SEC Filing | Evergy, Inc.

PROSPECTUS

$250,000,000

Kansas City Power & Light Company

Offer to Exchange $250,000,000 6.05% Senior Notes Due 2035, Series A

for 6.05% Senior Notes Due 2035, Series B

________________

We are offering to exchange our 6.05% senior notes due 2035, Series B, or the “exchange notes,” for our currently outstanding 6.05% senior notes due 2035, Series A, or the “old notes.” The exchange notes are substantially identical to the old notes, except that the exchange notes have been registered under the federal securities laws, and will not bear any legend restricting their transfer. The exchange notes will represent the same debt as the old notes, and we will issue the exchange notes under the same indenture.

The principal features of the exchange offer are as follows:

·	The exchange offer expires at 5:00 p.m., New York City time, on May 22, 2006, unless extended.

·	We will exchange all old notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer.

·	You may withdraw tendered old notes at any time prior to the expiration of the exchange offer.

·	We do not intend to apply for listing of the exchange notes on any securities exchange or to arrange for them to be quoted on any quotation system.

·	The exchange offer is subject to customary conditions, including the condition that the exchange offer not violate applicable law or any applicable interpretation of the staff of the Securities and Exchange Commission, or the “SEC.”

·	The exchange of old notes for exchange notes pursuant to the exchange offer will not be a taxable event for United States federal income tax purposes.

·	We will not receive any proceeds from the exchange offer.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. The letter of transmittal states that, by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date, as defined herein, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

______________________________

Investing in the exchange notes involves risks. See “Risk Factors” beginning on page 7.

______________________________

Neither the U.S. Securities and Exchange Commission nor any other federal or state agency has approved or disapproved of the securities to be distributed in the exchange offer, nor have any of these organizations determined that this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this Prospectus is April 20, 2006.

You should rely only upon the information contained in this prospectus and the documents to which we refer you. We have not authorized any person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should assume the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

_______________

This prospectus is part of a registration statement we have filed with the SEC relating to the exchange notes. As permitted by the SEC's rules, this prospectus does not contain all of the information included in the registration statement and the accompanying exhibits and schedules we filed with the SEC. You should read the registration statement and the exhibits and schedules for more information about us and the exchange notes. The registration statement, exhibits and schedules are also available at the SEC's Public Reference Section or through its website. See “Where You Can Find More Information” in this prospectus.

You may obtain a free copy of our filings with the SEC by writing or telephoning us at the following address: Kansas City Power & Light Company, 1201 Walnut, Kansas City, Missouri 64106-2124 (telephone no.: 816-556-2200) Attention: Corporate Secretary, or by contacting us at our website (www.kcpl.com). Information on our website is not part of this prospectus. In order to obtain timely delivery of such information, noteholders must request the information no later than May 15, 2006 (5 business days before the date on which this exchange offer will expire).

_______________

TABLE OF CONTENTS

Cautionary Statements Regarding Certain		Related Party Transactions	48
Forward-Looking Information	1	The Exchange Offer	48
Prospectus Summary	2	Description of the Exchange Notes	58
Risk Factors	7	Summary of U.S. Federal Income Tax
Use of Proceeds	11	Considerations	67
Selected Consolidated Financial Data	12	Plan of Distribution	72
Management’s Discussion and Analysis of		Legal Matters	72
Financial Condition and Results of Operations	12	Experts	72
Business	28	Indemnification of Directors, Officers and
Management and Directors	35	Others for Securities Act Liabilities		73
Executive Compensation	39	Where You Can Find More Information		73
Beneficial Ownership of Securities	48	Index to Consolidated Financial Statements	F-1

DEALER PROSPECTUS DELIVERY OBLIGATION

Until May 30, 2006, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This obligation is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

_______________

This exchange offer is not being made to, and we will not accept surrenders for exchange from, holders of old notes in any jurisdiction in which the exchange offer or the acceptance thereof would not be in compliance with the securities or blue sky laws of that jurisdiction.

CAUTIONARY STATEMENTS REGARDING CERTAIN FORWARD-LOOKING INFORMATION

This prospectus contains forward-looking statements that are not based on historical facts. These forward-looking statements are based on assumptions, expectations, and assessments made by our management in light of their experience and their perception of historical trends, current conditions, expected future developments and other factors they believe to be appropriate. Any forward-looking statements are not guarantees of our future performance and are subject to risks and uncertainties, including those discussed under the heading “Risk Factors” in this prospectus, and in our other SEC filings. These risks and uncertainties could cause actual results, developments and business decisions to differ materially from those contemplated or implied by forward-looking statements. Consequently, you should recognize these statements for what they are and we caution you not to rely upon them as facts. We disclaim any duty to update the forward-looking statements, which apply only as of the date of this prospectus. Some of the factors that may cause actual results, developments and business decisions to differ materially from those contemplated by these forward-looking statements include the following:

·	future economic conditions in the regional, national and international markets, including, but not limited, to regional and national wholesale electricity markets

·	market perception of the energy industry and KCP&L

·	changes in business strategy, operations or development plans

·	effects of current or proposed state and federal legislative and regulatory actions or developments, including, but not limited to, deregulation, re-regulation and restructuring of the electric utility industry

·	adverse changes in applicable laws, regulations, rules, principles or practices governing tax, accounting and environmental matters including, but not limited to, air quality

·	financial market conditions and performance including, but not limited to, changes in interest rates and in availability and cost of capital and the effects on our pension plan assets and costs

·	credit ratings

·	inflation rates

·	effectiveness of risk management policies and procedures and the ability of counterparties to satisfy their contractual commitments

·	impact of terrorist acts

·	increased competition including, but not limited to, retail choice in the electric utility industry and the entry of new competitors

·	ability to carry out marketing and sales plans

·	weather conditions including weather-related damage

·	cost, availability, quality and deliverability of fuel

·	ability to achieve generation planning goals and the occurrence and duration of unplanned generation outages

·	delays in the anticipated in-service dates of additional generating capacity

·	nuclear operations and

·	other risks and uncertainties.

This list of factors is not all-inclusive because it is not possible to predict all factors. We direct your attention to “Risk Factors” included in this prospectus, which should be carefully read for further understanding of potential risks.

PROSPECTUS SUMMARY

The following summary highlights selected information contained in this prospectus. You should read this summary together with the more detailed information that is contained in this prospectus. Unless otherwise indicated or the context requires otherwise, all references in this prospectus to the “Company” mean Kansas City Power & Light Company and its consolidated subsidiaries; references to ”KCP&L,” “we,” “us,” “our” or similar references mean Kansas City Power & Light Company; and references to “old notes” mean the outstanding 6.05% senior notes due 2035, Series A, “exchange notes” mean the 6.05% senior notes due 2035, Series B to be issued in the exchange offer, and “notes” mean both the old notes and the exchange notes.

The Exchange Offer

For a more complete description of the terms of the exchange offer, see “The Exchange Offer” below in this prospectus.

Securities Offered	$250 million aggregate principal amount of 6.05% senior notes due 2035, Series B.

Exchange Offer	We are offering to exchange $1,000 principal amount of our 6.05% senior notes due November 15, 2035, Series B, which have been registered under the Securities Act, for each $1,000 principal amount of our currently outstanding 6.05% senior notes due November 15, 2035, Series A, which were issued in a private offering on November 17, 2005. You are entitled to exchange your old notes for freely tradable exchange notes with substantially identical terms to the old notes. The exchange offer is intended to satisfy your registration rights. After the exchange offer is complete, you will no longer be entitled to any exchange or registration rights with respect to your old notes. Accordingly, if you do not exchange your old notes, you will not be able to reoffer, resell or otherwise dispose of your old notes unless you comply with the registration and prospectus delivery requirements of the Securities Act, or there is an exemption available. We will accept any and all old notes validly tendered and not withdrawn prior to 5:00 p.m., New York City time, on May 22, 2006. Holders may tender some or all of their old notes pursuant to the exchange offer. However, old notes may be tendered only in integral multiples of $1,000 in principal amount. The form and terms of the exchange notes are substantially identical to the form and terms of the old notes except that: · the exchange notes have been registered under the federal securities laws and will not bear any legend restricting their transfer; · the exchange notes bear a different CUSIP number than the old notes; and · the holders of the exchange notes will not be entitled to certain rights under the registration rights agreement, including the provisions for an increase in the interest rate on the old notes in some circumstances relating to the timing of the exchange offer. See “The Exchange Offer.”
2
Transferability of Exchange Notes	We believe you will be able to transfer freely the exchange notes without registration or any prospectus delivery requirement so long as you are able to make the representations listed under “The Exchange Offer — Purpose and Effect of the Exchange Offer — Transferability.” If you are a broker-dealer that acquired old notes as a result of market-making or other trading activities, you must deliver a prospectus in connection with any resale of the exchange notes. See “Plan of Distribution.”

Expiration Date	The exchange offer will expire at 5:00 p.m., New York City time, on May 22, 2006, which time and date we call the “expiration date,” unless we decide to extend it.

Conditions to the Exchange Offer	The exchange offer is subject to several customary conditions, which may be waived by us. The exchange offer is not conditioned upon any minimum principal amount of old notes being tendered.

Procedures for Tendering Old Notes	If you wish to accept the exchange offer, you must complete, sign and date the letter of transmittal, or a facsimile of it, in accordance with the instructions contained in this prospectus and in the letter of transmittal. You should then mail or otherwise deliver the letter of transmittal, or facsimile, together with the old notes to be exchanged and any other required documentation, to the exchange agent at the address set forth in this prospectus and in the letter of transmittal to arrive by 5:00 p.m., New York City time, on the expiration date. By executing the letter of transmittal, you will represent to us that, among other things: · you, or the person or entity receiving the related exchange notes, are acquiring the exchange notes in the ordinary course of business; · neither you nor any person or entity receiving the related exchange notes is engaging in or intends to engage in a distribution of the exchange notes within the meaning of the federal securities laws; · neither you nor any person or entity receiving the related exchange notes has an arrangement or understanding with any person or entity to participate in any distribution of the exchange notes; · you are not affiliated with us; and · you are not acting on behalf of any person or entity that could not truthfully make these statements. See “The Exchange Offer — Procedures for Tendering Old Notes” and “Plan of Distribution.”

Special Procedures for Beneficial Holders	If you are the beneficial holder of old notes that are registered in the name of your broker, dealer, commercial bank, trust company or other nominee, and you wish to tender in the exchange offer, you should contact the person in 3 whose name your old notes are registered promptly and instruct that person to tender on your behalf. See “The Exchange Offer — Procedures for Tendering Old Notes.”

Guaranteed Delivery Procedures	If you wish to tender your old notes and you cannot deliver those old notes, the letter of transmittal or any other required documents to the exchange agent before the expiration date, you may tender your old notes according to the guaranteed delivery procedures set forth under “The Exchange Offer—Guaranteed Delivery Procedures.”

Acceptance of Old Notes and Delivery of Exchange Notes	Subject to certain conditions, we will accept for exchange any and all old notes which are properly tendered in the exchange offer before 5:00 p.m., New York City time, on the expiration date. The exchange notes will be delivered promptly after the expiration date. See “The Exchange Offer — Exchange Date.”

Effect of Not Tendering	Any old notes that are not tendered or that are tendered but not accepted will remain subject to the restrictions on transfer. Because the old notes have not been registered under the federal securities laws, they bear a legend restricting their transfer absent registration or the availability of a specific exemption from registration. Upon the completion of the exchange offer, we will have no further obligations, except under limited circumstances, to provide for registration of the old notes under the federal securities laws. See “The Exchange Offer — Consequences of Failure to Exchange.”

Interest on the Exchange Notes and the Old Notes	The exchange notes will bear interest from the most recent interest payment date to which interest has been paid on the old notes or, if no interest has been paid, from November 17, 2005. Interest on the old notes accepted for exchange will cease to accrue upon the issuance of the exchange notes.

Withdrawal Rights	You may withdraw tenders at any time prior to 5:00 p.m., New York City time, on the expiration date pursuant to the procedures described under “The Exchange Offer — Withdrawal Rights.”

Summary of Federal Income Tax Consequences	The exchange of old notes for exchange notes will not be a taxable event for United States federal income tax purposes. You will not recognize any taxable gain or loss as a result of exchanging old notes for exchange notes and you will have the same tax basis and holding period in the exchange notes as you had in the old notes immediately before the exchange. See “Summary of U.S. Federal Income Tax Considerations.”

Use of Proceeds	We will not receive any proceeds from the issuance of exchange notes pursuant to the exchange offer.

Exchange Agent	The Bank of New York is serving as exchange agent in connection with the exchange notes. The address, telephone number and facsimile number of the exchange agent is set forth under “The Exchange Offer — Exchange Agent.”

The Exchange Notes

The summary below describes several of the principal terms of the exchange notes. The indenture under which the exchange notes will be issued and the financial terms and covenants of the exchange notes are the same as the old notes. Some of the terms and conditions described below are subject to important limitations and exceptions. The “Description of the Exchange Notes” section of this prospectus contains a more detailed description of the terms and conditions of the exchange notes.

Issuer	Kansas City Power & Light Company

Notes Offered	$250 million in aggregate principal amount of 6.05% senior notes due 2035, Series B.

Maturity Date	November 15, 2035.

Interest Payment Dates	May 15 and November 15 of each year, beginning November 15, 2006.

Ranking	The exchange notes will be our senior unsecured obligations. They will rank equal in right of payment with our existing and future senior unsecured obligations, including the old notes, and senior in right of payment to all of our future subordinated indebtedness. The exchange notes will be junior to any secured indebtedness we may incur to the extent of the collateral securing that indebtedness, including our mortgage bonds, which are issued pursuant to, and secured by, our General Mortgage Indenture and Deed of Trust. At December 31, 2005, we had approximately $159.3 million aggregate principal of mortgage bonds outstanding.

Optional Redemption	We may redeem all or a portion of the exchange notes at a redemption price equal to the greater of: · 100% of the principal amount of the exchange notes then outstanding to be redeemed; or · the sum of the present values of the remaining scheduled payments of principal and interest on the exchange notes to be redeemed (not including any portion of such payments of interest accrued to the date of redemption) discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable treasury rate plus 25 basis points plus, in each case, accrued and unpaid interest on the principal amount being redeemed to the redemption date. See “Description of the Exchange Notes — Optional Redemption.”

Trustee and Paying Agent	The Bank of New York

Governing Law	The indenture is, and the exchange notes will be, governed by the laws of the State of New York.

Kansas City Power & Light Company

Kansas City Power & Light Company, headquartered in Kansas City, Missouri, engages in the generation, transmission, distribution and sale of electricity. KCP&L serves approximately 500,000 customers located in all or portions of 24 counties in western Missouri and eastern Kansas. Customers include approximately 440,000 residences, over 55,000 commercial firms, and over 2,200 industrials, municipalities, and other electric utilities. KCP&L’s retail electric revenues averaged approximately 82% of its total electric revenues over the last three years. Wholesale firm power, bulk power sales and miscellaneous electric revenues accounted for the remainder of utility revenues. KCP&L is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter.

Our principal executive office is located at 1201 Walnut, Kansas City, Missouri 64106 (telephone: (816) 556-2200).

Ratio of Earnings to Fixed Charges


Year Ended December 31	2005	2004	2003	2002	2001

SEC ratio of earnings to fixed charges (a)	3.87	3.34	3.69	2.88	2.07

(a) For purposes of computing the ratio of earnings to fixed charges, earnings consists of income from continuing operations before cumulative effect of changes in accounting principles, losses from equity investments and minority interests in consolidated subsidiaries with fixed charges, plus interest charges (excluding the reduction for capitalized interest), income taxes, and the estimated interest components of rents. Fixed charges consist of interest charges (excluding the reduction for capitalized interest) and the estimated interest components of rents.

Risk Factors

Investing in the exchange notes involves substantial risks. See “Risk Factors” for a discussion of certain factors that should be considered by prospective purchasers before participating in the exchange offer.

RISK FACTORS

An investment in the exchange notes is subject to various risks, including the risks discussed below. These risks should be considered carefully with the information provided elsewhere in this prospectus before participating in the exchange offer.

Risks Related to the Exchange Offer

There has been no prior market for the exchange notes and therefore your ability to sell the exchange notes may be limited.

Following the completion of this exchange offer, the exchange notes will be freely tradable by most holders. See “The Exchange Offer.” We do not intend to list the exchange notes on any United States or foreign securities exchange. We can give no assurances concerning the liquidity of any market that may develop for the exchange notes, the ability of any investor to sell the exchange notes, or the price at which investors would be able to sell their exchange notes. If a market for the exchange notes does not develop, investors may be unable to resell the exchange notes for an extended period of time, if at all. Consequently, investors may not be able to liquidate their investment readily, and lenders may not readily accept the exchange notes as collateral for loans.

We also cannot assure you that you will be able to sell your exchange notes at a particular time or that the prices that you receive when you sell will be favorable. We also cannot assure you as to the level of liquidity of the trading market for the exchange notes or, in the case of any holders of old notes that do not exchange them, the trading market for those notes following the offer to exchange those notes for exchange notes. Future trading prices of the old notes and exchange notes will depend on many factors, including:

·	our operating performance and financial condition;

·	our ability to complete the offer to exchange the old notes for the exchange notes;

·	the interest of securities dealers in making a market for the old notes and the exchange notes; and

·	the market for similar securities.

Failure to exchange your old notes will leave them subject to transfer restrictions.

Any old notes that remain outstanding after this exchange offer will continue to be subject to restrictions on their transfer. After this exchange offer, holders of old notes will not have any further rights under the registration rights agreement, with limited exceptions. In general, old notes may not be offered or sold unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We currently do not anticipate registering the old notes under the Securities Act. As old notes are tendered and accepted in the exchange offer, the aggregate principal amount of old notes will decrease, which decrease will decrease their liquidity. Any market for old notes that are not exchanged could be adversely affected by the conclusion of this exchange offer.

Late deliveries of the old notes and other required documents could prevent a holder from exchanging its old notes.

Holders are responsible for complying with all exchange offer procedures. Issuance of exchange notes in exchange for old notes will only occur upon completion of the procedures described in this prospectus under the heading “The Exchange Offer — Procedures for Tendering Old Notes.” Therefore, holders of old notes who wish to exchange them for exchange notes should allow sufficient time for completion of the exchange procedures. We are not obligated to notify you of any failure to follow the proper procedures.

If you are a broker-dealer, your ability to transfer the exchange notes may be restricted.

A broker-dealer that purchased old notes for its own account as part of market-making or trading activities must deliver a prospectus when it sells the exchange notes. Our obligation to make this prospectus available to broker-dealers is limited. Consequently, we cannot guarantee that a proper prospectus will be available to broker-dealers wishing to resell their exchange notes.

Risks Related to the Company

Actual results in future periods for the Company could differ materially from historical results and the forward-looking statements contained in this prospectus. Factors that might cause or contribute to such differences include, but are not limited to, those discussed below. The Company’s business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results, and are often beyond the Company’s control. Additional risks and uncertainties not presently known or that the Company’s management currently believes to be immaterial may also adversely affect the Company. The risk factors described below, as well as the other information included in this prospectus and in the other documents filed with the SEC, should be carefully considered before making an investment in the exchange notes.

KCP&L has regulatory risks.

KCP&L is subject to extensive federal and state regulation, as described below. Failure to obtain adequate rates or regulatory approvals, in a timely manner, adoption of new regulations by federal or state agencies, or changes to current regulations and interpretations of such regulations may materially affect the Company’s business and its results of operations and financial position. The Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935, as amended, and provided certain utility customer protection authority to the Federal Energy Regulatory Commission (FERC) and the states. The Energy Policy Act of 2005, among other things, also requires FERC to perform a study of competition in wholesale and retail electricity markets and authorizes the creation of an Electric Reliability Organization (ERO) to establish and enforce mandatory reliability standards subject to FERC oversight. The final rule for ERO development and processes for insuring reliable grid operations was issued in February 2006. Management has not yet determined the impact of this final rule. FERC is in the process of establishing rules implementing the Energy Policy Act of 2005, and there is the risk that the rules may adversely affect operations, the results of operations and financial condition of the Company.

KCP&L is regulated by the Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (KCC) with respect to retail rates, certain accounting matters, standards of service and, in certain cases, the issuance of securities and certification of facilities and service territories. Failure to obtain adequate and timely rate relief may adversely affect KCP&L’s results of operations and financial condition. KCP&L is also subject to regulation by the Federal Energy Regulatory Commission (FERC) with respect to the issuance of short-term debt, wholesale electricity sales and transmission matters and the Nuclear Regulatory Commission (NRC) as to nuclear operations.

The Company has financial market and ratings risks.

The Company and Great Plains Energy, which is KCP&L’s source of equity capital, rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations. KCP&L’s capital requirements are expected to increase substantially over the next several years as it implements the generation and environmental projects in its comprehensive energy plan. The Company’s management believes that it and Great Plains Energy will maintain sufficient access to these financial markets at a reasonable cost based upon current credit ratings and market conditions. However, changes in market conditions or credit ratings could adversely affect each of their ability to access financial markets at a reasonable cost, impact the rate treatment provided KCP&L, or both, and therefore materially affect its results of operations and financial position.

KCP&L and certain of its securities are rated by Moody's Investors Service and Standard & Poor's. These ratings impact KCP&L’s cost of funds.

The Company’s financial statements reflect the application of critical accounting policies.

The application of the Company’s critical accounting policies reflects complex judgments and estimates. These policies include industry-specific accounting applicable to regulated public utilities, accounting for pensions and long-lived and intangible assets. The adoption of new Generally Accepted Accounting Principles (GAAP) or changes to current accounting policies or interpretations of such policies may materially affect the Company’s results of operations and financial position.

KCP&L is subject to environmental laws and the incurrence of environmental liabilities.

KCP&L is subject to regulation by federal, state and local authorities with regard to air and other environmental matters. The generation, transmission and distribution of electricity produces and requires disposal of certain hazardous products, which are subject to these laws and regulations. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. KCP&L regularly conducts environmental audits designed to ensure compliance with governmental regulations and to detect contamination. Failure to comply with these laws and regulations could have a material adverse effect on KCP&L’s results of operations and financial position.

New environmental laws and regulations affecting KCP&L’s operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to KCP&L or its facilities, which may substantially increase its environmental expenditures in the future. New facilities, or modifications of existing facilities, may require new environmental permits or amendments to existing permits. Delays in the environmental permitting process, denials of permit applications or conditions imposed in permits may materially affect the cost and timing of the generation and environmental retrofit projects included in the comprehensive energy plan, among other projects, and thus materially affect KCP&L’s results of operations and financial position. In addition, KCP&L may not be able to recover all of its costs for environmental expenditures through rates in the future. Under current law, KCP&L is also generally responsible for any on-site liabilities associated with the environmental condition of its facilities that it has previously owned or operated, regardless of whether the liabilities arose before, during or after the time it owned or operated the facilities. The incurrence of material environmental costs or liabilities, without related rate recovery, could have a material adverse effect on KCP&L’s results of operations and financial position. See Note 12 to the consolidated financial statements for additional information regarding environmental matters.

KCP&L is affected by demand, seasonality and weather.

The results of operations of KCP&L can be materially affected by changes in weather and customer demand. KCP&L estimates customer demand based on historical trends, to procure fuel and purchased power. Differences in customer usage from these estimates due to weather or other factors could materially affect KCP&L’s results of operations.

Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. KCP&L is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter. In addition, severe weather, including but not limited to tornados, snow, rain and ice storms can be destructive causing outages and property damage that can potentially result in additional expenses and lower revenues. KCP&L’s Iatan and Hawthorn stations use water from the Missouri River for cooling purposes. Low water and flow levels, which have been experienced in recent years, can increase KCP&L’s maintenance costs at these stations and, if these levels get low enough, could cause KCP&L to modify plant operations.

KCP&L has commodity price risks.

KCP&L engages in the wholesale and retail marketing of electricity and, accordingly, is exposed to risks associated with the price of electricity. KCP&L generates, purchases and sells electricity in the retail and wholesale markets.

Fossil fuel and transportation prices impact KCP&L’s costs.

Less than 1% of KCP&L's rates contain an automatic fuel adjustment clause, exposing KCP&L to risk from changes in the market prices of coal and natural gas used to generate power and in the cost of coal and natural gas transportation. Changes in KCP&L’s fuel mix due to electricity demand, plant availability, transportation issues, fuel prices and other factors can also adversely affect KCP&L’s fuel costs.

KCP&L does not hedge its entire exposure from fossil fuel and transportation price volatility. As a consequence, its results of operations and financial position may be materially impacted by changes in these prices, until increased costs are recovered in rates.

Wholesale electricity prices affect costs and revenues.

KCP&L's ability to maintain or increase its level of wholesale sales depends on the wholesale market price, transmission availability and the availability of KCP&L’s generation for wholesale sales, among other factors. A substantial portion of KCP&L’s wholesale sales are made in the spot market, and thus KCP&L has immediate exposure to wholesale price changes. Declines in wholesale market price or availability of generation or transmission constraints in the wholesale markets, could reduce KCP&L's wholesale sales and adversely affect KCP&L’s results of operations and financial position.

KCP&L is also exposed to risk because at times it purchases power to meet its customers’ needs. The cost of these purchases may be affected by the timing of customer demand and/or unavailability of KCP&L’s lower-priced generating units. Wholesale power prices can be volatile and generally increase in times of high regional demand and high natural gas prices.

KCP&L has operations risks.

The operation of KCP&L’s electric generation, transmission and distribution systems involves many risks, including breakdown or failure of equipment or processes; operating limitations that may be imposed by equipment conditions, environmental or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling; and catastrophic events such as fires, explosions, severe weather or other similar occurrences.

These and other operating events may reduce KCP&L’s revenues or increase its costs, or both, and may materially affect KCP&L’s results of operations and financial position.

KCP&L has construction-related risks.

KCP&L’s comprehensive energy plan includes the construction of an estimated 850 megawatt (MW) coal-fired generating plant, 100.5 MW of wind generation and environmental retrofits at two existing coal-fired units. KCP&L has not recently managed a construction program of this magnitude. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, and events beyond KCP&L’s control may occur that may materially affect the schedule, budget and performance of these projects. These risks may increase the costs of these construction projects, require KCP&L to purchase additional electricity to supply its retail customers until the projects are completed, or both, and may materially affect KCP&L’s results of operations and financial position.

KCP&L has retirement-related risks.

Through 2010, approximately 30% of KCP&L’s current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect KCP&L’s ability to manage and operate its business.

Substantially all of KCP&L’s employees participate in defined benefit and postretirement plans. If KCP&L employees retire when they become eligible for retirement through 2010, or if KCP&L’s plans experience adverse market returns on its investments, or if interest rates materially fall, KCP&L’s pension expense and contributions to the plans could rise substantially over historical levels. The timing and number of employees retiring and selecting the lump sum payment option could result in pension settlement charges that could materially affect KCP&L’s results of operations. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on KCP&L’s results of operations and financial position. Proposed legislation pending in Congress on pension reform could result in increased pension funding requirements. The Financial Accounting Standards Board (FASB) has a project to reconsider the accounting for pensions and other post-retirement benefits. This project may result in accelerated expense, liability recognition and contributions.

KCP&L has nuclear exposure.

KCP&L owns 47% (548 MW) of Wolf Creek Generating Station (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.

Wolf Creek has the lowest fuel cost per MWh of any of KCP&L's generating units. Although not expected, an extended outage of Wolf Creek, whether resulting from NRC action, an incident at the plant or otherwise, could have a substantial adverse effect on KCP&L's results of operations and financial position in the event KCP&L incurs higher replacement power and other costs that are not recovered through rates. If a long-term outage occurred, the state regulatory commissions could reduce rates by excluding the Wolf Creek investment from rate base.

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 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 anticipated level, KCP&L could be responsible for the balance of funds required. If returns are lower than the expected level, management believes a rate increase would be allowed ensuring full recovery of decommissioning costs over the remaining life of the unit.

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 and disposal of radioactive materials, and to potential retrospective assessments and losses in excess of insurance coverage.

USE OF PROCEEDS

On November 17, 2005, we issued and sold the old notes. The net proceeds from the sale of the old notes, after deducting the discount paid to the initial purchasers and other fees and expenses of the initial offering, were approximately $246.3 million. We used the net proceeds, together with cash on hand, to repay $250 million of 7.125% unsecured senior notes that matured on December 15, 2005.

We will not receive any proceeds from the issuance of the exchange notes in the exchange offer. We will cancel all of the old notes tendered in the exchange offer.

SELECTED CONSOLIDATED FINANCIAL DATA

The following selected financial data for the years ended December 31, 2001 though 2005 and as of December 31, 2001 through 2005 are derived from our audited consolidated financial statements, including the notes thereto. This table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements, including the notes thereto, appearing elsewhere in this prospectus. The following should also be read in conjunction with Note 20 to our consolidated financial statements for information regarding quarterly operating results.


Year Ended December 31^(a)	2005		2004		2003		2002		2001
	(dollars in millions)
Operating revenues	$	1,131	$	1,092	$	1,057	$	1,013	$	1,287
Income from continuing operations^(b)	$	144	$	143	$	126	$	103	$	116
Net income	$	144	$	143	$	117	$	96	$	120
Total assets at year end	$	3,339	$	3,337	$	3,303	$	3,139	$	3,146
Total redeemable preferred stock, mandatorily
redeemable preferred securities and long-
term debt (including current maturities)	$	976	$	1,126	$	1,336	$	1,313	$	1,311
(a) KCP&L’s consolidated financial statements include its wholly owned subsidiary HSS. In addition, KCP&L’s consolidated results of operations include KLT Inc. and Great Plains Power Incorporated for all periods prior to the October 1, 2001, formation of Great Plains Energy.
(b) This amount is before discontinued operations of $(8.7), $(4.0) and $3.6 million in 2003 through 2001, respectively. In 2002, this amount is before a $3.0 million cumulative effect of a change in accounting principle.

MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of the Company during the periods presented. It should be read in conjunction with the accompanying consolidated financial statements and related notes. See “Risk Factors” for further discussion of the Company’s risk factors.

Comprehensive Energy Plan

KCP&L continues to make progress in implementing its comprehensive energy plan and received orders from the MPSC and KCC in 2005. The orders were on agreements reached among KCP&L, the Commissions’ staffs and certain key parties in the respective jurisdictions. The Sierra Club and Concerned Citizens of Platte County have appealed the MPSC order, and the Sierra Club has appealed the KCC order. These appeals are expected to be decided in 2006. Although subject to these appeals, the MPSC and KCC orders remain in effect pending the applicable court’s decision.

In February 2006, KCP&L filed requests with the MPSC and KCC for annual rate increases of $55.8 million or 11.5% and $42.3 million or 10.5%, respectively. Iatan No. 2 detailed project engineering and design has begun and plant construction is expected to start in 2006. KCP&L has selected a developer and contractor for the construction of a 100.5 MW wind project in Kansas and management expects the project to be completed in time for inclusion in rates in 2007. See Note 5 to the consolidated financial statements for more information on the comprehensive energy plan.

Business Overview

KCP&L is an integrated, regulated electric utility that engages in the generation, transmission, distribution and sale of electricity. KCP&L has over 4,000 MWs of generating capacity and has transmission and distribution facilities that provide electricity to approximately 500,000 customers in the states of Missouri and Kansas. KCP&L has continued to experience modest load growth. Load growth consists of higher usage per customer and the addition of new customers. Retail electricity rates are below the national average.

KCP&L’s residential customers’ usage patterns are significantly affected by weather. Bulk power sales, the major component of wholesale sales, vary with system requirements, generating unit and purchased power availability, fuel costs and requirements of other electric systems. Less than 1% of revenues include an automatic fuel adjustment provision. KCP&L’s coal base load equivalent availability factor decreased to 82% in 2005 from 84% in 2004, reflecting scheduled and forced plant outages. The 176 MW Montrose No. 3 generator step-up transformer (GSU) failed in late May 2005. KCP&L leased a spare GSU until the failed GSU was repaired and installed during the fourth quarter of 2005. In August 2005, Hawthorn No. 5’s GSU failed, which resulted in a 32-day outage. A spare GSU was installed in September; however, the size of the spare GSU limits the output of the unit to net 500 MW. The 65 MW decrease in Hawthorn No. 5 capability will continue until a new transformer is installed, currently expected in June 2006. The outage to install the repaired GSU is expected to be completed in 14 days.

KCP&L’s nuclear unit, Wolf Creek, accounts for approximately 20% of its base load capacity and over a three-year period averaged over 20% of KCP&L’s MWhs generated. Wolf Creek’s availability was approximately 13% lower in 2005 compared to 2004 due to its scheduled spring 2005 refueling outage. Replacement power costs for scheduled Wolf Creek outages are accrued evenly over the unit’s 18-month operating cycle. KCP&L expects its cost of nuclear fuel to remain relatively stable through 2009 because of contracts in place.

The fuel cost per MWh generated and the purchased power cost per MWh has a significant impact on the results of operations for KCP&L. Generation fuel mix can substantially change the fuel cost per MWh generated. Nuclear fuel cost per MWh generated is substantially less than the cost of coal per MWh generated, which is significantly lower than the cost of natural gas and oil per MWh generated. The cost per MWh for purchased power is significantly higher than the cost per MWh of coal and nuclear generation. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply and purchased power, and the requirements of other electric systems to provide reliable power economically.

KCP&L expects its fuel expense to increase significantly in 2006 due to projected increases in the cost of coal and coal transportation. The anticipated increase in delivered coal prices is expected to affect most regional utilities; therefore, the increase is not expected to materially erode KCP&L’s position as a low cost regional electricity generator.

Rail companies have experienced longer cycle times for coal deliveries to utilities across the country since the third quarter of 2004. Western rail service further deteriorated in 2005 due to two train derailments that occurred on the primary rail line serving the Powder River Basin (PRB). Maintenance to repair significant sections of track on this rail line began in 2005 and is expected to be completed by the end of 2006. These repairs must be completed before normal train operations from the PRB can resume, which affects all users of PRB coal. Approximately 98% of KCP&L’s coal requirements come from the PRB and originate on the Burlington Northern Santa Fe and the Union Pacific railroads, both of which have been affected by the current rail situation. As a result, most utilities, including KCP&L, have coal inventories that are below desired levels. KCP&L implemented coal conservation measures by reducing coal generation in 2005 and expects to continue these measures for at least the first half of 2006. This reduction in coal generation in the marketplace caused upward pressure on both pricing for next power generation fuel sources (natural gas and/or oil) and wholesale electricity prices in 2005 and is expected to continue into 2006. The rail companies have indicated that they expect the impact related to the 2006 maintenance program to be less than the 10% to 15% reduction in deliveries experienced in 2005, but have offered no estimate on the likely reduction. Management cannot predict with any certainty the 2006 impact of the situation; however, an inability to obtain timely delivery of coal to meet generation requirements could materially impact KCP&L’s results of operations. Management is monitoring the situation

closely and steps will be taken, as necessary, to maintain an adequate energy supply for KCP&L’s retail load and firm MWh sales.

Lower Earnings expected in 2006

The Company’s projected net income is expected to decrease in 2006. The decrease in projected net income for 2006 is due to a significant increase in fuel cost and related transportation expenses at KCP&L and the absence of certain tax benefits recorded in 2005. These factors are expected to more than offset projected operational efficiencies, retail load growth, higher wholesale volume and higher allowance for equity funds used during construction related to the comprehensive energy plan.

Through 2010, approximately 30% of KCP&L’s current employees are eligible to retire with full pension benefits. The timing and number of employees retiring and selecting the lump sum payment option could result in settlement charges that could materially affect KCP&L’s 2006 results of operations.

Related Party Transactions

See Note 11 to the consolidated financial statements for information regarding related party transactions.

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 the results of operations and financial position. Management has identified the following accounting policies deemed critical to the understanding of the Company’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 Board of Directors for KCP&L.

Pensions

KCP&L does not have a pension plan; however, KCP&L employees and officers participate in Great Plains Energy’s pension plans. The Company incurs significant costs in providing non-contributory defined pension benefits under the Great Plains Energy pension plans. 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, compensation levels and employment periods), the level of contributions made to the plan, earnings on plan assets 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.

These actuarial assumptions are updated annually in accordance with Statement of Financial Accounting Standards (SFAS) No. 87, “Employers’ Accounting for Pensions.” In selecting an assumed discount rate, the prevailing market rate of fixed income debt instruments with maturities matching the expected timing of the benefit obligation was considered. The assumed rate of return on plan assets was developed based on the weighted average of long-term returns forecast for the expected portfolio mix of investments held by the plan. These assumptions are based on management’s best estimates and judgment; however, material changes may occur if these assumptions differ from actual events. See Note 8 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 for the Great Plains Energy pension plans. Each sensitivity reflects the impact of the change based solely on a change in that assumption only..



