchant Generation staff reductions announced in 2009. These charges were recorded in other operations and maintenance expense in the applicable statements of income. Substantially this entire 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.

In 2010, Ameren's Merchant Generation segment initiated additional involuntary separation programs to reduce additional positions under the terms and benefits consistent with Ameren's standard separation program. Ameren and Genco recorded a pretax charge to earnings of $4 million in 2010 for the severance costs related to 2010 involuntary separation programs. These charges were recorded in other operations and maintenance expense on Ameren's and Genco's statement of income and approximately $2 million was accrued in other current liabilities on Ameren's and Genco's balance sheet at December 31, 2010.

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.

In September 2010, UE filed an appeal with the Missouri Court of Appeals for the Southern District of Missouri. The Court of Appeals will conduct an independent review of the MoPSC's order. UE believes the Stoddard Circuit Court's judgment, which reversed parts of the MoPSC decision, will be found erroneous by the Court of Appeals; however, there can be no assurances that UE's appeal will be successful. If UE prevails on all issues of its appeal, UE will receive all of the funds held in the Stoddard Circuit Court's registry, plus accrued interest. If UE were to conclude that some portion of the funds held in the Stoddard Circuit Court's registry becomes probable of refund to Noranda, a charge to earnings would be recorded for the estimated amount of refund in the period in which that decision is made. A decision by the Court of Appeals is not expected until at least the third quarter of 2011.

See the 2010 Electric Rate Order section below for information about four industrial customers, one of which is Noranda, who have filed an appeal with the Cole County Circuit Court and also were granted a stay for their rate increases granted by the MoPSC's 2009 electric rate order as they specifically apply to each of their electric service accounts.

2010 Electric Rate Order

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

 

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Approval of the continued use of UE's existing FAC at the current 95% sharing level.

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Approval of the continued use of UE's existing vegetation management and infrastructure cost tracker.

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Approval of an increase in UE's annual depreciation rate due largely to the adoption of the life span depreciation methodology for its non-nuclear power plants.

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Denial of UE's request to implement a storm restoration cost tracker.

 

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

In June 2010, UE and other parties to the rate case filed for rehearing of certain aspects of the MoPSC order. The MoPSC denied all rate order rehearing requests filed by UE and other parties. UE appealed the return on equity included in the MoPSC order to the Circuit Court of Cole County, Missouri (Circuit Court). UE subsequently withdrew its appeal as the outcome of the pending electric rate case would supersede the result of this appeal. A group of industrial customers also appealed certain aspects of the MoPSC order to the Circuit Court. A decision is expected to be issued on the industrial customers' appeal by the Circuit Court in 2011.

On February 16, 2011, the Missouri Office of Public Counsel (MoOPC) made a filing with the MoPSC in which the MoOPC argued that the December 20, 2010 Order Granting Stay Pursuant to Section 386.520 (Stay Order), discussed below, of the Circuit Court should apply to all UE customers rather than to just the four UE industrial customers that requested the Circuit Court to grant these industrial customers' request to stay the MoPSC's 2010 Missouri electric rate order as to their billings. On that basis, the MoOPC requested the MoPSC to suspend UE's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with UE's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. If the requested suspension occurs, it would continue until the earlier of the time that a subsequent order is issued by the MoPSC, or an order reversing any such suspension is issued by a court of competent jurisdiction, but in no event beyond the implementation of new electric rates for UE. It is anticipated that new electric rates for UE will take effect by early August 2011, pursuant to an anticipated MoPSC rate order in UE's currently pending electric rate proceeding. If the currently effective 2010 rate schedules are suspended for all customers such that UE is only able to charge customers under its previously effective rate schedules for service provided for the period March through August 2011, the reduced charges, which would reflect the difference between billings under the 2010 Missouri electric rate order and billings under the 2009 Missouri electric rate order, are estimated at approximately $100 million and would result in corresponding reductions in pretax earnings and cash flows.

