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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

Current Report

Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

        Date of Report (Date of earliest event reported): May 12, 2004

Great Plains Energy Incorporated (Great Plains Energy) and Kansas City Power & Light Company (KCP&L) (the Registrants) are separately filing this combined Current Report on Form 8-K (Report). Information contained herein relating to an individual Registrant is filed by such registrant on its own behalf. Each Registrant makes representations only as to information relating to itself.

ITEM 5. OTHER EVENTS AND REGULATION FD DISCLOSURE

Exhibit 99 to this Report, which is incorporated by reference herein, gives effect to the following material item within the Registrants’ (i) historical December 31, 2003, 2002 and 2001 consolidated financial statements and notes thereto, (ii) Management’s Discussion and Analysis of Financial Condition and Results of Operations, (iii) Selected Financial Data, and (iv) Schedule II - Valuation and Qualifying Accounts and Reserves, as reported in Registrants’ combined Annual Report on Form 10-K, as amended by Amendment No. 1 on Form 10-K/A, for the year ended December 31, 2003 (2003 Form 10-K):

• the February 2004 announcement by Great Plains Energy of its plan to sell the KLT Gas Inc. natural gas properties (KLT Gas portfolio) and exit the gas business.

As previously disclosed in the Registrants’ combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, and the 2003 Form 10-K, Great Plains Energy’s Board of Directors on February 4, 2004, approved a plan to sell the KLT Gas portfolio and exit the gas business. The Company wrote down the KLT Gas portfolio to its estimated net realizable value in the first quarter of 2004. Under SFAS No. 144, the Registrants are required to present KLT Gas operations subsequent to the approval to sell the KLT Gas portfolio as discontinued operations, as well as recast all historical periods as discontinued operations.

Exhibit 99 to this Report includes Item 6. Selected Financial Data, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 8. Consolidated Financial Statements, and Schedule II - Valuation and Qualifying Accounts and Reserves as listed in Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K from the 2003 Form 10-K recast for the effects of the matter discussed above. No attempt has been made in this Report to modify or update the disclosures in these four items for items occurring subsequent to December 31, 2003, except as required to reflect the effects of the matter discussed above.

Exhibit 99 to this Report also includes a glossary of terms, cautionary statements regarding certain forward-looking information, the Independent Auditors’ Reports and Reports of Independent Auditors on Great Plains Energy and Subsidiaries’ and KCP&L and Subsidiaries’ financial statements for the periods presented and the Independent Auditors’ Report for DTI Holdings, Inc. and subsidiaries (Debtors-in-Possession).

ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS

Great Plains Energy Incorporated and Kansas City Power & Light Company

Great Plains Energy Incorporated

Kansas City Power & Light Company

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Date:  May 12, 2004

Exhibit 99

CAUTIONARY STATEMENTS REGARDING CERTAIN FORWARD-LOOKING INFORMATION
Statements made in this report that are not based on historical facts are forward-looking, may involve risks and uncertainties, and are intended to be as of the date when made. In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, the registrants are providing a number of important factors that could cause actual results to differ materially from the provided forward-looking information. These important factors include:

This list of factors is not all-inclusive because it is not possible to predict all factors.

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GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report:

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ITEM 6. SELECTED FINANCIAL DATA

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

The Management’s Discussion and Analysis of Financial Condition and Results of Operations that follow are a combined presentation for Great Plains Energy and consolidated KCP&L, both registrants under this filing. 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 registrants during the periods presented. It should be read in conjunction with the accompanying consolidated financial statements and related notes.

The operations of KLT Gas in prior periods have been reclassified and are presented as discontinued operations due to the February 2004 decision to sell the KLT Gas portfolio and exit the gas business. Losses in prior periods related to the operations of RSAE have been reclassified and are presented as discontinued operations due to the June 2003 disposition of RSAE.

Great Plains Energy
Great Plains Energy does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy’s direct subsidiaries are KCP&L, KLT Inc., GPP, IEC and GPES. Effective October 1, 2001, Great Plains Energy became the holding company of KCP&L, GPP and KLT Inc. In November 2002, the Company created a wholly-owned subsidiary, IEC, as an intermediate holding company that holds an indirect interest in Strategic Energy. GPES was formed in 2003 to provide services at cost to Great Plains Energy and certain of its subsidiaries, including consolidated KCP&L, as a service company under the 35 Act.

Great Plains Energy Business Overview
As a diversified energy company, Great Plains Energy’s reportable business segments include:

In February 2004, the Great Plains Energy Board of Directors approved management’s recommendation to sell the KLT Gas portfolio and exit the gas business. The Company evaluated this business and determined the amount of capital and the length of time required for development of reserves and production combined with the earnings volatility of the exploration process are no longer compatible with the Company’s strategic vision.

Over the first six months of 2004, the Company is engaging in a comprehensive strategic planning process to map its view of the future of the electric industry, and ultimately the Company, over the next five to ten years. This inclusive process draws on the creativity and skills of employees, outside experts and people from the community.

The strategic planning process will seek to enhance the disciplined growth of the Company and build upon the strong foundation of KCP&L and Strategic Energy. This platform for growth provides a balanced mix of regulated earnings from the utility operations of KCP&L and the potential continued growth of Strategic Energy as it expands its presence in competitive retail markets.

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Critical Accounting Policies
The preparation of financial statements in conformity with Generally Accepted Accounting Principles (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 highly 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 condition.

Pensions
The Company incurs significant costs in providing non-contributory defined pension benefits. The costs are measured using actuarial valuations that are dependent upon numerous factors derived from actual plan experience and assumptions of future plan experience.

Pension costs are impacted by actual employee demographics (including age, 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 assumptions are updated annually in accordance with Statement of Financial Accounting Standards (SFAS) No. 87, “Employers’ Accounting for Pensions”; however, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement. The Company generally recognizes gains and losses by amortizing over a five-year period the rolling five-year average of unamortized gains and losses. The key assumptions used in developing the 2003 pension disclosures include a 6.0% discount rate, a 9.0% expected return on plan assets and a 3.3% average compensation rate increase. The discount rate was reduced by 0.75% and 1.25% from 2002 and 2001, respectively, due to current market conditions, while the return on plan assets remained constant and the compensation rate decreased 0.80% from prior years.

In selecting an assumed discount rate, fixed income security yield rates for 30-year Treasury bonds and corporate high-grade bond yields were considered. The assumed rate of return on plan assets was developed based on the weighted average of the long-term returns forecast for the expected portfolio mix of investments held by the plan.

The following table reflects the sensitivities associated with a 0.5 percent increase or a 0.5 percent decrease in key actuarial assumptions. Each sensitivity reflects an evaluation of the change based solely on a change in that assumption only.

For the year ended December 31, 2003, the Company recorded $17.4 million of pension expense, an $11.9 million increase from the previous year. Pension expense for 2004 is expected to approximate $21.0 million, a $3.6 million increase over 2003. The 2004 increase is primarily due to lower discount

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rates and the amortization of investment losses from prior years that are recognized on a rolling five-year average basis.

The Company’s pension plan assets are primarily made up of equity and fixed income investments. The market value of the plan assets increased $16.8 million in 2003 primarily reflecting an overall improvement in the equity markets during the year. However, the increase was not enough to recover from significant market declines incurred in 2001 and 2002 when plan assets lost value of approximately $240.8 million. At plan year-end, the fair value of pension plan assets was $341.0 million, not including a $32.0 million contribution made after the plan year-end.

The total accumulated benefit obligation (ABO) of the plans exceeded the fair value of plan assets requiring the Company to record an additional minimum pension liability of $78.4 million as prescribed by SFAS No. 87. This was offset by an intangible asset of $17.4 million to the extent of prior service costs, with the remainder of $61.0 million charged to common equity through other comprehensive income (OCI). Accumulated OCI, net of deferred taxes, was $37.2 million. OCI could be restored through common equity in future periods to the extent fair value of trust assets exceeded the ABO.

Market conditions and interest rates significantly affect the future assets and liabilities of the plan. It is difficult to predict future pension costs, the additional pension liability and cash funding requirements due to volatile market conditions; however, similar charges may be required in the future.

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 incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent probable future reductions in revenue or refunds to customers. At December 31, 2003, KCP&L’s regulatory assets and liabilities totaled $145.6 million and $3.8 million, respectively. KCP&L’s continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric industry. In the event that SFAS No. 71 no longer applied to all, or a separable 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 SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” See Note 5 to the consolidated financial statements for a discussion of regulatory assets and liabilities.

At the end of January 2002, a severe ice storm occurred throughout large portions of the Midwest, including the greater Kansas City metropolitan area. In 2002, the KCC approved a stipulation and agreement regarding the treatment of the Kansas portion of the ice storm costs. Pursuant to the stipulation and agreement, KCP&L implemented a retail rate reduction January 1, 2003, and began calculating depreciation expense on Wolf Creek using a 60-year life instead of a 40-year life. As a result of the stipulation and agreement, KCP&L’s 2003 retail revenues decreased approximately $12.5 million and depreciation expense decreased approximately $7.7 million. The reduction in depreciation expense has been recorded as a regulatory asset. KCP&L also agreed to file a rate case by May 15, 2006.

In 2002, the MPSC approved KCP&L’s application for an accounting authority order related to the Missouri jurisdictional portion of the storm costs. The order allows KCP&L to defer and amortize $20.1 million, representing the Missouri portion of the storm costs, through January 2007. The amortization,

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which began in September 2002, is approximately $4.6 million annually for the remainder of the amortization period.

Asset Retirement Obligations
Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities are recognized at fair value as incurred and capitalized as part of the cost of the related long-lived asset. Accretion of the liabilities due to the passage of time is recorded as an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

The adoption of SFAS No. 143 changed the accounting for and the method used to report KCP&L’s obligation to decommission its 47% share of Wolf Creek. The legal obligation to decommission Wolf Creek was incurred when the plant was placed in service in 1985. The estimated liability, recognized on KCP&L’s balance sheet at January 1, 2003, is based on a third party nuclear decommissioning study conducted in 2002. KCP&L used a credit-adjusted risk free discount rate of 6.42% to calculate the retirement obligation. This estimated rate is based on the rate KCP&L could issue 30-year bonds, adjusted downward to reflect the portion of the anticipated costs in current year dollars that had been funded at date of adoption through a tax-qualified trust fund. The cumulative impact of prior decommissioning accruals recorded consistent with rate orders issued by the MPSC and KCC has been reversed and a new regulatory contra-asset for such amounts has been established. Amounts collected through these rate orders have been deposited in a legally restricted external trust fund. The fair market value of the trust fund was $75.0 million at December 31, 2003.