					Impact on							Impact on
					Projected			Impact on				2005
	Change in				Benefit			Pension				Pension
Actuarial assumption	Assumption				Obligation			Liability				Expense
					(millions)
Discount rate		0.5	%	increase		$	(32.9	)	$	(18.1	)	$	(2.3	)
Rate of return on plan assets		0.5	%	increase			-			-			(1.9	)
Discount rate		0.5	%	decrease			35.1			19.8			2.5
Rate of return on plan assets		0.5	%	decrease			-			-			1.9

KCP&L recorded pension expense reflecting orders from the MPSC and KCC that established annual pension costs at $22 million, reducing 2005 pension expense. The difference between pension costs under SFAS No. 87 and the amount allowed for ratemaking is recorded as a regulatory asset or liability for future ratemaking recovery or refunds, as appropriate. See discussion of Regulatory Matters below and Note 8 to the consolidated financial statements for additional information.

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

As a regulated utility, KCP&L is subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Accordingly, KCP&L has recorded assets and liabilities on its balance sheet resulting from the effects of the ratemaking process, which would not be recorded under GAAP if KCP&L were not regulated. Regulatory assets represent costs incurred that have been deferred because future recovery in customer rates is probable. Regulatory liabilities generally represent probable future reductions in revenue or refunds to customers. Future recovery of regulatory assets is not assured, but is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Future reductions in revenue or refunds for regulatory liabilities generally are not mandated, pending future rate proceedings or actions by the regulators. 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 on KCP&L’s rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedence on matters applicable to KCP&L; 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. KCP&L’s continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by restructuring and deregulation in the electric industry. In the event that SFAS No. 71 no longer applied to a deregulated portion of KCP&L’s operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment on utility plant assets as determined pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” See Note 5 to the consolidated financial statements for more information.

Impairment of Assets and Intangible Assets

Long-lived assets and intangible assets subject to amortization are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS No. 144.

Impairment analyses require management to make assumptions about future sales, operating costs and discount rates over the life of the related asset, or in some cases over an indefinite life. Potential impairment indicators include such factors as current period losses combined with a history of losses, or a projection of continuing losses or a significant decrease in the market price of the asset under review. Management’s assumptions about these factors require significant judgment and under different assumptions, the fair value of an asset could be materially different.

Accounting standards require a company to recognize an impairment in the current period results of operations if the sum of the undiscounted expected future cash flows from the company’s asset is less than the carrying value of the asset. The impairment recognized is the difference between the fair value and book value of the asset.

Results of Operations

The following discussion of the Company’s results of operations includes KCP&L, an integrated, regulated electric utility and HSS, an unregulated subsidiary of KCP&L. References to KCP&L, in the discussion that follows, reflect only the operations of the utility. The following table summarizes the Company’s comparative results of operations.


	2005			2004			2003
	(millions)
Operating revenues	$	1,130.9		$	1,091.6		$	1,057.0
Fuel		(207.9	)		(179.4	)		(160.3	)
Purchased power		(61.3	)		(52.5	)		(53.2	)
Other operating expenses		(460.8	)		(442.3	)		(422.6	)
Depreciation and amortization		(146.6	)		(145.2	)		(141.0	)
Gain (loss) on property		(4.6	)		(5.1	)		1.6
Operating income		249.7			267.1			281.5
Non-operating income (expenses)		11.8			(1.9	)		(3.1	)
Interest charges		(61.8	)		(74.2	)		(70.3	)
Income taxes		(48.2	)		(52.8	)		(83.5	)
Minority interest in subsidiaries		(7.8	)		5.1			1.3
Income from continuing operations		143.7			143.3			125.9
Discontinued operations, net of income taxes		-			-			(8.7	)
Net income	$	143.7		$	143.3		$	117.2

Net income was relatively unchanged in 2005 compared to 2004. KCP&L’s net income decreased $4.8 million primarily due to higher fuel costs and purchased power prices, as well as the effects of plant outages and coal conservation on fuel mix. Higher other operating expenses were partially offset by the regulatory accounting treatment of pension expense. These decreases to net income were offset by retail revenues increasing 6% as a result of significantly warmer summer weather in 2005 compared to an unusually mild summer in 2004. Additionally, the favorable impact of sustained audit positions on the 2005 composite tax rates lowered income taxes. KCP&L’s decrease was more than offset by $5.2 million in reduced losses at HSS primarily due to a 2004 impairment charge related to the 2005 sale of Worry Free.

Income from continuing operations increased $17.4 million in 2004 compared to 2003. Wholesale revenues increased as a result of increased generation, bundling transmission with energy and lower than expected retail loads during the summer months. An increase in operating expenses more than offset these factors primarily due to the increase in MWhs generated, including higher coal and coal transportation costs, higher administrative expenses, an impairment charge related to the first quarter 2005 sale of Worry Free and the

significant positive impact on 2003 of the Hawthorn No. 5 litigation settlements. Income taxes decreased due to the favorable impact of state tax planning on the composite tax rate and the allocation of tax benefits from holding company losses pursuant to Great Plains Energy’s intercompany tax allocation agreement with its subsidiaries, including the Company. The change in discontinued operations was due to a $7.1 million loss on the June 2003 disposition of HSS’ interest in RSAE and continuing losses through the date of disposition of $1.6 million.

Sales Revenues and MWh Sales


			%					%
	2005		Change			2004		Change			2003
Retail revenues	(millions)
Residential	$	380.0		9		$	347.1		(4	)	$	361.5
Commercial		434.6		3			421.1		1			417.6
Industrial		100.9		5			96.2		1			95.0
Other retail revenues		8.6		(2	)		8.7		1			8.7
Total retail		924.1		6			873.1		(1	)		882.8
Wholesale revenues		192.4		(4	)		200.2		27			157.5
Other revenues		14.3		(15	)		16.8		15			14.6
KCP&L electric revenues		1,130.8		4			1,090.1		3			1,054.9
Subsidiary revenues		0.1		(93	)		1.5		(25	)		2.1
Total revenues	$	1,130.9		4		$	1,091.6		3		$	1,057.0


			%					%
	2005		Change			2004		Change			2003
Retail MWh sales	(thousands)
Residential		5,383		10			4,903		(3	)		5,047
Commercial		7,292		4			6,998		1			6,933
Industrial		2,165		5			2,058		1			2,035
Other retail MWh sales		82		(3	)		85		-			85
Total retail		14,922		6			14,044		-			14,100
Wholesale MWh sales		4,608		(30	)		6,603		14			5,777
KCP&L electric MWh sales		19,530		(5	)		20,647		4			19,877

Retail revenues increased $51.0 million in 2005 compared to 2004. The increase was driven by significantly warmer summer weather in 2005 compared to an unusually mild summer in 2004 and continued load growth of approximately 2%, adjusted for weather for 2005 and 2004. Residential usage per customer increased 9% in 2005, driven by a 45% increase in cooling degree-days, which was 19% above normal.

Retail revenues decreased $9.7 million in 2004 compared to 2003 primarily due to a $14.4 million reduction in residential revenues. Residential usage per customer decreased 4% in 2004 compared to 2003 as a result of significantly cooler summer weather in 2004. The Kansas City area experienced one of the coolest summers in the past 30 years, which resulted in cooling degree-days 18% below normal. The impact of the cooler summer weather was partially offset by load growth in 2004. The average number of residential and commercial customers continues to grow; both increased 1% to 2% in 2005 and 2004 compared to the respective prior years.

Wholesale revenues decreased $7.8 million in 2005 compared to 2004 due to a 30% decrease in MWhs sold, which was significantly offset by an increase in the average market price per MWh. The decrease in MWhs sold was driven by a 5% decrease in net MWhs generated as a result of coal conservation and plant outages. Additionally, retail MWh sales increased 6% in 2005 compared to 2004, which resulted in less MWhs available for wholesale sales. Average market price per MWh increased 56% to $47.82 in 2005 compared to 2004 due to warmer summer weather in 2005, higher natural gas prices, transmission constraints and coal conservation in the region.

Wholesale revenues increased $42.7 million in 2004 compared to 2003. Wholesale MWhs sold increased 14%, primarily due to increased generation, bundling transmission with energy and lower than expected retail loads during the summer months, combined with successful marketing efforts. Average market prices per MWh increased 13% to $30.72 in 2004 compared to 2003, primarily due to more sales made during periods of higher natural gas prices and bundling transmission with energy to provide a delivered product. Additionally, wholesale revenues were affected by the partial settlements of the Hawthorn No. 5 litigation.

As described in “Business - Legal Proceedings”, KCP&L filed suit against multiple defendants who are alleged to have responsibility for the 1999 Hawthorn No. 5 boiler explosion. Various defendants settled with KCP&L in this litigation, resulting in KCP&L recording $2.4 million and $35.8 million in 2004 and 2003, respectively. A portion of the settlements, $1.2 million and $17.3 million for 2004 and 2003, respectively, was recorded as a recovery of capital expenditures. The following table summarizes the income statement impact related to the remainder of the settlements for loss of use of Hawthorn No. 5.


	2004			2003
	(millions)
Wholesale revenues	$	0.2		$	2.7
Fuel		0.2			4.0
Purchased Power		0.8			11.8
Operating income		1.2			18.5
Income taxes		(0.5	)		(7.2	)
Net income	$	0.7		$	11.3

Fuel and Purchased Power


Net MWhs Generated			%					%
by Fuel Type	2005		Change			2004		Change			2003
	(thousands)
Coal		14,994		(4	)		15,688		5			15,011
Nuclear		4,146		(13	)		4,762		14			4,178
Natural gas and oil		473		206			155		(43	)		270
Total Generation		19,613		(5	)		20,605		6			19,459

Fuel expense increased $28.5 million in 2005 compared to 2004 despite a 5% decrease in MWhs generated due to a combination of changes in the fuel mix to higher cost generation, increased coal and coal transportation costs and increased natural gas prices. The changes in fuel mix were driven by the number and duration of plant outages as well as coal conservation measures. KCP&L’s 2005 coal and coal transportation contracts were entered into at higher average prices than related 2004 contracts.

Fuel expense increased $19.1 million in 2004 compared to 2003 due to a 6% increase in MWhs generated, higher coal and coal transportation costs, higher natural gas costs and the net effect of $3.8 million from the Hawthorn No. 5 partial litigation settlements. The increase was partially offset by changes in the fuel mix to lower cost generation due to increased coal and nuclear fuel and less natural gas in the fuel mix. The change in fuel mix was primarily due to the 2003 refueling outage at Wolf Creek and the cooler 2004 summer weather, which allowed coal and nuclear capacity to supply a greater percentage of the reduced retail load.

Purchased power expense increased $8.8 million in 2005 compared to 2004. The average price per MWh purchased increased 61% in 2005 compared to 2004 partially offset by an 8% decline in MWhs purchased. The increased prices were driven by purchases during higher priced peak hours as a result of warmer weather, plant outages and overall higher average prices due to higher natural gas prices combined with transmission constraints, coal conservation and outages in the region.

Purchased power expense decreased $0.7 million in 2004 compared to 2003. MWhs purchased decreased 31% in 2004 compared to 2003 primarily due to lower retail customer demand and a 2% increase in the coal fleet equivalent availability factor in 2004 compared to 2003. The decrease in MWhs purchased was partially offset by an 11% increase in the average price per MWh purchased in 2004 compared to 2003 primarily due to higher natural gas market prices and increased market demand. Another offset includes the net effect of the Hawthorn No. 5 partial litigation settlements, which impacted purchased power expense by $11.0 million in 2004 compared to 2003.

Other Operating Expenses (including other operating, maintenance and general taxes)

Other operating expenses increased $18.5 million in 2005 compared to 2004 primarily due to the following:

·	increased employee related expenses of $4.7 million including severance and incentive compensation,

·	increased expenses of $2.4 million due to higher legal reserves,

·	increased regulatory expenses of $1.2 million including expenses related to the comprehensive energy plan,

·	increased general taxes of $5.9 million mostly due to increases in gross receipts tax, assessed property valuations and mill levies,

·	increased expenses of $4.2 million due to higher restoration costs for a January 2005 ice storm and June 2005 wind storms compared to the 2004 wind storm restoration costs and

·	increased production operations and maintenance expenses of $4.3 million primarily due to scheduled and forced plant maintenance in 2005 and the reversal of an environmental accrual in 2004.

Partially offsetting the increase in other operating expenses was:

·	decreased pension expense of $4.7 million due to the regulatory accounting treatment of pension expense in accordance with MPSC and KCC orders and

·	decreased transmission service expense of $5.7 million primarily due to lower wholesale MWhs sold.

Other operating expenses increased $19.7 million in 2004 compared to 2003 primarily due to the following:

·	increased pension expense of $3.5 million primarily due to lower discount rates, the amortization of investment losses from prior years and plan settlement losses,

·	increased other employee-related costs of $3.5 million including higher medical costs and incentive compensation costs,

·	increased property taxes of $4.3 million primarily due to increases in assessed property valuations and mill levies,

·	increased outside services of $4.4 million including costs associated with Sarbanes-Oxley compliance,

·	increased transmission and distribution expenses including $2.5 million primarily due to increased transmission usage charges as a result of the increased wholesale MWh sales, $2.3 million related to SPP administration and $1.3 million in storm related expenses and

·	increased office expense including $2.1 million expenditure to buy out computer equipment operating leases.

Partially offsetting the increase in other operating expenses was:

·	decreased plant maintenance expense of $1.3 million primarily due to differences in timing and scope of outages and $0.9 million in lower gross receipts taxes as a result of lower retail revenues and

·	decreased expenses due to the reversal of an environmental accrual and the establishment of a regulatory asset for the probable recovery in the Kansas jurisdiction of enhanced security costs.

Gain (loss) on Property

Gain (loss) on property remained relatively unchanged in 2005 compared to 2004, due to offsetting losses. During 2005, KCP&L wrote off $3.6 million of plant operating system development costs as a result of vendor non-performance. See Note 14 to the consolidated financial statements for related legal proceedings. Gain (loss) on property increased operating expenses $6.7 million in 2004 compared to 2003 primarily due to the 2004 impairment charge related to the 2005 sale of Worry Free.

Interest Charges

Interest charges decreased $12.4 million in 2005 compared to 2004 primarily due to $10.1 million of interest related to the IRS 1995-1999 audit settlement in 2004. Interest charges increased $3.9 million in 2004 compared to 2003. The increase was primarily due to the $10.1 million of interest discussed above, partially offset by a $6.3 million decrease primarily due to the 2004 redemption of KCP&L’s $154.6 million 8.3% Junior Subordinated Deferred Interest Bonds.

Income Taxes

Income taxes decreased $4.6 million in 2005 compared to 2004. Several factors contributed to the decreased taxes including lower taxable income in 2005. The favorable impact of sustained audit positions on the composite tax rate decreased income taxes $6.3 million, including $3.1 million reflecting the composite tax rate change on deferred tax balances, and the domestic manufacturers’ deduction provided for under the American Jobs Creation Act of 2004 contributed $1.5 million to the decrease in taxes. These 2005 decreases to income taxes were partially offset when compared to 2004 due to the $10.1 million 2004 tax reserves release discussed below.

Income taxes decreased $30.7 million in 2004 compared to 2003. Several factors contributed to the decreased taxes including lower taxable income in 2004. The favorable impact of state tax planning on the composite tax rate decreased income taxes $10.1 million, including $8.6 million reflecting the composite tax rate change on deferred tax balances resulting from book to tax temporary differences. An additional $10.1 million decrease is attributable to the reserves for the interest component of the IRS 1995-1999 audit settlement, which offset interest expense and had no impact on income from continuing operations. Income taxes also decreased by $5.9 million due to the allocation of tax benefits from holding company losses pursuant to Great Plains Energy’s intercompany tax allocation agreement with its subsidiaries, including the Company.

SIGNIFICANT BALANCE SHEET CHANGES (DECEMBER 31, 2005 COMPARED TO DECEMBER 31, 2004)

·	Fuel inventories decreased $4.0 million primarily due to $9.3 million in fewer coal deliveries resulting from railroad performance issues partially offset by an increase in coal due to physical inventory adjustments.

·	Deferred income taxes - current assets decreased $3.9 million partially due to a lower nuclear fuel outage reserve resulting from the completion of the scheduled spring 2005 refueling.

·	Other - nonutility property and investments decreased $12.9 million primarily due to KCP&L receiving a return of its net investment from the Central Interstate Low Level Radioactive Waste Compact Commission.

·	Construction work in progress increased $47.1 million due to $25.3 million in contract payments related to wind generation and environmental equipment upgrades and normal construction activity.

Regulatory assets increased $35.6 million primarily due to the regulatory accounting treatment for pension expense and the change in Wolf Creek depreciable life for Missouri regulatory purposes in accordance with MPSC and KCC orders. Additionally, adopting FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations” during 2005 increased regulatory assets $13.2 million.

·	Other - deferred charges and other assets increased $7.0 million primarily due to a reclass from accrued taxes of an $8.8 million income tax refund receivable that management expects to be delayed until the related IRS audit cycle can be completed.

·	Commercial paper increased $31.9 million primarily due to $25.3 million in contract payments related to wind generation and environmental equipment upgrades and timing of cash payments.

·	Accounts payable increased $21.9 million primarily due to timing of cash payments.

·	Accrued taxes decreased $7.0 million due to the timing of tax payments partially offset by an increase related to a reclass of an $8.8 million income tax refund receivable to other deferred charges and other assets.

·	Asset Retirement Obligations (AROs) increased $32.2 million primarily due to $11.3 million related to revised decommissioning cost estimates for Wolf Creek, $7.5 million of accretion and a $15.4 million addition due to adopting FIN No. 47 during 2005.

·	Regulatory liabilities increased $65.5 million primarily due to KCP&L’s regulatory treatment of SO₂ emission allowance sales totaling $61.0 million and $4.3 million of additional Wolf Creek amortization for Missouri regulatory purposes. See Note 5 to the consolidated financial statements.

·	Derivative instruments - deferred credits and other liabilities increased $2.6 million due to a change in the fair value of KCP&L’s interest rate swaps on its 1998 Series A, B and D Environmental Improvement Revenue Refunding (EIRR) bonds.

·	Other - deferred credits and other liabilities decreased $4.4 million primarily due to KCP&L receiving a return of its net investment from the Central Interstate Low Level Radioactive Waste Compact Commission.

·	Accumulated other comprehensive loss decreased $10.4 million primarily due to the fair values of the Treasury Locks (T-Locks), which were entered into and settled during 2005. See Note 20 to the consolidated financial statements.

Long-term debt increased $186.1 million primarily due to a $250.0 million issuance of senior notes and an $85.9 million issuance of Series 2005 EIRR bonds partially offset by the $145.3 million redemption of debt related to the buyout of the Combustion Turbine Synthetic Lease. EIRR bonds classified as current and current maturities decreased as a result of the repayment and remarketing of the respective bonds.

Capital Requirements and Liquidity

Capital requirements are principally comprised of KCP&L’s utility construction and other capital expenditures and debt maturities. These items as well as additional cash and capital requirements for the Company are discussed below.

Liquid resources at December 31, 2005, consisted of $3.0 million of cash and cash equivalents on hand and unused bank lines of credit of $218.1 million from KCP&L's revolving credit facility. See the Debt Agreements section below for more information on this agreement. At February 28, 2006, unused bank lines of credit had increased $9.3 million from the amount at December 31, 2005.

KCP&L expects to meet day-to-day cash flow requirements including interest payments, construction requirements (excluding its comprehensive energy plan), dividends to Great Plains Energy and pension benefit plan funding requirements, discussed below, with internally generated funds. KCP&L might not be able to meet these requirements with internally generated funds because of the effect of inflation on operating expenses, the level of MWh sales, regulatory actions, compliance with future environmental regulations and the availability of generating units. The funds needed to retire maturing debt will be provided from operations, the issuance of long and short-term debt and/or capital contributions from Great Plains Energy. In addition, the Company may issue debt or utilize capital contributions from Great Plains Energy to finance growth or take advantage of new opportunities.

KCP&L currently expects to fund its comprehensive energy plan from a combination of internal and external sources including, but not limited to, contributions from rate increases, capital contributions to KCP&L from Great Plains Energy's proceeds of new equity financing and 2004 FELINE PRIDES^SM equity in 2007, new debt financing, and internally generated funds.

Cash Flows from Operating Activities

The Company generated positive cash flows from operating activities for the periods presented. Cash flows from operating activities increased during 2005 compared to 2004 primarily due to sales of SO₂ emission allowances totaling $61.0 million and a $12.0 million cash settlement on the T-Locks, discussed in significant financing activities. Net income after consideration of non-cash items decreased primarily due to the decrease in operating income discussed in results of operations. The timing of the Wolf Creek outage affects the refueling outage accrual, deferred income taxes and amortization of nuclear fuel.

Cash flow from operating activities increased in 2004 compared to 2003 partially due to a $26.1 million increase in net income and the changes in working capital detailed in Note 2 to the consolidated financial statements. In addition, the timing of the Wolf Creek outage affects the refueling outage accrual, deferred income taxes and amortization of nuclear fuel.

Cash Flows from Investing Activities

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.

Utility capital expenditures increased $141.6 million during 2005 compared to 2004. KCP&L exercised its early termination option in the Combustion Turbine Synthetic Lease and subsequently paid $154.0 million to purchase the leased property and made contract payments totaling $25.3 million related to wind generation and environmental equipment upgrades. These payments were partially offset by the $28.5 million buyout of KCP&L’s operating lease for vehicles and heavy equipment in 2004. The increases in capital expenditures were partially offset by KCP&L’s receipt of $10.0 million for insurance recoveries related to Hawthorn No. 5 during 2005.

Utility capital expenditures increased $41.9 million in 2004 compared to 2003 primarily due to the $28.5 million buyout of KCP&L’s operating lease for vehicles and heavy equipment in 2004. Insurance recoveries and litigation settlements related to Hawthorn No. 5 in 2004 of $31.9 million, a $10.7 million increase over 2003 recoveries, offset cash used in investing activities.

Cash Flows from Financing Activities

The changes in cash flows from financing activities in 2005 compared to 2004 and in 2004 compared to 2003 reflect KCP&L’s retirement of $54.5 million of its medium-term notes and its redemption of $154.6 million of 8.3% Junior Subordinated Deferred Interest Bonds from KCPL Financing I during 2004. KCPL Financing I used those proceeds to redeem the $4.6 million common securities held by KCP&L and the $150.0 million of 8.3% Trust Preferred Securities. These 2004 financing activities were offset by $225.0 million in equity contributions from Great Plains Energy.

During 2005, KCP&L redeemed its secured 1994 series EIRR bonds totaling $35.9 million by issuing secured EIRR Bonds Series 2005 also totaling $35.9 million: $14.0 million at a fixed rate of 4.05% until maturity at March 1, 2015, and $21.9 million at a fixed rate of 4.65% until maturity at September 1, 2035. KCP&L also redeemed its unsecured Series C EIRR bonds totaling $50.0 million by issuing unsecured EIRR Bonds Series 2005 also totaling $50.0 million at a fixed rate of 4.65% until maturity at September 1, 2035. The previous interest rate periods on these two series, with interest rates of 2.25% and 2.38%, respectively, expired on August 31, 2005. Both of the redeemed series were classified as current liabilities at December 31, 2004. Both of the new EIRR Bonds Series 2005 are covered by municipal bond insurance policies issued by XL Capital Assurance Inc.

(XLCA). The insurance agreements between KCP&L and XLCA provide for reimbursement by KCP&L for any amounts that XLCA pays under the municipal bond insurance policies. The insurance policies are in effect for the term of the bonds. 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, 2005, 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 requires KCP&L to provide XLCA with $50 million of general mortgage bonds as collateral for KCP&L’s obligations under the insurance agreement in the event KCP&L issues general mortgage bonds (other than refundings of outstanding general mortgage bonds) resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. In the event of a default under the insurance agreements, XLCA may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.

KCP&L had $625.0 million of outstanding unsecured senior notes at December 31, 2005 and 2004. During 2005, KCP&L completed a private placement of $250.0 million of 6.05% unsecured senior notes, maturing in 2035. The proceeds from the issuance were used to repay the 7.125% unsecured senior notes that matured in 2005. Pursuant to its obligations under a registration rights agreement entered into in connection with the private placement, KCP&L is filing an S-4 registration statement, of which this prospectus is a part.

Significant Financing Activities

KCP&L’s long-term financing activities are subject to the authorization of the MPSC. In November 2005, the MPSC authorized KCP&L to issue up to $635 million of long-term debt and to enter into interest rate hedging instruments in connection with such debt through December 31, 2009. Under stipulations with the MPSC and the KCC, KCP&L maintains common equity at not less than 35% of total capitalization.

In February 2006, FERC authorized KCP&L to issue up to $300.0 million in outstanding short-term debt instruments through February 2008. 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.

During the first quarter of 2006, KCP&L entered into a Forward Starting Swap with a notional principal amount of $110 million to hedge interest rate volatility on the first $110 million of the anticipated refinancing of KCP&L’s $225 million senior notes that mature in March 2007.

During 2005, KCP&L entered into two T-Locks to hedge against interest rate fluctuations on the U.S. Treasury rate component of the $250.0 million 30-year long-term debt that KCP&L issued in 2005. The T-Locks settled simultaneously with the issuance of the long-term fixed rate debt and KCP&L received $12.0 million in cash for the settlement. See Note 20 to the consolidated financial statements.

During 2005, KCP&L entered into a revolving agreement to sell all of its retail electric accounts receivable to Receivables Company, which sold an undivided percentage ownership interest in the accounts receivable to an outside investor. Receivables Company received $70 million in cash from the outside investor, which was forwarded to KCP&L as consideration for its sale. KCP&L’s accounts receivable agreement is an additional source of liquidity with an all-in borrowing cost generally equal to or lower than KCP&L’s other sources of short-term borrowings including the revolving credit facility and commercial paper. See Note 3 to the consolidated financial statements for additional information.

Debt Agreements

KCP&L has a $250 million revolving credit facility with a group of banks that expires in December 2009 to provide support for its issuance of commercial paper and other general purposes. The facility contains a Material Adverse Change (MAC) clause that requires KCP&L to represent, prior to receiving funding, that no MAC has occurred. The clause does, however, permit KCP&L to access the facility even in the event of a MAC in order to repay maturing commercial paper. Available liquidity under this facility is not impacted by a decline in credit ratings unless the downgrade results in a MAC or occurs in the context of a merger, consolidation or sale. A default by KCP&L on other indebtedness totaling more than $25.0 million is a default under the current facility. Under the terms of the agreement, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At December 31, 2005, KCP&L was in compliance with this covenant. At December 31, 2005, KCP&L had $31.9 million of commercial paper outstanding and no cash borrowings under the facility. The weighted-average interest rate of the commercial paper was 4.35%.

KCP&L Projected Utility Capital Expenditures

KCP&L’s utility capital expenditures, excluding allowance for funds used to finance construction, were $332.1 million, $190.5 million and $148.7 million in 2005, 2004 and 2003, respectively. Utility capital expenditures projected for the next three years, excluding allowance for funds used during construction, are detailed in the following table..


	2006		2007		2008
	(millions)
Generating facilities
Iatan No. 2 ^(a)	$	30.7	$	120.4	$	274.5
Wind generation ^(a)		143.0		-		-
Environmental ^(a)		43.3		124.8		101.3
Other		49.3		53.1		53.9
Total generating facilities	266.3			298.3		429.7
Distribution and transmission facilities
Customer programs & asset management ^(a)	5.6			9.1		14.9
Other		93.4		83.9		84.4
Total distribution and transmission facilities		99.0		93.0		99.3
Nuclear fuel		20.9		25.2		1.1
General facilities		30.6		20.5		11.8
Total	$	416.8	$	437.0	$	541.9
^(a)Comprehensive energy plan

This utility capital expenditure plan is subject to continual review and change and includes utility capital expenditures related to KCP&L’s comprehensive energy plan for environmental investments and new capacity. See Note 5 to the consolidated financial statements.

Pensions

KCP&L does not have a pension plan; however, KCP&L employees and officers participate in Great Plains Energy’s pension plans. Great Plains Energy maintains defined benefit pension plans for substantially all employees, including officers, of KCP&L, Great Plains Energy Services Incorporated (Services) and Wolf Creek Nuclear Operating Corporation (WCNOC). KCP&L incurs significant costs in contributing to the plans. At a minimum, plans are funded on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants consistent with the funding requirements of the Employee Retirement Income Security Act of 1974 (ERISA) and further contributions may be made when deemed financially advantageous.

The Company contributed $13.8 million to the plans in 2005, which included $9.3 million of funding above the minimum ERISA funding requirements. In 2004, the Company contributed $32.7 million to the plans, which included $28.6 million of funding above the minimum ERISA funding requirements. The Company expects to contribute $20.0 million to the plans in 2006, which includes $6.0 million to meet ERISA funding requirements. Management believes the Company and Great Plains Energy have adequate access to capital resources through cash flows from operations or through existing lines of credit to support the funding requirements. Participants in the plans may request a lump-sum cash payment upon termination of their employment. A change in payment assumptions could result in increased cash requirements from pension plan assets with the Company being required to accelerate future funding.

Legislative changes have been proposed that would alter the manner in which pension plan assets and liabilities are valued for purposes of calculating required pension contributions and change the timing and manner in which required contributions to underfunded plans are made. If these proposals are adopted, the funding requirements could be significantly affected.

Under the terms of the pension plans, Great Plains Energy reserves the right to amend or terminate the plans, and from time to time benefits have changed. See Note 8 to the consolidated financial statements for additional information.

Credit Ratings

At December 31, 2005, the major credit rating agencies rated the Company’s securities as detailed in the following table.


	Moody's	Standard
	Investors Service	and Poor's
Outlook	Stable	Stable
Senior Secured Debt	A2	BBB
Senior Unsecured Debt	A3	BBB
Commercial Paper	P-2	A-2

The ratings presented reflect the current views of these rating agencies and are subject to change. The Company views maintenance of strong credit ratings as being extremely important and to that end an active and ongoing dialogue is maintained with the agencies with respect to the Company’s results of operations, financial position, and future prospects.

None of the Company’s outstanding debt requires the acceleration of interest and/or principal payments in the event of a ratings downgrade, unless the downgrade occurs in the context of a merger, consolidation or sale. In the event of a downgrade, the Company may be subject to increased interest costs on credit facilities. Additionally, in KCP&L’s bond insurance policies on its secured 1992 series EIRR bonds totaling $31.0 million, its Series 1993A and 1993B EIRR bonds totaling $79.5 million and its secured and unsecured EIRR Bonds Series 2005 totaling $35.9 million and $50.0 million, respectively, KCP&L has agreed to limits on its ability to issue additional mortgage bonds based on the mortgage bond’s credit ratings. See Note 18 to the consolidated financial statements.

Supplemental Capital Requirements and Liquidity Information

The information in the following table is provided to summarize cash obligations and commercial commitments.


Payment due by period	2006		2007		2008		2009		2010		After 2010			Total
Long-term debt	(millions)
Principal	$	-	$	225.5	$	-	$	-	$	-		$	755.3	$	980.8
Interest		54.2		43.4		40.6		40.6		40.6			541.1		760.5
Lease obligations		15.9		14.4		14.0		10.5		8.4			91.0		154.2
Pension plans		20.0		-		-		-		-			-		20.0
Purchase obligations
Fuel		107.9		99.9		91.5		46.0		32.3			37.7		415.3
Purchased capacity		5.4		6.8		7.8		8.2		5.4			18.6		52.2
Other		33.6		5.6		2.9		-		-			-		42.1
Total contractual obligations	$	237.0	$	395.6	$	156.8	$	105.3	$	86.7		$	1,443.7	$	2,425.1

Long-term debt includes current maturities. Long-term debt principal excludes $1.8 million discount on senior notes and the $2.6 million liability for the fair value adjustment to the EIRR bonds related to interest rate swaps. Variable rate interest obligations are based on rates as of December 31, 2005. See Note 18 to the consolidated financial statements for additional information.

Lease obligations include capital and operating lease obligations; capital lease obligations are $0.2 million per year for the years 2006 through 2010 and total $3.9 million after 2010. Lease obligations also include railcars to serve jointly-owned generating units where KCP&L is the managing partner. KCP&L will be reimbursed by the other owners for approximately $2.0 million per year ($22.7 million total) of the amounts included in the table above. See Note 12 to the consolidated financial statements for additional information regarding contractual commitments.

KCP&L expects to contribute $20.0 million to the pension plans in 2006, which includes $6.0 million to meet ERISA funding requirements. Minimum ERISA funding requirements for future periods after 2006 are not yet known.

Fuel represents KCP&L’s 47% share of Wolf Creek nuclear fuel commitments, KCP&L’s share of coal purchase commitments based on estimated prices to supply coal for generating plants and KCP&L’s share of rail transportation commitments for moving coal to KCP&L’s generating units.

KCP&L purchases 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 $11.4 million for 2006, $11.2 million per year for 2007 through 2010 and $12.3 million after 2010.

Other purchase obligations represent individual commitments entered into in the ordinary course of business.

The Company has long-term liabilities recorded on its consolidated balance sheet at December 31, 2005, under GAAP that do not have a definitive cash payout date and are not included in the table above.

Off-Balance Sheet Arrangements

KCP&L is contingently liable for guaranteed energy savings under an agreement with a customer, guaranteeing an aggregate value of approximately $3.9 million over the next four years. A subcontractor would indemnify KCP&L for any payments made by KCP&L under this guarantee. Approximately $1 million of the guarantee expires each year in 2006 through 2009.

KCP&L also has guarantees related to bond insurance policies that KCP&L has as a credit enhancement to its secured 1992 series EIRR bonds totaling $31.0 million, its Series 1993A and 1993B EIRR bonds totaling $79.5 million and EIRR Bond Series 2005 totaling $85.9 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.

Quantitative and Qualitative Disclosures about Market Risk

In the normal course of business, the Company faces 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 “Risk Factors” and discussion throughout “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further discussion of the Company’s risk factors.

The Company is 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 normal course of business, under the direction and control of an internal risk management committee, the Company’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 to be effective, it is not possible to identify and eliminate all risk. The Company 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.

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. The Company maintains commodity-price risk management strategies that use derivative instruments to minimize significant, unanticipated net income fluctuations caused by commodity price volatility.

Interest Rate Risk

The Company manages 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 be used to achieve the desired combination. Using outstanding balances and annualized interest rates as of December 31, 2005, a hypothetical 10% increase in the interest rates associated with long-term variable rate debt would result in an increase of less than $1.1 million in interest expense for 2006. Additionally, interest rates impact the fair value of long-term debt. Also, KCP&L had $31.9 million of commercial paper outstanding at December 31, 2005. The principal amount, which will vary during the year, of the commercial paper will drive KCP&L’s commercial paper interest expense. Assuming that $31.9 million of commercial paper was outstanding for all of 2006, a hypothetical 10% increase in commercial paper rates would result in an increase of less than $0.2 million in interest expense for 2006. A change in interest rates would impact the Company to the extent it redeemed any of its outstanding long-term debt. Book value of long-term debt was 1% below fair values at December 31, 2005.

Commodity Risk

KCP&L engages in the wholesale marketing of electricity and is exposed to risk associated with the price of electricity. KCP&L's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity and long, intermediate and short-term capacity or power purchase agreements. The agreements contain penalties for non-performance to limit KCP&L’s energy price risk on the contracted energy. KCP&L also enters into additional power purchase agreements 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 its generation assets and capacity and power purchase agreements to protect it 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 $5.3 million decrease in operating income for 2006 related to purchased power. In 2006, approximately 77% of KCP&L’s net MWhs generated are expected to be coal-fired. KCP&L currently has all of its coal requirements for 2006 under contract. A hypothetical 10% increase in the market price of coal could result in less than a $1.0 million increase in fuel expense for 2006. 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 $2.4 million in fuel expense for 2006. At December 31, 2005, KCP&L did not have any of its 2006 projected natural gas usage for generation requirements to serve retail load and firm MWh sales hedged. KCP&L had slightly under half of its 2005 projected natural gas usage for generation requirements to serve retail load and firm MWh sales hedged at December 31, 2004.

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, 2005, 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 $4.2 million reduction in the value of the decommissioning trust funds at December 31, 2005. A hypothetical 10% decrease in equity prices would have resulted in a $4.4 million reduction in the fair value of the equity securities at December 31, 2005. 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.

