NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of March 31, 2011, and changes during the three months ended March 31, 2011, under the Long-term Incentive Plan of 1998, as amended (1998 Plan), and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

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 Ameren Missouri 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. In February 2009, Noranda, Ameren Missouri's largest electric customer, and the MoOPC appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Cole County Circuit Court. The Stoddard and Pemiscot County cases were consolidated (collectively, the Stoddard Circuit Court), and the Cole County case was dismissed. In September 2009, the Stoddard Circuit Court 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. From the granting of the stay request until June 2010, Noranda paid into the Stoddard Circuit Court's registry the entire amount of its monthly base rate increase and monthly FAC payments. In June 2010, when the May 2010 electric rate order became effective, Noranda ceased making base rate payments into the Stoddard Circuit Court's registry. Noranda has continued to pay into the Stoddard Circuit Court's registry its monthly FAC payments relating to electric service during the time periods prior to the effectiveness of the May 2010 electric rate order. Because of the lag between accumulations of changes in net fuel costs and when those net fuel costs are recovered through FAC charges applied to customers' bills, a portion of Noranda's FAC payment in January 2012 is expected to be the last contested amount deposited into the Stoddard Circuit Court's registry relating to this 2009 electric rate order appeal. As of March 31, 2011, the aggregate amount held in the Stoddard Circuit Court's registry was approximately $13 million.

In August 2010, the Stoddard Circuit Court issued a judgment that reversed parts of the MoPSC's decision. Also, upon issuance, the Stoddard Circuit Court suspended its own judgment. Therefore, the entire amount currently held in the Stoddard Circuit Court's registry will remain in the Stoddard Circuit Court's registry pending the appeal discussed below.

In September 2010, Ameren Missouri filed an appeal with the Missouri Court of Appeals, Southern District. The Missouri Court of Appeals will conduct an independent review of the MoPSC's order. Ameren Missouri 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 Ameren Missouri's appeal will be successful. If Ameren Missouri prevails on all issues of its appeal, Ameren Missouri will receive all of the funds held in the Stoddard Circuit Court's registry, plus accrued interest. If Ameren Missouri 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 determination was made. A decision by the Missouri Court of Appeals is not expected before the third quarter of 2011.

2010 Electric Rate Order

In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $230 million, including $119 million to cover higher fuel costs and lower revenue from sales outside Ameren Missouri's system.

The MIEC and MoOPC appealed certain aspects of the MoPSC order to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also filed a request for a stay with the Cole County Circuit Court. In December 2010, the Cole County Circuit Court granted the request of the four industrial customers to stay the MoPSC's 2010 electric rate order and required those customers to pay into the Cole County 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 Ameren Missouri rate order for which appeals have been exhausted. On February 15, 2011, the four industrial customers posted the bond required by the stay. Since the bond was posted, the four industrial customers have made payments into the Cole County Circuit Court's registry equal to the difference between their billings under 2010 electric rates, which includes the FAC, and 2007 electric rates. As of March 31, 2011, the aggregate amount held by the Cole County Circuit Court, excluding the bond amount, was approximately $3 million.

 

On February 16, 2011, the MoOPC and the MIEC separately made filings with the MoPSC in which each argued that the stay granted by the Cole County Circuit Court in December 2010 should apply to all Ameren Missouri customers rather than to just the four industrial customers that requested the stay. The MoOPC requested the MoPSC suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and replace them with Ameren Missouri's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The MIEC requested the MoPSC suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order), including the FAC, and replace them with Ameren Missouri's rate schedules approved by the MoPSC in its 2007 electric rate order for all customers. On March 16, 2011, the MoPSC denied the MoOPC's request to suspend Ameren Missouri's currently effective rate schedules for all customers. By denying the MoOPC's request, the MoPSC effectively denied the MIEC's request to suspend currently effective rates as well. The MoOPC and the MIEC then asked the Missouri Court of Appeals, Western District, to require the MoPSC to suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with Ameren Missouri's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The Missouri Court of Appeals denied the request. On March 28, 2011, the MoOPC and MIEC made the same request to apply the stay granted to four industrial customers to all Ameren Missouri electric customers to the Cole County Circuit Court. On April 12, 2011, the Cole County Circuit Court denied the motion filed by the MoOPC and MIEC. The Cole County Circuit Court's April 12, 2011 order concluded that the stay only granted the request of the four industrial customers to pay into the Cole County Circuit Court's registry the difference between their billings under the 2010 Missouri electric rate order and their billings under the 2007 Missouri electric rate order and that the language in the stay on which the March 28, 2011 motion by the MIEC and MoOPC was based was not part of the operative language of the stay and therefore the stay did not require Ameren Missouri to cease charging the rates approved by the 2010 Missouri electric rate order to all Ameren Missouri electric customers.

