Actual results in future periods for Great Plains Energy and KCP&L could differ materially from historical results and the forward-looking statements contained in this report. The Companies’ business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. Additional risks and uncertainties not presently known or that the Companies’ management currently believes to be immaterial may also adversely affect the Companies. This information, as well as the other information included in this report and in the other documents filed with the SEC, should be carefully considered before making an investment in the securities of Great Plains Energy or KCP&L. Risk factors of KCP&L are also risk factors of Great Plains Energy.

Utility Regulatory Risks:

Complex utility regulation could adversely affect the Companies’ results of operations, financial position and cash flows.

The Companies are subject to, or affected by, extensive federal and state utility regulation, including regulation by the MPSC, KCC, FERC, NRC, SPP and NERC. The Companies must address in their business planning and management of operations the effects of existing and proposed laws and regulations and potential changes in the regulatory framework, including initiatives by federal and state legislatures, RTOs, utility regulators and taxing authorities. Failure of the Companies to obtain adequate rates or regulatory approvals in a timely manner, new or changed laws, regulations, standards, interpretations or other legal requirements, and increased compliance costs and potential non-compliance consequences may materially affect the Companies’ results of operations, financial position and cash flows. Certain of these risks are addressed in greater detail below.

The outcome of retail rate proceedings could have a material impact on the business and is largely outside the Companies’ control.

The rates that KCP&L and GMO are allowed to charge their customers ~~are the single most important item influencing~~significantly influence the Companies’ results of operations, financial position and cash flows. These rates are subject to the determination, in large part, of governmental entities outside of the Companies’ control, including the MPSC, KCC and FERC.

The utility rate-setting principle generally applicable to KCP&L and GMO is that rates should provide a reasonable opportunity to recover expenses and investment prudently incurred to provide utility service plus a reasonable return on such investment. Various expenses incurred by KCP&L and GMO have been excluded from rates by the MPSC and KCC in past rate cases as not being prudently incurred or not providing utility customer benefit, and there is a risk that certain expenses incurred in the future may not be recovered in rates. The MPSC and KCC also have ~~also excluded~~in the past and may in the future exclude from rates ~~from time to time~~ all or a portion of ~~the capital cost of~~investments in various facilities as not being prudently incurred or not being useful in providing utility service. ~~For example, KCC’s November 2010 rate order for KCP&L excluded a portion of the capital costs of the Iatan No. 1 environment project and Iatan No. 2 from KCP&L’s Kansas jurisdictional rate base.~~

In March 2007, KCP&L entered into a Collaboration Agreement with the Sierra Club and the Concerned Citizens of Platte County that provides for increases in KCP&L’s wind generation capacity and energy efficiency initiatives, reductions in certain emission permit levels at its Iatan and ~~LaCygne~~La Cygne generating stations, and projects to offset certain CO2 emissions. The wind generation, energy efficiency and emission permit reductions are conditioned on regulatory approval. In addition to these commitments, as discussed in the “Environmental Risks” and “Financial Risks” sections below, the Companies’ capital expenditures are expected to be substantial over the next several years for ~~other~~additional environmental ~~and~~projects, as well as other projects, and there is a risk that a portion of the capital costs could be excluded from rates in future rate cases.

The Companies are also exposed to cost-recovery shortfalls due to the inherent “regulatory lag” in the rate-setting process, especially during periods of significant cost inflation or declining retail usage, as KCP&L’s and GMO’s utility rates are generally based on historical information and are not subject to adjustment (other than principally for fuel and purchased power for KCP&L in Kansas and for GMO) between rate cases. These and other factors may result in under-recovery of costs, failure to earn the authorized return on investment, or both.

There are mandatory renewable energy standards in Missouri and Kansas. There is the potential for future federal or state mandatory energy efficiency requirements. KCP&L ~~agreed to implement various energy efficiency programs as part of the Collaboration Agreement and the 2005 Comprehensive Energy Plan. KCP&L~~ and GMO have implemented certain energy efficiency ~~programs. The Companies~~programs, and currently ~~recover energy efficiency~~the recovery of these program expenses are on a deferred basis with no recovery mechanism for associated lost revenues.

The MPSC order approving the GMO acquisition provides that the transaction costs will not be recovered through utility rates, and that the Missouri jurisdictional portion of transition costs will be eligible for recovery through utility rates only to the extent the costs are offset by benefits resulting from the acquisition. These costs continue to be deferred until the MPSC authorizes their rate recovery. The KCC order approving the GMO acquisition limited KCP&L’s recovery of transition costs through Kansas rates to $10.0 million over a five year period, starting in December 2010.

Failure to timely recover the full investment costs of capital projects, or the impact of renewable energy and energy efficiency programs, or other utility costs and expenses due to regulatory disallowances,

regulatory lag or other factors could lead to lowered credit ratings, reduced access to capital markets, increased financing costs, lower flexibility due to constrained financial resources and increased collateral security requirements, or reductions or delays in planned capital expenditures. In response to competitive, economic, political, legislative, public perception (including, but not limited to, the Companies’ environmental reputation) and regulatory pressures, the Companies may be subject to rate moratoriums, rate refunds, limits on rate increases, lower allowed returns on investment or rate reductions, including phase-in plans designed to spread the impact of rate increases over an extended period of time for the benefit of customers.

Regulatory requirements regarding utility operations may increase costs and may expose the Companies to compliance penalties or adverse rate consequences.

The ~~NRC extensively regulates nuclear power plants, including Wolf Creek. The~~ FERC, NERC and SPP have implemented and enforce an extensive set of transmission system reliability, cyber security and critical infrastructure protection standards that apply to public utilities, including KCP&L and GMO. The MPSC and KCC have the authority to implement utility operational standards and requirements, such as vegetation management standards, facilities inspection requirements and quality of service ~~standards, and KCP&L agreed to quality of service standards in Kansas in connection with the GMO acquisition.~~standards. In addition, the Companies are also subject to health, safety and other requirements enacted by the Occupational Safety and Health Administration, the Department of Transportation, the Department of Labor and other federal and state agencies. As discussed more fully under “Operational Risks,” the NRC extensively regulates nuclear power plants, including Wolf Creek. The costs of existing, new or modified regulations, standards and other requirements could have an adverse effect on the Companies’ results of operations, financial position and cash flows as a result of increased operations or maintenance and capital expenditures for new facilities or to repair or improve existing facilities. In addition, failure to meet quality of service, reliability, cyber security, critical infrastructure protection, operational or other standards and requirements could expose the Companies to penalties, additional compliance costs, or adverse rate consequences.

Environmental Risks:

The Companies are subject to current and potential environmental requirements and the incurrence of environmental liabilities, any or all of which may adversely affect their business and financial results.

The Companies are subject to extensive federal, state and local environmental laws, regulations and permit requirements relating to air and water quality, waste management and disposal, natural resources and health and safety. In addition to imposing continuing compliance obligations and remediation costs for historical and pre-existing conditions, these laws, regulations and ~~regulations~~permits authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. There is also a risk that new environmental laws and regulations, new judicial interpretations of environmental laws and regulations, or the requirements in new or renewed environmental permits could adversely affect the Companies’ operations. In addition, there is also a risk of lawsuits brought by third parties alleging violations of environmental commitments or requirements, creation of a public nuisance or other matters, and seeking injunctions or monetary or other ~~damages and certain~~damages. Certain federal courts have held that state and local governments and private parties have standing to bring climate change tort suits seeking company-specific emission reductions and damages.

Environmental permits are subject to periodic renewal, which may result in more stringent permit conditions and limits. New facilities, or modifications of existing facilities, may require new environmental permits or amendments to existing permits. Delays in the environmental permitting process, public opposition and challenges, denials of permit applications, limits or conditions imposed in permits and the associated uncertainty may materially adversely affect the cost and timing of ~~the~~ projects, and thus materially adversely affect the Companies’ results of operations, financial position and cash flows.

KCP&L and GMO ~~would~~periodically seek recovery of capital costs and expenses for environmental compliance and remediation through rate increases; however, there can be no assurance that ~~such rate increases~~recovery of these costs would be granted.

As discussed above, KCP&L and GMO may be subject to material adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental ~~reputation and regulatory pressures.~~reputation. The costs of compliance or noncompliance with ~~these~~ environmental requirements, or remediation costs, or adverse outcomes of lawsuits, or failure to timely recover environmental costs could have a material adverse effect on the Companies’ results of operations, financial position and cash flows. Certain of these matters are discussed in more detail below. See Note 1514 to the consolidated financial statements for additional information regarding certain significant environmental matters.

Air and Climate Change

The Companies believe it is likely that additional federal or relevant regional, state or local laws or regulations could be enacted to address global climate change. While the United States is not a current party to the international Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be reached in the future. Such laws or regulations could require the control or reduction of emissions of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. These requirements could include, among other things, taxes or fees on fossil fuels or emissions, cap and trade programs, emission limits and clean or renewable energy standards. The Companies’ current generation capacity is over 50% coal-fired, and is estimated to produce about one ton of CO2 per MWh generated. Great Plains Energy and KCP&L produce about 25 million and 18 million tons of CO2 per year, respectively. Missouri law requires at least 2% of the electricity provided by certain utilities, including KCP&L and GMO, to come from renewable resources, increasing to 15% by 2021. Kansas law requires certain utilities, including KCP&L, to have renewable energy generation capacity equal to at least 10% of their three-year average Kansas peak retail demand, increasing to 15% by 2016 and 20% by 2020.

The Companies believe it is likely that additional federal or relevant regional, state or local laws or regulations could be enacted to address global climate change. At the international level, while the United States is not a current party to the Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be reached in the future. Such laws or regulations could require the control or reduction of emissions of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. These requirements could include, among other things, taxes or fees on fossil fuels or emissions, cap and trade programs, and clean or renewable energy standards. The Companies’ current generation capacity is primarily coal-fired, and is estimated to produce about one ton of CO2 per MWh, or about 28 million and 21 million tons per year for Great Plains Energy and KCP&L, respectively. Missouri law requires at least 2% of the electricity provided by certain utilities, including KCP&L and GMO, to come from renewable resources by 2011, increasing to 15% by 2021. Kansas law requires certain utilities, including KCP&L, to have renewable energy generation capacity equal to at least 10% of their three-year average Kansas peak retail demand by 2011, increasing to 15% by 2016 and 20% by 2020. Management believes that national renewable energy standards are also likely.

Management believes that national renewable energy standards are also possible. The timing, provisions and impact of such requirements, including the cost to obtain and install new equipment to achieve compliance, cannot be reasonably estimated at this time. Such requirements could have a significant financial and operational impact on the Companies.

The Environmental Protection Agency (EPA) has enacted various regulations regarding the reporting and permitting of greenhouse gases and has proposed other ~~permitting~~ regulations under the existing Clean Air Act. ~~These existing and proposed rules establish new~~The EPA has established thresholds for greenhouse gas emissions, defining when Clean Air Act permits under the New Source Performance Standards, New Source Review and Title V operating permits programs would be required for new or existing industrial facilities and when the installation of best available control technology would be required. Most of the Companies’ generating facilities are affected by these existing rules and would be affected by ~~these existing and~~the proposed rules. Additional federal and/or state legislation or regulation respecting greenhouse gas emissions may be proposed or enacted in the ~~near~~ future. Further, pursuant to the Collaboration Agreement, KCP&L agreed to pursue a set of initiatives including energy efficiency, additional wind generation, lower emission permit levels at its Iatan and ~~LaCygne~~La Cygne stations and other initiatives designed to offset CO2 emissions. Requirements to reduce greenhouse gas emissions may cause the Companies to incur significant costs relating to their ongoing operations ~~(through~~(for additional environmental control equipment, retiring and replacing existing generation, or selecting more costly generation alternatives), or to procure emission allowance credits, or due to the imposition of taxes, fees or other governmental charges as a result of such emissions.

Rules issued by the EPA regarding emissions of mercury and other hazardous air pollutants, NOX, SO2 and particulates are also in a state of flux. ~~��Such~~Some of these rules have been overturned by the courts and remanded to the EPA to be revised consistent with the ~~court orders. The EPA is expected~~courts’ orders while others have been stayed pending judicial review or are otherwise subject to develop proposed standards in 2011, based on maximum achievable control technology (MACT), for mercury and potentially other hazardous air pollutant emissions. In addition, the EPA has notified KCP&L that MACT determinations and schedules of compliance are required for KCP&L’s Iatan No. 2 and Hawthorn No. 5 generating units. The Missouri and Kansas state environmental agencies have submitted to the

EPA their determinations that the Kansas City area is an ozone nonattainment area, and must submit by 2013 implementation plans outlining how the area will meet the standards. Additionally, the EPA has proposed to strengthen the national ambient air quality standard (NAAQS) for ozone and has strengthened the NAAQS for SO2.revision. The Companies’ current estimates of capital expenditures (exclusive of Allowance for Funds Used During Construction (AFUDC) and property taxes)

to comply with the currently effective Clean Air Interstate Rule (CAIR) ~~and with~~, the replacement to CAIR or the Cross-State Air Pollution Rule (CSAPR), the best available retrofit technology (BART) rule, the SO2 National Ambient Air Quality Standard (NAAQS), the industrial boiler rule, and the Mercury and Air Toxics Standards (MATS) rule is approximately $1 billion. ~~If CAIR is replaced by the proposed Transport Rule, the Companies do not expect the required capital expenditures to exceed that amount.~~ However, it is unknown what requirements and standards will be imposed in the future, ~~and~~ when the Companies may have to comply ~~the effects of the MACT determinations and schedules of compliance,~~ or what costs may ultimately be required.

Water

The Clean Water Act and associated regulations enacted by the EPA form a comprehensive program to preserve water quality. All of the Companies’ generating facilities, and certain of their other facilities, are subject to the Clean Water Act.

Previously issued EPA regulations regarding protection of aquatic life from being killed or injured by cooling water intake structures have been ~~suspended, and~~suspended; however, the EPA ~~is engaged in further~~has proposed revised rulemaking on this matter. At this time, the Companies are unable to predict how the EPA will respond or how that response will impact the Companies’ operations.

KCP&L holds a permit from the Missouri Department of Natural Resources (MDNR) authorizing KCP&L to, among other things, withdraw water from the Missouri ~~river~~River for cooling purposes and return the heated water to the Missouri ~~river.~~river at its Hawthorn Station. KCP&L has applied for a renewal of this permit and the EPA has submitted an interim objection letter regarding the allowable amount of heat that can be contained in the returned water. Until this matter is resolved, KCP&L continues to operate under its current permit. KCP&L cannot predict the outcome of this matter; however, while less significant outcomes are possible, this matter may require KCP&L to reduce its generation at Hawthorn Station, install cooling towers or both, any of which could have a significant adverse impact on KCP&L. The outcome could also affect the terms of water permit renewals at KCP&L’s Iatan Station and at GMO’s Sibley and Lake Road Stations. Additionally, the EPA in September 2009 announced plans to revise the existing standards for waste water discharges from coal-fired power plants. In November 2010, the EPA filed a motion requesting court approval of a consent agreement in which the EPA agreed to propose a rule in July 2012 and to finalize it in January 2014. Until a rule is proposed and finalized, the financial and operational impacts cannot be determined. Further, the possible effects of climate change, including potentially increased temperatures and reduced precipitation, could make it more difficult and costly to comply with the final permit requirements.

Solid Waste

Solid and hazardous waste generation, storage, transportation, treatment and disposal is regulated at the federal and state levels under various laws and regulations. The Companies principally use coal in generating electricity and dispose of coal combustion residuals (CCRs) in both on-site facilities and facilities owned by third parties. In response to an incident at a Tennessee Valley Authority coal combustion product containment area, the EPA has proposed regulations regarding the handling and disposal of CCRs, which include alternative proposals to regulate CCRs as special or hazardous wastes or as non-hazardous wastes. If enacted, any new laws and regulations, especially if CCRs are classified as hazardous waste, could have a material adverse effect on the Companies’ results of operations, financial position and cash flows.

Remediation

Under current law, the Companies are also generally responsible for any liabilities associated with the environmental condition of their properties, and other properties at which the Companies arranged for the disposal or treatment of hazardous substances, including properties that they have previously owned or

operated, such as manufactured gas plants (MGP), regardless of whether they were responsible for the contamination or whether the liabilities arose before, during or after the time they owned or operated the properties or arranged for the disposal or treatment of hazardous substances. In addition, the EPA has given advance notice of a proposed rulemaking to impose financial assurance requirements for various classes of facilities, including electric generation, transmission and distribution, that produce, transport, treat, store or dispose of certain hazardous substances.

Due to all of the above, the Companies’ projected capital and other expenditures for environmental compliance are subject to significant uncertainties, including the timing of implementation of any new or modified environmental requirements, the emissions limits imposed by such requirements and the types and costs of the compliance alternatives selected by the Companies. As a result, costs to comply with environmental requirements cannot be estimated with certainty, and actual costs could be significantly higher than projections. Other new environmental laws and regulations affecting the operations of the Companies may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to the Companies or their facilities, any of which may materially adversely affect the Companies’ business, adversely affect the Companies’ ability to continue operating its power plants as currently done and substantially increase their environmental expenditures or liabilities in the future.

Financial Risks:

Financial market disruptions and declines in credit ratings may increase financing costs and/or limit access to the credit markets, which may adversely affect liquidity and results.

The Companies’ capital requirements are expected to be substantial over the next several years. The Companies rely on access to short-term money markets, revolving credit facilities provided by financial institutions and long-term capital markets as significant sources of liquidity for capital requirements not satisfied by cash flows from operations. The Companies also rely on bank-provided credit facilities for credit support, such as letters of credit, to support operations. The amount of credit support required for operations varies ~~with~~and is impacted by a number of factors, including the amount and price of wholesale power purchased or sold.

Great Plains Energy, KCP&L, GMO and certain of their securities are rated by Moody's Investors Service and Standard & Poor's. These ratings impact the Companies’ cost of funds and Great Plains Energy’s ability to provide credit support for its subsidiaries. The interest rates on borrowings under the Companies’ revolving credit agreements and on a substantial portion of Great Plains Energy’s and GMO’s debt are subject to increase as their respective credit ratings decrease. The Companies have agreed to not seek rate recovery of GMO interest costs in excess of equivalent investment-grade debt, and the MPSC approval of the GMO acquisition is conditioned on the requirement that any post-acquisition financial effects of a credit downgrade of Great Plains Energy, KCP&L or GMO occurring as a result of the acquisition would be borne by shareholders and not utility customers.debt. The amount of collateral or other credit support required under power supply and certain other agreements is also dependent on credit ratings.

~~The~~Although the United States capital and credit markets ~~experienced unprecedented levels~~have generally stabilized after an extended period of volatility and disruption, ~~in recent years. Though market conditions have stabilized,~~ there is no assurance that conditions will not deteriorate in the ~~future.~~future due to the current instability in Europe or unforeseen events both in the United States and around the world. Adverse market conditions or decreases in Great Plains Energy’s, KCP&L’s or GMO’s credit ratings could have material adverse effects on the Companies. These effects could include, among others: reduced access to capital and increased cost of funds; dilution resulting from equity issuances at reduced prices; changes in the type and/or increases in the amount of collateral or other credit support obligations required to be posted with contractual counterparties; increased nuclear decommissioning trust and pension and other post-retirement benefit plan funding requirements; rate case disallowance of KCP&L’s or GMO’s costs of capital; reductions in or delays of capital expenditures, or reductions in Great Plains Energy’s ability to provide credit support for its subsidiaries. Any of these results could adversely affect the Companies’ results of operations, financial position and cash flows. In addition, market disruption and volatility could have an adverse impact on the Companies’ lenders, suppliers and other counterparties or customers, causing them to fail to meet their obligations.

A sustained decline in Great Plains Energy’s stock price below book value may result in goodwill impairments that could adversely affect Great Plains Energy’s results of operations and financial position, as well as credit facility covenants.

The GMO acquisition resulted in Great Plains Energy recording $169 million in goodwill. Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exists. Great Plains Energy’s stock traded at a price below carrying value throughout 2010. If the stock price were to decline substantially further from its current level in relation to carrying value, accounting rules may require Great Plains Energy to conduct additional goodwill impairment tests. There is no assurance that the results of these additional tests will not require Great Plains Energy to recognize an impairment of goodwill. An impairment of goodwill would reduce net income and shareholders’ equity, may adversely affect Great Plains Energy’s results of operations and financial position, and in certain circumstances could result in a breach of the debt to total capitalization covenants in Great Plains Energy’s and GMO’s revolving credit agreements.

Great Plains Energy has guaranteed substantially all of the outstanding debt of GMO and payments under these guarantees may adversely affect Great Plains Energy’s liquidity.

In connection with the GMO acquisition, Great Plains Energy issued guarantees covering substantially all of the outstanding debt of GMO and has guaranteed GMO’s current $450 million revolving credit facility. The guarantees ~~were~~are a factor in GMO ~~receiving~~maintaining investment-grade ratings and the guarantees obligate Great Plains Energy to pay amounts owed by GMO directly to the holders of the guaranteed debt in the event GMO defaults on its payment obligations. Great Plains Energy may also guarantee debt that GMO may issue in the future. Any guarantee payments could adversely affect Great Plains Energy’s liquidity.

The inability of Great Plains Energy’s subsidiaries to provide sufficient dividends to Great Plains Energy, or the inability otherwise of Great Plains Energy to pay dividends to its shareholders and meet its financial obligations would have an adverse effect.

Great Plains Energy is a holding company with no significant operations of its own. The primary source of funds for payment of dividends to its shareholders and its other financial obligations is dividends paid to it by its subsidiaries, particularly KCP&L and GMO. The ability of Great Plains Energy’s subsidiaries to pay dividends or make other distributions, and accordingly, Great Plains Energy’s ability to pay dividends on its common stock and meet its financial obligations principally depends on the actual and projected earnings and cash flow, capital requirements and general financial position of its subsidiaries, as well as on regulatory factors, financial covenants, general business conditions and other matters.

In addition, Great Plains Energy, KCP&L and GMO are subject to certain corporate and regulatory restrictions and financial covenants that could affect their ability to pay dividends. Great Plains Energy’s articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization. In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of directors necessary to constitute a majority of the full Great Plains Energy Board of Directors. Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out of retained earnings. The revolving credit agreements of Great Plains Energy, KCP&L and GMO contain a covenant requiring each company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 to 1.00. In addition, Great Plains Energy is prohibited from paying dividends on its common and preferred stock in the event its Equity Unit contract payments or interest payments on the debt underlying the Equity Units are deferred until such deferrals have been paid. While these corporate and regulatory restrictions and financial covenants are not expected to affect the Companies’ ability to pay

dividends at the current level in the foreseeable future, there is no assurance that adverse financial results would not trigger such restrictions or covenants and reduce or eliminate the Companies’ ability to pay dividends.

Market performance, increased retirements and retirement plan regulations could significantly impact retirement plan funding requirements and associated cash needs and expenses.

Substantially all of the Companies’ and ~~Wolf Creek Nuclear Operating Corporation’s~~WCNOC’s employees participate in defined benefit retirement and post-retirement plans. Former employees also have accrued benefits in defined benefit retirement and post-retirement plans. The costs of these plans depend on a number of factors, including the rates of return on plan assets, the level and nature of the provided benefits, discount rates, the interest rates used to measure required minimum funding levels, changes in benefit design, changes in laws or regulations, and the Companies’ required or voluntary contributions to the plans. The Companies currently have substantial unfunded liabilities under these plans. Also, if the rate of retirements exceeds planned levels, or if these plans experience adverse market returns on investments, or if interest rates materially fall, the Companies’ contributions to the plans could rise substantially over historical levels. In addition, changes in accounting rules and assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, could have a significant impact on the Companies’ results of operations, financial position and cash flows.

The use of derivative contracts in the normal course of business could result in losses that could negatively impact the Companies’ results of operations, financial position and cash flows.

The Companies use derivative instruments, such as swaps, options, futures and forwards, to manage commodity and financial risks. Losses could be recognized as a result of volatility in the market values of these contracts, if a counterparty fails to perform, or if the underlying transactions which the derivative instruments are intended to hedge fail to materialize. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

As a service provider to GMO, KCP&L may have exposure to GMO’s financial performance and operations.

GMO has no employees of its own. KCP&L employees operate and manage GMO’s properties, and KCP&L charges GMO for the cost of these services. These arrangements may pose risks to KCP&L, including possible claims arising from actions of KCP&L employees in operating GMO’s properties and providing other services to GMO. KCP&L’s claims for reimbursement for services provided to GMO are unsecured and rank equally with other unsecured obligations of GMO. KCP&L’s ability to be reimbursed for the costs incurred for the benefit of GMO depends on the financial ability of GMO to make such payments.

Customer and Weather-Related Risks:

Changes in customer electricity consumption due to sustained financial market disruptions, downturns or sluggishness in the economy, technological advances, or ~~otherwise~~other factors may adversely affect the Companies’ results of operations, financial position and cash flows.

The results of operations, financial position and cash flows of the Companies can be materially affected by changes in customer electricity consumption. The Companies estimate customer electricity consumption based on historical trends to procure fuel and purchased power. Sustained downturns or sluggishness in the economy generally affect the markets in which the Companies operate. Additionally, technological advances or other energy conservation measures could reduce customer electricity consumption.

Weather is a major driver of the Companies’ results of operations, financial position and cash flow.

Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Great Plains Energy and KCP&L are significantly impacted by seasonality, with approximately one-third of their retail electric revenues recorded in the third quarter. Unusually mild winter or summer weather can adversely affect sales. In addition, severe weather, including but not limited to tornados, snow, rain, flooding and ice

storms can be destructive causing outages and property damage that can potentially result in additional expenses, lower revenues and additional capital restoration costs. KCP&L’s and GMO’s rates may not always be adjusted timely and adequately to reflect these increased costs. Some of the Companies’ generating stations ~~use~~utilize water from the Missouri River for cooling purposes. Low water and flow levels, which have been experienced in past years, can increase maintenance costs at these stations and, if these levels were to get low enough, could require modifications to ~~plant operations. Conversely, Missouri River flooding has occurred at various times in past years, which has affected~~ plant operations. The possible effects of climate change (such as increased temperatures, increased occurrence of severe weather or reduced precipitation, among other possible results) could potentially increase the volatility of demand and prices for energy commodities, the frequency and impact of severe weather, increase the frequency of flooding or decrease water and flow levels.

Operational Risks:

Operations risks may adversely affect the Companies’ results of operations, financial position and cash flows.

The operation of the Companies’ electric generation, transmission, distribution and information systems involves many risks, including breakdown or failure of equipment, processes and personnel performance; problems that delay or increase the cost of returning facilities to service after ~~outages, operating~~outages; limitations that may be imposed by equipment conditions, environmental, safety or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling constraints; and catastrophic events such as fires, explosions, terrorism, cyber-threats, severe weather or other similar occurrences. An equipment or system outage or constraint can, among other things:

·	in the case of generation equipment, affect operating costs, increase capital requirements and costs, increase purchased power volumes and costs and reduce wholesale sales opportunities;

·	in the case of transmission equipment, affect operating costs, increase capital requirements and costs, require changes in the source of generation and affect wholesale sales opportunities and the ability to meet regulatory reliability and security requirements;

·	in the case of distribution systems, affect revenues and operating costs, increase capital requirements and costs, and affect the ability to meet regulatory service metrics and customer expectations; and

in the case of information systems, affect the control and operations of generation, transmission, distribution and other business operations and processes, increase operating costs, increase capital requirements and costs, and affect the ability to meet regulatory reliability and security requirements and customer expectations.

With the exception of Hawthorn No. 5, which was substantially rebuilt in 2001, and Iatan No. 2, which was completed in 2010, all of KCP&L’s and GMO’s coal-fired generating units and its nuclear generating unit were constructed prior to 1986. ~~All of GMO’s coal-fired generating units were constructed prior to 1984.~~ The age of these generating units increases the risk of unplanned outages, reduced generation output and higher maintenance expense. Training, preventive maintenance and other programs have been implemented, but there is no assurance that these programs will prevent or minimize future breakdowns or failures of the Companies’ generation facilities or increased maintenance expense.

The Companies currently have general liability and property insurance in place to cover their facilities in amounts that management considers appropriate. These policies, however, do not cover the Companies’ transmission or distribution systems, and the cost of repairing damage to these systems may adversely affect the Companies’ results of operations, financial position and cash flows. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at reasonable costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of the Companies’ facilities may not be sufficient to restore the loss or damage.

These and other operating events may reduce the Companies’ revenues, increase their costs, or both, and may materially affect their results of operations, financial position and cash flows.

The cost and schedule of construction projects may materially change and expected performance may not be achieved.

Great Plains Energy’s and KCP&L’s businesses are capital ~~intensive,~~intensive. The Companies currently have significant construction projects pending and ~~require~~may also have significant ~~capital investments to maintain existing facilities, for projected environmental~~construction projects ~~and to add new facilities.~~in the future. The risks of any construction project include: ~~the possibilities~~ that actual costs may exceed estimated costs due to inflation or other factors; risks associated with the incurrence of additional debt or the issuance of additional equity to fund such projects; delays that may occur in obtaining permits and materials; the failure of suppliers and contractors ~~may not~~to perform as required under their contracts; ~~there may be~~ inadequate availability or increased cost of equipment, materials or qualified craft labor; the scope, cost and timing of projects may change due to new or changed environmental requirements or other factors; and other events beyond the Companies’ control may occur that may materially affect the schedule, cost and performance of these projects.

These and other risks could materially increase the estimated costs of construction projects, delay the in-service dates of projects, adversely affect the performance of the projects, and/or require the Companies to purchase additional electricity to supply their respective retail customers until the projects are completed. ~~The Companies currently are not permitted to start recovering the costs of these projects in rates until they are completed and put into service.~~ Thus, these risks may significantly affect the Companies’ results of operations, financial position and cash flows.

Failure of one or more generation plant co-owners to pay their share of construction or operations and maintenance costs could increase the Companies’ costs and capital requirements.

KCP&L owns 47% of Wolf Creek, 50% of ~~LaCygne~~La Cygne Station, 70% of Iatan No. 1 and 55% of Iatan No. 2. GMO owns 18% of both Iatan units and 8% of Jeffrey Energy Center. The remaining portions of these facilities are owned by other utilities that are contractually obligated to pay their proportionate share of capital and other costs.

While the ownership agreements provide that a defaulting co-owner’s share of the electricity generated can be sold by the non-defaulting co-owners, there is no assurance that the revenues received will recover the increased costs borne by the non-defaulting co-owners. Occurrence of these or other events could materially increase the Companies’ costs and capital requirements.

~~Commodity Price Risks:~~The Companies are subject to information security risks and risks of unauthorized access to their systems.

In the course of their businesses, the Companies handle a range of system security and sensitive customer information. KCP&L and GMO are subject to laws and rules issued by different agencies concerning safeguarding and maintaining the confidentiality of this information. A security breach of the utilities' information systems such as theft or the inappropriate release of certain types of information, including confidential customer information or system operating information, could have a material adverse impact on the results of operations, financial condition and cash flows of the Companies.

~~Changes~~KCP&L and GMO operate in ~~commodity prices~~a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite implementation of security measures, the technology systems are vulnerable to disability, failures, or unauthorized access. Such failures or breaches of the systems could impact the reliability of the utilities’ generation and transmission and distribution systems and also subject the Companies to financial harm. If the technology systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive confidential data could be compromised, which could have ana material adverse ~~effect~~impact on the Companies’ results of operations, financial ~~position~~condition and cash flows.

The Companies engage in the wholesale and retail marketing of electricity and are exposed to risks associated with the price of electricity. To the extent that exposure to the price of electricity is not successfully hedged, the Companies could experience losses associated with the changing market price for electricity.

~~Increases in fuel, fuel transportation and purchased power prices could have an adverse impact on the Companies’ costs.~~

KCP&L’s Kansas retail rates contain an energy cost adjustment mechanism. KCP&L’s Missouri retail rates do not contain a similar provision. GMO’s retail electric and steam rates contain a fuel adjustment mechanism under which most, but not all, of the difference between actual fuel and purchased power costs and the amount of fuel and purchased power costs provided in base rates is passed along to GMO’s customers. As a result, the Companies are exposed to varying degrees of risk from changes in the market prices of fuel for generation of electricity and purchased power. Changes in the Companies’ fuel mix due to electricity demand, plant availability, transportation issues, fuel prices, fuel availability and other factors can also adversely affect the Companies’ fuel and purchased power costs.

The Companies do not hedge their respective entire exposure from fuel and transportation price volatility. Consequently, the Companies’ results of operations, financial position and cash flows may be materially impacted by changes in these prices unless and until increased costs are recovered in KCP&L’s Missouri retail rates.

~~Wholesale electricity sales affect revenues, creating earnings volatility.~~

The levels of the Companies’ wholesale sales depend on the wholesale market price, transmission availability and the availability of generation for wholesale sales, among other factors. A substantial portion of wholesale sales are made in the spot market, and thus the Companies have immediate exposure to wholesale price changes. Wholesale power prices can be volatile and generally increase in times of high regional demand and high natural gas prices. While an allocated portion of wholesale sales are reflected in KCP&L’s Kansas energy cost adjustment and GMO’s fuel adjustment mechanisms, KCP&L’s Missouri rates are set on an estimated amount of wholesale sales. KCP&L will not recover any shortfall in non-firm wholesale electric sales margin from the level included in Missouri rates and any amount above the level reflected in Missouri retail rates will be returned to Missouri retail customers in a future rate case. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce the Companies’ wholesale sales.

KCP&L is exposed to risks associated with the ownership and operation of a nuclear generating unit, which could result in an adverse effect on the Companies’ business and financial results.

KCP&L owns 47% of Wolf Creek. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including Wolf Creek. In the event of non-compliance, the NRC has the authority to impose fines, shut down the facilities, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Any revised safety requirements promulgated by the NRC could result in substantial capital expenditures at Wolf Creek. In addition, the events at the Fukushima nuclear power plant following the 2011 earthquake and tsunami in Japan could result in increased regulation of the nuclear industry and the introduction of additional requirements with respect to emergency planning and ability to deal with natural disasters.

Wolf Creek has the lowest fuel cost per MWh of any of KCP&L's generating units. An extended outage of Wolf Creek, whether resulting from NRC action, an incident at the plant or otherwise, could have a material adverse effect on KCP&L's results of operations, financial position and cash flows in the event KCP&L incurs higher replacement power and other costs that are not recovered through rates or insurance. If a long-term outage occurred, the state regulatory commissions could reduce rates by excluding the Wolf Creek investment from rate base. ~~As discussed in “Operational Risks”, above,~~ Wolf Creek was constructed prior to 1986 and the age of Wolf Creek increases the risk of unplanned outages and higher maintenance costs.

Ownership and operation of a nuclear generating unit exposes KCP&L to risks regarding decommissioning costs at the end of the unit's life. KCP&L contributes annually based on estimated decommissioning costs to a tax-qualified trust fund to be used to decommission Wolf Creek. The funding level assumes a projected level of return on trust assets. If the actual return on trust assets is below the projected level or actual decommissioning costs are higher than estimated, KCP&L could be responsible for the balance of funds required and may not be allowed to recover the balance through rates.

KCP&L is also exposed to other risks associated with the ownership and operation of a nuclear generating unit, including, but not limited to, potential liability associated with the potential harmful effects on the environment and human health resulting from the operation of a nuclear generating unit and the storage, handling, disposal and potential release (by accident, through third-party actions or otherwise) of radioactive materials. Under the structure for insurance among owners of nuclear generating units, KCP&L is also liable for potential retrospective premium assessments (subject to a cap) per incident at any commercial reactor in the country and losses in excess of insurance coverage.

Commodity Price Risks:

Changes in commodity prices could have an adverse effect on the Companies’ results of operations, financial position and cash flows.

Increases in fuel, fuel transportation and purchased power prices could have an adverse impact on the Companies’ costs.

Wholesale electricity sales affect revenues, creating earnings volatility.

The levels of the Companies’ wholesale sales depend on the wholesale market price, transmission availability and the availability of generation for wholesale sales, among other factors. A substantial portion of wholesale sales are made in the spot market, and thus the Companies have immediate exposure to wholesale price changes. Wholesale power prices can be volatile and generally increase in times of high regional demand and high natural gas prices. Conversely, wholesale power prices generally decrease in times of low regional demand and low natural gas prices. While an allocated portion of wholesale sales are reflected in KCP&L’s Kansas energy cost adjustment and GMO’s fuel adjustment mechanisms, KCP&L’s Missouri rates are set on an estimated amount of wholesale sales. KCP&L will not recover any shortfall in non-firm wholesale electric sales margin from the level included in Missouri rates and any amount above the level reflected in Missouri retail rates will be returned to Missouri retail customers in a future rate case. Declines in wholesale market price, availability of generation, transmission constraints in the wholesale markets, or low wholesale demand could reduce the Companies’ wholesale sales and may materially affect the Companies’ results of operations, financial conditions and cash flows.

Litigation Risks:

The outcome of legal proceedings cannot be predicted. An adverse finding could have a material adverse effect on the Companies’ results of operations, financial position and cash flows.

The Companies are party to various material litigation and regulatory matters arising out of their business operations. The ultimate outcome of these matters cannot presently be determined, nor, in many cases, can the liability that could potentially result from a negative outcome in each case ~~presently~~ be reasonably estimated. The liability that the Companies may ultimately incur with respect to any of these cases in the event of a negative outcome may be in excess of amounts currently reserved and insured against with respect to such matters.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Electric Utility Generation Resources

Year

Estimated 2011

Primary

Year

Estimated 2012

Primary

Unit

Location

Completed

MW Capacity

Fuel

Unit

Location

Completed

MW Capacity

Fuel

Base Load

Iatan No. 2

Missouri

2010

465

(a)

Coal

Base Load

Iatan No. 2

Missouri

2010

482

(a)

Coal

Wolf Creek

Kansas

1985

560

(a)

Nuclear

Wolf Creek

Kansas

1985

547

(a)

Nuclear

Iatan No. 1

Missouri

1980

494

(a)

Coal

Iatan No. 1

Missouri

1980

493

(a)

Coal

LaCygne No. 2

Kansas

1977

341

(a)

Coal

La Cygne No. 2

Kansas

1977

343

(a)

Coal

LaCygne No. 1

Kansas

1973

368

(a)

Coal

La Cygne No. 1

Kansas

1973

368

(a)

Coal

Hawthorn No. 5 (b)

Missouri

1969

563

Coal

Hawthorn No. 5 (b)

Missouri

1969

564

Coal

Montrose No. 3

Missouri

1964

176

Coal

Montrose No. 3

Missouri

1964

176

Coal

Montrose No. 2

Missouri

1960

164

Coal

Montrose No. 2

Missouri

1960

164

Coal

Montrose No. 1

Missouri

1958

170

Coal

Montrose No. 1

Missouri

1958

170

Coal

Peak Load

West Gardner Nos. 1, 2, 3 and 4

Kansas

2003

310

Natural Gas

Peak Load

West Gardner Nos. 1, 2, 3 and 4

Kansas

2003

310

Natural Gas

Osawatomie

Kansas

2003

Natural Gas

Hawthorn No. 9

Missouri

2000

130

Natural Gas

Osawatomie

Kansas

2003

Natural Gas

Hawthorn No. 8

Missouri

2000

Natural Gas

Hawthorn Nos. 6 and 9

Missouri

2000

232

Natural Gas

Hawthorn No. 7

Missouri

2000

Natural Gas

Hawthorn No. 8

Missouri

2000

Natural Gas

Hawthorn No. 6

Missouri

1997

136

Natural Gas

Hawthorn No. 7

Missouri

2000

Natural Gas

Northeast Black Start Unit

Missouri

1985

Oil

Northeast Black Start Unit

Missouri

1985

Oil

Northeast Nos. 17 and 18

Missouri

1977

110

Oil

Northeast Nos. 17 and 18

Missouri

1977

110

Oil

Northeast Nos. 13 and 14

Missouri

1976

105

Oil

Northeast Nos. 13 and 14

Missouri

1976

105

Oil

Northeast Nos. 15 and 16

Missouri

1975

Oil

Northeast Nos. 15 and 16

Missouri

1975

Oil

Northeast Nos. 11 and 12

Missouri

1972

Oil

Northeast Nos. 11 and 12

Missouri

1972

Oil

Wind

Spearville 2 Wind Energy Facility (c)

Kansas

2010

Wind

Spearville 2 Wind Energy Facility (c)

Kansas

2010

Wind

Spearville Wind Energy Facility (d)

Kansas

2006

Wind

Spearville Wind Energy Facility (d)

Kansas

2006

Wind

Total KCP&L

4,529

Total KCP&L

4,500

Base Load

Iatan No. 2

Missouri

2010

153

(a)

Coal

Base Load

Iatan No. 2

Missouri

2010

159

(a)

Coal

Iatan No. 1

Missouri

1980

127

(a)

Coal

Iatan No. 1

Missouri

1980

127

(a)

Coal

Jeffrey Energy Center Nos. 1, 2 and 3

Kansas

1978, 1980, 1983

173

(a)

Coal

Jeffrey Energy Center Nos. 1, 2 and 3

Kansas

1978, 1980, 1983

174

(a)

Coal

Sibley Nos. 1, 2 and 3

Missouri

1960, 1962, 1969

466

Coal

Sibley Nos. 1, 2 and 3

Missouri

1960, 1962, 1969

463

Coal

Lake Road Nos. 2 and 4

Missouri

1957, 1967

125

Coal and Natural Gas

Lake Road Nos. 2 and 4

Missouri

1957, 1967

119

Coal and Natural Gas

Peak Load

South Harper Nos. 1, 2 and 3

Missouri

2005

314

Natural Gas

Peak Load

South Harper Nos. 1, 2 and 3

Missouri

2005

317

Natural Gas

Crossroads Energy Center

Mississippi

2002

297

Natural Gas

Crossroads Energy Center

Mississippi

2002

297

Natural Gas

Ralph Green No. 3

Missouri

1981

Natural Gas

Ralph Green No. 3

Missouri

1981

Natural Gas

Greenwood Nos. 1, 2, 3 and 4

Missouri

1975-1979

255

Natural Gas/Oil

Greenwood Nos. 1, 2, 3 and 4

Missouri

1975-1979

253

Natural Gas/Oil

Lake Road No. 5

Missouri

1974

Natural Gas/Oil

Lake Road No. 5

Missouri

1974

Natural Gas/Oil

Lake Road Nos. 1 and 3

Missouri

1951, 1962

Natural Gas/Oil

Lake Road Nos. 1 and 3

Missouri

1951, 1962

Natural Gas/Oil

Lake Road Nos. 6 and 7

Missouri

1989, 1990

Oil

Lake Road Nos. 6 and 7

Missouri

1989, 1990

Oil

Nevada

Missouri

1974

Oil

Nevada

Missouri

1974

Oil

Total GMO

2,139

Total GMO

2,139

Total Great Plains Energy

6,668

Total Great Plains Energy

6,639

(a)

Share of a jointly owned unit.

~~(a)~~(b)

Share of a jointly owned unit.

The Hawthorn Generating Station returned to commercial operation in 2001 with a new boiler, air quality control equipment and

~~(b)~~

The Hawthorn Generating Station returned to commercial operation in 2001 with a new boiler, air quality control equipment and

an uprated turbine following a 1999 explosion.

(c)

The 48 MW Spearville 2 Wind Energy Facility's accredited capacity is 4 MW pursuant to SPP reliability standards.

~~(c)~~(d)

The 48 MW Spearville 2 Wind Energy Facility's accredited capacity is 4 MW pursuant to SPP reliability standards.

The 100.5 MW Spearville Wind Energy Facility's accredited capacity is 8 MW pursuant to SPP reliability standards.

(d)

The 100.5 MW Spearville Wind Energy Facility's accredited capacity is 8 MW pursuant to SPP reliability standards.

2223

KCP&L owns 50% of ~~LaCygne~~La Cygne Nos. 1 and 2, 70% of Iatan No. 1, 55% of Iatan No. 2 and 47% of Wolf Creek. GMO owns 18% of Iatan Nos. 1 and 2 and 8% of Jeffrey Energy Center Nos. 1, 2 and 3.

Electric Utility Transmission and Distribution Resources

Electric utility’s electric transmission system interconnects with systems of other utilities for reliability and to permit wholesale transactions with other electricity suppliers. Electric utility has approximately ~~3,500~~3,600 circuit miles of transmission lines, 15,600 circuit miles of overhead distribution lines and ~~6,500~~6,600 circuit miles of underground distribution lines in Missouri and Kansas. Electric utility has all material franchise rights necessary to sell electricity within its retail service territory. Electric utility’s transmission and distribution systems are continuously monitored for adequacy to meet customer needs. Management believes the current systems are adequate to serve customers.

Electric Utility General

Electric utility’s generating plants are located on property owned (or co-owned) by KCP&L or GMO, except the Spearville Wind Energy Facilities which are located on easements and the Crossroads Energy Center and South Harper which are contractually controlled. Electric utility’s service centers, electric substations and a portion of its transmission and distribution systems are located on property owned or leased by electric utility. Electric utility’s transmission and distribution systems are for the most part located above or underneath highways, streets, other public places or property owned by others. Electric utility believes that it has satisfactory rights to use those places or properties in the form of permits, grants, easements, licenses or franchise rights; however, it has not necessarily undertaken efforts to examine the underlying title to the land upon which the rights rest. Great Plains Energy’s and KCP&L’s headquarters are located in leased office space.

Substantially all of the fixed property and franchises of KCP&L, which consist principally of electric generating stations, electric transmission and distribution lines and systems, and buildings (subject to exceptions, reservations and releases), are subject to a General Mortgage Indenture and Deed of Trust dated as of

December 1, 1986. Mortgage bonds totaling ~~$755.3~~$642.5 million were outstanding at December 31, ~~2010.~~2011.

Substantially all of the fixed property and franchises of GMO’s St. Joseph Light & Power division is subject to a General Mortgage Indenture and Deed of Trust dated as of April 1, 1946. Mortgage bonds totaling ~~$12.4~~$11.2 million were outstanding at December 31, ~~2010.~~2011.

ITEM 3. LEGAL PROCEEDINGS

Other Proceedings

The Companies are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Notes 6,5, 14 and 15 ~~and 16~~ to the consolidated financial statements. Such descriptions are incorporated herein by reference.

ITEM 4. ~~(REMOVED AND RESERVED)~~MINE SAFETY DISCLOSURES

Not applicable.

2324

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

GREAT PLAINS ENERGY

Great Plains Energy’s common stock is listed on the New York Stock Exchange under the symbol “GXP”. At February ~~22, 2011,~~21, 2012, Great Plains Energy’s common stock was held by ~~22,047~~20,770 shareholders of record. Information relating to market prices and cash dividends on Great Plains Energy's common stock is set forth in the following table.



	Common Stock Price Range (a)								Common Stock							Common Stock Price Range (a)								Common Stock
	2010				2009				Dividends Declared							2011				2010				Dividends Declared
Quarter	High		Low		High		Low		2011			2010		2009		High		Low		High		Low		2012			2011		2010
First	$	19.60	$	17.43	$	20.34	$	11.17	$	0.2075	(b)	$	0.2075	$	0.2075	$	20.08	$	18.94	$	19.60	$	17.43	$	0.2125	(b)	$	0.2075	$	0.2075
Second		19.63		16.85		15.91		13.44					0.2075		0.2075		21.17		19.70		19.63		16.85					0.2075		0.2075
Third		19.06		16.95		18.17		14.81					0.2075		0.2075		21.24		16.53		19.06		16.95					0.2075		0.2075
Fourth		19.63		18.58		20.16		16.93					0.2075		0.2075		21.97		18.68		19.63		18.58					0.2125		0.2075
(a) Based on closing stock prices.	(a) Based on closing stock prices.															(a) Based on closing stock prices.
(b) Declared February 8, 2011, and payable March 21, 2011, to shareholders of record as of February 28, 2011.
(b) Declared February 7, 2012, and payable March 20, 2012, to shareholders of record as of February 28, 2012.																(b) Declared February 7, 2012, and payable March 20, 2012, to shareholders of record as of February 28, 2012.

Dividend Restrictions

For information regarding dividend restrictions, see Note 1312 to the consolidated financial statements.

Purchases of Equity Securities

The following table provides information regarding purchases by the Company of its equity securities during the fourth quarter of ~~2010.~~

2011.

Issuer Purchases of Equity Securities

Maximum Number

Total Number of

(or Approximate

Total Number of

(or Approximate

Shares (or Units)

Dollar Value) of

Shares (or Units)

Dollar Value) of

Total

Purchased as

Shares (or Units)

Total

Purchased as

Shares (or Units)

Number of

Average

Part of Publicly

that May Yet Be

Number of

Average

Part of Publicly

that May Yet Be

Price Paid

Announced

Purchased Under

Price Paid

Announced

Purchased Under

(or Units)

per Share

Plans or

the Plans or

(or Units)

per Share

Plans or

the Plans or

Month

Purchased

(or Unit)

Programs

Purchased

(or Unit)

Programs

October 1 - 31

15,470

(1)

$ 16.22

N/A

November 1 - 30

N/A

210

(1)

19.97

N/A

December 1 - 31

N/A

Total

15,470

$ 16.22

N/A

210

19.97

N/A

(1)

Represents restricted common shares surrendered to the Company following the resignation of a certain officer.

(1) Represents restricted common shares surrendered to the Company following the resignation of a certain officer.

KCP&L

KCP&L is a wholly owned subsidiary of Great Plains Energy, which holds the one share of issued and outstanding KCP&L common stock.

Dividend Restrictions

For information regarding dividend restrictions, see Note 1312 to the consolidated financial statements.

~~ITEM 6. SELECTED FINANCIAL DATA~~

Year Ended December 31 2010 2009 2008 2007 2006
Great Plains Energy (a)
(dollars in millions except per share amounts)
Operating revenues $ 2,256 $ 1,965 $ 1,670 $ 1,293 $ 1,140
Income from continuing operations (b)
$ 212 $ 152 $ 120 $ 121 $ 137
Net income attributable to Great Plains Energy $ 212 $ 150 $ 155 $ 159 $ 128
Basic earnings per common
share from continuing operations $ 1.55 $ 1.16 $ 1.16 $ 1.41 $ 1.74
Basic earnings per common share $ 1.55 $ 1.15 $ 1.51 $ 1.86 $ 1.62
Diluted earnings per common
share from continuing operations $ 1.53 $ 1.15 $ 1.16 $ 1.40 $ 1.73
Diluted earnings per common share $ 1.53 $ 1.14 $ 1.51 $ 1.85 $ 1.61
Total assets at year end $ 8,818 $ 8,483 $ 7,869 $ 4,832 $ 4,359
Total redeemable preferred stock, mandatorily
redeemable preferred securities and long-
term debt (including current maturities) $ 3,428 $ 3,214 $ 2,627 $ 1,103 $ 1,142
Cash dividends per common share $ 0.83 $ 0.83 $ 1.66 $ 1.66 $ 1.66
SEC ratio of earnings to fixed charges 2.28 1.81 2.26 2.53 3.50

KCP&L
Operating revenues $ 1,517 $ 1,318 $ 1,343 $ 1,293 $ 1,140
Net income $ 163 $ 129 $ 125 $ 157 $ 149
Total assets at year end $ 6,026 $ 5,702 $ 5,229 $ 4,292 $ 3,859
Total redeemable preferred stock, mandatorily
redeemable preferred securities and long-
term debt (including current maturities) $ 1,780 $ 1,780 $ 1,377 $ 1,003 $ 977
SEC ratio of earnings to fixed charges 2.86 2.44 2.87 3.53 4.11

(a) Great Plains Energy's results include GMO only from the July 14, 2008, acquisition date.
(b) This amount is before income (loss) from discontinued operations, net of income taxes, of $(1.5) million, $35.0 million,
$38.3 million and $(9.1) million in 2009 through 2006, respectively.

ITEM 6. SELECTED FINANCIAL DATA


Year Ended December 31	2011		2010		2009		2008		2007
Great Plains Energy (a)	(dollars in millions except per share amounts)
Operating revenues	$	2,318	$	2,256	$	1,965	$	1,670	$	1,293
Income from continuing operations (b)	$	174	$	212	$	152	$	120	$	121
Net income attributable to Great Plains Energy	$	174	$	212	$	150	$	155	$	159
Basic earnings per common
share from continuing operations	$	1.27	$	1.55	$	1.16	$	1.16	$	1.41
Basic earnings per common share	$	1.27	$	1.55	$	1.15	$	1.51	$	1.86
Diluted earnings per common
share from continuing operations	$	1.25	$	1.53	$	1.15	$	1.16	$	1.40
Diluted earnings per common share	$	1.25	$	1.53	$	1.14	$	1.51	$	1.85
Total assets at year end	$	9,118	$	8,818	$	8,483	$	7,869	$	4,832
Total redeemable preferred stock, mandatorily
redeemable preferred securities and long-
term debt (including current maturities)	$	3,544	$	3,428	$	3,214	$	2,627	$	1,103
Cash dividends per common share	$	0.835	$	0.83	$	0.83	$	1.66	$	1.66
SEC ratio of earnings to fixed charges		2.03		2.28		1.81		2.26		2.53

KCP&L
Operating revenues	$	1,558	$	1,517	$	1,318	$	1,343	$	1,293
Net income	$	136	$	163	$	129	$	125	$	157
Total assets at year end	$	6,292	$	6,026	$	5,702	$	5,229	$	4,292
Total redeemable preferred stock, mandatorily
redeemable preferred securities and long-
term debt (including current maturities)	$	1,915	$	1,780	$	1,780	$	1,377	$	1,003
SEC ratio of earnings to fixed charges		2.52		2.86		2.44		2.87		3.53

(a) Great Plains Energy's results include GMO only from the July 14, 2008, acquisition date.
(b) This amount is before income (loss) from discontinued operations, net of income taxes, of $(1.5) million, $35.0 million
and $38.3 million in 2009 through 2007, respectively.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GREAT PLAINS ENERGY INCORPORATED

EXECUTIVE SUMMARY

Description of Business

Great Plains Energy is a public utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy’s direct subsidiaries with operations or active subsidiaries are KCP&L and GMO. ~~Great Plains Energy acquired GMO on July 14, 2008.~~ Great Plains Energy’s sole reportable business segment is electric utility for the periods presented.

Electric utility consists of KCP&L, a regulated utility, and GMO’s regulated utility operations, which include its Missouri Public Service and St. Joseph Light & Power divisions. Electric utility has over 6,600 MWs of generating capacity and engages in the generation, transmission, distribution and sale of electricity to approximately ~~823,200~~823,000 customers in the states of Missouri and Kansas. Electric utility’s retail electricity rates are below the national average of investor-owned utilities.

~~2010~~

2011 Earnings Overview

Great Plains Energy’s ~~2010~~2011 earnings available for common shareholders ~~increased~~decreased to $172.8 million or $1.25 per share from $210.1 million or $1.53 per share in 2010. Several of KCP&L’s coal-fired power plants were impacted by flooding along the Missouri River in 2011, which decreased gross margin by an estimated $16 million due to coal conservation activities and increased other operating expenses $3.3 million. Gross margin also decreased due to unfavorable weather and demand, an estimated $11 million from ~~$148.5~~the impact of an extended refueling outage at Wolf Creek, and $7.5 million ~~or $1.14 per share~~from increased coal transportation costs not recovered in ~~2009 primarily~~KCP&L’s Missouri retail rates where there is no fuel recovery mechanism. Also in 2011, Great Plains Energy recognized $12.7 million of expense related to a voluntary separation program and a $13.1 million increase in electric utility’s general taxes driven by ~~an increase in gross margin due to~~higher property taxes.