BUSINESS

The Company

KCP&L, a Missouri corporation incorporated in 1922, is an integrated, regulated electric utility, which provides electricity to customers primarily in the states of Missouri and Kansas. The Company’s wholly owned subsidiary, HSS, sold its wholly owned subsidiary Worry Free in February 2005 and completed the disposition of its interest in RSAE in June 2003. After these sales, HSS has no active operations.

All of KCP&L’s common stock is owned by Great Plains Energy Incorporated (Great Plains Energy), a Missouri corporation headquartered in Kansas City, Missouri. Great Plains Energy is a public utility holding

company and does not own any significant assets other than the stock of its subsidiaries. In addition to KCP&L, Great Plains Energy owns subsidiaries which, among other things, provide competitive retail electricity supply services in several electricity markets offering retail choice and hold investments in affordable housing limited partnerships.

Business Segments

The Company’s sole reportable business segment is KCP&L. For information regarding the revenues, income and assets attributable to the Company's reportable business segment, see Note 16 to the consolidated financial statements. Comparative financial information and discussion regarding KCP&L’s reportable business segment can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

KCP&L

KCP&L, headquartered in Kansas City, Missouri, engages in the generation, transmission, distribution and sale of electricity. KCP&L serves approximately 500,000 customers located in all or portions of 24 counties in western Missouri and eastern Kansas. Customers include approximately 440,000 residences, over 55,000 commercial firms, and over 2,200 industrials, municipalities and other electric utilities. KCP&L’s retail revenues averaged approximately 82% of its total operating revenues over the three years ended December 31, 2005. Wholesale firm power, bulk power sales and miscellaneous electric revenues accounted for the remainder of utility revenues. KCP&L is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter.

Capital Program and Financing

For information on KCP&L’s capital program and financial needs, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations--Capital Requirements and Liquidity” and Notes 17 and 18 to the consolidated financial statements.

Comprehensive Energy Plan

For a discussion of KCP&L’s comprehensive energy plan, please refer to the Comprehensive Energy Plan section in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 5 to the consolidated financial statements.

Regulation

KCP&L is regulated by the MPSC and the KCC with respect to retail rates, certain accounting matters, standards of service and, in certain cases, the issuance of securities, certification of facilities and service territories. KCP&L is classified as a public utility under the Federal Power Act and accordingly, is subject to regulation by the FERC. By virtue of its 47% ownership interest in Wolf Creek Generating Station (Wolf Creek), KCP&L is subject to regulation by the NRC with respect to licensing, operations and safety-related requirements.

Missouri jurisdictional retail revenues averaged 57% of KCP&L’s total retail revenue over the last three years. Kansas jurisdictional retail revenues averaged 43% of KCP&L’s total retail revenue over the last three years. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies” and Note 5 to the consolidated financial statements for additional information concerning regulatory matters.

Missouri and Kansas Rate Case Filings

In February 2006, KCP&L filed rate cases with the MPSC and the KCC. For information on these rate cases, see Note 5 to the consolidated financial statements for additional discussion of KCP&L’s comprehensive energy plan.

Southwest Power Pool Regional Transmission Organization

Under FERC Order 2000, KCP&L, as an investor-owned utility, is strongly encouraged to join a FERC approved Regional Transmission Organization (RTO). See Note 5 to the consolidated financial statements for further information. On March 20, 2006, FERC issued an order rejecting in part, conditionally accepting in part and suspending the start of the Southwest Power Pool, Inc. (SPP) energy imbalance market for five months from the requested date of May 1, 2006. Guidance was provided on several issues considered critical to the successful implementation of this stage of the market. KCP&L will continue preparation for this new start-up date.

Competition

Missouri and Kansas continue on the fully integrated utility model and no legislation authorizing retail choice has been introduced in Missouri or Kansas for several years. As a result, KCP&L does not compete with others to supply and deliver electricity in its franchised service territory, although other sources of energy can provide alternatives to KCP&L’s customers. If Missouri or Kansas were to pass and implement legislation authorizing or mandating retail choice, KCP&L may no longer be able to apply regulated utility accounting principles to deregulated portions of its operations and may be required to write off certain regulatory assets and liabilities.

KCP&L does compete in the wholesale market to sell power in circumstances when power generated is not required for customers in its service territory. KCP&L competes in this regard with other owners of generating stations, principally utilities in its region, on the basis of availability and price. In recent years these wholesale sales have been an important source of revenues to KCP&L.

Power Supply

KCP&L is a member of the SPP reliability region. As one of the ten regional members of the North American Electric Reliability Council, SPP is responsible for maintaining reliability in its area through coordination of planning and operations. As a member of the SPP, KCP&L is required to maintain a capacity margin of at least 12% of its projected peak summer demand. This net positive supply of capacity and energy is maintained through its generation assets and capacity, power purchase agreements and peak demand reduction programs. The capacity margin is designed to ensure the reliability of electric energy in the SPP region in the event of operational failure of power generating units utilized by the members of the SPP.

KCP&L’s maximum system net hourly summer peak load of 3,610 MW occurred on August 21, 2003. The maximum winter peak load of 2,563 MW occurred on December 7, 2005. During 2005, the summer peak load was 3,512 MW. The projected peak summer demand for 2006 is 3,595 MW. KCP&L expects to meet its projected capacity requirements for the years 2006 through 2009 with its generation assets and through short-term capacity purchases, additional demand-side management and efficiency programs and the addition of wind generation. As part of its comprehensive energy plan, KCP&L expects to have Iatan No. 2 in service in 2010.

Fuel

The principal sources of fuel for KCP&L’s electric generation are coal and nuclear fuel. KCP&L expects, with normal weather, to satisfy approximately 98% of its 2006 fuel requirements from these sources with the remainder provided by natural gas and oil. The actual 2005 and estimated 2006 fuel mix and delivered cost in cents per net kWh generated are in the following table.


						Fuel cost in cents per
	Fuel Mix ^(a)					net kWh generated
	Estimated			Actual		Estimated	Actual
Fuel	2006			2005		2006	2005
Coal		77	%	77	%	1.24	1.01
Nuclear		21		21		0.44	0.44
Natural gas and oil		2		2		11.15	8.29
Total Generation		100	%	100	%	1.22	1.06
^(a)Fuel mix based on percent of total MWhs generated.

Less than 1% of KCP&L’s rates contain an automatic fuel adjustment clause. Consequently, to the extent the price of coal, coal transportation, nuclear fuel, nuclear fuel processing, natural gas or purchased power increase significantly after the expiration of the contracts described in this section, or if KCP&L’s lower fuel cost units do not meet anticipated availability levels, KCP&L’s net income may be adversely affected until the increased cost could be reflected in rates.

Coal

During 2006, KCP&L’s generating units, including jointly owned units, are projected to burn approximately 13.5 million tons of coal. KCP&L has entered into coal-purchase contracts with various suppliers in Wyoming's Powder River Basin (PRB), the nation's principal supply region of low-sulfur coal, and with local suppliers. These contracts will satisfy all projected coal requirements for 2006 and 2007 and 84%, 35% and 22% respectively, for 2008 through 2010. The remainder of KCP&L’s coal requirements will be fulfilled through additional contracts or spot market purchases. KCP&L has entered into its coal contracts over time at higher average prices affecting coal costs for 2006 and beyond.

KCP&L has also entered into rail transportation contracts with various railroads for moving coal from the PRB to its generating units. These contracts will satisfy approximately all of the projected requirements for 2006 and 2007 and 98%, 78% and 77%, respectively, for 2008 through 2010; however, KCP&L has been experiencing coal delivery issues. Coal transportation costs are expected to increase in 2006 and beyond. See Note 14 to the consolidated financial statements regarding a rate complaint case against Union Pacific Railroad Company. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Overview” for additional information.

Nuclear Fuel

KCP&L owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek, its only nuclear generating unit. Wolf Creek purchases uranium and has it processed for use as fuel in its reactor. This is a three step process that involves conversion of uranium concentrates to uranium hexafluoride, enrichment of uranium hexafluoride and fabrication of nuclear fuel assemblies. The owners of Wolf Creek have on hand or under contract 100% of the uranium and conversion services needed to operate Wolf Creek through September 2009. The owners also have under contract 100% of the uranium enrichment required to operate Wolf Creek through March 2008. Fabrication requirements are under contract through 2024. Letters of intent have been issued with suppliers for a substantial portion of Wolf Creek’s uranium, conversion and enrichment requirements extending through at least 2017.

All uranium, uranium conversion and uranium enrichment arrangements, as well as the fabrication agreement, have been entered into in the ordinary course of business. However, contraction and consolidation

among suppliers of these commodities and services, coupled with increasing worldwide demand and past inventory drawdowns, have introduced some uncertainty as to Wolf Creek's ability to replace some of these contracts in the event of a protracted supply disruption. Management believes this potential problem is common to the nuclear industry. Accordingly, in the event the affected contracts were required to be replaced, KCP&L’s and Wolf Creek's management believe the industry and government would work together to minimize disruption of the nuclear industry's operations, including Wolf Creek's operations.

See Note 4 to the consolidated financial statements for additional information regarding nuclear plant.

Natural Gas

KCP&L is projecting decreased use of natural gas during 2006 as a result of KCP&L’s projected normal summer weather and fewer plant outages in 2006. KCP&L has hedged approximately 45% of its 2006 projected natural gas usage for generation requirements to serve retail load and firm MWh sales.

Purchased Power

At times, KCP&L purchases power to meet its customers’ needs. Management believes KCP&L will be able to obtain enough power to meet its future demands due to the coordination of planning and operations in the SPP region; however, price and availability of power purchases may be impacted during periods of high demand. KCP&L’s purchased power, as a percent of MWh requirements, averaged approximately 5% for 2005, 2004 and 2003.

Environmental Matters

KCP&L’s operations are subject to regulation by federal, state and local authorities with regard to air and other environmental matters. The generation and transmission of electricity produces and requires disposal of certain hazardous products that are subject to these laws and regulations. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. Failure to comply with these laws and regulations could have a material adverse effect on KCP&L.

KCP&L operates in an environmentally responsible manner and seeks to use current technology to avoid and treat contamination. KCP&L regularly conducts environmental audits designed to ensure compliance with governmental regulations and to detect contamination. Environmental-related legislation is continuously introduced in Congress. Such legislation typically includes various compliance dates and compliance limits. Such legislation could have the potential for a significant financial impact on KCP&L, including the installation of new pollution control equipment to achieve compliance. However, KCP&L would seek recovery of capital costs and expenses for such compliance through rates. KCP&L will continue to monitor proposed legislation. See Note 12 to the consolidated financial statements for additional information regarding environmental matters.

Employees

At December 31, 2005, the Company had 2,078 employees, including 1,335 represented by three local unions of the International Brotherhood of Electrical Workers (IBEW). KCP&L has labor agreements with Local 1613, representing clerical employees (expires March 31, 2008), with Local 1464, representing transmission and distribution workers (expires January 31, 2009), and with Local 412, representing power plant workers (expires February 28, 2007).

Properties

KCP&L Generation Resources


			Year	Estimated 2006			Primary
		Unit	Completed	MW Capacity			Fuel
Base Load		Wolf Creek	1985		548	^(a)	Nuclear
		Iatan No. 1	1980		456	^{(a) (b)}	Coal
		LaCygne No. 2	1977		341	^(a)	Coal
		LaCygne No. 1	1973		370	^(a)	Coal
		Hawthorn No. 5 ^(c)	1969		563		Coal
		Montrose No. 3	1964		176		Coal
		Montrose No. 2	1960		164		Coal
		Montrose No. 1	1958		170		Coal
Peak Load		West Gardner Nos. 1, 2, 3 and 4 ^(e)	2003		308		Natural Gas
		Osawatomie ^(e)	2003		77		Natural Gas
		Hawthorn No. 9 ^(d)	2000		130		Natural Gas
		Hawthorn No. 8 ^(e)	2000		77		Natural Gas
		Hawthorn No. 7 ^(e)	2000		77		Natural Gas
		Hawthorn No. 6 ^(e)	1997		136		Natural Gas
		Northeast Nos. 17 and 18 ^(e)	1977		117		Oil
		Northeast Nos. 15 and 16 ^(e)	1975		116		Oil
		Northeast Nos. 13 and 14 ^(e)	1976		114		Oil
		Northeast Nos. 11 and 12 ^(e)	1972		111		Oil
		Northeast Black Start Unit	1985		2		Oil
Total					4,053
^(a)	KCP&L's share of a jointly owned unit.
^(b)	The Iatan No. 2 air permit limits KCP&L's accredited capacity of Iatan No. 1 to 456 MWs from 469 MWs
	until the air quality control equipment included in the comprehensive energy plan is operational.
^(c)	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.
(d)	Heat Recovery Steam Generator portion of combined cycle.
^(e)	Combustion turbines.

KCP&L owns the Hawthorn Station (Jackson County, Missouri), Montrose Station (Henry County, Missouri), Northeast Station (Jackson County, Missouri), West Gardner Station (Johnson County, Kansas) and Osawatomie Station (Miami County, Kansas). KCP&L also owns 50% of the 740 MW LaCygne No. 1 and 682 MW LaCygne No. 2 (Linn County, Kansas), 70% of the 651 MW Iatan No. 1 (Platte County, Missouri) and 47% of the 1,166 MW Wolf Creek Unit (Coffey County, Kansas). See Note 5 to the consolidated financial statements for information regarding KCP&L’s comprehensive energy plan and the proposed addition of new capacity.

KCP&L Transmission and Distribution Resources

KCP&L’s electric transmission system interconnects with systems of other utilities for reliability and to permit wholesale transactions with other electricity suppliers. KCP&L owns over 1,700 miles of transmission lines, approximately 9,000 miles of overhead distribution lines and over 3,700 miles of underground distribution lines in Missouri and Kansas. KCP&L has all the franchises necessary to sell electricity within the territories from which substantially all of its gross operating revenue is derived. KCP&L’s transmission and distribution systems are continuously monitored for adequacy to meet customer needs. Management believes the current systems are adequate to serve its customers.

KCP&L General

KCP&L’s principal plants and properties, insofar as they constitute real estate, are owned in fee simple. Certain other facilities are located on premises held under leases, permits or easements. KCP&L electric transmission and distribution systems are for the most part located over or under highways, streets, other public places or property owned by others for which permits, grants, easements or licenses (deemed satisfactory but without examination of underlying land titles) have been obtained.

Substantially all of the fixed property and franchises of KCP&L, which consists principally of electric generating stations, electric transmission and distribution lines and systems, and buildings subject to exceptions and reservations, are subject to a General Mortgage Indenture and Deed of Trust dated as of December 1, 1986. General mortgage bonds totaling $159.3 million were outstanding at December 31, 2005.

Legal Proceedings

Hawthorn No. 5 Litigation

KCP&L filed suit on April 3, 2001, in Jackson County, Missouri Circuit Court against multiple defendants who are alleged to have responsibility for the 1999 boiler explosion at KCP&L’s Hawthorn No. 5 generating unit, which was subsequently reconstructed and returned to service. KCP&L and National Union Fire Insurance Company of Pittsburgh, Pennsylvania (National Union) entered into a subrogation allocation agreement under which recoveries in this suit are generally allocated 55% to National Union and 45% to KCP&L. Certain defendants have been dismissed from the suit and various defendants settled, with KCP&L receiving a total of $38.2 million under the terms of the subrogation allocation agreement. Trial of this case with the one remaining defendant resulted in a March 2004 jury verdict finding KCP&L’s damages as a result of the explosion were $452 million. After deduction of amounts received from pre-trial settlements with other defendants and an amount for KCP&L’s comparative fault (as determined by the jury), the verdict would have resulted in an award against the defendant of approximately $97.6 million (of which KCP&L would have received $33 million pursuant to the subrogation allocation agreement after payment of attorney’s fees). In response to post-trial pleadings filed by the defendant, in May 2004, the trial judge reduced the award against the defendant to $0.2 million. Both KCP&L and the defendant have appealed this case to the Court of Appeals for the Western District of Missouri. Oral arguments occurred in February 2006 and an opinion is expected in the second quarter of 2006.

KCP&L Stipulations and Agreements

On March 28, 2005, and April 27, 2005, KCP&L filed Stipulations and Agreements with the MPSC and KCC, respectively, containing a regulatory plan and other provisions. The Stipulations and Agreements are discussed in Note 5 to the consolidated financial statements, which is incorporated herein by reference. Parties to the MPSC Stipulation and Agreement are KCP&L, the Staff of the MPSC, the City of Kansas City, Missouri, Office of Public Counsel, Praxair, Inc., Missouri Industrial Energy Consumers, Ford Motor Company, Aquila, Inc., The Empire District Electric Company, Missouri Joint Municipal Electric Utility Commission and the Missouri Department of Natural Resources. Parties to the KCC Stipulation and Agreement are KCP&L, the Staff of the KCC, Sprint Nextel Corporation and the Kansas Hospital Association.

The MPSC issued its Report and Order, approving the Stipulation and Agreement, on July 28, 2005, and the KCC issued its Order Approving Stipulation and Agreement on August 5, 2005. On September 22, 2005, the Sierra Club and Concerned Citizens of Platte County, two nonprofit corporations, filed a petition for review in the Circuit Court of Cole County, Missouri, seeking to review and set aside the MSPC Report and Order. On March 13, 2006, the Circuit Court affirmed the MPSC Order. This decision may be appealed to the Missouri Court of Appeals. On October 21, 2005, the Sierra Club filed a petition for review in the District Court of Shawnee County, Kansas, seeking to set aside or remand the KCC order. Although subject to the appeals, the MPSC and KCC orders remain in effect pending the courts’ decisions. The appeals are expected to be decided by the courts in 2006.

KCP&L Rate Cases

On February 1, 2006, KCP&L filed retail rate cases with the MPSC and KCC, requesting annual rate increases effective January 1, 2007, of approximately $55.8 million (11.5%) and $42.3 million (10.5%), respectively, over current levels. Hearings on these cases are expected to begin in September 2006 and the decisions of the MPSC and KCC are expected in December 2006.

Kansas City Power & Light Company v. Union Pacific Railroad Company

On October 12, 2005, KCP&L filed a rate complaint case with the Surface Transportation Board (STB) charging that Union Pacific Railroad Company’s (Union Pacific) rates for transporting coal from the PRB in Wyoming to KCP&L’s Montrose Station are unreasonably high. Prior to the end of 2005, the rates were established under a contract with Union Pacific. Efforts to extend the term of the contract were unsuccessful and Union Pacific is the only service for coal transportation from the PRB to Montrose Station. KCP&L charged that Union Pacific possesses market dominance over the traffic and requested the STB prescribe maximum reasonable rates. Management anticipates filing opening evidence by mid-year 2006 and the STB issuing its decision toward the end of 2007. Until the STB case is finalized, KCP&L is paying tariff rates subject to refund.

Framatome

In 2005, WCNOC filed a lawsuit on behalf of itself, KCP&L and the other two Wolf Creek owners against Framatome ANP, Inc., and Framatome ANP Richland, Inc. (Framatome) in the District Court of Coffey County, Kansas. The suit alleges various claims against Framatome related to the proposed design, licensing and installation of a digital control system. The suit seeks recovery of approximately $16 million in damages from Framatome. Framatome removed the case to U.S. District Court for the District of Kansas. Thereafter, the plaintiffs filed a motion to remand the case back to Coffey County District Court, which was granted. Framatome has filed a counterclaim against the three Wolf Creek owners seeking recovery of damages alleged to be in excess of $20 million.

MANAGEMENT AND DIRECTORS

The following table sets forth the names, ages (as of December 31, 2005) and titles of our board of directors and officers. All of the individuals in the following table identified as being officers have been officers or employees in a responsible position with us for the past five years except as noted under “Our Officers” below. The term of office of each officer commenced with his or her appointment by the board of directors and ends at such time as the board of directors may determine. There are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any other person involved in officer selection.

Name	Age	Position
Michael J. Chesser*	57	Chairman of the Board and Director
William H. Downey*	61	President and Chief Executive Officer and Director
Terry Bassham*	45	Chief Financial Officer
Lora C. Cheatum*	49	Vice President, Administrative Services
Michael W. Cline	44	Treasurer
F. Dana Crawford*	55	Vice President, Plant Operations
Barbara B. Curry*	51	Secretary
Stephen T. Easley*	50	Senior Vice President, Supply
Mark G. English	54	Assistant Secretary
Chris B. Giles*	52	Vice President, Regulatory Affairs
William P. Herdegen III*	51	Vice President, Customer Operations
John R. Marshall*	56	Senior Vice President, Delivery
35
Name	Age	Position
William G. Riggins*	47	Vice President, Legal and Environmental Affairs and General Counsel
Marvin L. Rollison	53	Vice President, Corporate Culture and Community Strategy
Richard A. Spring*	51	Vice President, Transmission
Lori A. Wright*	43	Controller
David L. Bodde	63	Director
Mark A. Ernst	47	Director
Randall C. Ferguson, Jr.	54	Director
Luis A. Jimenez	61	Director
James A. Mitchell	64	Director
William C. Nelson	68	Director
Linda H. Talbott	65	Director
* Designated an executive officer.

Our Officers

Michael J. Chesser. Mr. Chesser is Chairman of the Board and Chief Executive Officer - Great Plains Energy and Chairman of the Board - KCP&L (since October 2003). Previously he served as Chief Executive Officer of United Water (2002-2003); and President and Chief Executive Officer of GPU Energy (2000-2002). Mr. Chesser served as a member of the Executive committee in 2005. He has been a member of our board of directors since 2003.

William H. Downey. Mr. Downey is President and Chief Operating Officer - Great Plains Energy and President and Chief Executive Officer - KCP&L (since October 2003). Mr. Downey joined the Company in 2000 as Executive Vice President - Kansas City Power & Light Company and President - KCPL Delivery Company. Mr. Downey also serves on the board of Enterprise Financial Services Corp. and Grubb & Ellis Realty Advisors, Inc. He has been a member of our board of directors since 2003.

Terry Bassham. Mr. Bassham is Executive Vice President, Finance and Strategic Development and Chief Financial Officer - Great Plains Energy and Chief Financial Officer - KCP&L (since 2005). He was previously Executive Vice President, Chief Financial and Administrative Officer (2001-2005) and Executive Vice President and General Counsel (2000-2001) of El Paso Electric Company.

Lora C. Cheatum. Ms Cheatum is Vice President, Administrative Services (since 2005). She was previously Interim Vice President, Human Resources (2004-2005) and Director, Human Resources (2001-2004) of KCP&L, and Regional Human Resources Director (1999-2001) of McLane Distribution, a division of Wal-Mart.

Michael W. Cline. Mr. Cline is Treasurer and Chief Risk Officer - Great Plains Energy and Treasurer - KCP&L (since 2005). He was previously Treasurer of Great Plains Energy (2005), Assistant Treasurer of Great Plains Energy and KCP&L (2003-2005), Director, Corporate Finance (2001-2002), and Assistant Treasurer-Corporate Finance of Corning Inc. (2001).

F. Dana Crawford. Mr. Crawford is Vice President, Plant Operations (since 2005). He was previously Plant Manager (1994-2005) of KCP&L’s LaCygne Generating Station.

Barbara B. Curry. Ms. Curry is Senior Vice President, Corporate Services and Corporate Secretary - Great Plains Energy and Secretary - KCP&L (since 2005). She was previously Senior Vice President, Retail Operations (2003-2004), Executive Vice President, Global Human Resources (2001-2003) and Executive Vice President, Corporate Services (1997-2001) of TXU Corporation.

Stephen T. Easley. Mr. Easley is Senior Vice President, Supply (since 2000). He was previously Vice President, Generation Services (2002-2005), President and CEO of GPP (2001-2002) and Vice President -

Business Development of KCP&L Power Division (2000-2001). He was promoted to Senior Vice President, Supply of KCP&L in March 2005.

Mark G. English. Mr. English is General Counsel and Assistant Secretary - Great Plains Energy (since 2005) and Assistant Secretary - KCP&L (since 2003). He was previously Corporate Counsel and Assistant Secretary (2003-2005) and Corporate Counsel (2001-2003) of Great Plains Energy, and Vice President, General Counsel and Corporate Secretary of KLT Inc. (1997-2001).

Chris B. Giles. Mr. Giles is Vice President, Regulatory Affairs (since 2005). He was previously Senior Director, Regulatory Affairs and Business Planning (2004-2005) and Director, Regulatory Affairs of KCP&L (1993-2004).

William P. Herdegen III. Mr. Herdegen is Vice President, Customer Operations (since 2001). He was Chief Operating Officer of Laramore, Douglass and Popham, an engineering consulting company, (2001) and Vice President and Director of Utilities Practice of System Development Integration, a consulting company, (1999-2001).

John R. Marshall. Mr. Marshall is Senior Vice President, Delivery (since 2005). He was previously President of Coastal Partners, Inc., a strategy consulting company (2001-2005), Senior Vice President, Customer Service of Tennessee Valley Authority (2002-2004), and President of Duquesne Light Company (1999-2001).

William G. Riggins. Mr. Riggins is Vice President, Legal and Environmental Affairs and General Counsel (since 2000). He was previously General Counsel of Great Plains Energy (2000-2005).

Marvin L. Rollison. Mr. Rollison is Vice President, Corporate Culture and Community Strategy (since 2005). He was previously Supervisor-Engineering (2000-2005)

Richard A. Spring. Mr. Spring is Vice President, Transmission (since 1994).

Lori A. Wright. Ms. Wright is Controller of Great Plains and KCP&L (since 2002). She served as Assistant Controller of KCP&L from 2001 until named Controller in 2002 and was Director of Accounting and Reporting of American Electric Power Company, Inc. (2000-2001).

Our Board of Directors

Directors

Great Plains Energy, as our sole shareholder, elects our directors. Our directors are also directors of Great Plains Energy, and the board committees of Great Plains Energy function as our board committees. In addition to Mr. Chesser, who is our Chairman of the Board, and Mr. Downey, who is our President and Chief Executive Officer, the seven individuals listed below are all of our current directors and have consented to stand for election to the board of Great Plains Energy. If they are elected at the May 2, 2006 Great Plains Energy annual shareholders meeting to serve on the Great Plains Energy board, they will also be elected to our board to serve as directors until the next annual shareholders meeting and until their successors are elected and qualified. The committee information listed for each director refers to the Great Plains Energy board committees, which function as our board committees.

David L. Bodde. Dr. Bodde is the Senior Fellow and Professor, Arthur M. Spiro Center for Entrepreneurial Leadership at Clemson University (since 2004). He previously held the Charles N. Kimball Professor of Technology and Innovation (1996-2004) at the University of Missouri-Kansas City. He also serves on the board of The Commerce Funds. Dr. Bodde served as a member of the Executive, Audit and Governance committees during 2005. He has been a member of our board of directors since 1994.

Mark A. Ernst. Mr. Ernst is Chairman of the Board, President and Chief Executive Officer of H&R Block, Inc., a global provider of tax preparation, investment, mortgage and accounting services. He was elected Chairman of the Board in 2002, Chief Executive Officer in 2001 and President in 1999. Mr. Ernst also serves on the board of Knight Ridder, Inc. Mr. Ernst served on the Executive, Audit and Compensation and Development committees during 2005. He has been a member of our board of directors since 2000.

Randall C. Ferguson, Jr. Mr. Ferguson is the Senior Partner for Business Development for Tshibanda & Associates, LLC (since March 2005), a consulting and project management services firm committed to assisting clients to improve operations and achieve long-lasting, measurable results. Previously, he served as Senior Vice President Business Growth & Member Connections with the Greater Kansas City Chamber of Commerce (2003-2005) and the retired Senior Location Executive (1998-2003) for the IBM Kansas City Region. Mr. Ferguson served on the Audit and Governance committees during 2005. He has been a member of our board of directors since 2002.

Luis A. Jimenez. Mr. Jimenez is Senior Vice President and Chief Strategy Officer (since 2001) of Pitney Bowes Inc., a global provider of integrated mail and document management solutions. He served as Vice President, Global Growth and Future Strategy (1999-2001). Mr. Jimenez served on the Governance and Compensation and Development committees during 2005. He has been a member of our board of directors since 2001.

James A. Mitchell. Mr. Mitchell is the Executive Fellow-Leadership, Center for Ethical Business Cultures (since 1999), a not-for-profit organization, assisting business leaders in creating ethical and profitable cultures. Mr. Mitchell served on the Compensation and Development and Governance committees during 2005. He has been a member of our board of directors since 2002.

William C. Nelson. Mr. Nelson is Chairman (since 2001) of George K. Baum Asset Management, a provider of investment management services to individuals, foundations and institutions. He also serves on the board of DST Systems. Mr. Nelson served on the Executive, Audit and Compensation and Development committees during 2005. He has been a member of our board of directors since 2000.

Linda H. Talbott. Dr. Talbott is President of Talbott & Associates (since 1975), consultants in strategic planning, philanthropic management and development to foundations, corporations, and nonprofit organizations. She is also Chairman of the Center for Philanthropic Leadership. Dr. Talbott served as the Advising Director for Corporate Social Responsibility and on the Governance and Compensation and Development committees during 2005. She has been a member of our board of directors since 1983.

KCP&L Audit Committee

The KCP&L Board has designated the Audit Committee of the Great Plains Energy Board as the KCP&L Audit Committee for purposes of Section 10A of the Securities Exchange Act of 1934, as amended, and related rules. The members of the Audit Committee are Mark A. Ernst, David L. Bodde, Randall C. Ferguson, Jr., William K. Hall, William C. Nelson and Robert H. West. The Boards identified Messrs. Ernst, Hall, Nelson and West as “audit committee financial experts”, as that term is defined by the SEC pursuant to Section 407 of the Sarbanes-Oxley Act of 2002, and determined that those individuals are independent.

EXECUTIVE COMPENSATION

Summary Compensation Table

The following table contains compensation data for our executive officers named below, for fiscal years ended December 31, 2005, 2004 and 2003. The compensation shown is paid or payable for services in all capacities to Great Plains Energy and its subsidiaries, including KCP&L.


		Annual Compensation			Long Term Compensation
					Awards		Payouts
Name and Principal Position (a)	Year (b)	Salary ($) (c)	Bonus ($) (d)	Other Annual Compensation ($) (1) (e)	Restricted Stock Award(s) ($)(2) (f)	Securities Underlying Options/ SARs (#) (g)	LTIP Payouts ($) (3) (h)	All Other Compensation ($)(4) (i)
Michael J. Chesser Chairman of the Board	2005 2004 2003	610,000 550,000 137,500	555,707 495,535 123,750	- 311,436 -	- - 1,115,813	- - -	- - -	27,710 8,734 1,403
William H. Downey President and Chief Executive Officer	2005 2004 2003	440,000 400,000 325,000	395,292 270,292 219,375	- - -	- - 1,001,998	- - 5,249	85,947 - -	39,210 27,562 20,764
Terry Bassham Chief Financial Officer	2005 2004 2003	210,069 - -	141,998 - -	76,119 - -	275,942 - -	- - -	- - -	3,228 - -
Stephen T. Easley Senior Vice President- Supply	2005 2004 2003	250,000 225,000 210,000	147,798 116,684 94,500	- - -	302,000 - 128,378	- - 2,449	40,086 - -	14,381 11,972 10,737
John R. Marshall Senior Vice President- Delivery	2005 2004 2003	192,222 - -	347,657 - -	157,315 - -	636,635 - -	- - -	- - -	8,338 - -

(1) The executive officers named above received certain perquisites, which may include relocation costs, transportation allowances, a tax and financial planning allowance of up to $1,500, dues for one club and in limited situations, the expenses of spouses accompanying the executive officers. With the exception of Messrs. Marshall and Bassham in 2005 and Mr. Chesser in 2004, perquisites did not reach in any of the reported years the threshold for reporting of the lesser of either $50,000 or ten percent of salary and bonus set forth in the applicable SEC rules.

For 2005, amounts include:

Marshall: relocation costs of $151,115; transportation allowance of $4,200; club dues of $500; and tax/financial planning of $1,500.

Bassham: relocation costs of $69,173; transportation allowance of $5,400; club dues of $875; and spouse travel of $671.

For 2004, amounts include:

Chesser: relocation costs of $299,292; transportation allowance of $7,200; club dues of $1,150; and spouse travel of $3,794.

(2) At year-end 2005, amounts include:

Restricted Stock: The dollar value of the restricted stock awards shown in column (f) above is calculated by multiplying the number of shares awarded by the closing market price of the Great Plains Energy common stock on the date of the grant. The grants of restricted stock vest over time. Unvested grants of restricted stock are forfeited in the event the executive’s employment is terminated (except in the events of retirement, disability or death, in which cases the grants would be prorated for service during the restriction period).

Chesser: 12,135 shares vested October 1, 2005; 12,135 shares each vest on October 1, 2006 and October 1, 2007. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the remaining restricted stock was $678,589.

Downey: 8,825 shares vested October 1, 2005; 8,825 shares vest on October 1, 2006; and 8,826 shares vest on October 1, 2007. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the remaining restricted stock was $493,522.

Bassham: 9,083 shares vest March 28, 2008. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the restricted stock was $253,961.

Easley: 10,000 shares vest on February 1, 2008. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the restricted stock was $279,600.

Marshall: 20,275 shares of restricted stock were granted in 2005, vesting May 25, 2008. Dividends are reinvested with the same restrictions as the restricted stock. The value at December 31, 2005, of the restricted stock was $566,889.

(3) The LTIP Payouts for 2005 represent the value of common stock and cash dividends paid under 2003 Performance Shares for the period ended 2005. The value of the payouts are calculated as of February 7, 2006, the date the payouts were approved by the board.

(4) For 2005, amounts include:

Chesser: a contribution under the Great Plains Energy Employee Savings Plus Plan -- $6,300; a contribution under the Great Plains Energy Employee Savings Plus Plan accruing to the Great Plains Energy Non-Qualified Deferred Compensation Plan -- $12,000; flex dollars under the Great Plains Energy Flexible Benefits Plan -- $6,835; deferred flex dollars -- $1,582; and above-market interest paid on compensation deferred pursuant to the Great Plains Energy Non-Qualified Deferred Compensation Plan -- $993

Downey: a contribution under the Great Plains Energy Employee Savings Plus Plan -- $6,300; a contribution under the Great Plains Energy Employee Savings Plus Plan accruing to the Great Plains Energy Non-Qualified Deferred Compensation Plan -- $6,900; flex dollars under the Great Plains Energy Flexible Benefits Plan -- $6,253; deferred flex dollars -- $214; and above-market interest paid on compensation deferred pursuant to the Great Plains Energy Non-Qualified Deferred Compensation Plan -- $19,543.

Bassham: flex Dollars under the Great Plains Energy Flexible Benefits Plan -- $3,228.

Easley: a contribution under the Great Plains Energy Employee Savings Plus Plan -- $6,300; a contribution under the Great Plains Energy Employee Savings Plus Plan accruing to the Great Plains Energy Non-Qualified Deferred Compensation Plan -- $1,200; flex dollars under the Great Plains Energy Flexible Benefits Plan -- $4,192; and above-market interest paid on compensation deferred pursuant to the Great Plains Energy Non-Qualified Deferred Compensation Plan -- $2,689.

Marshall: a contribution under the Great Plains Energy Employee Savings Plus Plan accruing to the Great Plains Energy Non-Qualified Deferred Compensation Plan -- $5,200; flex dollars under the Great Plains Energy Flexible Benefits Plan -- $2,714; and above-market interest paid on compensation deferred pursuant to the Great Plains Energy Non-Qualified Deferred Compensation Plan -- $424.