With respect to further judicial proceedings regarding the 2010 electric rate order, Ameren Missouri will continue to address the merits of the order and any further filings that might be made relating to the stay, if any, through the judicial and regulatory review processes. We cannot predict the ultimate outcome of these proceedings, which could have a material effect on Ameren Missouri's and Ameren's results of operations, cash flows and financial position.

The stay in effect for the four industrial customers 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. At this time, Ameren Missouri 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 Ameren Missouri's customers. If Ameren Missouri were to conclude that some portion of these rate increases become probable of refund to Ameren Missouri's customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that determination was made. A decision is expected to be issued on the MIEC's and MoOPC's appeal by the Cole County Circuit Court in 2011.

Pending Electric Rate Case

In September 2010, Ameren Missouri filed a request with the MoPSC to increase its annual revenues for electric service. The currently pending request, as amended in April 2011, seeks an increase of approximately $200 million. This increase request was based primarily on energy infrastructure investments, costs incurred to implement environmental controls and other costs incurred for system-wide reliability improvements for customers. Of the amended request, approximately $106 million relates to recovery of the cost of installing and operating two scrubbers at Ameren Missouri's Sioux plant. Also included in this requested increase, as amended, is an approximately $40 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 the requested increase in normalized net fuel costs would have been reflected in rate adjustments implemented under Ameren Missouri's FAC. Capital additions relating to enhancements at the rebuilt Taum Sauk facility were also included in the amended increase request. The amended electric rate increase request was based on a 10.7% return on equity, a capital structure composed of 52.2% common equity, an aggregate electric rate base of $6.7 billion, and a test year ended March 31, 2010, with certain pro-forma adjustments through the true-up date of February 28, 2011. Ameren Missouri also requested continued use of its existing 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.

Ameren Missouri has agreed to settlements of various issues, which are subject to approval by the MoPSC. Ameren Missouri agreed to withdraw its request to implement an infrastructure investment tracking mechanism for certain projects beyond their in-service dates. Ameren Missouri also agreed to withdraw its request to recover its investments in energy efficiency programs over three years instead of six. Ameren Missouri continues to seek the ability to recover any under-recovery of fixed costs resulting from implementation of energy efficiency measures.

In April 2011, the MoPSC staff revised its initial rate recommendation in Ameren Missouri's pending electric rate case. The MoPSC staff now recommends an increase to Ameren Missouri's annual revenues of $86 million based on a midpoint return on equity of 8.75%. Included in this recommendation was approximately $33 million of asset disallowances relating to the Sioux plant scrubbers. Other parties have also made recommendations through testimony filed in this case.

 

The MoPSC has several important issues to consider in this case. Those issues include determining the appropriate return on equity, any asset disallowances related to the Sioux plant scrubbers or enhancements at the rebuilt Taum Sauk facility and the timing of the recoverability of the property taxes associated with those assets, and whether Ameren Missouri should be able to continue to employ its existing FAC at the current 95% sharing level.

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

FAC Prudence Review

Missouri law requires the MoPSC to complete prudence reviews of Ameren Missouri's FAC at least every 18 months. On April 27, 2011, the MoPSC issued an order with respect to its prudency review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri due to the loss of Noranda's load caused by a severe ice storm in January 2009.

Ameren Missouri disagrees with the MoPSC order's classification of these sales and believes that the terms of its FAC tariff do not provide for the inclusion of these sales in the FAC calculation. Ameren Missouri intends to seek rehearing of the MoPSC's order and, if necessary, to appeal this order through the judicial process. We cannot predict the ultimate outcome of the regulatory or judicial proceedings.

As a result of the order, Ameren Missouri will record, in the quarter ended June 30, 2011, a pretax charge to earnings of $17 million for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009.

Ameren Missouri recognized an additional $25 million of pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC has not completed a prudency review of the FAC for this subsequent period. Consequently, the MoPSC order issued on April 27, 2011, did not involve any pretax earnings associated with the same long-term partial requirements contracts subsequent to September 30, 2009. Ameren Missouri is reviewing the MoPSC order and is assessing whether it believes the earnings it recognized associated with these sales subsequent to September 30, 2009, are probable of refund to its electric customers. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made.

Illinois

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 was 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 was 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 also used a future test year, 2012, in each of these rate requests. Additionally, AIC requested 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 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.

Federal

COLA and ESP

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

 

Ameren Missouri 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 and the governor of Missouri, labor and other key stakeholders, support the passage of this legislation. However, passage of the legislation is uncertain.

Should the Missouri legislation be enacted into law, Ameren Missouri plans to file an ESP application with the NRC later in 2011. NRC approval of an ESP application is expected to take three to four years.