Partially offsetting these decreases were new retail rates in Kansas effective December 1, 2010, and ~~favorable weather.~~ Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO. In 2010, electric utility recognized a $16.8 million pre-tax loss representing KCP&L’s and GMO’s combined share of construction costs for the Iatan No. 1 environmental equipment and the Iatan No. 2 construction project.

Gross margin is a financial measure that is not calculated in accordance with Generally Accepted Accounting Principles (GAAP). See the explanation of gross margin and the reconciliation to GAAP operating revenues under Great Plains Energy’s Results of Operations for further information.

Partially offsetting the increase in gross margin was higher operations and maintenance expense driven by planned plant outages, increased depreciation and amortization expense due to additional regulatory amortization pursuant to KCP&L’s 2009 rate cases and depreciation from placing in service the Iatan No. 1 environmental equipment in 2009 and Iatan No. 2 in 2010 (Kansas jurisdiction only), increased general taxes and a decrease in the equity component of AFUDC. Great Plains Energy also recorded a $16.8 million pre-tax loss in 2010 representing KCP&L’s and GMO’s combined share of the impact of disallowed construction costs for the Iatan No. 1 environmental equipment and the Iatan No. 2 construction project.

~~Additionally, 2009 reflects a $16.0 million tax benefit due to the settlement of GMO’s 2003-2004 tax audit.~~

~~KCP&L’s Comprehensive Energy Plan~~

KCP&L’s Comprehensive Energy Plan included construction of Iatan No. 2, wind generation, environmental upgrades at certain coal-fired generating stations, infrastructure investments, and energy efficiency, affordability and demand response programs. With the construction of Iatan No. 2 completed in 2010, the remaining component of KCP&L’s Comprehensive Energy Plan is to obtain state regulatory approval to include the cost of Iatan No. 2 in rate base and begin recovering the investment in rates.

In August 2010, Iatan No. 2 successfully completed in-service testing, which was confirmed by KCC in October 2010, but is still subject to confirmation by the MPSC, which is expected during the current Missouri rate cases.

~~In the fourth quarter of 2010, Great Plains Energy and~~ KCP&L completed a final cost estimate for Iatan No. 2. The final cost estimate and previous cost estimate ranges are shown in the following table. The cost estimate ranges do not include AFUDC or the cost of common facilities that were identified at the time of the start-up of the Iatan No. 1 environmental project that will be used by both Iatan No. 1 and Iatan No. 2.

Final Cost Previous Estimate
Estimate Range Range Change
(millions)
Great Plains Energy's 73% share of Iatan No. 2 $ 1,203 - $ 1,218 $ 1,222 - $ 1,251 $ (19) - $ (33)
KCP&L's 55% share of Iatan No. 2 905 - 917 919 - 941 (14) - (24)

Kansas ~~Regulatory~~Rate Case Proceedings

In December 2009, KCP&L filed a request with KCC to increase retail electric annual revenues by $55.2 million. The request was subsequently adjusted by KCP&L during the rate case proceedings to $50.9 million as the net result of updates to the case. The request included costs related to Iatan No. 2, a new coal-fired generation unit, upgrades to the transmission and distribution system to improve reliability and overall increased costs of service.

In November 2010, KCC issued ~~its~~an order, effective December 1, 2010, for KCP&L, authorizing an increase in annual revenues of $21.8 million, a return on equity of 10.0%, an equity ratio of approximately 49.7% and a Kansas jurisdictional rate base of $1.781 billion. The annual revenue increase was subsequently adjusted by KCC in a January 2011 reconsideration order to $22.0 million. In February 2011, KCC issued an order granting KCP&L and another party to the case their respective petitions for reconsideration regarding rate case expenses. ~~The $22.0~~In January 2012, KCC issued its order allowing approximately $0.2 million ~~annual revenue increase is considered as interim subject to refund or true-up pending the outcome~~ of ~~the reconsideration proceedings regarding~~additional rate case ~~expenses. Also~~expenses to be included in ~~February 2011, KCP&L~~rates and ~~another party to the case filed petitions for judicial review with the Court of Appeals of the State of Kansas, which are stayed until conclusion of the reconsideration proceedings.~~amortized over three years. The rates authorized by KCC ~~will be~~are effective unless and until modified by KCC or stayed by a court.

KCP&L Missouri Rate Case Proceedings

~~Accounting rules state~~On February 27, 2012, KCP&L filed an application with the MPSC to request an increase of its retail rates of $105.7 million, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%. The request includes recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service and also includes a lower annual offset to the revenue requirement for the Missouri jurisdictional portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset). KCP&L currently expects that ~~when~~ it ~~becomes probable that part~~will not be able to achieve the $45.9 million wholesale margin offset currently reflected in its retail rates due to a decline in wholesale power prices, which is being driven by low natural gas prices.

On April 12, 2011, the MPSC issued an order and on April 14, 2011, the MPSC Staff filed a report which quantified an authorized revenue increase of approximately $34.8 million on an annual basis, which reflects a wholesale margin offset of approximately $45.9 million and authorizes a return on equity of 10.0%, an equity ratio of approximately 46.3% and a Missouri jurisdictional rate base of approximately $2.0 billion effective May 4, 2011. If the ~~cost of a recently completed plant~~actual Missouri jurisdiction wholesale margin amount exceeds the $45.9 million level reflected in the MPSC order, the difference will be ~~disallowed~~recorded as a regulatory liability and will be returned, with interest, to KCP&L Missouri customers in a future rate case. The MPSC order provides the opportunity for ~~rate-making purposes and~~KCP&L to retain a ~~reasonable estimate of the~~larger amount of non-firm wholesale electric sales margin than KCP&L proposed; however, there are no assurances that KCP&L will achieve the ~~disallowance can be made,~~$45.9 million wholesale margin offset amount and there are no means for KCP&L to recover any shortfall through its retail rates unless the ~~estimated amount of the probable disallowance shall be deducted from the reported cost of the plant and recognized as a loss.~~ MPSC authorizes future recovery.

As a result of disallowances in the ~~KCC~~April 2011 MPSC order, KCP&L recognized ~~Kansas jurisdictional~~ losses of ~~$4.4~~$1.5 million for construction costs related to Iatan No. 2 and ~~$2.0~~the Iatan No. 1 environmental project during 2011. KCP&L also recorded a $2.4 million loss for other disallowed costs in the MPSC order.

In a related order, the MPSC required KCP&L and GMO to apply to the Internal Revenue Service (IRS) to reallocate approximately $26.5 million of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO. KCP&L and GMO did apply to the IRS but in September 2011, the IRS denied KCP&L’s and GMO’s request. The MPSC has indicated it will consider the ratemaking treatment of the tax credits in a future rate case. Certain ratemaking treatments that may be pursued by the MPSC could trigger the loss or repayment to the IRS of a portion of unamortized deferred investment tax credits. At December 31, 2011, KCP&L and GMO had $127.9 million and $3.3 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On February 27, 2012, GMO filed an application with the MPSC to request an increase of its retail rates of $58.3 million for its Missouri Public Service division and $25.2 million for its L&P division, with a return on equity of 10.4% and a rate-making equity ratio of 52.5%. The requests include recovery of costs related to improving and maintaining infrastructure to continue to be able to provide reliable electric service, costs related to energy efficiency and demand side management programs, and increased fuel costs.

In December 2011, GMO filed a request with the MPSC seeking to recover costs for new and enhanced energy efficiency and demand side management programs under the Missouri Energy Efficiency Investment Act (MEEIA). If approved, the costs would be recovered through a rider mechanism and GMO would reduce its request to increase retail rates that it filed with the MPSC on February 27, 2012. A decision on the MEEIA request is expected in the second quarter of 2012.

On May 4, 2011, the MPSC issued an order and on May 10, 2011, the MPSC Staff filed a report which quantified authorized revenue increases on an annual basis of $30.1 million for GMO’s Missouri Public Service division and $29.3 million for GMO’s L&P division. The MPSC order authorized a return on equity of 10.0%, an equity ratio of approximately 46.6% and a Missouri jurisdictional rate base of $1.76 billion. In response to applications for clarification and rehearing of the MPSC order, the MPSC on May 27, 2011, issued an order of clarification and modification. The modified MPSC order revised the authorized annual revenue increases to approximately $35.7 million for GMO’s Missouri Public Service division and approximately $29.8 million for GMO’s L&P division, resulting primarily from a clarification of the amount of fuel costs shifted from GMO’s fuel adjustment clause to base rates. However, because the MPSC authorized an annual revenue increase that was greater than the amount originally requested by GMO for its L&P division and communicated to GMO’s L&P customers, the modified MPSC order deferred approximately $7.7 million of the L&P division increase, which is the amount over GMO’s requested $22.1 million increase for that division, and will phase in the deferred revenue amount in equal parts over a two-year period, plus carrying costs. In addition, GMO shall be allowed to recover the revenue which would have been allowed in the absence of a phase-in.

As a result of disallowances in the May 2011 MPSC order, GMO recognized losses of $0.8 million for construction costs related to the Iatan No. 1 environmental project. Management determined it is probable that the MPSC would disallow these costs as well in KCP&L’s and GMO’s pending rate cases. Therefore, KCP&L’s Missouri jurisdictional portion and GMO’s portion of these costs were recognized as a loss in addition to the KCP&L Kansas jurisdictional portion resulting in a $16.8 million pre-tax loss representing KCP&L’s and GMO’s combined share for construction costs incurred through December 31, 2010.

~~Missouri Regulatory Proceedings~~

~~The following table summarizes pending requests for retail rate increases with the MPSC.~~

Annual
Revenue Return on Rate-Making
Rate Jurisdiction File Date Increase Equity Equity Ratio
(millions)
KCP&L - Missouri (a)
6/4/2010 $ 92.1 (b) 11.00 % (b) 46.16 % (b)
GMO - Missouri Public Service division (a)
6/4/2010 75.8 (c) 11.00 % (c) 46.16 % (c)
GMO - St. Joseph Light & Power division (a)
6/4/2010 22.1 (d) 11.00 % (d) 46.16 % (d)

(a) The request includes costs related to Iatan No. 2, a new coal-fired generation unit, upgrades to the transmission
and distribution system to improve reliability and overall increased costs of service. For KCP&L, it also includes
increased coal transportation costs due to the expiration in 2010 of the majority of KCP&L's current coal
transportation contracts. Any authorized changes to retail rates are expected to be effective in May 2011 for
KCP&L and June 2011 for GMO.
(b) The requested increase was adjusted by KCP&L in a February 22, 2011, filing with the MPSC to $55.8 million
mainly due to lower fuel and purchased power costs, as there is no fuel recovery mechanism, and increased
deferred income taxes from bonus depreciation. The lower fuel and purchased power costs were driven by more
favorable coal transportation costs and lower actual 2010 fuel and purchased power costs than the amounts
included in the June 4, 2010, initial request. The requested return on equity was adjusted by KCP&L to 10.75%
and the rate-making equity ratio was adjusted to 46.286%.
(c) The requested increase was adjusted by GMO in a February 22, 2011, filing with the MPSC to $65.2 million as
the net result of updates to the case. The requested return on equity was adjusted by GMO to 10.75% and the
rate-making equity ratio was adjusted to 46.286%.
(d) The requested increase was adjusted by GMO in a February 22, 2011, filing with the MPSC to $23.2 million as
the net result of updates to the case. The requested return on equity was adjusted by GMO to 10.75% and the
rate-making equity ratio was adjusted to 46.286%.

In September 2010, GMO received an order from the MPSC approving construction accounting for the Iatan No. 2 project from the Iatan No. 2 in-service date to the effective date of new rates in the current rate case. The effect of the order is to defer GMO’s share of Iatan No. 2 operating costs, depreciation expense and carrying costs (interest) offset by Iatan No. 2’s system energy value to a regulatory asset rather than impacting the income statement until new rates are effective. KCP&L (Missouri jurisdiction only) was granted construction accounting as part of the Comprehensive Energy Plan.

In November 2010, the MPSC staff filed its construction audit and prudence review regarding construction expenditures through June 30, 2010, for Iatan No. 2 and the Iatan No. 1 environmental project. The MPSC staff recommended disallowances of approximately $130 million and $70 million of the total costs incurred through June 30, 2010, for Iatan No. 2 and the Iatan No. 1 environmental project ~~respectively, representing all audited expenditures above~~during 2011. GMO also recorded a $1.5 million loss for other disallowed costs in the ~~associated December 2006 control budget estimates of approximately $1.685 billion and $377 million.~~MPSC order.

~~The MPSC staff also filed testimony in KCP&L’s and GMO’s rate cases in November 2010. The MPSC staff’s testimony recommended a return on equity range of 8.5%~~Additionally, with respect to ~~9.5% and revenue increase/(decrease) ranges of approximately $(0.2) million to $14 million for KCP&L, approximately $0.9 million to $10.1 million for~~ GMO’s Missouri Public Service division, the MPSC concluded that GMO’s decision to add Crossroads Energy Center (Crossroads) to its generation asset resources was prudent and reasonable; however, the order disallowed from rate base approximately ~~$28.8~~$50 million for Crossroads, disallowed $4.9 million in associated annual transmission expense and offset rate base by approximately $15 million to ~~$32.6~~reflect accumulated deferred taxes associated with Crossroads. GMO’s request included a net plant amount of approximately $104 million for Crossroads. In assessing the impact of the Crossroads disallowances, management considered that KCP&L’s and GMO’s ~~St. Joseph Light & Power division. On February 22, 2011, the MPSC Staff filed updated testimony recommending the same return on equity range~~generation asset resources include a diverse fuel mix consisting primarily of ~~8.5% to 9.5%~~coal and revenue increase ranges of approximately $2.2 million to $17.0 million for KCP&L, approximately $29,000 to $9.2 million for GMO’s Missouri Public Service division, and approximately $14.9 million to $18.4 million for GMO’s St. Joseph Light & Power division. The revenue recommendations reflect the MPSC staff’s proposed construction cost disallowances of all audited expendituresnuclear fuel providing base load generation with natural gas facilities such as

asCrossroads to provide critical peaking and capacity support. This combined collection of ~~October 31, 2010, above the control budget estimates, among other differences from~~generating assets meets KCP&L’s and GMO’s ~~requests.~~service obligations and produces joint cash flows based on system-wide average costs. Great Plains Energy conducted an analysis to assess the recoverability of the combined collection of generation asset resources and determined that no potential impairment exists.

The rates established by the modified MPSC order took effect on June 25, 2011. On June 24, 2011, GMO filed its appeal of the MPSC order with the Cole County, Missouri, Circuit Court regarding the Crossroads issues discussed above. Other parties to the case have also filed appeals of the MPSC order. However, the rates authorized by the modified MPSC order will be effective unless and until modified by the MPSC or stayed by a court.

~~Hearings were held beginning~~

GMO Fuel Adjustment Clause (FAC) Prudence Review

GMO’s electric retail rates contain an FAC tariff under which 95% of the difference between actual fuel cost, purchased power costs and off-system sales margin and the amount provided in ~~late January 2011~~base rates for ~~KCP&L and ran through mid-February 2011 for GMO.~~these costs is passed along to GMO’s customers. The MPSC ~~Staff will file reconciliations~~requires prudence reviews of the ~~differences between~~FAC no less frequently than at 18-month intervals. On November 28, 2011, the MPSC staff filed its prudence review report for the 18-month prudence review period covering June 1, 2009 through November 30, 2010. The MPSC staff recommended to the MPSC to order GMO to refund approximately $19 million, plus interest, to customers through an adjustment to its FAC because the MPSC staff asserts that GMO was imprudent in its use of natural gas hedges to mitigate risk associated with its future purchases in the spot power market. GMO is disputing the MPSC staff’s claim of imprudence and filed its testimony on February 22, ~~2011, recommendations and KCP&L’s and GMO’s February 22, 2011, recommendations with hearings~~2012. A hearing is scheduled for ~~March 3~~May 16 – ~~4, 2011. New rates are~~17, 2012, with an order expected ~~to go into effect~~ in ~~May 2011 for KCP&L and~~ June ~~2011 for GMO.~~2012.

Transmission Investment Opportunities

In September 2010, GMO accepted a Notification to Construct from SPP for the Missouri portion of a 175-mile, 345kV transmission line in GMO’s service territory from Sibley, Missouri to Nebraska City, ~~Nebraska. Construction of the line is expected to occur over 2012 to 2017,~~Nebraska with an estimated cost of about $380 million for GMO’s portion of the ~~line.~~line and an expected 2017 in-service date. This line is one of a number of priority projects that the SPP has developed as part of its transmission expansion plans for the region. In June 2010, FERC approved the SPP’s proposed cost allocation method for these projects. KCP&L has also accepted a Notification to Construct from SPP for a 30-mile, 345kV transmission line, with estimated construction costs of $54 million and an expected 2015 in-service date, from KCP&L’s Iatan generating station to KCP&L’s Nashua substation. GMO and KCP&L have the obligation to build their separate lines, which may be done solely or with other entities, unless the obligation is transferred to another qualified transmission owner. GMO and KCP&L ~~have not determined which of these~~are evaluating alternative courses of ~~action to pursue.~~action. SPP retains the authority to revise or withdraw existing Notifications to Construct for transmission projects based upon emerging transmission plans and the associated needs for specific projects.

Wolf Creek Outage

On January 13, 2012, a breaker in a substation located at Wolf Creek failed. This failure was immediately followed by a loss of station power to Wolf Creek resulting in an unscheduled shutdown of Wolf Creek. Wolf Creek is expected to resume normal operations in March 2012 following the completion of repairs. This schedule assumes no discovery during the course of repairs of additional required work, and that all requirements of the NRC for resumption of normal operations are satisfied. Additional maintenance expenses and capital expenditures are expected as a result of this unscheduled outage.

ENVIRONMENTAL MATTERS

Electric utility’s current generation capacity is over 50% coal-fired and subject to extensive environmental regulation. Approximately 60% of electric utility’s coal-fired generation facilities have emission control equipment installed. Current plans call for 85% of the coal-fired facilities to have emission control equipment installed by approximately 2016. It is less likely that the remaining coal-fired units will have emission control equipment installed and they have a combined remaining net book value of approximately 1.5% of the Company’s $7.1 billion utility plant balance. In the event that the Company decides it is not cost effective to proceed with these less likely projects and determines that early retirement is the most prudent course of action for these generating facilities, the Company expects that the costs would continue to be capitalized and recovered in rates. However, there is no assurance that these investments would be recovered in rates and any amount not recovered would be recorded as a loss when such loss becomes probable. See Note 14 to the consolidated financial statements for additional information regarding environmental matters.

RELATED PARTY TRANSACTIONS

See Note 1817 to the consolidated financial statements for information regarding related party transactions.

~~ENVIRONMENTAL MATTERS~~

~~See Note 15 to the consolidated financial statements for information regarding environmental matters.~~

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures. Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or different estimates that could have been used could have a material impact on Great Plains Energy’s results of operations and financial position. Management has identified the following accounting policies as critical to the understanding of Great Plains Energy’s results of operations and financial position. Management has discussed the development and selection of these critical accounting policies with the Audit Committee of the Great Plains Energy Board of Directors (Board).

Pensions

Great Plains Energy and KCP&L incur significant costs in providing non-contributory defined pension benefits. The costs are measured using actuarial valuations that are dependent upon numerous factors derived from actual plan experience and assumptions of future plan experience.

Pension costs are impacted by actual employee demographics (including age, life expectancies, compensation levels and employment periods), earnings on plan assets, the level of contributions made to the plan, and plan amendments. In addition, pension costs are also affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

The assumed rate of return on plan assets was developed based on the ~~weighted average~~weighted-average of long-term returns forecast for the expected portfolio mix of investments held by the plan. The assumed discount rate was selected based on the prevailing market rate of fixed income debt instruments with maturities matching the expected timing of the benefit obligation. These assumptions, updated annually at the measurement date, are based on management’s best estimates and judgment; however, material changes may occur if these assumptions differ from actual events. See Note 98 to the consolidated financial statements for information regarding the assumptions used to determine benefit obligations and net costs.

The following table reflects the sensitivities associated with a 0.5% increase or a 0.5% decrease in key actuarial assumptions. Each sensitivity reflects the impact of the change based on a change in that assumption ~~only.~~

only.


				Impact on										Impact on
				Projected			2010							Projected			2011
	Change in			Benefit			Pension			Change in				Benefit			Pension
Actuarial assumption	Assumption			Obligation			Expense			Assumption				Obligation			Expense
				(millions)										(millions)
Discount rate	0.5	%	increase	$	(59.6	)	$	(4.6	)		0.5	%	increase	$	(64.4	)	$	(5.1	)
Rate of return on plan assets	0.5	%	increase		-			(2.6	)		0.5	%	increase		-			(2.8	)
Discount rate	0.5	%	decrease		66.0			5.0			0.5	%	decrease		69.1			5.2
Rate of return on plan assets	0.5	%	decrease		-			2.6			0.5	%	decrease		-			2.8

Pension expense for KCP&L is recorded in accordance with rate orders from the MPSC and KCC. The orders allow the difference between pension costs under GAAP and pension costs for ratemaking to be recorded as a regulatory asset or liability with future ratemaking recovery or refunds, as appropriate. The impact on 2011 pension expense in the table above reflects the impact on GAAP pension costs. Under the Companies’ rate agreements, any increase or decrease would be deferred in a regulatory asset or liability for future ratemaking treatment. KCP&L recorded ~~2010~~2011 pension expense of ~~$40~~$42.6 million after allocations to the other joint owners of generating facilities and capitalized amounts in accordance with the MPSC and KCC rate orders.

GMO records pension expense in accordance with rate orders from the MPSC. The difference between this expense and GAAP expense is recorded as a regulatory asset or liability. See Note 98 to the consolidated financial statements for additional discussion of the accounting for pensions.

The Company's ~~2011~~ projected 2012 weighted average long-term rate of return on plan assets is 7.3%, ~~a 0.7% decrease~~unchanged from ~~2010. The reduction in the rate of return is expected to increase 2011 GAAP pension expense approximately $4 million.~~

2011. Market conditions and interest rates significantly affect the future assets and liabilities of the plan. It is difficult to predict future pension costs, changes in pension liability and cash funding requirements due to volatile market conditions.

Regulatory Matters

Great Plains Energy and KCP&L have recorded assets and liabilities on their consolidated balance sheets resulting from the effects of the ratemaking process, which would not otherwise be recorded under GAAP. Regulatory assets represent incurred costs that are probable of recovery from future revenues. Regulatory liabilities represent future reductions in revenues or refunds to customers.

deregulation in the electric industry or changes in accounting rules. In the event that the criteria no longer applied to all or a portion of electric utility’s operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism iswere provided. Additionally, these factors could result in an impairment on utility plant assets. See Note 65 to the consolidated financial statements for additional information.

Impairments of Assets, Intangible Assets and Goodwill

Long-lived assets and intangible assets subject to amortization are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under GAAP.

Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exists. The goodwill impairment test is a two step process. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill, to identify potential impairment. If the carrying amount exceeds the fair value of the reporting unit, the second step of the test is performed, consisting of assignment of the reporting unit’s fair value to its assets and liabilities to determine an implied fair value of goodwill, which is compared to the carrying amount of goodwill to determine the impairment loss, if any, to be recognized in the financial statements. Great Plains Energy’s regulated electric utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics.

Great Plains Energy’s stock traded at a price below carrying value throughout 2010. If the stock price were to decline substantially further from its current level in relation to carrying value, accounting rules may require Great Plains Energy to conduct additional goodwill impairment tests. There is no assurance that the results of these additional tests will not require Great Plains Energy to recognize an impairment of goodwill.

The annual impairment test for the $169.0 million of GMO acquisition goodwill was conducted on September 1, ~~2010.~~2011. Fair value of the reporting unit exceeded the carrying amount by over ~~$700~~$800 million, including goodwill; therefore, there was no impairment of goodwill.

The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a determination of reporting unit invested capital using market multiples derived from the historical revenue, EBITDA and net utility asset values and market prices of stock of electric and gas company regulated peers. The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit, which involves a significant amount of management judgment.

The discounted cash flow analysis is most significantly impacted by two assumptions: estimated future cash flows and the discount rate applied to those cash flows. Management determined the appropriate discount rate to be based on the reporting unit’s weighted average cost of capital (WACC). The WACC takes into account both the cost of equity and after-tax cost of debt. Estimated future cash flows are based on Great Plains Energy’s internal business plan, which assumes the occurrence of certain events in the future, such as the outcome of future rate filings, future approved rates of return on equity, anticipated earnings/returns related to future capital investments, continued recovery of cost of service and the renewal of certain contracts. Management also makes assumptions regarding the run rate of operations, maintenance and general and administrative costs based on the expected outcome of the aforementioned events. Should the actual outcome of some or all of these assumptions differ significantly from the current assumptions, revisions to current cash flow assumptions could cause the fair value of Great Plains Energy’s reporting unit under the income approach to be significantly different in future periods and could result in a future impairment charge to goodwill.

The market approach analysis is most significantly impacted by management’s selection of relevant electric and gas company regulated peers as well as the determination of an appropriate control premium to be added to the calculated invested capital of the reporting unit, as control premiums associated with a controlling interest are not reflected in the quoted market price of a single share of stock. Management determined an appropriate control

premium by using an average of control premiums for recent acquisitions in the industry. Changes in results of peer companies, selection of different peer companies and future acquisitions with significantly different control premiums could result in a significantly different fair value of Great Plains Energy’s reporting unit.

Income Taxes

Income taxes are accounted for using the asset/liability approach. Deferred tax assets and liabilities are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, applying enacted statutory tax rates in effect for the year in which the differences are expected to reverse. Deferred investment tax credits are amortized ratably over the life of the related property. Deferred tax assets are also recorded for net operating loss, capital loss and tax credit carryforwards. The Company is required to estimate the amount of taxes payable or refundable for the current year and the deferred tax liabilities and assets for future tax consequences of events reflected in the Company’s consolidated financial statements or tax returns. This process requires management to make assessments regarding the timing and probability of the

ultimate tax impact. The Company records valuation allowances on deferred tax assets if it is determined that it is more likely than not that the asset will not be realized.

Additionally, the Company establishes reserves for uncertain tax positions based upon management’s judgment regarding potential future challenges to those positions. The accounting estimates related to the liability for uncertain tax positions require management to make judgments regarding the sustainability of each uncertain tax position based on its technical merits. If it is determined that it is more likely than not a tax position will be sustained based on its technical merits, the impact of the position is recorded in the Company’s consolidated financial statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. Management is also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months. See Note 2120 to the consolidated financial statements for additional information.

GREAT PLAINS ENERGY RESULTS OF OPERATIONS

The following table summarizes Great Plains Energy’s comparative results of operations.


	2011			2010			2009
	(millions)
Operating revenues	$	2,318.0		$	2,255.5		$	1,965.0
Fuel		(483.8	)		(430.7	)		(405.5	)
Purchased power		(203.4	)		(213.8	)		(183.7	)
Transmission of electricity by others		(30.2	)		(27.4	)		(26.9	)
Gross margin (a)		1,600.6			1,583.6			1,348.9
Other operating expenses		(835.0	)		(779.7	)		(726.6	)
Voluntary separation program		(12.7	)		-			-
Depreciation and amortization		(273.1	)		(331.6	)		(302.2	)
Operating income		479.8			472.3			320.1
Non-operating income and expenses		(2.3	)		24.4			42.6
Interest charges		(218.4	)		(184.8	)		(180.9	)
Income tax expense		(84.8	)		(99.0	)		(29.5	)
Loss from equity investments		(0.1	)		(1.0	)		(0.4	)
Income from continuing operations		174.2			211.9			151.9
Loss from discontinued operations		-			-			(1.5	)
Net income		174.2			211.9			150.4
Less: Net (income) loss attributable to noncontrolling interest		0.2			(0.2	)		(0.3	)
Net income attributable to Great Plains Energy		174.4			211.7			150.1
Preferred dividends		(1.6	)		(1.6	)		(1.6	)
Earnings available for common shareholders	$	172.8		$	210.1		$	148.5
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin below.

2011 compared to 2010

Great Plains Energy’s 2011 earnings available for common shareholders decreased to $172.8 million, or $1.25 per share, from $210.1 million, or $1.53 per share in 2010.

Electric utility’s net income decreased $35.4 million in 2011 compared to 2010. Flooding along the Missouri River in 2011 decreased gross margin by an estimated $16 million due to coal conservation activities and increased other operating expenses $3.3 million. Gross margin also decreased due to unfavorable weather and demand, an estimated $11 million expense from the impact of an extended refueling outage at Wolf Creek and $7.5 million from increased coal transportation costs not recovered in KCP&L’s Missouri retail rates. Also in 2011, electric utility recognized $12.7 million of expense related to a voluntary separation program and general

taxes increased $13.1 million driven by higher property taxes. Partially offsetting these decreases were new retail rates in Kansas effective December 1, 2010, and Missouri effective May 4, 2011, for KCP&L and June 25, 2011, for GMO. In 2010, electric utility recognized a $16.8 million pre-tax loss representing KCP&L’s and GMO’s ~~results~~combined share of construction costs for the Iatan No. 1 environmental equipment and the Iatan No. 2 construction project.

Great Plains Energy’s corporate and other activities loss from continuing operations ~~are only included subsequent~~increased $1.9 million in 2011 compared to ~~the July 14, 2008, date of acquisition.~~2010.

2010 2009 2008
(millions)
Operating revenues $ 2,255.5 $ 1,965.0 $ 1,670.1
Fuel (430.7 ) (405.5 ) (311.4 )
Purchased power (213.8 ) (183.7 ) (208.9 )
Transmission of electricity by others (27.4 ) (26.9 ) (22.5 )
Gross margin (a)
1,583.6 1,348.9 1,127.3
Other operating expenses (779.7 ) (726.6 ) (617.3 )
Depreciation and amortization (331.6 ) (302.2 ) (235.0 )
Operating income 472.3 320.1 275.0
Non-operating income and expenses 24.4 42.6 21.1
Interest charges (184.8 ) (180.9 ) (111.3 )
Income tax expense (99.0 ) (29.5 ) (63.8 )
Loss from equity investments (1.0 ) (0.4 ) (1.3 )
Income from continuing operations 211.9 151.9 119.7
Income (loss) from discontinued operations - (1.5 ) 35.0
Net income 211.9 150.4 154.7
Less: Net income attributable to noncontrolling interest (0.2 ) (0.3 ) (0.2 )
Net income attributable to Great Plains Energy 211.7 150.1 154.5
Preferred dividends (1.6 ) (1.6 ) (1.6 )
Earnings available for common shareholders $ 210.1 $ 148.5 $ 152.9
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin below.

2010 compared to 2009

Great Plains Energy’s 2010 earnings available for common shareholders increased to $210.1 million, or $1.53 per share, from $148.5 million, or $1.14 per share in 2009.

Electric utility’s net income increased $77.5 million in 2010 compared to 2009 primarily driven by an increase in gross margin due to new retail rates and favorable weather. Partially offsetting the increase in gross margin were higher ~~operations~~operating and maintenance expenses driven by planned plant outages, increased depreciation and amortization expense due to additional regulatory amortization pursuant to KCP&L’s 2009 rate cases and depreciation from placing in service the Iatan No. 1 environmental equipment during 2009 and Iatan No. 2 during 2010 (Kansas jurisdiction only), increased general taxes and a decrease in the equity component of AFUDC. Electric utility also recorded a $16.8 million pre-tax loss in 2010 representing KCP&L’s and GMO’s combined share of the impact of disallowed construction costs for the Iatan No. 1 environmental equipment and the Iatan No. 2 construction project.

Great Plains Energy’s corporate and other activities had an additional $17.4 million loss from continuing operations in 2010 compared to 2009 primarily due to $7.1 million of after-tax write downs of affordable housing investments and an additional $6.8 million of after-tax interest expense for Equity Units issued in 2009. Additionally, 2009 reflects a $16.0 million tax benefit due to the settlement of GMO’s 2003-2004 tax audit. Partially offsetting these items was the recognition of $3.9 million of deferred tax credits upon the sale of GMO’s former headquarters and $2.4 million of after-tax interest income, net of fees, from an interest refund from the IRS in 2010.

~~2009 compared to 2008~~

Great Plains Energy’s 2009 earnings available for common shareholders decreased to $148.5 million, or $1.14 per share, from $152.9 million, or $1.51 per share in 2008. A higher number of common shares outstanding diluted 2009 earnings per share by $0.33. Great Plains Energy’s significant share issuances were 32.2 million common shares for the acquisition of GMO in July 2008 and 11.5 million common shares in May 2009.

Electric utility’s net income increased $14.7 million in 2009 compared to 2008 reflecting the inclusion of GMO for the full year in 2009. Additionally, an increase in gross margin reflecting new retail rates effective August 1, 2009, and September 1, 2009, for Kansas and Missouri, respectively, an increase in the equity component of AFUDC and decreased income taxes also increased net income. Partially offsetting these increases was increased depreciation expense due to placing the Iatan environmental equipment in service and increased interest expense due to the issuance of new long-term debt in 2009.

Great Plains Energy’s corporate and other activities loss from continuing operations decreased $17.4 million in 2009 compared to 2008 primarily attributable to a $16.0 million tax benefit due to the settlement of GMO’s 2003-2004 tax audit in 2009 partially offset by $11.4 million of after-tax interest expense for Equity Units issued in 2009. Additionally, 2008 reflects a $5.7 million after-tax loss for the change in fair value of interest rate hedges.

Gross Margin

Gross margin is a financial measure that is not calculated in accordance with GAAP. Gross margin, as used by Great Plains Energy and KCP&L, is defined as operating revenues less fuel, purchased power and transmission of electricity by others. Expenses for fuel, purchased power and transmission of electricity by others, offset by wholesale sales margin, are subject to recovery through cost adjustment mechanisms, except for KCP&L’s Missouri retail operations. As a result, operating revenues increase or decrease in relation to a significant portion of these expenses. Management believes that gross margin provides a more meaningful basis for evaluating electric utility’s operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board. The Companies’ definition of gross margin may differ from similar terms used by other companies.

ELECTRIC UTILITY RESULTS OF OPERATIONS

The following table summarizes the electric utility segment results of operations.


	2010			2009			2008			2011			2010			2009
	(millions)									(millions)
Operating revenues	$	2,255.5		$	1,965.0		$	1,670.1		$	2,318.0		$	2,255.5		$	1,965.0
Fuel		(430.7	)		(405.5	)		(311.4	)		(483.8	)		(430.7	)		(405.5	)
Purchased power		(213.8	)		(183.7	)		(209.9	)		(203.4	)		(213.8	)		(183.7	)
Transmission of electricity by others		(27.4	)		(26.9	)		(22.5	)		(30.2	)		(27.4	)		(26.9	)
Gross margin (a)		1,583.6			1,348.9			1,126.3			1,600.6			1,583.6			1,348.9
Other operating expenses		(773.4	)		(712.0	)		(601.7	)		(828.7	)		(773.4	)		(712.0	)
Voluntary separation program											(12.7	)		-			-
Depreciation and amortization		(331.6	)		(302.2	)		(235.0	)		(273.1	)		(331.6	)		(302.2	)
Operating income		478.6			334.7			289.6			486.1			478.6			334.7
Non-operating income and expenses		23.1			37.7			21.3			-			23.1			37.7
Interest charges		(143.1	)		(151.0	)		(96.9	)		(176.9	)		(143.1	)		(151.0	)
Income tax expense		(123.3	)		(63.6	)		(70.9	)		(109.3	)		(123.3	)		(63.6	)
Net income	$	235.3		$	157.8		$	143.1		$	199.9		$	235.3		$	157.8
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great	(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great									(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great
Plains Energy's Results of Operations.	Plains Energy's Results of Operations.									Plains Energy's Results of Operations.

Electric Utility Gross Margin and MWh Sales

The following tables summarize electric utility’s gross margin and MWhs sold.


				%					%							%						%
Gross Margin (a)	2010			Change		2009			Change (b)	2008			2011			Change			2010			Change		2009
Retail revenues	(millions)												(millions)
Residential	$	915.8			19	$	772.6		NM	$	605.5		$	955.8			4		$	915.8			19	$	772.6
Commercial		838.0			11		752.5		NM		620.7			878.8			5			838.0			11		752.5
Industrial		193.5			13		171.9		NM		142.2			196.7			2			193.5			13		171.9
Other retail revenues		17.5			2		17.2		NM		13.3			19.5			11			17.5			2		17.2
Provision for rate refund (excess
Missouri wholesale margin)		(3.7	)	NA			-		NM		(2.9	)
Kansas property tax surcharge														3.7		NA				-		NA			-
Provision for rate refund														(2.9	)		(23	)		(3.7	)	NA			-
Fuel recovery mechanism under recovery		42.9			31		32.8		NM		30.7			50.6			18			42.9			31		32.8
Total retail		2,004.0			15		1,747.0		NM		1,409.5			2,102.2			5			2,004.0			15		1,747.0
Wholesale revenues		205.9			18		174.6		NM		230.1			172.4			(16	)		205.9			18		174.6
Other revenues		45.6			5		43.4		NM		30.5			43.4			(5	)		45.6			5		43.4
Operating revenues		2,255.5			15		1,965.0		NM		1,670.1			2,318.0			3			2,255.5			15		1,965.0
Fuel		(430.7	)		6		(405.5	)	NM		(311.4	)		(483.8	)		12			(430.7	)		6		(405.5	)
Purchased power		(213.8	)		16		(183.7	)	NM		(209.9	)		(203.4	)		(5	)		(213.8	)		16		(183.7	)
Transmission of electricity by others		(27.4	)		2		(26.9	)	NM		(22.5	)		(30.2	)		10			(27.4	)		2		(26.9	)
Gross margin	$	1,583.6			17	$	1,348.9		NM	$	1,126.3		$	1,600.6			1		$	1,583.6			17	$	1,348.9
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains	(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains												(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great Plains
Energy's Results of Operations.	Energy's Results of Operations.
(b) Not meaningful due to the acquisition of GMO on July 14, 2008.

% %
MWh Sales 2010 Change 2009
Change (a)
2008
Retail MWh sales (thousands)
Residential 9,459 9 8,647 NM 7,047
Commercial 10,950 3 10,637 NM 9,227
Industrial 3,286 5 3,143 NM 2,721
Other retail MWh sales 111 (9 ) 122 NM 94
Total retail 23,806 6 22,549 NM 19,089
Wholesale MWh sales 6,534 16 5,626 NM 5,237
Total MWh sales 30,340 8 28,175 NM 24,326
(a) Not meaningful due to the acquisition of GMO on July 14, 2008.


			%					%
MWh Sales	2011		Change			2010		Change			2009
Retail MWh sales	(thousands)
Residential		9,285		(2	)		9,459		9			8,647
Commercial		10,782		(2	)		10,950		3			10,637
Industrial		3,218		(2	)		3,286		5			3,143
Other retail MWh sales		119		8			111		(9	)		122
Total retail		23,404		(2	)		23,806		6			22,549
Wholesale MWh sales		5,491		(16	)		6,534		16			5,626
Total MWh sales		28,895		(5	)		30,340		8			28,175

Electric utility’s residential customers’ usage is significantly affected by weather. Bulk power sales, the major component of wholesale sales, vary with system requirements, generating unit, ~~and~~ purchased power and transmission availability, fuel costs, and requirements of other electric systems. Electric utility’s revenues contain certain fuel recovery mechanisms as follows:

KCP&L’s Kansas retail rates contain an ~~ECA~~Energy Cost Adjustment (ECA) tariff. The ECA tariff reflects the projected annual ~~amount~~amounts of fuel, purchased power, emission allowances, transmission costs and asset-based off-system sales margin. These projected amounts are subject to quarterly re-forecasts. Any difference between the ECA revenue collected and the actual ECA amounts for a given year (which may be positive or negative) is recorded as an increase to or reduction of retail revenues and deferred as a regulatory asset or liability to be recovered from or refunded to Kansas retail customers over twelve months beginning April 1 of the succeeding year.

GMO’s electric retail rates contain ~~an FAC~~a Fuel Adjustment Clause (FAC) tariff under which 95% of the difference between actual fuel cost, purchased power costs and off-system sales margin and the amount provided in base rates for these costs is passed along to GMO’s customers. The FAC cycle consists of an accumulation period of six months beginning in June and December with FAC rate approval requested every six months for a twelve month recovery period. The FAC is recorded as an increase to or reduction of retail revenues and deferred as a regulatory asset or liability to be recovered from or refunded to GMO’s electric retail customers.

GMO’s steam rates contain a ~~QCA~~Quarterly Cost Adjustment (QCA) under which 85% of the difference between actual fuel costs and base fuel costs is passed along to GMO’s steam customers. The QCA is recorded as an increase to or reduction of other revenues and deferred as a regulatory asset or liability to be recovered from or refunded to GMO’s steam customers.

KCP&L’s Missouri retail rates do not contain a fuel recovery mechanism, meaning that changes in fuel and purchased power costs will not be reflected in rates until new rates are authorized by the MPSC creating a regulatory lag between the time costs change and when they are reflected in rates. This regulatory lag applies to all costs not included in fuel recovery mechanisms as described above. In the current rising cost environment, regulatory lag can be expected to have an adverse impact, which could be material, on Great Plains Energy’s results of operations. Additionally, KCP&L’s retail rates in Missouri reflect a set level of non-firm wholesale electric sales margin. KCP&L will not recover any shortfall in non-firm wholesale electric sales margin from the level included in Missouri retail rates and any amount of margin above the level reflected in Missouri retail rates will be returned to KCP&L Missouri retail customers in a future rate case.

Electric utility’s gross margin increased $17.0 million in 2011 compared to 2010 primarily due to new retail rates effective December 1, 2010, and May 4, 2011, for KCP&L in Kansas and Missouri, respectively, and June 25, 2011, for GMO. This increase was partially offset by:

·	unfavorable weather, with a 6% decrease in cooling degree days;

·	a decrease in weather-normalized retail demand;

·	a $7.5 million increase in coal transportation costs not recovered in KCP&L’s Missouri retail rates where there is no fuel recovery mechanism, prior to new retail rates effective May 4, 2011;

·	an estimated $16 million impact of coal conservation activities due to flooding resulting in increased fuel expenses and purchased power expenses and reduced wholesale sales; and

an estimated $11 million impact from an extended refueling outage at Wolf Creek, which resulted in less generation available for wholesale sales, increased fuel expense due to the use of more coal in the fuel mix, which has a higher cost compared to nuclear fuel, and increased purchased power expense due to an increase in MWhs purchased. Wolf Creek’s latest refueling outage began on March 19, 2011, and included several increases in work scope that extended the outage. Primary components of the increased work scope were related to inspection and repair of essential service water system piping, testing and replacement of underground high voltage cables, and a repair of a ground on the main generator rotor. During the last week of June 2011 before the unit returned to full capacity, Wolf Creek had an unplanned outage related to one of two main feed pumps. Wolf Creek returned to 100% capacity in early July 2011.

Electric utility’s gross margin increased $234.7 million in 2010 compared to 2009 primarily due to ~~the increase in retail revenues driven by~~ new retail rates effective August 1, 2009 and September 1, 2009, for Kansas and Missouri, respectively, and favorable weather.

Retail MWhs sold in 2010 increased due to favorable weather, with a 2% increase in heating degree days and a 56% increase in cooling degree days. Cooling degree days were 23% above normal based on a 30-year average. Wholesale MWhs sold increased due to a 9% increase in generation resulting in more MWhs available for sale, partially offset by the higher retail load requirements. The increase in generation was primarily a result of Iatan No. 2 being placed in service during 2010 and Iatan No. 1 being off-line from January through mid-April 2009 to complete an environmental upgrade and unit overhaul, with the expenditures being capitalized and therefore not impacting operating and maintenance expenses. The coal base load equivalent availability factor increased to 82% in 2010 compared to 79% for 2009.

Electric utility’s gross margin increased $222.6 million in 2009 compared to 2008 driven by the inclusion of GMO for a full year and an increase in retail revenues due to new retail rates effective August 1, 2009, and September 1, 2009, for Kansas and Missouri, respectively. The increase to retail revenues was partially offset by a decline in weather-normalized customer usage driven by weakened economic conditions and unfavorable summer weather in 2009, with a 9% decrease in cooling degree days. Cooling degree days were 22% below normal based on a 30-year average.

The following table provides cooling degree days (CDD) and heating degree days (HDD) for the last three years at the Kansas City International Airport. CDD and HDD are used to reflect the demand for energy to cool or heat homes and buildings.


			%				%							%					%
	2010		Change		2009		Change			2008		2011		Change			2010		Change		2009

CDD		1,705		56		1,090		(9	)		1,196		1,598		(6	)		1,705		56		1,090

HDD		5,160		2		5,069		(9	)		5,590		5,220		1			5,160		2		5,069

Electric Utility Other Operating Expenses (including utility operating and maintenance expenses, general taxes and other)

Electric utility’s other operating expenses increased ~~$61.4~~$55.3 million in ~~2010~~2011 compared to ~~2009. Plant~~2010 primarily due to the following:

·	a $23.4 million increase in plant operating and maintenance expenses primarily due to Iatan No. 2 expenses being recognized with Kansas and Missouri rates effective December 1, 2010, and May 4, 2011, respectively, for KCP&L and Missouri rates effective June 25, 2011, for GMO;

·	a $13.1 million increase in general taxes driven by increased property taxes;

·	a $13.1 million increase in pension expense corresponding to the resetting of pension trackers with the effective dates of new retail rates at KCP&L and GMO;

·	a $6.8 million increase in amortization of regulatory assets pursuant to rate orders;

·	$3.3 million of expenses related to the impact of flooding; and

as a result of disallowances in the 2011 MPSC rate orders, KCP&L and GMO recognized combined losses of $2.3 million for construction costs related to Iatan No. 2 and to the Iatan No. 1 environmental project in 2011. KCP&L and GMO also recognized a $3.9 million loss for other disallowed costs in the MPSC rate orders. In 2010, KCP&L and GMO recognized combined losses of $16.8 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project.

Electric utility’s other operating expenses increased ~~$17.8~~$61.4 million in 2010 compared to 2009 primarily ~~driven by planned~~due to the following:

a $17.8 million increase in plant ~~outages, including the impact of outages in 2009 that included capitalizable improvements and therefore did not impact~~ operating and maintenance expenses primarily driven by planned plant outages, including the impact of outages in 2009 that included capitalizable improvements and therefore did not impact operating and maintenance expenses;

·	a $14.8 million increase in general taxes driven by increased gross receipts taxes on increased retail revenues and increased property taxes; and

·	a $5.4 million increase from the accounting effects of the 2010 KCC rate order.

These increases were partially offset by $7.5 million expensed in September 2009 after KCP&L exercised its option to terminate an agreement for the construction of a wind project. The accounting effects of the KCC rate order increased other operating expenses $5.4 million in 2010. General taxes increased $14.8 million in 2010 compared to 2009 driven by increased gross receipts taxes on increased retail revenues and increased property taxes.

Accounting rules state that when it becomes probable that part of the cost of a recently completed plant will be disallowed for rate-making purposes and a reasonable estimate of the amount of the disallowance can be made, the estimated amount of the probable disallowance shall be deducted from the reported cost of the plant and recognized as a loss. As a result of disallowances in the 2010 KCC rate order, KCP&L recognized Kansas jurisdictional losses of $4.4 million for construction costs related to Iatan No. 2 and $2.0 million for construction costs related to the Iatan No. 1 environmental project. Management determined it iswas probable that the MPSC would disallow these costs as well in KCP&L’s and GMO’s pending rate cases. Therefore, KCP&L’s Missouri jurisdictional portion and GMO’s portion of these costs were recognized as a loss in addition to the KCP&L Kansas jurisdictional portion resulting in a $16.8 million pre-tax loss representing KCP&L’s and GMO’s combined share for construction costs incurred through December 31, 2010.

Electric ~~utility’s other operating expenses increased $110.3~~Utility Voluntary Separation Program

In March 2011, Great Plains Energy announced an organizational realignment and voluntary separation program to assist in the management of overall costs within the level reflected in the Company’s retail electric rates and to enhance organizational efficiency. Savings from the realignment process and voluntary separation program, including approximately $15 million in ~~2009 compared~~labor costs on an annual basis, are expected to ~~2008 driven~~partially offset projected cost increases. Under the voluntary separation program, any non-union employee of the Company could voluntarily elect to separate from the Company and receive a severance payment equal to two weeks of salary for every year of employment, with a minimum severance payment equal to fourteen weeks of salary. There were 140 employees that made such elections and the majority separated from the Company on April 30, 2011. Electric utility recorded expense of $12.7 million related to this voluntary separation program reflecting severance and related payroll taxes provided by the ~~inclusion of GMO for a full year, increased employee-related costs and a $7.5 million payment~~Company to terminate an agreement for the construction of a wind project. These increases were partially offset by increased use of internal labor on capital projects as a result of more efficient operations as well as spending reductions and the impact of realized synergiesemployees who elected to voluntarily separate from the ~~GMO acquisition.~~Company.

Electric Utility Depreciation and Amortization

Electric utility’s depreciation and amortization costs decreased $58.5 million in 2011 compared to 2010 primarily due to a $32.7 million decrease attributable to lower depreciation rates for KCP&L and a $58.2 million decrease in regulatory amortization for KCP&L in Kansas and Missouri. These decreases were partially offset by $13.0 million of depreciation for Iatan No. 2, as well as increased depreciation expense for other capital additions.

Electric utility’s depreciation and amortization costs increased $29.4 million in 2010 compared to 2009 primarily due to $14.4 million of additional regulatory amortization pursuant to KCP&L’s 2009 rate cases. The remaining

Electric utility’s depreciation and amortization costs increased $67.2 million in 2009 compared to 2008 driven by the inclusion of GMO for a full year, $10.8 million of additional regulatory amortization pursuant to KCP&L’s 2009 rate cases, the impact of placing Iatan No. 1 and Sibley No. 3 environmental equipment in service during 2009 and normal depreciation activity for other capital additions.

~~Electric~~ Utility Non-Operating Income and Expenses

Electric utility’s non-operating income and expenses decreased $23.1 million in 2011 compared to 2010 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010.

Electric utility’s non-operating income and expenses decreased $14.6 million in 2010 compared to 2009 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects being placed in service.

Electric Utility Interest Charges

Electric utility’s ~~non-operating income and expenses~~interest charges increased ~~$16.4~~$33.8 million in ~~2009~~2011 compared to ~~2008~~2010 primarily due to a ~~$15.4~~$22.7 million ~~increase~~decrease in the ~~equity~~debt component of AFUDC resulting from ~~higher~~a lower average construction work in progress ~~balances~~balance due to Iatan No. 2 being placed in service in the third quarter of 2010, $21.9 million of interest on intercompany notes from Great Plains Energy to GMO issued in August 2010 and ~~the inclusion~~May 2011 and $5.9 million of ~~GMO for a full year.~~interest on 5.30% Senior Notes issued in September 2011. These items were partially offset by repayment of 7.95% Senior Notes, 7.75% Senior Notes and 6.50% Senior Notes in February 2011, June 2011 and November 2011, respectively.

~~Electric Utility Interest Charges~~

Electric utility’s interest charges decreased $7.9 million in 2010 compared to 2009 primarily due to the deferral to a regulatory asset of construction accounting carrying costs for Iatan No. 1, Iatan No. 2 and common facilities and the maturity of $68.5 million of ~~GMO’s~~ 7.625% Senior Notes in December 2009. These decreases were partially offset by a decrease in the debt component of AFUDC resulting from a lower average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects being placed in service, interest for a full year on ~~KCP&L’s~~ $400.0 million of 7.15% Mortgage Bonds Series 2009A issued in March 2009 and interest on an intercompany note from Great Plains Energy to GMO issued in August 2010.

Electric utility’s interest charges increased $54.1 million in 2009 compared to 2008 driven by the inclusion of GMO for a full year, interest on KCP&L’s $400.0 million of Mortgage Bonds Series 2009A issued in March 2009 and interest for a full year on $350.0 million of unsecured Senior Notes issued in March 2008. These increases were partially offset at KCP&L by decreased commercial paper outstanding, decreased rates on commercial paper and an increase in the debt component of AFUDC resulting from a higher average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects.

~~Electric~~ Utility Income Tax Expense

Electric utility’s income tax expense decreased $14.0 million in 2011 primarily due to decreased pre-tax income.

Electric utility’s income tax expense increased $59.7 million in 2010 compared to 2009 due to increased pre-tax income and a $2.8 million increase in income tax expense for the cumulative change in tax treatment of the Medicare Part D subsidy under the Federal health care reform legislation signed into law in 2010.

Electric utility’s income tax expense decreased $7.3 million in 2009 compared to 2008 due to an increase in KCP&L’s deferred tax balances in 2008 of $20.3 million as a result of an increase in the composite tax rate reflecting the 2008 sale of Strategic Energy. Additionally, 2008 reflected $6.7 million of allocated tax benefits from holding company losses. The tax sharing agreement between Great Plains Energy and its subsidiaries was modified on July 14, 2008. As part of the new agreement, parent company tax benefits are no longer allocated to KCP&L or other subsidiaries. The inclusion of GMO for a full year in 2009 also partially offset the decrease in income tax expense.

3839

GREAT PLAINS ENERGY SIGNIFICANT BALANCE SHEET CHANGES ~~(December~~

(December 31, ~~2010~~2011 compared to December 31, ~~2009)~~

·	Great Plains Energy’s accounts receivable pledged as collateral and collateralized note payable of $95.0 million reflects the adoption on January 1, 2010, of new accounting rules for transfers of financial assets. See Note 3 to the consolidated financial statements for additional information.

2010)

Great Plains Energy’s ~~refundable income taxes decreased $11.4~~deferred refueling outage costs increased $17.9 million ~~primarily~~ due to ~~income tax refunds received.~~the deferral of costs for the Wolf Creek refueling outage that began on March 19, 2011, and included several increases in work scope that extended the outage. These deferred costs will be amortized over the months prior to the next refueling outage currently scheduled for the fall of 2012.

Great Plains Energy’s deferred income taxes – current assets decreased ~~$22.5~~$6.8 million primarily due to ~~a reclassification to~~increased temporary differences resulting from increased deferred ~~income taxes – long-term driven by a change in the expected timing of utilizing net operating loss benefits as a result of bonus depreciation available in 2011.~~refueling outage costs.

Great Plains Energy’s ~~assets held for sale decreased $19.4~~current maturities of long-term debt increased $315.7 million due to ~~the sale of two properties with book values of $11.7 million and the~~ reclassification of ~~the remaining properties with book values~~$287.5 million of ~~$7.7 million to other – investments and other assets. See Note 4 to the consolidated financial statements for additional information.~~

Great Plains Energy’s ~~electric utility plant increased $1.7 billion primarily due to $1.3 billion, $103.0 million~~10.00% Equity Units subordinated notes and $76.8 million placed in service for Iatan No. 2, Spearville 2 Wind Energy Facility and the Iatan No. 1 environmental project and certain Iatan facility common costs, respectively, in addition to normal plant activity.