Long-Term Incentive Plans - Awards in Last Fiscal Year


Name (a)	Number of Shares, Units or Other Rights (#) (b)(1)	Performance or Other Period Until Maturation or Payout (c)	Estimated Future Payouts Under Non-Stock Price-Based Plans
Name (a)			Threshold ($ or #) (d)	Target ($ or #) (e)	Maximum ($ or #) (f)
Michael J. Chesser	30,233 shares	2 years ending 2006	0	30,233 shares	60,466 shares
Michael J. Chesser	30,233 shares	3 years ending 2007	0	30,233 shares	60,466 shares
William H. Downey	16,719 shares	2 years ending 2006	0	16,719 shares	33,438 shares
William H. Downey	16,719 shares	3 years ending 2007	0	16,719 shares	33,438 shares
Terry Bassham	6,358 shares	3 years ending 2007	0	6,358 shares	12,716 shares
John R. Marshall	7,096 shares	3 years ending 2007	0	7,096 shares	14,192 shares
Stephen T. Easley	5,782 shares	2 years ending 2006	0	5,782 shares	11,564 shares
	5,782 shares	3 years ending 2007	0	5,782 shares	11,564 shares

(1)

The awards of performance shares to Messrs. Chesser and Bassham are based on the following weightings of Great Plains Energy objectives during the applicable performance period: 50% total shareholder return compared to other Edison Electric Institute companies; 25% earnings per share; and 25% return on invested capital. The awards of performance shares to Messrs. Downey, Marshall and Easley are based 60%, 20% and 20%, respectively, on the Great Plains Energy objectives, with the remainder based on the following weightings of KCP&L objectives during the applicable

performance period: 25% earnings; 25% return on invested capital; 25% on regulatory/build plan on schedule and budget; and 25% distributed utility goal. Payment of performance shares will range from 0% to 200% of the target amount of performance shares, depending on performance. Payment will be made in an amount equal to the number of performance shares earned, multiplied by the fair market value of common stock at the end of the applicable performance period and divided by the fair market value of common stock at the time of grant.

Aggregated Option/SAR Exercises in the Last Fiscal Year and Fiscal Year-End Option/SAR Values


Name (a)	Shares Acquired on Exercise (#) (b)	Value Realized ($) (c)	Number of Securities Underlying Unexercised Options/SARs at Fiscal Year End (#)		Value of Unexercised In-the-Money Options/SARs at Fiscal Year End ($)
Name (a)		Value Realized ($) (c)	Exercisable (1)(d)	Unexercisable (d)	Exercisable(1) (e)	Unexercisable (e)
Michael J. Chesser	-	-	-	-	-	-
William H. Downey	-	-	40,000	5,249	109,400	1,207
Terry Bassham	-	-	-	-	-	-
Stephen T. Easley	-	-	19,000	2,449	54,240	563
John R. Marshall	-	-	-	-	-	-

Equity Compensation Plan

We do not have an equity compensation plan; however, our officers participate in Great Plains Energy’s Long-Term Incentive Plan. For a description of the Long-Term Incentive Plan, see Note 9 to the consolidated financial statements.

Pension Plans

Great Plains Energy has a non-contributory pension plan (Great Plains Energy Pension Plan) providing for benefits upon retirement, normally at age 65. In addition, a supplemental retirement benefit is provided for selected executive officers based on the number of years such persons were officers. The following table shows examples of single life option pension benefits (including unfunded supplemental retirement benefits) payable upon retirement at age 65 to the named executive officers, assuming that the person was covered by the supplemental retirement benefit for all years of service.


Average Annual Base Salary	Annual Pension for Years of Service Indicated
for Highest 36 Months	15	20	25	30 or more
150,000	45,000	60,000	75,000	90,000
200,000	60,000	80,000	100,000	120,000
250,000	75,000	100,000	125,000	150,000
300,000	90,000	120,000	150,000	180,000
350,000	105,000	140,000	175,000	210,000
400,000	120,000	160,000	200,000	240,000
450,000	135,000	180,000	225,000	270,000
500,000	150,000	200,000	250,000	300,000
550,000	165,000	220,000	275,000	330,000
600,000	180,000	240,000	300,000	360,000
650,000	195,000	260,000	325,000	390,000
700,000	210,000	280,000	350,000	420,000
750,000	225,000	300,000	375,000	450,000

Each eligible employee with 30 or more years of credited service, or whose age and years of service add up to 85, is entitled under the Great Plains Energy Pension Plan to a total monthly annuity equal to 50% of their average base monthly salary for the period of 36 consecutive months in which their earnings were highest. The monthly annuity will be proportionately reduced if their years of credited service are less than 30 or if their age and years of service do not add up to 85. The compensation covered by the Great Plains Energy Pension Plan -- base monthly salary -- excludes any bonuses and other compensation. The Great Plains Energy Pension Plan provides that pension amounts are not reduced by Social Security benefits. The estimated years of credited service under the Great Plains Energy Pension Plan for the named executive officers in the Summary Compensation table are as follows.


Officer		Years of Credited Service
Michael J. Chesser^(a)		2.5
William H. Downey		5.5
Terry Bassham		0.5
John R. Marshall^(a)		0
Stephen T. Easley		9
^(a) Pursuant to the terms of employment agreements, Messrs.
Chesser and Marshall will be credited with two years of service
for every one year of service earned. The additional year of
service will be paid as a supplemental retirement benefit.

Eligibility for supplemental retirement benefits is limited to executive officers selected by the Compensation and Development Committee of the board; all the named executive officers are participants. The total retirement benefit payable at the normal retirement date is equal to 1 2/3% of highest average annual base salary over the thirty-six consecutive month period when base salary was highest (highest average annual base salary), as shown above, for each year of credited service, plus an additional 1/3% of highest average annual base salary for each year of credited service when the executive was eligible for supplemental retirement benefits, up to 30 years (or a maximum of 60% of highest average annual base salary in the situation where the executive was eligible for supplemental retirement benefits for at least 30 years). A liability accrues each year to cover the estimated cost of future supplemental benefits.

The Internal Revenue Code imposes certain limitations on pensions that may be paid under tax qualified pension plans. In addition to the supplemental retirement benefits, the amount by which pension benefits exceed the limitations will be paid outside the qualified plan and accounted for by Great Plains Energy as an operating expense.

Severance Agreements

Great Plains Energy has severance agreements, or “Severance Agreements,” with certain of its executive officers, including the named executive officers, to ensure their continued service and dedication and their objectivity in considering on behalf of Great Plains Energy any transaction that would change the control of the Company. Under the Severance Agreements, an executive officer would be entitled to receive a lump-sum cash payment and certain insurance benefits during the three-year period after a Change in Control (or, if later, the three-year period following the consummation of a transaction approved by Great Plains Energy’s shareholders constituting a Change in Control) if the officer's employment was terminated by:

·	Great Plains Energy other than for cause or upon death or disability;

·	the executive officer for Good Reason (as defined in the Severance Agreements); and

·	the executive officer for any reason during a 30-day period commencing one year after the Change in Control or, if later, commencing one year following consummation of a transaction approved by Great Plains Energy’s shareholders constituting a change in control (a Qualifying Termination).

A Change in Control is defined as:

·	an acquisition by a person or group of 20% or more of the Great Plains Energy common stock (other than an acquisition from or by Great Plains Energy or by a Great Plains Energy benefit plan);

·	a change in a majority of the board; and

·	approval by the shareholders of a reorganization, merger or consolidation (unless shareholders receive 60% or more of the stock of the surviving company) or a liquidation, dissolution or sale of substantially all of Great Plains Energy’s assets.

Upon a Qualifying Termination, a lump-sum cash payment will be made to the executive officer of:

·	the officer's base salary through the date of termination;

·	a pro-rated bonus based upon the average of the bonuses paid to the officer for the last five fiscal years;

·	any accrued vacation pay;

·	two or three times the officer's highest base salary during the prior 12 months;

·	two or three times the average of the bonuses paid to the officer for the last five fiscal years;

·	the actuarial equivalent of the excess of the officer's accrued pension benefits including supplemental retirement benefits computed without reduction for early retirement and including two or three additional years of benefit accrual service, over the officer's vested accrued pension benefits; and

·	the value of any unvested Great Plains Energy contributions for the benefit of the officer under the Great Plains Energy Employee Savings Plus Plan.

In addition, Great Plains Energy must offer health, disability and life insurance plan coverage to the officer and his dependents on the same terms and conditions that existed immediately prior to the Qualifying Termination for two or three years, or, if earlier, until the executive officer is covered by equivalent plan benefits. Great Plains Energy must make certain "gross-up" payments regarding tax obligations relating to payments under the Severance Agreements as well as provide reimbursement of certain expenses relating to possible disputes that might arise.

In the following circumstances, termination of the officer’s employment prior to a Change in Control (or, if later, prior to the consummation of a transaction approved by shareholders that constitutes a Change in Control) will be treated as a Qualifying Termination:

·	the officer’s employment was terminated without Cause (as defined in the Severance Agreement) and the termination was at the request or direction of the other party to the agreement;

·	the officer terminates his employment for Good Reason; or

·	the officer’s employment is terminated without Cause and such termination is otherwise in connection with or in anticipation of a Change in Control that actually occurs.

Payments and other benefits under the Severance Agreements are in addition to balances due under the Great Plains Energy Long-Term Incentive Plan and Annual Incentive Plan. Upon a Change in Control (as defined in the Great Plains Energy Long-Term Incentive Plan), all stock options granted in tandem with limited stock appreciation rights will be automatically exercised.

Other Employment Arrangements

Pursuant to the terms of an employment arrangement, Mr. Chesser is entitled to receive three times annual salary and bonus if he is terminated without cause prior to his reaching age 63. After age 63, any benefit for termination without cause will be one times annual salary and bonus until age 65. Messrs. Chesser and Marshall will receive two credited years of service for every one year of service earned. The additional year of service will be paid as a supplemental retirement benefit.

Director Compensation

Our directors receive the following compensation for serving on the boards of Great Plains Energy and KCP&L:

An annual retainer of $50,000 was paid in 2005 ($25,000 of which was used to acquire shares of common stock through the Dividend Reinvestment and Direct Stock Purchase Plan on behalf of each non-employee member of the board). An additional retainer of $10,000 was paid annually to the lead director. Also, a retainer of $6,000, $5,000 and $5,000 was paid to the non-employee director serving as chair of the Audit Committee, the Compensation and Development Committee and the Governance Committee, respectively. Attendance fees of $1,000 for each board meeting and $1,000 for each committee and other meeting attended were also paid in 2005. Directors may defer the receipt of all or part of the cash retainers and meeting fees.

Great Plains Energy provides life and medical insurance coverage for each non-employee member of the board. The total premiums paid by Great Plains Energy for this coverage for all non-employee directors in 2005 was $32,789. Great Plains Energy pays or reimburses directors for travel, lodging and related expenses they incur in attending board and committee meetings, including the expenses incurred by directors’ spouses in accompanying the directors to one board meeting in 2005. It also matches, on a two-for-one basis, up to $5,000 per year of charitable donations made by a director to 501(c)(3) organizations that meet our strategic giving priorities and are located in the service territory.

Compensation and Development Committee Report on KCP&L Executive Compensation

The Committee’s Responsibilities

The Compensation and Development Committee of the Board of Great Plains Energy (Committee) is composed of six non-employee directors, each of whom is independent under applicable standards of the New York Stock Exchange. The Committee is responsible for setting the executive compensation structure and administering the policies and plans that govern compensation for the executive officers. The purpose of this report is to summarize the Committee’s compensation philosophy, identify key elements of the executive compensation programs and describe the process and practices applied by the Committee in making compensation decisions for fiscal year 2005.

Compensation Philosophy

The Committee has adopted a compensation philosophy intended to:

·	Attract and retain highly qualified and experienced executives;

·	Emphasize a significant alignment between pay and Great Plains Energy’s and/or the executive’s performance;

·	Motivate executives to achieve strong short-term and long-term financial and operational results;

·	Provide variable compensation opportunities that recognize and reward outstanding performance;

·	Align management interests with those of the shareholders; and

·	Provide a significant portion of total pay in the form of stock-based incentives, correspondingly requiring target levels of stock ownership.

Compensation Methodology

Each year the Committee reviews data from market surveys, proxy statements, and other information provided by independent compensation consultants relating to an assessment of Great Plains Energy’s competitive position with respect to base salaries, annual incentives, long-term incentives, and other specific aspects of executive compensation. The Committee reviews the alignment between executive pay and performance on a regular basis. In the most recent assessment of its compensation practices by the compensation consultant retained by the Committee, it was reported that analyses demonstrated a strong relationship between pay and performance. The Committee also considers in its assessment individual performance, level of responsibility, internal comparisons, and skills and experience. Certain of Great Plains Energy’s executive officers serve as officers and/or directors of various subsidiaries. The total compensation of officers is designed to cover the full range of services they provide to Great Plains Energy and its subsidiaries.

Components of Compensation

Base Salary

The Committee reviews executive officer base salaries annually and concurrent with an evaluation of the executive’s performance for the prior year. Base salaries are based upon job responsibilities, level of experience, individual performance, comparisons of the salaries of executives in similar positions obtained from market surveys, internal comparisons and competitive data provided by compensation consultants retained by the Committee. The goal for the base salary component is to compensate executives at a level, which approximates the median salaries of individuals in comparable positions in companies of similar size within the industry and general industry, as appropriate. Base salary increases for Messrs. Chesser, Downey and Easley were effective January 1, 2005. Messrs. Bassham and Marshall were not employed by Great Plains Energy until March 28, 2005 and May 25, 2005, respectively.

Annual Incentives

Annual cash incentives are provided to executive officers based upon the achievement of pre-established corporate and business unit objectives, and also provide the ability to recognize individual performance. In 2005, the Committee administered the Great Plains Energy Annual Incentive Plan (the Plan) that permitted the award of annual cash incentives to executive officers, including the Named Executive Officers set forth in the Summary Compensation Table. Target incentives under the Plan are established as a percentage of base pay, using survey data for individuals in comparable positions and markets and internal comparisons. The Committee has established total target annual bonus levels intended to approximate the 50^th percentile bonus levels in comparable positions and markets when target performance is achieved. Target annual incentives under the Plan for 2005 ranged from 30% to 60% of base pay. The total amount available for payment was determined by corporate earnings per share and subject to established threshold, target and maximum levels. The Plan will pay out at 100% at target. Fifty percent of the incentive is payable at the threshold level of performance and 150% of the incentive is payable at the maximum level of performance. If performance falls below target, but is above threshold, the amount of the award payable will be below the target award level. Similarly, performance above target will result in an award higher than target level. Individual awards will not be paid if the corporate EPS performance falls below the threshold level. The entire award is distributed proportionately among participants based on other corporate and business unit measures, such as return on invested capital, customer satisfaction, customer retention rate, reliability, and others. Individual performance is also taken into account. For 2005, discretion was used to exclude from Great Plains Energy reported earnings goals and results the applicable effects of mark-to-market gains and losses on energy contracts, seams elimination charge adjustment, certain compensation expenses and discontinued operations. As a result, corporate earnings per share were at the maximum level and individual awards were earned in the amounts set forth in the Summary Compensation Table.

The Annual Incentive Plan of Great Plains Energy Incorporated was amended in February of 2006. The amended Plan will continue to be based on achievement of pre-established company and business unit financial and operational metrics. For 2006, the measures for annual incentives are based 50% on core earnings, and 30% on financial ratios, production availability, achievement of comprehensive energy plan milestones, customer

satisfaction, profitability, employee engagement and/or other specified business unit objectives. The Committee also takes into account individual performance to account for 20% of the target award. Individual Incentive amounts will range from 0% to 200% of target based on performance, and the Committee intends to target the 50^th percentile or above as the basis for target annual bonus levels.

Long-Term Incentive Compensation

The Committee has structured a long-term compensation element to more closely align the interests of management with the creation of long-term shareholder value. The Great Plains Energy Long-Term Incentive Plan was approved by shareholders in 2002, and provides for grants by the Committee of stock options, restricted stock, performance shares, and other stock-based awards. Each executive officer is assigned a long-term incentive target based on both internal comparisons and upon survey data for individuals in comparable positions in the markets in which Great Plains Energy competes for executive talent. Compliance with stock ownership guidelines is also taken into consideration in determining grants under the Long-Term Incentive Program. The Committee has established total target long-term incentive targets at the 50^th percentile in comparable positions and markets. Targets range from 40% to 150% of base salary. Based on performance over the period, awards can pay out from 0% to 200%. However, since no long-term grants were made under the program in 2004, in 2005 executives received a two-year performance share grant for 2005-2006 performance, and a three-year performance share grant for 2005-2007 performance. Payouts, if any, will be made after the end of the period based on performance during the period. Goals for both long-term grants were based on pre-approved corporate and business unit measures.

For 2006, the performance share component of long-term awards will be based on the Company’s Total Shareholder Return over a three-year period, as compared to the Total Shareholder Return of the Edison Electric Institute (EEI) Index of electric utilities. The Committee believes this measure ensures strong alignment of executive financial interests with the long-term interests of its shareholders.

KCP&L Chief Executive Officer Compensation

The Committee considers the assessment of the Chief Executive Officer’s (CEO) performance and determination of the CEO’s compensation as among its principal responsibilities. Its objective with regards to setting an appropriate level of compensation is to motivate and retain a CEO who is committed to delivering sustained superior performance for the Company’s shareholder.

In 2005, Mr. Downey received a base salary of $440,000, which is below the median for CEOs of comparably-sized companies in similar markets. In determining Mr. Downey’s base salary, the Committee considered the financial performance of the Company; the cost and quality of services provided; leadership in enhancing the long-term value of the Company; performance against other pre-established objectives; survey data; and consideration of length of service. Mr. Downey’s annual incentive compensation award was targeted at 45% of base pay, also considered to be somewhat below market levels. In 2005, Mr. Downey’s incentive award was based 80% on Great Plains Energy performance which included a balanced scorecard of financial, customer-related and internal/operational metrics, and 20% on individual performance. Funding for annual awards was based on corporate earnings per share. The Great Plains Energy scorecard resulted in overall performance between target and maximum levels for purposes of the annual incentive plan, and earnings performance allowed funding at the maximum level. Mr. Downey received two long-term performance share grants in 2005 since no awards were made in 2004. Awards were determined in the same manner as for other executive officers. Mr. Downey’s long-term incentive target was 115% of base pay, which is consistent with the 50^th percentile for comparable CEO positions and markets.

It is the Committee’s intent that, when taken together, the components of Mr. Downey’s pay, including base salary, annual incentives and long-term incentives, would result in total compensation that would approximate the 50^th percentile of the market when incentive plan performance measures are met and in compensation levels at the 75^th percentile or higher when incentive plan performance is at superior levels.

Code Section 162(m)

Section 162(m) of the Internal Revenue Code precludes the Company from taking a deduction for compensation in excess of $1 million for any individual who, on the last day of that year, is the CEO or among the other four highest compensated officers unless that compensation qualifies as performance-based compensation under Section 162(m). With respect to incentive compensation, the Great Plains Energy Long-Term Incentive Plan was approved by shareholders in 2002 and offers vehicles, which are performance-based. It is the Committee’s intent to take reasonable steps to include the provisions necessary to qualify for exemptions from the limitations on such deductibility under Section 162(m) at the time the Plan is next taken for shareholder vote in May 2007. With respect to awards under the Great Plains Energy Annual Incentive Plan, the Committee believes that the interests of the Company’s shareholders are best served by not restricting the Committee’s and Company’s discretion and flexibility in developing compensation programs.

COMPENSATION AND DEVELOPMENT COMMITTEE

William C. Nelson (Chairman)

Mark A. Ernst

Luis A. Jimenez

James A. Mitchell

Linda H. Talbott

Robert H. West

BENEFICIAL OWNERSHIP OF SECURITIES

Great Plains Energy is our sole shareholder. The following table shows beneficial ownership of Great Plains Energy’s common stock by the named executive officers, directors and all directors and executive officers of KCP&L as of February 7, 2006, (with the exception of shares held in the Employee Savings Plus Plan, which is reported as of January 31, 2006). The total of all shares owned by directors and executive officers represents less than 1% of Great Plains Energy’s common stock.

Name of Beneficial Owner		Shares of Common Stock Beneficially Owned (1)
Named Executive Officers
	Michael J. Chesser	43,973
	William H. Downey	89,255
	Terry Bassham	11,721
	Stephen T. Easley	39,705
	John R. Marshall	25,761

Non-management Directors
	David L. Bodde	10,465	(2)
	Mark A. Ernst	8,663
	Randall C. Ferguson, Jr.	4,203
	Luis A. Jimenez	4,650
	James A. Mitchell	5,209
	William C. Nelson	5,069	(3)
	Linda H. Talbott	10,781
All KCP&L Executive Officers and Directors As A Group (20 persons)		334,181

(1)	Includes restricted stock and exercisable non-qualified stock options.

·	Restricted Stock: Chesser - 36,006 shares; Downey - 24,487 shares;

Bassham - 11,721 shares; Marshall - 23,567 shares; Easley - 12,593 shares; other executive officers - 15,886.

·	Exercisable Non-Qualified Stock Options: Downey - 40,000 shares; Easley - 19,000 shares; other executive officers - 36,000.

(2)	The nominee disclaims beneficial ownership of 1,000 shares reported and held by nominee's mother.

(3)	The nominee disclaims beneficial ownership of 62 shares reported and held by nominee’s wife.

RELATED PARTY TRANSACTIONS

See Note 11 of the notes to our consolidated financial statements for information regarding related party transactions.

THE EXCHANGE OFFER

The following is a summary of the exchange offer relating to the old notes. As a summary, it does not contain all of the information you might find useful. For further information, you should read the registration rights agreement and the form of letter of transmittal, copies of which have been filed as exhibits to the registration statement. The exchange offer is intended to satisfy certain of our obligations under the registration rights agreement.

Purpose and Effect of the Exchange Offer

Exchange Offer Registration Statement

We sold the old notes to BNP Paribas Securities Corp., J.P. Morgan Securities Inc., Banc of America Securities LLC, Credit Suisse First Boston LLC, BNY Capital Markets, Inc., KeyBanc Capital Markets, A Division of McDonald Investments Inc. and Wachovia Capital Markets LLC, or the “initial purchasers,” on November 17, 2005. As a condition to the offering of the old notes, we entered into a registration rights agreement dated November 17, 2005, pursuant to which we agreed, for the benefit of all holders of the old notes, at our own expense, to use our best efforts to consummate the exchange offer within 280 days after the initial issue date of the old notes.

Further, we agreed to keep the exchange offer open for acceptance for not less than 20 business days and to consummate the exchange offer not later than 40 days after the effective date of the exchange offer registration statement, such 40^th day being the “Consummation Deadline.” For each old note validly tendered pursuant to the exchange offer and not withdrawn, the holder of that note will receive an exchange note having a principal amount equal to that of the tendered old note. Interest on each exchange note will accrue from the last date on which interest was paid on the tendered old note in exchange therefor or, if no interest was paid on that old note, from the issue date.

Transferability

We issued the old notes on November 17, 2005 in a transaction exempt from the registration requirements of the Securities Act and applicable state securities laws. Accordingly, the old notes may not be offered or sold in the United States unless registered or pursuant to an applicable exemption under the Securities Act and applicable state securities laws. Based on no-action letters issued by the staff of the SEC (“Staff”) with respect to similar transactions, we believe that the exchange notes issued pursuant to the exchange offer in exchange for old notes may be offered for resale, resold and otherwise transferred by holders of notes who are not our affiliates without further compliance with the registration and prospectus delivery requirements of the Securities Act, provided that:

·	any exchange notes to be received by the holder were acquired in the ordinary course of the holder’s business;

·	at the time of the commencement of the exchange offer, the holder has no arrangement or understanding with any person to participate in the distribution, within the meaning of the Securities Act, of the exchange notes;

·	the holder is not an “affiliate” of ours, as defined in Rule 405 under the Securities Act; and

·	the holder did not purchase the old notes directly from us to resell pursuant to 144A or another available exemption.

However, we have not sought a no-action letter with respect to the exchange offer and we cannot assure you that the Staff would make a similar determination with respect to the exchange offer. Any holder who tenders its old notes in the exchange offer with any intention of participating in a distribution of exchange notes (1) cannot rely on the interpretation by the Staff, (2) will not be able to validly tender old notes in the exchange offer and (3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any secondary resale transactions.

Each broker-dealer that receives exchange notes for its own account in exchange for old notes, where those notes were acquired by such broker dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of those exchange notes. The Staff has taken the position that such broker-dealers may fulfill their prospectus delivery requirements with respect to the exchange notes (other than a resale of an unsold allotment from the original sale of the old notes) with the prospectus contained in the exchange offer registration statement. Under the registration rights agreement, we will be required to allow such broker-dealers to use the prospectus contained in the exchange offer registration statement for up to 180 days, subject to certain “black out” periods, following the exchange offer,

in connection with the resale of exchange notes received in exchange for notes acquired by such broker-dealers for their own account as a result of market-making or other trading activities. See “Plan of Distribution.”

Shelf Registration Statement

In the event that:

·	changes in law or the applicable interpretations of the Staff do not permit us to effect the exchange offer,

·	the exchange offer is not consummated on or prior to the 280th day following the closing date of the offering of the old notes,

·	following consummation of the exchange offer, any initial purchaser so requests with respect to old notes held by such initial purchaser and not eligible to be exchanged in the exchange offer, or

·	any holder of old notes (except exchanging dealers) not eligible to participate in the exchange offer or that participates in the exchange offer but does not receive freely tradable notes so requests,

then (the date on which the conditions described in the first two bullets above occur or the date on which the notice described under the third or fourth bullet above is given, the “trigger date”) we will at our cost:

·	promptly (no later than the 90th day after the trigger date), file with the SEC a “shelf” registration statement to cover resales of the old notes,

·	use our best efforts to cause the shelf registration statement to be declared effective under the Securities Act no later than the 180th day after the trigger date, and

use our best efforts to keep the shelf registration statement effective until two years (or such longer period if there are certain “black out” periods) after the shelf registration statement is declared effective or until all of the notes covered by the shelf registration statement have been sold or are no longer restricted securities.

We will have the ability to suspend the availability of the shelf registration statement during certain “black out” periods.

In the event of the filing of the shelf registration statement, we will provide to each relevant holder of old notes copies of the prospectus which is a part of the shelf registration statement and will notify each such holder when the shelf registration statement has become effective.

A holder of old notes that sells old notes pursuant to the shelf registration statement generally will be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to the purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such a holder (including certain indemnification obligations). We may require such holder to provide us with information about itself that we may, from time to time, reasonably require for inclusion in the shelf registration statement and the related prospectus and we may exclude from such registration any holder that unreasonably fails to furnish such information within a reasonable time after receiving such request.

Special Interest

We will pay additional cash interest on the old notes and exchange notes, subject to certain exceptions,

(1) if obligated to file a shelf registration statement, such shelf registration has not been filed on or prior to the 90^th day after the date on which the requirement to file such shelf registration statement is triggered,

(2) if the exchange offer registration statement is not declared effective by the SEC on or prior to the 240^th day after the date of original issue of the old notes or, if obligated to file a shelf registration statement, such shelf registration statement is not declared effective by the SEC on or prior to the 180th day after the date on which the requirement to file such shelf registration statement is triggered,

(3) if the exchange offer is not consummated on or before the 40th day after the exchange offer registration statement is declared effective or

(4) after the exchange offer registration statement or the shelf registration statement, as the case may be, is declared effective, either ceases to be effective or cannot be used to sell the notes because (1) an event occurs as a result of which the related prospectus forming part of such registration statement contains any untrue statement of a material fact or omits to state any material fact necessary to make the statements therein in light of the circumstances under which they were made not misleading, or (2) it shall be necessary to amend such registration statement or supplement the related prospectus to comply with the Securities Act or Exchange Act or the respective rules thereunder (each such event listed above, a “registration default”).

The interest rate borne by the notes which are “transfer restricted securities” (as defined below) will be increased by .25% per year upon the occurrence of such registration default, which rate will increase by an additional .25% per year if such registration default has not been cured within 90 days after the occurrence thereof and similar such increases shall occur for each succeeding 90 day period until all registration defaults have been cured, up to a maximum additional interest rate of 1.00% per year; and provided, further, that a registration default will be deemed not to have occurred if such registration default has occurred solely as a result of:

·	the filing of a post-effective amendment to the registration statement to incorporate annual audited financial information with respect to us where such post-effective amendment needs to be declared effective to permit holders to use the related prospectus or registration statement; or

·	other material events with respect to us that need to be described in the related prospectus or registration statement and we are proceeding promptly and in good faith to amend or supplement such documents accordingly;

provided however that in case one of the foregoing qualifications to the occurrence of a registration default occurs for a continuous period of more than 5 days, in the case of an exchange offer registration statement or related prospectus, or 30 days, in the case of a shelf registration statement or related prospectus, additional interest shall be payable from the date of such default until the default is cured. All accrued additional interest will be paid to holders of notes in the same manner and at the same time as regular payments of interest on the notes. Following the cure of all registration defaults, the accrual of additional interest will cease and the interest rate will revert to the original rate.

A “Transfer Restricted Security” is a note until (1) the date on which such note has been exchanged by a person other than a broker-dealer for a freely transferable exchange note in the exchange offer, (2) following the exchange by a broker-dealer in the exchange offer of such old note for an exchange note, the date on which such exchange note is sold to a purchaser who received a copy of this prospectus and the related registration statement on or prior to the date of such sale, (3) the date on which such note has been effectively registered under the Securities Act and disposed of in accordance with the shelf registration statement or (4) the date on which such note is distributed to the public pursuant to Rule 144 under the Securities Act or is saleable pursuant to Rule 144(k) under the Securities Act.

Terms of the Exchange Offer

Upon satisfaction or waiver of all the conditions of the exchange offer, we will accept any and all old notes properly tendered and not validly withdrawn prior to the expiration date and will promptly issue the exchange notes. See “— Conditions to the Exchange Offer” and “— Procedures for Tendering Old Notes.” We will issue $1,000 principal amount of exchange notes in exchange for each $1,000 principal amount of old notes accepted in the exchange offer. As of the date of this prospectus, there are $250,000,000 aggregate principal amount of

outstanding old notes. Holders may tender some or all of their old notes pursuant to the exchange offer. However, old notes may be tendered only in integral multiples of $1,000.

The exchange notes are identical to the old notes except for the elimination of certain transfer restrictions and registration rights pertaining to the old notes. The exchange notes will evidence the same debt as the old notes and will be issued pursuant to, and entitled to the benefits of, the indenture pursuant to which the old notes were issued and will be deemed one issue of notes, together with the old notes.

This prospectus, together with the letter of transmittal, is being sent to all registered holders and to others believed to have beneficial interests in the old notes. Holders of old notes do not have any appraisal or dissenters’ rights under the indenture in connection with the exchange offer. We intend to conduct the exchange offer in accordance with the applicable requirements of the Securities Act, the Exchange Act and the rules and regulations of the SEC promulgated thereunder.

For purposes of the exchange offer, we will be deemed to have accepted validly tendered old notes when, and if, we have given oral or written notice thereof to the exchange agent. The exchange agent will act as our agent for the purpose of distributing the appropriate exchange notes from us to the tendering holders. If we do not accept any tendered old notes because of an invalid tender, the occurrence of certain other events set forth in this prospectus or otherwise, we will return the unaccepted old notes, without expense, to the tendering holder thereof promptly after the expiration date.

Holders who tender old notes in the exchange offer will not be required to pay brokerage commissions or fees or, except as set forth below under “— Transfer Taxes,” transfer taxes with respect to the exchange of old notes pursuant to the exchange offer. We will pay all charges and expenses, other than certain applicable taxes, in connection with the exchange offer. See “— Fees and Expenses.”

Expiration Date; Extensions; Amendments

The term “expiration date” shall mean 5:00 p.m., New York City time, on May 22, 2006, for the exchange offer unless we, in our sole discretion, extend the exchange offer, in which case the term “expiration date” shall mean the latest date and time to which the exchange offer is extended. In order to extend the exchange offer, we will notify the exchange agent by oral or written notice and each appropriate registered holder by means of press release or other public announcement of any extension, in each case, prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date. We reserve the right, in our sole discretion,

·	to delay accepting any old notes,

·	to extend the exchange offer,

·	to terminate the exchange offer and not accept any old notes if each condition set forth below under “— Conditions to the Exchange Offer” shall not have been satisfied or waived by us, or

·	to amend the terms of the exchange offer in any manner.

We will notify the exchange agent of any delay, extension, termination or amendment by oral or written notice. We will also notify each registered holder of any amendment. We will give to the exchange agent written confirmation of any oral notice.

Exchange Date

As soon as practicable after the close of the exchange offer, we will accept for exchange all old notes properly tendered and not validly withdrawn prior to 5:00 p.m., New York City time, on the expiration date in accordance with the terms of this prospectus and the letter of transmittal.

Conditions to the Exchange Offer

Notwithstanding any other provisions of the exchange offer or any extension of the exchange offer, and subject to our obligations under the registration rights agreement, we

·	shall not be required to accept any old notes for exchange,

·	shall not be required to issue exchange notes in exchange for any old notes and

·	may terminate or amend the exchange offer

if, at any time before the acceptance of old notes for exchange, any of the following events shall occur:

·	any injunction, order or decree shall have been issued by any court or any governmental agency that would prohibit, prevent or otherwise materially impair our ability to proceed with the exchange offer;

·	any law, statute, rule or regulation is proposed, adopted or enacted which, in our sole judgment, might materially impair our ability to proceed with the exchange offer or materially impair the contemplated benefits of the exchange offer to us;

·	any governmental approval has not been obtained, which approval we shall, in our sole discretion, deem necessary for the consummation of the exchange offer as contemplated hereby; or

·	the exchange offer will violate any applicable law or any applicable interpretation of the Staff.

The foregoing conditions are for our sole benefit and may be asserted by us regardless of the circumstances giving rise to any of those conditions or may be waived by us in whole or in part at any time and from time to time in our sole discretion. Our failure at any time to exercise any of the foregoing rights shall not be deemed a waiver of any of those rights, and those rights shall be deemed ongoing rights that may be asserted at any time and from time to time.

In addition, we will not accept for exchange any old notes tendered, and no exchange notes will be issued in exchange for any tendered old notes, if at such time any stop order shall be threatened by the SEC or be in effect with respect to the registration statement of which this prospectus is a part or the qualification of the indenture for the notes under the Trust Indenture Act of 1939, as amended.

The exchange offer is not conditioned on any minimum aggregate principal amount of old notes being tendered for exchange.

Consequences of Failure to Exchange

Any old notes not tendered pursuant to the exchange offer will remain outstanding and will continue to be entitled to the benefits of the indenture and continue to accrue interest. The old notes will remain “restricted securities” within the meaning of the Securities Act. Accordingly, prior to the date that is one year after the later of the issue date and the last date on which we or any of our affiliates was the owner of the old notes, the old notes may be resold only:

to us;

·	to a person who the seller reasonably believes is a “qualified institutional buyer” purchasing for its own account or for the account of another “qualified institutional buyer” in compliance with the resale limitations of Rule 144A;

·	pursuant to the limitations on resale provided by Rule 144 under the Securities Act;

·	pursuant to the resale provisions of Rule 904 of Regulation S under the Securities Act;

·	pursuant to an effective registration statement under the Securities Act; or

·	pursuant to any other available exemption from the registration requirements of the Securities Act;

subject, in each of the foregoing cases, to compliance with applicable state securities laws. As a result, the liquidity of the market for non-tendered old notes could be adversely affected upon completion of the exchange offer.

Fees and Expenses

We will not make any payments to brokers, dealers or others soliciting acceptances of the exchange offer. The principal solicitation is being made by mail; however, additional solicitations may be made in person or by telephone by our officers and employees.

Expenses incurred in connection with the exchange offer will be paid by us. Such expenses include, among others, the fees and expenses of the trustee and the exchange agent, accounting and legal fees, printing costs and other miscellaneous fees and expenses.

Accounting Treatment

We will not recognize any gain or loss for accounting purposes upon the consummation of the exchange offer. We will defer the costs of the exchange offer and amortize them as additional interest expense over the term of the exchange notes.

Procedures for Tendering Old Notes

The tender of old notes pursuant to any of the procedures set forth in this prospectus and in the letter of transmittal will constitute a binding agreement between the tendering holder and us in accordance with the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal. The tender of old notes will constitute an agreement to deliver good and marketable title to all tendered old notes prior to the expiration date free and clear of all liens, charges, claims, encumbrances, interests and restrictions of any kind.

Except as provided in “— Guaranteed Delivery Procedures,” unless the old notes being tendered are deposited by you with the exchange agent prior to the expiration date and are accompanied by a properly completed and duly executed letter of transmittal, we may, at our option, reject the tender. Issuance of exchange notes will be made only against deposit of tendered old notes and delivery of all other required documents. Notwithstanding the foregoing, The Depository Trust Company, or “DTC,” participants tendering through its Automated Tender Offer Program, or “ATOP,” will be deemed to have made valid delivery where the exchange agent receives an agent’s message, as defined below, prior to the expiration date.

Accordingly, to properly tender old notes, the following procedures must be followed:

Notes held through a Custodian. Each beneficial owner holding old notes through a DTC participant must instruct the DTC participant to cause its old notes to be tendered in accordance with the procedures set forth in this prospectus.