As of March 31, 2011, Ameren Missouri 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 costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.6 million new shares of common stock valued at $17 million in the three months ended March 31, 2011.

Indenture Provisions and Other Covenants

Ameren Missouri's and AIC's indenture provisions and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and AIC are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. However, not meeting these ratios would not result in a default under these covenants and provisions. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended March 31, 2011, at an assumed interest rate of 7% and dividend rate of 8%.

 

		Required Interest Coverage Ratio(a)		Actual Interest Coverage Ratio		Bonds Issuable(b)				Required Dividend Coverage Ratio(c)		Actual Dividend Coverage Ratio		Preferred Stock Issuable
AMO		³2.0		3.5		$	2,243			³2.5		88.4		$	1,755
AIC		³2.0		6.9			3,225	(d)		³1.5		3.3			203

 

(a)	Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.

(b)	Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $91 million and $615 million at Ameren Missouri and AIC, respectively.

(c)	Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company's articles of incorporation.

(d)	Amount of bonds issuable by AIC based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture, pursuant to which Ameren's 8.875% $425 million senior unsecured notes due 2014 were issued, does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2010 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.

Ameren Missouri, AIC and Genco as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, AIC may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless AIC has specific authorization from the ICC.

Ameren Missouri's mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by Ameren Missouri. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.9 billion of free and unrestricted retained earnings at March 31, 2011.

AIC's articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. AIC committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization following the AIC Merger and AERG distribution. As of March 31, 2011, AIC had a ratio of common stock equity to total capitalization of 57%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and/or debt-to-capital ratios in order for Genco to pay dividends, make certain principal or interest payments, make certain loans to or investments in affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended and as of March 31, 2011:

 

Required Interest Coverage Ratio

Actual Interest Coverage Ratio

Required Debt-to- Capital Ratio

Actual Debt-to- Capital Ratio

Genco

³1.75(a) /2.50(

b)

4.4

£60%(

b)

47

%

 

(a)

A minimum interest coverage ratio of 1.75 is required for Genco to make certain restricted payments, as defined, including specified dividend, principal and interest payments on certain subordinated intercompany borrowings. As of the date of the restricted payment, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.

(b)

A minimum interest coverage ratio of 2.50 and for the most recently ended four fiscal quarters a debt-to-capital ratio of no greater than 60% are required for Genco to incur additional indebtedness, as defined other than permitted indebtedness, as defined. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and related interest expense. Money pool borrowings are permitted indebtedness and are not subject to these incurrence tests.

Genco's debt incurrence-related ratio restrictions and restricted payment limitations under its indenture may be disregarded if both Moody's and S&P reaffirm their ratings of Genco indenture debt in place at the time of the incurrence of the additional indebtedness after giving effect to such additional indebtedness.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At March 31, 2011, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three months ended March 31, 2011, and 2010:

 

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, uranium, and emission allowances. Such price fluctuations may cause the following:

 

•

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

 

•

market values of coal, natural gas, and uranium inventories or emission allowances that differ from the cost of those commodities in inventory; and

 

•

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

 

The following table presents open gross derivative volumes by commodity type as of March 31, 2011, and December 31, 2010:

 

Authoritative guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 7 - Fair Value Measurements for our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Ameren Missouri and AIC believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.

 

The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2011, and December 31, 2010:

 

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of March 31, 2011, and December 31, 2010:

 

		Ameren(a)				AMO				AIC				Genco
2011
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)		$	5			$	-			$	-			$	-
Interest rate derivative contracts(c)(d)			(9	)			-				-				(9	)
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Heating oil derivative contracts(e)			48				48				-				-
Natural gas derivative contracts(f)			(134	)			(21	)			(113	)			-
Power derivative contracts(g)			3				3				(325	)			-
Uranium derivative contracts(h)			1				1				-				-
2010:
Cumulative gains (losses) deferred in accumulated OCI:
Power derivative contracts(b)		$	8			$	-			$	-			$	-
Interest rate derivative contracts(c)(d)			(9	)			-				-				(9	)
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Heating oil derivative contracts(e)			19				19				-				-
Natural gas derivative contracts(f)			(165	)			(24	)			(141	)			-
Power derivative contracts(g)			1				3				(352	)			-
Uranium derivative contracts(h)			2				2				-				-

 

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

(b)

Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through May 2014 as of March 31, 2011. Current gains of $6 million and $8 million were recorded at Ameren as of March 31, 2011, and December 31, 2010, respectively.

(c)

Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at March 31, 2011, and December 31, 2010, was less than $1 million and less than $1 million, respectively. The balance of the gain will be amortized by June 2012.

(d)

Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco's April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at March 31, 2011, and December 31, 2010, was a loss of $10 million and $10 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.