KCP&L also must recognize, where possible to estimate, the future costs to settle other legal liabilities including the removal of water intake structures on rivers, capping/filling of piping at levees following steam power plant closures and capping/closure of ash landfills. Estimates for these liabilities are based on internal engineering estimates of third party costs to remove the assets in satisfaction of legal obligations and have been discounted using credit adjusted risk free rates ranging from 5.25% to 7.50% depending on the anticipated settlement date.

KLT Gas has estimated liabilities for gas well plugging and abandonment, facility removal and surface restoration. These estimates are based upon internal estimates of third party costs to satisfy the legal obligations and have been discounted using credit adjusted risk free rates ranging from 6.00% to 7.25%, depending upon the anticipated settlement date.

Revisions to the estimated liabilities of KCP&L and KLT Gas could occur due to changes in the decommissioning or other cost estimates and the timing thereof, extension of the nuclear operating license or changes in federal or state regulatory requirements.

On January 1, 2003, KCP&L recorded Asset Retirement Obligations (ARO) of $99.2 million and increased property and equipment, net of accumulated depreciation, by $18.3 million. KCP&L is a regulated utility subject to the provisions of SFAS No. 71 and management believes it is probable that any differences between expenses under SFAS No. 143 and expenses recovered currently in rates will be recoverable in future rates. As a result, the $16.3 million net cumulative effect of the adoption of SFAS No. 143 was recorded as a regulatory asset and therefore, had no impact on net income.

As a result of its adoption of SFAS No. 143 on January 1, 2003, KLT Gas recorded ARO of $1.2 million, increased property and equipment by $1.0 million and recorded an expense for the immaterial

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cumulative effect of the accounting change. These amounts are reflected in discontinued operations on Great Plains Energy’s consolidated balance sheet and income statement.

KCP&L has legal ARO for certain other assets where it is not possible to estimate the time period when the obligations will be settled. Consequently, the retirement obligations cannot be measured at this time. For transmission easements obtained by condemnation, KCP&L must remove its transmission lines if the line is de-energized. It is extremely difficult to obtain siting for new transmission lines. Consequently, KCP&L does not anticipate de-energizing any of its existing lines. KCP&L also operates, under state permits, ash landfills at several of its power plants. While the life of the ash landfill at one plant can be estimated and is included in the estimated liabilities above, the future life of ash landfills at other permitted landfills cannot be estimated. KCP&L can continue to maintain permits for these landfills after the adjacent plant is closed.

Although the liability for Wolf Creek decommissioning costs recorded under the ARO method is expected to be substantially the same at the end of Wolf Creek’s life as the liability to be recorded pursuant to regulatory orders the rate at which the liability increases varies under the different methods. Because KCP&L is subject to SFAS No. 71, the difference in the recognition of the liability will have no impact on earnings.

Prior to the adoption of SFAS No. 143, KLT Gas did not record separate asset retirement costs and liabilities, or the associated depreciation and accretion. Under the full cost method of accounting followed by KLT Gas, estimated dismantlement and abandonment costs, net of estimated salvage values, were recorded to the property cost to be amortized. Under SFAS No. 143, KLT Gas’ reserve for depreciation and asset retirement liabilities will increase systematically over the asset life up to the time of settlement with corresponding charges to expense.

It is anticipated the Company’s February 2004 decision to exit the gas business will be accomplished by the sale of KLT Gas’ assets. Management expects the ARO related to the KLT Gas portfolio to be transferred to the new owners at the time of the sale.

Asset Impairment, including Goodwill and Other Intangible Assets
SFAS No. 144
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.

During 2003, KLT Gas management determined that two gas properties were impaired as development activities indicated a decline in the estimates of future gas production. As a result of the lower estimated production, the carrying amount of each property exceeded its estimated fair value based upon discounted estimated future cash flows, which resulted in impairments on the two properties. Internal and third party models were used to estimate future production volumes, natural gas pricing, capital expenditures and operating costs. Cash flow models were based on management’s current understanding of prospect geology, well costs and projected operating expenses. Natural gas pricing assumptions were based on the New York Mercantile Exchange Henry Hub Natural Gas forward curve, adjusted for basis differentials and other transportation charges. The impairments of $15.2 million and the related income tax effect of $5.9 million are reflected in Loss from Discontinued Operations on Great Plains Energy’s consolidated statement of income resulting in a $9.3 million reduction to earnings in 2003.

Additionally, in the second half of 2003, Great Plains Energy management performed a strategic review of the KLT Gas natural gas properties (KLT Gas portfolio) and operations. At the direction of the Board of Directors, management engaged a third party specialist to help evaluate the KLT Gas business and

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provide recommendations regarding business strategy, management, staffing and optimization of the KLT Gas portfolio. The objective of the strategic review was to develop a course of action regarding KLT Gas operations for the Board of Directors’ consideration at its February 2004 meeting. After completion of the KLT Gas strategic review, management determined it would recommend a sale of the KLT Gas portfolio and a plan to exit the gas business at the February 2004 Board of Directors’ meeting.

As a result of its decision to recommend a sale of the KLT Gas portfolio and exit the gas business, Great Plains Energy management engaged a second third party specialist to complete a market reference valuation analysis of the KLT Gas portfolio. As a result of the KLT Gas strategic review and market reference valuation analysis having been conducted, an impairment test of the entire KLT Gas portfolio was performed at December 31, 2003, in accordance with SFAS No. 144, using a probability weighting of the likelihood of potential outcomes at the February 2004 meeting. The impairment test considered 1) the scenario of sale of the entire KLT Gas portfolio with fair value determined by a third party valuation specialist based on estimated market prices and 2) the scenario of hold and use with fair value determined by risk adjusted discounted cash flows. The impairment test indicated that the carrying amount of the KLT Gas portfolio exceeded the probability-weighted fair value, which resulted in an impairment of $39.3 million and the related income tax effect of $15.1 million, which is reflected in Loss from Discontinued Operations on Great Plains Energy’s consolidated statement of income, resulting in a $24.2 million reduction to earnings in 2003.

The accounting estimates related to asset impairments of KLT Gas are highly susceptible to change from period to period because they require management to make assumptions about future natural gas production volumes, natural gas pricing, capital expenditure requirements, operating costs and risk adjusted discount rates. Further, the estimates at December 31, 2003, were impacted by management’s assessment of the probability of potential outcomes related to selling or continuing to develop the KLT Gas portfolio. As a result of the decision in the first quarter of 2004 to exit the gas business, the carrying amount of the KLT Gas portfolio will be written down to its estimated realizable value in the first quarter of 2004.

SFAS No. 142
Goodwill is tested for impairment at least annually and more frequently when indicators of impairment exist as prescribed under SFAS No. 142, “Goodwill and Other Intangible Assets.” SFAS No. 142 requires that if the fair value of a reporting unit is less than its carrying value including goodwill, the implied fair value of the reporting unit goodwill must be compared with its carrying value to determine the amount of impairment. See Note 6 to the consolidated financial statements for information regarding the impact of adopting SFAS No. 142 on goodwill and goodwill amortization.

Strategic Energy’s 2003 annual impairment test was completed as of September 1, the annual review date, and there was no impairment of the Strategic Energy goodwill. At December 31, 2003 and 2002, the unamortized balance of Strategic Energy goodwill on Great Plains Energy’s balance sheet was $26.1 million.

RSAE’s goodwill was reviewed for impairment as of January 1, 2002, as required under the implementation provisions of SFAS No. 142. Based upon the results of a third party study and budgeted 2002 revenue, RSAE recorded a $3.0 million impairment of goodwill. The impairment was reflected as a cumulative effect to January 1, 2002, of a change in accounting principle.

Management believes that the accounting estimates related to impairment analyses required under SFAS No. 142 are critical accounting estimates. The estimates are highly susceptible to change from period to period because it requires company management to make assumptions about future sales, operating costs and discount rates over an indefinite life. Historically, actual margins and volumes have fluctuated and, to a great extent, fluctuations are expected to continue. The estimates of future margins

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are based upon internal budgets, which incorporate estimates of customer growth, business expansion and weather trends, among other items.

Strategic Energy – Energy and Energy-related Contract Accounting
Strategic Energy primarily purchases power under long-term forward physical delivery contracts to supply electricity to its retail energy customers under full requirement sales contracts. Both the forward purchase contracts and the full requirements sales contracts meet the accounting definition of a derivative; however, on a majority of the forward purchase derivative contracts and all of the full requirement sales contracts, Strategic Energy applies the normal purchase normal sale accounting treatment. Accordingly, Strategic Energy records receivables and revenues generated from the sales contracts as energy is delivered and consumed by the retail customer. Likewise, a liability and purchase power expense are recorded when the energy under long-term forward physical delivery contracts is delivered to Strategic Energy’s retail customers.

An inability to sustain the normal purchase / normal sale accounting treatment for forward purchase derivative contracts could result in asymmetrical accounting, whereby the timing of the impact on operating earnings would differ if normal purchase / normal sale accounting treatment was applied to the full requirements sales contracts, but the forward purchase derivative contracts no longer qualified for normal purchase / normal sale accounting treatment.

For forward purchase contracts that do not meet the qualifying criteria for normal purchase / normal sale accounting treatment, the Company elects cash flow hedge accounting, where appropriate. Under cash flow hedge accounting, the fair value of the contract is recorded as a current or long-term derivative asset or liability. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in OCI and subsequently reclassified as purchased power expense in Great Plains Energy’s consolidated statement of income as the power is delivered and/or the contract settles. Additionally, in the future OCI may have greater fluctuations than historically because of a larger number of derivative contracts designated for cash flow hedge accounting, but these fluctuations would not affect current period earnings or cash flows.

Changes in fair value of forward purchase derivative contracts that do not meet the requirements for the normal purchase / normal sale accounting treatment or cash flow hedge accounting are recorded in earnings and as a current or long-term derivative asset or liability. The subsequent changes in the fair value of these contracts could result in earnings volatility as the fair value of the changes in the associated derivative assets and liabilities are recorded on a net basis in purchased power expense in Great Plains Energy’s consolidated statement of income.

Derivative assets and liabilities consist of a combination of energy and energy-related contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices, contract quantities, or both. The market prices and quantities used to determine fair value reflect management’s best estimate considering various factors. However, future market prices and actual quantities will vary from those used in recording energy assets and liabilities at fair value, and it is possible that such variations could be material.