Also on February 16, 2011, the Missouri Industrial Energy Consumers (MIEC), of which the four UE industrial customers referred to above are members, made a filing with the MoPSC in response to the MoOPC filing discussed above. In its filing, MIEC supported the position set forth in the MoOPC filing that the Stay Order should apply to all UE customers, except that MIEC requested the MoPSC to suspend UE's currently effective rate schedules, including its FAC, and replace them with UE's rate schedules approved by the MoPSC in its 2007 electric rate order. If the requested suspension occurs, it would continue until the earlier of the time that a subsequent order is issued by the MoPSC, or an order reversing any such suspension is issued by a court of competent jurisdiction, but in no event beyond the implementation of new electric rates for UE. As noted, it is anticipated that new electric rates for UE will take effect by early August 2011. If the currently effective 2010 rate schedules (including the FAC) are suspended for all customers such that UE is only able to charge customers under its previously effective rate schedules for service provided for the period March through August 2011, the reduced charges, which would reflect the difference between billings under the 2010 Missouri electric rate order and billings under the 2007 Missouri electric rate order, including FAC billings, are estimated at approximately $300 million and would result in corresponding reductions in pre-tax earnings and cash flows.

The filings by the MoOPC and MIEC relate to the December 20, 2010 Stay Order, in which the Circuit Court granted the request of four UE industrial customers to stay the MoPSC's 2010 Missouri electric rate order and to require those customers to pay into the Circuit Court's registry the difference between their billings under the 2010 Missouri electric rate order and their billings under a Missouri electric rate order that became effective in June 2007, the last UE rate order for which appeals have been exhausted. On February 15, 2011, the four UE industrial customers posted the bond required by the Stay Order and are expected to begin making the required payments into the Circuit Court's registry.

The Stay Order does not address the merits of the appeals of the MoPSC's 2010 electric rate order or the 2009 electric rate order, which will be addressed in the ordinary course of the judicial review process. The judicial review process typically takes 18 to 24 months to complete following the initiation of the process. At this time, UE does not believe any aspect of the 2009 and 2010 electric rate increases authorized by the 2009 and 2010 Missouri electric rate orders are probable of refund to UE's customers. If UE were to conclude that some portion of these rate increases become probable of refund to UE's customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that decision was made.

UE disagrees with the Stay Order, as well as the related filings made by the MoOPC and MIEC with the MoPSC. With respect to further proceedings regarding the Stay Order, the pending review proceedings regarding the 2009 and 2010 Missouri electric rate orders and the MoOPC's and MIEC's filings with the MoPSC, UE will continue to address the merits of those orders and filings through the judicial and regulatory review processes.

There could be other material negative effects on UE and Ameren beyond those discussed above, which cannot be determined at this time. We cannot predict the ultimate outcome of these proceedings, which could have a material effect on UE's and Ameren's results of operations, cash flows and financial position.

Pending Electric Rate Case

On September 3, 2010, UE filed a request with the MoPSC to increase its annual revenues for electric service by approximately $263 million. This increase request was based primarily on energy infrastructure investments, costs incurred to implement environmental controls and other costs incurred to continue systemwide reliability improvements for customers. Of that request, approximately $110 million relates to recovery of the cost of installing and operating two scrubbers at UE's Sioux plant. Also included in this requested increase is a $73 million anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. Absent initiation of this general rate proceeding, 95% of this amount would have been reflected in rate adjustments implemented under UE's FAC. Capital additions relating to enhancements at the rebuilt Taum Sauk facility were also included in the increase request. The electric rate increase request is based on a 10.9% return on equity, a capital structure composed of 50.9% common equity, an aggregate electric rate base of $6.8 billion, and a test year ended March 31, 2010, with certain pro-forma adjustments through the anticipated true-up date of February 28, 2011.

 

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

In February 2011, the MoPSC staff responded to the UE request for an electric service rate increase. The MoPSC staff recommended an increase to UE's annual revenues of between $45 million and $99 million based on a return on equity of 8.25% to 9.25%. Included in this recommendation was approximately $50 million of increases in normalized net fuel costs and $32 million of asset disallowances relating to the Sioux plant scrubbers. Other parties also made recommendations through testimony filed in this case.