·	~~Great Plains Energy’s construction work in progress decreased $1.2 billion primarily due to projects placed in service as described above, in addition to normal plant activity.~~

·	Great Plains Energy’s affordable housing limited partnerships decreased $12.9 million primarily due to the write down of these investments. See Note 20 to the consolidated financial statements for additional information.

~~Great Plains Energy’s notes payable decreased $242.5 million primarily due to repayment with proceeds from the issuance of $250.0~~$500.0 million of ~~2.75%~~GMO’s 11.875% Senior Notes from long-term debt, partially offset by ~~a $6.9~~the repayment of $137.3 million ~~payment for the settlement~~and $197.0 million of ~~forward starting swaps (FSS)~~GMO’s 7.95% and ~~additional borrowings to support other normal operating activities.~~

·	~~Great Plains Energy’s commercial paper increased $76.9~~7.75% Senior Notes, respectively, and repayment of KCP&L’s $150.0 million ~~primarily due to increased borrowings driven by the timing~~ of ~~cash payments.~~

·	~~Great Plains Energy’s accounts payable decreased $38.7 million primarily due to the timing of cash payments, including payments related to KCP&L’s Comprehensive Energy Plan.~~6.50% Senior Notes at maturity.

Great Plains Energy’s derivative instruments – current liabilities ~~increased $20.5~~decreased $20.8 million ~~primarily~~ due to ~~mark-to-market losses on~~the settlement of Forward Starting Swaps (FSS) upon the issuance of Great Plains Energy’s ~~FSS, which is offset in OCI.~~$350.0 million of 4.85% Senior Notes.

Great Plains Energy’s deferred income taxes – ~~long-term~~deferred credits and other liabilities increased ~~$136.4~~$110.3 million primarily due to a ~~$119.1~~$233.3 million increase in temporary differences mostly as a result of bonus depreciation partially offset by net operating losses created.

Great Plains Energy’s other deferred credits and other liabilities decreased $28.3 million primarily due to a ~~reclassification with deferred income taxes – current assets described above.~~decrease in unrecognized tax benefits related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years.

Great Plains Energy’s long-term debt decreased ~~$270.3~~$200.4 million primarily due to ~~reflect~~reclassification of $287.5 million of Great Plains Energy’s 10.00% Equity Units Subordinated Notes and $500.0 million of GMO’s ~~$137.3 million 7.95%~~11.875% Senior Notes ~~$197.0~~to current maturities and the purchase in lieu of redemption of $112.8 million ~~7.75% Senior Notes and~~of KCP&L’s ~~$150.0 million 6.50% Senior Notes as current maturities. Current maturities of long-term debt increased similarly. Partially offsetting the decrease in long-term debt was~~EIRR bonds, offset by Great Plains Energy’s issuance of ~~$250.0~~$350.0 million of ~~2.75%~~4.85% Senior Notes in ~~August 2010.~~May 2011 and KCP&L’s issuance of $400.0 million of 5.30% Senior Notes in September 2011.

3940

CAPITAL REQUIREMENTS AND LIQUIDITY

Great Plains Energy operates through its subsidiaries and has no material assets other than the stock of its subsidiaries. Great Plains Energy’s ability to make payments on its debt securities and its ability to pay dividends is dependent on its receipt of dividends or other distributions from its subsidiaries, proceeds from the issuance of its securities and borrowing under its revolving credit facility.

Great Plains Energy’s capital requirements are principally comprised of debt maturities and electric utility’s construction and other capital expenditures. These items as well as additional cash and capital requirements are discussed below.

Great Plains Energy's liquid resources at December 31, ~~2010,~~2011, consisted of ~~$10.8~~$6.2 million of cash and cash equivalents on hand and ~~$923.6~~$929.7 million of unused bank lines of credit. The unused lines consisted of ~~$174.7~~$166.4 million from Great Plains Energy's revolving credit facility, ~~$312.1~~$366.5 million from KCP&L's credit facilities and ~~$436.8~~$396.8 million from GMO’s revolving credit facility. At February 22, 2011, Great Plains Energy’s unused bank lines of credit decreased $201.4 million from the amount at December 31, 2010, primarily due to the repayment of GMO’s $137.3 million of 7.95% Senior Notes that matured in February 2011, in addition to the timing of cash payments driven by normal business cycles and operations. See Note 1110 to the consolidated financial statements for more information on these credit facilities. Generally, Great Plains Energy uses these liquid resources to meet its day-to-day cash flow requirements, and from time to time issues equity and/or long-term debt to repay short-term debt or increase cash balances.

Great Plains Energy intends to meet day-to-day cash flow requirements including interest payments, retirement of maturing debt, construction requirements, dividends and pension benefit plan funding requirements with a combination of internally generated funds and proceeds from the issuance of equity securities, equity-linked securities and/or short-term and long-term debt. Great Plains Energy’s intention to meet a portion of these requirements with internally generated funds may be impacted by the effect of inflation on operating expenses, the level of ~~retail~~ MWh sales, regulatory actions, compliance with environmental regulations and the availability of generating units. In addition, Great Plains Energy may issue equity, equity-linked securities and/or debt to finance growth.

At December 31, ~~2010,~~2011, Great Plains Energy’s current maturities of long-term debt ~~maturities in 2011 and~~were $801.4 million. In January 2012, ~~were $485.7 million and $513.9 million, respectively. In February 2011, repayment of GMO’s $137.3~~KCP&L repaid $12.4 million of ~~7.95%~~4.00% EIRR bonds at maturity. Great Plains Energy’s $287.5 million of Equity Units subordinated notes mature in 2042 but must be remarketed by June 12, 2012. GMO’s $500.0 million of 11.875% Senior Notes ~~that matured~~mature in ~~February 2011 reduced the 2011 long-term debt maturities to $348.4 million.~~July 2012 and Great Plains Energy is evaluating alternatives to refinance ~~the remaining long-term debt, including issuing new~~this long-term debt. Based on current market conditions and Great Plains Energy’s unused bank lines of credit, Great Plains Energy expects to have the ability to access the markets to complete the necessary refinancing.

Cash Flows from Operating Activities

Great Plains Energy generated positive cash flows from operating activities for the periods presented. The decrease in cash flows from operating activities for Great Plains Energy in 2011 compared to 2010 is primarily due to a reduction in net income, the payment of $26.1 million for the settlement of FSS upon the issuance of $350.0 million of 4.85% Senior Notes in May 2011, an increase in pension and postretirement benefit funding and an increase in deferred refueling outage costs, partially offset by the adoption of new accounting rules in 2010. On January 1, 2010, Great Plains Energy adopted new accounting rules for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivable pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s balance sheet at December 31, 2010. See Note 3 for additional information. As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash in 2010.

The increase in cash flows from operating activities for Great Plains Energy in 2010 compared to 2009 is primarily due to an increase in net income, an increase in deferred income taxes from utilizing bonus depreciation, which defers the cash payment for taxes on current year income, and a decrease in cash flows for accounts payable due to the completion of significant construction projects. On January 1, 2010, Great Plains Energy adopted new accounting rules for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts receivables pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s balance sheet at December 31, 2010. See Note 3 for additional information. As a result, cashCash flows from operating activities were reduced by $95.0 million and cash flow from financing activities were raised by $95.0 million with no impact to

the net change in cash in ~~2010.~~2010 from the adoption of new accounting rules for transfers of financial assets as discussed above. Additionally, cash flows from operating activities in 2009 reflect the payment of $79.1 million for the settlement of FSS upon the issuance of $400.0 million of 7.15% Mortgage Bonds Series 2009A. ~~Other changes in working capital are detailed in Note 2 to the consolidated financial statements. The individual components of working capital vary with normal business cycles and operations.~~

The decrease in cash flows from operating activities for Great Plains Energy in 2009 compared to 2008 is primarily due to a decrease in accounts payable due to the timing of cash payments and completing significant construction projects and the payment of $79.1 million for the settlement of FSS upon the issuance of $400.0 million of 7.15% Mortgage Bonds Series 2009A in 2009. Partially offsetting these decreases was KCP&L’s 2008 payment of $41.2 million for the settlement of three Treasury Locks (T-Locks). Additionally, 2008 cash flows from operating activities include Strategic Energy. Great Plains Energy sold Strategic Energy in 2008. Other changes in working capital are detailed in Note 2 to the consolidated financial statements. The individual components of working capital vary with normal business cycles and operations.

Cash Flows from Investing Activities

Great Plains Energy’s cash used for investing activities varies with the timing of utility capital expenditures and purchases of investments and nonutility property. Investing activities are offset by the proceeds from the sale of properties and insurance recoveries.

Great Plains Energy’s utility capital expenditures decreased $161.4 million in 2011 compared to 2010 due to a decrease in cash utility capital expenditures primarily related to Iatan No. 2.

Great Plains Energy’s utility capital expenditures decreased $223.1 million in 2010 compared to 2009 due to a decrease in cash utility capital expenditures primarily related to the Iatan No. 1 environmental project, Iatan No. 2 and Spearville 2 Wind Energy Facility.

Great Plains Energy’s utility capital expenditures decreased $182.6 million in 2009 compared to 2008 due to a decrease in KCP&L’s cash utility capital expenditures primarily related to the Iatan No. 1 environmental project and Iatan No. 2.

In 2008, Great Plains Energy completed the sale of Strategic Energy and received gross cash proceeds of $307.7 million. At the time of the sale, Strategic Energy had $88.9 million of cash, resulting in proceeds from the sale of Strategic Energy, net of cash sold of $218.8 million.

On July 14, 2008, Great Plains Energy closed its acquisition of GMO. Great Plains Energy paid cash consideration of $0.7 billion. At the time of the acquisition, GMO had approximately $1.0 billion of cash from the sale of its electric and gas utility assets in Colorado, Kansas, Nebraska and Iowa to Black Hills.

Cash Flows from Financing Activities

Great Plains Energy’s cash flows from financing activities in 2011 reflect the issuance, at a discount, of $350.0 million of 4.85% Senior Notes that mature in 2021. Great Plains Energy used the proceeds to make a ten-year intercompany loan to GMO with GMO using the proceeds to repay $137.3 million of 7.95% Senior Notes and $197.0 million of 7.75% Senior Notes at maturity. KCP&L purchased in lieu of redemption its $63.3 million EIRR Series 2007A-1, $10.0 million EIRR Series 2007A-2 and $39.5 million EIRR Series 1993B bonds. Also reflected is KCP&L’s issuance, at a discount, of $400.0 million of 5.30% Senior Notes that mature in 2041. KCP&L used the proceeds to repay short-term borrowings and its $150.0 million of 6.50% Senior Notes at maturity.

Great Plains Energy’s cash flows from financing activities in 2010 reflect the issuance, at a discount, of $250.0 million of 2.75% Senior Notes that mature in 2013. Great Plains Energy used the proceeds to make a three-year intercompany loan to GMO with GMO using the proceeds to repay short-term borrowings. Also reflected is the $95.0 million impact of the short-term collateralized note payable described above under cash flows from operating activities.

Great Plains Energy’s cash flows from financing activities in 2009 reflect gross proceeds of $161.0 million from the issuance of 11.5 million shares of common stock at ~~$14~~$14.00 per share and gross proceeds of $287.5 million from the issuance of 5.8 million Equity Units. See Note 1211 to the consolidated financial statements for more information on the Equity Units. Also reflected in the cash flows from financing activities in 2009 is KCP&L’s issuance, at a discount, of $400.0 million of Mortgage Bonds Series 2009A that mature in 2019. Additionally, Great Plains Energy sold 3.8 million shares of common stock for $50.0 million in gross proceeds under a Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC (BNYMCM). Great Plains Energy paid $22.8 million in 2009 for fees related to all issuances of debt and common stock. The proceeds from these issuances were used primarily to repay short-term borrowings.

Great Plains Energy’s cash flows from financing activities in 2008 reflect KCP&L’s issuance of $350.0 million of unsecured Senior Notes that mature in 2018. The proceeds were used to repay short-term borrowings. GMO repaid $169.0 million on a credit agreement that was terminated in 2008 and subsequently borrowed $110.0 million under its new revolving credit facility. Additionally, GMO terminated various other credit agreements and paid $12.5 million of termination fees.

4142

Impact of Credit Ratings on Liquidity

The ratings of Great Plains Energy’s, KCP&L’s and GMO’s securities by the credit rating agencies impact their liquidity, including the cost of borrowings under their revolving credit agreements and in the capital markets. The Companies view maintenance of strong credit ratings as extremely important to their access to and cost of debt financing and to that end maintain an active and ongoing dialogue with the agencies with respect to results of operations, financial position, and future prospects. While a decrease in these credit ratings would not cause any acceleration of Great Plains Energy’s, KCP&L’s or GMO’s debt, it could increase interest charges under Great Plains Energy’s 6.875% Senior Notes due 2017, GMO’s 11.875% Senior Notes due 2012, ~~GMO’s 7.95% Senior Notes due 2011~~ and Great Plains Energy’s, KCP&L’s and GMO’s revolving credit agreements. A decrease in credit ratings could also have, among other things, an adverse impact, which could be material, on Great Plains Energy’s, KCP&L’s and GMO’s access to capital, the cost of funds, the ability to recover actual interest costs in state regulatory proceedings, the type and amounts of collateral required under supply agreements and Great Plains Energy’s ability to provide credit support for its subsidiaries.

At December 31, ~~2010,~~2011, the major credit rating agencies rated Great Plains Energy’s and KCP&L’s securities as detailed in the following table.


	Moody's	Standard
	Investors Service	& Poor's
Great Plains Energy
Outlook	Stable	Stable
Corporate Credit Rating	-	BBB
Preferred Stock	Ba2	BB+
Senior Unsecured Debt	Baa3	BBB-

KCP&L
Outlook	Stable	Stable
Senior Secured Debt	A3	BBB+
Senior Unsecured Debt	Baa2	BBB
Commercial Paper	P-2	A-2

GMO
Outlook	Stable	Stable
Senior Unsecured Debt (a)	Baa3	BBB
Commercial Paper (a)	P-3	A-2
(a) reflects Great Plains Energy guarantee

A securities rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.

Financing Authorization

Under stipulations with the MPSC and KCC, Great Plains Energy and KCP&L maintain common equity at not less than 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). KCP&L’s long-term financing activities are subject to the authorization of the MPSC. In March 2010, the MPSC authorized KCP&L to issue up to $450.0 million of long-term debt and to enter into interest rate hedging instruments in connection with such debt through December 31, 2011. KCP&L ~~had not~~ utilized ~~any~~$400.0 million of this ~~authorized~~ amount aswith the issuance in September 2011 of 5.30% unsecured Senior Notes maturing in 2041. In December 2011, KCP&L filed a request with the MPSC for authorization to issue up to $300.0 million of long-term debt and enter into interest rate hedging instruments in connection with such debt through December 31, ~~2010.~~2013. This authorization would replace the authorization which expired on December 31, 2011.

In December 2010, FERC authorized KCP&L to have outstanding at any time up to a total of $1.0 billion in short-term debt instruments through December 2012, conditioned on KCP&L’s borrowing costs not exceeding the greater of: (i) 4.25% over LIBOR; (ii) the greater of 2.25% over the prime rate, 2.75% over the federal funds rate, and 3.25% over LIBOR; or (iii) 4.25% over the A2/P-2 nonfinancial commercial paper rate most recently published by the Federal Reserve at the time of the borrowing. The authorization is subject to four restrictions: (i)

proceeds of debt backed by utility assets must be used for utility purposes; (ii) if any utility assets that secure authorized debt are divested or spun off, the debt must follow the assets and also be divested or spun off; (iii) if any proceeds of the authorized debt are used for non-utility purposes, the debt must follow the non-utility assets (specifically, if the non-utility assets are divested or spun off, then a proportionate share of the debt must follow the divested or spun off non-utility assets); and (iv) if utility assets financed by the authorized short-term debt are divested or spun off to another entity, a proportionate share of the debt must also be divested or spun off. At December 31, ~~2010,~~2011, there was ~~$736.5~~$773.0 million available under this authorization.

In March 2010, and modified in April 2010, FERC authorized GMO to have outstanding at any time up to a total of $500.0 million ofin short-term debt ~~authorization~~instruments through March 2012, conditioned on GMO’s borrowing costs not exceeding 4.3% over LIBOR, the prime rate or federal funds rate, as applicable, and subject to the same four restrictions as the KCP&L FERC short-term authorization discussed in the preceding paragraph. At December 31, ~~2010,~~2011, there was ~~$500.0~~$460.0 million available under this authorization. In ~~July 2010,~~January 2012, FERC authorized GMO to ~~issue~~have outstanding at any time up to a total of ~~$850.0~~$750.0 million in short-term debt instruments through March 2014, conditioned on GMO’s borrowing costs not exceeding the greater of ~~long-term debt, including intercompany debt, through July 2012~~2.25% over LIBOR or 1.75% over the prime rate or federal funds rate, as applicable, and subject to the same four restrictions as the KCP&L FERC short-term authorization discussed in the preceding paragraph. This authorization will become effective and replace the current authorization when it expires in March 2012.

In November 2011, FERC authorized GMO to issue up to a total of $850.0 million of long-term debt through December 2013. At December 31, ~~2010,~~2011, there was ~~$601.2~~$850.0 million available under this authorization.

KCP&L and GMO are also authorized by FERC to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO. At December 31, ~~2010, GMO had an outstanding payable of $12.1 million to KCP&L and~~2011, KCP&L had an outstanding payable under the money pool of ~~$2.0~~$8.5 million to Great Plains Energy.

Significant Financing Activities

Great Plains Energy

Great Plains Energy has an effective shelf registration statement for the sale of unspecified amounts of securities with the SEC that was filed and became effective in May ~~2009.~~2009 and expects to file a new shelf registration statement prior to the May 2012 expiration of its current one.

In May 2011, Great Plains Energy issued $350.0 million of 4.85% unsecured Senior Notes, maturing in 2021. Great Plains Energy settled six FSS simultaneously with the issuance of the debt and paid $26.1 million in cash for the settlement.

In August 2010, Great Plains Energy issued $250.0 million of 2.75% Senior Notes, maturing in 2013. Great Plains Energy settled two FSS simultaneously with the issuance of the three-year long-term debt and paid $6.9 million in cash for the settlement.

In May 2009, Great Plains Energy issued 11.5 million shares of common stock at $14.00 per share with $161.0 million in gross proceeds and 5.8 million Equity Units with gross proceeds of $287.5 million. See Note 1211 to the consolidated financial statements for ~~more~~additional information on the Equity Units.

In August 2008, Great Plains Energy entered into a Sales Agency Financing Agreement with BNYMCM. Under the terms of the agreement, Great Plains Energy may offer and sell up to 8.0 million shares of its common stock from time to time through BNYMCM, as agent, for a period of no more than three years. Great Plains Energy will pay BNYMCM a commission equal to 1% of the sales price of all shares sold under the agreement. During 2009, 3.8 million shares were sold for $49.5 million in net proceeds through BNYMCM. During 2008, 0.2 million shares were sold for $3.5 million in net proceeds.

KCP&L

KCP&L has an effective shelf registration statement providing for the sale of unspecified amounts of investment grade notes and general mortgage bonds with the SEC that was filed and became effective in May ~~2009.~~2009 and expects to file a new shelf registration statement prior to the May 2012 expiration of its current one.

In September 2011, KCP&L issued $400.0 million of 5.30% unsecured Senior Notes, maturing in 2041.

In March 2009, KCP&L issued $400.0 million of 7.15% Mortgage Bonds Series 2009A, maturing in 2019. KCP&L settled FSS simultaneously with the issuance of its $400.0 million 10-year long-term debt and paid $79.1 million in cash for the settlement.

In March 2008, KCP&L issued $350.0 million of 6.375% unsecured Senior Notes, maturing in 2018. KCP&L settled three T-Locks simultaneously with the issuance of its $350.0 million 10-year long-term debt and paid $41.2 million in cash for the settlement.

In May 2008, KCP&L’s Series 2008 EIRR bonds totaling $23.4 million maturing in 2038 were issued. The bonds have an initial long-term interest rate of 4.90% until June 30, 2013. At the end of the initial long-term interest rate period, the bonds are subject to remarketing and mandatory tender; however, KCP&L is not obligated to pay the purchase price of the bonds on the mandatory tender date. If the bonds are not successfully remarketed, the bonds will bear interest at a daily rate equal to 10% per annum until all of the bonds are successfully remarketed.

Debt Agreements

See Note 1110 to the consolidated financial statements for ~~discussion of~~information regarding revolving credit facilities.

Projected Utility Capital Expenditures

Great Plains Energy’s cash utility capital expenditures, excluding AFUDC to finance construction, were $456.6 million, $618.0 million and $841.1 million in 2011, 2010 and ~~$1,023.7 million in 2010,~~ 2009, ~~and 2008,~~ respectively. Utility capital expenditures projected for the next three years, excluding AFUDC, are detailed in the following table. This utility capital expenditure plan is subject to continual review and change.


	2011		2012		2013		2012		2013		2014
	(millions)						(millions)
Generating facilities (excluding construction of Iatan No. 2)	$	172.2	$	174.6	$	171.8
Generating facilities							$	202.4	$	245.6	$	229.6
Distribution and transmission facilities(a)		171.0		178.9		232.2		186.4		212.0		185.8
SPP balanced portfolio and priority transmission projects								4.2		42.2		70.9
General facilities		29.2		63.2		44.6		42.1		53.8		34.6
Nuclear fuel		14.8		26.2		31.5		20.8		40.1		25.3
Environmental		63.0		171.0		219.1		178.1		189.3		127.3
Construction of Iatan No. 2		53.1		-		-
Total utility capital expenditures	$	503.3	$	613.9	$	699.2	$	634.0	$	783.0	$	673.5

(a) Excludes SPP balanced portfolio and priority transmission projects

Pensions

The Company maintains defined benefit plans for substantially all active and inactive employees of KCP&L, GMO and WCNOC and incurs significant costs in providing the plans. Funding of the plans follows legal and regulatory requirements with funding equaling or exceeding the minimum requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA).

In ~~2010~~2011 and ~~2009,~~2010, the Company contributed ~~$64.5~~$128.8 million and ~~$42.1~~$64.5 million to the pension plans, respectively, and in ~~2011~~2012 the Company expects to contribute ~~$104.6~~$94.5 million to the plans to satisfy the ERISA funding requirements and the MPSC and KCC rate orders, with the majority paid by KCP&L. Additional contributions to the plans are expected beyond ~~2011~~2012 in amounts at least sufficient to meet the greater of ERISA or regulatory funding requirements; however, these amounts have not yet been determined.

Additionally, the Company provides post-retirement health and life insurance benefits for certain retired employees and expects to make benefit contributions of ~~$15.8~~$16.7 million under the provisions of these plans in ~~2011,~~2012, with the majority paid by KCP&L.

Management believes the Company has adequate access to capital resources through cash flows from operations or through existing lines of credit to support these funding requirements.

4445

Supplemental Capital Requirements and Liquidity Information

The information in the following table is provided to summarize Great Plains Energy’s cash obligations and commercial commitments.


Payment due by period	Payment due by period	2011		2012		2013		2014		2015		After 2015		Total		Payment due by period	2012		2013		2014		2015		2016		After 2016		Total
Long-term debt	Long-term debt	(millions)														Long-term debt	(millions)
	Principal	$	485.7	$	513.9	$	263.1	$	1.5	$	15.5	$	2,101.3	$	3,381.0	Principal	$	801.4	$	263.1	$	1.5	$	15.5	$	1.6	$	2,449.2	$	3,532.3
	Interest		227.2		180.5		147.7		127.2		113.5		794.9		1,591.0	Interest		242.1		182.3		160.4		145.6		145.2		1,215.5		2,091.1
Lease commitments	Lease commitments															Lease commitments
	Operating lease		17.9		16.8		15.0		14.3		13.5		129.4		206.9	Operating lease		19.7		16.3		14.8		13.6		9.8		119.2		193.4
	Capital lease		0.4		0.4		0.4		0.4		0.4		5.5		7.5	Capital lease		0.4		0.4		0.4		0.4		0.4		4.7		6.7
Pension and other post-retirement plans (a)	Pension and other post-retirement plans (a)		120.4		120.4		120.4		120.4		120.4		N/A		602.0	Pension and other post-retirement plans (a)		111.2		111.2		111.2		111.2		111.2		N/A		556.0
Purchase commitments	Purchase commitments															Purchase commitments
	Fuel		348.7		282.7		287.7		164.8		108.8		125.3		1,318.0	Fuel		397.4		360.5		202.0		103.9		83.2		94.1		1,241.1
	Purchased capacity		20.3		13.4		12.4		4.5		4.2		2.4		57.2	Power		8.5		29.2		34.8		34.8		34.8		686.3		828.4
	Non-regulated natural gas															Capacity		13.4		12.4		4.5		4.2		2.4		-		36.9
	transportation		4.6		2.9		2.9		2.9		2.9		3.4		19.6	La Cygne environmental project		376.6		300.2		125.4		5.5		-		-		807.7
	Other		163.4		17.6		6.8		8.1		2.7		55.1		253.7	Non-regulated natural gas
																transportation		2.8		3.6		3.6		3.6		3.6		0.9		18.1
																Other		54.4		101.7		21.0		25.4		3.7		49.8		256.0
Total contractual commitments (a)	Total contractual commitments (a)	$	1,388.6	$	1,148.6	$	856.4	$	444.1	$	381.9	$	3,217.3	$	7,436.9	Total contractual commitments (a)	$	2,027.9	$	1,380.9	$	679.6	$	463.7	$	395.9	$	4,619.7	$	9,567.7

(a)	The Company expects to make contributions to the pension and other post-retirement plans beyond 2011 but the amounts															The Company expects to make contributions to the pension and other post-retirement plans beyond 2012 but the amounts
	are not yet determined. Amounts for years after 2011 are estimates based on information available in determining the amount															are not yet determined. Amounts for years after 2012 are estimates based on information available in determining the amount
	for 2011. Actual amounts for years after 2011 could be significantly different than the estimated amounts in the table above.															for 2012. Actual amounts for years after 2012 could be significantly different than the estimated amounts in the table above.

Long-term debt includes current maturities. Long-term debt principal excludes ~~$2.5~~$4.9 million of discounts on senior notes. Variable rate interest obligations are based on rates as of December 31, ~~2010.~~2011. Equity Units subordinated notes totaling $287.5 million mature in 2042 but must be remarketed ~~between December 15, 2011 and~~by June 12, 2012. In connection with a successful remarketing of the notes, Great Plains Energy may elect, without the consent of any of the holders, to modify the notes’ stated maturity to any date on or after June 15, 2014 and earlier than June 15, 2042. If the notes have not been successfully remarketed by June 12, 2012, the holders of all notes will have the right to put their notes to Great Plains Energy on June 15, 2012, in payment of the associated common stock purchase contracts and Great Plains Energy will issue to the holders newly issued shares of the Company’s common stock. Interest on the Equity Units subordinated notes is included up to June 15, 2014. See Note 1211 to the consolidated financial statements for additional information.

Great Plains Energy has expected sublease income of ~~$2.0~~$1.2 million for the years ~~2011-2013.~~2012-2013. Lease commitments end in ~~2032~~2048 and include capital and operating lease obligations. Lease obligations also include railcars to serve jointly-owned generating units where KCP&L is the managing partner. Of the amounts included in the table above, KCP&L will be reimbursed by the other owners for approximately ~~$2.0~~$2.2 million per year ~~($13.7~~from 2012 to 2015 and then $0.4 million ~~total)~~per year from 2016 to 2025, for a total of ~~the amounts included in the table above.~~$13.0 million.

The Company expects to contribute ~~$120.4~~$111.2 million to the pension and other post-retirement plans in ~~2011,~~2012, of which the majority is expected to be paid by KCP&L. Additional contributions to the plans are expected beyond ~~2011~~2012 in amounts at least sufficient to meet the greater of ERISA or regulatory funding requirements; however, these amounts have not yet been determined. Amounts for years after ~~2011~~2012 are estimates based on information available in determining the amount for ~~2011.~~2012. Actual amounts for years after ~~2011~~2012 could be significantly different than the estimated amounts in the table above.

Fuel commitments consist of commitments for nuclear fuel, coal and coal transportation costs. Power commitments consist of commitments for renewable energy under power purchase agreements. KCP&L and GMO purchase capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to

purchase energy if needed or when market prices are favorable. KCP&L has capacity sales agreements not included above that total ~~$6.9 million for 2011,~~ $3.8 million for 2012 and $1.6 million for 2013. La Cygne environmental project represents contractual commitments related to environmental upgrades at KCP&L’s La Cygne station. KCP&L owns 50% of the La Cygne station and expects to be reimbursed by the other owner for its 50% share of the costs. Non-regulated

natural gas transportation consists of MPS Merchant’s commitments. Other represents individual commitments entered into in the ordinary course of business.

At December 31, ~~2010,~~2011, the total liability for unrecognized tax benefits for Great Plains Energy was ~~$42.0~~$24.0 million, which is not included in the table above. Great Plains Energy is unable to determine reasonably reliable estimates of the period of cash settlement with the respective taxing authorities. See Note 2120 to the consolidated financial statements for information regarding the recognition of tax benefits in the next twelve months, which is not expected to have a cash impact.

Great Plains Energy has other insignificant long-term liabilities recorded on its consolidated balance sheet at December 31, ~~2010, that~~2011, which do not have a definitive cash payout date and are not included in the table above.

Off-Balance Sheet Arrangements

In the ordinary course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees and ~~stand-by~~ letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended business purposes.

The majority of these agreements guarantee the Company’s own future performance, so a liability for the fair value of the obligation is not recorded.

At December 31, ~~2010,~~2011, Great Plains Energy has provided ~~$1,030.4~~$666.0 million of credit support for GMO as follows:

·	Great Plains Energy direct guarantees to GMO counterparties totaling ~~$65.4~~$40.7 million, of which ~~$45.4 million expire in 2011 and $20.0 million~~ expire in 2012,

·	Great Plains Energy letters of credit to GMO counterparties totaling ~~$15.8~~$11.6 million , which expire in ~~2011,~~2012, and

·	Great Plains Energy guarantees of GMO long-term debt totaling ~~$949.2~~$613.7 million, which includes debt with maturity dates ranging from ~~2011-2023.~~2012-2023.

Great Plains Energy has also guaranteed GMO’s $450 million revolving line of credit ~~dated August 9, 2010,~~ with a group of banks as amended December 2011 and expiring ~~August 9, 2013.~~in December 2016. At December 31, ~~2010,~~2011, GMO had no$40.0 million of commercial paper outstanding, ~~cash borrowings and~~ had issued letters of credit totaling $13.2 million and had no outstanding cash borrowings under this credit facility.

None of the guaranteed obligations are subject to default or prepayment as a result of a downgrade of GMO’s credit ratings, although such a downgrade has in the past, and could in the future, increase interest charges under GMO’s 11.875% Senior Notes due 2012 and ~~7.95% Senior Notes due 2011, as well as GMO’s~~ revolving line of credit.

At December 31, ~~2010,~~2011, KCP&L had issued letters of credit totaling ~~$24.4~~$21.5 million as credit support to certain counterparties.

KCP&L has ~~guarantees related to~~ bond insurance policies for its secured 1992 ~~series~~Series EIRR bonds totaling $31.0 million, Series 1993A ~~and 1993B EIRR~~ bonds totaling ~~$79.5~~$40.0 million, EIRR Bond Series 2005 totaling $85.9 million and EIRR Bonds Series ~~2007A and~~ 2007B totaling ~~$146.5~~$73.2 million. The insurance agreement between KCP&L and the issuer of the bond insurance policies provides for reimbursement by KCP&L for any amounts the insurer pays under the bond insurance policies. As the insurers’ credit ratings are below KCP&L’s credit ratings, the bonds are rated at KCP&L’s credit ratings.

4647

KANSAS CITY POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

The following table summarizes KCP&L's consolidated comparative results of operations.


	2010			2009			2008			2011			2010			2009
	(millions)									(millions)
Operating revenues	$	1,517.1		$	1,318.2		$	1,343.0		$	1,558.3		$	1,517.1		$	1,318.2
Fuel		(278.8	)		(251.3	)		(253.3	)		(333.5	)		(278.8	)		(251.3	)
Purchased power		(78.9	)		(70.8	)		(119.0	)		(70.8	)		(78.9	)		(70.8	)
Transmission of electricity by others		(15.0	)		(12.3	)		(11.1	)		(18.8	)		(15.0	)		(12.3	)
Gross margin (a)		1,144.4			983.8			959.6			1,135.2			1,144.4			983.8
Other operating expenses		(576.6	)		(522.0	)		(517.2	)		(611.7	)		(576.6	)		(522.0	)
Voluntary separation program											(9.2	)		-			-
Depreciation and amortization		(256.4	)		(229.6	)		(204.3	)		(193.1	)		(256.4	)		(229.6	)
Operating income		311.4			232.2			238.1			321.2			311.4			232.2
Non-operating income and expenses		19.1			28.5			19.2			(1.0	)		19.1			28.5
Interest charges		(85.7	)		(84.9	)		(72.3	)		(115.6	)		(85.7	)		(84.9	)
Income tax expense		(81.6	)		(46.9	)		(59.8	)		(69.1	)		(81.6	)		(46.9	)
Net income	$	163.2		$	128.9		$	125.2		$	135.5		$	163.2		$	128.9
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great	(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great									(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great
Plains Energy's Results of Operations.	Plains Energy's Results of Operations.									Plains Energy's Results of Operations.

KCP&L Gross Margin and MWh Sales

The following tables summarize KCP&L’s gross margin and MWhs sold.


				%					%									%						%
Gross Margin (a)	2010			Change		2009			Change			2008			2011			Change			2010			Change		2009
Retail revenues	(millions)														(millions)
Residential	$	564.5			20	$	472.2			2		$	463.0		$	593.0			5		$	564.5			20	$	472.2
Commercial		604.3			11		542.7			4			521.1			637.8			6			604.3			11		542.7
Industrial		122.8			13		108.8			(1	)		109.9			121.9			(1	)		122.8			13		108.8
Other retail revenues		11.7			9		10.9			2			10.6			12.5			5			11.7			9		10.9
Provision for rate refund (excess
Missouri wholesale margin)		(3.7	)	NA			-		NA				(2.9	)
Kansas property tax surcharge																3.7		NA				-		NA			-
Provision for rate refund																-		NM				(3.7	)	NA			-
Kansas ECA (over) under recovery		8.7		NM			(0.7	)	NM				1.6			11.7			35			8.7		NM			(0.7	)
Total retail		1,308.3			15		1,133.9			3			1,103.3			1,380.6			6			1,308.3			15		1,133.9
Wholesale revenues		188.9			14		166.2			(25	)		221.5			159.4			(16	)		188.9			14		166.2
Other revenues		19.9			10		18.1			(1	)		18.2			18.3			(8	)		19.9			10		18.1
Operating revenues		1,517.1			15		1,318.2			(2	)		1,343.0			1,558.3			3			1,517.1			15		1,318.2
Fuel		(278.8	)		11		(251.3	)		(1	)		(253.3	)		(333.5	)		20			(278.8	)		11		(251.3	)
Purchased power		(78.9	)		11		(70.8	)		(40	)		(119.0	)		(70.8	)		(10	)		(78.9	)		11		(70.8	)
Transmission of electricity by others		(15.0	)		22		(12.3	)		11			(11.1	)		(18.8	)		25			(15.0	)		22		(12.3	)
Gross margin	$	1,144.4			16	$	983.8			3		$	959.6		$	1,135.2			(1	)	$	1,144.4			16	$	983.8
(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great	(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great														(a) Gross margin is a non-GAAP financial measure. See explanation of gross margin under Great
Plains Energy's Results of Operations.	Plains Energy's Results of Operations.

4748


			%				%							%					%
MWh Sales	2010		Change		2009		Change			2008		2011		Change			2010		Change		2009
Retail MWh sales	(thousands)											(thousands)
Residential		5,719		10		5,203		(4	)		5,413		5,624		(2	)		5,719		10		5,203
Commercial		7,705		3		7,506		(3	)		7,704		7,614		(1	)		7,705		3		7,506
Industrial		1,956		4		1,884		(9	)		2,061		1,884		(4	)		1,956		4		1,884
Other retail MWh sales		87		-		88		9			80		88		1			87		-		88
Total retail		15,467		5		14,681		(4	)		15,258		15,210		(2	)		15,467		5		14,681
Wholesale MWh sales		6,051		12		5,381		7			5,030		5,165		(15	)		6,051		12		5,381
Total MWh sales		21,518		7		20,062		(1	)		20,288		20,375		(5	)		21,518		7		20,062

KCP&L’s gross margin decreased $9.2 million in 2011 compared to 2010 primarily due to:

·	unfavorable weather, with a 6% decrease in cooling degree days;

·	a decrease in weather-normalized retail demand;

·	a $7.5 million increase in coal transportation costs not recovered in KCP&L’s Missouri retail rates where there is no fuel recovery mechanism, prior to new retail rates effective May 4, 2011;

·	an estimated $16 million impact of coal conservation activities due to flooding resulting in increased fuel expenses and purchased power expenses and reduced wholesale sales; and

These decreases were partially offset by new retail rates effective December 1, 2010, and May 4, 2011, for KCP&L in Kansas and Missouri, respectively.

KCP&L’s gross margin increased $160.6 million in 2010 compared to 2009 primarily due to the increase in retail revenues driven by new retail rates effective August 1, 2009, and September 1, 2009, for Kansas and Missouri, respectively, and favorable weather.

KCP&L’s retail MWhs sold in 2010 increased due to favorable weather, with a 2% increase in heating degree days and a 56% increase in cooling degree days. Cooling degree days were 23% above normal based on a 30-year average. Wholesale MWhs sold increased due to a 9% increase in generation resulting in more MWhs available for sale, partially offset by the higher retail load requirements. The increase in generation was a result of Iatan No. 2 being placed in service during 2010 and Iatan No. 1 being off-line from January through mid-April 2009 to complete an environmental upgrade and unit overhaul, with the expenditures being capitalized and therefore not impacting operating and maintenance expenses. As a result, KCP&L’s coal base load equivalent availability factor increased to 81% in 2010 compared to 79% in 2009.

KCP&L’s gross margin increased $24.2 million in 2009 compared to 2008 primarily due to new retail rates effective August 1, 2009, and September 1, 2009, for Kansas and Missouri, respectively, partially offset by a decline in weather-normalized customer usage driven by weakened economic conditions and unfavorable summer weather in 2009, with a 9% decrease in cooling degree days. Cooling degrees days were 22% below normal based on a 30-year average.

KCP&L Other Operating Expenses (including operating and maintenance expenses, general taxes and other)

KCP&L’s other operating expenses increased ~~$54.6~~$35.1 million in ~~2010~~2011 compared to ~~2009. Plant~~2010 primarily due to:

·	a $14.6 million increase in plant operating and maintenance expenses primarily due to Iatan No. 2 expenses being recognized with Kansas and Missouri rates effective December 1, 2010, and May 4, 2011, respectively;

·	a $10.4 million increase in general taxes driven by increased property taxes;

·	a $6.4 million increase in amortization of regulatory assets pursuant to rate orders;

·	$3.0 million of expenses related to the impact of flooding; and

as a result of disallowances in the 2011 MPSC rate order, KCP&L recognized losses of $1.5 million for construction costs related to Iatan No. 2 and to the Iatan No. 1 environmental project in 2011. KCP&L also recognized a $2.4 million loss for other disallowed costs in the MPSC rate order. In 2010, KCP&L recognized losses of $13.0 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project.

KCP&L’s other operating expenses increased ~~$13.6~~$54.6 million in 2010 compared to 2009 primarily ~~driven by planned~~due to:

a $13.6 million increase in plant ~~outages, including the impact of outages in 2009 that included capitalizable improvements and therefore did not impact~~ operating and maintenance expenses primarily driven by planned plant outages, including the impact of outages in 2009 that included capitalizable improvements and therefore did not impact operating and maintenance expenses;

·	a $10.6 million increase in general taxes driven by increased gross receipts taxes on increased retail revenues and increased property taxes; and

·	a $5.4 million increase resulting from the accounting effects of the 2010 KCC rate order.

These increases were partially offset by $7.5 million expensed in September 2009 after KCP&L exercised its option to terminate an agreement for the construction of a wind project. The accounting effects of the KCC rate order increased other operating expenses $5.4 million in 2010. General taxes increased $10.6 million in 2010 compared to 2009 driven by increased gross receipts taxes on increased retail revenues and increased property taxes.

Accounting rules state that when it becomes probable that part of the cost of a recently completed plant will be disallowed for rate-making purposes and a reasonable estimate of the amount of the disallowance can be made, the estimated amount of the probable disallowance shall be deducted from the reported cost of the plant and recognized as a loss. As a result of disallowances in the 2010 KCC rate order, KCP&L recognized Kansas jurisdictional losses of $4.4 million for construction costs related to Iatan No. 2 and $2.0 million for construction costs related to the Iatan No. 1 environmental project. Management determined it iswas probable that the MPSC would disallow these costs as well in KCP&L’s pending rate case. Therefore, KCP&L’s Missouri jurisdictional portion of these costs was recognized as a loss in addition to the KCP&L Kansas jurisdictional portion resulting in a $13.0 million loss for KCP&L’s construction costs incurred through December 31, 2010.

KCP~~&L’s other operating expenses increased $4.8~~&L Voluntary Separation Program

KCP&L recorded expense of $9.2 million ~~in 2009 compared~~during 2011 related to ~~2008 primarily due~~the voluntary separation program reflecting severance and related payroll taxes provided by KCP&L to ~~increased employee-related costs and $7.5 million expensed in September 2009 after~~employees who elected to voluntarily separate from KCP&L exercised its option to terminate an agreement for the construction of a wind project. These increases were partially offset by increased use of internal labor on capital projects as a result of more efficient operations as well as spending reductions and realized synergies from the GMO acquisition.&L.

KCP&L Depreciation and Amortization

KCP&L’s depreciation and amortization costs decreased $63.3 million in 2011 compared to 2010 due to a $32.7 million decrease attributable to lower depreciation rates for KCP&L and a $58.2 million decrease in regulatory amortization for KCP&L in Kansas and Missouri. These decreases were partially offset by $9.4 million of depreciation for Iatan No. 2, as well as increased depreciation expense for other capital additions.

KCP&L’s depreciation and amortization costs increased $26.8 million in 2010 compared to 2009 primarily due to $14.4 million of additional regulatory amortization pursuant to KCP&L’s 2009 rate cases. The remaining

increase was due to placing in service the Iatan No. 1 environmental equipment during 2009 and commencement of depreciation on Iatan No. 2 during 2010 (Kansas jurisdiction only), as well as ~~normal~~increased depreciation activity for other capital additions. KCP&L’s depreciation and amortization costs increased $25.3 million in 2009 compared to 2008 primarily due to $10.8 million of additional regulatory amortization pursuant to KCP&L’s 2009 rate cases, placing the Iatan No. 1 environmental project in service during 2009 and normal depreciation activityexpense for other capital additions.

KCP&L Non-operating Income and Expenses

KCP&L’s non-operating income and expenses decreased $20.1 million in 2011 compared to 2010 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to Iatan No. 2 being placed in service in the third quarter of 2010.

KCP&L’s non-operating income and expenses decreased $9.4 million in 2010 compared to 2009 primarily due to a decrease in the equity component of AFUDC resulting from a lower average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects being placed in service.

KCP&L Interest Charges

KCP&L’s ~~non-operating income and expenses~~interest charges increased ~~$9.3~~$29.9 million in ~~2009~~2011 compared to ~~2008~~2010 primarily due to ~~an increase~~a $19.5 million decrease in the ~~equity~~debt component of AFUDC resulting from a ~~higher~~lower average construction work in progress balance due to ~~KCP&L’s Comprehensive Energy Plan projects.~~Iatan No. 2 being placed in service in the third quarter of 2010, a $7.1 million increase to interest expense relating to deferral to a regulatory asset of construction accounting carrying costs for Iatan Nos. 1 and 2 and common facilities and $5.9 million of interest on 5.30% Senior Notes issued in September 2011.

~~KCP&L Interest Charges~~

KCP&L’s interest charges increased $0.8 million in 2010 compared to 2009 primarily due to interest for a full year on $400.0 million of 7.15% Mortgage Bonds Series 2009A issued in March 2009 and a decrease in the debt component of AFUDC resulting from a lower average construction work in progress balance due to KCP&L’s Comprehensive Energy Plan projects being placed in service, mostly offset by the deferral to a regulatory asset of construction accounting carrying costs for Iatan No. 1, Iatan No. 2 and common facilities. KCP&L’s interest charges increased $12.6 million in 2009 compared to 2008 primarily due to interest on $400.0 million of Mortgage Bonds Series 2009A issued in March 2009 and interest for a full year on $350.0 million of unsecured Senior Notes issued in March 2008, partially offset by decreased commercial paper outstanding, decreased rates on commercial paper and an increase in the debt component of AFUDC resulting from a higher construction work in progress balance due to Comprehensive Energy Plan projects.

KCP&L Income Tax Expense

KCP&L’s income tax expense decreased $12.5 million in 2011 compared to 2010 primarily due to decreased pre-tax income.

KCP&L’s income tax expense increased $34.7 million in 2010 compared to 2009 primarily due to increased pre-tax income and a $2.8 million increase in income tax expense for the cumulative change in tax treatment of the Medicare Part D subsidy under the Federal health care reform legislation signed into law in the first quarter of 2010.

KCP&L’s income tax expense decreased $12.9 million in 2009 compared to 2008 primarily due to an increase in deferred tax balances in 2008 of $20.3 million as a result of an increase in the composite tax rate reflecting Great Plains Energy’s 2008 sale of Strategic Energy. Additionally, 2008 reflected $6.7 million of allocated tax benefits from holding company losses. The tax sharing agreement between Great Plains Energy and its subsidiaries was modified on July 14, 2008. As part of the new agreement, parent company tax benefits are no longer allocated to KCP&L or other subsidiaries.

4951

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In the ordinary course of business, Great Plains Energy and KCP&L face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operations and credit risks and are not represented in the following analysis. See Item ~~1A.~~1A Risk Factors and Item 7.7 MD&A for further discussion of risk factors.

Great Plains Energy and KCP&L are exposed to market risks associated with commodity price and supply, interest rates and equity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects the volatility of the markets may have on its operating results. During the ordinary course of business, under the direction and control of an internal risk management committee, Great Plains Energy’s and KCP&L’s hedging strategies are reviewed to determine the hedging approach deemed appropriate based upon the circumstances of each situation. Though management believes its risk management practices are effective, it is not possible to identify and eliminate all risk. Great Plains Energy and KCP&L could experience losses, which could have a material adverse effect on its results of operations or financial position, due to many factors, including unexpectedly large or rapid movements or disruptions in the energy markets, from regulatory-driven market rule changes and/or bankruptcy or non-performance of customers or counterparties, and/or failure of underlying transactions that have been hedged to materialize.

Hedging Strategies

Derivative instruments are frequently utilized to execute risk management and hedging strategies. Derivative instruments, such as futures, forward contracts, swaps or options, derive their value from underlying assets, indices, reference rates or a combination of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives, and instruments listed and traded on an exchange.

Interest Rate Risk

Great Plains Energy and KCP&L manage interest expense and short and long-term liquidity through a combination of fixed and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may also be used to achieve the desired combination. At December 31, ~~2010,~~2011, less than 1% of Great Plains Energy’s long-term debt was variable rate debt. KCP&L had no variable rate long-term debt at December 31, ~~2010.~~2011. Interest rates impact the fair value of long-term debt. A change in interest rates would impact Great Plains Energy and KCP&L to the extent they redeemed any of their outstanding long-term debt. Great Plains Energy’s and KCP&L’s book values of long-term debt were below fair value by 8%11% and 9%15%, respectively, at December 31, ~~2010.~~2011.

Great Plains Energy had ~~$9.5~~$22.0 million of notes payable outstanding at December 31, ~~2010.~~2011. The principal amount of the notes payable, which will vary during the year, drives Great Plains Energy’s notes payable interest expense. Assuming that ~~$9.5~~$22.0 million of notes payable was outstanding for all of ~~2011,~~2012, a hypothetical 10% increase in interest rates associated with short-term variable rate debt would result in an immaterial increase in interest expense for ~~2011.~~2012.

Great Plains Energy and KCP&L had ~~$263.5~~$267.0 million and $227.0 million, respectively, of commercial paper outstanding at December 31, ~~2010.~~2011. The principal amount of the commercial paper, which will vary during the year, drives Great Plains Energy’s and KCP&L’s commercial paper interest expense. Assuming that ~~$263.5~~$267.0 million and $227.0 million of commercial paper was outstanding for all of ~~2011,~~2012 for Great Plains Energy and KCP&L, respectively, a hypothetical 10% increase in commercial paper rates would result in an immaterial increase in interest expense for ~~2011.~~2012. Assuming that ~~$263.5~~$267.0 million and $227.0 million of commercial paper was outstanding for all of ~~2011,~~2012 for Great Plains Energy and KCP&L, respectively, a hypothetical 100 basis point increase in commercial paper rates would result in ~~a $2.6 million~~an increase in interest expense of $2.7 million for ~~2011.~~

Great Plains Energy and $2.3 million for KCP&L in 2012.

5052

Commodity Risk

Great Plains Energy and KCP&L engage in the wholesale and retail marketing of electricity and are exposed to risk associated with the price of electricity. Exposure to these risks is affected by a number of factors including the quantity and availability of fuel used for generation and the quantity of electricity customers consume. Customers’ electricity usage could also vary from year to year based on the weather or other factors. Quantities of fossil fuel used for generation vary from year to year based on the availability, price and deliverability of a given fuel type as well as planned and ~~scheduled~~unplanned outages at facilities that use fossil fuels.

KCP&L's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity. KCP&L also enters into additional power purchase transactions with the objective of obtaining the most economical energy to meet its physical delivery obligations to customers. KCP&L is required to maintain a capacity margin of at least 12% of its peak summer demand. This net positive supply of capacity and energy is maintained through KCP&L’s generation assets and capacity and power purchase agreements to protect KCP&L from the potential operational failure of one of its power generating units. KCP&L continually evaluates the need for additional risk mitigation measures in order to minimize its financial exposure to, among other things, spikes in wholesale power prices during periods of high demand.

KCP&L's sales include the sales of electricity to its retail customers and bulk power sales of electricity in the wholesale market. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply, the availability and cost of purchased power and the requirements of other electric systems; therefore, the impact of the hypothetical amounts that follow could be significantly reduced depending on the system requirements and market prices at the time of the increases. A hypothetical 10% increase in the market price of power could result in a ~~$0.7~~$0.4 million decrease in operating income for ~~2011~~2012 related to purchased power. In ~~2011,~~2012, approximately ~~78%~~77% of KCP&L’s net MWhs generated are expected to be coal-fired. KCP&L currently has ~~81%~~all of its coal requirements for ~~2011~~2012 under contract. A hypothetical 10% increase in the market price of coal could result in less than a ~~$6.5~~$2.6 million increase in fuel expense for ~~2011.~~2012. KCP&L has also implemented price risk mitigation measures to reduce its exposure to high natural gas prices. A hypothetical 10% increase in natural gas and oil market prices could result in an increase of $0.1 million in fuel expense for ~~2011.~~2012. At December 31, ~~2010,~~2011, KCP&L had hedged approximately 66%, ~~45%~~56% and ~~22%~~13% of its ~~2011,~~ 2012, 2013 and ~~2013,~~2014, respectively, projected natural gas usage for generation requirements to serve retail load and firm MWh sales. KCP&L’s Kansas ECA allows for the recovery of increased fuel and purchased power costs from Kansas retail customers. KCP&L’s Missouri retail rates do not contain a fuel recovery mechanism, meaning that changes in fuel costs create a regulatory lag.

In the GMO regulated electric operations in ~~2010,~~2011, approximately ~~59%~~62% of the power sold was generated and the remaining ~~41%~~38% was purchased through long-term contracts or in the open market. GMO has an FAC that allows GMO to adjust retail electric rates based on 95% of the difference between actual fuel and purchased power costs and the amount of fuel and purchased power costs provided in base rates.

Several measures have been taken to mitigate commodity price risk exposure in GMO’s electric utility operations. One of these measures is contracting for a diverse supply of coal to meet ~~78%~~approximately 97% and ~~49%~~86% of its ~~2011~~2012 and ~~2012,~~2013, respectively, native load fuel requirements of coal-fired generation. The price risk associated with natural gas and on-peak spot market purchased power requirements is also mitigated through a hedging plan using New York Mercantile Exchange (NYMEX) futures contracts and options. A hypothetical 10% increase in natural gas market prices could result in an increase of ~~$1.1~~$2.5 million in fuel expense for ~~2011.~~2012. At December 31, ~~2010,~~2011, GMO had financial contracts in place to hedge approximately ~~67%~~45%, ~~45%~~38% and 38% of expected on-peak natural gas and natural gas equivalent purchased power price exposure for ~~2011,~~ 2012, 2013 and ~~2013,~~2014, respectively. The mark-to-market value of these contracts at December 31, ~~2010,~~2011, was a liability of ~~$2.5~~$5.0 million.

5153

Credit Risk – MPS Merchant

MPS Merchant is exposed to credit risk. Credit risk is measured by the loss that would be recorded if counterparties failed to perform pursuant to the terms of the contractual obligations less the value of any collateral held. MPS Merchant’s counterparties are not externally rated. Credit exposure to counterparties at December 31, ~~2010,~~2011, was ~~$21.0~~$13.3 million.

Investment Risk

KCP&L maintains trust funds, as required by the NRC, to fund its share of decommissioning the Wolf Creek nuclear power plant. As of December 31, ~~2010,~~2011, these funds were invested primarily in domestic equity securities and fixed income securities and are reflected at fair value on KCP&L’s balance sheets. The mix of securities is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs; however, the equity securities in the trusts are exposed to price fluctuations in equity markets and the value of fixed rate fixed income securities are exposed to changes in interest rates. A hypothetical increase in interest rates resulting in a hypothetical 10% decrease in the value of the fixed income securities would have resulted in a ~~$4.1~~$4.9 million reduction in the value of the decommissioning trust funds at December 31, ~~2010.~~2011. A hypothetical 10% decrease in equity prices would have resulted in an ~~$8.5~~$8.4 million reduction in the fair value of the equity securities at December 31, ~~2010.~~2011. KCP&L's exposure to investment risk associated with the decommissioning trust funds is in large part mitigated due to the fact that KCP&L is currently allowed to recover its decommissioning costs in its rates. If the actual return on trust assets is below the anticipated level, KCP&L could be responsible for the balance of funds required to decommission Wolf Creek; however, while there can be no assurances, management believes a rate increase would be allowed to recover decommissioning costs over the remaining life of the unit.