Market prices for energy and energy-related commodities vary based upon a number of factors. Changes in market prices will affect the recorded fair value of energy contracts. Changes in the fair value of energy contracts will affect earnings in the period of the change for contracts under fair value accounting and OCI in the period of changed for contracts under cash flow hedge accounting, while changes in forward market prices related to contracts under accrual accounting will affect earnings in future periods to the extent those prices are realized. Strategic Energy cannot predict whether, or to

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what extent, the factors affecting market prices may change, but those changes could be material and could be either favorable or unfavorable.

Related Party Transactions
Custom Energy Holdings, L.L.C. (Custom Energy Holdings) holds 100% of the direct ownership interests in Strategic Energy. Great Plains Energy holds an 89% indirect ownership position in Strategic Energy. SE Holdings, L.L.C. (SE Holdings) owns the remaining 11% indirect ownership position in Strategic Energy. Richard Zomnir, President and Chief Executive Officer of Strategic Energy and certain other employees of Strategic Energy hold direct or indirect interests in SE Holdings. SE Holdings has a put option to sell all or part of its 11% interest in Strategic Energy (Put Interest) to Custom Energy Holdings at any time within the 90 days following January 31, 2004, at fair market value. On February 9, 2004, a letter agreement was entered into setting forth a procedure for determining the fair market value of the Put Interest (Letter Agreement). The Letter Agreement provides for SE Holdings to exercise its put option with respect to all but one unit (0.00001% of issued and outstanding units) of each of its respective series of ownership interest in Custom Energy Holdings. Upon closing of such a transaction, which is anticipated for mid-April 2004, subject to obtaining all necessary regulatory approvals, SE Holdings would continue to be a member of Custom Energy Holdings and be represented on the Management Committee of Custom Energy Holdings and Strategic Energy.

The Letter Agreement further provides that Mr. Zomnir will remain with Strategic Energy through the closing of the transaction. Upon consummation of the transaction, Mr. Zomnir will resign. An executive search is being conducted over the next several months considering both internal and external candidates for the position of President and Chief Executive Officer of Strategic Energy.

In November 2002, the Board of Directors of the Company approved a merger of Environmental Lighting Concepts, Inc. (ELC) into IEC to acquire ELC’s 6% indirect interest in Strategic Energy. The merger resulted in Great Plains Energy holding an 89% indirect interest in Strategic Energy. Gregory J. Orman, the former Executive Vice President – Corporate Development and Strategic Planning of the Company, was the majority shareholder of ELC and received $10.1 million in Company common stock and a note, which was paid in January 2003. See Note 12 to the consolidated financial statements.

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Great Plains Energy Results of Operations

2003 compared to 2002
Great Plains Energy’s 2003 earnings, as detailed in the table below, increased to $143.3 million, or $2.07 per share, from $124.5 million, or $1.99 per share, compared to 2002. The issuance of 6.9 million shares in November 2002 diluted 2003 earnings per share by $0.23.

KCP&L’s earnings increased $24.3 million in 2003 compared to 2002. Earnings in 2003 include $11.3 million related to the partial settlements of Hawthorn No. 5 litigation. See consolidated KCP&L Results of Operations for additional information. KCP&L’s revenue increased $45.0 million primarily due to a significant increase in wholesale MWhs sold at higher wholesale prices partially offset by the effect on retail revenues of the January 2003 Kansas rate reduction. This increase combined with a decrease in interest expense more than offset increases in purchased power expense, pension expense and power plant maintenance expense. The amortization of the Missouri jurisdictional portion of the storm costs

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increased $3.1 million in 2003. In 2002, KCP&L expensed $16.5 million for the Kansas jurisdictional portion of the storm costs.

Discontinued operations (RSAE) in 2003 includes 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. Losses from RSAE in 2002 of $4.0 million have been reclassified and presented as discontinued operations. Additionally, 2002 earnings reflect the $3.0 million cumulative effect to January 1, 2002, of a change in accounting principle for the adoption of SFAS No. 142 and the associated write-down of RSAE goodwill.

Strategic Energy’s earnings increased $9.9 million in 2003 compared to 2002. The increase is the result of a $301.5 million increase in revenue partially offset by a $283.5 million increase in purchased power expense primarily due to a 41% increase in MWhs sold. This increase was partially offset by an increase in administrative and general expenses including employee related expenses. In addition to the continued growth, Great Plains Energy’s ownership of Strategic Energy was increased by 6% in the fourth quarter of 2002.

Other non-regulated operations include a $28.1 million after tax gain related to the confirmation of the DTI bankruptcy. See Note 9 to the consolidated financial statements for additional information regarding DTI. Other non-regulated operations also included a $2.3 million decrease in earnings primarily due to higher reductions in affordable housing limited partnerships in 2003 compared to 2002.

Discontinued Operations (KLT Gas) includes after tax operating losses of $2.6 million and after tax impairments of $33.5 million. The after tax impairments consist of charges totaling $9.3 million on two properties in response to lower revised estimates of future gas production and a fourth quarter 2003 impairment charge of $24.2 million related to the Company’s KLT Gas strategic review and exit plan valuation analysis. See Note 7 to the consolidated financial statements for additional information regarding the KLT Gas property impairments and decision to exit the gas business.

2002 compared to 2001
Great Plains Energy’s 2002 earnings increased to $124.5 million, or $1.99 per share, from a loss of $25.8 million, or $(0.42) per share, compared to the same period of 2001.

KCP&L’s increase in earnings was the result of warmer summer 2002 weather compared to 2001, continued load growth and a 40% increase in wholesale MWh sales, which combined with other net positive impacts of the return to service of Hawthorn No. 5 in mid-2001 to more than offset increased expenses. The increased expenses included the January 2002 ice storm costs and increased pension expenses.

Discontinued operations (RSAE) for 2002 and 2001 reflect the operations of RSAE, which was disposed of in June 2003. The 2002 cumulative effect of changes in accounting principles reflects RSAE’s write-down of goodwill due to the adoption of SFAS No. 142.

Strategic Energy’s earnings increased $7.9 million; however, 2001 earnings included $15.0 million in earnings from the sale of power purchased from one supplier under wholesale contracts that expired at the end of 2001. The increase in 2002, excluding the effect in 2001 of these earnings from wholesale power sales, was due to continued growth in retail electric sales resulting from increases in customer accounts and MWhs served. This was partially offset by increased salaries and benefits and an increase in income taxes as a result of increased sales in states with higher income tax rates for the current year.

Other non-regulated operations included, among other things, a $3.8 million increase in earnings primarily due to lower reductions in affordable housing limited partnerships in 2002 compared to 2001.

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Additionally, 2001 reflects $173.8 million related to both DTI operating losses incurred in 2001 and the $140.0 million net write-off following DTI’s bankruptcy filings at the end of 2001. As a result of DTI’s filing for bankruptcy protection, DTI is not included in 2002 results of operations. See Note 9 to the consolidated financial statements for additional information. Additionally, in 2001 prior to KLT Telecom’s purchase of a majority ownership in DTI, DTI completed a tender offer for 50.4% of its outstanding senior discounted notes. This transaction resulted in a $15.9 million gain on the early extinguishment of debt.

During 2002, KLT Gas focused on the acquisition of additional leased acreage and the testing and development of several unconventional natural gas properties. Discontinued Operations (KLT Gas) in 2001 reflects the $12.0 million after tax gain on the sale of its 50% equity ownership in Patrick KLT Gas, LLC.

Consolidated KCP&L
The following discussion of consolidated KCP&L results of operations includes KCP&L, an integrated 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 integrated electric utility.

Consolidated KCP&L Business Overview
As an integrated, regulated electric utility, KCP&L engages in the generation, transmission, distribution and sale of electricity.

KCP&L has over 4,000 MW of generating capacity. Five combustion turbine units added 385 MW of peaking capacity in 2003. KCP&L has entered into a five-year construction and synthetic operating lease transaction with a Lease Trust for the five combustion turbines. In accordance with FIN No. 46, KCP&L consolidated the Lease Trust in the fourth quarter of 2003.

KCP&L has transmission and distribution facilities that served almost 490,000 customers as of December 31, 2003. KCP&L continues to experience load growth approximating the historical average of 2.0% to 2.5% annually through increased customer usage and additional customers. Rates charged for electricity are below the national average.

Customers of KCP&L set a record peak demand for the consumption of electricity on August 21, 2003. The all-time one-hour peak reached 3,610 MW when the downtown Kansas City, Missouri temperature was 105 degrees. A growing customer base and the extreme temperature contributed to the new peak. The previous summer peak for KCP&L of 3,374 MW was set August 28, 2000.

At the end of January 2002, a severe ice storm occurred throughout large portions of the Midwest, including the greater Kansas City metropolitan area. Total costs related to the January ice storm were approximately $51.3 million of which $14.7 million were capital expenditures and therefore charged to utility plant. KCP&L expensed a total of $16.5 million in 2002 for the Kansas jurisdictional portion of the storm costs and deferred $20.1 million of the storm costs applicable to Missouri.

See Item 1. Business, KCP&L section for information regarding the FERC Order 2000 and Notice of Proposed Rulemaking to Remedy Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design.

KCP&L has a wholly-owned subsidiary, HSS, that holds a residential services investment, Worry Free. Worry Free is no longer actively pursuing new customers and management does not anticipate any significant additional capital investments in Worry Free. In June 2003, HSS completed the disposition of its interest in RSAE.

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Consolidated KCP&L Results of Operations
The following table summarizes consolidated KCP&L’s comparative results of operations. Consolidated KCP&L results of operations include KCP&L, an integrated electric utility and HSS. For comparative purposes only, 2001 is presented below excluding the results of operations for KLT Inc. and subsidiaries and GPP, which were transferred to Great Plains Energy on October 1, 2001. For comparison 2001 presented below should only be used in the context of the discussion and analysis that follows.

As described in Item 3. Legal Proceedings, KCP&L filed suit against multiple defendants who are alleged to have responsibility for the 1999 Hawthorn No. 5 boiler explosion. KCP&L and its primary insurance company have entered into a subrogation allocation agreement under which recoveries in this suit are generally allocated 55% to the primary insurance company and 45% to KCP&L. As of December 31, 2003, various defendants have settled with KCP&L in this litigation, resulting in KCP&L recording $35.8 million under the terms of the subrogation allocation agreement. The amount recorded in 2003 earnings related to the loss of use of the plant was approximately $18.5 million ($11.3 million net of income taxes). The effect was to increase wholesale revenues $2.7 million, decrease fuel expense $4.0 million and decrease purchased power expense $11.8 million. The remaining $17.3 million was recorded as a recovery of capital expenditures.