Notes held through DTC. Pursuant to an authorization given by DTC to the DTC participants, each DTC participant holding old notes through DTC must

·	electronically transmit its acceptance through ATOP, and DTC will then edit and verify the acceptance, execute a book-entry delivery to the exchange agent’s account at DTC and send an agent’s message to the exchange agent for its acceptance, or

·	comply with the guaranteed delivery procedures set forth below and in a notice of guaranteed delivery. See “— Guaranteed Delivery Procedures.”

Promptly after the date of this prospectus, the exchange agent will establish an account at DTC for purposes of the exchange offer with respect to old notes held through DTC. Any financial institution that is a DTC participant may make book-entry delivery of interests in old notes into the exchange agent’s account through ATOP. However, although delivery of interests in the old notes may be effected through book-entry transfer into the exchange agent’s account through ATOP, an agent’s message in connection with such book-entry transfer, and any other required documents, must be, in any case, transmitted to and received by the exchange agent at its

address set forth under “— Exchange Agent,” or the guaranteed delivery procedures set forth below must be complied with, in each case, prior to the expiration date. Delivery of documents to DTC does not constitute delivery to the exchange agent. The confirmation of a book-entry transfer into the exchange agent’s account at DTC as described above is referred to herein as a “Book-Entry Confirmation.”

The term “agent’s message” means a message transmitted by DTC to, and received by, the exchange agent and forming a part of the book-entry confirmation, which states that DTC has received an express acknowledgment from each DTC participant tendering through ATOP that that DTC participant has received a letter of transmittal and agrees to be bound by the terms of the letter of transmittal and that we may enforce such agreement against such DTC participants.

Cede & Co., as the holder of the global old note, will tender a portion of the global old note equal to the aggregate principal amount due at the stated maturity for which instructions to tender are given by DTC participants.

By tendering, each holder and each DTC participant will represent to us that, among other things:

·	it is not our affiliate;

·	it is not a broker-dealer tendering old notes acquired directly from us for its own account;

·	it is acquiring the exchange notes in its ordinary course of business; and

·	it is not engaged in, and does not intend to engage in, and has no arrangement or understanding with any person to participate in, a distribution of the exchange notes.

Unless waived by us, we will not accept any alternative, conditional, irregular or contingent tenders. By transmitting an acceptance through ATOP, each tendering holder waives any right to receive any notice of the acceptance for purchase of its old notes.

We will resolve all questions as to the validity, form, eligibility (including time of receipt) and acceptance of tendered old notes, and that determination will be final and binding. We reserve the absolute right to reject any or all tenders that are not in proper form or the acceptance of which may, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any condition to the exchange offer and any irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer (including the instructions in the letter of transmittal) will be final and binding. Unless waived, any irregularities in connection with tenders must be cured within such time as we shall determine. We, along with the exchange agent, shall be under no duty to give notification of defects in such tenders and shall not incur liabilities for failure to give such notification. Tenders of old notes will not be deemed to have been made until those irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the irregularities have not been cured or waived will be returned by the exchange agent to the tendering holder, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date.

Letters of transmittal and old notes must be sent only to the exchange agent. Do not send letters of transmittal or old notes to us or DTC.

The method of delivery of old notes, letters of transmittal, any required signature guarantees and all other required documents, including delivery through DTC and any acceptance through ATOP, is at the election and risk of the persons tendering and delivering acceptances or letters of transmittal and, except as otherwise provided in the letter of transmittal, delivery will be deemed made only when actually received by the exchange agent. If delivery is by mail, it is suggested that the holder use properly insured, registered mail with return receipt requested, and that the mailing be made sufficiently in advance of the expiration date to permit delivery to the exchange agent prior to the expiration date.

must acknowledge that it will deliver a prospectus in connection with any resale of those exchange notes. See “Plan of Distribution.”

Guaranteed Delivery Procedures

DTC participants holding old notes through DTC who wish to cause their old notes to be tendered, but who cannot transmit their acceptances through ATOP prior to the expiration date, may cause a tender to be effected if:

·	guaranteed delivery is made by or through a firm or other entity identified in Rule 17Ad-15 under the Exchange Act, including the following, which we call “eligible institutions”:

a bank;

·	a broker, dealer, municipal securities dealer, municipal securities broker, government securities dealer or government securities broker;

·	a credit union;

·	a national securities exchange, registered securities association or clearing agency; or

·	a savings institution that is a participant in a Securities Transfer Association recognized program;

·	prior to the expiration date, the exchange agent receives from any of the above institutions a properly completed and duly executed notice of guaranteed delivery, by mail, hand delivery, facsimile transmission or overnight courier, substantially in the form provided with this prospectus; and

·	book-entry confirmation and an agent’s message in connection therewith are received by the exchange agent within three New York Stock Exchange trading days after the date of the execution of the notice of guaranteed delivery.

Withdrawal Rights

You may withdraw tenders of old notes, or any portion of your old notes, in integral multiples of $1,000 principal amount due at the stated maturity, at any time prior to 5:00 p.m., New York City time, on the expiration date. Any old notes properly withdrawn will be deemed to be not validly tendered for purposes of the exchange offer.

DTC participants holding old notes who have transmitted their acceptances through ATOP may, prior to 5:00 p.m., New York City time, on the expiration date, withdraw the instruction given thereby by delivering to the exchange agent, at its address set forth under “— Exchange Agent,” a written, telegraphic or facsimile notice of withdrawal of such instruction. Such notice of withdrawal must contain the name and number of the DTC participant, the principal amount of old notes to which such withdrawal relates and the signature of the DTC participant. Receipt of such written notice of withdrawal by the exchange agent effectuates a withdrawal.

A withdrawal of a tender of old notes by a DTC participant or a holder, as the case may be, may be rescinded only by a new transmission of an acceptance through ATOP or execution and delivery of a new letter of transmittal, as the case may be, in accordance with the procedures described herein.

A withdrawal of an instruction must be executed by a DTC participant in the same manner as the person’s name appears on its transmission through ATOP to which such withdrawal relates. If a notice of withdrawal is signed by a trustee, partner, executor, administrator, guardian, attorney-in-fact, agent, officer of a corporation or other person acting in a fiduciary or representative capacity, that person must so indicate when signing and must submit with the revocation appropriate evidence of authority to execute the notice of withdrawal. A DTC participant may withdraw an instruction only if that withdrawal complies with the provisions of this prospectus.

Exchange Agent

The Bank of New York will act as exchange agent for the exchange offer.

You should direct all executed letters of transmittal to the exchange agent at one of the addresses set forth below. You should direct questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for copies of the notice of guaranteed delivery to the exchange agent, addressed as follows:

By registered or certified mail:

The Bank of New York

Corporate Trust Operations

Reorganization Unit

101 Barclay Street - 7 East

New York, New York 10286

Attn: Carolle Montreuil

By hand/overnight courier:

The Bank of New York

Corporate Trust Operations

Reorganization Unit

101 Barclay Street - 7 East

New York, New York 10286

Attn: Carolle Montreuil

By facsimile (eligible institutions only): (212) 298-1915

By telephone inquiries: (212) 815-5920

Delivery to an address other than as set forth above will not constitute a valid delivery.

Transfer Taxes

Holders of old notes who tender their old notes for exchange notes will not be obligated to pay any transfer taxes in connection therewith, except that holders who instruct us to register exchange notes in the name of, or request that old notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be responsible for the payment of any applicable transfer tax thereon.

Other

Participation in the exchange offer is voluntary. You should carefully consider whether to accept the exchange offer. You should consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

DESCRIPTION OF THE EXCHANGE NOTES

The old notes were issued, and the exchange notes will be issued, under an Indenture dated as of March 1, 2002, as amended and supplemented and as further supplemented by a Supplemental Indenture No. 1 dated as of November 15, 2005, between us and The Bank of New York, as Trustee. We refer to that Indenture as so amended and supplemented as the “Indenture.” We sometimes refer to the old notes and the exchange notes as the “notes” in the following description. The terms of the exchange notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended.

The following description is only a summary of the material provisions of the exchange notes and the Indenture. We urge you to read the Indenture because it, not this description, defines your rights as holders of the exchange notes. You may request a copy of the Indenture at our address set forth under the heading “Where You Can Find More Information.”

The terms of the exchange notes are identical in all material respects to the terms of the old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the exchange notes. If we do not complete the exchange offer by May 30, 2006, holders of the old notes that have complied with their obligations under the registration rights agreement will be entitled to additional interest in an amount equal to a rate of 0.25% per annum for the first 90-day period immediately following the occurrence of a registration default, and such rate will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults have been cured, up to a maximum additional interest rate of 1.00% per annum. We will pay such additional interest on regular interest payment dates. Such additional interest will be in addition to any other interest payable from time to time with respect to the old notes.

We may issue debt securities from time to time in one or more series under the Indenture. The notes will be a new series of debt securities under the Indenture. In addition to the old notes, we previously issued $225,000,000 of a series of unsecured senior notes under the indenture bearing interest at 6.00% and maturing on March 15, 2007. There is no limitation on the amount of debt securities we may issue under the Indenture. Securities issued under the Indenture are sometimes hereinafter referred to as “Indenture Securities.”

The old notes and the exchange notes will vote and consent together on all matters as one class and none of those notes will have the right to vote or consent as a class separate from one another on any matter. Accordingly, in determining whether the required holders have given any notice, consent or waiver or taken any other action permitted under the Indenture, any old notes that remain outstanding after the exchange offer will be aggregated with the exchange notes, and the holders of the old notes and the exchange notes will vote together as a single series. All references in this prospectus to specified percentages in aggregate principal amount of the old notes means, at any time after the exchange offer is consummated, the percentages in aggregate principal amount of the old notes and the exchange notes collectively then outstanding.

We have included cross-references in the summary below to refer you to the section numbers of the Indenture we are describing.

Ranking of the Notes

The exchange notes will:

·	be general unsecured obligations, and

·	rank equally with all of our other unsecured and unsubordinated indebtedness from time to time outstanding.

As of December 31, 2005, our aggregate outstanding debt that would have ranked equally with the notes was approximately $853.9 million. The notes will effectively rank junior to our first mortgage bonds (the “General Mortgage Bonds”), which were issued under the General Mortgage Indenture and Deed of Trust, dated as of December 1, 1986, between us and UMB Bank, N.A. (formerly United Missouri Bank of Kansas City, N.A.), as supplemented (the “Mortgage Indenture”). The Mortgage Indenture constitutes a first mortgage lien upon substantially all of our fixed property and franchises. At December 31, 2005, there was approximately $159.3 million aggregate principal amount of General Mortgage Bonds outstanding.

Principal, Maturity and Interest

The exchange notes will mature on November 15, 2035. The notes are initially limited to $250,000,000 in aggregate principal amount. However, we may issue additional notes of this series from time to time, with the same ranking and terms as the notes (other than the issue date and in some cases, the first interest payment date) without the consent of the holders of the notes.

Interest on the exchange notes will:

·	accrue at the rate of 6.05% per year from November 17, 2005, or from the most recent interest payment date to which interest has been paid on the old notes,

·	be payable semi-annually in arrears on each May 15 and November 15, commencing November 15, 2006,

·	be payable to the person in whose name the notes are registered at the close of business on the relevant May 1 and November 1 preceding the applicable interest payment date, which we refer to as “record dates,”

·	be computed on the basis of a 360-day year comprised of twelve 30-day months, and

·	be payable on overdue interest to the extent permitted by law at the same rate as interest is payable on principal.

If any interest payment date, the maturity date or any redemption date falls on a day that is not a Business Day, the payment will be made on the next Business Day with the same force and effect as if made on the relevant interest payment date, maturity date or redemption date. Unless we default on a payment, no interest will accrue for the period from and after the applicable maturity or redemption date.

“Business Day” means, with respect to the notes, any day other than (1) a Saturday or a Sunday or (2) a day on which banking institutions in the Borough of Manhattan, The City of New York, and the State of New York or the State of Missouri, are authorized or obligated by law or executive order to close.

Optional Redemption

We may redeem the notes at our option at any time, upon no more than 60 and not less than 30 days’ notice by mail. The notes may be redeemed in whole at any time or in part from time to time, at our option, at a redemption price equal to the greater of:

·	100% of the principal amount of the notes then outstanding to be redeemed; or

the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed (not including any portion of such payments of interest accrued to the date of redemption) discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable treasury rate plus 25 basis points

plus, in each case, accrued and unpaid interest on the principal amount being redeemed to the redemption date.

“treasury rate” means, with respect to any redemption date:

the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated “H.15(519)” or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded U.S. Treasury securities adjusted to constant maturity under the caption “Treasury Constant Maturities,” for the maturity corresponding to the comparable treasury issue (if no maturity is within three months before or after the remaining life (as defined below), yields for the two published maturities most closely corresponding to the comparable treasury

issue will be determined and the treasury rate will be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month); or

if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semiannual equivalent yield to maturity of the comparable treasury issue, calculated using a price for the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for such redemption date.

The treasury rate will be calculated on the third business day preceding the date fixed for redemption.

“comparable treasury issue” means the U.S. Treasury security selected by an independent investment banker as having a maturity comparable to the remaining term (“remaining life”) of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such notes.

“comparable treasury price” means (1) the average of five reference treasury dealer quotations for such redemption date, after excluding the highest and lowest reference treasury dealer quotations, or (2) if the independent investment banker obtains fewer than four such reference treasury dealer quotations, the average of all such quotations.

“independent investment banker” means either BNP Paribas Securities Corp. or J.P. Morgan Securities Inc., as specified by us, or, if these firms are unwilling or unable to select the comparable treasury issue, an independent investment banking institution of national standing appointed by us.

“reference treasury dealer” means (1) BNP Paribas Securities Corp. and J.P. Morgan Securities Inc. and their respective successors, provided, however, that if either of the foregoing shall cease to be a primary U.S. government securities dealer in New York City (a “primary treasury dealer”), we will substitute therefor another primary treasury dealer and (2) any three other primary treasury dealers selected by us after consultation with the independent investment banker.

“reference treasury dealer quotations” means, with respect to each reference treasury dealer and any redemption date, the average, as determined by the independent investment banker, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the independent investment banker at 5:00 p.m., New York City time, on the third business day preceding such redemption date.

Payments and Paying Agents

Payment of principal and premium, if any, on the notes will be made against surrender of the notes at the principal offices of the Trustee. Payment of any installment of interest on the notes will be made to the person in whose name such note is registered at the close of business on the record date for such interest. Payments of such interest will be made at the principal offices of the Trustee, as paying agent, or by a check mailed to each holder of a note at such holder’s registered address.

All moneys paid by us to a paying agent for the payment of principal, premium, if any, or interest, if any, on any note that remain unclaimed at the end of two years after such principal, premium or interest shall have become due and payable will be repaid to us and the holder of such note entitled to receive such payment will thereafter look only to us for payment thereof. (Section 12.05) However, any such payment shall be subject to escheat pursuant to state abandoned property laws.

Consolidation, Merger and Sale or Disposition of Assets

The Indenture permits us, without the consent of the holders of any of the notes, to consolidate with or merge into any other corporation or sell, transfer or lease our assets as an entirety or substantially as an entirety to any person, provided that: (1) the successor corporation formed by or surviving any such consolidation or merger, or the person to which such sale, transfer or lease shall have been made (the “Successor”) is a corporation organized under the laws of the United States of America or any state thereof; (2) the Successor

assumes our obligations under the Indenture and the Indenture Securities; (3) immediately after giving effect to the transaction, no Event of Default (see “Events of Default and Certain Rights on Default”) and no event that, after notice or lapse of time, or both, would become an Event of Default, shall have occurred and be continuing; and (4) certain other conditions are met. The Indenture does not restrict the merger of another corporation into us. The Successor, other than a Successor by reason of a lease of our properties, will succeed to our rights and obligations under the Indenture and the notes, and we will be relieved of our obligations. (Sections 11.01 and 11.02)

These provisions will not, however, be applicable to the sale, transfer or lease by us to an affiliated company of facilities used for the generation of electricity (and not used for the transmission or distribution of electric energy), provided that all such sales, transfers or leases occurring after March 1, 2002 shall not in the aggregate represent assets with a depreciated value on our books, calculated with respect to the assets sold, transferred or leased at the time of such sale, transfer or lease, in excess of 65% of the depreciated value on our books of our total assets as set forth in our most recent Form 10-K or Form 10-Q filing. (Section 11.02)

Modification of the Indenture

The Indenture contains provisions permitting us and the Trustee, without the consent of the holders of the Indenture Securities (including the notes), to establish, among other things, the form and terms of any series of Indenture Securities issuable thereunder by one or more supplemental indentures, and, with the consent of the holders of a majority in aggregate principal amount of the Indenture Securities of any series at the time outstanding (including the notes), evidenced as in the Indenture provided, to execute supplemental indentures adding any provisions to or changing in any manner or eliminating any of the provisions of the Indenture or of any supplemental indenture with respect to Indenture Securities of such series, or modifying in any manner the rights of the holders of the Indenture Securities of such series; provided, however, that no such supplemental indenture shall (1) extend the fixed maturity, or the earlier optional date of maturity, if any, of any Indenture Security of a particular series or reduce the principal amount thereof or the premium thereon, if any, or reduce the rate of payment of interest thereon, or make the principal thereof or premium, if any, or interest thereon payable in any coin or currency other than that provided in the Indenture Security, without the consent of the holder of each Indenture Security so affected, or (2) reduce the principal amount of Indenture Securities of any series, the holders of which are required to consent to any such supplemental indenture, without the consent of the holders of all Indenture Securities of such series outstanding thereunder. (Sections 10.01 and 10.02)

Events of Default and Certain Rights on Default

The Indenture provides that the Trustee or the holders of 33% or more in aggregate principal amount of Indenture Securities of a series outstanding thereunder may declare the principal of all Indenture Securities of such series to be due and payable immediately, if any Event of Default with respect to such series of Indenture Securities shall occur and be continuing. However, if all defaults with respect to Indenture Securities of such series (other than non-payment of accelerated principal) are cured, the holders of a majority in aggregate principal amount of the Indenture Securities of such series outstanding thereunder may waive the default and rescind the declaration and its consequences. Events of Default with respect to a series of Indenture Securities include (unless specifically deleted in the supplemental indenture or Board Resolution under which such series of Indenture Securities is issued, or modified in any such supplemental indenture or Board Resolution):

·	failure to pay interest when due on any Indenture Security of such series, continued for 30 days,

·	failure to pay principal or premium, if any, when due on any Indenture Security of such series, continued for one Business Day,

failure to perform any of our other covenants in the Indenture or the Indenture Securities of such series (other than a covenant included in the Indenture or the Indenture Securities solely for the benefit of series of Indenture Securities other than such series), continued for 60 days after written notice from the Trustee or the holders of 33% or more in aggregate principal amount of the Indenture Securities of such series outstanding thereunder,

·	certain events of bankruptcy, insolvency or reorganization, and

·	any other Event of Default as may be specified for such series.

(Section 6.01)

The Indenture provides that the holders of a majority in aggregate principal amount of the Indenture Securities of any series outstanding thereunder (including the notes) may, subject to certain exceptions, direct the time, method and place of conducting any proceeding for any remedy available to, or exercising any power or trust conferred upon, the Trustee with respect to Indenture Securities of such series and may on behalf of all holders of Indenture Securities of such series waive any past default and its consequences with respect to Indenture Securities of such series, except a default in the payment of the principal of or premium, if any, or interest on any of the Indenture Securities of such series. (Section 6.06)

Holders of Indenture Securities of any series may not institute any proceeding to enforce the Indenture unless the Trustee thereunder shall have refused or neglected to act for 60 days after a request and offer of satisfactory indemnity by the holders of 33% or more in aggregate principal amount of the Indenture Securities of such series outstanding thereunder, but the right of any holder of Indenture Securities of any series to enforce payment of principal of or premium, if any, or interest on the holder’s Indenture Securities when due shall not be impaired. (Section 6.04)

The Trustee is required to give the holders of Indenture Securities of any series notice of defaults with respect to such series (Events of Default summarized above, exclusive of any grace period and irrespective of any requirement that notice of default be given) known to it within 90 days after the happening thereof, unless cured before the giving of such notice, but, except for defaults in payments of principal of, premium, if any, or interest on the Indenture Securities of such series, the Trustee may withhold notice if and so long as it determines in good faith that the withholding of such notice is in the interests of such holders. (Section 6.07)

We are required to deliver to the Trustee each year an Officers’ Certificate stating whether such officers have obtained knowledge of any default by us in the performance of certain covenants and, if so, specifying the nature thereof. (Section 4.06)

Concerning the Trustee

The Indenture provides that the Trustee shall, prior to the occurrence of any Event of Default with respect to the Indenture Securities of any series and after the curing or waiving of all Events of Default with respect to such series which have occurred, perform only such duties as are specifically set forth in the Indenture. During the existence of any Event of Default with respect to the Indenture Securities of any series, the Trustee shall exercise such of the rights and powers vested in it under the Indenture with respect to such series and use the same degree of care and skill in their exercise as a prudent man would exercise or use under the circumstances in the conduct of his own affairs. (Section 7.01)

The Trustee may acquire and hold Indenture Securities and, subject to certain conditions, otherwise deal with KCP&L as if it were not the Trustee under the Indenture. (Section 7.04)

As of December 31, 2005, the Trustee and its affiliates were the trustees for $937.4 million of our secured and unsecured debt under six separate indentures. The Bank of New York is also a lender under a $250 million revolving credit agreement with us, and under a $550 million revolving credit agreement with our parent, Great Plains Energy, with both agreements expiring in December 2009. The Bank of New York and its affiliates are also depositories for funds and perform other services for, and transact other banking business with our affiliates and us in the normal course and may do so in the future.

Satisfaction and Discharge

Upon our request, the Indenture will cease to be of further effect with respect to all Indenture Securities and the Trustee will execute proper instruments acknowledging satisfaction and discharge of the Indenture, when, among other things:

either (i) all Indenture Securities previously authenticated and delivered have been delivered to the Trustee for cancellation, or (ii) all the Indenture Securities not previously delivered to the Trustee for

cancellation have become due and payable (whether at maturity, early redemption or otherwise), and we have deposited, or caused to be deposited, irrevocably with the Trustee as funds in trust solely for the benefit of the holders of the Indenture Securities an amount in cash sufficient to pay principal of, premium, if any, and interest on all outstanding Indenture Securities; and

·	we have paid or caused to be paid all other sums payable under the Indenture.

(Section 12.01)

Defeasance

The Indenture provides that if, at any time after the date of the Indenture, we, if so permitted with respect to Indenture Securities of a particular series, shall deposit with the Trustee, in trust for the benefit of the holders thereof, (1) funds sufficient to pay, or (2) such amount of obligations issued or guaranteed by the government of the United States of America as will, or will together with the income thereon without consideration of any reinvestment thereof, be sufficient to pay all sums due for principal of, premium, if any, and interest on the Indenture Securities of such series, as they shall become due from time to time, and certain other conditions are met, the Trustee shall cancel and satisfy the Indenture with respect to such series to the extent provided therein. (Section 12.02) This latter provision is applicable to the notes but the trust may only be established for the notes if, among other things,

no Event of Default or event which, with the giving of notice or lapse of time or both, would become an Event of Default under the Indenture has occurred and is continuing on the date of the deposit, and 91 days have passed after the deposit has been made and, during that period, certain Events of Default have not occurred and are continuing as of the end of that period,

·	the deposit will not cause the Trustee to have any conflicting interest within the meaning of the Trust Indenture Act of 1939 with respect to our other securities and

we have delivered an opinion of counsel to the effect that the holders of the notes will not recognize income, gain or loss for federal income tax purposes and such opinion of counsel is based on a ruling of the Internal Revenue Service or other change in applicable federal income tax law as a result of the deposit or defeasance and will be subject to federal income tax in the same amounts, in the same manner and at the same time as if the deposit and defeasance had not occurred.

Exchange Act Filings

We have agreed in the Indenture that, whether or not required by the SEC, so long as any notes are outstanding, we will file with the SEC within the time periods specified in the SEC’s rules and regulations (as if required):

·	all quarterly and financial and other information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if we were required to file such Forms; and

·	all current reports that would be required to be filed with the SEC on Form 8-K if we were required to file such reports.

We have also agreed in the Indenture that, for so long as any notes remain outstanding, at any time we are not required to file the reports required by the preceding sentence with the SEC, we will furnish to the holders of the notes and to prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act. (Section 3.04 of the Supplemental Indenture)

Sinking Fund

We are not obligated to make mandatory redemption or sinking fund payments with respect to the notes. (Section 1.11 of the Supplemental Indenture)

Notices

Holders of the notes will receive notices by mail at their addresses as they appear in the security register. (Section 15.04)

Governing Law

New York law will govern the Indenture and the notes. (Section 15.05)

Book-Entry, Delivery and Form

The exchange notes will be represented by one or more global notes in registered form without interest coupons, or the “Global Exchange Notes.” The Global Exchange Notes will be deposited upon issuance with the Trustee as custodian for DTC in New York, New York, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below. So long as DTC or its nominee is the registered owner of a Global Exchange Note, DTC or such nominee will be considered the sole record owner or “Holder” of the notes represented by the Global Exchange Note for all purposes under the Indenture and the notes.

Each person owning a beneficial interest in a Global Exchange Note must rely on the procedures of DTC and on the procedures of the DTC participants to exercise any rights of a Holder of notes.

Under current industry practice, in the event that we request any action of Holders of notes, or in the event that an owner of a beneficial interest in a Global Exchange Note desires to take any action that DTC, as Holder of such Global Exchange Note, is entitled to take, DTC would authorize the DTC participants to take such action and the DTC participants would authorize persons owning through such DTC participants to take that action or would otherwise act upon the instruction of those persons. Neither we nor the Trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of notes by DTC, or for maintaining, supervising or reviewing any records of DTC relating to those notes.

Except as set forth below, the Global Exchange Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Exchange Notes may not be exchanged for exchange notes in certificated form except in the limited circumstances described below. See “— Exchange of Global Exchange Notes for Certificated Exchange Notes”. Except in the limited circumstances described below, owners of beneficial interests in the Global Exchange Notes will not be entitled to receive physical delivery of exchange notes in certificated form.

Transfers of beneficial interests in the Global Exchange Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of the Euroclear System, or “Euroclear,” and Clearstream Banking, S.A., or “Clearstream,” which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised us that, pursuant to procedures established by it:

·	upon deposit of the Global Exchange Notes, DTC will credit the accounts of Participants designated by the Participants depositing the Global Exchange Notes with portions of the principal amount of the Global Exchange Notes; and

ownership of these interests in the Global Exchange Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Exchange Notes).

Investors in the Global Exchange Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Exchange Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) that are Participants in such system. All interests in a Global Exchange Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Exchange Note to those Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Exchange Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of an interest in the Global Exchange Notes will not have exchange notes registered in their names, will not receive physical delivery of the exchange notes in certificated form and will not be considered the registered owners or “Holders” thereof under the Indenture for any purpose.

Payments in respect of the principal of, and interest and premium and additional interest, if any, on a Global Exchange Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered Holder under the Indenture. Under the terms of the Indenture, we and the Trustee will treat the Persons in whose names the notes, including the Global Exchange Notes, are registered as the owners of the exchange notes for the purpose of receiving payments and for all other purposes. Consequently, neither we nor the Trustee or any agent of us or the Trustee has or will have any responsibility or liability for:

any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interests in the Global Exchange Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Exchange Notes; or

·	any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the exchange notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of exchange notes will be governed by standing instructions and customary practices, will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee or us. Neither we nor the Trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the exchange notes, and we and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between Participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Cross-market transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counter-party in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf of delivering or receiving interests in the relevant Global Exchange Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a Holder of exchange notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Exchange Notes and only in respect of such portion of the aggregate principal amount of the exchange notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the exchange notes, DTC reserves the right to exchange the Global Exchange Notes for legended exchange notes in certificated form, and to distribute such exchange notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Exchange Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. Neither we nor the Trustee or any of our or their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Exchange Notes for Certificated Exchange Notes

A Global Exchange Note is exchangeable for certificated exchange notes if:

·	DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Exchange Notes and DTC fails to appoint a successor depositary or (b) has ceased to be a clearing agency registered under the Exchange Act;

·	we, at our option, notify the Trustee in writing that we elect to cause the issuance of the certificated exchange notes; or

·	there has occurred and is continuing an Event of Default with respect to the exchange notes.

In addition, beneficial interests in a Global Exchange Note may be exchanged for certificated exchange notes under prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, certificated exchange notes delivered in exchange for any Global Exchange Note or beneficial interests in Global Exchange Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

Same Day Settlement and Payment

We will make payments in respect of the exchange notes represented by the Global Exchange Notes (including principal, premium, if any, interest and additional interest, if any) by wire transfer of immediately available funds to the accounts specified by the Global Exchange Note Holder. We will make all payments of principal, interest and premium and additional interest, if any, with respect to certificated exchange notes by wire transfer of immediately available funds to the accounts specified by the Holders of the certificated exchange notes or, if no such account is specified, by mailing a check to each such Holder’s registered address. The exchange notes represented by the Global Exchange Notes are expected to be eligible to trade in the PORTAL(^SM) Market and to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in those exchange notes will, therefore, be required by DTC to be settled in immediately available funds. We expect that secondary trading in any certificated exchange notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Exchange Note from a Participant in DTC will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised us that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Exchange Note by or through a Euroclear or Clearstream participant to a Participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

Transfer

The exchange notes will be issued in registered form and will be transferable only upon the surrender of the exchange notes being transferred for registration of transfer. We may require payment of a sum sufficient to cover any tax, assessment or other governmental charge payable in connection with certain transfers and exchanges.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder of KCP&L will have any liability for any of our obligations under the exchange notes or the Indenture or for any claim based on, in respect of, or by reason of such obligations or their creation. Each Holder of the exchange notes by accepting an exchange note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the exchange notes. Such waiver and release may not be effective to waive liabilities under the U.S. Federal securities laws, and it is the view of the SEC that such a waiver is against public policy.

SUMMARY OF U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a general discussion of the material U.S. federal income tax consequences of the acquisition, ownership, and disposition of the exchange notes, to beneficial owners of the exchange notes that are U.S. Holders, as defined below, and the material U.S. federal income and estate tax consequences of the acquisition, ownership, and disposition of the exchange notes to beneficial owners of the exchange notes that are Non-U.S. Holders, as defined below. This discussion is based upon the Internal Revenue Code of 1986, as amended, or “Code,” the Treasury regulations promulgated thereunder, administrative pronouncements and judicial decisions, all as of the date hereof and all of which are subject to change, possibly on a retroactive basis.

This discussion applies only to beneficial owners that hold the exchange notes as “capital assets” within the meaning of section 1221 of the Code. This discussion does not address all aspects of U.S. federal income taxation that may be important to particular investors in light of their individual circumstances or the U.S. federal income tax consequences applicable to special classes of taxpayers such as banks and other financial institutions, insurance companies, real estate investment trusts, regulated investment companies, tax-exempt organizations, partnerships (or entities treated as partnerships) or other pass-through entities, dealers in securities or currencies, traders in securities that elect to use a mark-to-market method of accounting, persons liable for U.S. federal alternative minimum tax, U.S. Holders whose functional currency is not the U.S. dollar, former citizens or residents of the United States, and persons holding exchange notes as part of a hedging or conversion transaction or a straddle. The discussion does not address any non-income tax considerations (except as set forth below with respect to certain U.S. federal estate tax consequences to Non-U.S. Holders), or any foreign, state or local tax consequences.

As used herein, the term “U.S. Holder” means a beneficial owner of an exchange note who or that is for U.S. federal income tax purposes

·	a citizen or individual resident of the United States,

·	a corporation (or other entity properly classified as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any State within the United States, or the District of Columbia, or

·	an estate or trust treated as a U.S. person under section 7701(a)(30) of the Code.

The term “Non-U.S. Holder” means any beneficial owner of an exchange note that is not a U.S. Holder and is not a partnership or other entity properly classified as a partnership for U.S. federal income tax purposes.

If a partnership or other entity properly classified as a partnership for U.S. federal income tax purposes is a beneficial owner of an exchange note, the tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. Such entities and partners of such entities should consult their own tax advisors about the U.S. federal income and other tax consequences of the acquisition, ownership, and disposition of an exchange note.

This discussion is for general purposes only. Holders considering the exchange of their old notes should consult their own tax advisors regarding the application of the U.S. federal income tax laws to their particular situations and the consequences under federal estate or gift tax laws, as well as foreign, state, or local laws and tax treaties, and the possible effects of changes in tax laws.

Treatment of Exchanges under Exchange Offer

The exchange of old notes for the exchange notes pursuant to the exchange offer will not constitute a taxable exchange for U.S. federal income tax purposes. Therefore, you will not recognize taxable gain or loss as a result of exchanging old notes for exchange notes pursuant to the exchange offer, and the tax basis and holding period of the exchange notes received pursuant to the exchange offer will be the same as your adjusted tax basis and holding period for the old notes immediately before such exchange.

U.S. Federal Income Taxation of U.S. Holders

Payments of Interest

If you are a U.S. Holder, interest on your exchange notes generally will be taxable as ordinary interest income at the time payments are accrued or are received in accordance with your regular method of accounting for U.S. federal income tax purposes.

Additional Amounts

As more fully described under “Description of the Exchange Notes -- Optional Redemption” and “The Exchange Offer - Purpose and Effect of the Exchange Offer - Special Interest,” we may be required to pay amounts in excess of stated interest and principal on the exchange notes in certain circumstances. Although the matter is not free from doubt, it is our position that a U.S. Holder should not be required to report any amounts in excess of stated interest and principal on the exchange notes as income for U.S. federal income tax purposes before such time as such amounts accrue or are received in accordance with your regular method of accounting for U.S. federal income tax purposes. It is possible, however, that the Internal Revenue Service, or “IRS,” may take a different position regarding the payment or potential payment of such amounts, in which case the timing, character and amount of income, gain or loss with respect to an exchange note may be different and, in certain circumstances, a U.S. Holder could be required to treat as interest income all or a portion of any gain recognized on the disposition of an exchange note. Holders should consult their own tax advisors as to the tax consequences that relate to the payment or potential payment of amounts in excess of stated interest and principal on the exchange notes.

Amortizable Bond Premium

If a beneficial owner of an exchange note sells such exchange note to a U.S. Holder in a secondary market transaction for an amount in excess of, in general, its principal amount, such U.S. Holder will be considered to have purchased such exchange note with “amortizable bond premium” equal in amount to such excess. Generally, a U.S. Holder may elect to amortize such premium as an offset to interest income, using a constant yield method. The premium amortization is calculated assuming that we will exercise redemption rights in a manner that maximizes the U.S. Holder’s yield. If the U.S. Holder elects to amortize bond premium, such U.S. Holder must reduce his tax basis in the exchange note by the amount of the premium used to offset interest income as set forth above. An election to amortize bond premium applies to all taxable debt obligations held

during or after the taxable year for which the election is made and may be revoked only with the consent of the IRS.

Market Discount

If a beneficial owner of an exchange note sells such exchange note to a U.S. Holder in a secondary market transaction for an amount that is less than, in general, its principal amount, the amount of such difference is treated as “market discount” for federal income tax purposes to such U.S. Holder, unless such difference is considered to be de minimis as described in section 1278(a)(2)(C) of the Code. Under the market discount rules of the Code, a U.S. Holder is required to treat any principal payment on, or any gain on the sale, exchange or redemption or other taxable disposition of, an exchange note as ordinary income to the extent of the accrued market discount that has not previously been included in income. In general, the amount of market discount that has accrued is determined on a ratable basis although in certain circumstances an election may be made to accrue market discount on a constant interest basis. A U.S. Holder may not be allowed to deduct immediately a portion of the interest expense on any indebtedness incurred or continued to purchase or to carry exchange notes with market discount. A U.S. Holder may elect to include market discount in income currently as it accrues, in which case the interest deferral rule set forth in the preceding sentence will not apply. Such an election will apply to all debt instruments acquired on or after the first day of the taxable year to which such election applies and is irrevocable without the consent of the IRS. The tax basis in an exchange note will be increased by the amount of market discount included in income under such election. U.S. Holders are urged to consult their tax advisors as to the tax consequences of the acquisition, ownership, and disposition of exchange notes with market discount.