5254

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

								Page
								Number
Great Plains Energy Incorporated
Consolidated Statements of Income				54				56
Consolidated Balance Sheets				55				57
Consolidated Statements of Cash Flows					57			59
Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest							58	60
Consolidated Statements of Comprehensive Income					59			61

Kansas City Power & Light Company
Consolidated Statements of Income				60				62
Consolidated Balance Sheets				61				63
Consolidated Statements of Cash Flows					63			65
Consolidated Statements of Common Shareholder’s Equity						64		66
Consolidated Statements of Comprehensive Income					65			67

Combined Notes to Consolidated Financial Statements for Great Plains Energy Incorporated
and Kansas City Power & Light Company
	Note 1:	Summary of Significant Accounting Policies				66		68
	Note 2:	Supplemental Cash Flow Information			72			74
	Note 3:	Receivables	74					76
	Note 4:	~~Assets Held For Sale~~Nuclear Plant		75				77
	Note 5:	~~Nuclear Plant~~Regulatory Matters		75				80
	Note 6:	~~Regulatory Matters~~Goodwill and Intangible Assets			78			84
	Note 7:	~~Goodwill and Intangible Assets~~Asset Retirement Obligations			83			85
	Note 8:	~~Asset Retirement Obligations~~Pension Plans, Other Employee Benefits and Voluntary Separation Program					84	86
	Note 9:	~~Pension Plans and Other Employee Benefits~~Equity Compensation		85				95
	Note 10:	~~Equity Compensation~~						94
	~~Note 11:~~	Short-Term Borrowings and Short-Term Bank Lines of Credit						98
	Note 11:	Long-Term Debt						99
	Note 12:	~~Long-Term Debt~~Common Shareholders’ Equity			99			102
	Note 13:	~~Common Shareholders’ Equity~~Preferred Stock		~~102~~				103
	Note 14:	~~Preferred Stock~~Commitments and Contingencies						103
	Note 15:	~~Commitments and Contingencies~~Legal Proceedings		~~103~~				112
	Note 16:	~~Legal Proceedings~~Guarantees	~~114~~					113
	Note 17:	~~Guarantees~~						~~115~~
	~~Note 18:~~	Related Party Transactions and Relationships				~~116~~		113
	Note 18:	Derivative Instruments						113
	Note 19:	~~Derivative Instruments~~Fair Value Measurements		~~117~~				118
	Note 20:	~~Fair Value Measurements~~Taxes	~~122~~					123
	Note 21:	~~Taxes~~Segments and Related Information						128
	Note 22:	~~Segments and Related Information~~Discontinued Operations		~~133~~				129
	Note 23:	~~Discontinued Operations~~						~~134~~
	~~Note 24:~~	Jointly Owned Electric Utility Plants			~~135~~			129
	Note ~~25:~~24:	Quarterly Operating Results (Unaudited)				~~136~~		130

Report of Independent Registered Public Accounting Firm
	Great Plains Energy Incorporated			~~137~~				132
	Kansas City Power & Light Company				~~138~~			133

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Income

Year Ended December 31 2010 2009 2008
Operating Revenues (millions, except per share amounts)
Electric revenues $ 2,255.5 $ 1,965.0 $ 1,670.1
Operating Expenses
Fuel 430.7 405.5 311.4
Purchased power 213.8 183.7 208.9
Transmission of electricity by others 27.4 26.9 22.5
Utility operating and maintenance expenses 602.5 572.4 477.2
Depreciation and amortization 331.6 302.2 235.0
General taxes 155.1 139.8 128.1
Other 22.1 14.4 12.0
Total 1,783.2 1,644.9 1,395.1
Operating income 472.3 320.1 275.0
Non-operating income 43.9 49.5 31.9
Non-operating expenses (19.5 ) (6.9 ) (10.8 )
Interest charges (184.8 ) (180.9 ) (111.3 )
Income from continuing operations before income tax expense and
loss from equity investments 311.9 181.8 184.8
Income tax expense (99.0 ) (29.5 ) (63.8 )
Loss from equity investments, net of income taxes (1.0 ) (0.4 ) (1.3 )
Income from continuing operations 211.9 151.9 119.7
Income (loss) from discontinued operations, net of income taxes (Note 23) - (1.5 ) 35.0
Net income 211.9 150.4 154.7
Less: Net income attributable to noncontrolling interest (0.2 ) (0.3 ) (0.2 )
Net income attributable to Great Plains Energy 211.7 150.1 154.5
Preferred stock dividend requirements 1.6 1.6 1.6
Earnings available for common shareholders $ 210.1 $ 148.5 $ 152.9

Average number of basic common shares outstanding 135.1 129.3 101.1
Average number of diluted common shares outstanding 136.9 129.8 101.2

Basic earnings (loss) per common share
Continuing operations $ 1.55 $ 1.16 $ 1.16
Discontinued operations - (0.01 ) 0.35
Basic earnings per common share $ 1.55 $ 1.15 $ 1.51

Diluted earnings (loss) per common share
Continuing operations $ 1.53 $ 1.15 $ 1.16
Discontinued operations - (0.01 ) 0.35
Diluted earnings per common share $ 1.53 $ 1.14 $ 1.51

Cash dividends per common share $ 0.83 $ 0.83 $ 1.66

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets

December 31
2010 2009
ASSETS (millions, except share amounts)
Current Assets
Cash and cash equivalents $ 10.8 $ 65.9
Funds on deposit 5.2 4.4
Receivables, net 241.7 230.5
Accounts receivable pledged as collateral 95.0 -
Fuel inventories, at average cost 85.1 85.0
Materials and supplies, at average cost 132.8 121.3
Deferred refueling outage costs 9.6 19.5
Refundable income taxes 2.1 13.5
Deferred income taxes 14.3 36.8
Assets held for sale (Note 4) - 19.4
Derivative instruments 1.1 1.5
Prepaid expenses and other assets 13.9 14.7
Total 611.6 612.5
Utility Plant, at Original Cost
Electric 10,536.9 8,849.0
Less-accumulated depreciation 4,031.3 3,774.5
Net utility plant in service 6,505.6 5,074.5
Construction work in progress 307.5 1,508.4
Nuclear fuel, net of amortization of $131.1 and $106.0 79.2 68.2
Total 6,892.3 6,651.1
Investments and Other Assets
Affordable housing limited partnerships 0.3 13.2
Nuclear decommissioning trust fund 129.2 112.5
Regulatory assets 924.0 822.2
Goodwill 169.0 169.0
Derivative instruments 7.8 7.9
Other 84.0 94.4
Total 1,314.3 1,219.2
Total $ 8,818.2 $ 8,482.8

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets

December 31
2010 2009
LIABILITIES AND CAPITALIZATION (millions, except share amounts)
Current Liabilities
Notes payable $ 9.5 $ 252.0
Collateralized note payable 95.0 -
Commercial paper 263.5 186.6
Current maturities of long-term debt 485.7 1.3
Accounts payable 276.3 315.0
Accrued taxes 26.6 27.9
Accrued interest 75.4 72.5
Accrued compensation and benefits 46.8 45.1
Pension and post-retirement liability 4.1 4.6
Derivative instruments 20.8 0.3
Other 35.6 53.0
Total 1,339.3 958.3
Deferred Credits and Other Liabilities
Deferred income taxes 518.3 381.9
Deferred tax credits 133.4 140.5
Asset retirement obligations 143.3 132.6
Pension and post-retirement liability 427.5 440.4
Regulatory liabilities 258.2 237.8
Derivative instruments - 0.5
Other 129.4 145.1
Total 1,610.1 1,478.8
Capitalization
Great Plains Energy common shareholders' equity
Common stock-250,000,000 shares authorized without par value
136,113,954 and 135,636,538 shares issued, stated value 2,324.4 2,313.7
Retained earnings 626.5 529.2
Treasury stock-400,889 and 213,423 shares, at cost (8.9 ) (5.5 )
Accumulated other comprehensive loss (56.1 ) (44.9 )
Total 2,885.9 2,792.5
Noncontrolling interest 1.2 1.2
Cumulative preferred stock $100 par value
3.80% - 100,000 shares issued 10.0 10.0
4.50% - 100,000 shares issued 10.0 10.0
4.20% - 70,000 shares issued 7.0 7.0
4.35% - 120,000 shares issued 12.0 12.0
Total 39.0 39.0
Long-term debt (Note 12) 2,942.7 3,213.0
Total 5,868.8 6,045.7
Commitments and Contingencies (Note 15)
Total $ 8,818.2 $ 8,482.8

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Income


Year Ended December 31	2011			2010			2009
Operating Revenues	(millions, except per share amounts)
Electric revenues	$	2,318.0		$	2,255.5		$	1,965.0
Operating Expenses
Fuel		483.8			430.7			405.5
Purchased power		203.4			213.8			183.7
Transmission of electricity by others		30.2			27.4			26.9
Utility operating and maintenance expenses		658.2			602.5			572.4
Voluntary separation program		12.7			-			-
Depreciation and amortization		273.1			331.6			302.2
General taxes		170.9			155.1			139.8
Other		5.9			22.1			14.4
Total		1,838.2			1,783.2			1,644.9
Operating income		479.8			472.3			320.1
Non-operating income		5.9			43.9			49.5
Non-operating expenses		(8.2	)		(19.5	)		(6.9	)
Interest charges		(218.4	)		(184.8	)		(180.9	)
Income from continuing operations before income tax expense and
loss from equity investments		259.1			311.9			181.8
Income tax expense		(84.8	)		(99.0	)		(29.5	)
Loss from equity investments, net of income taxes		(0.1	)		(1.0	)		(0.4	)
Income from continuing operations		174.2			211.9			151.9
Loss from discontinued operations, net of income taxes (Note 22)		-			-			(1.5	)
Net income		174.2			211.9			150.4
Less: Net (income) loss attributable to noncontrolling interest		0.2			(0.2	)		(0.3	)
Net income attributable to Great Plains Energy		174.4			211.7			150.1
Preferred stock dividend requirements		1.6			1.6			1.6
Earnings available for common shareholders	$	172.8		$	210.1		$	148.5

Average number of basic common shares outstanding		135.6			135.1			129.3
Average number of diluted common shares outstanding		138.7			136.9			129.8

Basic earnings (loss) per common share
Continuing operations	$	1.27		$	1.55		$	1.16
Discontinued operations		-			-			(0.01	)
Basic earnings per common share	$	1.27		$	1.55		$	1.15

Diluted earnings (loss) per common share
Continuing operations	$	1.25		$	1.53		$	1.15
Discontinued operations		-			-			(0.01	)
Diluted earnings per common share	$	1.25		$	1.53		$	1.14

Cash dividends per common share	$	0.835		$	0.83		$	0.83

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY
Consolidated Statements of Cash Flows

Year Ended December 31 2010 2009 2008
Cash Flows from Operating Activities (millions)
Net income $ 211.9 $ 150.4 $ 154.7
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization 331.6 302.2 238.3
Amortization of:
Nuclear fuel 25.1 16.1 14.5
Other (4.7 ) (10.1 ) (1.9 )
Deferred income taxes, net 123.8 (3.6 ) 44.1
Investment tax credit amortization (2.9 ) (2.2 ) (1.8 )
Loss from equity investments, net of income taxes 1.0 0.4 1.3
Fair value impacts from interest rate hedging - - 9.2
Fair value impacts from energy contracts - Strategic Energy - - (189.1 )
Loss on sale of Strategic Energy - - 116.2
Other operating activities (Note 2) (133.7 ) (117.8 ) 52.4
Net cash from operating activities 552.1 335.4 437.9
Cash Flows from Investing Activities
Utility capital expenditures (618.0 ) (841.1 ) (1,023.7 )
Allowance for borrowed funds used during construction (28.5 ) (37.7 ) (31.7 )
Payment to Black Hills for asset sale working capital adjustment - (7.7 ) -
Proceeds from sale of Strategic Energy, net of cash sold - - 218.8
GMO acquisition, net cash received - - 271.9
Purchases of nuclear decommissioning trust investments (83.3 ) (99.0 ) (49.1 )
Proceeds from nuclear decommissioning trust investments 79.6 95.3 45.4
Other investing activities (7.5 ) (7.4 ) (10.7 )
Net cash from investing activities (657.7 ) (897.6 ) (579.1 )
Cash Flows from Financing Activities
Issuance of common stock 6.2 219.9 15.3
Issuance of long-term debt 249.9 700.7 363.4
Issuance fees (12.1 ) (22.8 ) (5.3 )
Repayment of long-term debt (1.3 ) (70.7 ) (169.9 )
Net change in short-term borrowings (165.6 ) (145.6 ) 118.4
Net change in collateralized short-term borrowings 95.0 - -
Dividends paid (114.2 ) (110.5 ) (172.0 )
Credit facility termination fees - - (12.5 )
Other financing activities (7.4 ) (4.0 ) (2.2 )
Net cash from financing activities 50.5 567.0 135.2
Net Change in Cash and Cash Equivalents (55.1 ) 4.8 (6.0 )
Cash and Cash Equivalents at Beginning of Year (includes $43.1 million

in assets of discontinued operations in 2008) 65.9 61.1 67.1
Cash and Cash Equivalents at End of Year $ 10.8 $ 65.9 $ 61.1

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets


	December 31
	2011		2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	6.2	$	10.8
Funds on deposit		1.4		5.2
Receivables, net		231.2		241.7
Accounts receivable pledged as collateral		95.0		95.0
Fuel inventories, at average cost		89.0		85.1
Materials and supplies, at average cost		140.3		132.8
Deferred refueling outage costs		27.5		9.6
Refundable income taxes		0.3		2.1
Deferred income taxes		7.5		14.3
Derivative instruments		1.0		1.1
Prepaid expenses and other assets		19.7		13.9
Total		619.1		611.6
Utility Plant, at Original Cost
Electric		10,924.8		10,536.9
Less-accumulated depreciation		4,235.8		4,031.3
Net utility plant in service		6,689.0		6,505.6
Construction work in progress		287.9		307.5
Nuclear fuel, net of amortization of $132.7 and $131.1		76.6		79.2
Total		7,053.5		6,892.3
Investments and Other Assets
Nuclear decommissioning trust fund		135.3		129.2
Regulatory assets		1,058.2		924.0
Goodwill		169.0		169.0
Derivative instruments		6.8		7.8
Other		76.1		84.3
Total		1,445.4		1,314.3
Total	$	9,118.0	$	8,818.2

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest

Year Ended December 31 2010 2009 2008
Shares Amount Shares Amount Shares Amount
Common Stock (millions, except share amounts)
Beginning balance 135,636,538 $ 2,313.7 119,375,923 $ 2,118.4 86,325,136 $ 1,065.9
Issuance of common stock 347,279 6.6 15,883,948 220.1 32,962,723 1,042.0
Common stock issuance fees - - - (7.0 ) - -
Issuance of restricted common stock 130,137 2.3 376,667 5.4 88,064 2.3
Equity compensation expense, net of forfeitures 1.0 0.8 5.9
Unearned Compensation
Issuance of restricted common stock (2.3 ) (5.4 ) (2.3 )
Forfeiture of restricted common stock 0.8 1.1 -
Compensation expense recognized 2.2 3.8 5.6
Equity Units allocated fees and expenses and the
present value of contract adjustment payments - (22.5 ) -
Other 0.1 (1.0 ) (1.0 )
Ending balance 136,113,954 2,324.4 135,636,538 2,313.7 119,375,923 2,118.4
Retained Earnings
Beginning balance 529.2 489.3 506.9
Cumulative effect of a change in accounting principle - - (0.1 )
Net income attributable to Great Plains Energy 211.7 150.1 154.5
Dividends:
Common stock (112.6 ) (108.9 ) (170.4 )
Preferred stock - at required rates (1.6 ) (1.6 ) (1.6 )
Performance shares (0.2 ) (0.1 ) -
Performance shares amendment - 0.4 -
Ending balance 626.5 529.2 489.3
Treasury Stock
Beginning balance (213,423 ) (5.5 ) (120,677 ) (3.6 ) (90,929 ) (2.8 )
Treasury shares acquired (188,383 ) (3.4 ) (132,593 ) (2.9 ) (39,856 ) (1.1 )
Treasury shares reissued 917 - 39,847 1.0 10,108 0.3
Ending balance (400,889 ) (8.9 ) (213,423 ) (5.5 ) (120,677 ) (3.6 )
Accumulated Other Comprehensive Income (Loss)
Beginning balance (44.9 ) (53.5 ) (2.1 )
Derivative hedging activity, net of tax (10.6 ) 5.3 (47.5 )
Change in unrecognized pension expense, net of tax (0.6 ) 3.3 (3.9 )
Ending balance (56.1 ) (44.9 ) (53.5 )
Total Great Plains Energy Common Shareholders' Equity $ 2,885.9 $ 2,792.5 $ 2,550.6

Noncontrolling Interest
Beginning balance $ 1.2 $ 1.0 $ -
GMO acquisition July 14, 2008 - - 0.8
Net income attributable to noncontrolling interest 0.2 0.3 0.2
Distribution (0.2 ) (0.1 ) -
Ending balance $ 1.2 $ 1.2 $ 1.0

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Balance Sheets


	December 31
	2011			2010
LIABILITIES AND CAPITALIZATION	(millions, except share amounts)
Current Liabilities
Notes payable	$	22.0		$	9.5
Collateralized note payable		95.0			95.0
Commercial paper		267.0			263.5
Current maturities of long-term debt		801.4			485.7
Accounts payable		275.6			276.3
Accrued taxes		25.8			26.6
Accrued interest		76.9			75.4
Accrued compensation and benefits		40.8			46.8
Pension and post-retirement liability		4.4			4.1
Derivative instruments		-			20.8
Other		26.0			35.6
Total		1,634.9			1,339.3
Deferred Credits and Other Liabilities
Deferred income taxes		628.6			518.3
Deferred tax credits		131.2			133.4
Asset retirement obligations		149.6			143.3
Pension and post-retirement liability		461.9			427.5
Regulatory liabilities		268.5			258.2
Other		101.1			129.4
Total		1,740.9			1,610.1
Capitalization
Great Plains Energy common shareholders' equity
Common stock - 250,000,000 shares authorized without par value
136,406,306 and 136,113,954 shares issued, stated value		2,330.6			2,324.4
Retained earnings		684.7			626.5
Treasury stock - 264,567 and 400,889 shares, at cost		(5.6	)		(8.9	)
Accumulated other comprehensive loss		(49.8	)		(56.1	)
Total		2,959.9			2,885.9
Noncontrolling interest		1.0			1.2
Cumulative preferred stock $100 par value
3.80% - 100,000 shares issued		10.0			10.0
4.50% - 100,000 shares issued		10.0			10.0
4.20% - 70,000 shares issued		7.0			7.0
4.35% - 120,000 shares issued		12.0			12.0
Total		39.0			39.0
Long-term debt (Note 11)		2,742.3			2,942.7
Total		5,742.2			5,868.8
Commitments and Contingencies (Note 14)
Total	$	9,118.0		$	8,818.2

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Comprehensive Income

Year Ended December 31 2010 2009 2008
(millions)
Net income $ 211.9 $ 150.4 $ 154.7
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments (28.0 ) (0.4 ) 27.0
Income tax benefit (expense) 10.8 0.1 (12.5 )
Net gain (loss) on derivative hedging instruments (17.2 ) (0.3 ) 14.5
Reclassification to expenses, net of tax (Note 19) 6.6 5.6 (62.0 )
Derivative hedging activity, net of tax (10.6 ) 5.3 (47.5 )
Defined benefit pension plans
Net gain (loss) arising during period (1.3 ) 5.0 (6.7 )
Less:  amortization of net gain included in net
periodic benefit costs 0.3 0.4 0.3
Less:  amortization of prior service costs included in net
periodic benefit costs - - 0.1
Income tax benefit (expense) 0.4 (2.1 ) 2.4
Net change in unrecognized pension expense (0.6 ) 3.3 (3.9 )
Comprehensive income 200.7 159.0 103.3
Less:  comprehensive income attributable to noncontrolling interest (0.2 ) (0.3 ) (0.2 )
Comprehensive income attributable to Great Plains Energy $ 200.5 $ 158.7 $ 103.1

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY
Consolidated Statements of Cash Flows


Year Ended December 31	2011			2010			2009
Cash Flows from Operating Activities	(millions)
Net income	$	174.2		$	211.9		$	150.4
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		273.1			331.6			302.2
Amortization of:
Nuclear fuel		21.4			25.1			16.1
Other		12.7			(4.7	)		(10.1	)
Deferred income taxes, net		111.2			123.8			(3.6	)
Investment tax credit amortization		(2.2	)		(2.9	)		(2.2	)
Loss from equity investments, net of income taxes		0.1			1.0			0.4
Other operating activities (Note 2)		(147.5	)		(133.7	)		(117.8	)
Net cash from operating activities		443.0			552.1			335.4
Cash Flows from Investing Activities
Utility capital expenditures		(456.6	)		(618.0	)		(841.1	)
Allowance for borrowed funds used during construction		(5.8	)		(28.5	)		(37.7	)
Payment to Black Hills for asset sale working capital adjustment		-			-			(7.7	)
Purchases of nuclear decommissioning trust investments		(18.5	)		(83.3	)		(99.0	)
Proceeds from nuclear decommissioning trust investments		15.1			79.6			95.3
Other investing activities		(19.9	)		(7.5	)		(7.4	)
Net cash from investing activities		(485.7	)		(657.7	)		(897.6	)
Cash Flows from Financing Activities
Issuance of common stock		5.9			6.2			219.9
Issuance of long-term debt		747.1			249.9			700.7
Issuance fees		(10.7	)		(12.1	)		(22.8	)
Repayment of long-term debt		(598.5	)		(1.3	)		(70.7	)
Net change in short-term borrowings		16.0			(165.6	)		(145.6	)
Net change in collateralized short-term borrowings		-			95.0			-
Dividends paid		(115.1	)		(114.2	)		(110.5	)
Other financing activities		(6.6	)		(7.4	)		(4.0	)
Net cash from financing activities		38.1			50.5			567.0
Net Change in Cash and Cash Equivalents		(4.6	)		(55.1	)		4.8
Cash and Cash Equivalents at Beginning of Year		10.8			65.9			61.1
Cash and Cash Equivalents at End of Year	$	6.2		$	10.8		$	65.9

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Income

Year Ended December 31 2010 2009 2008
Operating Revenues (millions)
Electric revenues $ 1,517.1 $ 1,318.2 $ 1,343.0
Operating Expenses
Fuel 278.8 251.3 253.3
Purchased power 78.9 70.8 119.0
Transmission of electricity by others 15.0 12.3 11.1
Operating and maintenance expenses 434.3 403.3 398.1
Depreciation and amortization 256.4 229.6 204.3
General taxes 129.3 118.7 118.9
Other 13.0 - 0.2
Total 1,205.7 1,086.0 1,104.9
Operating income 311.4 232.2 238.1
Non-operating income 24.7 33.2 25.9
Non-operating expenses (5.6 ) (4.7 ) (6.7 )
Interest charges (85.7 ) (84.9 ) (72.3 )
Income before income tax expense 244.8 175.8 185.0
Income tax expense (81.6 ) (46.9 ) (59.8 )
Net income $ 163.2 $ 128.9 $ 125.2

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Common Shareholders' Equity and Noncontrolling Interest


Year Ended December 31	2011						2010						2009
	Shares			Amount			Shares			Amount			Shares			Amount
Common Stock	(millions, except share amounts)
Beginning balance		136,113,954		$	2,324.4			135,636,538		$	2,313.7			119,375,923		$	2,118.4
Issuance of common stock		292,352			5.9			347,279			6.6			15,883,948			220.1
Common stock issuance fees					-						-						(7.0	)
Issuance of restricted common stock		-			-			130,137			2.3			376,667			5.4
Equity compensation expense, net of forfeitures					0.3						1.0						0.8
Unearned Compensation
Issuance of restricted common stock					(3.5	)					(2.3	)					(5.4	)
Forfeiture of restricted common stock					0.9						0.8						1.1
Compensation expense recognized					2.3						2.2						3.8
Equity Units allocated fees and expenses and the
present value of contract adjustment payments					-						-						(22.5	)
Other					0.3						0.1						(1.0	)
Ending balance		136,406,306			2,330.6			136,113,954			2,324.4			135,636,538			2,313.7
Retained Earnings
Beginning balance					626.5						529.2						489.3
Net income attributable to Great Plains Energy					174.4						211.7						150.1
Loss on reissuance of treasury stock					(0.7	)					-						-
Dividends:
Common stock					(113.5	)					(112.6	)					(108.9	)
Preferred stock - at required rates					(1.6	)					(1.6	)					(1.6	)
Performance shares					(0.4	)					(0.2	)					(0.1	)
Performance shares amendment					-						-						0.4
Ending balance					684.7						626.5						529.2
Treasury Stock
Beginning balance		(400,889	)		(8.9	)		(213,423	)		(5.5	)		(120,677	)		(3.6	)
Treasury shares acquired		(125,234	)		(2.4	)		(188,383	)		(3.4	)		(132,593	)		(2.9	)
Treasury shares reissued		261,556			5.7			917			-			39,847			1.0
Ending balance		(264,567	)		(5.6	)		(400,889	)		(8.9	)		(213,423	)		(5.5	)
Accumulated Other Comprehensive Income (Loss)
Beginning balance					(56.1	)					(44.9	)					(53.5	)
Derivative hedging activity, net of tax					6.8						(10.6	)					5.3
Change in unrecognized pension expense, net of tax					(0.5	)					(0.6	)					3.3
Ending balance					(49.8	)					(56.1	)					(44.9	)
Total Great Plains Energy Common Shareholders' Equity				$	2,959.9					$	2,885.9					$	2,792.5

Noncontrolling Interest
Beginning balance				$	1.2					$	1.2					$	1.0
Net income (loss) attributable to noncontrolling interest					(0.2	)					0.2						0.3
Distribution					-						(0.2	)					(0.1	)
Ending balance				$	1.0					$	1.2					$	1.2

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets

December 31
2010 2009
ASSETS (millions, except share amounts)
Current Assets
Cash and cash equivalents $ 3.6 $ 17.4
Funds on deposit 0.4 0.1
Receivables, net 169.4 161.7
Accounts receivable pledged as collateral 95.0 -
Fuel inventories, at average cost 44.9 45.6
Materials and supplies, at average cost 94.4 84.8
Deferred refueling outage costs 9.6 19.5
Refundable income taxes 9.0 -
Deferred income taxes 5.6 0.3
Derivative instruments - 0.2
Prepaid expenses and other assets 10.0 11.0
Total 441.9 340.6
Utility Plant, at Original Cost
Electric 7,540.9 6,258.5
Less-accumulated depreciation 3,104.4 2,899.0
Net utility plant in service 4,436.5 3,359.5
Construction work in progress 227.6 1,144.1
Nuclear fuel, net of amortization of $131.1 and $106.0 79.2 68.2
Total 4,743.3 4,571.8
Investments and Other Assets
Nuclear decommissioning trust fund 129.2 112.5
Regulatory assets 679.6 612.1
Other 32.3 65.3
Total 841.1 789.9
Total $ 6,026.3 $ 5,702.3

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED
Consolidated Statements of Comprehensive Income


Year Ended December 31	2011			2010			2009
	(millions)
Net income	$	174.2		$	211.9		$	150.4
Other comprehensive income (loss)
Loss on derivative hedging instruments		(5.9	)		(28.0	)		(0.4	)
Income tax benefit		2.3			10.8			0.1
Net loss on derivative hedging instruments		(3.6	)		(17.2	)		(0.3	)
Reclassification to expenses, net of tax (Note 18)		10.4			6.6			5.6
Derivative hedging activity, net of tax		6.8			(10.6	)		5.3
Defined benefit pension plans
Net gain (loss) arising during period		(1.2	)		(1.3	)		5.0
Less: amortization of net gain included in net periodic benefit costs		0.4			0.3			0.4
Income tax (expense) benefit		0.3			0.4			(2.1	)
Change in unrecognized pension expense, net of tax		(0.5	)		(0.6	)		3.3
Comprehensive income		180.5			200.7			159.0
Less: comprehensive (income) loss attributable to noncontrolling interest		0.2			(0.2	)		(0.3	)
Comprehensive income attributable to Great Plains Energy	$	180.7		$	200.5		$	158.7

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets

December 31
2010 2009
LIABILITIES AND CAPITALIZATION (millions, except share amounts)
Current Liabilities
Collateralized note payable $ 95.0 $ -
Commercial paper 263.5 186.6
Current maturities of long-term debt 150.3 0.2
Accounts payable 201.7 237.9
Accrued taxes 21.3 23.7
Accrued interest 26.2 26.7
Accrued compensation and benefits 46.8 45.1
Pension and post-retirement liability 2.6 3.2
Other 7.8 26.1
Total 815.2 549.5
Deferred Credits and Other Liabilities
Deferred income taxes 692.0 559.4
Deferred tax credits 129.4 135.7
Asset retirement obligations 129.7 119.8
Pension and post-retirement liability 407.3 421.2
Regulatory liabilities 141.3 126.9
Other 76.7 78.2
Total 1,576.4 1,441.2
Capitalization
Common shareholder's equity
Common stock-1,000 shares authorized without par value
1 share issued, stated value 1,563.1 1,563.1
Retained earnings 478.3 410.1
Accumulated other comprehensive loss (36.4 ) (41.5 )
Total 2,005.0 1,931.7
Long-term debt (Note 12) 1,629.7 1,779.9
Total 3,634.7 3,711.6
Commitments and Contingencies (Note 15)
Total $ 6,026.3 $ 5,702.3

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Income


Year Ended December 31	2011			2010			2009
Operating Revenues	(millions)
Electric revenues	$	1,558.3		$	1,517.1		$	1,318.2
Operating Expenses
Fuel		333.5			278.8			251.3
Purchased power		70.8			78.9			70.8
Transmission of electricity by others		18.8			15.0			12.3
Operating and maintenance expenses		470.9			434.3			403.3
Voluntary separation program		9.2			-			-
Depreciation and amortization		193.1			256.4			229.6
General taxes		139.7			129.3			118.7
Other		1.1			13.0			-
Total		1,237.1			1,205.7			1,086.0
Operating income		321.2			311.4			232.2
Non-operating income		2.9			24.7			33.2
Non-operating expenses		(3.9	)		(5.6	)		(4.7	)
Interest charges		(115.6	)		(85.7	)		(84.9	)
Income before income tax expense		204.6			244.8			175.8
Income tax expense		(69.1	)		(81.6	)		(46.9	)
Net income	$	135.5		$	163.2		$	128.9

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Cash Flows

Year Ended December 31 2010 2009 2008
Cash Flows from Operating Activities (millions)
Net income $ 163.2 $ 128.9 $ 125.2
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization 256.4 229.6 204.3
Amortization of:
Nuclear fuel 25.1 16.1 14.5
Other 24.2 19.0 11.1
Deferred income taxes, net 83.2 (38.2 ) (7.5 )
Investment tax credit amortization (2.1 ) (1.4 ) (1.4 )
Other operating activities (Note 2) (127.8 ) (66.1 ) 72.8
Net cash from operating activities 422.2 287.9 419.0
Cash Flows from Investing Activities
Utility capital expenditures (463.1 ) (626.5 ) (810.5 )
Allowance for borrowed funds used during construction (22.4 ) (31.1 ) (23.6 )
Purchases of nuclear decommissioning trust investments (83.3 ) (99.0 ) (49.1 )
Proceeds from nuclear decommissioning trust investments 79.6 95.3 45.4
Net money pool lending (6.1 ) (6.0 ) -
Other investing activities (13.4 ) (0.6 ) (8.5 )
Net cash from investing activities (508.7 ) (667.9 ) (846.3 )
Cash Flows from Financing Activities
Issuance of long-term debt - 413.2 363.4
Repayment of long-term debt (0.2 ) - -
Net change in short-term borrowings 76.9 (193.6 ) 14.4
Net change in collateralized short-term borrowings 95.0 - -
Net money pool borrowings 1.1 0.9 -
Dividends paid to Great Plains Energy (95.0 ) (72.0 ) (144.0 )
Equity contribution from Great Plains Energy - 247.5 200.0
Issuance fees (5.1 ) (4.0 ) (4.3 )
Net cash from financing activities 72.7 �� 392.0 429.5
Net Change in Cash and Cash Equivalents (13.8 ) 12.0 2.2
Cash and Cash Equivalents at Beginning of Year 17.4 5.4 3.2
Cash and Cash Equivalents at End of Year $ 3.6 $ 17.4 $ 5.4

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are
an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets


	December 31
	2011		2010
ASSETS	(millions, except share amounts)
Current Assets
Cash and cash equivalents	$	1.9	$	3.6
Funds on deposit		0.1		0.4
Receivables, net		172.9		169.4
Accounts receivable pledged as collateral		95.0		95.0
Fuel inventories, at average cost		59.0		44.9
Materials and supplies, at average cost		101.1		94.4
Deferred refueling outage costs		27.5		9.6
Refundable income taxes		5.7		9.0
Deferred income taxes		-		5.6
Prepaid expenses and other assets		16.0		10.0
Total		479.2		441.9
Utility Plant, at Original Cost
Electric		7,829.3		7,540.9
Less-accumulated depreciation		3,243.0		3,104.4
Net utility plant in service		4,586.3		4,436.5
Construction work in progress		203.5		227.6
Nuclear fuel, net of amortization of $132.7 and $131.1		76.6		79.2
Total		4,866.4		4,743.3
Investments and Other Assets
Nuclear decommissioning trust fund		135.3		129.2
Regulatory assets		780.7		679.6
Other		30.6		32.3
Total		946.6		841.1
Total	$	6,292.2	$	6,026.3

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Common Shareholder's Equity

Year Ended December 31 2010 2009 2008
Shares Amount Shares Amount Shares Amount
Common Stock (millions, except share amounts)
Beginning balance 1 $ 1,563.1 1 $ 1,315.6 1 $ 1,115.6
Equity contribution from Great Plains Energy - 247.5 200.0
Ending balance 1 1,563.1 1 1,563.1 1 1,315.6
Retained Earnings
Beginning balance 410.1 353.2 371.3
Net income 163.2 128.9 125.2
Transfer of HSS to KLT Inc. - - 0.7
Dividends:
Common stock held by Great Plains Energy (95.0 ) (72.0 ) (144.0 )
Ending balance 478.3 410.1 353.2
Accumulated Other Comprehensive Income (Loss)
Beginning balance (41.5 ) (46.9 ) (7.5 )
Derivative hedging activity, net of tax 5.1 5.4 (39.4 )
Ending balance (36.4 ) (41.5 ) (46.9 )
Total Common Shareholder's Equity $ 2,005.0 $ 1,931.7 $ 1,621.9

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these
statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets


	December 31
	2011			2010
LIABILITIES AND CAPITALIZATION	(millions, except share amounts)
Current Liabilities
Collateralized note payable	$	95.0		$	95.0
Commercial paper		227.0			263.5
Current maturities of long-term debt		12.7			150.3
Accounts payable		214.8			201.7
Accrued taxes		20.6			21.3
Accrued interest		30.0			26.2
Accrued compensation and benefits		40.8			46.8
Pension and post-retirement liability		3.0			2.6
Other		13.7			7.8
Total		657.6			815.2
Deferred Credits and Other Liabilities
Deferred income taxes		772.7			692.0
Deferred tax credits		127.9			129.4
Asset retirement obligations		134.3			129.7
Pension and post-retirement liability		440.9			407.3
Regulatory liabilities		142.8			141.3
Other		68.6			76.7
Total		1,687.2			1,576.4
Capitalization
Common shareholder's equity
Common stock-1,000 shares authorized without par value
1 share issued, stated value		1,563.1			1,563.1
Retained earnings		513.8			478.3
Accumulated other comprehensive loss		(31.4	)		(36.4	)
Total		2,045.5			2,005.0
Long-term debt (Note 11)		1,901.9			1,629.7
Total		3,947.4			3,634.7
Commitments and Contingencies (Note 14)
Total	$	6,292.2		$	6,026.3

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Comprehensive Income

Year Ended December 31 2010 2009 2008
(millions)
Net income $ 163.2 $ 128.9 $ 125.2
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments (0.9 ) 0.2 (65.0 )
Income tax benefit (expense) 0.3 (0.1 ) 25.4
Net gain (loss) on derivative hedging instruments (0.6 ) 0.1 (39.6 )
Reclassification to expenses, net of tax (Note 19) 5.7 5.3 0.2
Derivative hedging activity, net of tax 5.1 5.4 (39.4 )
Comprehensive income $ 168.3 $ 134.3 $ 85.8

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Cash Flows


Year Ended December 31	2011			2010			2009
Cash Flows from Operating Activities	(millions)
Net income	$	135.5		$	163.2		$	128.9
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		193.1			256.4			229.6
Amortization of:
Nuclear fuel		21.4			25.1			16.1
Other		29.5			24.2			19.0
Deferred income taxes, net		80.6			83.2			(38.2	)
Investment tax credit amortization		(1.5	)		(2.1	)		(1.4	)
Other operating activities (Note 2)		(118.3	)		(127.8	)		(66.1	)
Net cash from operating activities		340.3			422.2			287.9
Cash Flows from Investing Activities
Utility capital expenditures		(336.5	)		(463.1	)		(626.5	)
Allowance for borrowed funds used during construction		(2.9	)		(22.4	)		(31.1	)
Purchases of nuclear decommissioning trust investments		(18.5	)		(83.3	)		(99.0	)
Proceeds from nuclear decommissioning trust investments		15.1			79.6			95.3
Net money pool lending		12.1			(6.1	)		(6.0	)
Other investing activities		(9.7	)		(13.4	)		(0.6	)
Net cash from investing activities		(340.4	)		(508.7	)		(667.9	)
Cash Flows from Financing Activities
Issuance of long-term debt		397.4			-			413.2
Repayment of long-term debt		(263.1	)		(0.2	)		-
Net change in short-term borrowings		(36.5	)		76.9			(193.6	)
Net change in collateralized short-term borrowings		-			95.0			-
Net money pool borrowings		6.7			1.1			0.9
Dividends paid to Great Plains Energy		(100.0	)		(95.0	)		(72.0	)
Equity contribution from Great Plains Energy		-			-			247.5
0Issuance fees		(6.1	)		(5.1	)		(4.0	)
Net cash from financing activities		(1.6	)		72.7			392.0
Net Change in Cash and Cash Equivalents		(1.7	)		(13.8	)		12.0
Cash and Cash Equivalents at Beginning of Year		3.6			17.4			5.4
Cash and Cash Equivalents at End of Year	$	1.9		$	3.6		$	17.4

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are
an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Common Shareholder's Equity



Year Ended December 31	2011					2010					2009
	Shares		Amount			Shares		Amount			Shares		Amount
Common Stock	(millions, except share amounts)
Beginning balance		1	$	1,563.1			1	$	1,563.1			1	$	1,315.6
Equity contribution from Great Plains Energy				-					-					247.5
Ending balance		1		1,563.1			1		1,563.1			1		1,563.1
Retained Earnings
Beginning balance				478.3					410.1					353.2
Net income				135.5					163.2					128.9
Dividends:
Common stock held by Great Plains Energy				(100.0	)				(95.0	)				(72.0	)
Ending balance				513.8					478.3					410.1
Accumulated Other Comprehensive Income (Loss)
Beginning balance				(36.4	)				(41.5	)				(46.9	)
Derivative hedging activity, net of tax				5.0					5.1					5.4
Ending balance				(31.4	)				(36.4	)				(41.5	)
Total Common Shareholder's Equity			$	2,045.5				$	2,005.0				$	1,931.7

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these
statements.

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Comprehensive Income


Year Ended December 31	2011			2010			2009
	(millions)
Net income	$	135.5		$	163.2		$	128.9
Other comprehensive income (loss)
Gain (loss) on derivative hedging instruments		(0.6	)		(0.9	)		0.2
Income tax (expense) benefit		0.2			0.3			(0.1	)
Net gain (loss) on derivative hedging instruments		(0.4	)		(0.6	)		0.1
Reclassification to expenses, net of tax (Note 18)		5.4			5.7			5.3
Derivative hedging activity, net of tax		5.0			5.1			5.4
Comprehensive income	$	140.5		$	168.3		$	134.3

The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.

GREAT PLAINS ENERGY INCORPORATED

KANSAS CITY POWER & LIGHT COMPANY

Notes to Consolidated Financial Statements

The notes to consolidated financial statements that follow are a combined presentation for Great Plains Energy Incorporated and Kansas City Power & Light Company, both registrants under this filing. The terms “Great Plains Energy,” “Company,” “KCP&L,” and “Companies” are used throughout this report. “Great Plains Energy” and the “Company” refer to Great Plains Energy Incorporated and its consolidated subsidiaries, unless otherwise indicated. “KCP&L” refers to Kansas City Power & Light Company and its consolidated subsidiaries. “Companies” refers to Great Plains Energy Incorporated and its consolidated subsidiaries and KCP&L and its consolidated subsidiaries.

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

Great Plains Energy, a Missouri corporation incorporated in 2001, is a public utility holding company and does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy’s wholly owned direct subsidiaries with operations or active subsidiaries are as follows:

·	KCP&L is an integrated, regulated electric utility that provides electricity to customers primarily in the states of Missouri and Kansas. KCP&L has one active wholly owned subsidiary, Kansas City Power & Light Receivables Company (Receivables Company).

KCP&L Greater Missouri Operations Company (GMO) is an integrated, regulated electric utility that primarily provides electricity to customers in the state of Missouri. GMO also provides regulated steam service to certain customers in the St. Joseph, Missouri area. GMO wholly owns MPS Merchant Services, Inc. (MPS Merchant), which has certain long-term natural gas contracts remaining from its former non-regulated trading operations.

Each of Great Plains Energy’s and KCP&L’s consolidated financial statements includes the accounts of their subsidiaries. ~~All intercompany~~Intercompany transactions have been eliminated.

Great Plains Energy’s sole reportable business segment is electric utility. See Note 2221 for additional information.

Use of Estimates

The process of preparing financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires the use of estimates and assumptions that affect the reported amounts of certain types of assets, liabilities, revenues, and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.

Cash and Cash Equivalents

Cash equivalents consist of highly liquid investments with original maturities of three months or less at acquisition.

Funds on Deposit

Funds on deposit consist primarily of cash provided to counterparties in support of margin requirements related to commodity purchases, commodity swaps and futures contracts. Pursuant to individual contract terms with counterparties, deposit amounts required vary with changes in market prices, credit provisions and various other factors. Interest is earned on most funds on deposit. Great Plains Energy also holds funds on deposit from counterparties in the same manner. These funds are included in other current liabilities on the consolidated balance sheets.

6668

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial ~~instruments~~instrument for which it is practicable to estimate that value.

Nuclear decommissioning trust fund – KCP&L’s nuclear decommissioning trust fund assets are recorded at fair value. Fair value is based on quoted market prices of the investments held by the fund and/or valuation models.

Rabbi trust – GMO’s rabbi trusts related to its Supplemental Executive Retirement ~~Plans~~Plan (SERP) are recorded at fair value, which are based on quoted market prices of the investments held by the trusts and/or valuation models. The rabbi trusts are included in Other – Investments and Other Assets on Great Plains Energy’s consolidated balance sheets.

Long-term debt – Fair value is based on quoted market prices, with the incremental borrowing rate for similar debt used to determine fair value if quoted market prices were not available. At December 31, 2011, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, were $3.5 billion and $3.9 billion, respectively. At December 31, 2011, the book value and fair value of KCP&L’s long-term debt, including current maturities, were $1.9 billion and $2.2 billion, respectively. At December 31, 2010, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, ~~was~~were $3.4 billion and $3.7 billion, respectively. At December 31, 2010, the book value and fair value of KCP&L’s long-term debt, including current maturities, was $1.8 billion and $1.9 billion, respectively. At December 31, 2009, the book value and fair value of Great Plains Energy’s long-term debt, including current maturities, was $3.2 billion and $3.4 billion, respectively. At December 31, 2009, the book value and fair value of KCP&L’s long-term debt, including current maturities, waswere $1.8 billion and $1.9 billion, respectively.

Derivative instruments – The fair value of derivative instruments is estimated using market quotes, over-the-counter forward price and volatility curves and correlation among fuel prices, net of estimated credit risk.

Pension plans – For financial reporting purposes, the market value of plan assets is the fair value. KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purposes.

Derivative Instruments

The Company records derivative instruments on the balance sheet at fair value in accordance with GAAP. Great Plains Energy and KCP&L enter into derivative contracts to manage exposure to commodity price and interest rate fluctuations. Derivative instruments designated as normal purchases and normal sales (NPNS) and cash flow hedges are used solely for hedging purposes and are not issued or held for speculative reasons.

The Company considers various qualitative factors, such as contract and market place attributes, in designating derivative instruments at inception. Great Plains Energy and KCP&L may elect the NPNS exception, which requires the effects of the derivative to be recorded when the underlying contract settles. Great Plains Energy and KCP&L account for derivative instruments that are not designated as NPNS as cash flow hedges or non-hedging derivatives, which are recorded as assets or liabilities on the consolidated balance sheets at fair value. In addition, if a derivative instrument is designated as a cash flow hedge, Great Plains Energy and KCP&L document the method of determining hedge effectiveness and measuring ineffectiveness. See Note 1918 for additional information regarding derivative financial instruments and hedging activities.

Great Plains Energy and KCP&L offset fair value amounts recognized for derivative instruments under master netting arrangements, which include rights to reclaim cash collateral (a receivable), or the obligation to return cash collateral (a payable). Great Plains Energy and KCP&L classify cash flows from derivative instruments in the same category as the cash flows from the items being hedged.

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Utility Plant

Great Plains Energy’s and KCP&L's utility plant is stated at historical cost. These costs include taxes, an allowance for the cost of borrowed and equity funds used to finance construction and payroll-related costs, including pensions and other fringe benefits. Replacements, improvements and additions to units of property are capitalized. Repairs of property and replacements of items not considered to be units of property are expensed as incurred (except as discussed under Deferred Refueling Outage ~~Costs and Accounting for Planned Major Maintenance)~~Costs). When property units are retired or otherwise disposed, the original cost, net of salvage, is charged to accumulated depreciation. Substantially all of KCP&L’s utility plant is pledged as collateral for KCP&L’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented. Substantially all of GMO’s St. Joseph Light & Power division utility plant is pledged as collateral for GMO’s mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented.

As prescribed by ~~the~~The Federal Energy Regulatory Commission (FERC), Allowance for Funds Used During Construction (AFUDC) is charged to the cost of the plant during construction. AFUDC equity funds are included as a non-cash item in non-operating income and AFUDC borrowed funds are a reduction of interest charges. The rates used to compute gross AFUDC are compounded semi-annually and averaged 0.2% in 2011, 6.8% in 2010 and 7.6% in 2009 ~~and 7.1% in 2008~~ for KCP&L and for GMO averaged 5.4% in 2011, 4.6% in 2010 and 5.4% in ~~2009 and 4.9% in 2008 subsequent to its acquisition on July 14, 2008.~~2009.

Great Plains Energy’s and KCP&L’s balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following tables.

Great Plains Energy
December 31 2010 2009
Utility Plant, at original cost (millions)
Production (20 - 60 years) $ 6,369.4 $ 4,892.3
Transmission (15 - 70 years) 716.9 660.4
Distribution (8 - 66 years) 2,813.4 2,708.3
General (5 - 50 years) 637.2 588.0
Total (a)
$ 10,536.9 $ 8,849.0
(a) Includes $103.0 million and $96.3 million at December 31,
2010 and 2009, respectively, of land and other assets that
are not depreciated.

KCP&L
Great Plains Energy
December 31	December 31	2010		2009		2011		2010
Utility Plant, at original cost	Utility Plant, at original cost	(millions)				(millions)
	Production (20 - 60 years)	$	4,886.2	$	3,742.6
	Transmission (15 - 70 years)		408.7		371.3
	Distribution (8 - 55 years)		1,776.4		1,709.5
	General (5 - 50 years)		469.6		435.1
Generation (20 - 60 years)						$	6,594.0	$	6,369.4
Transmission (15 - 70 years)							734.8		716.9
Distribution (8 - 66 years)							2,921.1		2,813.4
General (5 - 50 years)							674.9		637.2
Total (a)	Total (a)	$	7,540.9	$	6,258.5	$	10,924.8	$	10,536.9
(a)	Includes $59.9 million and $56.1 million at December 31,
	2010 and 2009, respectively, of land and other assets that
	are not depreciated.
(a) Includes $105.5 million and $103.0 million at December 31,						(a) Includes $105.5 million and $103.0 million at December 31,
2011 and 2010, respectively, of land and other assets that						2011 and 2010, respectively, of land and other assets that
are not depreciated.

KCP&L
December 31	2011		2010
Utility Plant, at original cost	(millions)
Generation (20 - 60 years)	$	5,078.1	$	4,886.2
Transmission (15 - 70 years)		412.9		408.7
Distribution (8 - 55 years)		1,840.2		1,776.4
General (5 - 50 years)		498.1		469.6
Total (a)	$	7,829.3	$	7,540.9
(a) Includes $59.8 million and $59.9 million at December 31,
2011 and 2010, respectively, of land and other assets that
are not depreciated.

6870

Depreciation and Amortization

Depreciation and amortization of utility plant other than nuclear fuel is computed using the straight-line method over the estimated lives of depreciable property based on rates approved by state regulatory authorities. Annual depreciation rates average approximately 3%. Nuclear fuel is amortized to fuel expense based on the quantity of heat produced during the generation of electricity.

Great Plains Energy’s depreciation expense was $239.9 million, $243.6 million and $228.9 million for 2011, 2010 and ~~$175.1 million for 2010,~~ 2009, ~~and 2008,~~ respectively. KCP&L’s depreciation expense was $162.0 million, $170.9 million and $158.4 million for 2011, 2010 and ~~$145.4 million for 2010,~~ 2009, ~~and 2008,~~ respectively. Great Plains Energy’s and KCP&L’s depreciation and amortization expense includes $14.4 million, $72.6 million and $58.2 million for 2011, 2010 and ~~$47.4 million for 2010,~~ 2009, ~~and 2008,~~ respectively, of additional amortization to help maintain cash flow levels during KCP&L’s Comprehensive Energy Plan pursuant to orders of the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC). This additional amortization concluded following the December 2010 and May 2011 effective dates of new retail rates for KCP&L in Kansas and Missouri, respectively.

Nuclear Plant Decommissioning Costs

Nuclear plant decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration. Based on these cost estimates, KCP&L contributes to a tax-qualified trust fund to be used to decommission Wolf Creek Generating Station (Wolf Creek). Related liabilities for decommissioning are included on Great Plains Energy’s and KCP&L’s balance ~~sheet~~sheets in Asset Retirement Obligations (AROs).

As a result of the authorized regulatory treatment and related regulatory accounting, differences between the decommissioning trust fund asset and the related ARO are recorded as a regulatory asset or liability. See Note 87 for discussion of AROs including those associated with nuclear plant decommissioning costs.

Deferred Refueling Outage Costs

KCP&L uses the deferral method to account for operations and maintenance expenses incurred in support of Wolf Creek’s scheduled refueling outages and amortizes them evenly (monthly) over the unit’s operating cycle of 18 months until the next scheduled outage. Replacement power costs during an outage are expensed as incurred.

Regulatory Matters

KCP&L and GMO defer items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded if KCP&L and GMO were not regulated. See Note 65 for additional information concerning regulatory matters.

Revenue Recognition

Great Plains Energy and KCP&L recognize revenues on sales of electricity when the service is provided. Revenues recorded include electric services provided but not yet billed by KCP&L and GMO. Unbilled revenues are recorded for kWh usage in the period following the customers’ billing cycle to the end of the month. KCP&L’s and GMO’s estimate is based on net system kWh usage less actual billed kWhs. KCP&L’s and GMO’s estimated unbilled kWhs are allocated and priced by regulatory jurisdiction across the rate classes based on actual billing rates.

KCP&L and GMO collect from customers gross receipts taxes levied by state and local governments. These taxes from KCP&L’s Missouri customers are recorded gross in operating revenues and general taxes on Great Plains Energy’s and KCP&L’s statements of income. KCP&L’s gross receipts taxes collected from Missouri customers were $55.6 million, $54.3 million, and $46.8 million in 2011, 2010 and ~~$45.9 million in 2010,~~ 2009, ~~and 2008,~~ respectively. These taxes from KCP&L’s Kansas customers and GMO’s customers are recorded net in operating revenues on Great Plains Energy’s statements of income.

Great Plains Energy and KCP&L collect sales taxes from customers and remit to state and local governments. These taxes are presented on a net basis on Great Plains Energy’s and KCP&L’s statements of income.

Great Plains Energy and KCP&L record sale and purchase activity on a net basis in wholesale revenue or purchased power when transacting with Regional Transmission Organization (RTO)/Independent System Operator (ISO) markets.

Allowance for Doubtful Accounts

This reserve represents estimated uncollectible accounts receivable and is based on management’s judgment considering historical loss experience and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are charged off against the reserve when they are deemed uncollectible.

Property Gains and Losses

Net gains and losses from the ~~sales~~sale of assets and businesses and from asset impairments are recorded in operating expenses.

Asset Impairments

Long-lived assets and ~~finite lived~~finite-lived intangible assets subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the undiscounted expected future cash flows from an asset to be held and used is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. The amount of impairment recognized is the excess of the carrying value of the asset over its fair value.

Goodwill and indefinite lived intangible assets are tested for ~~impairment annually and when~~ impairment annually and when an event occurs indicating the possibility that an impairment ~~exist~~s.exists. The annual test must be performed at the same time each year. If the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, the implied fair value of the reporting unit goodwill is compared with its carrying value.

Income Taxes

~~Great Plains Energy has recognized deferred~~Income taxes are accounted for ~~temporary book to tax differences~~ using the asset/liability ~~method. The liability method requires that deferred~~approach. Deferred tax ~~balances be adjusted to reflect~~assets and liabilities are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, applying enacted statutory tax rates ~~that are anticipated to be~~ in effect ~~when~~for the ~~temporary~~year in which the differences are expected to reverse. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.

Great Plains Energy and KCP&L recognize tax benefits based on a “more-likely-than-not” recognition threshold. In addition, Great Plains Energy and KCP&L recognize interest accrued related to unrecognized tax benefits in interest expense and penalties in non-operating expenses.

Great Plains Energy ~~and its subsidiaries file~~files a consolidated federal income tax return as well as unitary and combined ~~and separate state~~ income tax ~~returns.~~returns in several state jurisdictions with Kansas and Missouri being the most significant. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss. KCP&L’s income tax provision includes taxes allocated based on its separate company income or loss.

Great Plains Energy and KCP&L have established a net regulatory asset for the additional future revenues to be collected from customers for deferred income taxes. Tax credits are recognized in the year generated except for certain KCP&L and GMO investment tax credits that have been deferred and amortized over the remaining service lives of the related properties.

Environmental Matters

Environmental costs are accrued when it is probable a liability has been incurred and the amount of the liability can be reasonably estimated.

Basic and Diluted Earnings per Common Share Calculation

To determine basic EPS, preferred stock dividend requirements and net income (loss) attributable to noncontrolling interest are deducted from income from continuing operations and net income before dividing by the average number of common shares outstanding. The ~~earnings (loss)~~loss per share impact of discontinued operations is determined by dividing ~~income (loss)~~loss from discontinued operations, net of income taxes, by the average number of common shares outstanding. The effect of dilutive securities, calculated using the treasury stock method, assumes the issuance of common shares applicable to performance shares, restricted stock, stock options and Equity Units.

