WM 02-0016, Transmittal of 2001 Annual Financial Reports

Transmittal of 2001 Annual Financial Reports

ML021330799
Person / Time
Site:	Wolf Creek
Issue date:	05/06/2002
From:	Maynard O Wolf Creek
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
WM 02-0016
Download: ML021330799 (242)

Text

W*PLF CREEK 'NUCLEAR OPERATING CORPORATION Otto L. Maynard President and Chief Executive Officer MAY 6 2002 WM 02-0016 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Station P1-137 Washington, D. C. 20555

Subject:

Docket No. 50-482: Transmittal of 2001 Annual Financial Reports Gentlemen:

Wolf Creek Nuclear Operating Corporation is transmitting one copy each of the 2001 Annual Reports, including financial statements, for Kansas Electric Power Cooperative, Inc., Kansas City Power & Light Company, and Western Resources, Inc., including its wholly owned subsidiary Kansas Gas and Electric Company. This information is being submitted in accordance with 10 CFR 50.71 (b).

If you have any questions concerning this matter, please contact me at (620) 364-4000 or Mr.

Tony Harris at (620) 364-4038.

Very truly yours, Otto L. Maynard OLM/rlr Enclosures (3) cc: J. N. Donohew (NRC), w/e D. N. Graves (NRC), w/e E. W. Merschoff (NRC), w/e Senior Resident Inspector (NRC), w/e P.O. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HC/VET

KansasElectric PowerCooperative,Inc.

April 24, 2002 Mr. Tom Robke Wolf Creek Nuclear Operating Corporation P.O. Box 411 Burlington, KS 66839

Dear Tom:

Pursuant your request to meet the requirements of 10 CFR 50.71(b) that WCNOC provide a copy of each Owner's annual report (including the certified financial statements) to the NRC upon issuance of the report, KEPCo is enclosing a copy of its 2001 audited financial statements.

I will be sure to send you multiple copies of our annual report when completed. Feel free to use this report to make as many copies as you need in the interim.

Sincerely yours, Sandy Abra ams Phone: 785.273.7010 Controller Fax: 785.271.4888 Enclosure (1) www.kepco.org PO. Box 4877 Topeka, KS 66604-0877 600 Corporate View Topeka, KS 66615 A Touchstone Energy' Cooperuive ____

Kansas Electric Power Cooperative, Inc.

Financial Statements As of December 31, 2001 and 2000 Together With Auditors' Report

Report of independent public accountants To the Board of Trustees of Kansas Electric Power Cooperative, Inc.:

We have audited the accompanying balance sheets of Kansas Electric Power Cooperative, Inc.,

("KEPCo") as of December 31, 2001 and 2000, and the related statements of revenues and expenses, cash flows, changes in patronage capital, and comprehensive income (loss) for the years then ended.

These financial statements are the responsibility of KEPCo's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As more fully described in Note 4 to the financial statements, certain depreciation and amortization methods have been used in the preparation of the financial statements which do not, in our opinion, conform to accounting principles generally accepted in the United States.

In our opinion, except for the effects on the financial statements of the matters referred to in the preceding paragraph, the financial statements referred to above present fairly, in all material respects, the financial position of KEPCo as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States.

In accordance with Government Auditing Standards, we have also issued a report dated March 1, 2002, on our consideration of KEPCo's internal control over financial reporting and our tests of its compliance with certain provisions of laws, regulations, contracts and grants.

Kansas City, Missouri, March 1, 2002

Kansas Electric Power Cooperative, Inc.