Sale, Exchange or Redemption of the Exchange Notes

Upon the sale, exchange, redemption or other taxable disposition of the exchange notes, you generally will recognize gain or loss equal to the difference, if any, between the amount realized upon the sale, exchange, redemption or other taxable disposition, other than amounts attributable to accrued and unpaid interest (which will be taxed as ordinary interest income to the extent such interest has not been previously included in income), and your adjusted tax basis in the exchange notes. Any amount attributable to accrued market discount that has not previously been included in income will be taxed in the manner described above under “--Market Discount.” The amount realized by you is the sum of cash plus the fair market value of all other property received on such sale, exchange, redemption or other taxable disposition. A U.S. Holder’s adjusted tax basis in the exchange notes generally will be your cost for the exchange notes (subject to the adjustments described above under “--Amortizable Bond Premium” and --Market Discount,” if applicable).

Subject to the discussion above under “--Additional Amounts,” and except as described above under “--Market Discount,” the gain or loss you recognize on the sale, exchange, redemption or other taxable disposition of the exchange notes generally will be capital gain or loss. The gain or loss generally will be long-term capital gain or loss if you have held the exchange notes for a consecutive combined period of more than 12 months. For individuals, the excess of net long-term capital gains over net short-term capital losses generally is taxed at a lower rate than ordinary income. The distinction between capital gain or loss and ordinary income or loss is also relevant for purposes of, among other things, limitations on the deductibility of capital losses.

Backup Withholding and Information Reporting

In general, a U.S. Holder that is not an exempt recipient will be subject to U.S. federal backup withholding tax at the applicable rate (currently 28%) with respect to payments on the exchange notes and the proceeds of a sale, exchange, redemption or other taxable disposition of the exchange notes, unless the U.S. Holder provides its taxpayer identification number to the paying agent and certifies, under penalty of perjury, that it is not subject to backup withholding on an IRS Form W-9 and otherwise complies with the applicable requirements of the backup withholding rules. In addition, such payments to, and the proceeds of a sale or other taxable disposition by, a U.S. Holder that is not an exempt recipient generally will be subject to information reporting requirements. Backup withholding is not an additional tax. The amount of any backup withholding from a payment to a U.S. Holder may be allowed as a credit against such U.S. Holder’s U.S. federal income tax liability and may entitle such U.S. Holder to a refund, provided the required information is furnished to the IRS in a timely manner.

U.S. Federal Income and Estate Taxation of Non-U.S. Holders

Payments of Interest

If you are a Non-U.S. Holder, subject to the discussion below under “--Additional Amounts” and “--Backup Withholding and Information Reporting,” you generally will not be subject to U.S. federal income or withholding tax on interest paid on the exchange notes so long as that interest is not effectively connected with your conduct of a trade or business within the United States (or, if a treaty applies, is not attributable to a permanent establishment maintained by you in the United States) and:

·	you do not actually or constructively own 10% or more of the total combined voting power of all of our stock entitled to vote;

·	you are not a “controlled foreign corporation” that is related to us, actually or by attribution, through stock ownership;

·	you are not a bank receiving the interest pursuant to a loan agreement entered into in the ordinary course of your trade or business; and

either (a) you certify under penalties of perjury on Form W-8BEN or a suitable substitute form that you are not a “U.S. person” as defined in the Code, and provide your name and address, and U.S. taxpayer identification number, if any or (b) a securities clearing organization, bank or other financial institution that holds customers’ securities in the ordinary course of its trade or business and holds exchange notes certifies under penalties of perjury that such statement has been received from you and furnishes a copy thereof, or (c) you provide such certification to a “qualified intermediary” or a “withholding foreign partnership” and certain other conditions are met.

A Non-U.S. Holder that does not qualify for exemption from withholding as described above generally will be subject to withholding of U.S. federal income tax at a rate of 30% on payments of interest on the exchange notes. You may be entitled to the benefits of an income tax treaty under which interest on the exchange notes is subject to a reduced rate of withholding tax or is exempt from U.S. withholding tax, provided a properly executed Form W-8BEN claiming the reduction or exemption is furnished to us and any other applicable procedures are complied with.

Special rules regarding exemption from, or reduced rates of, U.S. withholding tax may apply in the case of exchange notes held by partnerships or certain types of trusts. Partnerships and trusts that are prospective purchasers should consult their tax advisors regarding special rules that may be applicable in their particular circumstances.

Additional Amounts

As more fully described under “Description of the Exchange Notes -- Optional Redemption” and “The Exchange Offer - Purpose and Effect of the Exchange Offer - Special Interest,” we may be required to pay amounts in excess of stated interest and principal on the exchange notes in certain circumstances. It is unclear whether the payment of any such amounts to a Non-U.S. Holder would be subject to U.S. federal income or withholding tax. We may be required to withhold U.S. federal income tax from any such payments to you at a rate of 30% unless such amounts are effectively connected with your conduct of a trade or business within the U.S. or a tax treaty between the United States and your country of residence reduces or eliminates the withholding tax, and you provide a properly completed and executed Form W-8ECI or Form W-8BEN, as applicable. Holders should consult their own tax advisors as to the tax considerations that relate to the potential payment of amounts in excess of stated interest and principal on the exchange notes.

Sale, Exchange or Redemption of the Exchange Notes

Generally, any gain you recognize on the sale, exchange, redemption or other taxable disposition of an exchange note (other than amounts attributable to accrued and unpaid interest which will be treated as described under “—Payments of Interest” above) will be exempt from U.S. federal income and withholding tax, unless:

·	the gain is effectively connected with your conduct of a trade or business within the United States (or, if a treaty applies, is attributable to a permanent establishment maintained by you in the United States); or

·	if you are an individual, you are present in the United States for 183 days or more during the taxable year and certain other conditions are met.

Effectively Connected Income

If interest, gain or other income you recognize on an exchange note is effectively connected with your conduct of a trade or business within the United States (or, if a treaty applies, is attributable to a permanent establishment maintained by you in the United States), you will be exempt from the withholding tax previously discussed if you provide us with a properly completed and executed Form W-8ECI, but generally you will be subject to U.S. federal income tax on such interest, gain or other income at regular U.S. federal income tax rates. In addition to regular U.S. federal income tax, if you are a corporation, you may be subject to a branch profits tax equal to 30% of your effectively connected earnings and profits, as adjusted for certain items, unless you qualify for a lower rate under an applicable tax treaty.

Federal Estate Taxes

An exchange note held by an individual who at the time of death is not a citizen or resident of the U.S. (as specifically defined for U.S. estate tax purposes) will not be subject to U.S. federal estate tax as a result of such individual’s death, provided that the individual does not actually or constructively own 10% or more of the combined voting power of all our stock and that the interest accrued on the exchange notes was not effectively connected with that holder’s conduct of a trade or business within the United States.

Backup Withholding and Information Reporting

We must report annually to the IRS and to you the amount of interest paid to you and the tax withheld from those payments. These reporting requirements apply regardless of whether withholding was reduced or eliminated by any applicable tax treaty or otherwise. Copies of the information returns reporting those payments and withholding may also be made available to the tax authorities in the country in which you are a resident under the provisions of an applicable income tax treaty or agreement.

Under some circumstances, U.S. Treasury regulations require backup withholding and additional information reporting on payments of interest and other “reportable payments.” Such backup withholding and additional information reporting will not apply to payments on the exchange notes made by us or our paying agent to you if the certification described above under “—Payments of Interest” is received.

Backup withholding and information reporting generally will not apply to payments of proceeds from the sale or other disposition of an exchange note made to you by or through the foreign office of a broker. However, information reporting requirements, and possibly backup withholding, will apply, if such broker is, for U.S. federal income tax purposes, a U.S. person or has certain other enumerated connections with the U.S., unless such broker has documentary evidence in its records that you are a non-U.S. person and certain other conditions are met, or you otherwise establish an exemption. Payments of proceeds from the sale or other disposition of an exchange note made to you by or through the United States office of a broker are subject to information reporting and backup withholding at the applicable rate unless you certify, under penalties of perjury, that you are a non-U.S. person and you satisfy certain other conditions or otherwise establish an exemption. Backup withholding is not an additional tax. You may obtain a refund or credit against your U.S. federal income tax liability of any amounts withheld under the backup withholding rules, provided the required information is furnished to the IRS in a timely matter.

You should consult your tax advisor regarding the application of information reporting and backup withholding in your particular situation, the availability of an exemption therefrom, and the procedure for obtaining such an exemption, if available.

The U.S. federal income tax discussion set forth above is included for general information only and may not be applicable depending upon a Holder’s particular situation. Prospective purchasers of the

exchange notes should consult their own tax advisors with respect to the tax consequences to them of the acquisition, ownership and disposition of the exchange notes, including the tax consequences under state, local, estate, foreign and other tax laws and tax treaties and the possible effects of changes in U.S. or other tax laws.

PLAN OF DISTRIBUTION

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until May 30, 2006, all dealers effecting transactions in the exchange notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the expiration date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the securities) other than commissions or concessions of any broker or dealers and will indemnify the Holders of the exchange notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

LEGAL MATTERS

Certain legal matters with respect to the validity of the exchange notes offered hereby will be passed upon for us by Mark G. English, Esq. At March 29, 2006, Mr. English owned beneficially 1,297 shares of our parent’s, Great Plains Energy, common stock, including restricted stock and 4,355 performance shares, which may be paid in shares of our parent’s common stock at a later date based upon our parent’s performance.

EXPERTS

The consolidated financial statements, the related financial statement schedules and management’s report on the effectiveness of internal control over financial reporting included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein (which reports (1) express an unqualified opinion on the financial statements and financial statement schedules and include an explanatory paragraph regarding the adoption of a new accounting standard and revisions made to the consolidated statement of cash flows for the year ended December 31, 2003, (2) express an unqualified opinion on management’s assessment regarding the effectiveness of internal control over financial reporting, and (3) express an unqualified opinion on the effectiveness of internal control over financial reporting) and have been so included in reliance on the reports of such firm given upon their authority as experts in accounting and auditing.

INDEMNIFICATION OF DIRECTORS, OFFICERS

AND OTHERS FOR SECURITIES ACT LIABILITIES

Missouri law provides that a Missouri corporation, such as KCP&L, may indemnify, under circumstances provided by law, its directors, officers, employees and agents against liabilities and expenses they may incur. These circumstances could include indemnification for liabilities and expenses incurred in connection with claims arising under the Securities Act of 1933. Our restated articles of consolidation provide for indemnification of our directors, officers, employees, and agents, to the full extent permitted by Missouri law.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers or persons controlling KCP&L under the foregoing provisions, we have been informed that, in the opinion of the SEC, this indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, and other information with the SEC through the SEC's Electronic Data Gathering, Analysis and Retrieval system and these filings are publicly available through the SEC's website (http://www.sec.gov). You may read and copy such material at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain copies of such material at prescribed rates from the Public Reference Section of the SEC, 100 F Street, N.E., Washington, D.C. 20549.

(PAGE INTENTIONALLY LEFT BLANK)

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page No.
Audited Financial Statements of Kansas City Power & Light Company:
Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003	F-2
Consolidated Balance Sheets -- December 31, 2005 and 2004...................................................	F-3
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003 ...................................................................................................................................................	F-5
Consolidated Statements of Common Shareholder’s Equity for the years ended December 31, [ 2005, 2004 and 2003.................................................................................................................	F-6
Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 and 2003....................................................................................................................................	F-7
Notes to Consolidated Financial Statements...............................................................................	F-8
Report of Independent Registered Public Accounting Firm........................................................	F-42
Management’s Report on Internal Control Over Financial Reporting........................................	F-43
Report of Independent Registered Public Accounting Firm........................................................	F-43
Schedule II - Valuation and Qualifying Accounts and Reserves ...............................................	F-45

F-1



KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Income


Year Ended December 31	2005			2004			2003
Operating Revenues	(thousands)
Electric revenues	$	1,130,792		$	1,090,067		$	1,054,900
Other revenues		113			1,568			2,101
Total		1,130,905			1,091,635			1,057,001
Operating Expenses
Fuel		207,875			179,362			160,327
Purchased power		61,263			52,533			53,163
Other		265,707			259,699			241,701
Maintenance		90,321			83,535			85,391
Depreciation and amortization		146,610			145,246			140,955
General taxes		104,823			98,984			95,590
(Gain) loss on property		4,613			5,133			(1,603	)
Total		881,212			824,492			775,524
Operating income		249,693			267,143			281,477
Non-operating income		16,104			5,402			5,251
Non-operating expenses		(4,281	)		(7,407	)		(8,280	)
Interest charges		(61,841	)		(74,170	)		(70,294	)
Income from continuing operations before
income taxes and minority interest in subsidiaries		199,675			190,968			208,154
Income taxes		(48,213	)		(52,763	)		(83,572	)
Minority interest in subsidiaries		(7,805	)		5,087			1,263
Income from continuing operations		143,657			143,292			125,845
Discontinued operations, net of income taxes (Note 7)		-			-			(8,690	)
Net income	$	143,657		$	143,292		$	117,155

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

F-2

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets

	December 31
	2005		2004
ASSETS	(thousands)
Current Assets
Cash and cash equivalents	$	2,961	$	51,619
Receivables, net		70,264		63,366
Fuel inventories, at average cost		17,073		21,121
Materials and supplies, at average cost		57,017		54,432
Deferred income taxes		8,944		12,818
Prepaid expenses		11,292		12,511
Derivative instruments		-		363
Total		167,551		216,230
Nonutility Property and Investments
Nuclear decommissioning trust fund		91,802		84,148
Other		7,694		20,576
Total		99,496		104,724
Utility Plant, at Original Cost
Electric		4,959,539		4,841,355
Less-accumulated depreciation		2,322,813		2,196,835
Net utility plant in service		2,636,726		2,644,520
Construction work in progress		100,952		53,821
Nuclear fuel, net of amortization of $115,240 and $127,631		27,966		36,109
Total		2,765,644		2,734,450
Deferred Charges and Other Assets
Regulatory assets		179,922		144,345
Prepaid pension costs		98,002		116,024
Derivative instruments		-		674
Other		27,905		20,947
Total		305,829		281,990
Total	$	3,338,520	$	3,337,394

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

F-3

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Balance Sheets

	December 31
	2005			2004
LIABILITIES AND CAPITALIZATION	(thousands)
Current Liabilities
Notes payable to Great Plains Energy	$	500		$	24
Commercial paper		31,900			-
Current maturities of long-term debt		-			250,000
EIRR bonds classified as current		-			85,922
Accounts payable		106,040			84,105
Accrued taxes		27,448			34,497
Accrued interest		11,549			9,800
Accrued payroll and vacations		27,520			22,870
Accrued refueling outage costs		8,974			13,180
Other		8,600			8,327
Total		222,531			508,725
Deferred Credits and Other Liabilities
Deferred income taxes		627,048			654,055
Deferred investment tax credits		29,698			33,587
Asset retirement obligations		145,907			113,674
Pension liability		85,301			90,491
Regulatory liabilities		69,641			4,101
Derivative instruments		2,601			-
Other		38,387			42,832
Total		998,583			938,740
Capitalization
Common shareholder's equity
Common stock-1,000 shares authorized without par value
1 share issued, stated value		887,041			887,041
Retained earnings		283,850			252,893
Accumulated other comprehensive loss		(29,909	)		(40,334	)
Total		1,140,982			1,099,600
Long-term debt (Note 18)		976,424			790,329
Total		2,117,406			1,889,929
Commitments and Contingencies (Note 12)
Total	$	3,338,520		$	3,337,394

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

F-4


KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Cash Flows

							Revised
Year Ended December 31	2005			2004			2003
Cash Flows from Operating Activities	(thousands)
Net income	$	143,657		$	143,292		$	117,155
Adjustments to reconcile income to net cash from operating activities:
Depreciation and amortization		146,610			145,246			140,955
Amortization of:
Nuclear fuel		13,374			14,159			12,334
Other		7,681			7,719			9,350
Deferred income taxes, net		(33,408	)		10,861			34,285
Investment tax credit amortization		(3,889	)		(3,984	)		(3,994	)
(Gain) loss on property		4,613			5,133			(1,603	)
Minority interest in subsidiaries		7,805			(5,087	)		(1,263	)
Other operating activities (Note 2)		79,043			(1,080	)		(24,627	)
Net cash from operating activities		365,486			316,259			282,592
Cash Flows from Investing Activities
Utility capital expenditures		(332,055	)		(190,548	)		(148,675	)
Allowance for borrowed funds used during construction		(1,598	)		(1,498	)		(1,368	)
Purchases of nonutility property		(127	)		(254	)		(147	)
Proceeds from sale of assets		469			7,465			4,135
Purchases of nuclear decommissioning trust investments		(34,607	)		(49,720	)		(111,699	)
Proceeds from nuclear decommissioning trust investments		31,055			46,167			108,179
Hawthorn No. 5 partial insurance recovery		10,000			30,810			3,940
Hawthorn No. 5 partial litigation settlements		-			1,139			17,263
Other investing activities		(930	)		(7,100	)		(4,045	)
Net cash from investing activities		(327,793	)		(163,539	)		(132,417	)
Cash Flows from Financing Activities
Issuance of long-term debt		334,417			-			-
Repayment of long-term debt		(335,922	)		(209,140	)		(124,000	)
Net change in short-term borrowings		32,376			(21,959	)		(1,867	)
Dividends paid to Great Plains Energy		(112,700	)		(119,160	)		(98,000	)
Equity contribution from Great Plains Energy		-			225,000			100,000
Issuance fees		(4,522	)		(2,362	)		(266	)
Net cash from financing activities		(86,351	)		(127,621	)		(124,133	)
Net Change in Cash and Cash Equivalents		(48,658	)		25,099			26,042
Less: Net Change in Cash and Cash Equivalents from
Discontinued Operations		-			-			(307	)
Cash and Cash Equivalents at Beginning of Year		51,619			26,520			171
Cash and Cash Equivalents at End of Year	$	2,961		$	51,619		$	26,520

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

F-5

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

	2005					2004					2003
	Shares		Amount			Shares		Amount			Shares		Amount
Common Stock	(thousands, except share amounts)
Beginning balance		1	$	887,041			1	$	662,041			1	$	562,041
Equity contribution from Great Plains Energy		-		-			-		225,000			-		100,000
Ending balance		1		887,041			1		887,041			1		662,041
Retained Earnings
Beginning balance				252,893					228,761					209,606
Net income				143,657					143,292					117,155
Dividends:
Common stock held by Great Plains Energy				(112,700	)				(119,160	)				(98,000	)
Ending balance				283,850					252,893					228,761
Accumulated Other Comprehensive Loss
Beginning balance				(40,334	)				(35,244	)				(26,614	)
Derivative hedging activity, net of tax				7,571					(233	)				(83	)
Minimum pension obligation, net of tax				2,854					(4,857	)				(8,547	)
Ending balance				(29,909	)				(40,334	)				(35,244	)
Total Common Shareholder's Equity			$	1,140,982				$	1,099,600				$	855,558

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

F-6

KANSAS CITY POWER & LIGHT COMPANY
Consolidated Statements of Comprehensive Income

Year Ended December 31	2005			2004			2003
	(thousands)
Net income	$	143,657		$	143,292		$	117,155
Other comprehensive income
Gain on derivative hedging instruments		12,650			280			657
Income taxes		(4,759	)		(111	)		(256	)
Net gain on derivative hedging instruments		7,891			169			401
Reclassification to expenses, net of tax		(320	)		(402	)		(484	)
Derivative hedging activity, net of tax		7,571			(233	)		(83	)
Change in minimum pension obligation		5,410			(7,321	)		(14,012	)
Income taxes		(2,556	)		2,464			5,465
Net change in minimum pension obligation		2,854			(4,857	)		(8,547	)
Comprehensive income	$	154,082		$	138,202		$	108,525

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

F-7

KANSAS CITY POWER & LIGHT COMPANY

Notes to Consolidated Financial Statements

The terms “Company” and “KCP&L” are used throughout this report. “KCP&L” refers to Kansas City Power & Light Company and the “Company” refers to KCP&L and its consolidated subsidiaries.

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization

KCP&L, a wholly owned subsidiary of Great Plains Energy Incorporated (Great Plains Energy), is an integrated, regulated electric utility that provides electricity to customers primarily in the states of Missouri and Kansas. The Company’s wholly owned subsidiary, Home Service Solutions Inc. (HSS) sold its wholly owned subsidiary, Worry Free Service, Inc. (Worry Free) in February 2005 and completed the disposition of its interest in R.S. Andrews Enterprises, Inc. (RSAE) in June 2003. See Note 7 for additional information concerning the June 2003 disposition of RSAE. After these sales, HSS has no active operations.

The Company’s sole reportable business segment is KCP&L. Other activities not considered a reportable segment include the activity of HSS.

Cash and Cash Equivalents

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

Fair Value of Financial Instruments

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

Nonutility property and investments - Investments and nonutility property includes the nuclear decommissioning trust fund recorded at fair value. Fair value is based on quoted market prices of the investments held by the fund.

Long-term debt - The incremental borrowing rate for similar debt was used to determine fair value if quoted market prices were not available. Book values of long-term debt were 1% below fair values at December 31, 2005.

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

Derivative Instruments

The Company accounts for derivative instruments in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. This statement generally requires derivative instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships. The Company enters into derivative contracts to manage its exposure to commodity price fluctuations and interest rate risk. 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. The Company may elect the NPNS exception, which requires the effects of the derivative to be recorded as the underlying contract settles.

The Company accounts 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. At the inception of a derivative instrument, the Company designates its derivative instrument as NPNS, a cash flow hedge or a non-hedging derivative under the requirements of SFAS No. 133. In addition, if a derivative instrument is designated as a cash flow hedge, the Company documents its method of determining hedge effectiveness and measuring ineffectiveness. See Note 20 for additional information regarding derivative financial instruments and hedging activities.

F-8

Other Nonutility Property

Other nonutility property includes land, buildings and surge protectors and is recorded at historical cost, net of accumulated depreciation, and has a range of estimated useful lives of 7 to 43 years.

Utility Plant

KCP&L's utility plant is stated at historical costs of construction. 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 Accrued Refueling Outage Costs). When property units are retired or otherwise disposed, the original cost, net of salvage, is charged to accumulated depreciation. Substantially all 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.

As prescribed by the Federal Energy Regulatory Commission (FERC), Allowance for Funds used During Construction (AFDC) is charged to the cost of the plant. AFDC is included in the rates charged to customers by KCP&L over the service life of the property. AFDC equity funds are included as a non-cash item in non-operating income and AFDC borrowed funds are a reduction of interest charges. The rates used to compute gross AFDC are compounded semi-annually and averaged 7.1% in 2005, 8.6% in 2004 and 8.2% in 2003.

The balances of utility plant, at original cost, with a range of estimated useful lives are listed in the following table.


December 31	2005		2004
Utility Plant, at original cost	(millions)
Production (23 - 42 years)	$	2,970.1	$	2,938.5
Transmission (27 - 76 years)		331.2		315.5
Distribution (8 - 75 years)		1,377.3		1,320.0
General (5 - 50 years)		280.9		267.4
Total ^(a)	$	4,959.5	$	4,841.4
^(a) Includes $80.4 million and $66.6 million of land and other assets for
which depreciation was not recorded in 2005 and 2004, respectively.

Depreciation, Depletion and Amortization

Depreciation and amortization of KCP&L’s 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.

Depreciation of nonutility property is computed using the straight-line method. The Company’s nonutility property annual depreciation rates for 2005, 2004 and 2003 were 11.2%, 11.8% and 11.1%, respectively.

Accrued Refueling Outage Costs

KCP&L accrues anticipated incremental costs to be incurred during scheduled Wolf Creek refueling outages monthly over the unit's operating cycle, normally the 18 months preceding the outage. Estimated incremental costs, which include operating, maintenance and replacement power expenses, are based on anticipated outage costs and the estimated outage duration. Changes to or variances from those estimates are recorded when known or are probable.

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. Related liabilities for decommissioning are included on the Company’s balance sheet in Asset Retirement Obligations (AROs). As a result of the authorized regulatory treatment and related regulatory accounting, differences between the

F-9

decommissioning trust fund asset and the related ARO are recorded as a regulatory asset or liability. See Note 15 for discussion of AROs including those associated with nuclear plant decommissioning costs.

Regulatory Matters

KCP&L, an integrated, regulated electric utility, is subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Pursuant to SFAS No. 71, KCP&L defers items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded if KCP&L were not regulated. See Note 5 for additional information concerning regulatory matters.

Revenue Recognition

KCP&L recognizes revenues on sales of electricity when the service is provided. Revenues recorded include electric services provided but not yet billed by KCP&L. Unbilled revenues are recorded for kWh usage in the period following the customers’ billing cycle to the end of the month. The estimate is based on net system kWh usage less actual billed kWhs, adjusted for weather. Estimated unbilled kWhs are allocated and priced by state across the rate classes based on the following month budget.

As a public utility, KCP&L collects from customers gross receipts taxes levied by state and local governments. These taxes are recorded gross in operating revenues and general taxes on the Company’s statements of income. KCP&L’s gross receipts taxes collected were $39.3 million, $37.6 million and $38.3 million in 2005, 2004 and 2003, respectively.

KCP&L records sale and purchase activity on a net basis in purchased power when RTO/ISO markets require it to sell and purchase power from the RTO/ISO rather than directly transact with suppliers and end-use customers.

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 charged to income to maintain the allowance at a level considered adequate to cover losses. Receivables are charged off against the reserve when they are deemed uncollectible.

Property Gains and Losses

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

Asset Impairments

Long-lived assets and finite lived intangible assets subject to amortization are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” SFAS No. 144 requires that 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.

Income Taxes

In accordance with SFAS No. 109, “Accounting for Income Taxes,” the Company has recognized deferred taxes for temporary book to tax differences using the liability method. The liability method requires that deferred tax balances be adjusted to reflect enacted tax rates that are anticipated to be in effect when the temporary differences 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 its subsidiaries, including the Company, file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss. In accordance with Great Plains Energy’s intercompany tax allocation agreement with its subsidiaries, including the Company, it also allocates its

F-10

own net income tax benefits to its direct subsidiaries based on the positive taxable income of each company in the consolidated federal or combined state returns. Consistent with its ratemaking treatment, KCP&L uses the separate return method, adjusted for the allocation of parent company tax benefits, to compute its income tax provision.

KCP&L has 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 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.

Stock Options

KCP&L officers participate in Great Plains Energy’s equity compensation plan, which is described more fully in Note 9. The Company adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” for stock options as of January 1, 2003. The Company elected to use the modified prospective method of adoption; therefore, stock option compensation cost recognized beginning January 1, 2003, was the same as if the fair value recognition provisions of SFAS No. 123 had been applied to all stock options granted after October 1, 1995.

In December 2004, FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” which the Company adopted as of January 1, 2006. Management determined that this statement will not have a significant impact on the Company’s results of operations or financial position.

2.	SUPPLEMENTAL CASH FLOW INFORMATION

*Other Operating Activities*
	2005			2004			2003
Cash flows affected by changes in:	(millions)
Receivables	$	(8.5	)	$	1.6		$	(2.9	)
Fuel inventories		4.9			1.8			(0.8	)
Materials and supplies		(2.6	)		2.2			(5.8	)
Accounts payable		16.3			1.8			7.8
Accrued taxes		(17.2	)		(6.6	)		(2.8	)
Accrued interest		1.7			(2.0	)		(3.7	)
Accrued refueling outage costs		(4.2	)		11.4			(6.5	)
Pension and postretirement benefit assets and obligations		4.6			(8.0	)		(20.3	)
Allowance for equity funds used during construction		(1.8	)		(2.1	)		(1.4	)
Proceeds from the sale of SO₂ emission allowances		61.0			0.3			0.2
Proceeds from T-Locks		12.0			-			-
Other		12.8			(1.5	)		11.6
Total other operating activities	$	79.0		$	(1.1	)	$	(24.6	)
Cash paid during the period:
Interest	$	57.6		$	73.8		$	71.4
Income taxes	$	104.1		$	64.9		$	68.1

F-11

Discontinued Operations

In 2005, the Company changed the presentation of its consolidated statements of cash flows to include the cash flows from operating, investing and financing activities of discontinued operations within the respective categories of operating, investing and financing activities and retroactively revised the consolidated statement of cash flows for the year ended December 31, 2003, as applicable.


	2003
	(millions)
Net cash flows from operating activities as previously reported	$	281.4
Change in net cash flows		1.2
Net cash flows from operating activities as currently reported		282.6
Net cash flows from investing activities as previously reported		(132.4	)
Change in net cash flows		-
Net cash flows from investing activities as currently reported		(132.4	)
Net cash flows from financing activities as previously reported		(122.6	)
Change in net cash flows		(1.5	)
Net cash flows from financing activities as currently reported	$	(124.1	)

Significant Non-Cash Items

Asset Retirement Obligations

During 2005, KCP&L recorded AROs totaling $26.7 million, increased net utility plant by $13.0 million and increased regulatory assets by $13.7 million. This activity had no impact on the Company’s 2005 net income and had no effect on 2005 cash flows. See Note 15 for additional information.

During 2003, KCP&L adopted SFAS No. 143, “Accounting for Asset Retirement Obligation,” and accordingly, recorded AROs totaling $99.2 million, reversed the decommissioning liability of $64.6 million previously accrued and increased net utility plant by $18.3 million. The $16.3 million net cumulative effect was recorded as a regulatory asset and therefore, had no impact on net income. The adoption of SFAS No. 143 had no effect on the Company’s 2003 cash flows.

FIN No. 46

KCP&L consolidated a lease trust and de-consolidated KCPL Financing I in 2003, as required by FASB Interpretation (FIN) No. 46, “Consolidation of Variable Interest Entities,” as amended. As a result of the consolidation of the lease trust, the Company’s long-term debt increased $143.8 million. The consolidation of the lease trust had no effect on the Company’s 2003 cash flows. See Note 12 for additional information concerning the consolidation of the lease trust.

Prior to the de-consolidation of KCPL Financing I, the Company reflected $150 million of 8.3% preferred securities issued by KCPL Financing I on its respective balance sheets. As a result of the de-consolidation, the Company’s other nonutility property and investments increased $4.6 million representing the investment in the common securities of KCPL Financing I, and long-term debt increased $154.6 million representing the 8.3% Junior Subordinated Deferrable Interest Debentures issued by KCP&L and held by KCPL Financing I. The de-consolidation of KCPL Financing I had no effect on the Company’s 2003 cash flows.

Minimum Pension Liability

The Company reduced its minimum pension liability $6.3 million primarily due to an increase in the market value of plan assets. This was offset by a $0.9 million reduction of an intangible asset and Other Comprehensive Income (OCI) of $5.4 million ($2.9 million net of tax) in 2005. In 2004, primarily as a result of lower discount rates and historical losses in the market value of plan assets, the Company recorded an additional minimum pension liability of $5.4 million and a reduction to an intangible asset of $1.9 million offset by OCI of $7.3 million ($4.9 million net of tax). Recording the minimum pension liabilities had no effect on the Company’s cash flows.

F-12

RSAE Disposition

In 2003, HSS completed the disposition of its interest in RSAE. See Note 7 for additional information concerning the disposition of RSAE. The following table summarizes the Company’s loss from discontinued operations as a result of this transaction.


	2003
	(millions)
Cash repayment of supported bank line	$	(22.1	)
Write-off of intercompany balance and investment		4.8
Accrued transaction costs		(1.6	)
Income tax benefit		11.8
Loss on disposition		(7.1	)
Pre-disposition operating losses		(1.6	)
Discontinued operations	$	(8.7	)

3.	RECEIVABLES

The Company’s receivables are detailed in the following table.


	December 31
	2005			2004
	(millions)
Customer accounts receivable ^(a)	$	34.0		$	21.6
Allowance for doubtful accounts		(1.0	)		(1.7	)
Other receivables		37.3			43.5
Total receivables	$	70.3		$	63.4
^(a) Customer accounts receivable included unbilled receivables of $31.4
million and $31.2 million at December 31, 2005 and 2004, respectively.

The Company’s other receivables at December 31, 2005, consisted primarily of receivables from partners in jointly owned electric utility plants and wholesale sales receivables. At December 31, 2004, the balance consisted primarily of receivables from partners in jointly owned electric utility plants, wholesale sales receivables and accounts receivable held by Worry Free.

During 2005, KCP&L entered into a new three-year revolving agreement to sell all of its retail electric accounts receivable to its wholly owned subsidiary, Kansas City Power & Light Receivables Company (Receivables Company), which in turn sold an undivided percentage ownership interest in the accounts receivable to Victory Receivables Corporation, an independent outside investor. In accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities,” the agreements qualify as a sale under which the creditors of Receivables Company are entitled to be satisfied out of the assets of Receivables Company prior to any value being returned to KCP&L or its creditors. Accounts receivable sold by Receivables Company to the outside investor under this revolving agreement totaled $70 million at December 31, 2005. The proceeds of this sale were forwarded to KCP&L as consideration for its sale. The new agreement allows for a maximum outstanding principal amount sold to the outside investor of $100 million during the period June 1 through October 31, and $70 million during the period November 1 through May 31 of each year.

Under the agreement, 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 2.5% of the outstanding principal amount of the receivables sold to Receivables Company. KCP&L does not recognize a servicing asset or liability since management determined the collection agent fee earned by KCP&L approximates market value.

F-13

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


			Receivables			Consolidated
2005	KCP&L		Company			KCP&L
	(millions)
Receivables (sold) purchased	$	(605.8	)	$	535.8		$	(70.0	)
Collections		499.3			(499.3	)		-
(Gain) loss on sale of accounts receivable ^(a)		6.0			(5.0	)		1.0
Servicing fees		1.4			(1.4	)		-
Fees to outside investor		-			(1.5	)		(1.5	)

Cash flows during the period
Cash proceeds from sale of receivables ^(b)	$	569.3		$	(499.3	)	$	70.0
Servicing fees		1.4			(1.4	)		-
^(a) The net loss is the result of the timing difference inherent in collecting receivables and over
the life of the agreement will net to zero.
^(b) During 2005, Receivables Company received $70 million cash from the outside investor
for the sale of accounts receivable, which was then forwarded to KCP&L for consideration
of its sale.

KCP&L had a revolving agreement, which expired in January 2005, to sell all of its right, title and interest in the majority of its customer accounts receivable to Receivables Company, which in turn sold most of the receivables to independent outside investors. The expired agreement was structured as a true sale under which the creditors of Receivables Company were entitled to be satisfied out of the assets of Receivables Company prior to any value being returned to KCP&L or its creditors. Accounts receivable sold under the expired revolving agreement totaled $84.9 million at December 31, 2004. As a result of the sale to the outside investors, Receivables Company received up to $70 million in cash, which was forwarded to KCP&L as consideration for its sale. At December 31, 2004, Receivables Company had received $65.0 million in cash.

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


	2005		2004		2003
Gross proceeds on sale of	(millions)
accounts receivable	$	46.1	$	929.1	$	939.5
Collections		44.3		928.0		949.5
Loss on sale of accounts receivable		-		2.5		3.7
Late fees		0.1		2.2		2.3

4.	NUCLEAR PLANT

KCP&L owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek), its only nuclear generating unit. Wolf Creek is regulated by the Nuclear Regulatory Commission (NRC), with respect to licensing, operations and safety-related requirements.

Spent Nuclear Fuel and 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 kilowatt-hour of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to fuel expense. In 2002, the U.S. Senate approved Yucca Mountain, Nevada as a long-term geologic repository. The DOE is currently in the process of preparing an application to obtain the NRC license to proceed with construction of the repository. Management cannot predict when this site may be available. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel first from the

F-14

owners with the oldest spent fuel. Wolf Creek has completed an on-site storage facility that is designed to hold all spent fuel generated at the plant through the end of its 40-year licensed life in 2025. See Note 14 for a related legal proceeding.

Nuclear Plant Decommissioning Costs

The Public Service Commission of the State of Missouri (MPSC) and The State Corporation Commission of the State of Kansas (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 2005 and is the basis for the current cost of decommissioning estimates in the following table. The MPSC issued an order effective January 20, 2006, continuing the Missouri jurisdictional funding at the previously ordered level. The MPSC order did not explicitly approve or disapprove the 2005 decommissioning cost study submitted by KCP&L. The KCC has not yet ruled on the study but has set a procedural schedule in 2006 to address it.

The Missouri funding schedule previously approved by the MPSC assumes funding through the expiration of Wolf Creek’s current NRC operating license (2025). In 2005, the MPSC order regarding the comprehensive energy plan increased Wolf Creek’s depreciable life for Missouri regulatory purposes from 40 to 60 years and assumes funding through 2045. The Kansas funding schedule previously approved by KCC assumes that Wolf Creek will be granted a 20-year license extension and, thus, assumes funding through 2045. WCNOC has filed with the NRC a letter of intent to file an application for a license extension. Management anticipates that WCNOC will file that application with the NRC in 2006. As such, it is likely that any future decommissioning cost study and funding levels will be based on the assumed extended life.