The following table reconciles Great Plains Energy’s basic and diluted EPS from continuing operations.

2010 2009 2008
Income (millions, except per share amounts)
Income from continuing operations $ 211.9 $ 151.9 $ 119.7
Less: net income attributable to noncontrolling interest 0.2 0.3 0.2
Less: preferred stock dividend requirements 1.6 1.6 1.6
Income from continuing operations available for common shareholders $ 210.1 $ 150.0 $ 117.9
Common Shares Outstanding
Average number of common shares outstanding 135.1 129.3 101.1
Add: effect of dilutive securities 1.8 0.5 0.1
Diluted average number of common shares outstanding 136.9 129.8 101.2
Basic EPS from continuing operations $ 1.55 $ 1.16 $ 1.16
Diluted EPS from continuing operations $ 1.53 $ 1.15 $ 1.16


	2011			2010		2009
Income	(millions, except per share amounts)
Income from continuing operations	$	174.2		$	211.9	$	151.9
Less: net income (loss) attributable to noncontrolling interest		(0.2	)		0.2		0.3
Less: preferred stock dividend requirements		1.6			1.6		1.6
Income from continuing operations available for common shareholders	$	172.8		$	210.1	$	150.0
Common Shares Outstanding
Average number of common shares outstanding		135.6			135.1		129.3
Add: effect of dilutive securities		3.1			1.8		0.5
Diluted average number of common shares outstanding		138.7			136.9		129.8
Basic EPS from continuing operations	$	1.27		$	1.55	$	1.16
Diluted EPS from continuing operations	$	1.25		$	1.53	$	1.15

The computation of diluted EPS for 2011 excludes anti-dilutive shares consisting of 50,897 performance shares, 43,641 restricted stock shares and 6,000 stock options.

The computation of diluted EPS for 2010 excludes anti-dilutive shares consisting of 340,690 performance shares, 251,526 restricted stock shares and 196,137 stock options.

The computation of diluted EPS for 2009 excludes anti-dilutive shares consisting of 150,895 performance shares, 438,281 restricted stock shares and 231,670 stock options.

~~The computation of diluted EPS for 2008 excludes anti-dilutive shares consisting of 364,217 performance shares, 530,398 restricted stock shares and 455,469 stock options.~~

Dividends Declared

In February ~~2011,~~2012, Great Plains Energy’s Board of Directors (Board) declared a quarterly dividend of ~~$0.2075~~$0.2125 per share on Great Plains Energy’s common stock. The common dividend is payable March ~~21, 2011,~~20, 2012, to shareholders of record as of February 28, ~~2011.~~2012. The Board also declared regular dividends on Great Plains Energy’s preferred stock, payable ~~June 1, 2011,~~March 20, 2012, to shareholders of record as of ~~May 10,~~June 1, 2011.

In February ~~2011,~~2012, KCP&L’s Board of Directors declared a cash dividend payable to Great Plains Energy of $25 million payable on March ~~17, 2011.~~19, 2012.

7173

2.	SUPPLEMENTAL CASH FLOW INFORMATION

Great Plains Energy Other Operating Activities
2010 2009 2008
Cash flows affected by changes in: (millions)
Receivables $ (12.6 ) $ 7.9 $ 61.9
Accounts receivable pledged as collateral (95.0 ) - -
Fuel inventories (0.1 ) 2.0 (16.7 )
Materials and supplies (11.5 ) (22.0 ) (3.7 )
Accounts payable 12.8 (70.9 ) 56.2
Accrued taxes 6.7 42.2 73.2
Accrued interest 2.9 2.9 17.8
Deferred refueling outage costs 9.9 (7.1 ) (5.9 )
Accrued plant maintenance costs 1.7 2.9 2.1
Fuel adjustment clauses 2.7 7.8 (18.0 )
Pension and post-retirement benefit obligations (10.2 ) 18.4 3.1
Allowance for equity funds used during construction (26.0 ) (39.6 ) (24.2 )
Write down of affordable housing investments 11.2 - -
Iatan Nos. 1 and 2 impact of disallowed construction costs 16.8 - -
Deferred acquisition costs - - (15.8 )
Interest rate hedge settlements (6.9 ) (79.1 ) (41.2 )
Other (36.1 ) 16.8 (36.4 )
Total other operating activities $ (133.7 ) $ (117.8 ) $ 52.4
Cash paid during the period:
Interest $ 237.7 $ 211.9 $ 95.0
Income taxes $ 0.9 $ 5.1 $ 27.1
Non-cash investing activities:
Liabilities assumed for capital expenditures $ 44.9 $ 82.8 $ 104.7

Great Plains Energy Other Operating Activities
Year Ended December 31	2011			2010			2009
Cash flows affected by changes in:	(millions)
Receivables	$	3.6		$	(12.6	)	$	7.9
Accounts receivable pledged as collateral		-			(95.0	)		-
Fuel inventories		(3.9	)		(0.1	)		2.0
Materials and supplies		(7.5	)		(11.5	)		(22.0	)
Accounts payable		5.7			12.8			(70.9	)
Accrued taxes		1.4			6.7			42.2
Accrued interest		1.5			2.9			2.9
Deferred refueling outage costs		(17.9	)		9.9			(7.1	)
Fuel adjustment clauses		(1.7	)		2.7			7.8
Pension and post-retirement benefit obligations		(56.0	)		(10.2	)		18.4
Allowance for equity funds used during construction		(1.0	)		(26.0	)		(39.6	)
Write down of affordable housing investments		-			11.2			-
Interest rate hedge settlements		(26.1	)		(6.9	)		(79.1	)
Iatan Nos. 1 and 2 impact of disallowed construction costs		2.3			16.8			-
Uncertain tax positions		(20.8	)		(6.1	)		10.7
Other		(27.1	)		(28.3	)		9.0
Total other operating activities	$	(147.5	)	$	(133.7	)	$	(117.8	)
Cash paid during the period:
Interest	$	254.4		$	237.7		$	211.9
Income taxes	$	2.8		$	0.9		$	5.1
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	39.7		$	44.9		$	82.8

7274

KCP&L Other Operating Activities
	2010			2009			2008
Year Ended December 31										2011			2010			2009
Cash flows affected by changes in:	(millions)									(millions)
Receivables	$	(4.1	)	$	(7.6	)	$	50.9		$	(20.2	)	$	(4.1	)	$	(7.6	)
Accounts receivable pledged as collateral		(95.0	)		-			-			-			(95.0	)		-
Fuel inventories		0.7			6.1			(16.0	)		(14.1	)		0.7			6.1
Materials and supplies		(9.6	)		(16.5	)		(4.3	)		(6.7	)		(9.6	)		(16.5	)
Accounts payable		0.8			(54.3	)		57.3			11.0			0.8			(54.3	)
Accrued taxes		(15.7	)		51.8			81.3			2.7			(15.7	)		51.8
Accrued interest		(0.5	)		8.6			8.5			3.8			(0.5	)		8.6
Deferred refueling outage costs		9.9			(7.1	)		(5.9	)		(17.9	)		9.9			(7.1	)
Pension and post-retirement benefit obligations		7.9			39.3			(5.1	)		(45.6	)		7.9			39.3
Allowance for equity funds used during construction		(21.9	)		(30.6	)		(22.5	)		(0.7	)		(21.9	)		(30.6	)
Kansas Energy Cost Adjustment		(8.8	)		2.2			(1.6	)		(5.8	)		(8.8	)		2.2
Iatan Nos. 1 and 2 impact of disallowed construction costs		13.0			-			-			1.5			13.0			-
Interest rate hedge settlements		-			(79.1	)		(41.2	)		-			-			(79.1	)
Uncertain tax positions											(10.4	)		(1.8	)		3.3
Other		(4.5	)		21.1			(28.6	)		(15.9	)		(2.7	)		17.8
Total other operating activities	$	(127.8	)	$	(66.1	)	$	72.8		$	(118.3	)	$	(127.8	)	$	(66.1	)
Cash paid during the period:
Interest	$	101.1		$	77.2		$	63.0		$	111.3		$	101.1		$	77.2
Income taxes	$	18.2		$	31.9		$	23.5		$	0.1		$	18.2		$	31.9
Non-cash investing activities:
Liabilities assumed for capital expenditures	$	37.4		$	75.5		$	90.8		$	32.0		$	37.4		$	75.5

Significant Non-Cash Items

On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the recognition of $95.0 million of accounts ~~receivables~~receivable pledged as collateral and a corresponding short-term collateralized note payable on Great Plains Energy’s and KCP&L’s balance ~~sheets at December 31, 2010. See Note 3 for additional information.~~sheets. As a result, cash flows from operating activities were reduced by $95.0 million and cash flows from financing activities were raised by $95.0 million with no impact to the net change in cash atfor the year ended December 31, 2010.

On July 14, 2008, Great Plains Energy closed its acquisition of GMO. The total purchase price of the acquisition was approximately $1.7 billion. The fair value of the 32.2 million shares of Great Plains Energy common stock issued was approximately $1.0 billion. Great Plains Energy paid approximately $0.7 billion of cash consideration.

In May 2008, KCP&L’s Series 2008 Environmental Improvement Revenue Refunding (EIRR) bonds totaling $23.4 million maturing in 2038 were issued. The proceeds were deposited with a trustee pending KCP&L’s submission of qualifying expenses for reimbursement. At December 31, 2008, KCP&L had received $13.4 million in cash proceeds and had a $10.0 million short-term receivable for the proceeds that were deposited with the trustee. In 2009, KCP&L received the remaining $10.0 million in cash.

In 2008, KCP&L recorded a $12.6 million net increase in AROs, consisting of a $14.2 million increase as a result of changes in cost estimates and timing used to compute the present value of asbestos AROs for KCP&L’s generating stations, with a corresponding increase in net utility plant and a decrease of $1.6 million resulting from an update to the cost estimates to decommission Wolf Creek, with a corresponding increase in regulatory liabilities. This activity had no impact on Great Plains Energy’s or KCP&L’s 2008 cash flows.

7375

3.	RECEIVABLES

Great Plains Energy’s and KCP&L’s receivables are detailed in the following table.


	December 31						December 31
	2010			2009			2011			2010
Great Plains Energy	(millions)						(millions)
Customer accounts receivable - billed	$	62.0		$	47.3		$	69.8		$	62.0
Customer accounts receivable - unbilled		82.3			77.9			82.4			82.3
Allowance for doubtful accounts		(2.7	)		(2.8	)		(2.5	)		(2.7	)
Other receivables		100.1			108.1			81.5			100.1
Total	$	241.7		$	230.5		$	231.2		$	241.7
KCP&L
Customer accounts receivable - billed	$	6.5		$	-		$	16.4		$	6.5
Customer accounts receivable - unbilled		50.1			44.6			50.0			50.1
Allowance for doubtful accounts		(1.5	)		(1.7	)		(1.4	)		(1.5	)
Intercompany receivables		43.2			42.4			38.7			43.2
Other receivables		71.1			76.4			69.2			71.1
Total	$	169.4		$	161.7		$	172.9		$	169.4

Great Plains Energy’s and KCP&L’s other receivables at December 31, ~~2010~~2011 and ~~2009,~~2010 consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables.

Sale of Accounts Receivable – KCP&L

KCP&L sells all of its retail electric accounts receivable to its wholly owned subsidiary, Receivables Company, which in turn sells an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor. ~~On January 1, 2010, Great Plains Energy and KCP&L adopted new accounting guidance for transfers of financial assets, which resulted in the~~Receivables Company’s sale of the undivided percentage ownership interest in accounts receivable byto Victory Receivables ~~Company no longer meeting the criteria for derecognition and now being~~Corporation is accounted for as a secured ~~borrowing. As a result,~~borrowing with $95.0 million of accounts ~~receivables~~receivable pledged as collateral ~~are recognized with~~and a corresponding short-term collateralized note payable recognized on Great Plains Energy’s and KCP&L’s balance sheets at December 31, 2011 and 2010.

KCP&L sells its receivables at a fixed price based upon the expected cost of funds and charge-offs. These costs comprise KCP&L’s loss on the sale of accounts receivable. KCP&L services the receivables and receives an annual servicing fee of 1.5% ~~to 2.5%~~ of the outstanding principal amount of the receivables sold to Receivables Company. KCP&L does not recognize a servicing asset or liability because management determined the collection agent fee earned by KCP&L approximates market value. ~~In February 2011, the~~The agreement ~~was amended to extend the expiration date of the agreement from May 2011 to October 2011.~~expires in September 2014 and allows for $110 million in aggregate outstanding principal amount at any time.

7476

Information regarding KCP&L’s sale of accounts receivable to Receivables Company is reflected in the following tables.


				Receivables			Consolidated
2011	KCP&L			Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(1,415.6	)	$	1,415.6		$	-
Gain (loss) on sale of accounts receivable (a)		(17.9	)		17.7			(0.2	)
Servicing fees		2.6			(2.6	)		-
Fees to outside investor		-			(1.2	)		(1.2	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,412.4	)		1,412.4			-
Cash paid to KCP&L for receivables purchased		1,394.7			(1,394.7	)		-
Servicing fees		2.6			(2.6	)		-
Interest on intercompany note		0.5			(0.5	)		-


				Receivables			Consolidated						Receivables			Consolidated
2010	KCP&L			Company			KCP&L			KCP&L			Company			KCP&L
	(millions)									(millions)
Receivables (sold) purchased	$	(1,341.0	)	$	1,341.0		$	-		$	(1,341.0	)	$	1,341.0		$	-
Gain (loss) on sale of accounts receivable (a)		(17.0	)		16.8			(0.2	)		(17.0	)		16.8			(0.2	)
Servicing fees		3.2			(3.2	)		-			3.2			(3.2	)		-
Fees to outside investor		-			(1.2	)		(1.2	)		-			(1.2	)		(1.2	)

Cash flows during the period
Cash from customers transferred to Receivables Company		(1,337.4	)		1,337.4			-			(1,337.4	)		1,337.4			-
Cash paid to KCP&L for receivables purchased		1,320.7			(1,320.7	)		-			1,320.7			(1,320.7	)		-
Servicing fees		3.2			(3.2	)		-			3.2			(3.2	)		-
Interest on intercompany note		0.5			(0.5	)		-			0.5			(0.5	)		-

(a) Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
over the life of the agreement will net to zero.

Receivables Consolidated
2009 KCP&L Company KCP&L
(millions)
Receivables (sold) purchased $ (1,172.4 ) $ 1,172.4 $ -
Gain (loss) on sale of accounts receivable (a)
(14.8 ) 14.6 (0.2 )
Servicing fees 2.0 (2.0 ) -
Fees to outside investor - (1.2 ) (1.2 )

Cash flows during the period
Cash from customers transferred to Receivables Company (1,167.6 ) 1,167.6 -
Cash paid to KCP&L for receivables purchased 1,153.0 (1,153.0 ) -
Servicing fees 2.0 (2.0 ) -
Interest on intercompany note 0.4 (0.4 ) -
(a) Any net gain (loss) is the result of the timing difference inherent in collecting receivables and
over the life of the agreement will net to zero.

4.	~~ASSETS HELD FOR SAL~~E

A~~s of December 31, 2009,~~ ~~Great Plains Energy had several~~ ~~real estate properties a~~vailable for immediate sale in their present condition and management was actively marketing these properties. The carrying amounts for these assets were presented at fair value less estimated selling cost and were included in assets held for sale on Great Plains Energy’s consolidated balance sheets as of December 31, 2009. In March 2010, one of the properties with a book value of $0.6 million was sold resulting in an insignificant loss on the sale. In October 2010, one of the properties included in the electric utility segment with a book value of $11.1 million was sold resulting in an insignificant gain on the sale. As of December 31, 2010, management determined that the sale of the remaining properties was no longer considered probable. Accordingly, the $7.7 million of properties were reclassified from assets held for sale to other-investments and other assets on the consolidated balance sheet as of December 31, 2010.

5.	NUCLEAR PLANT

KCP&L owns 47% of Wolf Creek, its only nuclear generating unit. Wolf Creek is located in Coffey County, Kansas, just northeast of Burlington, Kansas. Wolf Creek’s operating license expires in 2045. Wolf Creek is regulated by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements. Wolf Creek is operating in the category of nuclear plants receiving the lowest level of NRC oversight.

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kWh of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to fuel expense. In ~~March~~ 2010, the DOE filed a motion with the Nuclear Regulatory Commission (NRC) to withdraw its then pending application to the NRC to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, ~~Nevada, which would bring the licensing process to an end.~~Nevada. An NRC board denied the DOE’s

motion to withdraw its application, ~~in June 2010,~~ and the DOE appealed that decision to the full NRC. In 2011, the NRC ~~in early July 2010. The NRC has not yet decided that appeal. The question of~~issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s ~~legal authority~~application by the end of September 2011 due to ~~withdraw~~a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license ~~application also is pending in multiple lawsuits filed with~~review and to issue a ~~federal appellate court.~~decision on the license application. Oral argument to the court is ~~set for late March 2011.~~expected later in 2012. Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025, and believes it will be able to expand on-site storage as needed past 2025. Management cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity. See Note 1615 for a related legal proceeding.

Low-Level Radioactive Waste

Wolf Creek disposes of most of its low-level radioactive waste (Class A waste) at an existing third-party repository in Utah. Management expects that the site located in Utah will remain available to Wolf Creek for disposal of its Class A waste. Wolf Creek has contracted with a waste processor that will process, take title and store in another state most of the remainder of Wolf Creek’s ~~low level~~low-level radioactive waste (Classes B and C waste, which is higher in radioactivity but much lower in volume). Should on-site waste storage be needed in the future, Wolf Creek has current storage capacity on site for about four years’ generation of Classes B and C waste and believes it will be able to expand that storage capacity as needed if it becomes necessary to do so.

Nuclear Plant Decommissioning Costs

The MPSC and KCC require KCP&L and the other owners of Wolf Creek to submit an updated decommissioning cost study every three years and to propose funding levels. The most recent study was submitted to the MPSC and KCC in August ~~2008~~2011 and is the basis for the current cost of decommissioning estimates in the ~~table below. KCC issued its order~~following table. Funding levels included in ~~August 2009 approving the 2008 decommissioning cost study, and approved funding levels in its order issued in November 2010. The MPSC does~~KCP&L retail rates have not ~~explicitly approve or disapprove of the decommissioning cost study and issued its order approving the funding levels in May 2009.~~changed.

Total

KCP&L's

Total

KCP&L's

Station

47% Share

Station

47% Share

(millions)

Current cost of decommissioning (in 2008 dollars)

$ 594

$ 279

Current cost of decommissioning (in 2011 dollars)

630

296

Future cost of decommissioning (in 2045-2053 dollars) (a)

2,575

1,210

Future cost of decommissioning (in 2045-2053 dollars) (a)

2,455

1,154

Annual escalation factor

3.73%

Annual escalation factor

3.73%

Annual return on trust assets (b)

6.83%

Annual return on trust assets (b)

6.89%

(a)

Total future cost over an eight year decommissioning period.

(b)

The 6.83% rate of return is through 2025. The rate then systematically decreases through 2053 to 1.87%

The 6.89% rate of return is through 2025. The rate then systematically decreases

based on the assumption that the fund's investment mix will become increasingly more conservative

through 2053 to 1.81% based on the assumption that the fund's investment mix

as the decommissioning period approaches.

will become increasingly more conservative as the decommissioning period

approaches.

Nuclear Decommissioning Trust Fund

In ~~2010~~2011 and ~~2009,~~2010, KCP&L contributed approximately $3.4 million and $3.7 million, respectively, to a tax-qualified trust fund to be used to decommission Wolf Creek. Amounts funded are charged to other operating expense and recovered in customers’ rates. The funding level assumes a projected level of return on trust assets. If the actual return on trust assets is

below the projected level or actual decommissioning costs are higher than estimated,, KCP&L could be responsible for the balance of funds required; however, while there can be no assurances, management believes a rate increase would be allowed to recover decommissioning costs over the remaining life of the unit.

The following table summarizes the change in Great Plains Energy’s and KCP&L’s nuclear decommissioning trust fund.

December 31 2010 2009
Decommissioning Trust (millions)
Beginning balance January 1 $ 112.5 $ 96.9
Contributions 3.7 3.7
Earned income, net of fees 2.0 2.8
Net realized gains/(losses) 6.7 (5.5 )
Net unrealized gains 4.3 14.6
Ending balance $ 129.2 $ 112.5


December 31	2011			2010
Decommissioning Trust	(millions)
Beginning balance January 1	$	129.2		$	112.5
Contributions		3.4			3.7
Earned income, net of fees		4.8			2.0
Net realized gains		0.3			6.7
Net unrealized gains (losses)		(2.4	)		4.3
Ending balance	$	135.3		$	129.2

The nuclear decommissioning trust is reported at fair value on the balance sheets and is invested in assets as detailed in the following table. At December 31, 2009, KCP&L was holding short-term investments in the decommissioning trust fund, which were invested in equity securities in early 2010 as a result of a change in the asset allocation of the trust to a higher proportion of equity securities given the 20-year extension of Wolf Creek’s operating license approved by the NRC in November 2008.

December 31
2010 2009
Gross Gross Gross Gross
Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair
Basis Gains Losses Value Basis Gains Losses Value
(millions)
Equity securities $     73.4 $     13.1 $     (1.0) $     85.5 $     36.3 $       8.9 $     (0.7) $     44.5
Debt securities         38.1           2.6         (0.1)         40.6         35.3           2.1               -         37.4
Other           3.1               -               -           3.1         30.6               -               -         30.6
   Total $   114.6 $     15.7 $     (1.1) $   129.2 $   102.2 $     11.0 $     (0.7) $   112.5


	December 31
	2011									2010
	Cost		Unrealized		Unrealized			Fair		Cost		Unrealized		Unrealized			Fair
	Basis		Gains		Losses			Value		Basis		Gains		Losses			Value
	(millions)
Equity securities	$	76.5	$	12.3	$	(4.5	)	$	84.3	$	73.4	$	13.1	$	(1.0	)	$	85.5
Debt securities		44.2		4.5		(0.1	)		48.6		38.1		2.6		(0.1	)		40.6
Other		2.4		-		-			2.4		3.1		-		-			3.1
Total	$	123.1	$	16.8	$	(4.6	)	$	135.3	$	114.6	$	15.7	$	(1.1	)	$	129.2

The weighted average maturity of debt securities held by the trust at December 31, ~~2010,~~2011, was approximately ~~7.6~~7 years. The costs of securities sold are determined on the basis of specific identification. The following table summarizes the realized gains and losses from the sale of securities byin the nuclear decommissioning trust fund.

2010 2009 2008
(millions)
Realized Gains $ 7.3 $ 2.8 $ 2.7
Realized Losses (0.6 ) (8.3 ) (10.9 )


	2011			2010			2009
	(millions)
Realized gains	$	1.0		$	7.3		$	2.8
Realized losses		(0.7	)		(0.6	)		(8.3	)

Nuclear Insurance

The owners of Wolf Creek (Owners) maintain nuclear insurance for Wolf Creek for nuclear liability, nuclear property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war. The nuclear property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for acts of terrorism and related losses, including replacement power costs. There is no industry aggregate limit for liability claims related to terrorism, regardless of the number of acts of terrorism affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place. An industry aggregate limit of $3.2 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), the Owners’ insurance provider, exists for property claims related to terrorism, including accidental outage power

costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits plus any recoverable reinsurance are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

In the event of a catastrophic loss at Wolf Creek, the insurance coverage may not be adequate to cover property damage and extra expenses incurred. Uninsured losses, to the extent not recovered through rates, would be assumed by KCP&L and the other owners and could have a material ~~adverse~~ effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, which was reauthorized through December 31, 2025, by the Energy Policy Act of 2005, the Owners are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently $12.6 billion. This limit of liability consists of the maximum available commercial insurance of $0.4 billion and the remaining $12.2 billion is provided through an industry-wide retrospective assessment program mandated by law, known as the Secondary Financial Protection (SFP) program. Under the SFP program, the Owners can be assessed up to $117.5 million ($55.2 million, KCP&L’s 47% share) per incident at any commercial reactor in the country, payable at no more than $17.5 million ($8.2 million, KCP&L’s 47% share) per incident per year. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

Nuclear Property Insurance

The Owners carry decontamination liability, premature decommissioning liability and property damage insurance from NEIL for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, KCP&L's 47% share). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. KCP&L’s share of any remaining proceeds can be used for further decontamination, property damage restoration and premature decommissioning costs. Premature decommissioning coverage applies only if an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses, and only after trust funds have been exhausted.

Accidental Nuclear Outage Insurance

The Owners also carry additional insurance from NEIL to cover costs of replacement power and other extra expenses incurred in the event of a prolonged outage resulting from accidental property damage at Wolf Creek.

Under all NEIL policies, the Owners are subject to retrospective assessments if NEIL losses, for each policy year, exceed the accumulated funds available to the insurer under that policy. The estimated maximum amount of retrospective assessments under the current policies could total approximately ~~$26.2~~$30.9 million ($~~12.3~~14.5 million, KCP&L’s 47% share) per policy year.

6.5.	REGULATORY MATTERS

KCP~~&L’s Comprehensive Energy Plan~~

KCP&L’s Comprehensive Energy Plan included construction of Iatan No. 2, wind generation, environmental upgrades at certain coal-fired generating stations, infrastructure investments, and energy efficiency, affordability and demand response programs. With the construction of Iatan No. 2 completed in 2010, the remaining ~~component~~ ~~of KCP&L’s Comprehensive Energy Plan is~~ ~~to obtain state regulatory approval to include the cost of~~ ~~Iatan No. 2~~ in ~~rate base~~ ~~and begin recovering the investment in rates~~.

~~In the fourth quarter of 2010, Great Plains Energy and KCP~~&L completed a final cost estimate for Iatan No. 2. The final cost estimate and previous cost estimate ranges are shown in the following table. The cost estimate ranges do not include AFUDC or the cost of common facilities that were identified at the time of the start-up of the Iatan No. 1 environmental project that will be used by both Iatan No. 1 and Iatan No. 2.

Kansas ~~Regulatory~~Rate Case Proceedings

On February 27, 2012, KCP&L filed an application with the MPSC ~~would disallow these costs as well in KCP&L’s and GMO’s pending rate cases. Therefore, KCP&L’s Missouri jurisdictional portion and GMO’s portion~~to request an increase of ~~these costs were recognized as a loss in addition to the KCP&L Kansas jurisdictional portion resulting in a $16.8~~its retail rates of $105.7 million, ~~pre-tax loss~~ ~~representing KCP&L’s and GMO’s combined share~~ ~~for construction costs incurred through December 31, 2010.~~

~~Missouri Regulatory Proceedings~~

~~The following table summarizes pending requests for retail rate increases~~ with ~~the MPSC.~~

In September 2010, GMO received an order from the MPSC approving construction accounting for the Iatan No. 2 project from the Iatan No. 2 in-service date to the effective date of new rates in the current rate case. The effect of the order is to defer GMO’s share of Iatan No. 2 operating costs, depreciation expense and carrying costs (interest) ~~offset by Iatan No. 2’s system energy value~~ to a regulatory asset rather than impacting the income statement until new rates are effective. KCP&L (Missouri jurisdiction only) was granted construction accounting as part of the Comprehensive Energy Plan.

In November 2010, the MPSC staff filed its construction audit and prudence review regarding construction expenditures through June 30, 2010, for Iatan No. 2 and the Iatan No. 1 environmental project. The MPSC staff recommended disallowances of approximately $130 million and $70 million of the total costs incurred through June 30, 2010, for Iatan No. 2 and the Iatan No. 1 environmental project, respectively~~, representing all audited expenditures above the associated December 2006 control budget estimates of approximately $1.685 billion and $377 million~~.

~~The MPSC staff also filed testimony in KCP&L’s and GMO’s rate cases in November 2010. The MPSC staff’s testimony recommended~~ a return on equity ~~range~~ of ~~8.5%~~10.4% and a rate-making equity ratio of 52.5%. The request includes recovery of costs related to ~~9.5%~~improving and maintaining infrastructure to continue to be able to provide reliable electric service and also includes a lower annual offset to the revenue ~~increase/(decrease) ranges of approximately $(0.2) million to $14 million~~requirement for ~~KCP&L, approximately $0.9 million to $10.1 million for GMO’s~~the Missouri Public Service division, and approximately $28.8 million to $32.6 million for GMO’s St. Joseph Light & Power division. On February 22, 2011, the MPSC Staff filed updated testimony recommending the same return on equity range of 8.5% to 9.5% and revenue increase ranges of approximately $2.2 million to $17.0 million for KCP&L, approximately $29,000 to $9.2 million for GMO's Missouri Public Service division, and approximately $14.9 million to $18.4 million for GMO's St. Joseph Light & Power division. The revenuejurisdictional

portion of KCP&L’s annual non-firm wholesale electric sales margin (wholesale margin offset). KCP&L currently expects that it will not be able to achieve the $45.9 million wholesale margin offset currently reflected in its retail rates due to a decline in wholesale power prices, which is being driven by low natural gas prices.

On April 12, 2011, the MPSC issued an order and on April 14, 2011, the MPSC Staff filed a report which quantified an authorized revenue increase of approximately $34.8 million on an annual basis, which reflects a wholesale margin offset of approximately $45.9 million and authorizes a return on equity of 10.0%, an equity ratio of approximately 46.3% and a Missouri jurisdictional rate base of approximately $2.0 billion effective May 4, 2011. If the actual Missouri jurisdiction wholesale margin amount exceeds the $45.9 million level reflected in the MPSC order, the difference will be recorded as a regulatory liability and will be returned, with interest, to KCP&L Missouri customers in a future rate case. The MPSC order provides the opportunity for KCP&L to retain a larger amount of non-firm wholesale electric sales margin than KCP&L proposed; however, there are no assurances that KCP&L will achieve the $45.9 million wholesale margin offset amount and there are no means for KCP&L to recover any shortfall through its retail rates unless the MPSC authorizes future recovery.

As a result of disallowances in the April 2011 MPSC order, KCP&L recognized losses of $1.5 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project during 2011. KCP&L also recorded a $2.4 million loss for other disallowed costs in the MPSC order.

~~recommendations~~In a related order, the MPSC required KCP&L and GMO to apply to the Internal Revenue Service (IRS) to reallocate approximately $26.5 million of Iatan No. 2 qualifying advance coal project tax credits from KCP&L to GMO. KCP&L and GMO did apply to the IRS but in September 2011, the IRS denied KCP&L’s and GMO’s request. The MPSC has indicated it will consider the ratemaking treatment of the tax credits in a future rate case. Certain ratemaking treatments that may be pursued by the MPSC could trigger the loss or repayment to the IRS of a portion of unamortized deferred investment tax credits. At December 31, 2011, KCP&L and GMO had $127.9 million and $3.3 million, respectively, of unamortized deferred investment tax credits.

GMO Missouri Rate Case Proceedings

On May 4, 2011, the MPSC issued an order and on May 10, 2011, the MPSC Staff filed a report which quantified authorized revenue increases on an annual basis of $30.1 million for GMO’s Missouri Public Service division and $29.3 million for GMO’s St. Joseph Light & Power (L&P) division. The MPSC order authorized a return on equity of 10.0%, an equity ratio of approximately 46.6% and a Missouri jurisdictional rate base of $1.76 billion. In response to applications for clarification and rehearing of the MPSC order, the MPSC on May 27, 2011, issued an order of clarification and modification. The modified MPSC order revised the authorized annual revenue increases to approximately $35.7 million for GMO’s Missouri Public Service division and approximately $29.8 million for GMO’s L&P division, resulting primarily from a clarification of the amount of fuel costs shifted from GMO’s fuel adjustment clause to base rates. However, because the MPSC authorized an annual revenue increase that was greater than the amount originally requested by GMO for its L&P division and communicated to GMO’s L&P customers, the modified MPSC order deferred approximately $7.7 million of the L&P division increase,

which is the amount over GMO’s requested $22.1 million increase for that division, and will phase in the deferred revenue amount in equal parts over a two-year period, plus carrying costs. In addition, GMO shall be allowed to recover the revenue which would have been allowed in the absence of a phase in.

As a result of disallowances in the May 2011 MPSC order, GMO recognized losses of $0.8 million for construction costs related to Iatan No. 2 and the Iatan No. 1 environmental project during 2011. GMO also recorded a $1.5 million loss for other disallowed costs in the MPSC order.

Additionally, with respect to GMO’s Missouri Public Service division, the MPSC concluded that GMO’s decision to add Crossroads Energy Center (Crossroads) to its generation asset resources was prudent and reasonable; however, the order disallowed from rate base approximately $50 million for Crossroads, disallowed $4.9 million in associated annual transmission expense and offset rate base by approximately $15 million to reflect accumulated deferred taxes associated with Crossroads. GMO’s request included a net plant amount of approximately $104 million for Crossroads. In assessing the impact of the Crossroads disallowances, management considered that KCP&L’s and GMO’s generation asset resources include a diverse fuel mix consisting primarily of coal and nuclear fuel providing base load generation with natural gas facilities such as Crossroads to provide critical peaking and capacity support. This combined collection of generating assets meets KCP&L’s and GMO’s service obligations and produces joint cash flows based on system-wide average costs. Great Plains Energy conducted an analysis to assess the recoverability of the combined collection of generation asset resources and determined that no potential impairment exists.

GMO Fuel Adjustment Clause (FAC) Prudence Review

GMO’s electric retail rates contain an FAC tariff under which 95% of the difference between actual fuel cost, purchased power costs and off-system sales margin and the amount provided in base rates for these costs is passed along to GMO’s customers. The MPSC requires prudence reviews of the FAC no less frequently than at 18-month intervals. On November 28, 2011, the MPSC staff filed its prudence review report for the 18-month prudence review period covering June 1, 2009 through November 30, 2010. The MPSC staff recommended to the MPSC to order GMO to refund approximately $19 million, plus interest, to customers through an adjustment to its FAC because the MPSC staff asserts that GMO was imprudent in its use of natural gas hedges to mitigate risk associated with its future purchases in the spot power market. GMO is disputing the MPSC staff’s ~~proposed construction cost disallowances~~claim of ~~all audited expenditures as of October 31, 2010, above the control budget estimates,~~ ~~among other differences from KCP&L’s~~imprudence and ~~GMO’s requests~~. filed its testimony on February 22, 2012. A hearing is scheduled for May 16 – 17, 2012, with an order expected in June 2012.

~~Hearings were held~~ ~~beginning~~ ~~in late January 2011 for KCP&L~~ ~~and ran through mid-~~February 2011 for GMO. The MPSC Staff will file reconciliations of the differences between its February 22, 2011, recommendations and KCP&L's and GMO's February 22, 2011, recommendations with hearings scheduled for March 3 - 4, 2011. New rates are expected to go into effect in May 2011 for KCP&L and June 2011 for GMO.

SPP and NERC ~~Audits~~

Inquiries

~~In November 2009, the~~The Southwest Power Pool, Inc. (SPP) and the North American Electric Reliability Corporation (NERC) conducted scheduled audits of KCP&L and GMO regarding compliance with NERC reliability and critical infrastructure protection standards. KCP&L and GMO received the final audit report alleging violation of certain standards and management anticipates paying ~~a penalty that will have an immaterial impact to cash flows and results of operations.~~ ~~The SPP also~~ conducted a compliance inquiry regarding a transmission system outage that occurred in the St. Joseph, Missouri area in the summer of 2009. ~~NERC~~ The North American Electric Reliability Corporation (NERC) is also investigating the circumstances surrounding this transmission system outage. The outcome of the outage inquiry cannot be predicted at this time.

~~Energy Efficiency~~

Great Plains Energy and KCP&L have implemented various energy efficiency programs. KCP&L also agreed in the Collaboration Agreement to pursue initiatives, including energy efficiency, designed to offset CO2 ~~emissions. The Companies currently recover energy efficiency program expenses on a deferred basis~~ with no recovery mechanism for associated lost revenues. An MPSC rulemaking proceeding in Missouri to address recovery of and earnings on investments in energy efficiency programs is near completion with final rules expected to be effective in the second quarter of 2011. Great Plains Energy and KCP&L will evaluate alternatives for future energy efficiency programs under these new rules.

~~MPSC Regulatory Approval of the GMO Acquisition~~

Appeals of the MPSC order approving the GMO acquisition were filed with the Cole County, Missouri, Circuit Court, which affirmed the order in June 2009. That decision was appealed and the Missouri Court of Appeals, Western District, upheld the MPSC order in August 2010. The case was transferred to the Missouri Supreme Court in December 2010.

~~GMO Missouri 2007 Rate Case Appeal~~

Appeals of the May 2007 MPSC order approving an approximate $59 million increase in annual revenues were filed in July and August of 2007 with the Circuit Court of Cole County, Missouri, by the Office of Public Counsel, AG Processing, Sedalia Industrial Energy Users’ Association and AARP seeking to set aside or remand the order of the MPSC. In February 2009, the Circuit Court affirmed the MPSC order. The Circuit Court’s decision was affirmed by the Court of Appeals in August 2009. The case was transferred to the Missouri Supreme Court in August 2010. In December 2010, the Missouri Supreme Court re-transferred the case to the Court of Appeals, Western District, which re-adopted its opinion and re-affirmed the MPSC order on January 4, 2011. The Company does not currently expect any further action with respect to this matter.

Regulatory Assets and Liabilities

Great Plains Energy and KCP&L have recorded assets and liabilities on their consolidated balance sheets resulting from the effects of the ratemaking process, which would not otherwise be recorded if the Companies were not regulated. Regulatory assets represent incurred costs that are probable of recovery from future revenues. Regulatory liabilities represent future reductions in revenues or refunds to customers.

8182

Management regularly assesses whether regulatory assets and liabilities are probable of future recovery or refund by considering factors such as decisions by the MPSC, KCC or FERC in KCP&L’s and GMO’s rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedent on matters applicable to the Companies; and changes in laws and regulations. If recovery or refund of regulatory assets or liabilities is not approved by regulators or is no longer deemed probable, these regulatory assets or liabilities are recognized in the current period results of operations. The Companies’ continued ability to meet the criteria for recording regulatory assets and liabilities may be affected in the future by restructuring and deregulation in the electric industry or changes in accounting ~~rules~~.rules. In the event that the criteria no longer applied to any or all of the Companies’ operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism iswere provided. Additionally, these factors could result in an impairment on utility plant assets.

Great Plains Energy’s and KCP&L’s regulatory assets and liabilities are detailed in the following tables.


							Great								Great
December 31, 2010	KCP&L			GMO			Plains Energy
December 31, 2011									KCP&L			GMO			Plains Energy
Regulatory Assets	(millions)								(millions)
Taxes recoverable through future rates	$	117.2		$	25.3		$	142.5	$	119.6		$	24.6		$	144.2
Loss on reacquired debt		5.0	(a)		0.7	(a)		5.7		9.1	(a)		2.7	(a)		11.8
Cost of removal		8.5			-			8.5		4.6			-			4.6
Asset retirement obligations		27.5			12.8			40.3		31.4			13.8			45.2
Pension settlements		9.0	(b)		-			9.0
Pension and post-retirement costs		377.1	(c)		106.7	(c)		483.8		466.4	(b)		122.0	(b)		588.4
Deferred customer programs		44.7	(d)		15.6			60.3		48.2	(c)		20.6			68.8
Rate case expenses		12.3	(e)		3.3	(e)		15.6		9.6	(d)		3.8	(d)		13.4
Skill set realignment costs		4.8	(f)		-			4.8		3.4	(e)		-			3.4
Fuel adjustment clauses		8.4	(e)		37.1	(e)		45.5		14.0	(d)		36.4	(d)		50.4
Acquisition transition costs		29.3	(g)		22.5	(g)		51.8		24.7	(f )		20.2	(f )		44.9
St. Joseph Light & Power acquisition		-			2.6	(h)		2.6
Storm damage		-			3.2	(i)		3.2
Derivative instruments		-			3.1	(j)		3.1		-			7.6	(g)		7.6
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1	(k)		4.3	(l)		19.4		16.4			6.1			22.5
Iatan No. 2 construction accounting costs		17.2	(l)		6.5	(l)		23.7		27.9			15.4			43.3
Kansas property tax surcharge										3.7	(d)		-			3.7
Other		3.5	(m)		0.7	(m)		4.2		1.7	(h)		4.3	(h)		6.0
Total	$	679.6		$	244.4		$	924.0	$	780.7		$	277.5		$	1,058.2
Regulatory Liabilities
Emission allowances	$	85.9		$	0.5		$	86.4	$	82.0		$	0.2		$	82.2
Asset retirement obligations		44.9			-			44.9		49.3			-			49.3
Pension		-			37.1			37.1		0.7			40.8			41.5
Cost of removal		-			62.8	(n)		62.8		-			61.9	(i)		61.9
Other		10.5			16.5			27.0		10.8			22.8			33.6
Total	$	141.3		$	116.9		$	258.2	$	142.8		$	125.7		$	268.5

(a)	Amortized over the life of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.

(b)	~~$5.0 million not included~~ Represents unrecognized gains and losses, prior service and transition costs that will be recognized in ~~rate base~~future net periodic pension and post-retirement costs, pension settlements amortized ~~through 2012.~~

~~(c)~~

~~Represents the funded status of the pension plans more than offset by related liabilities. Also represents~~over various periods and financial and regulatory

accounting method differences not included in rate base that will be eliminated over the life of the pension plans.

~~(d)~~ (c)

$~~13.2~~10.4 million not included in rate base and amortized over various periods.

~~(e)~~ (d)

Not included in rate base and amortized over various periods.

~~(f)~~ (e)

$~~2.8~~2.4 million not included in rate base and amortized through 2017.

~~(g)~~

Not included in rate base. The MPSC order provided for the deferral of transition costs to be amortized over a five-year period to the extent that synergy savings exceed transition cost amortization. The Company settled its first post-transaction rate cases and the settlement agreements did not address transition costs. The Company will continue to defer transition costs until amortization is ordered by the MPSC. KCC order approved the deferral of up to $10.0 million of transition costs to be amortized over a five-year period beginning with rates effective in December 2010.

~~(h)~~ (f)

Not included in rate base and amortized through ~~2015.~~2016.

~~(i)~~

~~Not included in rate base and amortized through 2012.~~

~~(j)~~ (g)

Represents the fair value of derivative instruments for commodity contracts. Settlements of the contracts are recognized in fuel expense and included in GMO’s ~~fuel adjustment clause (FAC).~~FAC.

~~(k)~~

~~$11.6 million not included in rate base and under consideration in the pending Missouri rate case.~~

~~(l)~~

~~Not included in rate base and under consideration in the pending Missouri rate cases.~~

~~(m)~~ (h)

Certain insignificant items are not included in rate base and amortized over various periods.

~~(n)~~ (i)

Estimated cumulative net provision for future removal costs.

Great
December 31, 2009 KCP&L GMO Plains Energy
Regulatory Assets (millions)
Taxes recoverable through future rates $ 77.6 $ 22.9 $ 100.5
Loss on reacquired debt 5.3 0.3 5.6
Cost of removal 7.9 - 7.9
Asset retirement obligations 23.8 11.9 35.7
Pension settlements 13.5 - 13.5
Pension and post-retirement costs 395.0 84.5 479.5
Deferred customer programs 35.6 7.1 42.7
Rate case expenses 7.4 1.5 8.9
Skill set realignment costs 6.1 - 6.1
Fuel adjustment clauses 0.7 47.5 48.2
Acquisition transition costs 29.3 22.2 51.5
St. Joseph Light & Power acquisition - 3.1 3.1
Storm damage - 4.8 4.8
Derivative instruments - 2.1 2.1
Iatan No. 1 and Common facilities depreciation and carrying costs 4.6 1.4 6.0
Other 5.3 0.8 6.1
Total $ 612.1 $ 210.1 $ 822.2
Regulatory Liabilities
Emission allowances $ 86.2 $ 0.8 $ 87.0
Asset retirement obligations 33.4 - 33.4
Pension - 34.0 34.0
Cost of removal - 62.5 62.5
Other 7.3 13.6 20.9
Total $ 126.9 $ 110.9 $ 237.8


					Great
December 31, 2010	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	117.2	$	25.3	$	142.5
Loss on reacquired debt		5.0		0.7		5.7
Cost of removal		8.5		-		8.5
Asset retirement obligations		27.5		12.8		40.3
Pension and post-retirement costs		386.1		106.7		492.8
Deferred customer programs		44.7		15.6		60.3
Rate case expenses		12.3		3.3		15.6
Skill set realignment costs		4.8		-		4.8
Fuel adjustment clauses		8.4		37.1		45.5
Acquisition transition costs		29.3		22.5		51.8
Derivative instruments		-		3.1		3.1
Iatan No. 1 and Common facilities depreciation and carrying costs		15.1		4.3		19.4
Iatan No. 2 construction accounting costs		17.2		6.5		23.7
Other		3.5		6.5		10.0
Total	$	679.6	$	244.4	$	924.0
Regulatory Liabilities
Emission allowances	$	85.9	$	0.5	$	86.4
Asset retirement obligations		44.9		-		44.9
Pension		-		37.1		37.1
Cost of removal		-		62.8		62.8
Other		10.5		16.5		27.0
Total	$	141.3	$	116.9	$	258.2

7.6.	GOODWILL AND INTANGIBLE ASSETS

Accounting rules require goodwill to be tested for impairment annually and when an event occurs indicating the possibility that an impairment exists. The annual impairment test for the $169.0 million of GMO acquisition goodwill was conducted on September 1, ~~2010.~~2011. The goodwill impairment test is a two step ~~process. The firs~~tprocess. The first step compares thethe fair value of a reporting unit to its carrying amount, including goodwill, to identify potential impairment. If the carrying amount exceeds the fair value of the reporting unit, the second step of the test is performed, consisting of assignment of the reporting unit’s fair value to its assets and liabilities to determine an implied fair value of goodwill,, which is compared to the carrying amount of goodwill to determine the impairment loss, if any, to be recognized in the financial statements. Great Plains Energy’s regulated electric

utility operations are considered one reporting unit for assessment of impairment, as they are included within the same operating segment and have similar economic characteristics. The determination of fair value of the reporting unit consisted of two valuation techniques: an income approach consisting of a discounted cash flow analysis and a market approach consisting of a determination of reporting unit invested capital using market multiples derived from the historical revenue, EBITDA and net utility asset values and market prices of stock of electric and gas company regulated peers. The results of the two techniques were evaluated and weighted to determine a point within the range that management considered representative of fair value for the reporting unit. Fair value of the reporting unit exceeded the carrying amount, including goodwill; therefore, there was no impairment of goodwill.

Great Plains Energy’s and KCP&L’s intangible assets are included in electric utility plant on the consolidated balance sheets and are detailed in the following table.

December 31, 2010 December 31, 2009
Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
KCP&L (millions)
Computer software $ 168.2 $ (118.0 ) $ 147.0 $ (106.3 )
Transmission line 5.8 - - -

Great Plains Energy
Computer software $ 201.1 $ (137.3 ) $ 170.8 $ (117.8 )
Transmission line and upgrades 27.9 (4.4 ) 22.1 (3.7 )
Organization start-up costs 0.1 - 0.1 -


	December 31, 2011					December 31, 2010
	Gross Carrying		Accumulated			Gross Carrying		Accumulated
	Amount		Amortization			Amount		Amortization
KCP&L	(millions)
Computer software	$	171.7	$	(129.9	)	$	168.2	$	(118.0	)
Asset improvements		11.7		(0.6	)		5.8		-

Great Plains Energy
Computer software	$	202.5	$	(143.5	)	$	201.1	$	(137.3	)
Asset improvements		27.0		(3.7	)		27.9		(4.4	)

Great Plains Energy’s and KCP&L’s amortization expense related to intangible assets is detailed in the following table.


	2010		2009		2011		2010
	(millions)				(millions)
Great Plains Energy	$	13.1	$	10.9	$	13.5	$	13.1
KCP&L		12.2		10.4		12.6		12.2

The following table provides the estimated amortization expense related to Great Plains Energy’s and KCP&L’s intangible assets for ~~2011~~2012 through ~~2015~~2016 for the intangible assets included in the consolidated balance sheets at December 31, ~~2010.~~2011.


	2011		2012		2013		2014		2015		2012		2013		2014		2015		2016
	(millions)										(millions)
Great Plains Energy	$	12.7	$	10.8	$	8.4	$	5.0	$	2.9	$	13.9	$	11.2	$	8.1	$	6.0	$	4.7
KCP&L		11.9		10.0		7.6		4.3		2.3		11.0		8.3		5.3		3.4		2.1

8.7.	ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations associated with tangible long-lived assets are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel. These liabilities are recognized at estimated fair value as incurred and capitalized as part of the cost of the related long-lived assets and depreciated over their useful lives. Accretion of the liabilities due to the passage of time is recorded to a regulatory asset and/or liability. Changes in the estimated fair values of the liabilities are recognized when known.

KCP&L has AROs related to decommissioning Wolf Creek, site remediation of its Spearville Wind Energy Facilities, asbestos abatement and for removal of storage tanks, an ash pond and landfill. GMO has AROs related to asbestos abatement, an ash pond and landfill and removal of storage tanks and communication towers.

~~Management has~~GPE and KCP&L have identified an additional asbestos ARO. Certain wiring used in generating stations includes asbestos insulation, which would require special handling if disturbed. Due to the inability to reasonably estimate the quantities or the amount of disturbance that will be necessary during dismantlement at the end of the life of a plant, a fair value of the obligation cannot be reasonably estimated at this time. Management will continue to monitor the obligation and will recognize a liability in the period in which sufficient information becomes available to reasonably estimate its fair value.

The following table summarizes the change in Great Plains Energy’s and KCP&L’s AROs.


	Great Plains Energy					KCP&L				Great Plains Energy					KCP&L
	2010		2009			2010		2009		2011			2010		2011			2010
	(millions)									(millions)
Beginning balance	$	132.6	$	124.3		$	119.8	$	111.9	$	143.3		$	132.6	$	129.7		$	119.8
Additions		2.0		1.2			2.0		0.6		0.8			2.0		-			2.0
Revision in timing and/or estimates		-		(1.0	)		-		-		(3.8	)		-		(3.8	)		-
Accretion		8.7		8.1			7.9		7.3		9.3			8.7		8.4			7.9
Ending balance	$	143.3	$	132.6		$	129.7	$	119.8	$	149.6		$	143.3	$	134.3		$	129.7

9.8.	PENSION PLANS, ~~AND~~ OTHER EMPLOYEE BENEFITS AND VOLUNTARY SEPARATION PROGRAM

Great Plains Energy maintains defined benefit pension plans for substantially all active and inactive employees, including officers, of KCP&L, GMO and Wolf Creek Nuclear Operating Corporation (WCNOC) and incurs significant costs in providing the plans. Pension benefits under these plans reflect the employees’ compensation, years of service and age at retirement. In addition to providing pension benefits, Great Plains Energy provides certain post-retirement health care and life insurance benefits for substantially all retired employees of KCP&L, GMO and WCNOC.

KCP&L and GMO record pension and post-retirement expense in accordance with rate orders from the MPSC and KCC that allow the difference between pension and post-retirement costs under GAAP and ~~pension~~ costs for ratemaking to be recognized as a regulatory asset or liability. This difference between financial and regulatory accounting methods is due to timing and will be eliminated over the life of the ~~pension~~ plans.

~~In addition to providing pension benefits,~~During 2011, Great Plains Energy ~~provides certain post-retirement health care and life insurance benefits for~~recorded settlement charges of $10.1 million from the voluntary separation program as a result of accelerated pension distributions. The Companies deferred substantially all ~~retired employees~~ of ~~KCP&L, GMO,~~the charges as a regulatory asset and ~~WCNOC. The cost of post-retirement benefits charged~~expect to ~~KCP&L and GMO are accrued during an employee's years of service and recovered through rates.~~recover it over future periods pursuant to regulatory agreements. See below for information regarding the voluntary separation program.

The following pension benefits tables provide information relating to the funded status of all defined benefit pension plans on an aggregate basis as well as the components of net periodic benefit costs. For financial reporting purposes, the market value of plan assets is the fair value. KCP&L uses a five-year smoothing of assets to determine fair value for regulatory reporting purposes. As a result of the GMO acquisition on July 14, 2008, the Company’s 2008 pension and post-retirement expenses under GAAP increased $2.4 million and $1.1 million, respectively. The underfunded status of the pension and other post-retirement benefit plans transferred at the date of acquisition was $48.9 million. Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with ~~joint-owners~~joint owners of power plants.