Consolidated KCP&L’s income from continuing operations increased $23.2 million in 2003 compared to 2002. KCP&L’s revenue increased $45.0 million primarily due to a significant increase in wholesale MWhs sold at higher wholesale prices partially offset by the effect on retail revenues of the January 2003 Kansas rate reduction. Revenues also increased due to the partial settlements of Hawthorn No. 5 litigation discussed above of $2.7 million. This increase in revenues combined with a $10.4 million decrease in interest expense and $4.4 million decrease in depreciation expense more than offset increases of $7.0 million in purchased power expense, $11.3 million in pension expense, $6.7 million in power plant maintenance expense and $3.3 million in transmission expense. The amortization of the Missouri jurisdictional portion of the storm costs increased $3.1 million in 2003. In 2002, KCP&L expensed $16.5 million for the Kansas jurisdictional portion of the storm costs.

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Consolidated KCP&L’s income from continuing operations increased $3.1 million in 2002 compared to 2001, as a result of warmer summer 2002 weather compared to 2001, continued load growth and a 40% increase in wholesale MWh sales. These factors combined with other net positive impacts of the return to service of Hawthorn No. 5 in mid-2001 to more than offset increased expenses. The increased expenses included $18.0 million of January 2002 ice storm costs and $25.4 million in increased KCP&L administrative and general expenses primarily attributable to increased pension expenses.

Discontinued operations in 2003 includes 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. Losses from RSAE of $4.0 million and $7.2 million in 2002 and 2001, respectively, have been reclassified and are presented as discontinued operations. Additionally, 2002 earnings reflect the $3.0 million cumulative effect to January 1, 2002, of a change in accounting principle for the adoption of SFAS No. 142 and the associated write-down of RSAE goodwill.

Consolidated KCP&L Sales Revenues and MWh Sales

Retail revenues decreased $5.5 million in 2003 compared to 2002. The Kansas rate reduction effective January 1, 2003, decreased retail revenues approximately $12.5 million in 2003. See Critical Accounting Policies for additional information. This reduction was partially offset by continued load growth in 2003. Load growth consists of higher usage-per-customer and the addition of new customers. Retail revenues increased $15.5 million in 2002 compared to 2001 due to warmer 2002 summer weather and continued load growth, which included increased residential and commercial revenues of $25.4 million mostly offset by a reduction in industrial revenues. The reduction in industrial revenues was primarily due to a weakened economy and the loss of $4.4 million in revenues from one of KCP&L’s major industrial customers. The average number of residential and commercial customers

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increased approximately 1% and 2%, respectively, in 2003 compared to 2002. The average number of both residential and commercial customers increased approximately 2% in 2002 compared to 2001.

Wholesale revenues increased $49.5 million in 2003 compared to 2002, which in 2003, includes $2.7 million related to the partial settlements of Hawthorn No. 5 litigation. Wholesale revenues increased $28.7 million in 2002 compared to 2001. 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. These factors, combined with a more focused sales effort, helped increase MWh sales 16% in 2003 compared to 2002 and 40% in 2002 compared to 2001. This accounted for approximately 30% of the revenue variance in 2003 compared to 2002 and 91% of the revenue variance in 2002 compared to 2001. Approximately 70% of the revenue variance in 2003 compared to 2002 was due to average market prices per MWh of power sold in 2003 increasing 33% to $27.27. The increase was driven by higher natural gas prices. Wholesale revenues in 2002 also increased $1.7 million compared to 2001 due to additional capacity sales beginning in the last half of 2001. Less than 1% of revenues reflect rates that include an automatic fuel adjustment provision.

KCP&L Fuel and Purchased Power
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 change the fuel cost per MWh generated substantially. In 2003, KCP&L experienced a record coal base load capacity factor of 77%. The coal base load fleet achieved a record level of generation of over 15 million MWhs, a 6% increase compared to 2002. Nuclear fuel costs per MWh generated remain substantially less than the cost of coal per MWh generated. Replacement power costs for planned Wolf Creek outages are accrued evenly over the unit’s operating cycle. KCP&L expects its cost of nuclear fuel to remain fairly constant through the year 2008. Coal has a significantly lower cost per MWh generated than natural gas and oil. KCP&L’s procurement strategies continue to provide delivered coal costs below the regional average. Fossil plants averaged 75% of total generation and the nuclear plant the remainder over the last three years. The cost per MWh for purchased power is significantly higher than the fuel 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, availability and cost of purchased power and the requirements of other electric systems to provide reliable power economically.

Fuel expense increased $0.6 million in 2003 compared to 2002 primarily due to a 3% increase in MWhs generated. This increase was partially offset by a lower average fuel cost per MWh generated due to increased coal and less natural gas and oil in the fuel mix and a $4.0 million decrease related to the partial settlements of Hawthorn No. 5 litigation. Fuel costs decreased $4.1 million in 2002 compared to 2001, despite a 12% increase in generation. Lower fuel cost per MWh generated due to additional coal and less natural gas and oil in the fuel mix was the primary reason for the decline in fuel costs. The return to service of Hawthorn No. 5, a low cost coal-fired unit, in mid-2001 contributed to the change in generation fuel mix. Significantly lower natural gas prices and a reduction in the cost of uranium during 2002 also contributed to the lower fuel cost.

Purchased power expense increased $7.0 million in 2003 compared to 2002. Excluding the $11.8 million related to the partial settlements of Hawthorn No. 5 litigation, approximately 60% of the increase in 2003 is attributable to a 31% increase in the price per MWh driven primarily by increased natural gas prices. MWhs purchased increased 27% in 2003 compared to 2002 due to increased customer needs. Purchased power expenses decreased $19.0 million in 2002 compared to 2001. Cost per MWh purchased decreased approximately 31% in 2002 compared to 2001 due to regional energy availability, a less volatile energy market and decreased MWh purchases during peak hours. Also contributing to the decrease was a 15% decrease in MWhs purchased due to the increased availability of KCP&L’s generating units.

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Consolidated KCP&L Other Operating Expenses (including operating, maintenance and general taxes)
Consolidated KCP&L’s other operating expenses increased $11.0 million in 2003 compared to 2002 primarily due to the following:

Consolidated KCP&L’s other operating expenses increased $44.6 million in 2002 compared to 2001 primarily due to the following:

Consolidated KCP&L Depreciation
Consolidated KCP&L’s depreciation expense decreased $4.5 million in 2003 compared to 2002. Depreciation expense decreased approximately $7.7 million due to the change to a 60-year life for Wolf Creek pursuant to the 2002 KCC stipulation and agreement. See Critical Accounting Policies, Regulatory Matters for additional information. This decrease was partially offset by increased depreciation expense of $2.2 million related to capital additions and $1.3 million as a result of the consolidation of the Lease Trust. See Note 13 of the consolidated financial statements for additional information regarding consolidation of the Lease Trust.

Consolidated KCP&L’s depreciation expense increased $7.8 million in 2002 compared to 2001 primarily due to increased capital additions relating to Hawthorn No. 5, which was returned to service mid-2001. Additionally, KCP&L exercised its purchase option on the previously leased Hawthorn No. 6 unit in late 2001.

Consolidated KCP&L Interest Charges
Consolidated KCP&L’s interest charges decreased $10.0 million in 2003 compared to 2002. KCP&L’s long-term debt interest expense decreased $9.3 million in 2003 compared to 2002 primarily due to lower levels of outstanding long-term debt as a result of the repayment of $124.0 million of medium-term notes in 2003. Lower average interest rates in 2003 compared to 2002 also contributed to the decrease.

Consolidated KCP&L’s interest charges increased $1.9 million in 2002 compared to 2001. KCP&L’s long-term debt interest expense increased $3.0 million in 2002 compared to 2001, primarily due to higher average levels of long-term debt outstanding. Lower average rates on variable rate long-term debt partially offset the higher average levels of long-term debt. The higher average levels of debt outstanding primarily reflect the issuances of long-term debt in 2001 and the 2002 issuance of $225.0

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million of unsecured, fixed-rate senior notes partially offset by $227.0 million of scheduled debt repayments during 2002.

KCP&L’s short-term debt interest expense decreased $7.7 million in 2002 compared to 2001. Average interest rates were down more than 50% and average levels of outstanding commercial paper were down more than 70% in 2002 compared to 2001. KCP&L had no commercial paper outstanding at December 31, 2002.

Allowance for borrowed funds used to finance construction decreased $8.2 million in 2002 compared to 2001 due to decreased construction work in progress primarily due to the return to service of Hawthorn No. 5 in mid-2001.

Wolf Creek
Wolf Creek, a nuclear unit, is 20% of KCP&L’s base load generating capacity and 14% of KCP&L’s total generating capacity, including the 2003 addition of five leased combustion turbines that added peaking capacity. Wolf Creek’s operating performance has remained strong over the last three years, contributing an average of 24% of KCP&L’s annual MWh generation while operating at an average capacity of 92%. Wolf Creek has the lowest fuel cost per MWh generated of any of KCP&L’s generating units.

KCP&L accrues the incremental operating, maintenance and replacement power costs for planned outages evenly over the unit’s operating cycle, normally 18 months. As actual outage expenses are incurred, the refueling liability and related deferred tax asset are reduced. Wolf Creek returned to service on December 2, 2003, following a scheduled 36-day refueling and maintenance outage that was extended 10 days for a reactor head assembly inspection. The extension did not have a material impact on KCP&L’s 2003 results of operations. The next outage is scheduled for the spring of 2005 and is estimated to be a 28-day outage.

Wolf Creek’s assets represent approximately 32% of KCP&L’s assets and its operating expenses represent approximately 18% of KCP&L’s operating expenses. An extended shut-down of Wolf Creek could have a substantial adverse effect on KCP&L’s business, financial condition and results of operations because of higher replacement power and other costs. Although not expected, the NRC could impose an unscheduled plant shut-down, reacting to safety concerns at the plant or other similar nuclear units.  If a long-term shut-down occurred, the state regulatory commissions could reduce rates by excluding the Wolf Creek investment from rate base.

There has been significant opposition and delays to development of a low-level radioactive waste disposal facility. See Note 13 to the consolidated financial statements for additional information. An inability to complete this project would require KCP&L to write-off its net investment in the project, which was $7.4 million at December 31, 2003. KCP&L, and the other owners of Wolf Creek, could also still be required to participate in development of an alternate site.

Ownership and operation of a nuclear generating unit exposes KCP&L to risks regarding decommissioning costs at the end of the unit’s life and to potential retrospective assessments and property losses in excess of insurance coverage. These risks are more fully discussed in the related sections of Notes 1 and 13 to the consolidated financial statements.