Nuclear decommissioning cost and the associated nuclear decommissioning trust funding levels were addressed in the general rate cases filed in February 2006. KCP&L proposed cost estimates, assumptions and related funding schedules for nuclear plant decommissioning in its general rate cases as provided in the following table. KCP&L’s proposal will be considered by the MPSC and KCC; however, the outcome could differ from the proposal.


	Total		KCP&L's
	Station		47% Share
	(millions)
Current cost of decommissioning (in 2005 dollars)	$	518		$	243
Future cost of decommissioning (in 2045 dollars)		2,897			1,362

Annual escalation factor	4.40%
Annual return on trust assets^(a)	6.48%
^(a) The 6.48% rate of return is thru 2025. The rate then systematically decreases
through 2045 to 4.04% based on the assumption that the fund's investment mix
will become increasingly more conservative as the decommissioning date
approaches.

F-15

KCP&L currently contributes approximately $3.6 million annually to a tax-qualified trust fund to be used to decommission Wolf Creek. If KCP&L’s proposal is accepted by the MPSC and KCC, total annual funding would not change. Amounts funded are charged to other operating expense and recovered in billings to customers. If the actual return on trust assets is below the anticipated level, management believes a rate increase would be allowed ensuring full recovery of decommissioning costs over the remaining life of the station. The following table summarizes the change in the decommissioning trust fund.


December 31	2005		2004
Decommissioning Trust	(millions)
Beginning balance	$	84.1	$	75.0
Contributions		3.6		3.6
Realized gains		3.9		3.6
Unrealized gains		0.2		1.9
Ending balance	$	91.8	$	84.1

The decommissioning trust is reported at fair value on the balance sheets and is invested in assets as detailed in the following table.


	December 31
Asset Category	2005			2005
Equity securities		48	%	46	%
Debt securities		46	%	50	%
Other		6	%	4	%
Total		100	%	100	%

Nuclear Liability and Insurance

The owners of Wolf Creek, a nuclear generating station, (Owners) maintain nuclear insurance for Wolf Creek in four areas: liability, worker radiation, property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war. Both the nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts of terrorism and related losses, as defined by the Terrorism Risk Insurance Act, including replacement power costs. An industry aggregate limit of $0.3 billion exists for liability claims, regardless of the number of non-certified acts 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, 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 are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. For certified acts of terrorism, the individual policy limits apply. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

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 $10.8 billion. This limit of liability consists of the maximum available commercial insurance of $0.3 billion, and the remaining $10.5 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 $100.6 million ($47.3 million, KCP&L’s 47% share) per incident at any commercial reactor in the country, payable at no more than $15 million ($7.1 million, KCP&L’s 47% share) per incident per year effective with the Energy Policy Act of 2005. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. This assessment is in addition to worker radiation claims insurance. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims.

F-16

Property, Decontamination, Premature Decommissioning and Extra Expense Insurance

The Owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, KCP&L's 47% share). NEIL provides this insurance.

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 $26.5 million ($12.4 million, KCP&L’s 47% share) per policy year.

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 KCP&L’s results of operations, financial position and cash flows.

Low-Level Waste

The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Compact) and selected a site in northern Nebraska to locate a disposal facility. WCNOC and the owners of the other five nuclear units in the Compact provided most of the pre-construction financing for this project.

On December 18, 1998, the application for a license to construct this project was denied. After the license denial, WCNOC, the Compact Commission (Commission) and others filed a lawsuit in federal court contending Nebraska officials acted in bad faith while handling the license application. In September 2002, the U.S. District Court Judge presiding over the lawsuit issued his decision in the case finding that the State of Nebraska acted in bad faith in processing the license application for a low-level radioactive waste disposal site in Nebraska and rendered a judgment on behalf of the Commission in the amount of $151.4 million against the state. After the U.S. Court of Appeals affirmed the decision, Nebraska and the Commission settled the case by Nebraska agreeing to pay the Commission a one-time amount of $145.8 million. At the request of the Commission, WCNOC along with other members of the Compact, filed with the Commission their claims for refund. In 2005, WCNOC received a return of its investment of $19.6 million ($9.2 million, KCP&L’s 47% share), including pre-judgment interest and attorney’s fees. The Commission continues to explore alternative long-term waste disposal capability and has retained a portion of the settlement, above the amounts returned, until it determines what role it will take in the development of alternative disposal capability. In February 2006, the Commission decided to refund an additional $1.7 million ($0.8 million, KCP&L’s 47% share) to WCNOC. The remaining insignificant amount will be retained by the Commission for future operations. At December 31, 2005, KCP&L’s balance sheet no longer reflects an investment in the Compact. KCP&L's net investment in the Compact was $7.4 million at December 31, 2004.

Wolf Creek continues to dispose of its low-level radioactive waste at the reopened disposal facility at Barnwell, South Carolina. South Carolina intends to gradually decrease the amount of waste it allows from outside its compact until around 2008 when it intends to no longer accept waste from generators outside its compact. Wolf Creek remains able to dispose of some of its radioactive waste at a facility in Utah. Although management is

F-17

unable to predict when a permanent disposal facility for Wolf Creek low-level radioactive waste might become available, this issue is not expected to affect continued operation of Wolf Creek.

5.	REGULATORY MATTERS

KCP&L’s Comprehensive Energy Plan

·	KCP&L will make energy infrastructure investments as detailed in the orders and summarized in the table below.


			Estimated
			Capital
Project		Details	Expenditures
			(millions)
Iatan No. 2 ^(a)		Building and owning 465 MW of an 850 MW coal fired
		plant with an estimated completion date of June 2010	$	733
Wind Generation		Installation of 100.5 MW of wind generation in 2006		166
Environmental		Retrofit of selected existing coal plants		272
Asset Management		Enhanced system performance and reliability		42
Customer Programs		Various demand management, distributed generation and
		efficiency programs		53
Total ^(b)			$	1,266
(a)	MW based on current estimates.
(b)	These amounts are estimates. Because of the magnitude of these investments and the length of time
	to implement the comprehensive energy plan, actual expenditures may differ from these estimates.

Ownership agreements are being finalized with Iatan No. 2 partners. KCP&L has awarded a contract for detailed engineering design services and project and construction management support. Detailed project engineering and design has begun and plant construction is expected to start in 2006. KCP&L has received an air permit from the Missouri Department of Natural Resources, which is being appealed by the Sierra Club. KCP&L anticipates issuances of a wetlands permit, a permit for the construction of a temporary barge slip and an Environmental Assessment with a finding of No Significant Impact toward mid-year 2006.

KCP&L has selected a developer and contractor for the construction of a 100.5 MW wind project in Kansas. Construction will begin in the first half of 2006 and management expects the project to be completed in time for inclusion in rates in 2007. The orders also include the possible addition of another 100 MW of wind generation in 2008 if supported by a detailed evaluation.

KCP&L has awarded a contract to install a Selective Catalytic Reduction (SCR) system at LaCygne No. 1 scheduled for completion in May 2007. Additional environmental upgrades at LaCygne No. 1 are scheduled for 2009. Other planned environmental investments include a similar SCR upgrade and the addition of a wet scrubber and baghouse at Iatan No. 1 expected to be completed in 2008.

·	Several demand management efficiency and affordability programs are being implemented to help customers manage usage and costs including online energy analysis, air conditioner cycling and low-income weatherization.

KCP&L’s current rates will remain in place until 2007 in accordance with the orders. On February 1, 2006, KCP&L filed requests with the MPSC and KCC for annual rate increases of $55.8 million or 11.5% and $42.3 million or 10.5%, respectively. The requested rate increases are for recovery of increasing operating costs including fuel, transportation and pensions as well as investments in wind generation and

F-18

customer programs. The request is based on a return on equity of 11.5% and an adjusted equity ratio of 53.8%. KCP&L anticipates that approved rate adjustments will go into effect January 1, 2007. The last rate case required by the orders is expected to be filed in 2009, with rates effective near the time Iatan No. 2 is placed in service. Two additional rate cases could be filed in 2007 and 2008 at KCP&L’s discretion.

The KCC order allows KCP&L to request recovery, on a dollar-for-dollar basis with no profit to the company, of actual fuel and purchased power expense incurred through an energy cost adjustment. Similarly, an interim energy charge, based on forecasted costs and subject to customer refund, is contained in the MPSC order. The rate requests filed with the MPSC and KCC on February 1, 2006, do not include the fuel clauses; however, fuel clauses still could be proposed and implemented based on developments during the proceedings.

·	KCP&L may sell SO₂emission allowances during the term of the orders. The sales proceeds are recorded as a regulatory liability for ratemaking purposes and will be amortized in accordance with the last rate case filed under the orders. In 2005, KCP&L sold $60.3 million of SO₂emission allowances.

The rate increase requests filed with the MPSC and the KCC on February 1, 2006, include pension costs of approximately $46 million calculated consistently with the methodology established in the orders. The orders established KCP&L’s annual pension costs for regulatory purposes at $22 million until 2007 through the creation of regulatory assets or liabilities, as appropriate. See Note 8 for additional information.

Wolf Creek’s depreciable life for Missouri regulatory purposes has been increased from 40 to 60 years. The MPSC order calls for $10.3 million, on an annual jurisdictional basis, of additional amortization expense to be recorded to offset the reduction in depreciation expense due to the change in depreciable life. The 60-year Missouri depreciable life matches the current Kansas regulatory depreciable life. In 2005, KCP&L began recording depreciation and amortization expense in accordance with the order.

·	The orders are intended to provide KCP&L with regulatory mechanisms to be able to recover the prudent costs of its investments as they are placed in service and an ability to maintain targeted credit ratios over the five-year term of the orders.

The orders provide regulatory clarity on certain items; however, normal regulatory risk will continue to exist as the commissions establish rates in the rate cases, including, but not limited to, the actual amount of costs to be recovered through rates, the return on equity, the capital structure utilized and expenses to be recovered.

F-19

Regulatory Assets and Liabilities

KCP&L is subject to the provisions of SFAS No. 71 and has recorded assets and liabilities on its balance sheet resulting from the effects of the ratemaking process, which would not be recorded under GAAP for non-regulated entities. Regulatory assets represent costs incurred that have been deferred because future recovery in customer rates is probable. Regulatory liabilities generally represent probable future reductions in revenue or refunds to customers. Future recovery of regulatory assets is not assured, but is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Future reductions in revenue or refunds for regulatory liabilities generally are not mandated, pending future rate proceedings or actions by the regulators. 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 on KCP&L’s rate case filings; decisions in other regulatory proceedings, including decisions related to other companies that establish precedence on matters applicable to KCP&L; 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. KCP&L’s continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by restructuring and deregulation in the electric industry. In the event that SFAS No. 71 no longer applied to a deregulated portion of KCP&L’s operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of utility plant assets if the cost of the assets could not be expected to be recovered in customer rates. Whether an asset has been impaired is determined pursuant to the requirements of SFAS No. 144.


	Amortization		December 31
	ending period		2005		2004
Regulatory Assets			(millions)
Taxes recoverable through future rates			$	85.7	$	81.0
Decommission and decontaminate federal uranium
enrichment facilities		2007		1.3		2.0
Loss on reacquired debt		2037		7.1		7.7
January 2002 incremental ice storm costs (Missouri)		2007		4.9		9.5
Change in depreciable life of Wolf Creek		2045		27.4		15.5
Cost of removal				9.3		13.9
Asset retirement obligations				23.6		11.4
Future recovery of pension costs				15.6		-
Other		Various		5.0		3.3
Total Regulatory Assets			$	179.9	$	144.3
Regulatory Liabilities
Emission allowances			$	64.3	$	4.1
Pension accounting method difference				1.0		-
Additional Wolf Creek amortization (Missouri)				4.3		-
Total Regulatory Liabilities			$	69.6	$	4.1

Except as noted below, regulatory assets for which costs have been incurred have been included (or are expected to be included, for costs incurred subsequent to the most recently approved rate case) in KCP&L’s rate base, thereby providing a return on invested costs when included in rate base. Certain regulatory assets do not result from cash expenditures and therefore do not represent investments included in rate base or have offsetting liabilities that reduce rate base. The pension accounting method difference (which may be either a regulatory asset or liability) and certain insignificant items in Regulatory Assets - Other are not included in rate base.

Southwest Power Pool Regional Transmission Organization

Under FERC Order 2000, KCP&L, as an investor-owned utility, is strongly encouraged to join a FERC approved RTO. RTOs combine transmission operations of utility businesses into regional organizations that schedule transmission services and monitor the energy market to ensure regional transmission reliability and non-discriminatory access. The Southwest Power Pool (SPP), of which KCP&L is a member, obtained approval from FERC as an RTO in a January 24, 2005, order. KCP&L intends on participating in the SPP RTO and during 2005, KCP&L filed applications with the MPSC and KCC seeking authorization to participate in the SPP RTO. In

F-20

these applications, KCP&L requested authorization be granted by May 1, 2006. In February 2006, KCP&L reached an agreement with the MPSC staff and interveners regarding interim approval to turn over functional control of KCP&L’s transmission facilities to the SPP RTO and participate in the energy imbalance market scheduled to start May 1, 2006. KCC has held workshops seeking additional information on the request to participate.

During 2005, a cost/benefit analysis was completed under the direction of the SPP Regional State Committee (composed of state commissioners from the states where the SPP RTO operates). The analysis indicates that implementation of an energy imbalance market within the SPP region would provide net benefits of approximately $373 million over a 10-year period to the transmission-owning members of the SPP RTO; however, there was no significant documented impact for KCP&L over the 10-year period. During 2005, SPP RTO filed its plans for the energy imbalance market with FERC. These plans include a May 1, 2006, start date for the energy imbalance market. Subsequently, FERC issued an order rejecting this filing. SPP RTO made a revised filing on January 4, 2006, addressing FERC’s issues.

6.	INTANGIBLE ASSETS

KCP&L’s electric utility plant on the consolidated balance sheets included intangible computer software of $92.9 million and $88.7 million at December 31, 2005 and 2004, respectively. Accumulated amortization related to this computer software was $68.8 million and $61.3 million at December 31, 2005 and 2004, respectively.

7.	RSAE DISCONTINUED OPERATIONS

In 2003, HSS completed the disposition of its interest in RSAE. The financial statements reflect RSAE as discontinued operations for 2003 in accordance with SFAS No. 144. The following table summarizes the discontinued operations.


	2003
	(millions)
Revenues		$	31.8

Loss from operations before income taxes			(1.6	)
Loss on disposal before income taxes			(18.9	)
Total loss on discontinued operations before income taxes			(20.5	)
Income tax benefit			11.8
Discontinued operations, net of income taxes		$	(8.7	)

8.	PENSION PLANS AND OTHER EMPLOYEE BENEFITS

Pension Plans and Other Employee Benefits

KCP&L does not have a defined benefit pension plan; however, KCP&L employees and officers participate in Great Plains Energy’s pension plans. Great Plains Energy maintains defined benefit pension plans for substantially all employees, including officers, of KCP&L, Great Plains Energy Services Incorporated (Services) and WCNOC. Pension benefits under these plans reflect the employees’ compensation, years of service and age at retirement. The funding policy for the pension plans is to contribute amounts sufficient to meet the minimum funding requirements under the Employee Retirement Income Security Act of 1974 (ERISA) plus additional amounts as considered appropriate.

The MPSC and KCC 2005 orders establish KCP&L’s annual pension costs at $22 million through the creation of regulatory assets and liabilities for future recovery from or refund to customers, as appropriate. As a result, pension cost for KCP&L was reduced by $14.6 million and a corresponding regulatory asset and liability were established.

F-21

For defined benefit pension plans sponsored by Great Plains Energy, contributions and expense are allocated to KCP&L and Services based on labor costs of plan participants. Any additional minimum pension liability is allocated based on the Company’s funded status per plan.

In addition to providing pension benefits, Great Plains Energy provides certain postretirement health care and life insurance benefits for substantially all retired employees of KCP&L, Services and WCNOC. The cost of postretirement benefits charged to KCP&L are accrued during an employee's years of service and recovered through rates. The Company funds the portion of net periodic postretirement benefit costs that are tax deductible. For post-retirement health care plans sponsored by Great Plains Energy, contributions and expense are allocated to KCP&L and Services based upon the number of plan participants.

The following information is for Great Plains Energy’s pension plans and other employee benefits; however, Services expenses are billed to KCP&L and other Great Plains Energy subsidiaries, with the majority being billed to KCP&L.

F-22

The following pension benefits tables provide information relating to the funded status of all Great Plains Energy’s defined benefit pension plans on an aggregate basis as well as the components of net periodic benefit costs. The plan measurement date for the majority of plans is September 30. In 2005, contributions of $0.2 million and $3.8 million were made to the pension and postretirement benefit plans, respectively, after the measurement date and in 2004, contributions of $20.7 million were made to the pension plans after the measurement date. Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants.


	Pension Benefits						Other Benefits
	2005			2004			2005			2004
Change in projected benefit obligation (PBO)	(millions)
PBO at beginning of year	$	515.7		$	501.5		$	49.1		$	52.1
Service cost		17.3			16.7			0.9			0.9
Interest cost		29.8			30.1			2.9			3.1
Contribution by participants		-			-			1.2			1.1
Amendments		0.6			-			-			-
Actuarial loss (gain)		33.0			25.1			3.6			(3.2	)
Benefits paid		(41.2	)		(54.7	)		(4.1	)		(4.3	)
Benefits paid by Company		(0.6	)		(0.3	)		(0.6	)		(0.6	)
Settlements		-			(2.7	)		-			-
PBO at end of plan year	$	554.6		$	515.7		$	53.0		$	49.1
Change in plan assets
Fair value of plan assets at beginning of year	$	370.5		$	341.0		$	14.7		$	8.3
Actual return on plan assets		47.8			33.9			0.3			0.3
Contributions by employer and participants		35.1			50.3			1.3			10.4
Benefits paid		(41.2	)		(54.7	)		(4.1	)		(4.3	)
Fair value of plan assets at end of plan year	$	412.2		$	370.5		$	12.2		$	14.7
Prepaid (accrued) benefit cost
Funded status	$	(142.4	)	$	(145.2	)	$	(40.8	)	$	(34.4	)
Unrecognized actuarial loss		195.0			195.9			14.1			10.5
Unrecognized prior service cost		32.6			36.3			0.8			1.0
Unrecognized transition obligation		0.3			0.4			8.2			9.4
Net prepaid (accrued) benefit cost		85.5			87.4			(17.7	)		(13.5	)
Regulatory asset, net		14.6			-			-			-
Net amount recognized at December 31	$	100.1		$	87.4		$	(17.7	)	$	(13.5	)
Amounts recognized in the consolidated balance sheets
Prepaid benefit cost	$	98.3		$	89.2		$	-		$	-
Accrued benefit cost		(12.8	)		(1.8	)		(17.7	)		(13.5	)
Minimum pension liability adjustment		(74.3	)		(84.2	)		-			-
Intangible asset		14.4			15.6			-			-
Accumulated other comprehensive income		59.9			68.6			-			-
Regulatory asset, net		14.6			-			-			-
Net amount recognized in balance sheets		100.1			87.4			(17.7	)		(13.5	)
Contributions and changes after
measurement date		0.2			20.7			3.8			-
Net amount recognized at December 31	$	100.3		$	108.1		$	(13.9	)	$	(13.5	)

F-23


	Pension Benefits									Other Benefits
	2005			2004			2003			2005			2004			2003
Components of net periodic benefit cost (millions)
Service cost	$	17.3		$	16.7		$	15.0		$	0.9		$	0.9		$	0.9
Interest cost		29.8			30.1			29.9			2.9			3.1			3.2
Expected return on plan assets		(32.4	)		(31.7	)		(27.7	)		(0.6	)		(0.6	)		(0.6	)
Amortization of prior service cost		4.3			4.3			4.3			0.2			0.2			0.2
Recognized net actuarial loss (gain)		18.6			7.7			1.3			0.5			0.7			0.6
Transition obligation		0.1			0.1			0.1			1.2			1.2			1.2
Amendment		-			-			-			-			-			0.1
Net settlements		-			1.8			-			-			-			-
Net periodic benefit cost before
regulatory adjustment		37.7			29.0			22.9			5.1			5.5			5.6
Regulatory adjustment		(14.6	)		-			-			-			-			-
Net periodic benefit cost	$	23.1		$	29.0		$	22.9		$	5.1		$	5.5		$	5.6

The accumulated benefit obligation (ABO) for all defined benefit pension plans was $469.9 million and $445.4 million at December 31, 2005 and 2004, respectively. The PBO, ABO and the fair value of plan assets at plan year-end are aggregated by funded and under funded plans in the following table.


	2005		2004
Pension plans with the ABO in excess of plan assets	(millions)
Projected benefit obligation	$	337.8	$	309.8
Accumulated benefit obligation		280.6		266.1
Fair value of plan assets		204.1		180.0
Pension plans with plan assets in excess of the ABO
Projected benefit obligation	$	216.8	$	205.9
Accumulated benefit obligation		189.3		179.3
Fair value of plan assets		208.1		190.5

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolio. 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 portfolio 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	2005			2004			2005			2004
Discount rate		5.62	%		5.82	%		5.62	%		5.82	%
Rate of compensation increase		3.57	%		3.06	%		3.60	%		3.05	%

F-24


Weighted average assumptions used to determine	Pension Benefits						Other Benefits
net costs for years ended at December 31	2005			2004			2005				2004
Discount rate		5.82	%		6.00	%		5.82	%			6.00	%
Expected long-term return on plan assets		8.75	%		9.00	%		4.26	%	*		6.62	%	*
Rate of compensation increase		3.06	%		3.30	%		3.05	%			3.25	%
* after tax

Primarily as a result of lower discount rates and historical losses in the market value of plan assets, the Company has a minimum pension liability offset by an intangible asset and OCI. The amounts recognized in the Company’s balance sheets related to the minimum pension liability are detailed in the following table.


December 31	2005		2004
	(millions)
Additional minimum pension liability	$	73.5	$	79.8
Intangible asset		13.7		14.6
Deferred taxes		22.5		25.0
OCI, net of tax		37.3		40.2

Pension plan assets are managed in accordance with “prudent investor” guidelines contained in the ERISA requirements. The investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets within a reasonable and prudent level of risk. Investments are diversified across classes and within each class to minimize risks. At December 31, 2005 and 2004, respectively, the fair value of plan assets was $412.2 million, not including a $0.2 million contribution made after the plan year-end, and $370.5 million, not including a $20.7 million subsequent contribution. The asset allocation for Great Plains Energy’s pension plans at the end of 2005 and 2004, and the target allocation for 2006 are reported in the following table. The portfolio is periodically rebalanced to generally meet target allocation percentages.


				Plan Assets at
	Target			December 31
Asset Category	Allocation			2005			2004
Equity securities		61	%		61	%		59	%
Debt securities		27	%		26	%		31	%
Real estate		7	%		7	%		8	%
Other		5	%		6	%		2	%
Total		100	%		100	%		100	%

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The cost trend assumed for 2005 was 10% and is 9% for 2006. The cost trend rate will continue to decline through 2010 to the ultimate cost trend rate of 5%. The health care plan requires retirees to make monthly contributions on behalf of themselves and their dependents in an amount determined by Great Plains Energy.

The effects of a one-percentage point change in the medical cost trend rates, holding all other assumptions constant, at December 31, 2005, are detailed in the following table.


	Increase			Decrease
		(millions)
Effect on total service and interest component		$	0.1	$	(0.1	)
Effect on postretirement benefit obligation			0.7		(0.7	)

F-25

The Company expects to contribute $20.0 million to the plans in 2006, which includes $6.0 million to meet ERISA funding requirements. The Company will also contribute $4.3 million to other postretirement benefit plans in 2006. Great Plains Energy’s funding policy is to contribute amounts sufficient to meet the ERISA minimum funding requirements plus additional amounts as considered appropriate; therefore, actual contributions may differ from expected contributions. The following Great Plains Energy benefit payments, which reflect expected future service, as appropriate, are expected to be paid through 2015.


	Pension		Other
	Benefits		Benefits
	(millions)
2006	$	43.8	$	6.0
2007		43.2		7.0
2008		41.8		7.7
2009		42.7		8.6
2010		45.6		9.3
2011-2015		230.3		57.1

Employee Savings Plans

Great Plains Energy has defined contribution savings plans that cover substantially all employees of the Company. Employee contributions are matched, subject to limits. The Company’s annual cost of the plans was approximately $3.1 million for each of the last three years.

9.	EQUITY COMPENSATION

KCP&L does not have an equity compensation plan; however, KCP&L officers participate in Great Plains Energy’s Long-Term Incentive Plan. Great Plains Energy’s Long-Term Incentive Plan is an equity compensation plan approved by its shareholders. The Long-Term Incentive Plan permits the grant of restricted stock, stock options, limited stock appreciation rights and performance shares to officers and other employees of Great Plains Energy and its subsidiaries. In accordance with the provisions of SFAS No. 123, compensation expense and accrued dividends related to equity compensation are recognized over the stated vesting period. Forfeitures of equity compensation are recognized when incurred and previously recorded compensation expense related to the forfeited shares is reversed. The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 3.0 million. At December 31, 2005, 2.0 million shares remained available for future issuance.

Stock Options Granted 2001 - 2003

Stock options were granted under the plan at market value of the shares on the grant date. The options vest three years after the grant date and expire in ten years if not exercised. Exercise prices range from $24.90 to $27.73 and the weighted-average remaining contractual life at December 31, 2005 was 6 years. In accordance with the provisions of SFAS No. 123, the Company recognized an insignificant amount of compensation expense in 2005, 2004 and 2003.

The fair value for the stock options granted in 2001 - 2003 was estimated at the date of grant using the Black-Scholes option-pricing model. The option valuation model requires the input of highly subjective assumptions, primarily stock price volatility, changes in which can materially affect the fair value estimate. The weighted-average assumptions used are detailed in the following table.


	2003
Risk-free interest rate		4.77	%
Dividend yield		6.88	%
Stock volatility		22.65	%
Expected option life (in years)		10

F-26

Stock option activity for KCP&L officers for the last three years is summarized in the following table.


	2005					2004					2003
	Shares			Price*		Shares			Price*		Shares			Price*
Beginning balance		173,564		$	25.47		200,564		$	25.36		346,000		$	25.20
Granted		-			-		-			-		22,564			27.73
Exercised		(68,000	)		25.08		(21,000	)		24.61		(13,000	)		26.19
Forfeited		(7,640	)		27.73		(6,000	)		24.90		(155,000	)		25.26
Ending balance		97,924		$	25.57		173,564		$	25.47		200,564		$	25.36
Exercisable at December 31		83,000		$	25.18		63,000		$	25.41		7,000		$	21.67
* weighted-average price

Performance Shares

The payment of performance shares is contingent upon achievement of specific performance goals over a stated period of time as approved by the Compensation and Development Committee of Great Plains Energy’s Board of Directors. The number of performance shares ultimately paid can vary from the number of shares initially granted depending on Great Plains Energy’s performance over stated performance periods. Performance shares have a value equal to the market value of the shares on the grant date with accruing dividends. Performance share activity for KCP&L officers for the last three years is summarized in the following table.


	2005			2004		2003
Beginning balance		16,779			16,779		124,500
Granted		178,570			-		16,779
Cancelled		-			-		(124,500	)
Forfeited		(27,286	)		-		-
Ending balance		168,063			16,779		16,779

Compensation expense for performance shares is recognized over the performance period. In 2005, the Company recognized compensation expense of $0.9 million and reversed an insignificant amount related to forfeited shares. The Company recognized an insignificant amount of compensation expense in 2004 and $0.3 million in 2003. No compensation expense had been recorded related to performance shares cancelled in 2003.

Restricted Stock

Restricted stock cannot be sold or otherwise transferred by the recipient prior to vesting and has a value equal to the fair market value of the shares on the grant date. Restricted stock shares issued in 2003 totaling 48,440 vested in 2003 and were issued out of treasury stock; however, 45,561 of these shares were restricted as to transfer until December 31, 2004, but were considered vested under SFAS No. 123 because the employee’s right to retain the shares of stock was not contingent upon remaining in the service of the Company and was not contingent upon achievement of performance conditions.

All other restricted stock shares issued vest on a graded schedule over a stated period of time with accruing reinvested dividends. Restricted stock activity for KCP&L officers for the last three years is summarized in the following table.


	2005			2004		2003
Beginning balance		62,881			62,881		-
Granted ^(a)		47,099			-		111,321
Vested		(20,960	)		-		(48,440	)
Ending balance		89,020			62,881		62,881
^(a) Restricted stock shares issued in 2003 totaling 48,440
vested in 2003 and were issued out of treasury stock.

Compensation expense for restricted stock is recognized over the vesting period. The Company recognized compensation expense of $0.7 million, $0.4 million and $1.6 million in 2005, 2004 and 2003, respectively and reversed an insignificant amount related to forfeited shares in 2005.

F-27

10.

TAXES

Components of income taxes are detailed in the following table.


	2005			2004			2003
Current income taxes	(millions)
Federal	$	79.9		$	39.2		$	26.1
State		5.6			6.7			5.7
Total		85.5			45.9			31.8
Deferred income taxes
Federal		(14.3	)		22.2			37.1
State		(19.1	)		(11.3	)		6.8
Total		(33.4	)		10.9			43.9
Investment tax credit amortization		(3.9	)		(4.0	)		(4.0	)
Total income tax expense		48.2			52.8			71.7
Less: taxes on discontinued
operations (Note 7)
Current tax (benefit) expense		-			-			(21.5	)
Deferred tax expense		-			-			9.7
Income taxes on continuing operations	$	48.2		$	52.8		$	83.5

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 table.


	Income Tax Expense									Income Tax Rate
	2005			2004			2003			2005			2004			2003
	(millions)
Federal statutory income tax	$	67.1		$	68.6		$	73.3			35.0	%		35.0	%		35.0	%
Differences between book and tax
depreciation not normalized		2.3			1.4			3.9			1.2			0.7			1.9
Amortization of investment tax credits		(3.9	)		(4.0	)		(4.0	)		(2.0	)		(2.0	)		(1.9	)
State income taxes		4.2			7.0			7.1			2.2			3.6			3.4
Changes in uncertain tax positions, net		(1.7	)		(2.7	)		3.9			(0.9	)		(1.4	)		1.9
Rate changes on deferred taxes		(11.7	)		(8.6	)		-			(6.1	)		(4.4	)		-
Allocation of parent company tax benefits		(5.4	)		(5.9	)		-			(2.8	)		(3.0	)		-
Other		(2.7	)		(3.0	)		(0.7	)		(1.5	)		(1.5	)		(0.4	)
Total	$	48.2		$	52.8		$	83.5			25.1	%		27.0	%		39.9	%

During 2005, the Company’s income tax expense decreased $6.3 million due to the favorable impact of sustained audited positions on the Company’s composite tax rate. SFAS No. 109 requires the Company to adjust deferred tax balances to reflect tax rates that are anticipated to be in effect when the differences reverse. The largest component of the Company’s decreases in effective income tax rates in 2005 and 2004 was the result of adjusting KCP&L’s deferred tax balance to its lower composite tax rate due to the impact of sustained audited positions and state tax planning. The impact of the composite tax rate reductions on the deferred tax balances resulted in tax benefits for the Company of $11.7 million in 2005 and $8.6 million in 2004.

F-28

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.


December 31	2005			2004
Current deferred income taxes	(millions)
Nuclear fuel outage	$	3.4		$	5.1
Derivative instruments		-			0.1
Accrued vacation		4.7			3.8
Other		0.8			3.8
Net current deferred income tax asset		8.9			12.8
Noncurrent deferred income taxes
Plant related		(554.2	)		(556.5	)
Income taxes on future regulatory recoveries		(85.7	)		(81.0	)
Derivative instruments		(4.5	)		-
Pension and postretirement benefits		(8.4	)		(9.2	)
Storm related costs		(1.9	)		(3.7	)
Debt issuance costs		(2.7	)		(2.8	)
SO₂emission allowance sales		24.2			1.3
Other		6.2			(2.1	)
Net noncurrent deferred tax liability		(627.0	)		(654.0	)
Net deferred income tax liability	$	(618.1	)	$	(641.2	)


December 31		2005			2004
	(millions)
Gross deferred income tax assets	$	100.3		$	120.8
Gross deferred income tax liabilities		(718.4	)		(762.0	)
Net deferred income tax liability	$	(618.1	)	$	(641.2	)

Uncertain Tax Positions

Management evaluates and records tax liabilities for uncertain tax positions based on the probability of ultimately sustaining the tax deductions or income positions. Management assesses the probabilities of successfully defending the tax deductions or income positions based upon statutory, judicial or administrative authority.

At December 31, 2005 and 2004, the Company had $1.2 million and $3.7 million, respectively, of liabilities for uncertain tax positions related to tax deductions or income positions taken on tax returns. Management believes the tax deductions or income positions are properly treated on such tax returns, but has recorded reserves based upon its assessment of the probabilities that certain deductions or income positions may not be sustained when the returns are audited. The tax returns containing these tax deductions or income positions are currently under audit or will likely be audited. The timing of the resolution of these audits is uncertain. If the positions are ultimately sustained, the Company will reverse these tax provisions to net income. If the positions are not ultimately sustained, the Company may be required to make cash payments plus interest. During 2005, the Company reversed $2.0 million of previously recorded liabilities for uncertain tax positions.

Internal Revenue Service Settlement

In November 2002, KCP&L accepted a settlement offer related to the proposed disallowance of interest deductions on corporate-owned life insurance (COLI) loans. The offer allowed 20% of the interest originally deducted and taxed only 20% of the gain on surrender of the COLI policies. KCP&L surrendered the policies in February 2003. KCP&L paid $1.3 million to the IRS in 2003 to satisfy the liability associated with the surrender. In December 2004, KCP&L settled the 1995-1999 IRS audit and paid tax of $7.3 million and interest of $4.2 million related to the disallowed COLI interest deduction. KCP&L accrued for these payments in 2000.

F-29

In addition to COLI, as part of the settlement of the 1995-1999 IRS audit, the Company agreed to additional tax of $6.9 million and interest of $5.9 million related primarily to timing differences. This settlement did not have a significant impact on the Company’s net income because the liability had been previously recorded in the liabilities for uncertain tax positions or had offsetting impacts on deferred taxes.

11.

RELATED PARTY TRANSACTIONS AND RELATIONSHIPS

The Company receives various support and administrative services from Services, an affiliate of the Company. These services are billed to the Company at cost, based on payroll and other expenses, incurred by Services for the benefit of the Company. These costs totaled $42.6 million, $62.7 million and $45.2 million for 2005, 2004 and 2003, respectively. These costs consisted primarily of employee compensation, benefits and fees associated with various professional services. At December 31, 2005 and 2004, the Company had a net intercompany payable to Services of $3.5 million and $9.2 million, respectively. In 2005, approximately 80% of Services’ employees were transferred to KCP&L to better align resources with the operating business.

12.

COMMITMENTS AND CONTINGENCIES

Environmental Matters

The Company is subject to regulation by federal, state and local authorities with regard to air and other environmental matters primarily through KCP&L’s operations. The generation, transmission and distribution of electricity produces and requires disposal of certain hazardous products that are subject to these laws and regulations. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. Failure to comply with these laws and regulations could have a material adverse effect on the Company.

Environmental-related legislation is continuously introduced in Congress. Such legislation typically includes various compliance dates and compliance limits. Such legislation could have the potential for a significant financial impact on KCP&L, including the installation of new pollution control equipment to achieve compliance. However, KCP&L would seek recovery of capital costs and expenses for such compliance through rates. KCP&L will continue to monitor proposed legislation.

The following table contains estimates of expenditures to comply with environmental laws and regulations described below. The allocation between states is based on location of the facilities and has no bearing as to recovery in jurisdictional rates.


Clean Air Estimated Required										Estimated
Environmental Expenditures	Missouri			Kansas			Total			Timetable
	(millions)
CAIR	$395	-	575	$	-		$395	-	575	2005 - 2015
Incremental BART	55	-	85	225	-	325	280	-	410	2005 - 2013
Incremental CAMR	48	-	70	4	-	6	52	-	76	2010 - 2018
Comprehensive energy plan retrofits	(171)			(101)			(272)			2006 - 2008
Estimated required environmental expenditures in
excess of the comprehensive energy plan retrofits	$327	-	559	$128	-	230	$455	-	789

Expenditure estimates provided in the table above include, but are not limited to, the accelerated environmental upgrade expenditures included in the MPSC and KCC orders discussed in Note 5. These expenditures are

F-30

expected to reduce SO₂, NO_x, mercury and air particulate matter. KCP&L’s expectation is that any such expenditures will be recovered through rates.