Pension Benefits Other Benefits
2010 2009 2010 2009
Change in projected benefit obligation (PBO) (millions)
PBO at beginning of year $ 836.3 $ 772.5 $ 148.9 $ 135.4
Service cost 30.3 29.1 3.8 4.1
Interest cost 49.3 47.3 8.8 8.3
Contribution by participants - - 5.6 5.3
Amendments 0.5 5.7 - 3.4
Actuarial (gain) loss 55.1 33.1 (12.5 ) 3.9
Benefits paid (60.1 ) (49.3 ) (11.0 ) (11.5 )
Settlements - (2.1 ) - -
PBO at end of plan year $ 911.4 $ 836.3 $ 143.6 $ 148.9
Change in plan assets
Fair value of plan assets at beginning of year $ 488.2 $ 418.7 $ 52.0 $ 38.9
Actual return on plan assets 62.7 75.1 0.5 0.7
Contributions by employer and participants 64.5 42.1 23.9 22.0
Benefits paid (57.8 ) (47.7 ) (10.6 ) (9.6 )
Fair value of plan assets at end of plan year $ 557.6 $ 488.2 $ 65.8 $ 52.0
Funded status at end of year $ (353.8 ) $ (348.1 ) $ (77.8 ) $ (96.9 )
Amounts recognized in the consolidated balance sheets
Current pension and other post-retirement liability $ (3.1 ) $ (3.7 ) $ (1.0 ) $ (0.9 )
Noncurrent pension liability and other post-retirement liability (350.7 ) (344.4 ) (76.8 ) (96.0 )
Net amount recognized before regulatory treatment (353.8 ) (348.1 ) (77.8 ) (96.9 )
Accumulated OCI or regulatory asset/liability 403.2 386.2 54.8 74.0
Net amount recognized at December 31 $ 49.4 $ 38.1 $ (23.0 ) $ (22.9 )
Amounts in accumulated OCI or regulatory asset/liability
not yet recognized as a component of net periodic cost:
Actuarial loss $ 219.5 $ 227.8 $ 8.5 $ 19.3
Prior service cost 15.3 19.4 44.1 51.3
Transition obligation - 0.1 3.0 4.3
Other 168.4 138.9 (0.8 ) (0.9 )
Net amount recognized at December 31 $ 403.2 $ 386.2 $ 54.8 $ 74.0

Pension Benefits Other Benefits
2010 2009 2008 2010 2009 2008
Components of net periodic benefit costs (millions)
Service cost $ 30.3 $ 29.1 $ 20.8 $ 3.8 $ 4.1 $ 1.7
Interest cost 49.3 47.3 37.6 8.8 8.3 5.7
Expected return on plan assets (36.6 ) (32.4 ) (38.6 ) (2.1 ) (1.6 ) (1.0 )
Prior service cost 4.6 4.2 4.2 7.2 6.9 2.7
Recognized net actuarial (gain) loss 37.4 36.3 32.3 (0.1 ) (0.4 ) 0.6
Transition obligation 0.1 0.1 0.1 1.3 1.3 1.2
Settlement charges - 0.1 - - - -
Net periodic benefit costs before
regulatory adjustment 85.1 84.7 56.4 18.9 18.6 10.9
Regulatory adjustment (32.3 ) (28.4 ) (3.5 ) - (0.3 ) -
Net periodic benefit costs 52.8 56.3 52.9 18.9 18.3 10.9
Other changes in plan assets and benefit
obligations recognized in OCI or
regulatory assets/liabilities (a)

Current year net (gain) loss 29.1 (9.2 ) 227.1 (10.9 ) (0.2 ) 6.0
Amortization of gain (loss) (37.4 ) (36.3 ) (39.9 ) 0.1 0.4 (0.7 )
Prior service cost 0.5 5.7 - - 24.8 18.7
Amortization of prior service cost (4.6 ) (4.2 ) (5.2 ) (7.2 ) (6.9 ) (3.4 )
Transition obligation - - - - 1.2 -
Amortization of transition obligation (0.1 ) (0.1 ) - (1.3 ) (1.3 ) (1.4 )
Other regulatory activity 29.5 10.1 52.8 0.1 (3.1 ) 2.1
Total recognized in OCI or regulatory asset/liability 17.0 (34.0 ) 234.8 (19.2 ) 14.9 21.3
Total recognized in net periodic benefit costs
and OCI or regulatory asset/liability $ 69.8 $ 22.3 $ 287.7 $ (0.3 ) $ 33.2 $ 32.2
(a) 2008 includes the effect of the remeasurement adjustment


	Pension Benefits						Other Benefits
	2011			2010			2011			2010
Change in projected benefit obligation (PBO)	(millions)
PBO at beginning of year	$	911.4		$	836.3		$	143.6		$	148.9
Service cost		31.1			30.3			3.1			3.8
Interest cost		49.6			49.3			7.8			8.8
Contribution by participants		-			-			6.6			5.6
Amendments		-			0.5			-			-
Actuarial (gain) loss		83.2			55.1			7.4			(12.5	)
Benefits paid		(54.7	)		(60.1	)		(14.3	)		(11.0	)
Settlements		(40.0	)		-			-			-
PBO at end of plan year	$	980.6		$	911.4		$	154.2		$	143.6
Change in plan assets
Fair value of plan assets at beginning of year	$	557.6		$	488.2		$	65.8		$	52.0
Actual return on plan assets		(3.7	)		62.7			2.5			0.5
Contributions by employer and participants		128.8			64.5			23.0			23.9
Benefits paid		(91.6	)		(57.8	)		(13.9	)		(10.6	)
Fair value of plan assets at end of plan year	$	591.1		$	557.6		$	77.4		$	65.8
Funded status at end of year	$	(389.5	)	$	(353.8	)	$	(76.8	)	$	(77.8	)
Amounts recognized in the consolidated balance sheets
Current pension and other post-retirement liability	$	(3.5	)	$	(3.1	)	$	(0.9	)	$	(1.0	)
Noncurrent pension liability and other post-retirement liability		(386.0	)		(350.7	)		(75.9	)		(76.8	)
Net amount recognized before regulatory treatment		(389.5	)		(353.8	)		(76.8	)		(77.8	)
Accumulated OCI or regulatory asset/liability		491.8			403.2			52.5			54.8
Net amount recognized at December 31	$	102.3		$	49.4		$	(24.3	)	$	(23.0	)
Amounts in accumulated OCI or regulatory asset/liability
not yet recognized as a component of net periodic benefit cost:
Actuarial loss	$	295.6		$	219.5		$	15.7		$	8.5
Prior service cost		10.7			15.3			36.9			44.1
Transition obligation		-			-			1.7			3.0
Other		185.5			168.4			(1.8	)		(0.8	)
Net amount recognized at December 31	$	491.8		$	403.2		$	52.5		$	54.8


	Pension Benefits									Other Benefits
	2011			2010			2009			2011			2010			2009
Components of net periodic benefit costs	(millions)
Service cost	$	31.1		$	30.3		$	29.1		$	3.1		$	3.8		$	4.1
Interest cost		49.6			49.3			47.3			7.8			8.8			8.3
Expected return on plan assets		(38.0	)		(36.6	)		(32.4	)		(1.8	)		(2.1	)		(1.6	)
Prior service cost		4.6			4.6			4.2			7.2			7.2			6.9
Recognized net actuarial (gain) loss		38.7			37.4			36.3			(0.5	)		(0.1	)		(0.4	)
Transition obligation		-			0.1			0.1			1.3			1.3			1.3
Settlement charges		10.1			-			0.1			-			-			-
Net periodic benefit costs before
regulatory adjustment		96.1			85.1			84.7			17.1			18.9			18.6
Regulatory adjustment		(27.9	)		(32.3	)		(28.4	)		1.1			-			(0.3	)
Net periodic benefit costs		68.2			52.8			56.3			18.2			18.9			18.3
Other changes in plan assets and benefit
obligations recognized in OCI or
regulatory assets/liabilities
Current year net (gain) loss		114.8			29.1			(9.2	)		6.7			(10.9	)		(0.2	)
Amortization of gain (loss)		(38.7	)		(37.4	)		(36.3	)		0.5			0.1			0.4
Prior service cost		-			0.5			5.7			-			-			24.8
Amortization of prior service cost		(4.6	)		(4.6	)		(4.2	)		(7.2	)		(7.2	)		(6.9	)
Transition obligation		-			-			-			-			-			1.2
Amortization of transition obligation		-			(0.1	)		(0.1	)		(1.3	)		(1.3	)		(1.3	)
Other regulatory activity		17.1			29.5			10.1			(1.0	)		0.1			(3.1	)
Total recognized in OCI or regulatory asset/liability		88.6			17.0			(34.0	)		(2.3	)		(19.2	)		14.9
Total recognized in net periodic benefit costs
and OCI or regulatory asset/liability	$	156.8		$	69.8		$	22.3		$	15.9		$	(0.3	)	$	33.2

For financial reporting purposes, the estimated prior service cost and net loss ~~and transition costs~~ for the defined benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in ~~2011~~2012 are $4.5 million ~~$38.5 million~~ and ~~$0.1~~$44.5 million, respectively. For financial reporting purposes, net actuarial gains and losses are recognized on a rolling five-year average basis. For regulatory reporting purposes, net actuarial gains and losses are amortized over ten years. The estimated prior service cost, net gain and transition costs for the other post-retirement benefit plans that will be amortized from accumulated OCI or a regulatory asset into net periodic benefit cost in ~~2011~~2012 are $7.2 million, ~~$(1.0)~~$(0.1) million and ~~$1.3~~$1.0 million, respectively.

The accumulated benefit obligation (ABO) for all defined benefit pension plans was ~~$808.8~~$852.6 million and ~~$741.4~~$808.8 million at December 31, ~~2010~~2011 and ~~2009,~~2010, respectively. The PBO, ABO and ~~the~~ fair value of plan assets at plan year-end are aggregated by funded and ~~under funded~~underfunded plans in the following table.


	2010		2009		2011		2010
Pension plans with the ABO in excess of plan assets	(millions)				(millions)
Projected benefit obligation	$	911.4	$	836.3	$	980.6	$	911.4
Accumulated benefit obligation		808.8		741.4		852.6		808.8
Fair value of plan assets		557.6		488.2		591.1		557.6
Pension plans with plan assets in excess of the ABO					Pension plans with plan assets in excess of the ABO
Projected benefit obligation	$	-	$	-	$	-	$	-
Accumulated benefit obligation		-		-		-		-
Fair value of plan assets		-		-		-		-

The GMO SERP is reflected as an unfunded ABO of ~~$21.1~~$20.6 million. ~~The Company~~Great Plains Energy has segregated approximately ~~$21.5~~$20.1 million of assets for this plan as of December 31, ~~2010,~~2011, and expects to fund future benefit payments from these assets.

The expected long-term rate of return on plan assets represents ~~the Company’s~~Great Plains Energy’s estimate of the long-term return on plan assets and is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns of various asset classes. Based on the target asset allocation for each asset class, the overall expected rate of return for the portfolios was developed and adjusted for the effect of projected benefits paid from plan assets and future plan contributions. The following tables provide the weighted-average assumptions used to determine benefit obligations and net costs.

Weighted average assumptions used to determine Pension Benefits Other Benefits
the benefit obligation at plan year-end 2010 2009 2010 2009
Discount rate 5.54% 5.92% 5.50% 5.87%
Rate of compensation increase 4.08% 4.26% 4.06% 4.25%


Weighted average assumptions used to determine	Pension Benefits		Other Benefits
net costs for years ended at December 31	2010	2009	2010	2009
Weighted-average assumptions used to determine					Pension Benefits						Other Benefits
the benefit obligation at plan year-end					2011			2010			2011			2010
Discount rate						5.01	%		5.54	%		5.03	%		5.50	%
Rate of compensation increase						4.08	%		4.08	%		4.07	%		4.06	%


Weighted-average assumptions used to determine					Pension Benefits						Other Benefits
net costs for years ended December 31					2011			2010			2011			2010
Discount rate	5.92%	6.11%	5.87%	6.10%		5.54	%		5.92	%		5.50	%		5.87	%
Expected long-term return on plan assets	8.00%		4.25% *	4.00% *		7.29	%		8.00	%		2.83	% *		4.25	% *
Rate of compensation increase	4.26%	4.27%	4.25%			4.08	%		4.26	%		4.06	%		4.25	%
* after tax					* after tax

For pension benefits, ~~the Company's 2011~~Great Plains Energy's 2012 projected ~~weighted average~~weighted-average long-term rate of return on plan assets is 7.3%, ~~a 0.7% decrease~~unchanged from ~~2010. The reduction in the rate of return is expected to increase 2011 GAAP pension expense approximately $4 million.~~2011.

~~The Company~~Great Plains Energy expects to contribute ~~$104.6~~$94.5 million to the pension plans in ~~2011~~2012 to meet Employee Retirement Income Security Act of 1974 (ERISA) funding requirements and regulatory orders, the majority of which is expected to be paid by KCP&L. ~~The Company’s~~Great Plains Energy’s funding policy is to contribute amounts sufficient to meet the ERISA funding requirements and MPSC and KCC rate orders plus additional amounts as considered appropriate; therefore, actual contributions may differ from expected contributions. ~~The Company~~Great Plains Energy also expects to contribute ~~$15.8~~$16.7 million to other post-retirement benefit plans in ~~2011,~~2012, the majority of which is expected to be paid by KCP&L.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid through ~~2020.~~
2021.


	Pension		Other		Pension		Other
	Benefits		Benefits		Benefits		Benefits
	(millions)				(millions)
2011	$	71.4	$	8.4
2012		66.9		8.3	$	76.6	$	8.6
2013		66.2		8.4		65.5		8.1
2014		65.3		8.6		67.3		8.3
2015		67.9		8.6		66.5		8.2
2016-2020		370.0		47.7
2016						70.1		8.4
2017-2021						381.0		46.3

KCP&L’s secured 1992 Series EIRR bonds totaling $31.0 million, secured Series 1993A and 1993B EIRR bonds totaling $79.5 million, and secured and unsecured EIRR Bonds Series 2005 totaling $35.9 million and $50.0 million, respectively, are covered by a municipal bond insurance policy between KCP&L and Syncora Guarantee, Inc. (Syncora). The insurance agreements between KCP&L and Syncora provide for reimbursement by KCP&L for any amounts that Syncora pays under the municipal bond insurance policies. The insurance agreements contain a covenant that the indebtedness to total capitalization ratio of KCP&L and its consolidated subsidiaries will not be greater than 0.68 to 1.00. At December 31, ~~2010,~~2011, KCP&L was in compliance with this covenant. KCP&L is also restricted from issuing additional bonds under its General Mortgage Indenture if, after giving effect to such additional bonds, the proportion of secured debt to total indebtedness would be more than 75%, or more than 50% if the long term rating for such bonds by Standard & Poor’s or Moody’s Investors Service would be at or below A- or A3, respectively. The insurance agreement covering the unsecured EIRR Bond Series 2005 also required KCP&L to provide collateral to Syncora in the form of $50.0 million of Mortgage Bonds Series 2005 EIRR Insurer due 2035 for KCP&L’s obligations under the insurance agreement as a result of KCP&L issuing general mortgage bonds in 2009 (other than refunding of outstanding general mortgage bonds) ~~resulting~~that resulted in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. The bonds are not incremental debt for KCP&L but collateralize Syncora’s claim on KCP&L if Syncora was

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required to meet its obligation under the insurance agreement. In the event of a default under the insurance agreements, Syncora may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.

KCP&L Senior Notes

~~100~~In September 2011, KCP&L issued $400.0 million of 5.30% unsecured Senior Notes, maturing in 2041. In November 2011, KCP&L repaid its $150.0 million 6.5% Senior Notes at maturity.

GMO First Mortgage Bonds

GMO has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated April 1, 1946, as supplemented. The Indenture creates a mortgage lien on substantially all of GMO’s St. Joseph Light & Power division utility plant. Mortgage bonds totaling ~~$12.4~~$11.2 million and ~~$13.5~~$12.4 million, respectively, were outstanding at December 31, ~~2010~~2011 and ~~2009.~~2010.

GMO Senior Notes

The fair value adjustment for GMO represents the $133.3 million purchase accounting adjustment to record GMO’s debt related to the 11.875% ~~series~~ and 7.75% ~~series~~ Senior Notes that are not fully reflected in electric retail rates as of the July 14, 2008, acquisition date, at estimated fair value, with the offset recorded to goodwill. The fair value adjustment is being amortized as a reduction to interest expense over the remaining life of the individual debt issues. Amortization for 2011, 2010 and 2009 ~~and 2008~~ was $33.6 million, $34.6 million and $33.0 million, ~~and $15.8~~respectively. The fair value adjustment will be fully amortized in 2012 with amortization of $16.3 million.

GMO repaid its $137.3 million ~~respectively. Amortization for~~7.95% Senior Notes that matured in February 2011 and ~~2012 is estimated at $33.8~~$197.0 million ~~and $16.1 million, respectively.~~7.75% Senior Notes that matured in June 2011.

Great Plains Energy ~~2.75%~~ Senior Notes

In ~~August 2010,~~May 2011, Great Plains Energy issued ~~$250.0~~$350.0 million of ~~2.75%~~4.85% unsecured Senior Notes, maturing in ~~2013.~~2021. As a result of amortizing the loss recognized in Other Comprehensive Income (OCI) on Great Plains Energy’s three-year Forward Starting Swaps (FSS), the effective interest rate is ~~3.67%.~~7.34% through May 2014.

Great Plains Energy 10.00% Equity Units Subordinated Notes Classified As Current Maturities

In May 2009, Great Plains Energy issued $287.5 million of Equity Units. Equity Units, each with a stated amount of $50, initially consist of a 5% undivided beneficial interest in $1,000 principal amount of 10.00% subordinated notes due June 15, 2042, and a purchase contract requiring the holder to purchase the Company’s common stock by June 15, 2012 (the settlement date). Each purchase contract obligates the holder of the purchase contract to purchase, and Great Plains Energy to sell, no later than June 15, 2012, for $50 in cash, newly issued shares of the Company’s common stock equal to the settlement rate. The purchase contracts may be settled earlier at the option of the holder subject to certain conditions, including but not limited to, the occurrence of a fundamental change (as defined in the agreement) at least 20 business days prior to June 15, 2012. The settlement rate will vary according to the applicable market value of the Company’s common stock at the settlement date. The applicable market value will be measured by the average of the closing price per share of the Company’s common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding June 15, 2012. The settlement rate will be applied to the 5,750,000 Equity Units at the settlement date to issue a number of common shares determined as described in the following table.

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Applicable		Settlement rate	Market value
market value		(in common shares)	per Equity Unit (a)
$16.80 or greater		2.9762 to 1	Greater than $50 per Equity Unit

$16.80 to $14.00		$50 divided by the applicable	Equal to $50 per Equity Unit
		market value to 1

$14.00 or less		3.5714 to 1	Less than $50 per Equity Unit
(a)	Assumes that the market price of the Company's common stock on June 15, 2012,
	is the same as the applicable market value.

Great Plains Energy makes quarterly contract adjustment payments at the rate of 2.00% per year of the stated amount of $50 per Equity Unit and interest payments at the rate of 10.00% per year on the subordinated notes. Great Plains Energy must attempt to remarket the subordinated notes, in whole but not in part, ~~between December 15, 2011, and~~by June 12, 2012. In connection with a successful remarketing of the notes, Great Plains Energy may elect, without the consent of any of the holders, to modify the notes’ stated maturity to any date on or after June

~~101~~

15, 2014 and earlier than June 15, 2042. The proceeds from a successful remarketing will be used to satisfy the holders’ obligation under the purchase contract. If the notes have not been successfully remarketed by June 12, 2012, the holders of all notes will have the right to put their notes to Great Plains Energy on June 15, 2012, in satisfaction of the holders’ obligation under the purchase contracts and Great Plains Energy will issue to the holders newly issued shares of the Company’s common stock equal to the settlement rate.

The May 2009 present value of the contract adjustment payments of $15.1 million was recorded as a liability in other current liabilities and other deferred credits and other liabilities with a corresponding amount recorded as capital stock premium and expense on Great Plains Energy’s consolidated balance sheet. The liability is being relieved as Great Plains Energy makes quarterly contract adjustment payments.

Scheduled Maturities

Great Plains Energy’s and KCP&L’s long-term debt maturities for the next five years are detailed in the following table.


	2011		2012		2013		2014		2015		2012		2013		2014		2015		2016
	(millions)										(millions)
Great Plains Energy	$	485.7	$	513.9	$	263.1	$	1.5	$	15.5
Great Plains Energy $											Great Plains Energy $	801.4	$	263.1	$	1.5	$	15.5	$	1.6
KCP&L		150.3		12.7		0.4		0.4		14.4		12.7		0.4		0.4		14.4		0.4

~~13.~~12.

COMMON SHAREHOLDERS’ EQUITY

Great Plains Energy has an effective shelf registration statement for the sale of unspecified amounts of securities with the Securities and Exchange Commission (SEC) that was filed and became effective in May 2009.

In August 2008, Great Plains Energy entered into a Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC (BNYMCM). Under the terms of the agreement, Great Plains Energy may offer and sell up to 8.0 million shares of its common stock from time to time through BNYMCM, as agent, for a period of no more than three years. Great Plains Energy will pay BNYMCM a commission equal to 1% of the sales price of all shares sold under the agreement. No shares were sold during 2010. During 2009, 3.8 million shares were sold for $49.5 million in net proceeds. During 2008, 0.2 million shares were sold for $3.5 million in net proceeds.

Great Plains Energy has 5.0 million shares of common stock registered with the SEC for its Dividend Reinvestment and Direct Stock Purchase Plan. The plan allows for the purchase of common shares by reinvesting

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dividends or making optional cash payments. Great Plains Energy can issue new shares or purchase shares on the open market for the plan. At December 31, ~~2010, 0.8~~2011, 0.7 million shares remained available for future issuances.

Great Plains Energy has 12.3 million shares of common stock registered with the SEC for a defined contribution savings plan. Shares issued under the ~~plans~~plan may be either newly issued shares or shares purchased in the open market. At December 31, ~~2010, 1.9~~2011, 0.4 million shares remained available for future issuances.

Treasury shares are held for future distribution upon issuance of shares in conjunction with the Company’s Long-Term Incentive Plan.

~~102~~

Great Plains Energy’s articles of incorporation restrict the payment of common stock dividends in the event common equity is 25% or less of total capitalization. In addition, if preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of directors necessary to constitute a majority of the full Board. Certain conditions in the MPSC and KCC orders authorizing the holding company structure require Great Plains Energy and KCP&L to maintain consolidated common equity of at least 30% and 35%, respectively, of total capitalization (including only the amount of short-term debt in excess of the amount of construction work in progress). Under the Federal Power Act, KCP&L and GMO generally can pay dividends only out of retained earnings. The revolving credit agreements of Great Plains Energy, KCP&L and GMO contain a covenant requiring each company to maintain a consolidated indebtedness to consolidated total capitalization ratio of not more than 0.65 to 1.00. In addition, Great Plains Energy is prohibited from paying dividends on its common and preferred stock in the event its Equity Unit contract payments or interest payments on the debt underlying the Equity Units are deferred until such deferrals have been paid.

As of December 31, ~~2010,~~2011, all of Great Plains Energy’s and KCP&L’s retained earnings and net income were free of restrictions. As a result of the above restrictions, Great Plains Energy’s subsidiaries had restricted net assets of approximately $2.8 billion as of December 31, ~~2010.~~2011. The restrictions are not expected to affect the Companies’ ability to pay dividends at the current level in the foreseeable future.

~~14.~~13.

PREFERRED STOCK

At December 31, ~~2010,~~2011, 1.6 million shares of Cumulative No Par Preferred Stock, 390,000 shares of Cumulative Preferred Stock, $100 par value and 11.0 million shares of no par Preference Stock were authorized under Great Plains Energy’s ~~Articles~~articles of ~~Incorporation.~~incorporation. All of the 390,000 authorized shares of Cumulative Preferred Stock are issued and outstanding. Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices ranging from 101% to 103.7% of par value. If Great Plains Energy voluntarily files for dissolution or liquidation, the Cumulative Preferred Stock holders are entitled to receive the redemption prices. If a proceeding for dissolution or liquidation is filed against Great Plains Energy, the Cumulative Preferred Stock holders are entitled to receive the $100 par value per share plus accrued and unpaid dividends.

~~15.~~14.

COMMITMENTS AND CONTINGENCIES

Environmental Matters

Great Plains Energy and KCP&L are subject to extensive ~~regulation by~~ federal, state and local ~~authorities with regard~~environmental laws, regulations and permit requirements relating to ~~environmental matters primarily through their utility operations.~~air and water quality, waste management and disposal, natural resources and health and safety. In addition to imposing ~~extensive and~~ continuing compliance obligations and remediation costs, these laws, regulations and permits authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is expected to be material to Great Plains Energy and KCP&L. Failure to comply with environmental requirements or to timely recover environmental costs through rates could have a material ~~adverse~~ effect on Great Plains ~~Energy~~Energy’s and KCP~~&L.~~&L’s results of operations, financial position and cash flows.

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The following discussion groups environmental and certain associated matters into the broad categories of air and climate change, water, solid waste and remediation.

Air and Climate Change Overview

The Clean Air Act and associated regulations enacted by the Environmental Protection Agency (EPA) form a comprehensive program to preserve air quality. States are required to establish regulations and programs to address all requirements of the Clean Air Act and have the flexibility to enact more stringent requirements. All of Great Plains Energy’s and KCP&L’s generating facilities, and certain of their other facilities, are subject to the Clean Air Act.

~~103~~

Great Plains Energy’s and KCP&L’s current estimate of capital expenditures (exclusive of AFUDC and property taxes) to comply with the ~~currently effective~~currently-effective Clean Air Interstate Rule (CAIR) ~~and with~~, the replacement to CAIR or the Cross-State Air Pollution Rule (CSAPR), the best available retrofit technology (BART) rule, the SO2 National Ambient Air Quality Standard (NAAQS), the industrial boiler rule and the Mercury and Air Toxics Standards (MATS) rule that would reduce emissions of toxic air pollutants, (all of which are discussed below) is approximately $1 billion. As discussed below, CAIR has been remanded to the EPA, but remains in effect until the EPA issues final rules consistent with the court’s order or until the court takes further action. In July 2010, the EPA proposed the Transport Rule to replace CAIR. However, due to uncertainties regarding the proposal (discussed below), it is not possible to predict what the final rules may be, when the rules may be issued, or the costs associated with such rules. The actual cost of compliance with any existing, proposed or future rules ~~and with BART,~~ may be significantly different from the cost estimate provided.

The ~~potential~~approximate $1 billion current estimate of capital ~~costs~~expenditures reflects the following capital projects:

·	KCP&L’s La Cygne No. 1 scrubber and baghouse installed by June 2015;

·	KCP&L’s La Cygne No. 2 full air quality control system (AQCS) installed by June 2015;

·	KCP&L’s Montrose No. 3 full AQCS installed by approximately 2017; and

·	GMO’s Sibley No. 3 scrubber and baghouse installed by approximately 2017.

In September 2011, KCP&L commenced construction of the ~~Collaboration Agreement provisions (discussed below) relating~~La Cygne project. Other capital projects at KCP&L’s Montrose Nos. 1 and 2 and GMO’s Sibley Nos. 1 and 2 and Lake Road Nos. 4 and 6 are possible but are currently considered less likely. Any capacity and energy requirements resulting from a decision not to NOx~~, SO~~2 and particulate emission limits at the LaCygne generating station are within the disclosed overall capital cost estimate of approximately $1 billion (discussed above). However, the estimated capital costs do not reflect potential costs relatingproceed with these less likely projects is currently expected to requirements enacted in the future, including potential requirements regarding climate change and control of mercury emissions (discussed below), and also do not reflect costs relating to additional wind generation,be met through renewable energy ~~efficiency and other CO~~2 ~~emission offsets contemplated by the Collaboration Agreement or that may be~~additions required under ~~the~~ Missouri orand Kansas renewable energy standards, ~~which are discussed below.~~ demand side management programs, construction of combustion turbines and/or combined cycle units, and/or power purchase agreements.

The estimate does not reflect the non-capital costs the Companies incur on an ongoing basis to comply with environmental laws, which may increase in the future due to the ~~implementation of KCP&L’s Comprehensive Energy Plan and the~~ Companies’ ongoing compliance with current or future environmental laws. ~~KCP&L expects to seek recovery of the costs associated with the Collaboration Agreement and the~~The Companies expect to seek recovery of the costs associated with environmental requirements through rate increases; however, there can be no assurance that such rate increases would be granted. The Companies may be subject to materially adverse rate treatment in response to competitive, economic, political, legislative or regulatory pressures and/or public perception of the Companies’ environmental reputation.

Clean Air Interstate Rule (CAIR) and ~~Transport~~Cross-State Air Pollution Rule (CSAPR)

The CAIR requires reductions in SO2 and NOx emissions in 28 states, including Missouri. The ~~reduction~~reductions in ~~both~~ SO2 and NOx emissions isare accomplished through statewide caps for NOx and SO2. ~~More restrictive caps are scheduled to become effective January 1, 2015.~~ Great Plains Energy’s and KCP&L’s fossil fuel-fired plants located in Missouri are subject to CAIR, while their fossil fuel-fired plants in Kansas are not.

On July 11, 2008, the D.C. Circuit Court of Appeals vacated CAIR in its entirety and remanded the matter to the EPA to promulgate a new rule consistent with its opinion. On December 23, 2008, the Court issued an order remanding CAIR to the EPA to revise the rule consistent with its July 2008 order. ~~The CAIR thus remains in effect pending future EPA or court action, including the proposed Transport Rule discussed below.~~

CAIR currently establishes a market-based cap-and-trade program with an emission allowance allocation. Facilities demonstrate compliance with CAIR by holding sufficient allowances for each ton of SO2 ~~and NO~~x ~~emitted in any given year. KCP&L and GMO are currently allowed to utilize unused SO~~2 emission allowances that they have either accumulated during previous years of the Acid Rain Program or purchased to meet the more stringent CAIR requirements. At December 31, 2010, KCP&L had accumulated unused SO2 ~~emission allowances sufficient to support over 135,000 tons of SO~~2 emissions (enough to support expected requirements under the current CAIR for the foreseeable future) under the provisions of the Acid Rain program, which are recorded in inventory at zero cost. At December 31, 2010, GMO had accumulated unused SO2 ~~emission allowances sufficient to support just over 13,000 tons of SO~~2 emissions (enough to support expected requirements under the current CAIR through 2011), which it has received under the Acid Rain Program or purchased, and are recorded in inventory at average cost. KCP&L and GMO purchase NOx ~~allowances as needed.~~

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~~Analysis of the current CAIR rule indicates that NO~~x ~~and SO~~2 control may be required for KCP&L’s Montrose Station and GMO’s Sibley and Lake Road Stations in Missouri, and control may be achieved through a combination of pollution control equipment and the use or purchase of emission allowances as needed.

In July ~~2010,~~2011, the EPA ~~proposed~~finalized the ~~Transport Rule~~CSAPR to replace the ~~current~~currently-effective CAIR. The ~~Transport Rule, like CAIR, will require~~CSAPR requires the states within its scope to reduce power plant SO2 and NOx emissions that contribute to ozone and fine particle nonattainment in other states. The geographical scope of the ~~Transport Rule is broader than CAIR, and~~CSAPR includes Kansas, ~~in addition to~~ Missouri and other states. ~~The Transport Rule would also impose more stringent emissions limitations than CAIR~~Kansas and ~~unlike CAIR, would~~Missouri are included in the annual SO2 and NOx programs for the control of fine particulate matter in the CSAPR. In December 2011, the EPA finalized a rulemaking to include Missouri for ozone season control but not ~~utilize Acid Rain Program allowances for compliance.~~Kansas. The EPA ~~is proposing~~will address the inclusion of Kansas in a ~~preferred approach~~separate action and ~~is taking comment on two alternatives.~~revisit Kansas’ status in the CSAPR at that time. In the ~~EPA’s preferred approach,~~CSAPR, the EPA ~~would~~ set an emissions budget for each of the affected ~~states and the District of Columbia.~~states. The ~~preferred approach would allow~~CSAPR allows limited interstate emissions allowance trading among power plants; however, it ~~would~~does not permit trading of SO2 allowances between the Companies’ Kansas and Missouri power plants. In the first alternative, the EPA is proposing to set an emissions budget for each state and allow emissions allowance trading only among power plants within a state. In the second alternative, the EPA is proposing to set an emissions budget for each state, specify the allowable emission limit for each power plant and allow some averaging. Compliance with the Transport Rule would begin in 2012. There would be additional reductions in SO2 allowances allocable to the Companies’ Missouri power plants taking effect in ~~2014 pursuant to the preferred approach.~~2014. There is no such 2014 additional reduction in SO2 allowances allocable to the Companies’ Kansas power plants. In February 2012, the EPA finalized technical adjustments to the final CSAPR. The rules amend the assurance penalty provisions, which would further restrict interstate trading of emission allowances, to start in 2014 instead of 2012. The EPA revised certain unit-level allocations in certain states, including Kansas and Missouri, which would re-allocate allowances to assist KCP&L in compliance with the CSAPR.

Compliance with the CSAPR was to begin in 2012. Multiple states, utilities and other parties, including KCP&L, filed requests for reconsideration and stays with the EPA and/or the D.C. Circuit Court. In ~~January~~December 2011, the D.C. Circuit Court issued an order staying the CSAPR pending the Court's resolution of the petitions for review of the rule. The order requires the EPA ~~supplemented~~to continue administering the ~~record supporting~~CAIR while the proposed Transport Rule. The EPA made available additional information relevant to the rulemaking, including, among other things, unit-level allowances for existing units calculated using two alternative methodologies and data supporting those calculations.CSAPR is stayed.

The ~~proposed Transport Rule~~CSAPR is complex and ~~as noted, contains alternative approaches.~~ Great Plains Energy and KCP&L are unable to predict when the Transport Rule (or other rule replacing CAIR) might be adopted, or the actual requirements of such rule. Preliminary analysis of the Transport Rule has raised various questions regarding the emission allowances allocation to, and the allowable emission rates for, the Companies’ power plants pursuant to the preferred approach and alternatives, which the Companies addressed during the rule’s comment period. Regardless of the resolution of those questions, theevaluating its impacts. The Companies project that they may not be allocated sufficient SO2 or NOX emissions allowances to cover their currently expected operations ~~starting in 2012 pursuant to~~when the ~~preferred approach.~~rule becomes effective. Any shortfall in allocated allowances ~~would need~~is anticipated to be addressed through a combination of permissible allowance trading, installing additional emission control equipment, changes in plant ~~operation,~~processes, or purchasing additional power in the wholesale market, or a combination of these and other alternatives. While Great Plains Energy and KCP&L cannot reasonably predict at this time the impacts of the final Transport Rule, if it were finalized as currently proposed, the Companies expect that any required capital expenditures would not exceed the $1 billion estimate of capital expenditures (exclusive of AFUDC and property taxes) to comply with the currently effective CAIR and BART rule disclosed above. Any final rule could have a significant adverse effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.market.

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Best Available Retrofit Technology (BART) Rule

The EPA BART rule directs state air quality agencies to identify whether visibility-reducing emissions from sources subject to BART are below limits set by the state or whether retrofit measures are needed to reduce emissions. BART applies to specific eligible facilities including KCP&L’s ~~LaCygne~~La Cygne Nos. 1 and 2 in Kansas, KCP&L’s Iatan No. 1, in which GMO has an 18% interest, KCP&L’s Montrose No. 3 in Missouri, GMO’s Sibley Unit No. 3 and Lake Road Unit No. 6 in Missouri and Westar Energy, Inc.’s (Westar) Jeffrey Unit Nos. 1 and 2 in Kansas, in which GMO has an 8% interest. ~~Initially, in Missouri, compliance with CAIR will be compliance with BART for individual sources.~~ Both Missouri and Kansas have submitted BART plans to the EPA. In December 2011, the EPA ~~but neither Missouri nor~~issued a proposal that would approve the CSAPR as an alternative to determining BART. As a result, states in the CSAPR would be able to substitute participation in the CSAPR for source-specific BART. In December 2011, the EPA approved the Kansas ~~has received EPA approval for their~~ BART ~~plans.~~plan.

Mercury and ~~Other Hazardous~~ Air ~~Pollutant Emissions~~Toxics Standards (MATS) Rule

In January 2009, the EPA issued a memorandum stating that new electric steam generating units (EGUs) that began construction while the Clean Air Mercury Rule (CAMR) was effective are subject to a new source maximum achievable control technology (MACT) determination on a case-by-case basis.

In July 2009, the EPA sent ~~letters~~a letter notifying KCP&L that a MACT ~~determinations~~determination and ~~schedules~~schedule of compliance ~~are~~is required for coal and oil-fired EGUs that began actual construction or reconstruction after December 15, 2000, and identified Iatan No. 2 ~~and Hawthorn No. 5~~ as an affected ~~EGUs.~~EGU. This was an outcome of the D.C. Circuit Court of Appeals’ vacatur of both the CAMR and the contemporaneously promulgated rule removing EGUs from MACT requirements. ~~KCP&L believes that Hawthorn No. 5 is not an affected EGU based on the reconstruction dates of the unit, and provided supporting documentation to the Missouri Department of Natural Resources (MDNR).~~ It is not currently known how the MACT ~~determinations~~determination and ~~schedules~~schedule of

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compliance will impact the permitting or operating requirements for ~~these two units,~~Iatan No. 2, but it is possible a MACT determination may ultimately require additional emission control equipment and permit ~~limits at Iatan No. 2, Hawthorn No. 5, or both.~~limits.

In ~~April 2010,~~December 2011, the EPA ~~in a court approved settlement, agreed to develop MACT standards for mercury~~finalized the Mercury and ~~potentially other~~Air Toxics Standards (MATS) Rule that will reduce emissions of toxic air pollutants, also known as hazardous air pollutant emissions. In the settlement agreement, the EPA agreed to propose MACT standards in March 2011 with final standards by November 2011. These MACT standards, if adopted, could impact KCP&L’s and GMO’spollutants, from new and existing ~~facilities.~~

~~Management cannot predict~~coal- and oil-fired EGUs with a capacity of greater than 25 MWs. The rule establishes numerical emission limits for mercury, particulate matter (a surrogate for non-mercury metals), and hydrochloric acid (a surrogate for acid gases). The rule establishes work practices, instead of numerical emission limits, for organic air toxics, including dioxin/furan. Compliance with the outcome of further judicial, administrative or regulatory actions or their financial or operational effects on Great Plains Energy and KCP&L. Such actions could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows. Some of therule would need to be addressed by installing additional emission control ~~technology for SO~~2 ~~and NO~~x ~~could also aid~~equipment, changes in plant operation, purchasing additional power in the ~~control~~wholesale market or a combination of ~~mercury.~~these and other alternatives. The rule allows three years for compliance with authority for state permitting authorities to grant an additional year as needed for technology installation. The EPA indicated that it expects this option to be broadly available.

Industrial Boiler Rule

In ~~April 2010,~~February 2011, the EPA issued a final rule that would reduce emissions of hazardous air pollutants from new and existing industrial boilers. In May 2011, the EPA announced it would stay the effective date of the final rule during reconsideration; although in January 2012, the D.C. Circuit Court vacated the stay and remanded the stay to the EPA. In December 2011, the EPA issued a proposed revised rule ~~that would set MACT standards~~and intends to issue a final rule in the spring of 2012. The proposed revised rule establishes numeric emission limits for mercury, particulate matter (as a surrogate for non-mercury metals), hydrogen chloride (as a surrogate for acid gases), and carbon monoxide (as a surrogate for non-dioxin organic hazardous air ~~pollutants from industrial boilers.~~pollutants). The ~~proposed~~final rule ~~would establish~~establishes emission limits for KCP&L’s and GMO’s ~~new and~~ existing units that produce steam other than for the generation of electricity. ~~This~~The existing boiler rule and its proposed ~~rule does~~revisions do not apply to KCP&L’s and GMO’s electricity generating boilers, but would apply to most of GMO’s Lake Road boilers, which also serve steam customers, and to auxiliary boilers at other generating facilities. The EPA finalized the rule in late February 2011. The financial and operational impacts to Great Plains Energy and KCP&L, which could be material, are being evaluated but cannot be determined at this time.

New Source Review

The Clean Air Act requires companies to obtain permits and, if necessary, install control equipment to reduce emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in regulated emissions.

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In ~~January 2004,~~March 2010, the U.S. District Court in the District of Kansas approved a settlement agreement between Westar ~~received notification from~~and the ~~EPA alleging~~parties of a lawsuit filed by the Department of Justice on behalf of the EPA. The lawsuit asserted that ~~it had violated new source review requirements and Kansas environmental regulations by making modifications to~~certain projects completed at the Jeffrey Energy Center ~~without obtaining the proper permits. In February 2009, the Attorney General~~violated certain requirements of the United States filed a complaint against Westar alleging that it violated the Clean Air Act and related federal and state regulations by making major modifications to the Jeffrey Energy Center beginning in 1994 without first obtaining appropriate permits authorizing this construction and without installing and operating best available control technology to control emissions.EPA’s New Source Review program. The Jeffrey Energy Center consists of three coal-fired units located in Kansas that is 92% owned by Westar and operated exclusively by Westar. GMO has an 8% interest in the Jeffrey Energy Center and is generally responsible for its 8% share of the facility’s operating costs and capital expenditures. ~~In January 2010, Westar entered into a settlement agreement, which was approved by the court in March 2010.~~ The settlement agreement ~~requires,~~required, among other things, the installation of a selective catalytic reduction (SCR) system at one of the Jeffrey Energy Center units by the end of 2014 and the payment of a $3 million civil penalty. Westar has ~~preliminarily~~ estimated the cost of this SCR at approximately $240 million. ~~This amount could materially change depending on final engineering and design.~~ Depending on the NOx emission reductions attained by that SCR and attainable through the installation of other controls at the other two units, the settlement agreement may require the installation of a second SCR system on one of the other two units by the end of 2016. There is no assurance that GMO’s share of these costs would be recovered in rates and failure to recover such costs could have a significant ~~adverse~~ effect on Great Plains Energy’s results of operations, financial position and cash flows.

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KCP&L has received requests for information from the Kansas Department of Health and Environment (KDHE) pertaining to a past La Cygne No. 1 scrubber project. KCP&L is working with the KDHE to resolve this issue and management currently believes the outcome will not have a significant impact on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

Collaboration Agreement

In March 2007, KCP&L, the Sierra Club and the Concerned Citizens of Platte County entered into a Collaboration Agreement under which KCP&L agreed to pursue a set of initiatives including energy efficiency, additional wind generation, lower emission permit levels at its Iatan and ~~LaCygne~~La Cygne generating stations and other initiatives designed to offset CO2 emissions. Full implementation of the terms of the Collaboration Agreement will necessitate approval from the appropriate authorities, as some of the initiatives in the agreement require regulatory approval.

In 2006, KCP&L installed ~~100MW~~100 MWs of wind generation at its Spearville wind site. KCP&L agreed in the Collaboration Agreement to pursue increasing its wind generation capacity to ~~500MW~~500 MWs in total by the end of 2012 with ~~100MW~~100 MWs to be added by the end of 2010 and the remainder added by the end of 2012, subject to regulatory approval. In 2010, KCP&L completed a ~~48MW~~48 MWs wind project adjacent to its existing Spearville wind site with wind turbines it already owned and also secured ~~52MW~~52 MWs of renewable energy credits. During 2011, KCP&L ~~issued requests~~entered into long-term power purchase agreements for ~~proposals to add up to 100MW~~approximately 231 MWs of wind generation beginning in 2012 and ~~is evaluating the proposals. KCP&L is evaluating alternatives to meet the remaining~~GMO entered into a long-term power purchase agreement for approximately 100 MWs of wind generation ~~capacity requirement, including the purchase of renewable energy credits, power purchase agreements, KCP&L-built installations or some combination thereof.~~beginning in 2012, which expire in 2032.

KCP&L ~~agreed in the Collaboration Agreement to seek~~has a consent agreement ~~which it has done,~~ with the ~~Kansas Department of Health and Environment (KDHE)~~KDHE incorporating limits for stack particulate matter emissions, as well as limits for NOx and SO2 emissions, at its ~~LaCygne~~La Cygne Station that, consistent with the Collaboration Agreement, will be below the presumptive limits under BART. KCP&L further agreed to use its best efforts to install emission control technologies to reduce those emissions from the ~~LaCygne~~La Cygne Station prior to the required compliance date under BART, but in no event later than June 1, 2015. ~~KCP&L has~~In August 2011, KCC issued ~~requests for proposals for environmental equipment required to comply with BART at the LaCygne Station and is evaluating the responses. In February 2011,~~its order on KCP~~&L filed a~~&L’s predetermination request ~~with KCC for predetermination of the ratemaking treatment~~ that ~~will~~would apply to the recovery of costs for its 50% share of the environmental equipment required to comply with BART at the ~~LaCygne~~La Cygne Station. ~~The request~~In the order, KCC stated that KCP&L’s decision to retrofit La Cygne was reasonable, reliable, efficient and prudent and the $1.23 billion cost estimate is reasonable. If the cost for ~~predetermination includes an estimated total~~the project is at or below the $1.23 billion estimate, absent a showing of fraud or other intentional imprudence, KCC stated that it will not re-evaluate the prudency of the cost of the project. If the cost of the project exceeds the $1.23 ~~billion.~~billion estimate and KCP&L seeks to recover amounts exceeding the estimate, KCP&L will bear the burden of proving that any additional costs were prudently incurred. KCP&L’s 50% share of the estimated cost is $615 million. KCP&L began the project in September 2011.

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In the Collaboration Agreement, KCP&L also agreed to offset an additional 711,000 tons of CO2 by the end of 2012. KCP&L currently expects to achieve this offset through a number of alternatives, including improving the efficiency of its coal-fired units, equipping certain gas-fired units for winter operation and, if necessary, possibly reducing output of, or retiring, one or more coal-fired units.

Climate Change

The Companies are subject to existing greenhouse gas reporting regulations and ~~as discussed below, will be subject to~~ certain greenhouse gas permitting ~~requirements starting in 2011.~~requirements. Management believes it is ~~likely~~possible that additional federal or relevant state or local laws or regulations could be enacted to address global climate change. At the international level, while the United States is not a current party to the international Kyoto Protocol, it has agreed to undertake certain voluntary actions under the non-binding Copenhagen Accord and pursuant to subsequent international discussions relating to climate change, including the establishment of a goal to reduce greenhouse gas emissions. International agreements legally binding on the United States may be

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reached in the future. Such new laws or regulations could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as CO2, which are created in the combustion of fossil fuels. The Companies’ current generation capacity is primarily coal-fired and is estimated to produce about one ton of CO2 per MWh, or approximately 2825 million tons and 2118 million tons per year for Great Plains Energy and KCP&L, respectively.

Laws have recently been passed in Missouri and Kansas, the states in which the Companies’ retail electric businesses are operated, setting renewable energy standards, and management believes that national clean or renewable energy standards are also ~~likely.~~possible. While management believes additional requirements addressing these matters will probably be enacted, the timing, provisions and impact of such requirements, including the cost to obtain and install new equipment to achieve compliance, cannot be reasonably estimated at this time. In addition, certain federal courts have held that state and local governments and private parties have standing to bring climate change tort suits seeking company-specific emission reductions and monetary or other damages. ~~The U.S. Supreme Court has agreed to hear an appeal of one of those suits.~~ While the Companies are not a party to any climate change tort suit, there is no assurance that such suits may not be filed in the future or as to the outcome if such suits are filed. Such requirements or litigation outcomes could have the potential for a significant financial and operational impact on Great Plains Energy and KCP&L. The Companies would likely seek recovery of capital costs and expenses for compliance through rate increases; however, there can be no assurance that such rate increases would be granted.

Legislation concerning the reduction of emissions of greenhouse gases, including CO2, is being considered at the federal and state levels. The timing and effects of any such legislation cannot be determined at this time. In the absence of new Congressional mandates, the EPA is proceeding with the regulation of greenhouse gases under the existing Clean Air Act.

In May 2010, the EPA issued a final rule addressing greenhouse gas emissions from stationary sources under the Clean Air Act permitting programs. This final rule sets thresholds for greenhouse gas emissions that define when permits under the Prevention of Significant Deterioration (PSD) and Title V Operating Permit programs are required for new and existing industrial facilities. The EPA phased in the Clean Air Act permitting requirements for greenhouse gas emissions in two initial steps. In step 1, which started January 2,March 2011, only sources currently subject to the PSD permitting program (i.e., those that are newly-constructed or modified in a way that significantly increases emissions of a pollutant other than greenhouse gas) are subject to Title V or PSD permitting requirements, respectively, for their greenhouse gas emissions. For these projects, only projects with new or increases of greenhouse gas emissions of 75,000 tons per year or more of total greenhouse gases, on a CO2 equivalent basis, need to determine the best available control technology for their greenhouse gas emissions. In addition, sources subject to the Title V Operating Permit Program need to address greenhouse gas emissions as those permits are applied

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for or renewed. In step 2, starting July 1, 2011, Title V and PSD permitting requirements will cover, for the first time, new construction projects that emit greenhouse gas emissions of at least 100,000 tons per year even if they do not exceed the permitting thresholds for any other pollutant. In addition, modifications at such existing facilities that increase greenhouse gas emissions by at least 75,000 tons per year will be subject to permitting requirements, even if they do not significantly increase emissions of any other pollutant. Great Plains Energy’s and KCP&L’s generating facilities that trigger these thresholds for new installations, modifications or Title V operating permits will be subject to this rule.

~~In December 2010,~~ the EPA announced it ~~entered into~~finalized a ~~proposed~~ settlement agreement to issue a rule that will address greenhouse gas emissions from EGUs. The rule would establish new source performance standards for new and modified EGUs and emission guidelines for existing EGUs. Under the settlement agreement, the EPA ~~would commit~~committed to issuing proposed regulations by ~~July~~September 2011, although the EPA did not meet that date, and final regulations by May 2012.

At the state level, a Kansas law enacted in May 2009 ~~requires~~required Kansas public electric utilities, including KCP&L, to have renewable energy generation capacity equal to at least 10% of their three-year average Kansas peak retail demand by 2011. The percentage increases to 15% by 2016 and 20% by 2020. A Missouri law enacted in November 2008 ~~requires~~required at least 2% of the electricity provided by Missouri investor-owned utilities (including KCP&L and GMO) to their Missouri retail customers to come from renewable resources, including wind, solar, biomass and hydropower, by 2011, increasing to 5% in 2014, 10% in 2018, and 15% in 2021, with a small portion (estimated to be about 2MW in 2011 for each of KCP&L and GMO) required to come from solar resources.

KCP&L and GMO project that ~~their current renewable resources (including accumulated renewable energy credits)~~they will be ~~sufficient for compliance~~compliant with the Missouri renewable requirements, exclusive of the solar requirement, through ~~2017~~2023 for KCP&L and ~~2015, respectively.~~2018 for GMO. KCP&L and GMO project that the purchase of solar renewable energy credits will be sufficient for compliance with the Missouri solar requirements ~~through 2011. The Companies have issued requests~~ for ~~proposals for compliance with~~ the ~~solar requirement beyond 2011 and are evaluating the proposals. KCP&L and GMO continue to evaluate options for compliance beyond these years.~~

foreseeable future. KCP&L also projects that ~~its current renewable resources (including accumulated renewable energy credits) combined~~it will be compliant with the ~~48MW wind project and 52MW of~~Kansas renewable energy credits discussed above will be sufficient for compliance with the 2011 Kansas requirements. KCP&L issued requests for proposals to add up to 100MW of wind generation in 2012 and is evaluating the proposals.requirements through 2016.

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Additionally, in November 2007, governors from six Midwestern states, including Kansas, signed the Midwestern Greenhouse Gas Reduction Accord, which has established the goal of reducing member states’ greenhouse gas emissions to 15% to 20% below 2005 levels by 2020, and 60% to 80% below 2005 levels by 2050.

Greenhouse gas legislation or regulation has the potential of having significant financial and operational impacts on Great Plains Energy and KCP&L, including the potential costs and impacts of achieving compliance with limits that may be established. However, the ultimate financial and operational consequences to Great Plains Energy and KCP&L cannot be determined until such legislation is passed and/or regulations are ~~issued or, with respect to those regulations that have been issued, additional guidance is provided.~~issued. Management will continue to monitor the progress of relevant legislation and regulations.

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~~Ozone NAAQS~~

In June 2007, monitor data indicated that the Kansas City area violated the 1997 primary eight-hour ozone national ambient air quality standard (NAAQS). Missouri and Kansas have implemented the responses established in the maintenance plans for control of ozone. The responses in both states do not require additional controls at Great Plains Energy’s and KCP&L’s generation facilities beyond the currently proposed controls for CAIR and BART. The EPA has various options over and above the implementation of the maintenance plans for control of ozone to address the violation but has not yet acted. At this time, management is unable to predict how the EPA will respond or how that response will impact Great Plains Energy’s and KCP&L’s operations. However, the EPA’s response could have a significant effect on Great Plains Energy's and KCP&L's results of operations, financial position and cash flows.

In March 2008, the EPA significantly strengthened its NAAQS for ground-level ozone. The EPA revised the primary eight-hour ozone standard, designed to protect public health, to a level of 0.075 parts per million (ppm). The EPA also strengthened the secondary eight-hour ozone standard to the level of 0.075 ppm making it identical to the revised primary standard. The previous primary and secondary standards, set in 1997, were effectively 0.084 ppm.

In March 2009, the MDNR and KDHE submitted to the EPA their determinations that the Kansas City area is a nonattainment area under the 2008 primary eight-hour ozone standard. The EPA will make final designations of attainment and nonattainment areas. By 2013, states must submit state implementation plans outlining how states will reduce ozone to meet the standards in nonattainment areas. Although the impact on Great Plains Energy’s and KCP&L’s operations will not be known until after the final nonattainment designations and the state implementation plans are submitted, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

In January 2010, the EPA proposed to reconsider and further strengthen the 2008 NAAQS for ground-level ozone. The EPA proposed to strengthen the primary eight-hour ozone standard to a level within the range of 0.060-0.070 ppm. The EPA also proposed to establish a distinct cumulative, seasonal secondary standard, designed to protect sensitive vegetation and ecosystems, to within the range of 7-15 ppm-hours. In December 2010, the EPA filed a motion requesting court approval for additional time, until July 2011, to finalize the rule.

SO2 NAAQS

In June 2010, the EPA strengthened the primary NAAQS for SO2. The EPA revised the primary SO2 standard by establishing a new 1-hour standard at a level of 0.075 ppm. The EPA revoked the two existing primary standards of 0.140 ppm evaluated over ~~24-hours~~24 hours and 0.030 ppm evaluated over an entire year. ~~Although~~In July 2011, the ~~impact on Great Plains Energy’s and KCP&L’s operations will not~~MDNR recommended to the EPA that part of Jackson County, Missouri, which is in the Companies’ service territory, be ~~known until after~~designated a nonattainment area for the nonattainment designations are approved and the state implementation plans submitted, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.new 1-hour SO2 standard.

Montrose Station Notice of Violation

In June 2009, KCP&L received notification from the MDNR alleging that its Montrose Station had excess particulate matter emissions in 2008. In November 2011, KCP&L ~~is working with~~and MDNR Executed an Abatement Order on Consent that resolved all claims for the ~~MDNR~~violations alleged without KCP&L admitting the validity or accuracy of such claims. KCP&L agreed in compromise and satisfaction of MDNR’s claims to ~~resolve this issue and management believes~~complete a supplemental environmental project in the ~~outcome will have an insignificant impact to Great Plains Energy’s and KCP&L’s results~~amount of ~~operations, financial position and cash flows.~~$150,000.

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Water

The Clean Water Act and associated regulations enacted by the EPA form a comprehensive program to preserve water quality. Like the Clean Air Act, states are required to establish regulations and programs to address all requirements of the Clean Water Act, and have the flexibility to enact more stringent requirements. All of Great Plains Energy’s and KCP&L’s generating facilities, and certain of their other facilities, are subject to the Clean Water Act.

~~Section 316(b) of~~In March 2011, the ~~Clean Water Act is designed to protect aquatic life from being killed or injured by cooling water intake structures. The~~ EPA ~~had previously issued~~proposed regulations pursuant to Section 316(b) of the Clean Water Act regarding cooling water intake ~~structures. Subsequent~~structures pursuant to ~~an appellate court ruling, the EPA suspended the regulations and is engaged in further rulemaking on this matter. In December 2010, in~~ a court approved ~~settlement,~~settlement. KCP&L generation facilities with cooling water intake structures would be subject to a limit on how many fish can be killed by being pinned against intake screens (impingement) and would be required to conduct studies to determine whether and what site-specific controls, if any, would be required to reduce the number of aquatic organisms drawn into cooling water systems (entrainment). The EPA agreed to ~~propose a new~~finalize the rule ~~in March 2011 and to finalize it in~~by July 2012. ~~At this time, management is unable to predict how~~Although the ~~EPA will respond or how that response will~~ impact on Great Plains Energy’s and KCP&L’s ~~operations.~~operations will not be known until after the rule is finalized, it could have a significant effect on Great Plains Energy’s and KCP&L’s results of operations, financial position and cash flows.

KCP&L holds a permit from the MDNR covering water discharge from its Hawthorn Station. The permit authorizes KCP&L to, among other things, withdraw water from the Missouri river for cooling purposes and return the heated water to the Missouri river. KCP&L has applied for a renewal of this permit and the EPA has submitted an interim objection letter regarding the allowable amount of heat that can be contained in the returned water. Until this matter is resolved, KCP&L continues to operate under its current permit. KCP&L cannot predict the outcome of this matter; however, while less significant outcomes are possible, this matter may require KCP&L to reduce its generation at Hawthorn Station, install cooling towers or both, any of which could have a significant impact on KCP&L. The outcome could also affect the terms of water permit renewals at KCP&L’s Iatan Station and at GMO’s Sibley and Lake Road Stations.