(e)

Represents net gains on heating oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through December 2013 as of March 31, 2011. Current gains deferred as regulatory liabilities include $29 million and $29 million at Ameren and Ameren Missouri as of March 31, 2011, respectively. Current losses deferred as regulatory assets include $3 million and $3 million at Ameren and Ameren Missouri as of March 31, 2011, respectively. Current gains deferred as regulatory liabilities include $13 million and $13 million at Ameren and Ameren Missouri as of December 31, 2010, respectively. Current losses deferred as regulatory assets include $6 million and $6 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

(f)

Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2016 at Ameren, Ameren Missouri, and AIC, in each case as of March 31, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and AIC, respectively, as of March 31, 2011. Current losses deferred as regulatory assets include $74 million, $10 million, and $64 million at Ameren, Ameren Missouri and AIC, respectively, as of March 31, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $84 million, $11 million, and $73 million at Ameren, Ameren Missouri and AIC, respectively, as of December 31, 2010.

(g)

Represents net gains associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2013 at Ameren and AIC and through December 2012 at Ameren Missouri, in each case as of March 31, 2011. Current gains deferred as regulatory liabilities include $8 million, $5 million, and $3 million at Ameren, Ameren Missouri and AIC, respectively, as of March 31, 2011. Current losses deferred as regulatory assets include $7 million, $2 million, and $184 million at Ameren, Ameren Missouri and AIC, respectively, as of March 31, 2011. Current gains deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and AIC, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $13 million, $3 million, and $181 million at Ameren, Ameren Missouri and AIC, respectively, as of December 31, 2010.

(h)

Represents net gains on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through November 2011 as of March 31, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri as of March 31, 2011, respectively. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.

We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) International Swaps and Derivatives Association agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of March 31, 2011, and December 31, 2010, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

 

The following table presents the amount of cash collateral held from counterparties, as of March 31, 2011, and December 31, 2010, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:

 

 

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. As of March 31, 2011, other collateral consisted of letters of credit in the amount of $11 million and $4 million held by Ameren and Genco, respectively. As of December 31, 2010, other collateral consisted of letters of credit in the amount of $28 million and $1 million held by Ameren and AIC, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2011, and December 31, 2010:

 

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies' credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of March 31, 2011, and December 31, 2010, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2011, or December 31, 2010, and (2) those counterparties with rights to do so requested collateral:

 

 

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three months ended March 31, 2011 and 2010, associated with derivative instruments designated as cash flow hedges. See Note 11 - Other Comprehensive Income for additional information regarding changes in OCI.

 

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three months ended March 31, 2011 and 2010:

 

				Location of Gain (Loss) Recognized in Income		Gain (Loss) Recognized in Income
						2011				2010
Ameren(a)		Heating oil		Operating Expenses - Fuel		$	19			$	1
		Natural gas (generation)		Operating Expenses - Fuel			-				(1	)
		Power		Operating Revenues - Electric			(2	)			31
				Total		$	17			$	31
AMO		Natural gas (generation)		Operating Expenses - Fuel		$	(1	)		$	1
		Power		Operating Revenues - Electric			-				(1	)
				Total		$	(1	)		$	-
Genco		Heating oil		Operating Expenses - Fuel		$	15			$	1
		Natural gas (generation)		Operating Expenses - Fuel			-				(1	)
		Power		Operating Revenues			-				1
				Total		$	15			$	1

 

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

 

Derivatives that Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three months ended March 31, 2011 and 2010:

 

				Gain (Loss) Recognized in Regulatory Liabilities  or Regulatory Assets
				2011				2010
Ameren(a)		Heating oil		$	29			$	1
		Natural gas			31				(106	)
		Power			2				(10	)
		Uranium			(1	)			(1	)
		Total		$	61			$	(116	)
AMO		Heating oil		$	29			$	1
		Natural gas			3				(15	)
		Power			-				16
		Uranium			(1	)			(1	)
		Total		$	31			$	1
AIC		Natural gas		$	28			$	(89	)
		Power			27				(133	)
		Total		$	55			$	(222	)

(a)	Includes amounts for intercompany eliminations.

As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, AIC entered into financial contracts with Marketing Company. These financial contracts are derivative instruments. They are accounted for as cash flow hedges by Marketing Company and as derivatives that qualify for regulatory deferral by AIC. Consequently, AIC and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities by AIC and OCI by Marketing Company. In Ameren's consolidated financial statements, all financial statement effects of the derivative instruments entered into among affiliates were eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts. The following table presents the fair value of the financial contracts included on AIC's balance sheet at March 31, 2011, and December 31, 2010:

 

				2011				2010
AIC		MTM derivative liabilities - affiliates		$	179			$	172
		Other deferred credits and liabilities			146				178
		Total		$	325			$	350