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KCP&L Projected Utility Capital Expenditures
Total utility capital expenditures, excluding allowance for funds used to finance construction, were $148.7 million, $132.0 million and $262.0 million in 2003, 2002 and 2001, respectively. Utility capital expenditures projected for the next three years are as follows:

This utility capital expenditure plan is subject to continual review and change. General facilities in 2004 includes a $30 million expenditure to buy out the operating lease for vehicles and heavy equipment. KCP&L is currently evaluating purchase and construction options to meet capacity and energy requirements in 2005 and thereafter. Consequently, the table does not reflect utility capital expenditures for new capacity.

Strategic Energy

Strategic Energy Business Overview
Strategic Energy provides retail electricity services by entering into long-term contracts with its customers to supply electricity. In return, Strategic Energy receives an ongoing management fee, which is included in the contracted sales price for the electricity. Of the states that offer retail choice, Strategic Energy operates in California, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas. Strategic Energy is targeting expansion into Connecticut and Maryland in 2004, as well as expansion into additional utility territories in Ohio and Texas. Strategic Energy also provides strategic planning and consulting services in the natural gas and electricity markets.

Great Plains Energy’s indirect ownership in Strategic Energy currently totals 89%. In the normal course of business, Great Plains Energy and KLT Inc. provide financial or performance assurance to third parties on behalf of Strategic Energy in the form of guarantees to those third parties. Additionally, Great Plains Energy provides guarantees and indemnities supporting letters of credit and surety bonds obtained by Strategic Energy. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Strategic Energy on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish Strategic Energy’s intended business purposes.

At December 31, 2003, Strategic Energy provided retail electricity services on behalf of approximately 48,000 commercial, institutional and small manufacturing accounts. Strategic Energy’s diverse customer base, totaling over 6,800 customers, includes numerous Fortune 500 companies, smaller companies, and governmental entities. Based solely on current signed contracts and expected usage, Strategic Energy has forecasted future MWh commitments of 16.3 million, 10.1 million and 3.1 million for the years 2004 through 2006, respectively. Strategic Energy expects to deliver additional MWh sales in these years through growth in existing markets by re-signing existing customers and by signing new customers as well as through expansion into new markets. Strategic Energy’s projected MWh sales for 2004 based on signed contracts and expected additional MWh sales are in the range of 19 million to 21 million MWhs.

Strategic Energy maintains a commodity-price risk management strategy that uses forward physical energy purchases and derivative instruments to minimize significant, unanticipated earnings fluctuations caused by commodity-price volatility. As a result of supplying electricity to retail customers

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under fixed rate contracts, Strategic Energy’s policy is to match customers’ demand with fixed price purchases. In certain markets where Strategic Energy operates, entering into forward fixed price contracts is cost prohibitive. Derivative instruments, primarily swaps, are used to limit the unfavorable effect that price increases will have on electricity purchases. These instruments effectively fix the future purchase price of electricity, protecting Strategic Energy from price volatility.

See Item 1. Business, Strategic Energy section for information regarding the FERC Notice of Proposed Rulemaking to Remedy Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design.

Strategic Energy Supplier Concentration and Credit Risk
Credit risk represents the loss that Strategic Energy could incur if a counterparty failed to perform under its contractual obligations. To reduce its credit exposure, Strategic Energy enters into payment netting agreements with certain counterparties that permit Strategic Energy to offset receivables and payables with such counterparties. Strategic Energy further manages credit risk with certain counterparties by entering into agreements that enable Strategic Energy to terminate the transaction or modify collateral thresholds upon the occurrence of credit-related events.

Based on guidelines set by its Exposure Management Committee, Strategic Energy monitors its counterparty credit risk by routinely evaluating the credit quality and performance of its suppliers. Among other things, Strategic Energy monitors counterparty credit ratings, liquidity and results of operations. As a result of these evaluations, Strategic Energy may, among other things, establish counterparty credit limits and adjust the amount of collateral required from its suppliers.

Strategic Energy enters into forward contracts with multiple suppliers. At December 31, 2003, Strategic Energy’s five largest suppliers under forward supply contracts represented 65% of the total future committed purchases. Strategic Energy’s five largest suppliers, or their guarantors, are rated investment grade. In the event of supplier non-delivery or default, Strategic Energy’s results of operations could be affected to the extent the cost of replacement power exceeded the combination of the contracted price with the supplier and the amount of collateral held by Strategic Energy to mitigate its credit risk with the supplier. Strategic Energy’s results of operations could also be affected, in a given period, if it was required to make a payment upon termination of a supplier contract to the extent that the contracted price with the supplier exceeded the market value of the contract at the time of termination.

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The following table provides information on Strategic Energy’s credit exposure, net of collateral, as of December 31, 2003. It further delineates the exposure by the credit rating of counterparties and provides guidance on the concentration of credit risk and an indication of the maturity of the credit risk by credit rating of the counterparties.

External ratings are determined by using publicly available credit ratings of the counterparty. If a counterparty has provided a guarantee by a higher rated entity, the determination has been based on the rating of its guarantor. Internal ratings are determined by, among other things, an analysis of the counterparty’s financial statements and consideration of publicly available credit ratings of the counterparty’s parent. Investment grade counterparties are those with a minimum senior unsecured debt Standard & Poor’s rating of BBB- or a Moody’s rating of Baa3. Exposure before credit collateral has been calculated considering all netting agreements in place, netting accounts payable and receivable exposure with net mark-to-market exposure. Exposure before credit collateral is impacted primarily by the power supply volume under contract with a given counterparty and the relationship between current market prices and contracted power supply prices. Credit collateral includes the amount of cash deposits, guarantees and letters of credit received from counterparties. Net exposure has only been calculated for those counterparties to which Strategic Energy is exposed and excludes counterparties exposed to Strategic Energy.

At December 31, 2003, Strategic Energy had exposure before credit collateral to non-investment grade counterparties totaling $36.5 million of which 63% is scheduled to mature in less than two years. In addition, Strategic Energy held collateral totaling $30.8 million limiting its net exposure to these non-investment grade counterparties to $5.7 million at December 31, 2003.

In July 2003, Mirant filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The bankruptcy court entered an Interim Order, which ordered Mirant to comply with

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the terms of its prepetition trading contracts. In accordance with the Master Power Purchase and Sale Agreement and the ISDA Master Agreement between Strategic Energy and Mirant, the $10.0 million collateral threshold limit in both agreements was reduced to zero upon the bankruptcy filing. Since that time, Mirant and Strategic Energy have continued to perform under the conditions of their agreements. The Interim Order was finalized and Mirant has assumed its contracts with Strategic Energy.

Strategic Energy is continuing to pursue a strategy of contracting with national and regional counterparties that have direct supplies and assets in the region of demand. Strategic Energy is also continuing to address counterparty issues with strict margining and collateral requirements, netting of credit exposures against payable balances, preferences for higher credit quality counterparties and, in some cases, replacement of lower quality counterparty contracts.

Strategic Energy Results of Operations
The following table summarizes Strategic Energy’s comparative results of operations.

Strategic Energy’s net income increased $9.9 million in 2003 compared to 2002. The increased net income is primarily due to continued growth in retail electric sales from the expansion into new markets and continued sales efforts in existing markets. In addition to continued growth, Great Plains Energy’s ownership of Strategic Energy was increased by 6% in the fourth quarter of 2002. These increases were partially offset by increased general and administrative expenses including employee related expenses. Also, revenues less purchased power divided by MWh sold (gross margin per MWh) decreased to $7.34 in 2003 compared to $8.70 in 2002. The decrease in gross margin per MWh in 2003 compared to 2002 was primarily due to the roll-off of higher margin contracts that were obtained during periods of high market price volatility in late 2000 and early 2001 and to a lesser extent market conditions, including increased competition. Strategic Energy currently expects the gross margin per MWh on new customer contracts to average $5.00 to $6.00 and the gross margin per MWh on total customer contracts to average $6.20 to $6.50 in 2004.

Strategic Energy’s net income increased $7.9 million in 2002 compared to 2001; however, 2001 net income included earnings of $15.0 million from the sale of power purchased from one supplier under wholesale contracts that expired at the end of 2001. The increased net income in 2002 compared to 2001 is primarily due to continued growth in retail electric sales from the expansion into new markets and continued sales efforts in existing markets, partially offset by increased labor and benefits as well as other general and administrative expenses and income taxes due to increased sales in states with higher income tax rates.

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Strategic Energy Operating Revenues
Operating revenues from Strategic Energy increased $301.5 million in 2003 compared to 2002 and $377.6 million in 2002 compared to 2001 as shown in the following table.

At December 31, 2003, Strategic Energy served over 6,800 customers, a 31% increase from approximately 5,200 customers at the end of 2002. Customers at the end of 2002 increased 53% from 3,400 customers at the end of 2001. These customers represented approximately 48,000 accounts at the end of 2003, a 45% increase from approximately 33,000 accounts at the end of 2002. Accounts at the end of 2002 increased 69% from approximately 19,500 accounts at the end of 2001.

Retail electric revenues increased $303.7 million in 2003 compared to 2002 primarily due to increased retail MWh sales. Retail MWhs sold increased approximately 41% to 16.6 million in 2003 from 11.8 million in 2002. The increase in MWh sales resulted primarily from effective sales efforts in re-signing approximately 80% of existing customers as well as signing new customers in markets in which Strategic Energy continued to experience favorable conditions for growth. MWh sales in California increased 70% to 5.5 million in 2003 from 3.2 million in 2002 and MWh sales in Texas increased 58% to 4.5 million in 2003 from 2.8 million in 2002.

Retail electric revenues increased $446.2 million in 2002 compared to 2001 primarily due to increased retail MWh sales, partially offset by an 8% decrease in average retail revenues per MWh. Retail MWhs sold increased 162% to 11.8 million in 2002 from 4.5 million in 2001, primarily from continued growth in existing markets and expansion into new markets during 2002. Growth in existing markets came primarily from strong sales efforts in re-signing existing customers as well as signing new customers. Expansion into new markets contributed 2.8 million in MWh sales and approximately $166 million of retail electric revenues during 2002. Several factors contribute to changes in the average retail revenues per MWh, including the underlying price of the commodity, the nature and type of products offered and the mix of sales by geographic market.

Strategic Energy Purchased Power
Strategic Energy primarily purchases power under long-term forward physical delivery contracts to supply electricity to its retail energy customers based on projected usage. Strategic Energy sells any excess retail supply of electricity back into the wholesale market. The proceeds from the sale of excess supply of electricity are recorded as a reduction of purchased power. The amount of excess retail supply sales that reduced purchased power was $160.4 million, $126.4 million and $95.6 million in 2003, 2002 and 2001, respectively.

Strategic Energy utilizes derivatives in the procurement of electricity that are economic hedges but not considered accounting hedges. Accordingly, changes in the fair value of these derivative instruments are recorded as a component of purchased power. The amounts were insignificant for all periods presented.