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Additionally, in September 2009, the EPA announced plans to revise the existing standards for water discharges from coal-fired power plants. In November 2010, the EPA filed a motion requesting court approval of a consent agreement in which the EPA agreed to propose a rule in July 2012 and to finalize it in January 2014. Until a rule is proposed and finalized, the financial and operational impacts to Great Plains Energy and KCP&L cannot be determined.

Solid Waste

Solid and hazardous waste generation, storage, transportation, treatment and disposal is regulated at the federal and state levels under various laws and regulations. In May 2010, the EPA proposed to regulate coal combustion residuals (CCRs) under the Resource Conservation and Recovery Act (RCRA) to address the risks from the disposal of CCRs generated from the combustion of coal at electric generating facilities. The EPA is considering two options in this proposal. Under the first ~~proposal,~~option, the EPA would regulate CCRs as special wastes subject to regulation under subtitle C of RCRA (hazardous), when they are destined for disposal in landfills or surface impoundments. Under the second ~~proposal,~~option, the EPA would regulate disposal of CCRs under subtitle D of RCRA (non-hazardous). The Companies principally use coal in generating electricity and dispose of the CCRs in both on-site facilities and facilities owned by third parties. The proposed CCR rule has the potential of having a significant financial and operational impact on Great Plains Energy and KCP&L in connection with achieving compliance with the proposed requirements. However, the financial and operational consequences to Great Plains Energy and KCP&L cannot be determined until an option is selected by the EPA and the final regulation is enacted.

Remediation

Certain federal and state laws, including the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) hold current and previous owners or operators of real property, and any person who arranges for the disposal or treatment of hazardous substances at a property, liable on a joint and several basis for the costs of cleaning up contamination at or migrating from such real property, even if they did not know of and

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were not responsible for such contamination. CERCLA and other laws also authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. GMO is named as a potentially responsible party at two disposal sites for polychlorinated ~~biphenyls (PCBs),~~biphenyl (PCB) contamination, and retains some environmental liability for several operations and investments it no longer owns. In addition, GMO also owns, or has acquired liabilities from companies that once owned or operated, former manufactured gas plant (MGP) sites, which are subject to the supervision of the EPA and various state environmental agencies.

At December 31, ~~2010~~2011 and ~~2009,~~2010, KCP&L had $0.3 million accrued for environmental remediation expenses, which covers ground water monitoring at a former MGP site. At December 31, ~~2010~~2011 and ~~2009,~~2010, Great Plains Energy had $0.4 million accrued for environmental remediation expenses, which includes the $0.3 million at KCP&L, and additional potential remediation and ground water monitoring costs relating to two GMO sites. The amounts accrued were established on an undiscounted basis and Great Plains Energy and KCP&L do not currently have an estimated time frame over which the accrued amounts may be paid.

In addition to the $0.4 million accrual above, at December 31, 2011 and 2010, Great Plains Energy had $2.1 million accrued for the future investigation and remediation of certain additional GMO identified MGP sites, PCB contaminated sites and retained liabilities. This estimate was based upon review of the potential costs associated with conducting investigative and remedial actions at identified sites, as well as the likelihood of whether such actions will be necessary. This estimate could change materially after further investigation, and could also be affected by the actions of environmental agencies and the financial viability of other potentially responsible ~~parties.~~parties; however, given the uncertainty of these items the possible loss or range of loss in excess of the amount accrued is not estimable.

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GMO has pursued recovery of remediation costs from insurance carriers and other potentially responsible parties. As a result of a settlement with an insurance carrier, approximately ~~$2.3~~$2.4 million in insurance proceeds less an annual deductible is available to GMO to recover qualified MGP remediation expenses. GMO would seek recovery of additional remediation costs and expenses through rate increases; however, there can be no assurance that such rate increases would be granted.

In January 2010, the EPA announced an advance notice of proposed rulemaking under CERCLA identifying classes of facilities for which the EPA will develop financial assurance requirements, including the electric power generation, transmission and distribution industry. The CERCLA financial assurance would be for risks associated with Great Plains Energy’s and KCP&L’s production, transportation, treatment, storage or disposal of CERCLA hazardous substances. The impact on Great Plains Energy and KCP&L cannot be determined until the regulations are finalized.

In April 2010, the EPA announced an advance notice of proposed rulemaking for the use and distribution in commerce of certain PCBs, PCB items and certain other areas of the PCB regulations. The EPA is reassessing the use, distribution in commerce, marking, and storage for reuse of liquid PCBs in electric and non-electric equipment and the use of the 50 ppm level for excluded PCB products among other things. The impact on Great Plains Energy and KCP&L cannot be determined until the regulations are finalized.

Contractual Commitments

Great Plains Energy’s and KCP&L’s expenses related to lease commitments are detailed in the following table.

2010 2009 2008
(millions)
Great Plains Energy $ 17.2 $ 23.4 $ 20.7
KCP&L $ 13.2 $ 19.3 $ 18.1

~~112~~


	2011		2010		2009
	(millions)
Great Plains Energy	$	20.9	$	17.2	$	23.4
KCP&L		17.0		13.2		19.3

Great Plains Energy’s and KCP&L’s contractual commitments at December 31, ~~2010,~~2011, excluding pensions and long-term debt, are detailed in the following tables.


Great Plains Energy
	2011		2012		2013		2014		2015		After 2015		Total		2012		2013		2014		2015		2016		After 2016		Total
Lease commitments	(millions)														(millions)
Operating lease	$	17.9	$	16.8	$	15.0	$	14.3	$	13.5	$	129.4	$	206.9	$	19.7	$	16.3	$	14.8	$	13.6	$	9.8	$	119.2	$	193.4
Capital lease		0.4		0.4		0.4		0.4		0.4		5.5		7.5		0.4		0.4		0.4		0.4		0.4		4.7		6.7
Purchase commitments															Purchase commitments
Fuel		348.7		282.7		287.7		164.8		108.8		125.3		1,318.0		397.4		360.5		202.0		103.9		83.2		94.1		1,241.1
Purchased capacity		20.3		13.4		12.4		4.5		4.2		2.4		57.2
Power																8.5		29.2		34.8		34.8		34.8		686.3		828.4
Capacity																13.4		12.4		4.5		4.2		2.4		-		36.9
La Cygne environmental project																376.6		300.2		125.4		5.5		-		-		807.7
Non-regulated natural gas															Non-regulated natural gas
transportation		4.6		2.9		2.9		2.9		2.9		3.4		19.6		2.8		3.6		3.6		3.6		3.6		0.9		18.1
Other		163.4		17.6		6.8		8.1		2.7		55.1		253.7		54.4		101.7		21.0		25.4		3.7		49.8		256.0
Total contractual commitments	$	555.3	$	333.8	$	325.2	$	195.0	$	132.5	$	321.1	$	1,862.9	$	873.2	$	824.3	$	406.5	$	191.4	$	137.9	$	955.0	$	3,388.3


KCP&L
	2011		2012		2013		2014		2015		After 2015		Total		2012		2013		2014		2015		2016		After 2016		Total
Lease commitments	(millions)														(millions)
Operating lease	$	14.1	$	13.1	$	12.7	$	12.5	$	12.1	$	129.4	$	193.9	$	16.0	$	14.0	$	13.0	$	12.2	$	9.7	$	119.2	$	184.1
Capital lease		0.2		0.2		0.2		0.2		0.2		3.2		4.2		0.2		0.2		0.2		0.2		0.2		2.6		3.6
Purchase commitments															Purchase commitments
Fuel		296.8		241.5		249.1		144.4		104.9		125.3		1,162.0		336.0		298.8		169.1		91.5		79.1		94.1		1,068.6
Purchased capacity		5.5		4.7		3.7		2.9		3.0		1.2		21.0
Power																8.5		29.2		34.8		34.8		34.8		499.1		641.2
Capacity																4.7		3.7		2.9		3.0		1.2		-		15.5
La Cygne environmental project																376.6		300.2		125.4		5.5		-		-		807.7
Other		127.5		15.0		6.0		7.3		1.9		40.8		198.5		40.3		100.9		20.2		24.6		2.9		39.5		228.4
Total contractual commitments	$	444.1	$	274.5	$	271.7	$	167.3	$	122.1	$	299.9	$	1,579.6	$	782.3	$	747.0	$	365.6	$	171.8	$	127.9	$	754.5	$	2,949.1

Great Plains Energy has expected sublease income of ~~$2.0~~$1.2 million for the years ~~2011-2013.~~2012-2013. Lease commitments end in ~~2032.~~2048. Operating lease commitments include rail cars to serve jointly-owned generating units where KCP&L is the managing partner. Of the amounts included in the table above, KCP&L will be reimbursed by the other owners for approximately ~~$2.0~~$2.2 million per year ~~($13.7~~from 2012 to 2015 and then $0.4 million ~~total)~~per year from 2016 to 2025, for a total of ~~the amounts included in the table above.~~$13.0 million.

111

Fuel commitments consist of commitments for nuclear fuel, coal and coal transportation. Power commitments consist of commitments for renewable energy under power purchase agreements. KCP&L and GMO purchase capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable. KCP&L has capacity sales agreements not included above that total ~~$6.9 million for 2011,~~ $3.8 million for 2012 and $1.6 million for 2013. La Cygne environmental project represents contractual commitments related to environmental upgrades at KCP&L’s La Cygne station. KCP&L owns 50% of the La Cygne station and expects to be reimbursed by the other owner for its 50% share of the costs. Non-regulated natural gas transportation consists of MPS Merchant’s commitments. Other represents individual commitments entered into in the ordinary course of business.

~~113~~

~~16.~~15.

LEGAL PROCEEDINGS

~~KCP&L Hawthorn No. 5 Litigation~~

KCP&L received reimbursement for the 1999 Hawthorn No. 5 boiler explosion under a property damage insurance policy with Travelers Property Casualty Company of America (Travelers). Travelers filed suit in the U.S. District Court for the Eastern District of Missouri in November 2005, against National Union Fire Insurance Company of Pittsburgh, Pennsylvania, (National Union) and KCP&L was added as a defendant in June 2006. The case was subsequently transferred to the U.S. District Court for the Western District of Missouri. Travelers sought recovery of $10 million that KCP&L recovered through subrogation litigation. On July 24, 2008, the Court held that Travelers is not entitled to any recovery from KCP&L. Travelers appealed this decision on March 11, 2009, to the Court of Appeals for the Eighth Circuit. In September 2010, the Court of Appeals affirmed the District Court’s decision. The Company does not currently expect any further action with respect to this matter.

KCP&L Spent Nuclear Fuel and Radioactive Waste

In January 2004, KCP&L and the other two Wolf Creek owners filed a lawsuit against the United States in the U.S. Court of Federal Claims seeking $14.1 million of damages resulting from the government’s failure to begin accepting spent nuclear fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982. The Wolf Creek case was tried before a U.S. Court of Federal Claims judge in June 2010, and a decision was issued in November 2010, granting KCP&L and the other two Wolf Creek owners $10.6 million ($5.0 million KCP&L share) in damages. In January 2011, KCP&L and the other two Wolf Creek owners as well as the United States filed appeals of the decision ~~of the U.S. Court of Federal Claims~~ to the U.S. Court of Appeals for the Federal Circuit. Briefing to the Court was completed in December 2011, and oral argument has been scheduled for March 7, 2012.

~~KCP&L Advanced Coal Credit Arbitration~~

In July 2009, KCP&L was served a notice to arbitrate by The Empire District Electric Company (Empire), Kansas Electric Cooperative, Inc. (KEPCO) and Missouri Joint Municipal Electric Utility Commission (MJMEUC), the non-Company joint owners of Iatan No. 2. These joint owners asserted that they were entitled to receive proportionate shares (or the monetary equivalent) of approximately $125 million of qualifying advance coal project credits for Iatan No. 2. As independent entities, the joint owners are taxed separately and the non-Company joint owners do not dispute that they did not, in fact, apply for the credits themselves. Notwithstanding this, they contended that they should receive proportional shares of the credit. On December 30, 2009, an arbitration panel issued its order denying the KEPCO and MJMEUC claims but ordering KCP&L and Empire to jointly seek a reallocation of the tax credit from the IRS giving Empire its representative percentage of the total tax credit, worth approximately $17.7 million. The order further specified that if the IRS denies the parties’ reallocation request or if Empire is allocated less than its proportionate share of the tax credits, KCP&L will be responsible for paying Empire the full value of its representative percentage of the tax credits (less the amount of tax credits, if any, Empire ultimately receives) in cash. In September 2010, the IRS issued an amended memorandum of understanding to reallocate $17.7 million of the original $125 million of the advanced coal project credits to Empire, meeting the requirements of the arbitration order issued on December 30, 2009. KCP&L subsequently dismissed its March 31, 2010, appeal of the arbitration order. In 2010, KCP&L reversed a $17.7 million liability previously recorded in other current liabilities for this matter.

~~Iatan Levee Litigation~~

On May 22, 2009, several farmers filed suit against Great Plains Energy and KCP&L in the Circuit Court of Platte County, Missouri, alleging negligence, private nuisance, trespass and violations of the Missouri Crop Protection Act and seeking unspecified compensatory and punitive damages. These allegations stem from flooding at or near the Iatan Station in 2007 and 2008. The farmers allege the flooding was a result of maintenance of a nearby levee. The petition seeks class certification from the courts. Written discovery and depositions are underway. This matter is set for trial in October 2011. Management cannot predict the outcome of this matter.

~~114~~

GMO Price Reporting Litigation

In response to complaints of manipulation of the California energy market ~~in July 2001,~~ FERC issued an order in July 2001 requiring net sellers of power in the California markets from October 2, 2000, through June 20, 2001, at prices above a FERC determined competitive market clearing price to make refunds to net purchasers of power in the California market during that time period. Because MPS Merchant was a net purchaser of power during the refund period, it has received approximately $8 million in refunds through settlements with certain sellers of power. MPS Merchant estimates that it is entitled to approximately $12 million in additional refunds under the standards FERC has used in this case. FERC has stated that interest will be applied to the refunds but the amount of interest has not yet been determined. However, in December 2001, various parties appealed the FERC order to the United States Court of Appeals for the Ninth Circuit seeking review of a number of issues, including changing the refund period to include periods prior to October 2, 2000. MPS Merchant was a net seller of power during the period prior to October 2, 2000. On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit issued an order finding, among other things, that FERC did not provide a sufficient justification for refusing to exercise its remedial authority under the Federal Power Act to determine whether market participants violated FERC-approved tariffs during the period prior to October 2, 2000, and imposing a remedy for any such violations. The court remanded the matter to FERC ~~to determine whether tariff violations occurred and, if so, the appropriate remedy.~~for further consideration. In ~~March 2008,~~May 2011, FERC issued an order ~~declining~~which clarified the scope of the hearing in the refund proceeding and ruled on requests for rehearing and motions to ~~order refunds~~dismiss. A hearing is set for ~~the period prior to October 2, 2000. That order has been appealed to the U.S. Court of Appeals for the Ninth Circuit.~~April 2012. If FERC ultimately includes the period prior to October 2, 2000, MPS Merchant could be found to owe refunds.

FERC initiated a separate docket, generally referred to as the Pacific Northwest refund proceeding, to determine if any refunds were warranted related to the potential impact of the California market issues on buyers in the Pacific Northwest between December 25, 2000, and June 20, 2001. FERC rejected the refund requests, but its decision was remanded by the Court of Appeals for FERC to consider whether any acts of market manipulation support the imposition of refunds. Claims against MPS Merchant total $5.1 million for the period addressed under the Pacific Northwest refund proceedings.

112

In October 2006, the MPSC filed suit in the Circuit Court of Jackson County, Missouri against 18 companies, including GMO and MPS Merchant alleging that the companies manipulated natural gas prices through the misreporting of natural gas trade data and, therefore, violated Missouri antitrust laws. The suit does not specify alleged damages and was filed on behalf of all local distribution gas companies in Missouri who bought and sold natural gas from June 2000 to October 2002. The defendants’ motions to dismiss the case were granted in January 2009. In February 2009, the MPSC appealed the dismissal to the Missouri Court of Appeals for the Western District of Missouri. In December 2009, the Missouri Court of Appeals affirmed the dismissal and the MPSC filed a request for rehearing or, in the alternative, transfer to the Missouri Supreme Court. The Missouri Supreme Court accepted the transfer in April 2010, but in September 2010, transferred the case back to the Court of Appeals, which then reaffirmed its earlier opinion. The Company does not currently expect any further action with respect to this matter.

~~17.~~16.

GUARANTEES

In the ordinary course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees and letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended business purposes. The majority of these agreements guarantee the Company’s own future performance, so a liability for the fair value of the obligation is not recorded.

~~115~~

At December 31, ~~2010,~~2011, Great Plains Energy has provided ~~$1,030.4~~$666.0 million of credit support for GMO as follows:

·	Great Plains Energy direct guarantees to GMO counterparties totaling ~~$65.4~~$40.7 million, of which ~~$45.4 million expire in 2011 and $20.0 million~~ expire in 2012,

·	Great Plains Energy letters of credit to GMO counterparties totaling ~~$15.8~~$11.6 million, , which expire in ~~2011,~~2012, and

·	Great Plains Energy guarantee of GMO long-term debt totaling ~~$949.2~~$613.7 million, which includes debt with maturity dates ranging from ~~2011-2023.~~2012-2023.

~~18.~~17.

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

KCP&L employees manage GMO’s business and operate its facilities at cost. These costs totaled $108.4 million for 2011, $100.9 million for 2010 and $102.7 million for ~~2009 and $41.0 million for 2008, subsequent to the July 14, 2008, acquisition of GMO.~~2009. Additionally, KCP&L and GMO engage in wholesale electricity transactions with each other. KCP&L and GMO are also authorized to participate in the Great Plains Energy money pool, an internal financing arrangement in which funds may be lent on a short-term basis to KCP&L and GMO. The following table summarizes KCP&L’s related party receivables and payables.

December 31
2010 2009
(millions)
Receivable from GMO $    29.6 $ 26.4
Payable to Great Plains Energy Services Incorporated             - (0.2 )
Receivable from Great Plains Energy        13.3     15.1
Receivable from MPS Merchant          0.3    0.9

~~116~~


	December 31
	2011		2010
	(millions)
Net receivable from GMO	$	24.1	$	29.9
Net receivable from Great Plains Energy		9.5		13.3

~~19.~~18.

DERIVATIVE INSTRUMENTS

Great Plains Energy and KCP&L are exposed to a variety of market risks including interest rates and commodity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on Great Plains Energy’s and KCP&L’s operating results. Commodity risk management activities, including the use of certain derivative instruments, are subject to the management, direction and control of an internal risk management committee. Management’s interest rate risk management strategy uses derivative instruments to adjust Great Plains Energy’s and KCP&L’s liability portfolio to optimize the mix of fixed and floating rate debt within an established range. In addition, Great Plains Energy and KCP&L use derivative instruments to hedge against future interest rate fluctuations on anticipated debt issuances. Management maintains commodity price risk management strategies that use derivative instruments to reduce the effects of fluctuations in fuel expense caused by commodity price volatility. Counterparties to commodity derivatives and interest rate swap agreements expose Great Plains Energy and KCP&L to credit loss in the event of nonperformance. This credit loss is limited to the cost of replacing these contracts at current

113

market rates. Derivative instruments, excluding those instruments that qualify for the ~~normal purchase normal sale~~NPNS election, which are accounted for by accrual accounting, are recorded on the balance sheet at fair value as an asset or liability. Changes in the fair value of derivative instruments are recognized currently in net income unless specific hedge accounting criteria are met, except GMO utility operations hedges that are recorded to a regulatory asset or liability consistent with MPSC regulatory orders, as discussed below.

Great Plains Energy and KCP&L have posted collateral, in the ordinary course of business, for the aggregate fair value of all derivative instruments with credit risk-related contingent features that are in a liability position. At December 31, ~~2010,~~2011, Great Plains Energy and KCP&L have posted collateral in excess of the aggregate fair value of its derivative instruments; therefore, if the credit risk-related contingent features underlying these agreements were triggered, Great Plains Energy and KCP&L would not be required to post additional collateral to its counterparties.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, signed into law in July 2010, includes provisions related to the swaps and over-the-counter derivative markets. The Companies currently expect that their commodity and interest rate hedges will be exempt from mandatory clearing and exchange trading requirements. Capital and margin requirements for these hedges are expected to be determined over the next year as regulatory agencies implement rules. While the Companies currently do not anticipate this law and the associated regulatory rules to have a material impact on their financial condition, the ultimate impact cannot be reasonably determined until the final rules are issued.

Interest Rate Risk Management

In ~~August 2010,~~May 2011, Great Plains Energy issued ~~$250.0~~$350.0 million of long-term debt and settled ~~two~~six FSS simultaneously with the issuance of ~~the~~this long-term fixed rate debt. Great Plains Energy had entered into the ~~two~~six FSS with notional amounts ~~of $125.0~~totaling $350.0 million to hedge against interest rate ~~fluctuations~~variability on ~~a portion of~~ the ~~August 2010~~ debt issuance. The ~~two~~six FSS were treated as cash flow hedges with no ineffectiveness recorded in ~~2010~~2011 or ~~2009.~~2010. A pre-tax loss of ~~$6.9~~$26.1 million was recorded to OCI and is being reclassified to interest expense over the ~~life~~first three years of the ~~three-year~~ten-year debt. ~~At December 31, 2010, $0.9~~In 2011, a $5.4 million ~~of the~~ loss has been reclassified from OCI to interest expense.

In December 2009 and January 2010, Great Plains Energy entered into five FSS with total notional amounts of $350.0 million to hedge against interest rate fluctuations on debt anticipated to be issued in 2011. The five FSS remove a portion of the interest rate variability on $350.0 million of the debt expected to be issued thereby enabling Great Plains Energy to predict with greater assurance its future interest costs on that debt. The five FSS are treated as cash flow hedges with no ineffectiveness in 2010 or 2009. At December 31, 2010, a $20.8 million loss was recorded in OCI for the five FSS. The FSS will settle simultaneously with the issuance of the underlying long-term debt expected to be issued. Any gain or loss on the settlement will be recorded to OCI and reclassified to interest expense over the life of the debt.

~~117~~

Commodity Risk Management

KCP&L’s risk management policy is to use derivative instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales. At December 31, ~~2010,~~2011, KCP&L ~~has~~had hedged 66%, ~~45%~~56% and ~~22%~~13%, respectively, of the ~~2011,~~ 2012, 2013 and ~~2013~~2014 projected natural gas usage for retail load and firm MWh sales ~~primarily~~ by utilizing futures ~~contracts and financial instruments.~~contracts. KCP&L has designated the natural gas hedges as cash flow hedges. The fair values of these instruments are recorded as derivative assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, any ineffective portion of the change in fair market value would be recorded currently in fuel expense. KCP&L has not recorded any ineffectiveness on natural gas hedges in 2011, 2010 ~~2009~~ or ~~2008.~~2009.

GMO’s risk management policy is to use derivative instruments to mitigate price exposure to natural gas price volatility in the market. The fair value of the portfolio relates to financial contracts that will settle against actual purchases of natural gas and purchased power. At December 31, ~~2010,~~2011, GMO had financial contracts in place to hedge approximately ~~67%~~45%, ~~45%~~38% and 38%, respectively, of the expected on-peak natural gas and natural gas equivalent purchased power price exposure for ~~2011,~~ 2012, 2013 and ~~2013, respectively.~~2014. GMO has designated its natural gas hedges as economic hedges (non-hedging derivatives). In connection with GMO’s 2005 Missouri electric rate case, it was agreed that the settlement costs of these contracts would be recognized in fuel expense. The settlement cost is included in GMO’s FAC. A regulatory asset has been recorded to reflect the change in the timing of recognition authorized by the MPSC. To the extent recovery of actual costs incurred is allowed, amounts will not impact earnings, but will impact cash flows due to the timing of the recovery mechanism.

MPS Merchant, which has certain long-term natural gas contracts remaining from its former non-regulated trading operations, manages the daily delivery of its remaining contractual commitments with economic hedges (non-hedging derivatives) to reduce its exposure to changes in market prices. Within the trading portfolio, MPS Merchant takes certain positions to hedge physical sale or purchase contracts. MPS Merchant records the fair value of physical trading energy contracts as derivative assets or liabilities with an offsetting entry to the consolidated statements of income.

~~118~~114

The notional and recorded fair values of open positions for derivative instruments are summarized in the following table. The fair values of these derivatives are recorded on the consolidated balance sheets. The fair values below are gross values before netting agreements and netting of cash collateral.


	December 31										December 31					December 31
	2010					2009					2011					2010
	Notional					Notional					Notional					Notional
	Contract		Fair			Contract		Fair			Contract		Fair			Contract		Fair
	Amount		Value			Amount		Value			Amount		Value			Amount		Value
Great Plains Energy	(millions)										(millions)
Futures contracts
Cash flow hedges	$	4.0	$	-		$	3.2	$	-		$	2.0	$	(0.5	)	$	4.0	$	-
Non-hedging derivatives		59.5		(2.5	)		29.8		(0.9	)		23.6		(5.0	)		59.5		(2.5	)
Forward contracts
Non-hedging derivatives		202.8		8.9			234.4		9.1			97.3		7.8			202.8		8.9
Option contracts
Cash flow hedges		-		-			2.3		0.2
Non-hedging derivatives		0.2		-			-		-			0.4		-			0.2		-
Anticipated debt issuance
Forward starting swaps		350.0		(20.8	)		362.5		(0.7	)		-		-			350.0		(20.8	)
KCP&L
Futures contracts
Cash flow hedges		4.0		-			3.2		-			2.0		(0.5	)		4.0		-
Option contracts
Cash flow hedges		-		-			2.3		0.2

The fair ~~value~~values of Great Plains Energy’s and KCP&L’s open derivative positions are summarized in the following tables. The tables contain both derivative instruments designated as hedging instruments as well as ~~derivative instruments not designated as hedging instruments (non-hedging derivatives)~~non-hedging derivatives under GAAP. The fair values below are gross values before netting agreements and netting of cash collateral.


Great Plains Energy
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		7.8		5.0
Total Derivatives		$	7.8	$	5.5

December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1
Interest rate contracts	Derivative instruments		-		20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts	Derivative instruments		9.4		3.0
Total Derivatives		$	9.5	$	23.9

Great Plains Energy
      Balance Sheet Asset Derivatives Liability Derivatives
December 31, 2010       Classification Fair Value Fair Value
Derivatives Designated as Hedging Instruments (millions)
Commodity contracts Derivative instruments $       0.1 $         0.1
Interest rate contracts Derivative instruments              -           20.8
Derivatives Not Designated as Hedging Instruments
Commodity contracts Derivative instruments           9.4             3.0
Total Derivatives $       9.5 $       23.9

December 31, 2009
Derivatives Designated as Hedging Instruments
Commodity contracts Derivative instruments $       0.4 $         0.2
Interest rate contracts Derivative instruments              -             0.7
Derivatives Not Designated as Hedging Instruments
Commodity contracts Derivative instruments           9.9             1.7
Total Derivatives $     10.3 $         2.6

~~119~~115

KCP&L
      Balance Sheet Asset Derivatives Liability Derivatives
December 31, 2010       Classification Fair Value Fair Value
Derivatives Designated as Hedging Instruments (millions)
Commodity contracts Derivative instruments $       0.1 $         0.1

December 31, 2009
Derivatives Designated as Hedging Instruments
Commodity contracts Derivative instruments $       0.4 $         0.2


KCP&L
	Balance Sheet	Asset Derivatives		Liability Derivatives
December 31, 2011	Classification	Fair Value		Fair Value
Derivatives Designated as Hedging Instruments		(millions)
Commodity contracts	Derivative instruments	$	-	$	0.5

December 31, 2010
Derivatives Designated as Hedging Instruments
Commodity contracts	Derivative instruments	$	0.1	$	0.1

The following tables summarize the amount of gain (loss) recognized in OCI or earnings for interest rate and commodity hedges.


Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
				Gain (Loss) Reclassified from
				Accumulated OCI into Income
				(Effective Portion)

	Amount of Gain
	(Loss) Recognized
	in OCI on Derivatives			Income Statement
	(Effective Portion)			Classification		Amount
2011	(millions)				(millions)
Interest rate contracts	$	(5.3	)	Interest charges	$	(16.9	)
Commodity contracts		(0.6	)	Fuel		(0.1	)
Income tax benefit		2.3		Income tax benefit		6.6
Total	$	(3.6	)	Total	$	(10.4	)

2010
Interest rate contracts	$	(27.1	)	Interest charges	$	(10.1	)
Commodity contracts		(0.9	)	Fuel		(0.5	)
Income tax benefit		10.8		Income tax benefit		4.0
Total	$	(17.2	)	Total	$	(6.6	)

Great Plains Energy
Derivatives in Cash Flow Hedging Relationship
Gain (Loss) Reclassified from
Accumulated OCI into Income
(Effective Portion)
Amount of Gain
(Loss) Recognized
in OCI on Derivatives      Income Statement
(Effective Portion)          Classification Amount
2010 (millions) (millions)
Interest rate contracts $   (27.1) Interest charges $   (10.1)
Commodity contracts         (0.9) Fuel         (0.5)
Income tax benefit (expense)          10.8 Income tax benefit (expense)         4.0
Total $   (17.2) Total $     (6.6)

2009
Interest rate contracts $       0.4 Interest charges $     (8.0)
Commodity contracts           (0.8) Fuel         (1.1)
Income tax benefit (expense)            0.1 Income tax benefit (expense)         3.5
Total $     (0.3) Total $     (5.6)

~~120~~116


KCP&L	KCP&L
Derivatives in Cash Flow Hedging Relationship	Derivatives in Cash Flow Hedging Relationship				Derivatives in Cash Flow Hedging Relationship
			Gain (Loss) Reclassified from					Gain (Loss) Reclassified from
			Accumulated OCI into Income					Accumulated OCI into Income
			(Effective Portion)					(Effective Portion)
		Amount of Gain
		(Loss) Recognized			Amount of Gain
		in OCI on Derivatives	Income Statement		(Loss) Recognized
		(Effective Portion)	Classification	Amount	in OCI on Derivatives			Income Statement
					(Effective Portion)			Classification		Amount
2011					(millions)				(millions)
Interest rate contracts					$	-		Interest charges	$	(8.7	)
Commodity contracts						(0.6	)	Fuel		(0.1	)
Income tax benefit						0.2		Income tax benefit		3.4
Total					$	(0.4	)	Total	$	(5.4	)

2010		(millions)		(millions)
Interest rate contracts		$ -	Interest charges	$ (8.8)	$	-		Interest charges	$	(8.8	)
Commodity contracts		(0.9)	Fuel	(0.5)		(0.9	)	Fuel		(0.5	)
Income tax benefit (expense)		0.3	Income tax benefit (expense)	3.6
Income tax benefit						0.3		Income tax benefit		3.6
Total		$ (0.6)	Total	$ (5.7)	$	(0.6	)	Total	$	(5.7	)

2009
Interest rate contracts		$ 1.0	Interest charges	$ (7.5)
Commodity contracts		(0.8)	Fuel	(1.1)
Income tax benefit (expense)		(0.1)	Income tax benefit (expense)	3.3
Total		$ 0.1	Total	$ (5.3)

The following table summarizes the amount of gain (loss) recognized in a regulatory balance sheet account or earnings for GMO utility commodity hedges. GMO utility commodity derivatives fair value changes are recorded to either a regulatory asset or liability consistent with MPSC regulatory orders.


Great Plains Energy	Great Plains Energy
Derivatives in Regulatory Account Relationship	Derivatives in Regulatory Account Relationship
			Gain (Loss) Reclassified from					Gain (Loss) Reclassified from
			Regulatory Account					Regulatory Account
		Amount of Gain (Loss)			Amount of Gain (Loss)
		Recognized on Regulatory			Recognized on Regulatory
		Account on Derivatives	Income Statement		Account on Derivatives			Income Statement
		(Effective Portion)	Classification	Amount	(Effective Portion)			Classification	Amount
		(millions)		(millions)	(millions)				(millions)
2011
Commodity contracts					$	(8.3	)	Fuel	$	(3.8	)
Total					$	(8.3	)	Total	$	(3.8	)

2010
Commodity contracts	Commodity contracts	$ (8.2)	Fuel	$ (7.2)	$	(8.2	)	Fuel	$	(7.2	)
Total		$ (8.2)	Total	$ (7.2)	$	(8.2	)	Total	$	(7.2	)

2009
Commodity contracts		$ (12.8)	Fuel	$ (20.5)
Total		$ (12.8)	Total	$ (20.5)

Great Plains Energy’s income statement reflects ~~a loss~~losses for the change in fair value of the MPS Merchant commodity contract derivatives not designated as hedging instruments of $1.1 million for 2011 and $0.2 million for ~~2010 and a gain of $1.6 million for 2009.~~2010.

~~121~~117

The amounts recorded in accumulated OCI related to the cash flow hedges are summarized in the following table.

Great Plains Energy KCP&L
December 31 December 31
2010 2009 2010 2009
(millions)
Current assets $ 12.0 $ 13.3 $ 12.0 $ 13.3
Current liabilities (101.5 ) (84.9 ) (71.6 ) (81.2 )
Noncurrent liabilities - (0.5 ) - -
Deferred income taxes 34.8 28.0 23.2 26.4
Total $ (54.7 ) $ (44.1 ) $ (36.4 ) $ (41.5 )


	Great Plains Energy						KCP&L
	December 31						December 31
	2011			2010			2011			2010
	(millions)
Current assets	$	11.3		$	12.0		$	11.3		$	12.0
Current liabilities		(89.5	)		(101.5	)		(62.5	)		(71.6	)
Noncurrent liabilities		(0.2	)		-		��	(0.2	)		-
Deferred income taxes		30.5			34.8			20.0			23.2
Total	$	(47.9	)	$	(54.7	)	$	(31.4	)	$	(36.4	)

Great Plains Energy’s accumulated OCI in the table above at December 31, ~~2010,~~2011, includes ~~$15.6~~$20.5 million that is expected to be reclassified to expenses over the next twelve months. KCP&L’s accumulated OCI includes ~~$8.8~~$9.1 million that is expected to be reclassified to expense over the next twelve months.

~~The amounts reclassified to expenses for 2008 are summarized in the following table.~~

2008
Great Plains Energy (millions)
Fuel expense $ (2.3 )
Interest expense 2.8
Income tax expense (0.2 )
Income (loss) from discontinued operations
Purchased power expense (106.1 )
Income taxes 43.8
OCI $ (62.0 )
KCP&L
Fuel expense $ (2.3 )
Interest expense 2.5
OCI $ 0.2

~~20.~~19.

FAIR VALUE MEASUREMENTS

GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad categories, giving the highest priority to quoted prices in active markets for identical assets or liabilities and lowest priority to unobservable inputs. A definition of the various levels, as well as discussion of the various measurements within the levels, is as follows:

Level 1 – Unadjusted quoted prices for identical assets or liabilities in active markets that Great Plains Energy and KCP&L have access to at the measurement date. Assets categorized within this level consist of Great Plains Energy’s and KCP&L’s various exchange traded derivative instruments and equity and U.S. Treasury securities that are actively traded within KCP&L’s decommissioning trust fund and GMO’s SERP rabbi trust fund.

Level 2 – Market-based inputs for assets or liabilities that are observable (either directly or indirectly) or inputs that are not observable but are corroborated by market data. Assets and liabilities categorized within this level consist of Great Plains Energy’s and KCP&L’s various non-exchange traded derivative instruments traded in

~~122~~

over-the-counter markets and certain debt securities within KCP&L’s decommissioning trust fund and GMO’s SERP rabbi trust fund.

Level 3 – Unobservable inputs, reflecting Great Plains Energy’s and KCP&L’s own assumptions about the assumptions market participants would use in pricing the asset or liability. Assets categorized within this level consist of Great Plains Energy’s various non-exchange traded derivative instruments traded in over-the-counter markets ~~and certain debt securities within KCP&L’s decommissioning trust fund~~ for which sufficiently observable market data is not available to corroborate the valuation inputs.

~~123~~118

The following tables include Great Plains Energy’s and KCP&L’s balances of financial assets and liabilities measured at fair value on a recurring basis at December 31, ~~2010~~2011 and ~~2009.~~2010.

Fair Value Measurements Using
Description
December 31
2010

Netting(d)

Quoted Prices in Active Markets for Identical Assets
(Level 1)

Significant Other Observable Inputs
(Level 2)

Significant Unobservable Inputs
(Level 3)

KCP&L (millions)
Assets
Derivative instruments (a)
$ - $ (0.1 ) $ 0.1 $ - $ -
Nuclear decommissioning trust (b)

Equity securities 85.5 - 85.5 - -
Debt securities
U.S. Treasury 8.9 - 8.9 - -
U.S. Agency 4.8 - - 4.8 -
State and local obligations 2.5 - - 2.5 -
Corporate bonds 23.7 - - 23.7 -
Foreign governments 0.7 - - 0.7 -
Other 0.4 - - 0.4 -
Total nuclear decommissioning trust 126.5 - 94.4 32.1 -
Total 126.5 (0.1 ) 94.5 32.1 -
Liabilities
Derivative instruments (a)
- (0.1 ) 0.1 - -
Total $ - $ (0.1 ) $ 0.1 $ - $ -
Other Great Plains Energy
Assets
Derivative instruments (a)
$ 8.9 $ (0.5 ) $ 0.5 $ 5.2 $ 3.7
SERP rabbi trust (c)

Equity securities 0.2 - 0.2 - -
Debt securities 7.0 - - 7.0 -
Total SERP rabbi trust 7.2 - 0.2 7.0 -
Total 16.1 (0.5 ) 0.7 12.2 3.7
Liabilities
Derivative instruments (a)
20.8 (3.0 ) 3.0 20.8 -
Total $ 20.8 $ (3.0 ) $ 3.0 $ 20.8 $ -
Great Plains Energy
Assets
Derivative instruments (a)
$ 8.9 $ (0.6 ) $ 0.6 $ 5.2 $ 3.7
Nuclear decommissioning trust (b)
126.5 - 94.4 32.1 -
SERP rabbi trust (c)
7.2 - 0.2 7.0 -
Total 142.6 (0.6 ) 95.2 44.3 3.7
Liabilities
Derivative instruments (a)
20.8 (3.1 ) 3.1 20.8 -
Total $ 20.8 $ (3.1 ) $ 3.1 $ 20.8 $ -


							Fair Value Measurements Using
Description	December 31 2011			Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
KCP&L	(millions)
Assets
Nuclear decommissioning trust (b)
Equity securities	$	84.3		$	-		$	84.3	$	-		$	-
Debt securities
U.S. Treasury		15.3			-			15.3		-			-
U.S. Agency		3.6			-			-		3.6			-
State and local obligations		2.6			-			-		2.6			-
Corporate bonds		26.4			-			-		26.4			-
Foreign governments		0.7			-			-		0.7			-
Other		(0.6	)		-			-		(0.6	)		-
Total nuclear decommissioning trust		132.3			-			99.6		32.7			-
Total		132.3			-			99.6		32.7			-
Liabilities
Derivative instruments (a)		-			(0.5	)		0.5		-			-
Total	$	-		$	(0.5	)	$	0.5	$	-		$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	7.8		$	-		$	-	$	4.7		$	3.1
SERP rabbi trust (c)
Equity securities		0.2			-			0.2		-			-
Debt securities		0.1			-			-		0.1			-
Total SERP rabbi trust		0.3			-			0.2		0.1			-
Total		8.1			-			0.2		4.8			3.1
Liabilities
Derivative instruments (a)		-			(5.0	)		5.0		-			-
Total	$	-		$	(5.0	)	$	5.0	$	-		$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	7.8		$	-		$	-	$	4.7		$	3.1
Nuclear decommissioning trust (b)		132.3			-			99.6		32.7			-
SERP rabbi trust (c)		0.3			-			0.2		0.1			-
Total		140.4			-			99.8		37.5			3.1
Liabilities
Derivative instruments (a)		-			(5.5	)		5.5		-			-
Total	$	-		$	(5.5	)	$	5.5	$	-		$	-

~~124~~119


						Fair Value Measurements Using											Fair Value Measurements Using
Description	December 31 2009		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		December 31 2010		Netting(d)			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
KCP&L	(millions)											(millions)
Assets
Derivative instruments (a)	$	0.2	$	(0.2	)	$	0.2	$	0.2	$	-	$	-	$	(0.1	)	$	0.1	$	-	$	-
Nuclear decommissioning trust (b)												Nuclear decommissioning trust (b)
Equity securities		44.5		-			44.5		-		-		85.5		-			85.5		-		-
Debt securities
U.S. Treasury		11.2		-			11.2		-		-		8.9		-			8.9		-		-
U.S. Agency		3.5		-			-		3.5		-		4.8		-			-		4.8		-
State and local obligations		3.1		-			-		2.9		0.2		2.5		-			-		2.5		-
Corporate bonds		18.9		-			-		18.9		-		23.7		-			-		23.7		-
Foreign governments		0.7		-			-		0.7		-		0.7		-			-		0.7		-
Other		1.2		-			-		1.2		-		0.4		-			-		0.4		-
Total nuclear decommissioning trust		83.1		-			55.7		27.2		0.2		126.5		-			94.4		32.1		-
Total		83.3		(0.2	)		55.9		27.4		0.2		126.5		(0.1	)		94.5		32.1		-
Liabilities
Derivative instruments (a)		-		(0.2	)		-		0.2		-		-		(0.1	)		0.1		-		-
Total	$	-	$	(0.2	)	$	-	$	0.2	$	-	$	-	$	(0.1	)	$	0.1	$	-	$	-
Other Great Plains Energy
Assets
Derivative instruments (a)	$	9.2	$	(0.7	)	$	0.7	$	5.1	$	4.1	$	8.9	$	(0.5	)	$	0.5	$	5.2	$	3.7
SERP rabbi trust (c)
Equity securities		0.2		-			0.2		-		-		0.2		-			0.2		-		-
Debt securities		6.9		-			-		6.9		-		7.0		-			-		7.0		-
Total SERP rabbi trust		7.1		-			0.2		6.9		-		7.2		-			0.2		7.0		-
Total		16.3		(0.7	)		0.9		12.0		4.1		16.1		(0.5	)		0.7		12.2		3.7
Liabilities
Derivative instruments (a)		0.8		(1.6	)		1.6		0.8		-		20.8		(3.0	)		3.0		20.8		-
Total	$	0.8	$	(1.6	)	$	1.6	$	0.8	$	-	$	20.8	$	(3.0	)	$	3.0	$	20.8	$	-
Great Plains Energy
Assets
Derivative instruments (a)	$	9.4	$	(0.9	)	$	0.9	$	5.3	$	4.1	$	8.9	$	(0.6	)	$	0.6	$	5.2	$	3.7
Nuclear decommissioning trust (b)		83.1		-			55.7		27.2		0.2		126.5		-			94.4		32.1		-
SERP rabbi trust (c)		7.1		-			0.2		6.9		-		7.2		-			0.2		7.0		-
Total		99.6		(0.9	)		56.8		39.4		4.3		142.6		(0.6	)		95.2		44.3		3.7
Liabilities
Derivative instruments (a)		0.8		(1.8	)		1.6		1.0		-		20.8		(3.1	)		3.1		20.8		-
Total	$	0.8	$	(1.8	)	$	1.6	$	1.0	$	-	$	20.8	$	(3.1	)	$	3.1	$	20.8	$	-

120

(a)	The fair value of derivative instruments is estimated using market quotes, over-the-counter forward price and volatility curves and correlations among fuel prices, net of estimated credit risk.

(b)

Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include ~~$2.7~~$3.0 million and ~~$29.4~~$2.7 million at December 31, ~~2010~~2011 and ~~2009,~~2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

~~125~~

(c)

Fair value is based on quoted market prices of the investments held by the fund and/or valuation models. The total does not include ~~$14.6~~$20.3 million and ~~$16.2~~$14.6 million at December 31, ~~2010~~2011 and ~~2009,~~2010, respectively, of cash and cash equivalents, which are not subject to the fair value requirements.

(d)

Represents the difference between derivative contracts in an asset or liability position presented on a net basis by counterparty on the consolidated balance sheet where a master netting agreement exists between the Company and the counterparty. At December 31, ~~2010~~2011 and ~~2009,~~2010, Great Plains Energy netted ~~$2.5~~$5.5 million and ~~$0.9~~$2.5 million, respectively, of cash collateral posted with counterparties.

The following tables reconcile the beginning and ending balances for all ~~level~~Level 3 assets and liabilities, net measured at fair value on a recurring basis for ~~2010~~2011 and ~~2009.~~2010.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Other
Great Great
Plains Plains
KCP&L Energy Energy
State & Local Derivative
Obligations Instruments Total
(millions)
Balance January 1, 2010 $ 0.2 $ 4.1 $ 4.3
Total realized/unrealized gains or (losses)
Included in non-operating income - (12.5 ) (12.5 )
Sales (0.2 ) - (0.2 )
Settlements - 12.1 12.1
Balance December 31, 2010 $ - $ 3.7 $ 3.7

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at December 31, 2010 $ - $ 0.1 $ 0.1


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Other
	Great
	Plains
	Energy
	Derivative
	Instruments
	(millions)
Balance January 1, 2011	$	3.7
Total realized/unrealized gains
included in non-operating income		10.9
Settlements		(11.5	)
Balance December 31, 2011	$	3.1

Total unrealized losses included in non-operating
income relating to assets and liabilities still on the
consolidated balance sheet at December 31, 2011	$	(0.2	)

~~126~~121

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Other
Great Great
Plains Plains
KCP&L Energy Energy
Mortgage
U.S. State & Local Backed Derivative
Description Agency Obligations Securities Total Instruments Total
(millions)
Balance January 1, 2009 $ 3.9 $ - $ 2.9 $ 6.8 $ 3.8 $ 10.6
Total realized/unrealized gains or (losses)
Included in regulatory liability - - 1.1 1.1 - 1.1
Included in non-operating income - - - - 1.2 1.2
Purchase, issuances, and settlements (3.9 ) - (4.0 ) (7.9 ) (0.9 ) (8.8 )
Transfers in and/or out of Level 3 - 0.2 - 0.2 - 0.2
Balance December 31, 2009 $ - $ 0.2 $ - $ 0.2 $ 4.1 $ 4.3

Total unrealized gains and (losses) included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at December 31, 2009 $ - $ - $ - $ - $ 0.8 $ 0.8


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
				Other
				Great			Great
				Plains			Plains
	KCP&L			Energy			Energy
	State & Local			Derivative
	Obligations			Instruments			Total
	(millions)
Balance January 1, 2010	$	0.2		$	4.1		$	4.3
Total realized/unrealized losses
included in non-operating income		-			(12.5	)		(12.5	)
Sales		(0.2	)		-			(0.2	)
Settlements		-			12.1			12.1
Balance December 31, 2010	$	-		$	3.7		$	3.7

Total unrealized gains included in non-operating
income relating to assets and liabilities still
on the consolidated balance sheet at December 31, 2010	$	-		$	0.1		$	0.1

Investments in Affordable Housing Limited Partnerships

Nearly all of Great Plains Energy’s investments in affordable housing limited partnerships were recorded at cost; the equity method was used for the remainder. Accounting guidance requires entities to evaluate whether an event or change in circumstances has occurred that may have a significant adverse effect on the fair value of the investment (an impairment indicator). During 2010, an impairment indicator occurred, which required Great Plains Energy to evaluate if its cost method investments in affordable housing limited partnerships were impaired. The value of these investments iswas derived from tax credits and potential cash distributions from the partnerships upon sales of the underlying properties. All of the tax credits ~~have~~had been received and management ~~does~~did not anticipate receiving any cash distributions from the ~~partnership;~~partnerships; therefore, management concluded that the investments were impaired and that the impairment was other than temporary since the partnerships ~~are~~were in the process of liquidating over the next 2 – 3 years. As a result of the evaluation, management concluded that the cost method investments ~~have~~had no value and accordingly, Great Plains Energy recorded an $11.2 million pre-tax impairment loss in non-operating expense on the consolidated income ~~statement.~~

statement in 2010.

~~127~~122

~~21.~~20.

TAXES

Components of income tax expense (benefit) are detailed in the following tables.

Great Plains Energy 2010 2009 2008
Current income taxes (millions)
Federal $ (7.4 ) $ (11.1 ) $ (21.0 )
State (4.3 ) (0.9 ) 1.1
Foreign 0.1 1.3 -
Total (11.6 ) (10.7 ) (19.9 )
Deferred income taxes
Federal 99.8 (13.6 ) 3.3
State 24.0 10.0 40.8
Total 123.8 (3.6 ) 44.1
Noncurrent income taxes
Federal (4.8 ) 8.3 (0.6 )
State (1.8 ) 1.1 (1.0 )
Foreign 0.5 (1.5 ) -
Total (6.1 ) 7.9 (1.6 )
Investment tax credit
Deferral (4.2 ) 37.2 74.2
Amortization (2.9 ) (2.2 ) (1.8 )
Total (7.1 ) 35.0 72.4
Total income tax expense 99.0 28.6 95.0
Less: taxes on discontinued operations
Current tax expense - (1.1 ) 25.8
Deferred tax expense - 0.2 4.5
Noncurrent income tax expense - - 0.9
Income tax expense on continuing operations $ 99.0 $ 29.5 $ 63.8


KCP&L	2010			2009			2008
Great Plains Energy										2011			2010			2009
Current income taxes	(millions)									(millions)
Federal	$	5.5		$	41.2		$	(8.0	)	$	2.9		$	(7.4	)	$	(11.1	)
State		1.1			4.8			4.5			(6.0	)		(4.3	)		(0.9	)
Foreign											(0.4	)		0.1			1.3
Total		6.6			46.0			(3.5	)		(3.5	)		(11.6	)		(10.7	)
Deferred income taxes
Federal		69.8			(41.7	)		(38.4	)		90.5			99.8			(13.6	)
State		13.4			3.5			30.9			20.7			24.0			10.0
Total		83.2			(38.2	)		(7.5	)		111.2			123.8			(3.6	)
Noncurrent income taxes
Federal		(1.6	)		3.4			(1.7	)		(18.0	)		(4.8	)		8.3
State		(0.3	)		(0.1	)		(0.3	)		(2.1	)		(1.8	)		1.1
Foreign											(0.6	)		0.5			(1.5	)
Total		(1.9	)		3.3			(2.0	)		(20.7	)		(6.1	)		7.9
Investment tax credit
Deferral		(4.2	)		37.2			74.2			-			(4.2	)		37.2
Amortization		(2.1	)		(1.4	)		(1.4	)		(2.2	)		(2.9	)		(2.2	)
Total		(6.3	)		35.8			72.8			(2.2	)		(7.1	)		35.0
Total	$	81.6		$	46.9		$	59.8
Total income tax expense											84.8			99.0			28.6
Less: taxes on discontinued operations
Current tax benefit											-			-			(1.1	)
Deferred tax expense											-			-			0.2
Income tax expense on continuing operations										$	84.8		$	99.0		$	29.5

~~128~~123


KCP&L	2011			2010			2009
Current income taxes	(millions)
Federal	$	1.0		$	5.5		$	41.2
State		(0.6	)		1.1			4.8
Total		0.4			6.6			46.0
Deferred income taxes
Federal		66.0			69.8			(41.7	)
State		14.6			13.4			3.5
Total		80.6			83.2			(38.2	)
Noncurrent income taxes
Federal		(9.3	)		(1.6	)		3.4
State		(1.1	)		(0.3	)		(0.1	)
Total		(10.4	)		(1.9	)		3.3
Investment tax credit
Deferral		-			(4.2	)		37.2
Amortization		(1.5	)		(2.1	)		(1.4	)
Total		(1.5	)		(6.3	)		35.8
Total	$	69.1		$	81.6		$	46.9

Income Tax Expense and Effective Income Tax Rates

Income tax expense and the effective income tax rates reflected in continuing operations in the financial statements and the reasons for their differences from the statutory federal rates are detailed in the following tables.

Income Tax Expense Income Tax Rate
Great Plains Energy 2010 2009 2008 2010 2009 2008
(millions)
Federal statutory income tax $ 108.7 $ 63.4 $ 64.2 35.0 % 35.0 % 35.0 %
Differences between book and tax
depreciation not normalized (5.2 ) (9.9 ) (5.4 ) (1.7 ) (5.5 ) (2.9 )
Amortization of investment tax credits (2.9 ) (2.2 ) (1.8 ) (0.9 ) (1.2 ) (1.0 )
Federal income tax credits (12.5 ) (8.0 ) (10.2 ) (4.1 ) (4.4 ) (5.6 )
State income taxes 11.4 7.9 3.2 3.7 4.4 1.8
Rate change on deferred taxes - - 19.3 - - 10.5
Medicare Part D subsidy legislation 2.8 - - 0.9 - -
Changes in uncertain tax positions, net 0.3 (72.1 ) 0.1 0.1 (39.8 ) 0.1
GMO transaction costs - - (1.9 ) - - (1.0 )
Valuation allowance (2.7 ) 55.8 - (0.9 ) 30.8 -
Other (0.9 ) (5.4 ) (3.7 ) (0.3 ) (3.0 ) (2.1 )
Total $ 99.0 $ 29.5 $ 63.8 31.8 % 16.3 % 34.8 %

Income Tax Expense Income Tax Rate
KCP&L 2010 2009 2008 2010 2009 2008
(millions)
Federal statutory income tax $ 85.7 $ 61.5 $ 64.7 35.0 % 35.0 % 35.0 %
Differences between book and tax
depreciation not normalized (4.5 ) (7.7 ) (5.2 ) (1.8 ) (4.4 ) (2.8 )
Amortization of investment tax credits (2.1 ) (1.4 ) (1.4 ) (0.9 ) (0.8 ) (0.8 )
Federal income tax credits (8.5 ) (7.8 ) (9.8 ) (3.5 ) (4.4 ) (5.3 )
State income taxes 8.9 5.8 3.8 3.6 3.3 2.1
Medicare Part D subsidy legislation 2.8 - - 1.1 - -
Changes in uncertain tax positions, net - (0.5 ) (0.6 ) - (0.3 ) (0.3 )
Parent company tax benefits (a)
- - (6.7 ) - - (3.6 )
Rate change on deferred taxes - - 20.3 - - 11.0
Other (0.7 ) (3.0 ) (5.3 ) (0.2 ) (1.7 ) (3.0 )
Total $ 81.6 $ 46.9 $ 59.8 33.3 % 26.7 % 32.3 %
(a) The tax sharing between Great Plains Energy and its subsidiaries was modified on July 14, 2008. As part of the new
agreement, parent company tax benefits are no longer allocated to KCP&L or other subsidiaries.

Great Plains Energy and KCP&L are required to adjust deferred tax assets and liabilities to reflect tax rates that are anticipated to be in effect when timing differences reverse. Due to the 2008 sale of Strategic Energy, L.L.C. (Strategic Energy), the composite tax rate for the companies was expected to increase as a result of the change in composition of states that Great Plains Energy conducts business. Therefore, deferred tax assets and liabilities were adjusted in 2008 to reflect the expected increase in the composite tax rate. The impact of the increase in the composite tax rate on deferred tax assets and liabilities resulted in tax expense for Great Plains Energy and KCP&L of $19.3 million and $20.3 million, respectively, at December 31, 2008.