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

2011 Natural Gas Delivery Service Rate Order

In January 2011, the MoPSC approved a stipulation and agreement that resolved a June 2010 request by UE to increase annual natural gas revenues. The stipulation and agreement provided for an increase in annual natural gas delivery revenues of $9 million, which included approximately $2 million of annual revenues previously collected through the ISRS rider for the test year ended December 31, 2009. The new rates became effective on February 20, 2011. The stipulation and agreement approved a revised block-rate structure for residential customers that results in more certainty of margin revenue recovery regardless of weather conditions or conservation efforts, as recovery is less dependent on usage. The new residential structure is expected to allow UE to recover approximately half of its natural gas non-PGA residential revenues through a fixed monthly charge, with the remaining amount to be recovered based on sales.

 

As part of the stipulation and agreement, UE will not file a separate natural gas rate increase request before December 31, 2012. However, UE can file a combined natural gas and electric rate case before that date. Further, this agreement does not prevent UE from filing to recover infrastructure replacement costs through an ISRS during this moratorium. The return on equity to be used by UE for purposes of an ISRS tariff filing is 10%.

FAC Prudence Review

Missouri law requires the MoPSC to complete prudence reviews of UE's FAC at least every 18 months. In August 2010, the MoPSC staff completed a prudence review of the FAC from March 1, 2009, to September 30, 2009. The MoPSC staff contends that UE should have included in the FAC calculation all costs and revenues associated with certain contract sales that were made due to the loss of Noranda load caused by a severe ice storm in January 2009. UE disagrees with the MoPSC staff's classification of these transactions and opposes their inclusion in the FAC calculation. UE recognized margin associated with these contracts of $17 million during the period reviewed by the MoPSC and an additional $25 million of margin subsequent to September 30, 2009. If the MoPSC were to agree with the staff position, and if the MoPSC's order were to be upheld by the courts on appeal, UE would be required to pass through to customers the $42 million in margin associated with these contracts and record a charge to earnings. The MoPSC is expected to issue an order with respect to this prudence review in 2011. If UE were to conclude that some portion of these contested FAC amounts become probable of refund to UE's customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that decision is made. UE cannot predict the outcome of this MoPSC prudence review.

Renewable Energy Portfolio Requirement

A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate from renewable energy sources electricity 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 generation, the procurement of renewable energy, or the procurement of renewable energy credits. UE expects that any related costs or investments would ultimately be recovered in rates.

In July 2010, the MoPSC issued final rules implementing the state's renewable energy portfolio requirement. In addition to other concerns, UE objected to the MoPSC rules creating geographical restrictions as well as the calculation of the 1% limit on customer rates. In February 2011, the Missouri legislature rejected the contested portion of the MoPSC rules creating geographical restrictions. This legislative action allows UE to comply with the law through its own generation or the procurement of renewable energy or renewable energy credits from sources regardless of geographical location. In August 2010, UE filed an appeal with the Circuit Court of Cole County, Missouri. UE is appealing the portion of the MoPSC rules calculating the 1% limit on customer rates. UE cannot predict when the court will issue a ruling or the ultimate outcome of the appeal.

Illinois

2010 Electric and Natural Gas Delivery Service Rate Order

In April 2010, the ICC issued a rate order for AIC, which was amended in May 2010, that approved a net increase in annual revenues for electric delivery service of $35 million and a net decrease in annual revenues for natural gas delivery service of $20 million. The rate changes became effective in May 2010. In response to the ICC rate order, AIC took steps to reduce expenditures to align its spending with the revenues allowed in the amended rate order.

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

The ICC order also extended the amortization period of the integration-related regulatory asset for Ameren's acquisition of IP, which was previously set to be fully amortized by December 2010. The new order extended the amortization for two years beginning in May 2010. The ICC order also created a $3 million regulatory asset for AIC's costs incurred in 2009 for its voluntary and involuntary separation programs. These costs are being amortized over three years, beginning May 2010.

AIC and certain intervenors were granted a rehearing with the ICC. In November 2010, the ICC approved an order on the rehearing issues, which authorized an increase in annual revenues of $25 million, in addition to the net $15 million increase authorized in the ICC's May 2010 amended rate order. The overall annual delivery service revenue increase as a result of these orders is $40 million. The rate changes relating to the rehearing issues became effective on November 19, 2010.

In December 2010, AIC and an intervenor appealed portions of the ICC's orders to the Appellate Court of the Fourth District of Illinois. A decision by the Appellate Court is expected in 2011.