As previously discussed, Strategic Energy operates in several retail choice electricity markets. The cost of supplying electricity to retail customers can vary widely by geographic market. This variability can be affected by many factors including, among other items, geographic differences in the cost per

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MWh of purchased power and capacity charges due to regional purchased power availability and requirements of other electricity providers and differences in transmission charges. However, Strategic Energy has mitigated the effects of higher supply costs by entering into long-term, full-requirements contracts with customers that are priced to the customers based on the cost of the associated supply contract.

Purchased power increased $283.5 million in 2003 compared to 2002 and increased $356.4 million in 2002 compared to 2001 primarily due to the increases in electric MWh sales discussed above. Additionally, purchased power expense as a percentage of electric revenues increased in 2002 compared to 2001 primarily due to purchases of power from one supplier during 2001 under wholesale contracts that expired at the end of 2001.

Strategic Energy Other Operating Expenses
Strategic Energy’s other operating expenses as a percentage of operating revenues decreased to 3.9% in 2003 from 4.8% and 9.4% 2002 and 2001, respectively, due to Strategic Energy’s efforts in leveraging its infrastructure and the effects of achieving economies of scale. Other operating expenses increased $4.5 million in 2003 compared to 2002 primarily due to higher labor and benefit costs from the addition of employees and higher other general and administrative expenses associated with higher sales volumes, geographic market expansion, and regulatory and market development initiatives.

Other operating expenses decreased $1.1 million in 2002 compared to 2001 primarily due to a $15.5 million decrease in the cost of commercial gas sales from Strategic Energy’s natural gas retail supply service, which was phased out by the end of 2001. This decrease was mostly offset by increased labor and benefit costs from the addition of employees and increasing health care related costs, higher profit sharing and deferred compensation expense which are tied to earnings and financial performance, and higher other general and administrative expenses associated with higher sales volumes, geographic market expansion, and regulatory and market development initiatives.

Strategic Energy Non-operating Income (Expenses)
Strategic Energy’s non-operating income (expenses) includes non-operating income less minority interest expense and non-operating expenses. Minority interest expense represents the share of Strategic Energy’s net income not attributable to Great Plains Energy’s indirect ownership interest in Strategic Energy. Non-operating income (expenses) decreased $2.3 million in 2003 compared to 2002 primarily due to a $1.7 million decrease in minority interest expense resulting from Great Plains Energy’s acquisition of an additional 6% indirect ownership interest in Strategic Energy during the fourth quarter of 2002. Non-operating income (expenses) increased $4.0 million in 2002 compared to 2001 primarily due to a gain of $1.4 million recognized on the sale of gas contracts during the second quarter of 2001 and an increase in minority interest expense of $2.8 million.

Other Non Regulated Activities

Investment in Affordable Housing Limited Partnerships — KLT Investments
KLT Investments Inc.‘s (KLT Investments) earnings in 2003 totaled $8.1 million (including an after tax reduction of $6.7 million in its affordable housing investment) compared to earnings of $10.4 million in 2002 (including an after tax reduction of $5.7 million in its affordable housing investment) and earnings of $6.6 million in 2001 (including an after tax reduction of $8.6 million in its affordable housing investment).

On a quarterly basis, KLT Investments compares the cost of properties accounted for by the cost method to the total of projected residual value of the properties and remaining tax credits to be received. Estimated residual values are based on studies performed by an independent firm. Based on the latest comparison, KLT Investments reduced its investments in affordable housing limited

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partnerships by $11.0 million, $9.0 million, and $13.5 million in 2003, 2002 and 2001, respectively. Pretax reductions in affordable housing investments are estimated to be $7 million, $10 million, and $3 million for the years 2004 through 2006, respectively. These projections are based on the latest information available but the ultimate amount and timing of actual reductions could be significantly different from the above estimates. The properties underlying the partnership investment are subject to certain risks inherent in real estate ownership and management. Even after these estimated reductions, earnings from the investments in affordable housing are expected to be positive for the years 2004 through 2006. KLT Investments’ management does not anticipate making additional investments in affordable housing limited partnerships at this time.

KLT Investments accrued tax credits related to its investments in affordable housing limited partnerships of $19.1 million, $19.3 million and $19.2 million in 2003, 2002 and 2001, respectively.

Subsidiary of KLT Telecom Files for Bankruptcy — DTI
The accounting treatment related to DTI and its 2001 bankruptcy is complex and is addressed in greater detail in Note 9 to the consolidated financial statements; consequently, Note 9 in its entirety is incorporated by reference in this portion of Management’s Discussion and Analysis and should be read as a component of this discussion.

On December 31, 2001, a subsidiary of KLT Telecom, Holdings and its subsidiaries, Digital Teleport and Digital Teleport of Virginia, Inc., filed separate voluntary petitions in the Bankruptcy Court for the Eastern District of Missouri for reorganization under Chapter 11 of the U.S. Bankruptcy Code, which cases have been procedurally consolidated. Holdings and its two subsidiaries are collectively called “DTI”.

In December 2002, Digital Teleport entered into an agreement to sell substantially all of its assets (Asset Sale) to CenturyTel Fiber Company II, LLC (CenturyTel), a nominee of CenturyTel, Inc. The Asset Sale was approved by the Bankruptcy Court in 2003 and closed in 2003.

KLT Telecom received $19.2 million in 2003 related to the confirmation of the DTI bankruptcy. Additionally, KLT Telecom realized approximately $21 million of cash tax benefits in 2003. Pending final resolution of the MODOR Claim and the put option of a certain minority shareholder (which are described below), the Company recorded a net gain of $28.1 million or $0.41 per share in 2003. The impact on net income was primarily due to the net effect of the confirmation of the DTI bankruptcy and the resulting distribution, the reversal of a $15.8 million tax valuation allowance and the reversal of a $5 million debtor in possession financing commitment previously reserved.

In early 2004, KLT Telecom paid $2.5 million to certain executives of Digital Teleport for entering into employment agreements required as a condition precedent to the Asset Sale. The amount was recorded as a liability in 2003.

The Bankruptcy Court conducted an evidentiary hearing regarding three priority proofs of claim by the Missouri Department of Revenue in the aggregate amount of $2.8 million (collectively, the MODOR Claim), and ruled substantially in favor of Digital Teleport. MODOR appealed this ruling. KLT Telecom may receive an additional distribution from the bankruptcy estate; however, the amount and timing of any additional distribution is dependant upon the outcome of the MODOR appeal.

KLT Telecom originally acquired a 47% interest in DTI in 1997. On February 8, 2001, KLT Telecom acquired control of DTI by purchasing shares from another Holdings shareholder, Weinstein, increasing its ownership to 83.6%. In connection with this purchase, KLT Telecom granted Weinstein a put option. The put option provided for the sale by Weinstein of his remaining shares in Holdings to KLT Telecom during a period beginning September 1, 2003, and ending August 31, 2005. The put option provides

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for an aggregate exercise price for these remaining shares equal to their fair market value with an aggregate floor amount of $15 million. The floor amount of the put option was fully reserved during the fourth quarter of 2001, as described in Note 9 to the consolidated financial statements. On September 2, 2003, Weinstein delivered a notice of exercise of his claimed rights under the put option. KLT Telecom rejected the notice of exercise. KLT Telecom denied that Weinstein has any remaining rights or claims pursuant to the put option, and denied any obligation to pay Weinstein any amount under the put option. Subsequent to KLT Telecom’s rejection of his notice of exercise, Weinstein filed suit alleging breach of contract. See Item 3. Legal Proceedings for additional information.

The operating results of DTI have been included for the period February 8, 2001 (date of acquisition) through September 30, 2001, for consolidated KCP&L and through December 31, 2001, for Great Plains Energy. Because of DTI’s bankruptcy filings, KLT Telecom no longer had control over nor could it exert significant control over DTI. As a consequence, as of December 31, 2001, DTI was de-consolidated and presented on the cost basis. Consequently, KLT Telecom did not include in its financial results the ongoing results of operations, earnings or losses incurred by DTI since December 31, 2001.

Because of the bankruptcy filings, a $195.8 million net write-off was included in (Gain) Loss on Property in operating expenses on Great Plains Energy’s 2001 Consolidated Statement of Income. A corresponding tax benefit of $55.8 million was included in income taxes. The 2001 net impact of the bankruptcy to income was a $140.0 million reduction. Income taxes reported in 2001 do not reflect the entire effect of the net write-off because of the uncertainty of recognizing future tax deductions while in the bankruptcy process.

Other
During 2001, KLT Energy Services wrote off its $6.2 million cost basis investment in the common stock of Bracknell Corporation (Bracknell) due to a decline in its share price and the bankruptcy filing of one of Bracknell’s subsidiaries.

Discontinued Operations (KLT Gas)

KLT Gas Business Overview, Decision to Exit the Gas Business and Discontinued Operations

In February 2004, the Great Plains Energy Board of Directors approved management’s recommendation to sell the KLT Gas portfolio and exit the gas business. The Company evaluated this business and determined the amount of capital and the length of time required for development of reserves and production, combined with the earnings volatility of the exploration process, are no longer compatible with the Company’s strategic vision. Management will continue to operate the KLT Gas portfolio during the sale process, which it expects to complete during 2004. See Note 7 to the consolidated financial statements for additional information.

In addition to the first quarter 2004 write down of the KLT Gas portfolio to its estimated realizable value discussed in Note 7 to the consolidated financial statements, management expects to incur losses during 2004 to operate KLT Gas while it markets the KLT Gas portfolio for sale. Management estimates the 2004 losses to operate KLT Gas will approximate $6.0 million before taxes, which after taxes would reduce 2004 earnings by approximately $4.0 million. The after tax losses will be reflected as a loss from discontinued operations in Great Plains Energy’s consolidated statements of income in the periods incurred. The estimated losses to operate KLT Gas anticipate completion of a sale of the KLT Gas portfolio at December 31, 2004. The ultimate impact to Great Plains Energy’s consolidated statements of income for 2004 will be different than the estimates to the extent costs to operate deviate from the budget and/or the timing of the KLT Gas portfolio sale deviates from December 31, 2004.

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Prior to the decision to exit the business, KLT Gas focused on exploring for, developing, and producing unconventional natural gas resources, including coalbed methane properties. KLT Gas’ leased properties are located primarily in Colorado, Kansas and Wyoming with some leases in Nebraska and Texas.

In 2003, KLT Gas completed the sale of approximately 30,000 undeveloped acres in Kansas. KLT Gas follows the full cost accounting method for its natural gas properties, under which the acreage sale was accounted for as an adjustment to capitalized costs with no gain recognized in earnings.