Clean Air Interstate Rule

The Environmental Protection Agency (EPA) Clean Air Interstate Rule (CAIR) requires reductions in SO₂ and NO_x emissions in 28 states, including Missouri, and became effective July 11, 2005. The reduction in both SO₂ and NO_x emissions will be accomplished through establishment of permanent statewide caps for NO_x effective January 1, 2009, and SO₂ effective January 1, 2010. More restrictive caps will be effective on January 1, 2015. KCP&L’s coal-fired plants located in Missouri are subject to CAIR, while its coal-fired plants in Kansas are not.

KCP&L expects to meet the emissions reductions required by CAIR at its Missouri plants through a combination of pollution control capital projects and the purchase of emission allowances in the open market as needed. The final rule establishes a market-based cap-and-trade program. Missouri will establish an emission allowance allocation mechanism through a State Implementation Plan (SIP) that is expected to be issued by December 2006. Facilities will demonstrate compliance with CAIR by holding sufficient allowances for each ton of SO₂ and NO_x emitted in any given year with SO₂ emission allowances transferable among all regulated facilities nationwide and NO_x emission allowances transferable among all regulated facilities within the 28 CAIR states. KCP&L will also be allowed to utilize unused SO₂ emission allowances that it has banked from previous years of the Acid Rain Program to meet the more stringent CAIR requirements. At December 31, 2005, KCP&L had over 125,000 tons of SO₂ emission allowances, which are recorded in inventory at zero cost. KCP&L is permitted to sell excess SO₂ emission allowances in accordance with KCP&L’s comprehensive energy plan as approved by the MPSC and KCC. During 2005, KCP&L sold SO₂ emission allowances for proceeds of $61.0 million. See Note 5 for more information.

Analysis of the final rule indicates that selective catalytic reduction technology for NO_x control and scrubbers for SO₂ control will likely be required for KCP&L’s Montrose station, in addition to the environmental upgrades at Iatan No. 1 included in the comprehensive energy plan. The timing of the installation of such control equipment is currently being developed. KCP&L continues to refine the preliminary cost estimates detailed in the table above and explore alternatives. The ultimate cost of these regulations could be significantly different from the amounts estimated. As discussed below, certain of the control technology for SO₂ and NO_x will also aid in the control of mercury.

Best Available Retrofit Technology Rule

In 2005, the EPA published regulations on best available retrofit technology (BART) that amended its July 1999 regional haze regulations regarding emission controls for industrial facilities emitting air pollutants that reduce visibility. The BART regulations apply to specific eligible facilities and were effective September 6, 2005. KCP&L coal-fired plants on the BART eligible list include LaCygne Nos. 1 and 2 in Kansas and Iatan No. 1 and Montrose No. 3 in Missouri. The CAIR suggests that states in CAIR that meet the CAIR requirement may also meet BART requirements for individual sources. Missouri is considering this proposal as part of the CAIR SIP, but no final decision has been reached. Kansas is not a CAIR state and therefore BART will likely impact LaCygne Nos. 1 and 2. The BART rule directs state air quality agencies to identify whether emissions from sources subject to BART are below limits set by the state, or whether retrofit measures are needed to reduce emissions. States must submit a BART implementation plan in 2007 with required emission controls. If emission controls to comply with BART are required at LaCygne Nos. 1 and 2, additional capital expenditures will be required. KCP&L continues to refine its preliminary cost estimates detailed in the table above and explore alternatives. The ultimate cost of these regulations could be significantly different from the amounts estimated.

Mercury Emissions

In 2000, the National Research Council published its findings of a study under the Clean Air Act, which stated that power plants that burn fossil fuels, particularly coal, generate the greatest amount of mercury emissions from man-made sources. In 2005, the EPA reversed its December 2000 finding that it was “appropriate and necessary” to regulate fossil fuel-fired power plants under section 112 of the Clean Air Act, concluding that the earlier finding lacked foundation and that recent information demonstrates that it is not appropriate or necessary to regulate fossil fuel-fired power plants under section 112. The EPA therefore removed coal- and oil-fired power plants from the section 112(c) list. Under section 112 of the Clean Air Act, the EPA would have been required to

F-31

issue Maximum Available Control Technology standards for affected facilities and would have been prohibited from using cap and trade provisions for achieving compliance.

In 2005, the EPA published the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from coal-fired power plants located in 48 states, including Kansas and Missouri, under the New Source Performance Standards of the Clean Air Act. The rule was effective July 18, 2005, and established a market-based cap-and-trade program that will reduce nationwide utility emissions of mercury in two phases. The first phase cap is effective January 1, 2010, and will establish a permanent nationwide cap of 38 tons of mercury for coal-fired power plants. Management anticipates meeting the first phase cap by taking advantage of KCP&L’s mercury reductions achieved through capital expenditures to comply with CAIR and BART. The second phase is effective January 1, 2018, and will establish a permanent nationwide cap of 15 tons of mercury for coal-fired power plants. When fully implemented, the rule will reduce utility emissions of mercury by nearly 70% from current emissions of 48 tons per year.

Facilities will demonstrate compliance with the standard by holding allowances for each ounce of mercury emitted in any given year and allowances will be readily transferable among all regulated facilities nationwide. Under the cap-and-trade program, KCP&L will be able to purchase mercury allowances or elect to install pollution control equipment to achieve compliance. While it is expected that mercury allowances will be available in sufficient quantities for purchase in the 2010-2018 timeframe, the significant reduction in the nationwide cap in 2018 may hamper KCP&L’s ability to obtain reasonably priced allowances beyond 2018. Management expects capital expenditures will be required to install additional pollution control equipment to meet the second phase cap. During the ensuing years, management will closely monitor advances in technology for removal of mercury from Powder River Basin (PRB) coal and expects to make decisions regarding second phase removal based on then available technology to meet the 2018 compliance date. The ultimate cost of this rule could be significantly different from the amounts estimated in the table above. KCP&L is a participant in the DOE project at the Sunflower Electric Holcomb plant to investigate control technology options for mercury removal from coal-fired plants burning sub-bituminous coal.

In 2005, the EPA agreed to reconsider certain aspects of the rule and to invite additional comments on certain aspects of the rule. However, in its reconsideration notice, the EPA reiterated its position that the methodology used for the risk analysis performed to justify the CAMR is sound and scientifically justified. Comments were due in December 2005. The EPA’s actions to de-list mercury under section 112 of the Clean Air Act and issue CAMR remain controversial and subject to challenge.

Carbon Dioxide

At a December 1997 meeting in Kyoto, Japan, delegates from 167 nations, including the U.S., agreed to a treaty (Kyoto Protocol) that would require a 7% reduction in U.S. CO₂ emissions below 1990 levels, a nearly 30% cut from current levels. In 2001, the Bush administration announced it will not negotiate implementation of the Kyoto Protocol and it will not send the Kyoto Protocol to the U.S. Senate for ratification.

In 2002, President Bush unveiled his Clear Skies Initiative, which included a climate change policy. The climate change policy is a voluntary program that relies heavily on incentives to encourage industry to voluntarily limit emissions. The strategy includes tax credits, energy conservation programs, funding for research into new technologies, and a plan to encourage companies to track and report their emissions so that companies could gain credits for use in any future emissions trading program. The greenhouse strategy links growth in emissions of greenhouse gases to economic output. The administration's strategy is intended to reduce the greenhouse gas intensity of the U.S. economy by 18% over the next 10 years. Greenhouse gas intensity measures the ratio of greenhouse gas emissions to economic output as measured by Gross Domestic Product (GDP). Under this plan, as the economy grows, greenhouse gases also would continue to grow, although at a slower rate than they would have without these policies in place. When viewed per unit of economic output, the rate of emissions would drop. The plan projects that the U.S. would lower its rate of greenhouse gas emissions from an estimated 183 metric tons per $1 million of GDP in 2002 to 151 metric tons per $1 million of GDP by 2012.

In 2002, KCP&L joined the Power Partners through Edison Electric Institute (EEI). Power Partners is a voluntary program with the DOE under which utilities commit to undertake measures to reduce, avoid or sequester CO₂

F-32

emissions. In 2003, the EEI sent a letter to numerous Administration officials, in which the EEI committed to work with the government over the next decade to reduce the power sector’s CO₂ emissions per kWh generated (carbon intensity) by the equivalent of 3% to 5% of the current level. In 2004, Power Partners entered into a cooperative umbrella memorandum of understanding (MOU) with the DOE. This MOU contains supply and demand-side actions as well as offset projects that will be undertaken to reduce the power sector’s CO₂ emissions per kWh generated over the next decade consistent with the EEI commitment of 3% to 5%.

Air Particulate Matter and Ozone

In 1997, the EPA revised ozone and particulate matter air quality standards creating a new eight-hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns (PM-2.5) in diameter. In 2004, the EPA designated the Kansas City area as attainment with respect to the PM-2.5 National Ambient Air Quality Standards (NAAQS). In 2005, the EPA published a final rule that designated Jackson, Platte, Clay and Cass counties in Missouri and Johnson, Linn, Miami and Wyandotte counties in Kansas as attainment with respect to the eight-hour ozone NAAQS effective June 2, 2005.

Water Use Regulations

In 2004, the EPA finalized the Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures at existing facilities. This final regulation is applicable to certain existing power producing facilities that employ cooling water intake structures that withdraw 50 million gallons or more per day and use 25% or more of that water for cooling purposes. KCP&L is required to complete a Section 316(b) comprehensive demonstration study on each of its generating facilities’ intake structures by the end of 2007, the studies are expected to cost a total of $1.2 million to $2.0 million. Depending on the outcome of the comprehensive demonstration studies, facilities may be required to implement technological, operational or restoration measures to achieve compliance. Compliance with the final rule is expected to be achieved between 2011 and 2014. Until the Section 316(b) comprehensive demonstration studies are completed, the impact of this final rule cannot be quantified.

Contractual Commitments

The Company’s expense related to lease commitments was $19.4 million, $18.4 million and $23.1 million in 2005, 2004 and 2003, respectively.

The Company’s contractual commitments at December 31, 2005, excluding pensions and long-term debt are detailed in the following table.


	2006		2007		2008		2009		2010		After 2010		Total
	(millions)
Lease commitments	$	15.9	$	14.4	$	14.0	$	10.5	$	8.4	$	91.0	$	154.2
Purchase commitments
Fuel ^(a)		107.9		99.9		91.5		46.0		32.3		37.7		415.3
Purchased capacity		5.4		6.8		7.8		8.2		5.4		18.6		52.2
Other		33.6		5.6		2.9		-		-		-		42.1
Total contractual commitments	$	162.8	$	126.7	$	116.2	$	64.7	$	46.1	$	147.3	$	663.8
^(a) Fuel commitments consists of commitments for nuclear fuel, coal and coal transportation costs.

Lease commitments end in 2028 and include insignificant amounts for capital leases. As the managing partner of three jointly owned generating units, KCP&L has entered into leases for railcars to serve those units. KCP&L has reflected the entire lease commitment in the above amounts, although the other owners will reimburse approximately $2.0 million per year ($22.7 million total).

F-33

Synthetic Lease

In 2001, KCP&L entered into a synthetic lease arrangement with a Lease Trust (Lessor) to finance the purchase, installation, assembly and construction of five combustion turbines and related property and equipment that added 385 MWs of peaking capacity. Rental payments under the lease, which reflects interest payments only, began in 2004 and were to end in October 2006. KCP&L exercised its early termination option in 2005 and purchased the leased property for $154.0 million. KCP&L’s expense for the synthetic lease was $2.0 million and $1.9 million in 2005 and 2004, respectively.

The Lease Trust, a special purpose entity, acting as Lessor in the synthetic lease arrangement discussed above, was considered a variable interest entity under FIN No. 46. Because KCP&L had variable interests in the Lease Trust, including among other things, a residual value guarantee provided to the Lessor, KCP&L was the primary beneficiary of the Lease Trust. The Lease Trust was consolidated in 2003, as required by FIN No. 46. As a result, the Company’s depreciation expense increased $1.9 million, $5.1 million and $1.3 million in 2005, 2004 and 2003, respectively, with offsetting recognition of minority interest.

13.

GUARANTEES

At December 31, 2005, KCP&L had guaranteed, with a maximum potential of $3.9 million, energy savings under an agreement with a customer that expires over the next four years. A subcontractor would indemnify KCP&L for any payments made by KCP&L under this guarantee. This guarantee was entered into before December 31, 2002; therefore, a liability was not recorded in accordance with FIN No. 45, “Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Guarantees of Indebtedness of Others.”

14.

LEGAL PROCEEDINGS

Union Pacific

In 2005, KCP&L filed a rate complaint case with the Surface Transportation Board (STB) charging that Union Pacific Railroad Company’s (Union Pacific) rates for transporting coal from the PRB in Wyoming to KCP&L’s Montrose Station are unreasonably high. Prior to the end of 2005, the rates were established under a contract with Union Pacific. Efforts to extend the term of the contract were unsuccessful and Union Pacific is the only service for coal transportation from the PRB to Montrose Station. KCP&L charged that Union Pacific possesses market dominance over the traffic and requested the STB prescribe maximum reasonable rates. Management anticipates filing opening evidence by mid-year 2006 and the STB issuing its decision toward the end of 2007. Until the STB case is finalized, KCP&L is paying tariff rates subject to refund.

Framatome

In 2005, WCNOC filed a lawsuit on behalf of itself, KCP&L and the other two Wolf Creek owners against Framatome ANP, Inc., and Framatome ANP Richland, Inc. (Framatome) in the District Court of Coffey County, Kansas. The suit alleges various claims against Framatome related to the design, licensing and installation of a digital control system. The suit seeks recovery of approximately $16 million in damages from Framatome. Framatome removed the case to U.S. District Court for the District of Kansas. Thereafter, the plaintiffs filed a motion to remand the case back to Coffey County District Court. The federal court has not yet decided that motion. Framatome has not yet filed its answer in the lawsuit.

Hawthorn No. 5 Subrogation Litigation

KCP&L filed suit in 2001, in Jackson County, Missouri Circuit Court against multiple defendants who are alleged to have responsibility for the 1999 Hawthorn No. 5 boiler explosion. KCP&L and National Union Fire Insurance Company of Pittsburgh, Pennsylvania (National Union) have entered into a subrogation allocation agreement under which recoveries in this suit are generally allocated 55% to National Union and 45% to KCP&L. Certain defendants have been dismissed from the suit and various defendants settled, with KCP&L receiving a total of $38.2 million, of which $18.5 million was recorded as a recovery of capital expenditures. Trial of this case with the one remaining defendant resulted in a March 2004 jury verdict finding KCP&L’s damages as a result of the explosion were $452 million. After deduction of amounts received from pre-trial settlements with other defendants and an amount for KCP&L’s comparative fault (as determined by the jury), the verdict would have resulted in an award against the defendant of approximately $97.6 million (of which KCP&L would have received $33 million

F-34

pursuant to the subrogation allocation agreement after payment of attorney’s fees). In response to post-trial pleadings filed by the defendant, in 2004, the trial judge reduced the award against the defendant to $0.2 million. Both KCP&L and the defendant have appealed this case to the Court of Appeals for the Western District of Missouri. Oral arguments are expected in the first quarter of 2006.

KCP&L has received $204.8 million in insurance recoveries related to property destroyed in the 1999 explosion at the Hawthorn No. 5 generating unit. Recoveries received related to property destroyed and subrogation settlements recorded as a recovery of capital expenditures have been recorded as an increase in accumulated depreciation.

Spent Nuclear Fuel and Radioactive Waste

In 2004, KCP&L and the other two Wolf Creek owners filed suit against the United States in the U.S. Court of Federal Claims seeking an unspecified amount of monetary damages resulting from the government’s failure to begin accepting spent fuel for disposal in January 1998, as the government was required to do by the Nuclear Waste Policy Act of 1982. Approximately sixty other similar cases are pending before that court. The court has stayed the Wolf Creek case until at least October 2006 to allow for some of the earlier cases to be decided first. Another federal court already has determined that the government breached its obligation to begin accepting spent fuel for disposal. The questions now before the court in the pending cases are whether and to what extent the utilities are entitled to monetary damages for that breach. KCP&L management cannot predict the outcome of the Wolf Creek case.

15.

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 as an operating expense. Changes in the estimated fair values of the liabilities are recognized when known.

In 2005, FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” FIN No. 47 clarifies the term conditional ARO, as used in SFAS No. 143. Conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Under FIN No. 47, an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. The Company adopted the provisions of FIN No. 47 for the year ended December 31, 2005.

KCP&L management determined AROs exist for asbestos in certain fossil fuel plants and for an ash pond and landfill. The additional AROs at December 31, 2005, totaled $8.4 million for remediation of asbestos and $7.0 million for the remediation of the ash pond and landfill. The AROs were derived from third party and internal engineering estimates. To estimate the AROs, KCP&L used a credit-adjusted risk free discount rate of 5.6% for 12.5-year assets, 5.89% for 19.5-year asset and 6.12% for 29.5-year assets. The estimated rate was based on the rate KCP&L could issue bonds for the specific period.

In recording the AROs, net utility plant was increased by $2.2 million. KCP&L is a regulated utility subject to the provisions of SFAS No. 71 and management believes it is probable any differences between expense under SFAS No. 143 and expense recovered currently in rates will be recoverable in future rates. As a result, the $13.2 million net effect of adopting FIN No. 47 was recorded as a regulatory asset; therefore, it had no impact on net income.

During 2005, KCP&L also recorded an addition to its ARO to decommission Wolf Creek of $11.3 million, which reflects a 2005 update to the decommissioning study cost estimates. To estimate the additional ARO, KCP&L used a credit-adjusted risk free discount rate of 5.89%. In recording the ARO addition, net utility plant was

F-35

increased by $10.8 million. A related $0.5 million for accretion expense and depreciation was recorded as a regulatory asset; therefore, it had no impact on net income.

Revisions to the estimated liabilities of KCP&L could occur due to changes in the decommissioning or other cost estimates, extension of the nuclear operating license or changes in federal or state regulatory requirements.

The following table summarizes the change in KCP&L’s AROs.


December 31	2005			2004
	(millions)
Beginning balance	$	113.7		$	106.7
Additions		26.7			-
Settlements		(2.0	)		-
Accretion		7.5			7.0
Ending balance	$	145.9		$	113.7

The following table illustrates the effect of FIN No. 47 related AROs if the provisions of FIN No. 47 had been applied beginning January 1, 2003. Pro forma amounts for the periods prior to adoption of FIN No. 47 were measured using assumptions consistent with the period of adoption.


December 31	2005		2004		2003
	(millions)
Beginning balance	$	14.6	$	13.8	$	13.0
Accretion		0.8		0.8		0.8
Ending balance	$	15.4	$	14.6	$	13.8

16.

SEGMENT AND RELATED INFORMATION

The Company has one reportable segment based on its method of internal reporting, which segregates the reportable segment based on products and services, management responsibility and regulation. The reportable business segment is KCP&L, an integrated, regulated electric utility. Other includes the operations of HSS, 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, income taxes include the effects of allocating Great Plains Energy’s tax benefits. Segment performance is evaluated based on net income. The following tables reflect summarized financial information concerning the Company’s reportable segment.


							Total
2005	KCP&L			Other			Company
	(millions)
Operating revenues	$	1,130.8		$	0.1			$	1,130.9
Depreciation and amortization		(146.5	)		(0.1	)			(146.6	)
Interest charges		(61.8	)		-				(61.8	)
Income taxes		(49.3	)		1.1				(48.2	)
Net income (loss)		145.2			(1.5	)			143.7

F-36


							Total
2004	KCP&L			Other			Company
	(millions)
Operating revenues	$	1,090.1		$	1.5			$	1,091.6
Depreciation and amortization		(144.3	)		(0.9	)			(145.2	)
Interest charges		(73.7	)		(0.5	)			(74.2	)
Income taxes		(55.7	)		2.9				(52.8	)
Net income (loss)		150.0			(6.7	)			143.3


							Total
2003		KCP&L			Other		Company
	(millions)
Operating revenues	$	1,054.9		$	2.1			$	1,057.0
Depreciation and amortization		(139.9	)		(1.1	)			(141.0	)
Interest charges		(69.9	)		(0.4	)			(70.3	)
Income taxes		(84.4	)		0.9				(83.5	)
Discontinued operations, net of income taxes		-			(8.7	)			(8.7	)
Net income (loss)		127.2			(10.0	)			117.2


					Total
	KCP&L		Other		Company
2005	(millions)
Assets	$	3,334.6	$	3.9		$	3,338.5
Capital expenditures		332.2		-			332.2
2004
Assets	$	3,330.2	$	7.2		$	3,337.4
Capital expenditures		190.8		-			190.8
2003
Assets	$	3,293.5	$	9.1		$	3,302.6
Capital expenditures		148.8		-			148.8

17.

SHORT-TERM BORROWINGS AND SHORT-TERM BANK LINES OF CREDIT

KCP&L has a $250 million revolving credit facility with a group of banks that expires in December 2009, to provide support for its issuance of commercial paper and other general purposes. A default by KCP&L on other indebtedness totaling more than $25.0 million is a default under the facility. Under the terms of the agreement, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At December 31, 2005, KCP&L was in compliance with this covenant. At December 31, 2005, KCP&L had $31.9 million of commercial paper outstanding and no cash borrowings under the facility. The weighted-average interest rate of the commercial paper was 4.35%. At December 31, 2004, KCP&L had no cash borrowings or commercial paper outstanding.

F-37

18.

LONG-TERM DEBT AND EIRR BONDS CLASSIFIED AS CURRENT LIABILITIES

The Company’s long-term debt is detailed in the following table.


			December 31
	Year Due		2005			2004
General Mortgage Bonds			(millions)
7.95% Medium-Term Notes		2007	$	0.5		$	0.5
3.45%* EIRR bonds		2012-2035		158.8			158.8
Senior Notes
7.125%		2005		-			250.0
6.00%		2007		225.0			225.0
6.50%		2011		150.0			150.0
6.05%		2035		250.0			-
Unamortized discount				(1.8	)		(0.6	)
EIRR bonds
4.75% Series A & B		2015		104.6			107.0
2.38% Series C				-			50.0
4.75% Series D		2017		39.3			40.2
4.65% Series 2005		2035		50.0			-
2.10% Combustion Turbine Synthetic Lease				-			145.3
Current liabilities
EIRR bonds classified as current				-			(85.9	)
Current maturities				-			(250.0	)
Total excluding current liabilities			$	976.4		$	790.3
* Weighted-average interest rate at December 31, 2005

Amortization of Debt Expense

The Company’s amortization of debt expense was $2.3 million for 2005 and $2.1 million for 2004 and 2003.

KCP&L General Mortgage Bonds

KCP&L has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented. The Indenture creates a mortgage lien on substantially all utility plant. Mortgage bonds secure $159.3 million of medium-term notes and Environmental Improvement Revenue Refunding (EIRR) bonds at December 31, 2005 and 2004. In 2004, KCP&L redeemed $54.5 million of its medium-term notes at maturity.

During 2005, KCP&L redeemed its secured 1994 series EIRR bonds totaling $35.9 million by issuing secured EIRR Bonds Series 2005 also totaling $35.9 million: $14.0 million at a fixed rate of 4.05% until maturity at March 1, 2015, and $21.9 million at a fixed rate of 4.65% until maturity at September 1, 2035. The previous interest rate periods on this series, with an interest rate of 2.25%, expired on August 31, 2005. This series was classified as a current liability at December 31, 2004. The new EIRR Bonds Series 2005 is covered by a municipal bond insurance policy issued by XL Capital Assurance Inc. (XLCA). The insurance agreement between KCP&L and XLCA is described below.

In 2004, KCP&L secured a municipal bond insurance policy as a credit enhancement to its secured 1992 series EIRR bonds totaling $31.0 million. This municipal bond insurance policy replaced a 364-day credit facility with a bank, which expired in August 2004 and previously supported full liquidity of these bonds. These variable-rate secured EIRR bonds with a final maturity in 2017 are remarketed on a weekly basis through a Dutch auction process. The insurance agreement between KCP&L and XLCA is described below.

KCP&L Unsecured Notes

KCP&L had $196.5 million of unsecured EIRR bonds outstanding excluding the fair value of interest rate swaps of a $2.6 million liability and $0.7 million asset at December 31, 2005 and 2004, respectively. The interest rates

F-38

swaps resulted in an effective rate of 5.43% for the Series A, B and D EIRR bonds at December 31, 2005. During 2005, KCP&L redeemed its unsecured Series C EIRR bonds totaling $50.0 million by issuing unsecured EIRR Bonds Series 2005 also totaling $50.0 million at a fixed rate of 4.65% until maturity at September 1, 2035. The previous interest rate period on this series, with an interest rate of 2.38%, expired on August 31, 2005. The Series C EIRR bonds were classified as current liabilities at December 31, 2004. The new EIRR Bonds Series 2005 is covered by a municipal bond insurance policy issued by XLCA. The insurance agreement between KCP&L and XLCA is described below.

KCP&L had $625.0 million of outstanding unsecured senior notes at December 31, 2005 and 2004. During 2005, KCP&L privately issued $250.0 million of 6.05% unsecured senior notes, maturing in 2035. The proceeds from the issuance were used to repay the 7.125% unsecured senior notes that matured in 2005. KCP&L entered into two Treasury Locks (T-Locks) to hedge against interest rate fluctuations on the U.S. Treasury rate component of this issuance. As a result, the effective interest rate on these notes was 5.78% at December 31, 2005. See Note 20 for more information about the T-Locks.

KCP&L exercised its early termination option in the Combustion Turbine Synthetic Lease and purchased the leased property during 2005.

Municipal Bond Insurance Policies

The insurance agreements between KCP&L and XLCA provide for reimbursement by KCP&L for any amounts that XLCA pays under the municipal bond insurance policies. The insurance policies are in effect for the term of the bonds. 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, 2005, 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 requires KCP&L to provide XLCA with $50.0 million of general mortgage bonds as collateral for KCP&L’s obligations under the insurance agreement in the event KCP&L issues general mortgage bonds (other than refundings of outstanding general mortgage bonds) resulting in the aggregate amount of outstanding general mortgage bonds exceeding 10% of total capitalization. In the event of a default under the insurance agreements, XLCA may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.

Scheduled Maturities

The Company’s long-term debt maturities for the years 2006 through 2010 are $225.5 million in 2007.

19.

COMMON SHAREHOLDER’S EQUITY

Under stipulations with the MPSC and KCC, KCP&L has committed to maintain consolidated common equity of not less than 35% of total capitalization.

Great Plains Energy made capital contributions to KCP&L of $225 million in 2004. These contributions were used to pay down long-term debt. At December 31, 2005, KCP&L’s capital contributions from Great Plains Energy totaled $400 million and are reflected in common stock in the consolidated KCP&L balance sheet.

20.

DERIVATIVE INSTRUMENTS

The Company is 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 the Company’s operating results. The risk management activities, including the use of derivative instruments, are subject to the management, direction and control of internal risk management committees. Management’s interest rate risk management strategy uses derivative instruments to adjust the Company’s liability portfolio to optimize the mix of fixed and floating rate debt within an established

F-39

range. In addition, the Company uses 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 the Company to credit loss in the event of nonperformance. This credit loss is limited to the cost of replacing these contracts at current market rates. Derivative instruments, excluding those instruments that qualify for the 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 are recognized currently in net income unless specific hedge accounting criteria are met.

Fair Value Hedges - Interest Rate Risk Management

In 2002, KCP&L remarketed its 1998 Series A, B and D EIRR bonds totaling $146.5 million to a five-year fixed interest rate of 4.75% ending October 1, 2007. Simultaneously with the remarketing, KCP&L entered into an interest rate swap for the $146.5 million based on the London Interbank Offered Rate (LIBOR) to effectively create a floating interest rate obligation. The transaction is a fair value hedge with no ineffectiveness. Changes in the fair market value of the swap are recorded on the balance sheet as an asset or liability with an offsetting entry to the respective debt balances with no net impact on net income.

Cash Flow Hedges - Treasury Locks

In 2005, KCP&L entered into two T-Locks to hedge against interest rate fluctuations on the U.S. Treasury rate component of the $250.0 million 30-year long-term debt that KCP&L issued. The T-Locks settled simultaneously with the issuance of the long-term fixed rate debt. The T-Locks removed the uncertainty with respect to the U.S. Treasury rate component of the debt to be issued, thereby enabling KCP&L to predict with greater assurance what its future interest costs on that debt would be. The T-Locks were accounted for as cash flow hedges and no ineffectiveness was recorded on the T-Locks. A pre-tax gain of $12.0 million on the T-Locks was recorded to OCI and is being reclassified to interest expense over the life of the issued 30-year debt. An insignificant amount was reclassified from OCI to interest expense subsequent to the debt issuance.

Cash Flow Hedges - 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, 2005, KCP&L did not have any projected natural gas usage hedged for retail load and firm MWh sales. The hedging instruments in place at December 31, 2004, were designated as cash flow hedges. The fair values of these instruments are recorded as current assets or current liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, the ineffective portion of the change in fair market value is recorded currently in fuel expense. KCP&L did not record any gains or losses due to ineffectiveness during 2005, 2004 or 2003. When the natural gas is purchased, the amounts in OCI are reclassified to fuel expense in the consolidated income statement.

The notional and recorded fair values of the Company’s derivative instruments are summarized in the following table. The fair values of these derivatives are recorded on the consolidated balance sheets.


		December 31
		2005					2004
		Notional					Notional
		Contract		Fair			Contract		Fair
		Amount		Value			Amount		Value
Swap contracts	(millions)
Cash flow hedges		$	-	$	-		$	6.3	$	(0.3	)
Interest rate swaps
Fair value hedges			146.5		(2.6	)		146.5		0.7

F-40

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


December 31	2005			2004
	(millions)
Current assets	$	11.9		$	(0.3	)
Deferred income taxes		(4.5	)		0.2
Total	$	7.4		$	(0.1	)

The amounts recorded in current assets reflected in accumulated OCI in the table above at December 31, 2005, are related to settlement of the T-Locks and are expected to be reclassified to expenses as discussed above.

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


	2005			2004			2003
	(millions)
Fuel expense	$	(0.5	)	$	(0.7	)	$	(0.8	)
Income taxes		0.2			0.3			0.3
OCI	$	(0.3	)	$	(0.4	)	$	(0.5	)

21.

JOINTLY OWNED ELECTRIC UTILITY PLANTS

KCP&L’s share of jointly owned electric utility plants at December 31, 2005, is detailed in the following table.


	Wolf Creek				LaCygne			Iatan No. 1
	Unit				Units			Unit
		(millions, except MW amounts)
KCP&L's share			47	%		50	%		70	%

Utility plant in service		$	1,414		$	337		$	263
Accumulated depreciation			712			244			190
Nuclear fuel, net			28
KCP&L's accredited capacity--MWs			548			711			456		^(a)
^(a)The Iatan No. 2 air permit limits KCP&L's accredited capacity of Iatan No. 1
to 456 MWs from 469 MWs until the air quality control equipment included
in the comprehensive energy plan is operational.

Each owner must fund its own portion of the plant's operating expenses and capital expenditures. KCP&L’s share of direct expenses is included in the appropriate operating expense classifications in the Company’s financial statements.

22.

QUARTERLY OPERATING RESULTS (UNAUDITED)


Quarter	1st		2nd		3rd		4th
2005	(millions)
Operating revenue	$	233.3	$	272.1	$	353.0	$	272.5
Operating income		24.6		59.0		100.1		66.0
Net income		10.3		29.0		68.9		35.5
2004
Operating revenue	$	247.0	$	275.0	$	323.7	$	245.9
Operating income		49.7		68.3		111.3		37.8
Net income		21.2		32.3		63.9		25.9

Quarterly data is subject to seasonal fluctuations with peak periods occurring in the summer months.

F-41

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Kansas City Power & Light Company

We have audited the accompanying consolidated balance sheets of Kansas City Power & Light Company and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedules listed in the index to the consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Kansas City Power & Light Company and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 15 to the consolidated financial statements, effective December 31, 2005, the Company changed its method of accounting for conditional asset retirement obligations to adopt FIN 47 “Accounting for Conditional Asset Retirement Obligations”. As discussed in Note 2 to the consolidated financial statements, in 2005 the Company changed the presentation of its consolidated statements of cash flows to include the cash flows from operating, investing, and financing activities of discontinued operations within the respective categories of operating, investing and financing activities of the Company and retroactively revised the statement of cash flows for the year ended December 31, 2003, for the change.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2006, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP

Kansas City, Missouri

March 8, 2006

F-42

Management’s Report on Internal Control Over Financial Reporting

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 15d-15(f) under the Securities Exchange Act of 1934, as amended) for KCP&L. Under the supervision and with the participation of KCP&L’s chief executive officer and chief financial officer, management evaluated the effectiveness of KCP&L’s internal control over financial reporting as of December 31, 2005. Management used for this evaluation the framework in Internal Control - Integrated Framework issued by the COSO of the Treadway Commission. Management has concluded that, as of December 31, 2005, KCP&L’s internal control over financial reporting is effective based on the criteria set forth in the COSO framework. Deloitte & Touche, LLP, the independent registered public accounting firm that audited the financial statements included in this annual report on Form 10-K, has issued its audit report on this assessment, which is included below.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Kansas City Power & Light Company

We have audited management's assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Kansas City Power & Light Company and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

F-43

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2005, of the Company and our report dated March 8, 2006, expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of a new accounting standard and revisions made to the consolidated statement of cash flows for the year ended December 31, 2003.

/s/DELOITTE & TOUCHE LLP

Kansas City, Missouri

March 8, 2006

F-44

Schedule II - Valuation and Qualifying Accounts and Reserves

Kansas City Power & Light Company
Valuation and Qualifying Accounts
Years Ended December 31, 2005, 2004 and 2003

			Additions
			Charged
	Balance At		To Costs		Charged						Balance
	Beginning		And		To Other						At End
Description	Of Period		Expenses		Accounts			Deductions			Of Period
Year Ended December 31, 2005	(millions)
Allowance for uncollectible accounts	$	1.7	$	3.3	$	4.6	^(a)	$	7.0	^(b)	$	2.6
Legal reserves		3.2		3.1		-			1.8	^(c)		4.5
Environmental reserves		0.3		-		-			-			0.3
Uncertain tax positions		3.7		0.3		-			2.8	^(d)		1.2
Year Ended December 31, 2004
Allowance for uncollectible accounts	$	4.9	$	2.6	$	2.7	^(a)	$	8.5	^(b)	$	1.7
Legal reserves		3.8		1.4		-			2.0	^(c)		3.2
Environmental reserves		1.8		-		-			1.5	^(e)		0.3
Uncertain tax positions		6.4		2.1		-			4.8	^(d)		3.7
Year Ended December 31, 2003
Allowance for uncollectible accounts	$	5.6	$	3.5	$	2.7	^(a)	$	6.9	^(b)	$	4.9
Legal reserves		3.8		3.1		-			3.1	^(c)		3.8
Environmental reserves		1.9		-		-			0.1	^(f)		1.8
Uncertain tax positions		2.5		3.9		1.2	^(g)		1.2	^(d)		6.4
Discontinued operations		1.7		-		-			1.7	^(h)		-

^(a)Recoveries. Charged to other accounts for the year ended December 31, 2005, includes the establishment of an
allowance of $1.6 million.
^(b)Uncollectible accounts charged off. Deductions for the year ended December 31, 2004, includes a charge off of
$1.4 million by Worry Free.
^(c)Payment of claims.
^(d)Reversal of uncertain tax positions. Deductions for the year ended December 31, 2005, includes a reclass of
$0.8 million to franchise taxes payable. Deductions for the year ended December 31, 2003, includes taxes paid
for an IRS settlement.
^(e) Reversal of reserve for remediation of soil and groundwater.
^(f)Payment of expenses.
^(g)Establishment of liability for uncertain tax positions for prior years current tax expense in excess of taxes paid.
^(h)In 2003, HSS completed the disposition of its interest in RSAE.

F-45

(PAGE INTENTIONALLY LEFT BLANK)

Kansas City Power & Light Company

Offer to Exchange

$250,000,000

6.05% Senior Notes, due 2035

Series A

for

6.05% Senior Notes, due 2035

Series B

____________________

Prospectus

April 20, 2006