Pending Electric and Natural Gas Delivery Service Rate Cases

AIC filed a request with the ICC in February 2011 to increase its annual revenues for electric delivery service by $60 million. The electric rate increase request is based on an 11.25% return on equity, a capital structure composed of 53% equity, and a rate base of $2 billion.

AIC also filed a request with the ICC in February 2011 to increase its annual revenues for natural gas delivery service by $51 million. The natural gas rate increase request is based on an 11.0% return on equity, a capital structure composed of 53% equity, and a rate base of $978 million.

In an attempt to limit regulatory lag, AIC is also using a future test year, 2012, in each of these rate requests. Additionally, AIC is requesting a rider mechanism for its pension costs. This requested rider mechanism would allow AIC to recover or refund any difference between pension expense incurred and the amount allowed in rates annually, subject to an annual reconciliation.

A decision by the ICC in these proceedings is required by January 2012. AIC 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 AIC to recover its costs and earn a reasonable return on its 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 AIC. Pursuant to the 2007 Illinois Electric Settlement Agreement, AIC, Genco and AERG made aggregate contributions of $150 million over the four-year period, with $60 million coming from AIC, $62 million from Genco, and $28 million from AERG. As of December 31, 2010, AIC, Genco and AERG had no obligations remaining under the 2007 Illinois Electric Settlement Agreement.

Ameren, AIC and Genco recognized 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, AIC and Genco, incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the year ended December 31, 2010, of $3 million, $1 million, and $1 million, respectively (year ended December 31, 2009 – $25 million, $10 million, and $10 million, respectively) under the terms of the 2007 Illinois Electric Settlement Agreement. Other electric generators and utilities in Illinois contributed $851 million to the comprehensive rate relief and customer assistance program.

 

ICC Reliability Audit

In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on AIC's 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 AIC to improve its systems and response to emergencies. In November 2008, AIC presented to the ICC a plan to implement Liberty Consulting Group's recommendations.

AIC has committed to and is implementing various recommendations contained in Liberty Consulting Group's report, as outlined in its November 2008 plan. However, in order to fulfill that commitment in a timely manner, AIC must be able to align the timing of its distribution-implementation expenditures with the recognition of those costs in rates. Without the necessary funding or a rider mechanism to recover the distribution costs, AIC may defer some of the projects until the distribution costs can be recovered either in base rates or through some other cost recovery mechanism. The recovery of costs not already approved as part of the 2010 rate order will be sought in future rate proceedings, including the 2011 pending rate case described above.

Federal

Electric Transmission Investment

In 2006, Ameren formed a wholly owned subsidiary, Ameren Illinois Transmission Company, to construct and operate electric transmission assets in Illinois. In 2010, that subsidiary was renamed as ATXI. In December 2010, ATXI received MISO approval to become a transmission owner. In January 2011, ATXI received FERC approval for rate recovery of the transmission line it constructed and placed in service in 2010. Based on preliminary transmission rate calculations, ATXI anticipates revenues of approximately $7 million in 2011.

In August 2010, Ameren announced the formation of ATX. In August 2010, Ameren, on behalf of UE, AIC, ATXI and ATX, filed a request with FERC seeking transmission rate incentives for four new transmission projects. These initial projects, subject to regulatory approval, consist of a potential $1.3 billion investment in high voltage transmission projects in Illinois and Missouri. There is no statutory date by which FERC must issue an order in this matter; however, Ameren expects FERC will issue an order in 2011.

Regional Transmission Organization

UE is a transmission owning member of MISO, which is a FERC-regulated RTO that provides transmission tariff administration services for electric transmission systems. UE received authorization from the MoPSC to participate in MISO, subject to certain conditions.

 

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 continued, conditional MISO participation is authorized by the MoPSC through April 30, 2012. The MoPSC order 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. As required by the MoPSC, in November 2010, UE filed another study with the MoPSC updating its evaluation of 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. UE's study concluded that it should remain in MISO through April 30, 2012; however, additional studies should be conducted to determine if UE's participation in MISO should be extended past that date. If UE were to withdraw from MISO, UE might need to obtain FERC approval and to meet conditions imposed by FERC, in addition to obtaining MoPSC approval.