In 2003, KLT Gas leased additional acreage in the Rocky Mountain region. Exploration of portions of the newly acquired acreage commenced in the third quarter of 2003. In addition, KLT Gas continued to test a prospect in Colorado, as well as develop a pilot project in the Powder River Basin and two additional projects in the Rocky Mountain region.

See Note 1, Natural Gas Properties included in Assets of Discontinued Operations section, to the consolidated financial statements for information regarding the effect of SFAS No. 141, “Business Combinations” and SFAS No. 142 on KLT Gas’ contractual mineral rights included in Assets of Discontinued Operations on Great Plains Energy’s consolidated balance sheet.

Discontinued Operations (KLT Gas) includes after tax operating losses of $2.6 million and impairments of $54.5 million, which reduced earnings by $33.5 million. The impairments include impairment charges totaling $15.2 million, which reduced earnings by $9.3 million, on two properties in response to lower revised estimates of future gas production and a fourth quarter 2003 impairment charge of $39.3 million, which reduced earnings by $24.2 million, related to the Company’s KLT Gas strategic review and exit plan valuation analysis. See Note 7 to the consolidated financial statements for additional information regarding KLT Gas property impairments. Discontinued Operations (KLT Gas) in 2001 included its second quarter Patrick KLT Gas, LLC sale, which resulted in a $12.0 million after tax gain. Also reflected in 2002 and 2001 Discontinued Operations (KLT Gas) are tax credits recorded related to its investment in natural gas properties of $6.5 million and $6.0 million, respectively. The law that allowed substantially all of these credits expired at the end of 2002.

Great Plains Energy and Consolidated KCP&L
Significant Balance Sheet Changes

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Capital Requirements and Liquidity
Great Plains Energy operates through its subsidiaries and has no material assets other than the stock of its subsidiaries. Great Plains Energy’s ability to make payments on its debt securities and its ability

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to pay dividends is dependent on its receipt of dividends from its subsidiaries and proceeds from the sale of its securities.

Great Plains Energy’s capital requirements are principally comprised of KCP&L’s utility capital expenditures and KCP&L’s pension benefit plan funding requirements discussed below. Additional cash and capital requirements for the companies, including long-term debt requirements, are discussed below.

Great Plains Energy’s liquid resources at December 31, 2003, included cash flows from operations of subsidiaries, $114.2 million of cash and cash equivalents on hand and $299.5 million of unused bank lines of credit. The unused lines consisted of $150.0 million from KCP&L’s short-term bank lines of credit, $27.3 million from Strategic Energy’s revolving credit facility, and $122.2 million from Great Plains Energy’s revolving credit facility. See the Debt Agreements section below for more information on these agreements.

KCP&L’s consolidated statements of cash flows include KLT Inc. and GPP for all the periods prior to the October 1, 2001 formation of the holding company. The effect of the 2001 bankruptcy of DTI on the statements of cash flows is detailed in Note 9 to the consolidated financial statements.

Cash Flows From Operations
Great Plains Energy and consolidated KCP&L generated positive cash flows from operating activities for the periods presented. The increase in cash flows from operating activities for Great Plains Energy in 2003 compared to 2002 is primarily due to a $56.0 million increase in income from continuing operations and the changes in working capital detailed in Note 2 to the consolidated financial statements. The individual components of working capital vary with normal business cycles and operations. Consolidated KCP&L’s cash flow from operations increased slightly in 2003 compared to 2002 due to a $26.2 million increase in income from continuing operations and an increase in deferred taxes mostly offset by the changes in working capital detailed in Note 2 to the consolidated financial statements. Also, the timing of the Wolf Creek outage affects the refueling outage accrual, deferred income taxes and amortization of nuclear fuel. The decrease for Great Plains Energy and consolidated KCP&L in 2002 compared to 2001 is due primarily to the recast of KLT Gas as discontinued operations partially offset by the changes in working capital detailed in Note 2 to the consolidated financial statements.

Investing Activities
Great Plains Energy’s and consolidated KCP&L’s cash used for investing activities varies with the timing of utility capital expenditures and purchases of investments and nonutility property. Investing activities are offset by the proceeds from the sale of properties and insurance recoveries. Utility capital expenditures and the allowance for borrowed funds used during construction increased $17.9 million in 2003 compared to 2002 primarily due to transmission plant and nuclear fuel additions partially offset by 2002 capital expenditures of $14.7 million related to the January 2002 ice storm and insurance proceeds and partial litigation settlements from Hawthorn No. 5 received in 2003. Additionally, Great Plains Energy received proceeds of $19.2 million as a result of the DTI bankruptcy.

Utility capital expenditures and the allowance for borrowed funds used during construction decreased $139.1 million in 2002 compared to 2001 primarily due to KCP&L’s mid-2001 completion of the rebuild of Hawthorn No. 5 partially offset by KCP&L’s capital expenditures of $14.7 million as a result of the January 2002 ice storm. Cash used for purchases of investments and nonutility property in 2002 compared to 2001 decreased primarily reflecting KLT Telecom’s 2001 investments in DTI and DTI’s 2001 purchases of telecommunications property.

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Financing Activities
The change in Great Plains Energy and consolidated KCP&L’s cash flows from financing activities in 2003 compared to 2002 reflects the 2003 equity infusion of $100.0 million from Great Plains Energy to KCP&L and KCP&L’s subsequent redemption of $104.0 million of medium-term notes. Great Plains Energy essentially funded the infusion with proceeds from its $151.8 million common stock offering in late 2002; however, prior to the infusion, Great Plains Energy used the offering proceeds to repay short-term borrowings in late 2002 and then re-borrowed in early 2003 to make the equity infusion into KCP&L at the time of redemption. An additional $20.0 million of KCP&L’s medium-term notes were retired during 2003. The increase in dividends paid by Great Plains Energy is primarily attributable to the public offering of 6.9 million common shares in late 2002.

On November 7, 2002, Great Plains Energy entered into an Agreement and Plan of Merger (Agreement) with ELC, the ELC shareholders and IEC, a wholly-owned subsidiary of Great Plains Energy. The ELC Shareholders received $15.1 million in merger consideration. As part of the merger consideration, on November 7, 2002, Great Plains Energy issued 387,596 additional shares of its common stock to the ELC Shareholders. The Agreement valued such shares at approximately $8 million. The remainder of the merger consideration was in short-term notes, which were paid in January 2003.

Great Plains Energy repaid $185.8 million of debt balances in 2002 compared to net borrowings in 2001 of $186.5 million. Included in the Great Plains Energy’s amounts is the consolidated KCP&L’s repayment of $64.2 million of debt balances in 2002 compared to net borrowings of $160.4 million in 2001. The repayments in 2002 compared to the borrowings in 2001 reflect decreased investing activities in utility capital expenditures, nonutility property and investments discussed above.

KCP&L expects to meet day-to-day operating requirements including interest payments, construction requirements (excluding new generating capacity) and dividends to Great Plains Energy with internally-generated funds. However, it 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 Great Plains Energy and consolidated KCP&L need to retire maturing debt (detailed below) will be provided from operations, the issuance of long and short-term debt and/or the issuance of equity or equity-linked instruments. In addition, the Company may issue debt, equity and/or equity-linked instruments to finance growth or take advantage of new opportunities.

Strategic Energy expects to meet day-to-day operating requirements including interest payments, credit support fees, capital expenditures and dividends to its indirect interest holders with internally-generated funds. However, it 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, commodity-price volatility and the effects of counterparty non-performance.

Great Plains Energy filed a registration statement in April 2002 for the issuance of an aggregate amount up to $300 million of any combination of senior debt securities, subordinated debt securities, trust preferred securities, convertible securities, or common stock. The registration statement became effective in November 2002 and Great Plains Energy issued $151.8 million of common stock.

As a registered public utility holding company, Great Plains Energy must receive authorization from the SEC under the 35 Act to issue securities. Great Plains Energy is currently authorized to issue up to $1.2 billion of debt and equity through December 31, 2005. Great Plains Energy has utilized $500.7 million of this amount as follows: (i) $39.0 million in preferred stock issued in connection with the October 1, 2001, reorganization; (ii) $150.0 million in a 364-day revolving credit facility and $150 million in a three-year revolving credit facility ($102.8 million was outstanding at December 31, 2003, under the

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replaced $225.0 million revolving credit facility discussed below); (iii) $159.8 million in common equity issued in a public offering and in connection with IEC’s acquisition of an indirect ownership interest in Strategic Energy and (iv) $1.9 million in restricted stock issued to executives on October 1, 2003.

Under its current SEC authorization, Great Plains Energy cannot issue securities other than common stock unless (i) the security to be issued, if rated, is rated investment grade by one nationally recognized statistical rating organization, (ii) all of its outstanding securities that are rated (except for its preferred stock) are rated investment grade, and (iii) it has maintained common equity as a percentage of consolidated capitalization (as reflected on its consolidated balance sheets as of the end of each quarter) of at least 30%. Great Plains Energy was in compliance with these conditions as of December 31, 2003.

KCP&L filed a shelf registration statement for up to $255 million of senior and subordinated debt securities, trust preferred securities and related guarantees in 2003 providing KCP&L flexibility to access the capital markets.

KCP&L may issue equity and long-term debt only with the authorization of the MPSC. KCP&L’s previous authorization expired at the end of 2003. KCP&L has filed an application with the MPSC for authority to issue up to $600 million of long-term debt through March 31, 2006. KCP&L expects the MPSC to act on its application within the next few months.

Issuances of short-term debt by KCP&L are subject to SEC authorization under the 35 Act. Under the current authorization, KCP&L may issue and have outstanding at any one time up to $500 million of short-term debt. Under this authorization, KCP&L cannot issue short term debt (other than commercial paper or short-term bank facilities) unless (i) the short-term debt to be issued, if rated, is rated investment grade by one nationally recognized statistical rating organization, (ii) all of its outstanding securities that are rated are rated investment grade, (iii) all of the outstanding rated securities of Great Plains Energy (except preferred stock) are rated investment grade, and (iv) Great Plains Energy and KCP&L have maintained common equity as a percentage of consolidated capitalization (as reflected on their consolidated balance sheets as of the end of each quarter) of at least 30%. KCP&L was in compliance with these conditions as of December 31, 2003.

In 2003, KCP&L also completed the remarketing of its 1998 Series C EIRR bonds totaling $50.0 million. The bonds are classified as current liabilities in the December 31, 2003, balance sheet. The remarketed bonds were issued with a one-year maturity at a fixed interest rate of 2.25%.