	Income Tax Expense									Income Tax Rate
Great Plains Energy	2011			2010			2009			2011			2010			2009
	(millions)
Federal statutory income tax	$	90.7		$	108.7		$	63.4			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		4.0			(5.2	)		(9.9	)		1.5			(1.7	)		(5.5	)
Amortization of investment tax credits		(2.2	)		(2.9	)		(2.2	)		(0.8	)		(0.9	)		(1.2	)
Federal income tax credits		(13.1	)		(12.5	)		(8.0	)		(5.0	)		(4.1	)		(4.4	)
State income taxes		10.5			11.4			7.9			4.0			3.7			4.4
Medicare Part D subsidy legislation		-			2.8			-			-			0.9			-
Changes in uncertain tax positions, net		(4.4	)		0.3			(72.1	)		(1.7	)		0.1			(39.8	)
Valuation allowance		(2.2	)		(2.7	)		55.8			(0.8	)		(0.9	)		30.8
Other		1.5			(0.9	)		(5.4	)		0.5			(0.3	)		(3.0	)
Total	$	84.8		$	99.0		$	29.5			32.7	%		31.8	%		16.3	%

~~129~~124


	Income Tax Expense									Income Tax Rate
KCP&L	2011			2010			2009			2011			2010			2009
	(millions)
Federal statutory income tax	$	71.6		$	85.7		$	61.5			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		3.4			(4.5	)		(7.7	)		1.6			(1.8	)		(4.4	)
Amortization of investment tax credits		(1.5	)		(2.1	)		(1.4	)		(0.7	)		(0.9	)		(0.8	)
Federal income tax credits		(13.0	)		(8.5	)		(7.8	)		(6.3	)		(3.5	)		(4.4	)
State income taxes		8.1			8.9			5.8			3.9			3.6			3.3
Medicare Part D subsidy legislation		-			2.8			-			-			1.1			-
Changes in uncertain tax positions, net		0.3			-			(0.5	)		0.1			-			(0.3	)
Other		0.2			(0.7	)		(3.0	)		0.2			(0.2	)		(1.7	)
Total	$	69.1		$	81.6		$	46.9			33.8	%		33.3	%		26.7	%

Deferred Income Taxes

The tax effects of major temporary differences resulting in deferred income tax assets (liabilities) in the consolidated balance sheets are in the following tables.


	Great Plains Energy						KCP&L						Great Plains Energy						KCP&L
December 31	2010			2009			2010			2009			2011			2010			2011			2010
Current deferred income taxes	(millions)
Net operating loss carryforward	$	-		$	30.4		$	-		$	-
Current deferred income tax asset (liability)													(millions)
Other		14.7			7.8			5.6			0.3		$	7.9		$	14.7		$	(0.1	)	$	5.6
Net current deferred income tax asset before
Net current deferred income tax asset (liability) before
valuation allowance		14.7			38.2			5.6			0.3			7.9			14.7			(0.1	)		5.6
Valuation allowance		(0.4	)		(1.4	)		-			-			(0.4	)		(0.4	)		-			-
Net current deferred income tax asset		14.3			36.8			5.6			0.3
Net current deferred income tax asset (liability)														7.5			14.3			(0.1	)		5.6
Noncurrent deferred income taxes
Plant related		(975.5	)		(854.7	)		(711.5	)		(631.0	)		(1,193.6	)		(975.5	)		(861.6	)		(711.5	)
Income taxes on future regulatory recoveries		(142.6	)		(104.5	)		(117.2	)		(77.6	)		(144.3	)		(142.6	)		(119.6	)		(117.2	)
Derivative instruments		46.0			39.3			34.4			37.4			43.3			46.0			31.1			34.4
Pension and postretirement benefits		(16.3	)		(4.5	)		2.0			6.5			(34.2	)		(16.3	)		(11.7	)		2.0
SO2 emission allowance sales		30.8			30.3			33.4			34.5			31.1			30.8			31.9			33.4
Fuel clause adjustments		(16.6	)		(17.6	)		(3.2	)		0.2			(17.2	)		(16.6	)		(5.4	)		(3.2	)
Transition costs		(20.0	)		(19.9	)		(11.4	)		(11.4	)		(17.4	)		(20.0	)		(9.6	)		(11.4	)
Tax credit carryforwards		204.3			202.4			101.5			97.6			213.7			204.3			116.8			101.5
Long-term debt fair value adjustment		19.2			32.5			-			-			6.3			19.2			-			-
Customer demand programs		(23.3	)		(16.5	)		(17.3	)		(13.8	)		(26.4	)		(23.3	)		(18.6	)		(17.3	)
Net operating loss carryforward		409.2			361.3			1.1			0.6			543.7			409.2			77.9			1.1
Other		(7.3	)		(1.6	)		(3.8	)		(2.4	)		(10.1	)		(7.3	)		(3.9	)		(3.8	)
Net noncurrent deferred tax liability before
Net noncurrent deferred income tax liability before
valuation allowance		(492.1	)		(353.5	)		(692.0	)		(559.4	)		(605.1	)		(492.1	)		(772.7	)		(692.0	)
Valuation allowance		(26.2	)		(28.4	)		-			-			(23.5	)		(26.2	)		-			-
Net noncurrent deferred tax liability		(518.3	)		(381.9	)		(692.0	)		(559.4	)
Net noncurrent deferred income tax liability														(628.6	)		(518.3	)		(772.7	)		(692.0	)
Net deferred income tax liability	$	(504.0	)	$	(345.1	)	$	(686.4	)	$	(559.1	)	$	(621.1	)	$	(504.0	)	$	(772.8	)	$	(686.4	)

Great Plains Energy KCP&L
December 31 2010 2009 2010 2009
(millions)
Gross deferred income tax assets $ 1,140.7 $ 1,126.4 $ 602.4 $ 597.9
Gross deferred income tax liabilities (1,644.7 ) (1,471.5 ) (1,288.8 ) (1,157.0 )
Net deferred income tax liability $ (504.0 ) $ (345.1 ) $ (686.4 ) $ (559.1 )

125


	Great Plains Energy						KCP&L
December 31	2011			2010			2011			2010
	(millions)
Gross deferred income tax assets	$	1,203.6		$	1,140.7		$	618.7		$	602.4
Gross deferred income tax liabilities		(1,824.7	)		(1,644.7	)		(1,391.5	)		(1,288.8	)
Net deferred income tax liability	$	(621.1	)	$	(504.0	)	$	(772.8	)	$	(686.4	)

Tax Credit Carryforwards

At December 31, ~~2010~~2011 and ~~2009,~~2010, Great Plains Energy had ~~$102.6~~$118.0 million and ~~$98.7~~$102.6 million, respectively, of federal general business income tax credit carryforwards. At December 31, ~~2010~~2011 and ~~2009,~~2010, KCP&L had ~~$101.5~~$116.8 million and ~~$97.6~~$101.5 million, respectively, of federal general business income tax credit carryforwards. The carryforwards for both Great Plains Energy and KCP&L relate primarily to Advanced Coal Investment Tax Credits and Wind Production tax credits and expire in the years 2028 to ~~2030.~~2031. Approximately $0.5 million of Great Plains Energy’s credits are related to Low Income Housing credits that were acquired in the GMO acquisition. Due to federal limitations on the utilization of income tax attributes acquired in the GMO acquisition, management expects these credits to expire unutilized and has provided a valuation allowance against $0.4 million of the federal income tax benefit.

~~130~~

At December 31, ~~2010~~2011 and ~~2009,~~2010, Great Plains Energy had ~~$90.0~~$91.0 million and ~~$87.6~~$90.0 million, respectively, of federal alternative minimum tax credit carryforwards. Of this amount, $89.8 million was acquired in the GMO acquisition. These credits do not expire and can be used to reduce taxes paid in the future.

At December 31, ~~2010~~2011 and ~~2009,~~2010, Great Plains Energy had ~~$11.8~~$4.7 million and ~~$16.2~~$11.8 million, respectively, of state income tax credit carryforwards. The state income tax credits relate primarily to the Company’s Missouri affordable housing investment portfolio, and the carryforwards expire in the years ~~2011~~2012 to ~~2015.~~2016. Management expects that a portion of these credits will expire unutilized and has provided a valuation allowance against ~~$0.6~~$0.3 million of the state income tax benefit.

~~Advanced Coal Credit~~

In April 2008, KCP&L was notified that its application filed in 2007 for $125.0 million in advanced coal investment tax credits (ITC) was approved by the IRS. The credit is based on the amount of expenses incurred on the construction of Iatan No. 2. Additionally, in order to meet the advanced clean coal standards and avoid forfeiture and/or the recapture of tax credits in the future, KCP&L must meet or exceed certain environmental performance standards for at least five years once the plant is placed in service.

In September 2010, the IRS issued an amended memorandum of understanding to reallocate $17.7 million of the original $125 million of the advanced coal project credits to Empire, meeting the requirements of an arbitration order issued on December 30, 2009. See Note 16 for the related legal proceeding. As a result, Great Plains Energy and KCP&L reduced the amount of advanced coal credit previously recognized. The amount of deferred federal tax expense associated with the reduction in 2010, was $4.2 million. Since the tax laws require KCP&L to reduce income tax expense for ratemaking and financial statement purposes ratably over the life of the plant, Great Plains Energy and KCP&L concurrently recognized a separate deferred advanced coal ITC benefit to offset the current and deferred federal tax expense. Great Plains Energy and KCP&L recognized $0.7 million of ITC in 2010 after the plant was placed in service and will continue to recognize the tax benefits over the life of the plant. At December 31, 2010, Great Plains Energy and KCP&L had $106.6 million of deferred advanced coal ITC.

Net Operating Loss Carryforwards

At December 31, ~~2010~~2011 and ~~2009,~~2010, Great Plains Energy had ~~$353.0~~$473.1 million and ~~$337.5~~$353.0 million, respectively, of tax benefits related to federal net operating loss (NOL) carryforwards. Approximately ~~$317.5~~$315.7 million and ~~$320.5~~$317.5 million, at December 31, ~~2010~~2011 and ~~2009,~~2010, respectively, are tax benefits related to NOLs that were acquired in the GMO acquisition. The tax benefits for NOLs are $32.6 million originating in 2003, ~~are $34.4 million,~~ $152.4 million originating in 2004, $74.1 million originating in 2005, $53.3 million originating in 2006, $1.3 million originating in 2007, ~~$2.5~~$2.4 million originating in 2008, ~~$26.9~~$23.4 million originating in 2009, ~~and $8.1~~$11.6 million originating in ~~2010.~~2010, and $122.0 million originating in 2011. The federal NOL carryforwards expire in years 2023 to ~~2030.~~2031.

In addition, Great Plains Energy also had deferred tax benefits of ~~$56.2~~$70.6 million and ~~$54.2~~$56.2 million related to state NOLs as of December 31, ~~2010~~2011 and ~~2009,~~2010, respectively. Approximately ~~$49.4~~$49.9 million and ~~$49.9~~$49.4 million at December 31, ~~2010~~2011 and ~~2009,~~2010, respectively, were acquired in the GMO acquisition. Management does not expect to utilize ~~$25.7~~$23.2 million of NOLs in state tax jurisdictions where the Company does not expect to operate in the future. Therefore, a valuation allowance has been provided against ~~$25.7~~$23.2 million of state tax benefits.

Valuation Allowances

Great Plains Energy is required to assess the ultimate realization of deferred tax assets using a “more likely than not” assessment threshold. This assessment takes into consideration tax planning strategies within Great Plains Energy’s control. As a result of this assessment, Great Plains Energy has established a partial valuation allowance for federal and state tax NOL carryforwards, and tax credit carryforwards.

126

During 2011 and 2010, $2.7 million and ~~2009,~~ $3.2 million, respectively, of tax benefit ~~and $6.5 million of tax expense, respectively, on continuing operations~~ was recorded ~~and~~in continuing operations. These adjustments are primarily ~~relates~~related to a portion of the valuation allowance against federal and state

~~131~~

NOL carryforwards. The remaining valuation allowances against federal and state NOL carryforwards and tax credit carryforwards were acquired in the GMO acquisition and were recorded as a part of the purchase accounting entries impacting goodwill.

Uncertain Tax Positions

At December 31, ~~2010~~2011 and ~~2009,~~2010, Great Plains Energy had ~~$42.0~~$24.0 million and ~~$51.4~~$42.0 million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $11.8 million and $17.3 million at December 31, 2011 and 2010, ~~and 2009, is~~respectively, are expected to impact the effective tax rate if recognized. The $18.0 million decrease in unrecognized tax benefits in 2011 is primarily due to a decrease of $18.4 million of unrecognized tax benefits related to the settlement of the IRS audit for Great Plains Energy’s 2006-2008 tax years. The $18.4 million tax benefit recognized related to the 2006-2008 audit was offset by an increase of $16.4 million in deferred income tax liabilities since a significant portion of the unrecognized tax benefits were related to temporary tax differences, which resulted in an increase to net income of $2.0 million.

At December 31, 2009, Great Plains Energy had $51.4 million of liabilities related to unrecognized tax benefits of which $17.3 million was expected to impact the effective rate if recognized. The $9.4 million decrease in unrecognized tax benefits isin 2010 was primarily due to a decrease of $8.6 million of unrecognized tax benefits related to the sale of certain GMO property during 2010.

At December 31, ~~2008, Great Plains Energy~~2011 and 2010, KCP&L had $97.3 million of liabilities related to unrecognized tax benefits of which $80.2 million is expected to impact the effective rate if recognized. The $45.9 million decrease in unrecognized tax benefits in 2009 was primarily due to a decrease of unrecognized tax benefits of $74.5 million related to the Joint Committee on Taxation approval of the IRS audit for GMO’s 2003-2004 tax years, offset by an increase of $11.3 million of unrecognized tax benefits related to prior year tax positions taken on GMO tax returns, and a $20.5 million increase of unrecognized tax benefits related to Great Plains Energy consolidated 2008 and 2009 tax years. The tax benefits recognized related to the 2003-2004 IRS audit were also offset by an increase in valuation allowance for federal and state net operating losses of $56.0$8.7 million and ~~a reduction in deferred income tax assets of $2.5 million, which resulted in an increase to net income of $16.0 million in 2009 related to the 2003-2004 IRS audit.~~

~~At December 31, 2010 and 2009, KCP&L had~~ $19.1 ~~and $20.9~~ million, respectively, of liabilities related to unrecognized tax benefits. Of these amounts, $0.2 million and $0.3 million at December 31, 2011 and 2010, ~~and $0.4 million at December 31, 2009,~~respectively, are expected to impact the effective tax rate if recognized. The ~~$1.8~~$10.4 million decrease in unrecognized tax benefits in 2011 is primarily due to a ~~$2.6~~decrease of $12.1 million ~~decrease as a result of~~related to the settlements of the IRS audit for ~~the~~ Great Plains ~~Energy consolidated 2005~~Energy’s 2006-2008 tax ~~year.~~years. The tax benefit recognized related to the 2006-2008 audit was offset by an increase of deferred income tax liabilities which resulted in an insignificant impact to net income. At December 31, ~~2008,~~2009, KCP&L had ~~$17.6~~$20.9 million of liabilities related to unrecognized tax benefits of which ~~$1.1~~$0.4 million iswas expected to impact the effective rate if recognized.

The following table reflects activity for Great Plains Energy and KCP&L related to the liability for unrecognized tax benefits.


	Great Plains Energy										KCP&L									Great Plains Energy									KCP&L
		2010			2009			2008			2010			2009			2008			2011			2010			2009			2011			2010			2009
		(millions)																		(millions)
Balance at January 1	Balance at January 1	$	51.4		$	97.3		$	21.9		$	20.9		$	17.6		$	19.6		$	42.0		$	51.4		$	97.3		$	19.1		$	20.9		$	17.6
Additions for current year tax positions	Additions for current year tax positions		2.7			13.2			5.3			1.3			3.9			3.8			1.4			2.7			13.2			-			1.3			3.9
Additions for prior year tax positions	Additions for prior year tax positions		2.1			8.2			2.6			1.5			3.0			2.6			2.4			2.1			8.2			2.3			1.5			3.0
Additions for GMO prior year tax positions	Additions for GMO prior year tax positions		-			11.6			77.0			-			-			-			-			-			11.6			-			-			-
Reductions for prior year tax positions	Reductions for prior year tax positions		(10.6	)		(1.3	)		(0.8	)		(1.6	)		(0.8	)		(0.7	)		(20.9	)		(10.6	)		(1.3	)		(12.6	)		(1.6	)		(0.8	)
Settlements	Settlements		(3.8	)		(76.7	)		(8.5	)		(2.9	)		(2.2	)		(7.5	)		-			(3.8	)		(76.7	)		-			(2.9	)		(2.2	)
Statute expirations	Statute expirations		(0.3	)		(0.7	)		(0.2	)		(0.1	)		(0.6	)		(0.2	)		(0.7	)		(0.3	)		(0.7	)		(0.1	)		(0.1	)		(0.6	)
Foreign currency translation adjustments	Foreign currency translation adjustments		0.5			(0.2	)		-			-			-			-			(0.2	)		0.5			(0.2	)		-			-			-
Balance at December 31	Balance at December 31	$	42.0		$	51.4		$	97.3		$	19.1		$	20.9		$	17.6		$	24.0		$	42.0		$	51.4		$	8.7		$	19.1		$	20.9

Great Plains Energy and KCP&L recognize interest ~~accrued~~ related to unrecognized tax benefits in interest expense and penalties in non-operating expenses. At December 31, 2011, 2010 ~~2009~~ and ~~2008,~~2009, accrued interest related to unrecognized tax benefits for Great Plains Energy was $5.7 million, $6.7 million ~~$5.9 million~~ and ~~$2.6~~$5.9 million, respectively. Amounts accrued for penalties with respect to unrecognized tax benefits was $1.1 million at December 31, 2011, 2010 and 2009. In 2011, Great Plains Energy recognized a decrease of $0.9 million of interest expense related to unrecognized tax benefits. In 2010 and 2009, Great Plains Energy recognized an increase of ~~$0.5 million and $1.4 million, respectively, of~~ interest expense related to unrecognized tax ~~benefits. The remaining increase in accrued interest~~

benefits of $0.5 million and $1.4 million, respectively.

~~132~~127

and the penalties of $1.1 million were primarily associated with prior year GMO tax return positions identified and recorded to goodwill. In 2008, Great Plains Energy recognized a reduction in interest expense of $6.6 million.

KCP&L had accrued interest related to unrecognized tax benefits of $0.2 million, $1.4 million ~~at December 31, 2010~~ and $1.7 million, at December 31, 2011, 2010 and 2009, ~~and 2008.~~respectively. Amounts accrued for penalties with respect to unrecognized tax benefits for KCP&L are insignificant. In 2011 and 2010, KCP&L recognized a reduction of $1.2 million and $0.3 million of interest ~~expense. In 2008, KCP&L recognized a reduction of $1.7 million of interest expense.~~expense, respectively.

The IRS is currently auditing Great Plains Energy and its subsidiaries for the ~~2006-2008~~2009-2010 tax ~~years and the Company is protesting an audit assessment by the Canada Revenue Authority (CRA) against a former GMO subsidiary for the 2002 tax year.~~years. The Company estimates that it is reasonably possible that ~~$18.2~~$4.7 million for Great Plains Energy and ~~$12.2~~$0.2 million for KCP&L of unrecognized tax benefits may be recognized in the next twelve months due to statute expirations or settlement agreements with tax authorities.

Great Plains Energy files a consolidated federal income tax return as well as unitary and combined income tax returns in several state jurisdictions with Kansas and Missouri being the most significant. The Company also files separate company returns in Canada and certain other states.

~~22.~~21.

SEGMENTS AND RELATED INFORMATION

~~Great Plains Energy~~

Great Plains Energy has one reportable segment based on its method of internal reporting, which ~~generally~~ segregates reportable segments based on products and services, management responsibility and regulation. The one reportable business segment is electric utility, consisting of KCP&L and GMO’s regulated utility operations. Other includes GMO activity other than its regulated utility operations, ~~Strategic Energy discontinued operations,~~ unallocated corporate charges, consolidating entries and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing-related activities. The summary of significant accounting policies applies to the reportable segment. For segment reporting, the segment’s income taxes include the effects of allocating holding company tax benefits prior to July 14, 2008. GMO is only included for periods subsequent to the July 14, 2008, date of acquisition. Segment performance is evaluated based on net income attributable to Great Plains Energy.

The following tables reflect summarized financial information concerning Great Plains Energy’s reportable segment.


	Electric						Great Plains			Electric						Great Plains
2010	Utility			Other			Energy
2011										Utility			Other			Energy
	(millions)									(millions)
Operating revenues	$	2,255.5		$	-		$	2,255.5		$	2,318.0		$	-		$	2,318.0
Depreciation and amortization		(331.6	)		-			(331.6	)		(273.1	)		-			(273.1	)
Interest charges		(143.1	)		(41.7	)		(184.8	)		(176.9	)		(41.5	)		(218.4	)
Income tax (expense) benefit		(123.3	)		24.3			(99.0	)		(109.3	)		24.5			(84.8	)
Loss from equity investments		-			(1.0	)		(1.0	)
Net income (loss) attributable to Great Plains Energy		235.3			(23.6	)		211.7			199.9			(25.5	)		174.4


	Electric						Great Plains
2010	Utility			Other			Energy
	(millions)
Operating revenues	$	2,255.5		$	-		$	2,255.5
Depreciation and amortization		(331.6	)		-			(331.6	)
Interest charges		(143.1	)		(41.7	)		(184.8	)
Income tax (expense) benefit		(123.3	)		24.3			(99.0	)
Net income (loss) attributable to Great Plains Energy		235.3			(23.6	)		211.7

~~133~~128


	Electric						Great Plains			Electric						Great Plains
2009	Utility			Other			Energy			Utility			Other			Energy
	(millions)									(millions)
Operating revenues	$	1,965.0		$	-		$	1,965.0		$	1,965.0		$	-		$	1,965.0
Depreciation and amortization		(302.2	)		-			(302.2	)		(302.2	)		-			(302.2	)
Interest charges		(151.0	)		(29.9	)		(180.9	)		(151.0	)		(29.9	)		(180.9	)
Income tax (expense) benefit		(63.6	)		34.1			(29.5	)		(63.6	)		34.1			(29.5	)
Loss from equity investments		-			(0.4	)		(0.4	)
Discontinued operations		-			(1.5	)		(1.5	)		-			(1.5	)		(1.5	)
Net income (loss) attributable to Great Plains Energy		157.8			(7.7	)		150.1			157.8			(7.7	)		150.1

	Exact name of registrant as specified in its charter,
Commission	state of incorporation, address of principal	I.R.S. Employer
File Number	executive offices and telephone number	Identification Number

001-32206	GREAT PLAINS ENERGY INCORPORATED	43-1916803
	(A Missouri Corporation)
	1200 Main Street
	Kansas City, Missouri 64105
	(816) 556-2200

000-51873	KANSAS CITY POWER & LIGHT COMPANY	44-0308720
	(A Missouri Corporation)
	1200 Main Street
	Kansas City, Missouri 64105
	(816) 556-2200

Registrant	Title of each class
Great Plains Energy Incorporated	Cumulative Preferred Stock par value $100 per share	3.80%
	Cumulative Preferred Stock par value $100 per share	4.50%
	Cumulative Preferred Stock par value $100 per share	4.35%
	Common Stock without par value
	Corporate Units

	TABLE OF CONTENTS
			Page
			Number
	Cautionary Statements Regarding Forward-Looking Information		3
	Glossary of Terms		4
	PART I
Item 1.	Business		6
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		22
Item 2.	Properties		2223
Item 3.	Legal Proceedings		2324
Item 4.	~~(Removed and Reserved)~~Mine Safety Disclosures		2324
	PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters
		and Issuer Purchases of Equity Securities	2425
Item 6.	Selected Financial Data		2526
Item 7.	Management's Discussion and Analysis of Financial Condition
		and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		5052
Item 8.	Financial Statements and Supplementary Data		5355
Item 9.	Changes in and Disagreements With Accountants on Accounting
		and Financial Disclosure	~~139~~134
Item 9A.	Controls and Procedures		~~139~~134
Item 9B.	Other Information		~~143~~138
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		~~143~~138
Item 11.	Executive Compensation		~~144~~138
Item 12.	Security Ownership of Certain Beneficial Owners and Management
		and Related Stockholder Matters	~~144~~139
Item 13.	Certain Relationships and Related Transactions, and Director Independence		~~145~~139
Item 14.	Principal Accounting Fees and Services		~~145~~140
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		~~147~~141


			Year First
			Assumed
			an Officer
Name	Age	Current Position(s)	Position

Michael J. Chesser (a)	63	Chairman of the Board and Chief Executive Officer – Great Plains Energy and KCP&L	2003
Terry Bassham (b)	51	President and Chief Operating Officer – Great Plains Energy and KCP&L	2005
James C. Shay (c)	48	Senior Vice President – Finance and Strategic Development and Chief Financial Officer – Great Plains Energy and KCP&L	2010
Kevin E. Bryant (d)	36	Vice President – Investor Relations and Treasurer – Great Plains Energy and KCP&L	2006
Charles A. Caisley (e)	39	Vice President – Marketing and Public Affairs – Great Plains Energy and KCP&L	2011
Michael L. Deggendorf (f)	50	Senior Vice President – Delivery – KCP&L	2005
Ellen E. Fairchild (g)	50	Vice President, Corporate Secretary and Chief Compliance Officer – Great Plains Energy and KCP&L	2010
Scott H. Heidtbrink (h)	50	Senior Vice President – Supply – KCP&L	2008
Heather A. Humphrey (i)	41	General Counsel and Senior Vice President – Human Resources – Great Plains Energy and KCP&L	2010
Lori A. Wright (j)	49	Vice President - Business Planning and Controller – Great Plains Energy and KCP&L	2002

Abbreviation or Acronym		Definition

AFUDC		Allowance for Funds Used During Construction
ARO		Asset Retirement Obligation
BART		Best available retrofit technology
Board		Great Plains Energy Board of Directors
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
Clean Air Act		Clean Air Act Amendments of 1990
CO2		Carbon dioxide
Collaboration Agreement		Agreement among KCP&L, the Sierra Club and the Concerned Citizens of Platte County
Company		Great Plains Energy Incorporated and its subsidiaries
Companies		Great Plains Energy Incorporated and its consolidated subsidiaries and KCP&L and its consolidated subsidiaries
CSAPR		Cross-State Air Pollution Rule
DOE		Department of Energy
EBITDA		Earnings before interest, income taxes, depreciation and amortization
ECA		Energy Cost Adjustment
EGU		Electric steam generating unit
EIRR		Environmental Improvement Revenue Refunding
EPA		Environmental Protection Agency
EPS		Earnings per common share
ERISA		Employee Retirement Income Security Act of 1974, as amended
FAC		Fuel Adjustment Clause
~~FASB~~		~~Financial Accounting Standards Board~~
FERC		The Federal Energy Regulatory Commission
FGIC		Financial Guaranty Insurance Company
FSS		Forward Starting Swaps
GAAP		Generally Accepted Accounting Principles
GMO		KCP&L Greater Missouri Operations Company, a wholly owned subsidiary of Great Plains Energy ~~as of July 14, 2008~~
Great Plains Energy		Great Plains Energy Incorporated and its subsidiaries
ISO		Independent System Operator
KCC		The State Corporation Commission of the State of Kansas
KCP&L		Kansas City Power & Light Company, a wholly owned subsidiary of Great Plains Energy
KDHE		Kansas Department of Health and Environment
~~KLT Inc.~~kV		~~KLT Inc., a wholly owned subsidiary of Great Plains Energy~~Kilovolt
KW		Kilowatt
kWh		Kilowatt hour
L&P		St. Joseph Light & Power, a division of GMO
MACT		Maximum achievable control technology
MATS		Mercury and Air Toxics Standards
MD&A		Management’s Discussion and Analysis of Financial Condition and
		Results of Operations
MDNR		Missouri Department of Natural Resources
MEEIA		Missouri Energy Efficiency Investment Act
MGP		Manufactured gas plant

~~MISO~~Abbreviation or Acronym		~~Midwest Independent Transmission System Operator, Inc.~~Definition

MPS Merchant		MPS Merchant Services, Inc., a wholly owned subsidiary of GMO
MPSC		Public Service Commission of the State of Missouri

~~Abbreviation or Acronym~~		~~Definition~~

MW		Megawatt
MWh		Megawatt hour
NAAQS		National Ambient Air Quality Standard
NERC		North American Electric Reliability Corporation
NEIL		Nuclear Electric Insurance Limited
NOL		Net operating loss
NOx		Nitrogen oxide
NPNS		Normal purchases and normal sales
NRC		Nuclear Regulatory Commission
OCI		Other Comprehensive Income
PCB		Polychlorinated biphenyls
ppm		Parts per million
PRB		Powder River Basin
QCA		Quarterly Cost Adjustment
Receivables Company		Kansas City Power & Light Receivables Company, a wholly owned subsidiary of KCP&L
RTO		Regional Transmission Organization
SCR		Selective catalytic reduction
SEC		Securities and Exchange Commission
SERP		Supplemental Executive Retirement Plan
~~Services~~		~~Great Plains Energy Services Incorporated, a wholly owned subsidiary of~~ ~~Great Plains Energy~~
SO2		Sulfur dioxide
SPP		Southwest Power Pool, Inc.
~~Strategic Energy~~		~~Strategic Energy, L.L.C.~~
Syncora		Syncora Guarantee Inc.
~~T - Lock~~		~~Treasury Lock~~
WCNOC		Wolf Creek Nuclear Operating Corporation
Westar		Westar Energy, Inc., a Kansas utility company
Wolf Creek		Wolf Creek Generating Station


							Fuel cost in cents per										Fuel cost in cents per
	Fuel Mix (a)						net kWh generated				Fuel Mix (a)						net kWh generated
	Estimated			Actual			Estimated		Actual		Estimated			Actual			Estimated		Actual
Fuel	2011			2010			2011		2010		2012			2011			2012		2011
Coal		82	%		80	%		1.89		1.69		80	%		83	%		2.06		2.06
Nuclear		15			17			0.69		0.65		15			13			0.71		0.72
Natural gas and oil		1			2			7.34		8.95		3			2			5.45		7.82
Wind		2			1			-		-		2			2			-		-
Total Generation		100	%		100	%		1.80		1.65		100	%		100	%		1.95		1.92
(a) Fuel mix based on percent of net MWhs generated.	(a) Fuel mix based on percent of net MWhs generated.										(a) Fuel mix based on percent of net MWhs generated.

(d)	Mr. Bryant was appointed Vice President – Investor Relations and Treasurer of Great Plains Energy, KCP&L and GMO in 2011. He was Vice President – Strategy and Risk Management of KCP&L and GMO (2011) and Vice President – Energy Solutions (2006-2011) of KCP&L and GMO.
(e)	Mr. Caisley was appointed Vice President – Marketing and Public Affairs of Great Plains Energy, KCP&L and GMO in 2011. He was Senior Director of Public Affairs (2008-2011) and Director of Governmental Affairs (2007-2008). Prior to that, he was the president of the Missouri Energy Development Association (2005-2007).

(f)	Mr. Deggendorf was appointed Senior Vice President – Delivery of KCP&L and GMO in 2008. He was Vice President – Public Affairs of Great Plains Energy (2005-2008) and Senior Director, Energy Solutions (2002-2005) of KCP&L.
(g)	Ms. Fairchild was appointed Vice President, Corporate Secretary and Chief Compliance Officer of Great Plains Energy, KCP&L and GMO in 2010. She was Senior Director of Investor Relations and Assistant Secretary (2010) and Director of Investor Relations (2008-2010) of Great Plains Energy, KCP&L and GMO. Prior to that, she was an associate at Hagen and Partners (2005-2007), a public relations firm.

(h)	Mr. Heidtbrink was appointed Senior Vice President – Supply of KCP&L and GMO in 2009. He was Senior Vice President – Corporate Services of KCP&L and GMO (2008), and Vice President – Power Generation & Energy Resources (2006-2008) of GMO.
(i)	Ms. Humphrey was appointed General Counsel and Vice President – Human Resources of Great Plains Energy, KCP&L and GMO in 2010. She was Senior Director of Human Resources and Interim General Counsel of Great Plains Energy, KCP&L and GMO (2010) and Managing Attorney of KCP&L (2007-2010). Prior to that, she was a shareholder of the law firm of Shughart Thomson & Kilroy (1996-2006).


	Final Cost			Previous Estimate
	Estimate Range			Range			Change
	(millions)
Great Plains Energy's 73% share of Iatan No. 2	$ 1,203	-	$ 1,218	$ 1,222	-	$ 1,251	$ (19)	-	$ (33)
KCP&L's 55% share of Iatan No. 2	905	-	917	919	-	941	(14)	-	(24)


					Great
December 31, 2009	KCP&L		GMO		Plains Energy
Regulatory Assets	(millions)
Taxes recoverable through future rates	$	77.6	$	22.9	$	100.5
Loss on reacquired debt		5.3		0.3		5.6
Cost of removal		7.9		-		7.9
Asset retirement obligations		23.8		11.9		35.7
Pension settlements		13.5		-		13.5
Pension and post-retirement costs		395.0		84.5		479.5
Deferred customer programs		35.6		7.1		42.7
Rate case expenses		7.4		1.5		8.9
Skill set realignment costs		6.1		-		6.1
Fuel adjustment clauses		0.7		47.5		48.2
Acquisition transition costs		29.3		22.2		51.5
St. Joseph Light & Power acquisition		-		3.1		3.1
Storm damage		-		4.8		4.8
Derivative instruments		-		2.1		2.1
Iatan No. 1 and Common facilities depreciation and carrying costs		4.6		1.4		6.0
Other		5.3		0.8		6.1
Total	$	612.1	$	210.1	$	822.2
Regulatory Liabilities
Emission allowances	$	86.2	$	0.8	$	87.0
Asset retirement obligations		33.4		-		33.4
Pension		-		34.0		34.0
Cost of removal		-		62.5		62.5
Other		7.3		13.6		20.9
Total	$	126.9	$	110.9	$	237.8


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)

	Real		Hedge			Limited
Description	Estate		Funds			Partnerships		Total
	(millions)
Balance January 1, 2010	$	26.8	$	2.4		$	0.1	$	29.3
Actual return on plan assets
Relating to assets still held		2.5		(0.2	)		-		2.3
Relating to assets sold		-		(0.7	)		-		(0.7	)
Purchase, sales, and settlements		1.0		6.9			-		7.9
Transfers in and/or out of Level 3		-		-			-		-
Balance December 31, 2010	$	30.3	$	8.4		$	0.1	$	38.8


				Fair Value Measurements Using
Description		December 31 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
	Equity securities	$	1.4	$	1.4	$	-	$	-
	Fixed income
	U.S. Treasury		14.3		14.3		-		-
	U.S. Agency, state and local obligations		27.2		-		27.2		-
	U.S. corporate bonds (a)		14.8		-		14.8		-
	Foreign corporate bonds		1.5		-		1.5		-
	Mutual funds		0.2		0.2		-		-
	Total	$	59.4	$	15.9	$	43.5	$	-
	Cash and cash equivalents - money market funds		18.0
	Total Other Post-Retirement Benefit Plans	$	77.4

(a)	This category is comprised of $12.7 million of corporate bonds, $0.6 million of collateralized mortgage obligations and $1.5 million
	of other asset-backed securities.


				Fair Value Measurements Using
Description		December 31 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(millions)
Other Post-Retirement Benefit Plans
	Fixed income
	U.S. Treasury	$	12.1	$	12.1	$	-	$	-
	U.S. Agency, state and local obligations		22.2		-		22.2		-
	U.S. corporate bonds (a)		11.4		-		11.4		-
	Foreign corporate bonds		1.0				1.0
	Mutual funds		0.1		0.1		-		-
	Total	$	46.8	$	12.2	$	34.6	$	-
	Cash and cash equivalents - money market funds		19.0
	Total Other Post-Retirement Benefit Plans	$	65.8

(a)	This category is comprised of $9.2 million of corporate bonds, $0.9 million of collateralized mortgage obligations and $1.3 million
	of other asset-backed securities.


	Performance	Grant Date
	Shares	Fair Value*
Beginning balance	294,641	$ 13.62
Performance adjustment	(21,674)
Granted	231,598	23.37
Earned	(8,433)	10.87
Forfeited	(64,348)	20.54
Ending balance	431,784	18.01
* weighted-average


	Nonvested	Grant Date	Nonvested			Grant Date
	Restricted Stock	Fair Value*	Restricted Stock			Fair Value*
Beginning balance	612,587	$ 20.24		406,657		$	16.23
Granted and issued	130,137	17.80		182,385			19.03
Vested	(291,787)	25.00		(149,688	)		17.29
Forfeited	(44,280)	17.99		(53,171	)		17.25
Ending balance	406,657	16.23		386,183			17.06
* weighted-average			* weighted-average


		Exercise
Stock Options	Shares	Price*
Beginning balance	244,610	$ 36.73
Exercised	(917)	9.21
Forfeited or expired	(44,912)	55.97
Outstanding and exercisable at December 31, 2010	198,781	32.51
* weighted-average

Outstanding and Exercisable Options
		Weighted Average
		Remaining	Weighted
Exercise	Number of	Contractual Life	Average
Price Range	Shares	in Years	Exercise Price
$23.91 - $27.73	189,852	1.0	$ 24.44
$181.11	3,998	0.1	181.11
$221.82 - $251.86	4,931	0.3	222.48
Total	198,781	0.9	32.51


	Share	Grant Date	Share		Grant Date
	Units	Fair Value*	Units		Fair Value*
Beginning balance	21,443	$ 22.36		39,063	$	20.04
Issued	17,620	17.21		15,168		20.57
Ending balance	39,063	20.04		54,231		20.19
* weighted-average			* weighted-average


		December 31								December 31
	Year Due	2010			2009			Year Due		2011			2010
KCP&L		(millions)								(millions)
General Mortgage Bonds
4.90%* EIRR bonds	2012-2035	$	158.8		$	158.8
7.15% Series 2009A (8.59% rate**)	2019		400.0			400.0
4.87% EIRR bonds(a)(b)									2012-2035	$	119.3		$	158.8
7.15% Series 2009A (8.59% rate)(c)									2019		400.0			400.0
4.65% EIRR Series 2005	2035		50.0			50.0			2035		50.0			50.0
5.125% EIRR Series 2007A-1	2035		63.3			63.3
2.625% EIRR Series 2007A-2	2035		10.0			10.0
EIRR Series 2007A-1(d)									2035		-			63.3
EIRR Series 2007A-2(d)									2035		-			10.0
5.375% EIRR Series 2007B	2035		73.2			73.2			2035		73.2			73.2
Senior Notes
6.50% Series	2011		150.0			150.0					-			150.0
5.85% Series (5.72% rate**)	2017		250.0			250.0
6.375% Series (7.49% rate**)	2018		350.0			350.0
6.05% Series (5.78% rate**)	2035		250.0			250.0
EIRR Bonds
4.90% Series 2008	2038		23.4			23.4
5.85% Series (5.72% rate)(c)									2017		250.0			250.0
6.375% Series (7.49% rate)(c)									2018		350.0			350.0
6.05% Series (5.78% rate)(c)									2035		250.0			250.0
5.30% Series									2041		400.0			-
EIRR bonds 4.90% Series 2008									2038		23.4			23.4
Other	2011-2018		3.3			3.5			2012-2018		2.9			3.3
Current maturities			(150.3	)		(0.2	)				(12.7	)		(150.3	)
Unamortized discount			(2.0	)		(2.1	)				(4.2	)		(2.0	)
Total KCP&L			1,629.7			1,779.9

Total KCP&L excluding current maturities											1,901.9			1,629.7
Other Great Plains Energy
GMO First Mortgage Bonds
9.44% Series	2011-2021		12.4			13.5
GMO First Mortgage Bonds 9.44% Series									2012-2021		11.2			12.4
GMO Pollution Control Bonds
5.85% SJLP Pollution Control	2013		5.6			5.6			2013		5.6			5.6
0.298%*** Wamego Series 1996	2026		7.3			7.3
0.650%*** State Environmental 1993	2028		5.0			5.0
0.164% Wamego Series 1996(e)									2026		7.3			7.3
0.353% State Environmental 1993(e)									2028		5.0			5.0
GMO Senior Notes
7.95% Series	2011		137.3			137.3					-			137.3
7.75% Series	2011		197.0			197.0					-			197.0
11.875% Series	2012		500.0			500.0			2012		500.0			500.0
8.27% Series	2021		80.9			80.9			2021		80.9			80.9
Fair Value Adjustment			49.9			84.5					16.3			49.9
GMO Medium Term Notes
7.16% Series	2013		6.0			6.0			2013		6.0			6.0
7.33% Series	2023		3.0			3.0			2023		3.0			3.0
7.17% Series	2023		7.0			7.0			2023		7.0			7.0
Great Plains Energy 2.75% Senior Notes (3.67% rate**)	2013		250.0			-
Great Plains Energy 6.875% Senior Notes (7.33% rate**)	2017		100.0			100.0
Great Plains Energy 2.75% Senior Notes (3.67% rate)(c)									2013		250.0			250.0
Great Plains Energy 6.875% Senior Notes (7.33% rate)(c)									2017		100.0			100.0
Great Plains Energy 10.00% Equity Units Subordinated Notes	2042		287.5			287.5			2012		287.5			287.5
Great Plains Energy 4.85% Senior Notes (7.34% rate)(c)									2021		350.0			-
Current maturities			(335.4	)		(1.1	)				(788.7	)		(335.4	)
Unamortized discount			(0.5	)		(0.4	)				(0.7	)		(0.5	)
Total Great Plains Energy excluding current maturities		$	2,942.7		$	3,213.0				$	2,742.3		$	2,942.7
* Weighted-average interest rates at December 31, 2010
** Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
*** Variable rate
(a) Weighted-average interest rates at December 31, 2011								(a) Weighted-average interest rates at December 31, 2011
(b) December 31, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by KCP&L								(b) December 31, 2011, does not include $39.5 million EIRR Series 1993B bonds because the bonds have been repurchased and are held by KCP&L
(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments								(c) Rate after amortizing gains/losses recognized in OCI on settlements of interest rate hedging instruments
(d) December 31, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have								(d) December 31, 2011, does not include $63.3 million EIRR Series 2007 A-1and $10.0 million EIRR Series 2007 A-2 bonds because the bonds have
been repurchased and are held by KCP&L								been repurchased and are held by KCP&L
(e) Variable rate								(e) Variable rate


	Electric Utility								Great Plains			Electric							Great Plains
	Electric Utility		Other		Eliminations				Energy			Utility		Other		Eliminations			Energy
2011												(millions)
Assets												$	9,483.4	$	51.9	$	(417.3	)	$	9,118.0
Capital expenditures													456.6		-		-			456.6
2010	(millions)
Assets	$	9,152.7	$	66.3		$	(400.8	)		$	8,818.2	$	9,152.7	$	66.3	$	(400.8	)	$	8,818.2
Capital expenditures		618.1		-			-				618.1		618.1		-		-			618.1
2009
Assets	$	8,765.3	$	152.5		$	(435.0	)		$	8,482.8	$	8,765.3	$	152.5	$	(435.0	)	$	8,482.8
Capital expenditures		841.3		-			-				841.3		841.3		-		-			841.3
2008
Assets	$	8,161.9	$	141.7		$	(434.3	)		$	7,869.3
Capital expenditures (a)		1,023.7		1.2			-				1,024.9

(a) Includes capital expenditures from discontinued operations of $0.8 million.

Great Plains Energy
	Wolf Creek			LaCygne			Iatan No. 1			Iatan No. 2			Iatan			Jeffrey
	Unit			Units			Unit			Unit			Common			Energy Center
	(millions, except MW amounts)
Great Plains Energy's share		47	%		50	%		88	%		73	%		79	%		8	%

Utility plant in service	$	1,423.7		$	410.5		$	638.9		$	1,282.4		$	326.8		$	151.1
Accumulated depreciation		778.2			298.0			239.9			58.9			16.1			74.8
Nuclear fuel, net		79.2			-			-			-			-			-
Construction work in progress		75.3			48.1			23.4			8.0			23.3			6.4
2011 accredited capacity-MWs		560			709			621			618		NA				173


Great Plains Energy
	Wolf Creek			La Cygne			Iatan No. 1			Iatan No. 2			Iatan			Jeffrey
	Unit			Units			Unit			Unit			Common			Energy Center
	(millions, except MW amounts)
Great Plains Energy's share		47	%		50	%		88	%		73	%		79	%		8	%

Utility plant in service	$	1,473.8		$	493.6		$	667.9		$	1,293.0		$	364.4		$	158.4
Accumulated depreciation		776.3			303.1			252.8			270.0			30.4			75.5
Nuclear fuel, net		76.6			-			-			-			-			-
Construction work in progress		39.4			79.1			6.5			5.9			30.2			5.3
2012 accredited capacity-MWs		547			711			620			641		NA				174

Fee Category	2011		2010
Audit Fees	$	1,125,215	$	1,098,722
Audit-Related Fees		70,750		104,169
Tax Fees		231,643		112,058
All Other Fees		91,975		-
Total Fees	$	1,519,583	$	1,314,949

Financial Statements
Great Plains Energy		Page No.
a.	Consolidated Statements of Income for the years ended December 31, 2011, 2010 ~~2009~~ and ~~2008~~ 2009	5456
b.	Consolidated Balance Sheets - December 31, ~~2010~~2011 and ~~2009~~ 2010	5557
c.	Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 ~~2009~~ and ~~2008~~ 2009	5759
d.	Consolidated Statements of Common Shareholders’ Equity and Noncontrolling Interest for the years ended December 31, 2011, 2010 ~~2009~~ and ~~2008~~ 2009	5860
e.	Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 ~~2009~~ and ~~2008~~ 2009	5961
f.	Notes to Consolidated Financial Statements	6668
g.	Report of Independent Registered Public Accounting Firm	~~137~~132

KCP&L
h.	Consolidated Statements of Income for the years ended December 31, 2011, 2010 ~~2009~~ and ~~2008~~ 2009	60 62
i.	Consolidated Balance Sheets - December 31, ~~2010~~2011 and ~~2009~~ 2010	6163
j.	Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 ~~2009~~ and ~~2008~~ 2009	6365
k.	Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, 2011, 2010 ~~2009~~ and ~~2008~~ 2009	6466
l.	Consolidated Statements of Comprehensive Income for the years ended December 31, 2011, 2010 ~~2009~~ and ~~2008~~ 2009	6567
m.	Notes to Consolidated Financial Statements	6668
n.	Report of Independent Registered Public Accounting Firm	~~138~~133

Financial Statement Schedules
	Great Plains Energy
a.	Schedule I – Parent Company Financial Statements	157

b.	Schedule II – Valuation and Qualifying Accounts and Reserves	~~164~~160
	KCP&L
c.	Schedule II – Valuation and Qualifying Accounts and Reserves	~~165~~161

Exhibit Number		Description of Document	Registrant
2.1	*	Agreement and Plan of Merger among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of February 6, 2007 (Exhibit 2.1 to Form 8-K filed on February 8, 2007).	Great Plains Energy
2.2	*	Mutual Notice of Extension among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of January 31, 2008 (Exhibit 2.1.2 to Form 10-K for the year ended December 31, 2007).	Great Plains Energy
2.3	*	Mutual Notice of Extension among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp., and Black Hills Corporation dated as of April 29, 2008 (Exhibit 10.1 to Form 8-K filed on April 30, 2008).	Great Plains Energy
3.1	*	Articles of Incorporation of Great Plains Energy Incorporated, as amended effective May 7, 2009 (Exhibit 3.1.1 to Form 10-Q for the quarter ended March 31, 2009).	Great Plains Energy
3.2	*	By-laws of Great Plains Energy Incorporated, as amended May 4, 2010 (Exhibit 3.1 to Form 8-K filed on May 5, 2010).	Great Plains Energy
3.3	*	Restated Articles of ~~Incorporation~~Consolidation of Kansas City Power & Light Company, restated as of October 26, 2010. (Exhibit 3.3 to Form 10-K for the year ended December 31, 2010)	KCP&L
3.4	*	By-laws of Kansas City Power & Light Company, as amended April 1, 2008 (Exhibit 3.2 to Form 8-K filed on April 7, 2008).	KCP&L
4.1	*	Indenture, dated June 1, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Trustee (Exhibit 4.4 to Form 8-A/A filed on June 14, 2004).	Great Plains Energy
4.2	*	First Supplemental Indenture, dated June 14, 2004, between Great Plains Energy Incorporated and BNY Midwest Trust Company, as Trustee (Exhibit 4.5 to Form 8-A/A filed on June 14, 2004).	Great Plains Energy
4.3	*	Second Supplemental Indenture dated as of September 25, 2007, between Great Plains Energy Incorporated and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on September 26, 2007).	Great Plains Energy

4.4	*	Third Supplemental Indenture dated as of August 13, 2010 between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on August 13, 2010).	Great Plains Energy
4.5	*	Fourth Supplemental Indenture dated as of May 19, 2011 between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as Trustee (Exhibit 4.1 to Form 8-K filed on May 19, 2011).	Great Plains Energy
4.6	*	Subordinated Indenture dated as of May 18, 2009 between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on May 19, 2009).	Great Plains Energy

~~4.6~~ 4.7	*	Supplemental Indenture No. 1 dated as of May 18, 2009 between Great Plains Energy Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K filed on May 19, 2009).	Great Plains Energy
~~4.7~~4.8	*	Purchase Contract and Pledge Agreement dated as of May 18, 2009 among Great Plains Energy Incorporated, The Bank of New York Mellon Trust Company, N.A., as purchase contract agent and The Bank of New York Mellon Trust Company, N.A., as collateral agent, custodial agent and securities intermediary (Exhibit 4.3 to Form 8-K filed on May 19, 2009).	Great Plains Energy
~~4.8~~4.9	*	Indenture, dated as of August 24, 2001, between Aquila, Inc. and BankOne Trust Company, N.A., as Trustee (Exhibit 4(d) to Registration Statement on Form S-3 (File No. 333-68400) filed by Aquila, Inc. on August 27, 2001).	Great Plains Energy
~~4.9~~4.10	*	Second Supplemental Indenture, dated as of July 3, 2002, between Aquila, Inc. and BankOne Trust Company, N.A., as Trustee related to 11.875% Senior Notes due July 1, 2012 (Exhibit 4(c) to Form S-4 (File No. 333-100204) filed by Aquila, Inc. on September 30, 2002).	Great Plains Energy
~~4.10~~4.11	*	General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, n.a. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4-bb to Form 10-K for the year ended December 31, 1986).	Great Plains Energy KCP&L
~~4.11~~4.12	*	Fifth Supplemental Indenture dated as of September 15, 1992, to Indenture dated as of December 1, 1986 (Exhibit 4-a to Form 10-Q for the quarter ended September 30, 1992).	Great Plains Energy KCP&L
~~4.12~~4.13	*	Seventh Supplemental Indenture dated as of October 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4-a to Form 10-Q for the quarter ended September 30, 1993).	Great Plains Energy KCP&L

~~4.13~~4.14	*	Eighth Supplemental Indenture dated as of December 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4 to Registration Statement, Registration No. 33-51799).	Great Plains Energy KCP&L
~~4.14~~4.15	*	Eleventh Supplemental Indenture dated as of August 15, 2005, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2005).	Great Plains Energy KCP&L
~~4.15~~4.16	*	Twelfth Supplemental Indenture, dated as of March 1, 2009, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.2 to Form 8-K filed on March 24, 2009).	Great Plains Energy KCP&L

~~4.16~~4.17	*	Thirteenth Supplemental Indenture, dated as of March 1, 2009, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.3 to Form 8-K filed on March 24, 2009).	Great Plains Energy KCP&L
~~4.17~~4.18	*	Fourteenth Supplemental Indenture, dated as of March 1, 2009, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.4 to Form 8-K filed on March 24, 2009).	Great Plains Energy KCP&L
~~4.18~~4.19	*	Fifteenth Supplemental Indenture, dated as of June 30, 2011, to the General Mortgage and Deed of Trust dated as of December 1, 1986, between Kansas City Power & Light Company and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), Trustee (Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 2011).	Great Plains Energy KCP&L
4.20	*	Indenture dated as of December 1, 2000, between Kansas City Power & Light Company and The Bank of New York (Exhibit 4-a to Form 8-K filed on December 18, 2000).	Great Plains Energy KCP&L
~~4.19~~4.21	*	Term sheet for $150 million aggregate principal amount of 6.50% Senior Notes due November 15, 2011 (Exhibit 4-b to Form 8-K filed on November 19, 2001).	Great Plains Energy KCP&L
~~4.20~~4.22	*	Indenture dated March 1, 2002 between The Bank of New York and Kansas City Power & Light Company (Exhibit 4.1.b. to Form 10-Q for the quarter ended March 31, 2002).	Great Plains Energy KCP&L
~~4.21~~4.23	*	Supplemental Indenture No. 1 dated as of November 15, 2005, to Indenture dated March 1, 2002 between The Bank of New York and Kansas City Power & Light Company (Exhibit 4.2.j to Form 10-K for the year ended December 31, 2005).	Great Plains Energy KCP&L

~~4.22~~4.24	*	Indenture dated as of May 1, 2007, between Kansas City Power & Light Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.1 to Form 8-K filed on June 4, 2007).	Great Plains Energy KCP&L
~~4.23~~4.25	*	Supplemental Indenture No. 1 dated as of June 4, 2007 between Kansas City Power & Light Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K filed on June 4, 2007).	Great Plains Energy KCP&L
~~4.24~~4.26	*	Supplemental Indenture No. 2 dated as of March 11, 2008, between Kansas City Power & Light Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.2 to Form 8-K filed on March 11, 2008).	Great Plains Energy KCP&L
4.27	*+	Supplemental Indenture No. 3 dated as of September 20, 2011 between Kansas City Power & Light Company and The Bank of New York Mellon Trust Company, N.A., Trustee (Exhibit 4.1 to Form 8-K filed on September 20, 2011).	Great Plains Energy KCP&L
10.1	*+	Amended Long-Term Incentive Plan, effective as of May 7, 2002 (Exhibit 10.1.a to Form 10-K for the year ended December 31, 2002).	Great Plains Energy KCP&L
10.2	*+	Great Plains Energy Incorporated Long-Term Incentive Plan as amended May 1, 2007 (Exhibit 10.1 to Form 8-K filed on May 4, 2007).	Great Plains Energy KCP&L
10.3	*+	Great Plains Energy Incorporated Amended Long-Term Incentive Plan adopted as of May 3, 2011 (Exhibit 10.1 to Form 8-K filed on May 6, 2011).	Great Plains Energy KCP&L
10.4	*+	Great Plains Energy Incorporated Long-Term Incentive Plan Awards Standards and Performance Criteria Effective as of May 6, 2008 (Exhibit 10.1.25 to Form 10-Q for the quarter ended June 30, 2008).	Great Plains Energy KCP&L