FERC Order – MISO Charges

Complaints were filed with FERC by UE, and AIC as well as other MISO participants with respect to the FERC's March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. Subsequently, FERC has issued a series of orders related to the applicability and the implementation of the order, which in some cases have conflicted with previous orders.

In May 2009, FERC changed the effective date for refunds such that certain operational costs will be allocated among MISO market participants beginning November 2008, instead of August 2007. In June 2009, UE, CIPS, CILCO and IP filed a request for hearing. The rehearing request is pending.

In June 2009, FERC issued an order dismissing rehearing requests of a November 2008 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 2006, through November 2007. UE, CIPS, CILCO and IP filed a request for rehearing in July 2009. This rehearing request is pending.

UE and AIC do not believe that the ultimate resolution of these proceedings will have a material effect on their results of operations, financial position, or liquidity.

MISO and PJM Dispute Resolution

During 2009 and 2010, MISO and PJM discovered errors in the calculations quantifying certain transactions between the RTOs, which both parties alleged had financial impacts on their respective markets. As a result, during 2010 each RTO filed separate complaints with FERC against the other. In January 2011, a settlement agreement was filed with FERC by the two RTOs. Under the agreement, no payment between the RTOs will be required, but financial settlement practices will be modified to ensure greater accuracy for transactions between the RTOs. The January 2011 settlement agreement filed with FERC and the modification of settlement practices will not have a material impact on the Ameren Companies' results of operations, financial position, or liquidity. Ameren is not able to predict if or when FERC will approve the settlement agreement.

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 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 on to UE. In February 2010, Entergy filed a request for rehearing of the January 2010 opinion. UE has not recorded any prospective refund for additional charges paid as a result of the July 2007 order.

The 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. UE believes that the likelihood of incurring any expense is not probable, and therefore no liability has been recorded as of December 31, 2010. UE plans to participate in any proceeding that FERC initiates to address the court's decisions.

COLA and ESP

In 2008, UE filed an application with the NRC for a COLA for a new 1,600-megawatt nuclear unit at UE's existing Callaway County, Missouri, nuclear plant site. In 2009, UE suspended its efforts to build a new nuclear unit at its existing Missouri nuclear plant site, and the NRC suspended review of the COLA.

UE is considering filing an application to obtain an ESP from the NRC at the Callaway nuclear plant site. An ESP approves a specific location for a nuclear facility; however, additional licenses would be required for the specific type and design of nuclear facility to be built at that site. An ESP does not authorize construction of a plant. An ESP is valid for 20 years and potentially could be renewed for up to an additional 20 years. In December 2010 and January 2011, the Missouri Energy Partnership Act was separately introduced in both the Missouri Senate and House of Representatives. The purpose of this legislation is to maintain an option for nuclear power in the state of Missouri, recover the costs of the ESP for a period up to 20 years, and provide appropriate consumer protections.

All of Missouri's major electric utility providers, including cooperatives, municipals, and other investor-owned utilities, are supporting the passage of this legislations. In addition, the governor of Missouri, labor and other key stakeholders are supporting this legislation.

Should the Missouri legislation be enacted into law, UE plans to file an ESP application with the NRC in 2011. NRC approval of an ESP application often takes three to four years.

As of December 31, 2010, UE had capitalized approximately $67 million relating to its efforts to construct a new nuclear unit. All of these 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, a charge to earnings could be recognized in a future period.

Pumped-storage Hydroelectric Facility Relicensing

In June 2008, UE filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The existing FERC license expired on June 30, 2010. On July 2, 2010, UE received a license extension that allows Taum Sauk to continue operations until FERC issues a new license. UE conducted studies using current field data and submitted the study results to multiple state and federal agencies in February 2011. UE anticipates filing the study results with FERC in the spring of 2011. A FERC order is expected after a review of the study results is completed. However, we cannot predict the ultimate outcome of the order.