KCP&L has entered into a revolving agreement, which expires in October 2004, to sell all of its right, title and interest in the majority of its customer accounts receivable to Receivables Company, which in turn sells most of the receivables to outside investors. KCP&L expects the agreement to be renewed annually. See Note 3 to the consolidated financial statements.

Debt Agreements
Great Plains Energy syndicated a $225.0 million, revolving credit facility with a group of banks in the first quarter of 2003. The line expires in March 2004, but may be extended for an additional year at the Company’s option. Effective March 5, 2004, Great Plains Energy replaced this revolving credit facility with a $150.0 million 364-day revolving credit facility and a $150.0 million three-year revolving credit facility. The new facilities have substantially the same terms and conditions as the existing credit facility. The existing facility contains a Material Adverse Change (MAC) clause that requires Great Plains Energy to represent, prior to receiving funding, that no MAC has occurred. The clause does, however, permit the Company 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 occurs in the context of a merger, consolidation or sale. A default by

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Great Plains Energy or any of its significant subsidiaries of other indebtedness totaling more than $25.0 million is a default under this bank line. Under the terms of this agreement, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio not greater than 0.65 to 1.0 at all times and an interest coverage ratio greater than 2.25 to 1.0, as those ratios are defined in the agreement. At December 31, 2003, the Company was in compliance with these covenants.

Strategic Energy maintains a secured revolving credit facility for up to $95 million with a group of banks. This facility is partially guaranteed by Great Plains Energy. The facility enhances Strategic Energy’s liquidity including its ability to provide credit support through letters of credit for purchased power and regulatory requirements. The maximum amount available for loans and letters of credit under the facility is the lesser of $95 million or the borrowing base, as defined in the agreement. The borrowing base generally is the sum of certain Strategic Energy accounts receivable and the amount of the Great Plains Energy guarantee which was $40.0 million at December 31, 2003. At December 31, 2003, Strategic Energy had a minimum fixed charge ratio, as defined in the agreement, of at least 1.05 to 1.0; however, if the ratio drops below 1.05 to 1.0, Great Plains Energy’s guarantee amount is required to be increased based on quarterly calculations. At December 31, 2003, $58.5 million in letters of credit had been issued under the agreement, leaving $27.3 million of capacity available for loans and additional letters of credit. The line expires in June 2004, but may be extended for an additional year by mutual agreement of the parties. The facility contains a MAC clause that requires Strategic Energy to represent, prior to receiving funding, that no MAC has occurred. A default by Strategic Energy of other indebtedness, as defined in the facility, totaling more than $5.0 million is a default under the facility. Under the terms of this agreement, Strategic Energy is required to maintain a minimum net worth of $30 million and a maximum debt to EBITDA ratio of 2.0 to 1.0, as those are defined in the agreement. At December 31, 2003, Strategic Energy was in compliance with these covenants.

KCP&L’s primary sources of liquidity are cash flows from operations and bilateral credit lines totaling $150.0 million with seven banks (as of December 31, 2003). KCP&L uses these lines to provide support for its issuance of commercial paper. These bank facilities are each for a 364-day term and mature at various times throughout the year. The facilities can be extended for one year under their term out provisions. KCP&L has MAC clauses in three agreements covering $70.0 million of available bilateral credit lines. These three facilities require KCP&L to represent, prior to receiving funding, that no MAC has occurred. Under these agreements, KCP&L is able to access the facilities even in the event of a MAC in order to redeem maturing commercial paper. KCP&L’s available liquidity under these facilities is not impacted by a decline in credit ratings unless the downgrade occurs in the context of a merger, consolidation or sale. A default by KCP&L on other indebtedness is a default under these bank line agreements. Under the terms of certain bank line agreements, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreements, not greater than 0.65 to 1.0 at all times. At December 31, 2003, KCP&L was in compliance with the covenant.

Under the indenture relating to KCP&L’s Debentures, which are held by KCPL Financing I, KCP&L may not declare or pay any dividends on any shares of its capital stock if at the time (i) there is an event of default (as defined in the indenture), (ii) KCP&L is in default with respect to its payment of any obligations under its guarantee of preferred securities issued by KCPL Financing I, or (iii) KCP&L has elected to defer payments of interest on the Debentures.

Great Plains Energy has agreements with KLT Investments associated with notes KLT Investments issued to acquire its affordable housing investments. Great Plains Energy has agreed not to take certain actions including, but not limited to, merging, dissolving or causing the dissolution of KLT Investments, or withdrawing amounts from KLT Investments if the withdrawals would result in KLT Investments not being in compliance with minimum net worth and cash balance requirements. The

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agreements also give KLT Investments’ lenders the right to have KLT Investments repurchase the notes if Great Plains Energy’s senior debt rating falls below investment grade, or if Great Plains Energy ceases to own at least 80% of KCP&L’s stock. At December 31, 2003, KLT Investments had $10.6 million in outstanding notes, including current maturities.

Under stipulations with the MPSC and KCC, Great Plains Energy and KCP&L maintain common equity at not less than 30% and 35%, respectively, of total capitalization. Pursuant to an SEC order, Great Plains Energy’s and KCP&L’s authorization to issue securities is conditioned on maintaining a consolidated common equity capitalization of at least 30% and complying with other conditions described above.

Pensions
The Company maintains defined benefit plans for substantially all of its employees and incurs significant costs in providing the plans, with the majority incurred by KCP&L. Plans are funded at a minimum on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants consistent with the funding requirements of the Employment Retirement Income Security Act of 1974 (ERISA) and further contributions may be made when deemed financially advantageous.

Due to sharp declines in the debt and equity markets since the third quarter of 2000, the value of assets held in the trusts to satisfy pension plan obligations has decreased significantly. As a result, the Company’s minimum funding requirements determined under ERISA have increased from $1.6 million in 2002 to $9.7 million in 2003, all of which was funded by KCP&L. The Company funded an additional $31.5 million in 2003, of which KCP&L contributed $29.6 million. The additional funding will reduce payments in future years.

The ERISA funding requirement for 2004 is $24.3 million of which $20.1 million was paid in 2003. KCP&L will be responsible for $23.1 million, of which $18.9 million was contributed in 2003. Management believes the Company has adequate access to capital resources through cash flows from operations or through existing lines of credit to support the remaining required funding. 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.

Under the terms of the pension plans, the Company reserves the right to amend or terminate the plans, and from time to time benefits have changed. See Note 10 to the consolidated financial statements for further discussion.

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Credit Ratings
At December 31, 2003, the major credit rating agencies rated the companies’ securities as follows:

The ratings reflect the November 12, 2003, Moody’s Investor Service downgrade of its ratings of KCP&L securities and corresponding change in its rating outlook from negative to stable. At the same time, the credit ratings and rating outlook for Great Plains Energy’s securities were affirmed. The ratings presented reflect the current views of these rating agencies and no assurances can be given that these ratings will continue for any given period of time. The companies view maintenance of strong credit ratings as being extremely important; however, and to that end, an active and ongoing dialogue is maintained with the agencies with respect to the companies’ results of operations, financial position, and future prospects.

None of the companies’ outstanding debt, except for the notes associated with affordable housing investments discussed above, is impacted by a decline in credit ratings, which would cause 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. However, in the event of a downgrade the companies and/or their subsidiaries may be subject to increased interest costs on their credit facilities. Additionally, in KCP&L’s bond insurance policies on its Series 1993A and 1993B EIRR bonds, which aggregate $79.5 million, 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.

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Supplemental Capital Requirements and Liquidity Information
The following information is provided to summarize cash obligations and commercial commitments.

Long-term debt includes current maturities. See Note 18 to the consolidated financial statements and the consolidated KCP&L long-term debt discussion below for additional information.

See the consolidated KCP&L lease obligation discussion below and Note 13 to the consolidated financial statements for additional information.

Purchased power represents Strategic Energy’s agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Strategic Energy has energy sales contracts not included above for 2004 and 2005 totaling $111.9 million and $37.8 million, respectively.

The Company has long-term liabilities recorded on its consolidated balance sheet at December 31, 2003, under GAAP, that do not have a definitive cash payout date and are not included in the table above.

Long-term debt includes current maturities. Long-term debt principal excludes $0.7 million discount on senior notes and the $3.3 million fair value adjustment to the EIRR bonds related to SFAS No. 133. EIRR bonds classified as current liabilities of $129.3 million due at various dates during the years 2012

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through 2018 are included here on their final due date. Variable rate interest obligations are based on rates as of January 1, 2004. See Note 18 to the consolidated financial statements for additional information.

Lease obligations include capital and operating lease obligations; capital lease obligations are less than 3% of the total. Lease obligations also include leases for railcars to serve jointly-owned generating units where KCP&L is the managing partner. KCP&L will be reimbursed by the other owners for about $2.0 million per year ($24.0 million total) of the amounts included in the table above. See Note 13 to the consolidated financial statements for additional information.

Nuclear fuel represents KCP&L’s 47% share of Wolf Creek nuclear fuel commitments including enrichment, fabrication, uranium and conversion. Coal represents KCP&L’s share of purchase commitments based on estimated prices to supply coal for generating plants.

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. This can be a cost-effective alternative to new construction. KCP&L has capacity sales agreements not included above that total $12.5 million for 2004 and $11.8 million per year for 2005 through 2008.

Consolidated KCP&L has long-term liabilities recorded on its consolidated balance sheet at December 31, 2003, under GAAP, that do not have a definitive cash payout date and are not included in the table above.

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

As a registered public utility holding company system, Great Plains Energy must receive authorization from the SEC under the 35 Act to issue guarantees on behalf of its subsidiaries. Under its current SEC authorization, guarantees cannot be issued unless (i) all of its outstanding securities that are rated (except for its preferred stock) are rated investment grade and (ii) it has maintained common equity as a percentage of consolidated capitalization (as reflected on its consolidated balance sheets as of the end of each quarter) of at least 30%. Great Plains Energy was in compliance with these conditions as of December 31, 2003. Great Plains Energy is currently authorized to issue up to $600 million for guarantees on behalf of its subsidiaries and the nonutility subsidiaries have $300 million of authorization for guarantees they can issue on behalf of other nonutility subsidiaries.

As prescribed in FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Guarantees of Indebtedness of Others,” the Company began recording a liability for the fair value of obligations it undertakes for guarantees issued after December 31, 2002. The interpretation does not encompass guarantees of the Company’s own future performance, such as Great Plains Energy’s guarantees to support Strategic Energy power purchases and regulatory requirements. KCP&L began recording an immaterial amount for the fair value of guarantees issued in 2003 for the residual value of vehicles and heavy equipment under an operating lease, which terminated with the buy out of the lease in early 2004.

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