 

Regulatory Assets and Liabilities

In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, UE and AIC defer certain costs pursuant to actions of regulators or based on the expected ability to recover such costs in rates charged to customers. UE and AIC 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 Ameren's, UE's and AIC's regulatory assets and regulatory liabilities at December 31, 2010 and 2009:

 

		2010																2009
		Ameren(a)				UE				AIC								Ameren(a)				UE				AIC
Current regulatory assets:
Under-recovered FAC(b)(c)		$	158			$	158			$	-							$	39			$	39			$	-
Under-recovered Illinois electric power costs(b)(d)			4				-				4								5				-				5
Under-recovered PGA(b)(d)			2				-				2								4				-				4
MTM derivative assets(e)			103				21				254								62				24				165
Total current regulatory assets		$	267			$	179			$	260							$	110			$	63			$	174
Noncurrent regulatory assets:
Pension and postretirement benefit costs(f)		$	555			$	251			$	304							$	659			$	288			$	371
Income taxes(g)			230				225				5								192				190				2
Asset retirement obligation(h)			9				3				6								36				31				5
Callaway costs(b)(i)			51				51				-								55				55				-
Unamortized loss on reacquired debt(b)(j)			53				25				28								56				26				30
Recoverable costs – contaminated facilities(k)			127				-				127								150				-				150
IP integration(l)			7				-				7								17				-				17
Recoverable costs – debt fair value adjustment(m)			5				-				5								6				-				6
MTM derivative assets(e)			85				14				249								49				10				324
SO2 emission allowances sale tracker(n)			12				12				-								16				16				-
FERC-ordered MISO resettlements – March 2007(o)			3				3				-								7				7				-
Vegetation management and infrastructure inspection(p)			3				3				-								7				7				-
Storm costs(q)			23				23				-								27				27				-
Demand-side costs(r)			39				39				-								15				15				-
Reserve for workers' compensation liabilities(s)			14				8				6								15				9				6
Bad debt rider (t)			2				-				2								30				-				30
Credit facilities fees(u)			12				12				-								-				-				-
Employee separation costs(v)			8				6				2								-				-				-
Common stock issuance costs(w)			12				12				-								-				-				-
Construction accounting for pollution control equipment(b)(x)			4				4				-								-				-				-
Other(y)			5				3				2								5				2				3
Total noncurrent regulatory assets		$	1,259			$	694			$	743							$	1,342			$	683			$	944
Current regulatory liabilities:
Over-recovered FAC(z)		$	-			$	-			$	-							$	10			$	10			$	-
Over-recovered Illinois electric power costs(d)			62				-				62								44				-				44
Over-recovered PGA(d)			12				1				11								13				4				9
MTM derivative liabilities(aa)			25				22				3								15				11				4
Total current regulatory liabilities(bb)		$	99			$	23			$	76							$	82			$	25			$	57
Noncurrent regulatory liabilities:
Income taxes(cc)		$	54			$	48			$	6							$	72			$	59			$	13
Removal costs(dd)			1,177				655				522								1,084				716				367
Emission allowances(ee)			2				2				-								35				35				-
Vegetation management and infrastructure inspection(ff)			3				3				-								2				2				-
MTM derivative liabilities(aa)			20				13				7								14				12				2
Bad debt rider(gg)			5				-				5								2				-				2
Pension and postretirement benefit costs tracker(hh)			45				45				-								41				41				-
Energy efficiency rider(ii)			13				-				13								7				-				7
Total noncurrent regulatory liabilities		$	1,319			$	766			$	553							$	1,257			$	865			$	391

 

(a)	Includes intercompany eliminations.

(b)	These assets earn a return.

(c)	Under-recovered fuel costs for periods from June 2009 through December 2010. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments occur over the following four months, and then recovery from customers occurs over the next 12 months.

(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)	Deferral of commodity-related derivative MTM losses, as well as the MTM losses on financial contracts entered into by AIC with Marketing Company.

(f)	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.

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

(h)	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.

(i)

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.

(j)	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.

(k)

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

(l)	Reorganization costs related to the integration and restructuring of IP into the Ameren system. These costs are recoverable in rates through May 2012.

(m)	A portion of 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.

(n)

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. The MoPSC's May 2010 electric rate order discontinued any future deferrals under this tracking mechanism. The MoPSC's order continued to allow recovery of the previously incurred cost through either February 2011 or June 2012, depending on when the cost was incurred.

(o)	Costs associated with a March 2007 FERC order that resettled costs among MISO market participants. The costs were previously charged to expense but were subsequently reversed and recorded as a regulatory asset. These costs are recoverable in rates through June 2012.

(p)

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 2008 through September 2008 exceeded the amount allowed in base rates. The excess cost incurred during that time period is being amortized over three years, beginning in March 2009. UE's vegetation management and infrastructure inspection costs from March 2010 through June 2010 also exceeded the amount allowed in base rates. The amortization period for these excess costs incurred from March 2010 through June 2010 will be determined in UE's pending electric rate case.

(q)

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 are being amortized over five years, beginning in March 2009, as approved by the January 2009 MoPSC electric rate order. The 2009 storm costs are being amortized over five years, beginning in July 2010, as approved by the May 2010 MoPSC electric rate order.

(r)

Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. Costs incurred from May 2008 through September 2008 are being amortized over ten years, beginning in March 2009. Costs incurred from October 2008 through December 2009 are being amortized over six years, beginning in July 2010. The amortization period for the costs incurred after December 2009 will be determined in UE's pending electric rate case.

(s)	Reserve for workers' compensation claims.

(t)	A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by AIC under GAAP and the level of such costs built into electric and natural gas rates. The under-recovery relating to 2009 will be recovered from customers from June 2010 through May 2011.

(u)

UE's costs incurred to enter into and maintain the 2009 Multiyear Credit Agreements, prior to their termination in 2010. These costs are being amortized over two years, beginning in July 2010, as approved by the May 2010 MoPSC electric rate order. These costs are being amortized to construction work in progress, which will be subsequently depreciated when assets are placed into service.

(v)

Cost incurred for the 2009 voluntary and involuntary separation programs. The UE-related costs are being amortized over three years, beginning in July 2010, as approved by the May 2010 MoPSC electric rate order. The AIC-related costs are being amortized over three years, beginning in May 2010, as approved by the April 2010 ICC electric and natural gas rate order.

(w)	The MoPSC's May 2010 electric rate order allowed UE to recover its portion of Ameren's September 2009 common stock issuance costs. These costs are being amortized over five years, beginning in July 2010.

(x)

The MoPSC's May 2010 electric rate order allowed UE to continue recording an allowance for funds used during construction for pollution control equipment at its Sioux plant until the earlier of January 2012 or when the cost of that equipment is placed in customer rates. The amortization period will be determined in a future electric rate case.

(y)

Includes costs related to AIC's November 2007 electric and natural gas delivery service rate cases. The costs associated with AIC's electric delivery service rate cases are being amortized over a three-year period; the costs associated with AIC's natural gas delivery service rate cases are being amortized over a five-year period, as approved in the 2008 ICC rate order. At UE, the balance includes funding for low-income assistance, weatherization, and other miscellaneous items.

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

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

(bb)	Included in Other Current Liabilities on UE's balance sheet.

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

(dd)	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.

(ee)	The deferral of gains on emission allowance vintage swaps UE entered into during 2005. This gain will be amortized as emission allowances are used.

(ff)

A regulatory tracking mechanism for the difference between the level of vegetation management and infrastructure inspection costs incurred by UE under GAAP and the level of such costs built into electric rates. UE's vegetation management and infrastructure inspection costs from October 2008 through February 2010 were less than the amount allowed in base rates. The over-recovery incurred during that time period is being amortized over three years, beginning in July 2010. UE's vegetation management and infrastructure inspection costs from July 2010 through December 2010 were also less than the amount allowed in base rates. The amortization period for this over-recovery will be determined in a future UE electric rate case.

(gg)

A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by AIC under GAAP and the level of such costs built into electric and natural gas rates. The over-recovery relating to 2009 will be refunded to customers starting in June 2010 through May 2011. The over-recovery relating to 2010 will be refunded to customers starting in June 2011 through May 2012.

(hh)	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.

(ii)

A regulatory tracking mechanism that allows AIC to recover its electric and natural gas costs associated with developing, implementing and evaluating customer energy efficiency and demand response programs. This over-recovery will be refunded to customers over the following 12 months after the plan year.

UE and AIC 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.