Balance sheets December 31, 2001 and 2000 ASSETS 2001 2000 UTILITY PLANT:

In-service $213,227,413 $206,641,790 (57,998,723) (51,414,777)

Less- Allowances for depreciation 155,228,690 155,227,013 708,646 5,637,156 Construction work in progress 4,266,872 3,869,202 Nuclear fuel, net of amortization 160,204,208 164,733,371 RESTRICTED ASSETS:

Investments in the National Rural Utilities 2,603,692 2,603,907 Cooperative Finance Corporation 4,135,743 4,126,194 Bond fund reserve 4,702,277 4,489,977 Decommissioning fund 49,425 47,380 Investments in associated organizations 11,491,137 11,267,458 CURRENT ASSETS:

5,655,642 3,203,938 Cash and cash equivalents 5,945,212 6,455,178 Member accounts receivable 2,686,336 2,198,483 Materials and supplies, at average cost 522,621 586,370 Other assets and prepaid expenses 14,809,811 12,443,969 OTHER LONG-TERM ASSETS:

Deferred charges Wolf Creek disallowed costs (less accumulated amortization 19,364,704 of $7,334,915 and $6,618,217 for 2001 and 2000, respectively) 18,648,006 569,847 Deferred Department of Energy decommissioning costs 498,626 2,284,905 Deferred incremental outage costs 547,820 Other deferred charges (less accumulated amortization of 1,756,143 1,935,881

$741,548 and $561,810 for 2001 and 2000, respectively) 3,933,310 4,333,057 Unamortized debt issue costs 946,216 Wolf Creek nuclear operating investments 88,543 7,282,976 Other investments 36,717,586 25,472,448

$211,977,604 $225,162,384 (continued)

Kansas Electric Power Cooperative, Inc.

Balance sheets December 31, 2001 and 2000 (continued)

PATRONAGE CAPITAL AND LIABILITIES 2001 2000 PATRONAGE CAPITAL:

Memberships $ 3,100 $ 3,100 11,801,741 11,801,741 Patronage capital (payment restricted as indicated)

Unallocated margin (loss) (5,076,532) (651,747) 6,728,309 11,153,094 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Unrealized loss in market value of investments (236,052)

LONG-TERM DEBT:

Federal Financing Bank 102,749,728 107,421,981 52,690,000 54,090,000 Grantor Trust Series 1997 34,300,000 35,500,000 Pollution control revenue bonds 189,739,728 197,011,981 (6,564,153) (7,232,441)

Less- Current maturities of long-term debt 183,175,575 189,779,540 OTHER LONG-TERM LIABILITIES:

433,588 506,531 Deferred Department of Energy decommissioning costs 4,702,277 4,489,977 Wolf Creek decommissioning liability Wolf Creek nuclear operating liabilities 1,803,952 1,865,085 237,423 73,978 Arbitrage rebate long-term liability 7,177,240 6,935,571 CURRENT LIABILITIES:

6,564,153 7,232,441 Current maturities of long-term debt 798,087 Arbitrage rebate short-term liability 6,473,224 5,767,078 Accounts payable 225,458 217,312 Payroll and payroll-related liabilities 1,197,338 1,082,786 Accrued property taxes 436,307 2,432,527 Accrued interest payable Patronage capital distributions payable 14,896,480 17,530,231

$211,977,604 $225,162,384 The accompanying notes are an integral part of these balance sheets.

Kansas Electric Power Cooperative, Inc.

Statements of revenues and expenses For the years ended December 31, 2001 and 2000 2001 2000 OPERATING REVENUES:

Sales of electric energy $ 75,957,574 $ 75,651,145 221,070 321,423 Other 76,178,644 75,972,568 OPERATING EXPENSES: 41,720,138 41,812,744 Power purchased 2,780,385 2,430,196 Nuclear fuel 7,339,822 6,757,328 Plant operations 2,427,964 2,554,585 Plant maintenance 3,963,281 5,036,211 Administrative and general 847,717 896,436 Amortization of deferred charges 6,137,977 7,112,466 Depreciation and decommissioning 64,284,601 67,532,649 8,645,995 11,687,967 Net operating revenues INTEREST AND OTHER DEDUCTIONS: 13,236,970 12,564,197 Interest on long-term debt 411,024 399,746 Amortization of debt issue costs 62,668 56,006 Other interest expense 13,710,662 13,019,949 (4,373,954) (2,022,695)

Net operating loss OTHER INCOME AND EXPENSE: 1,372,777 930,647 Interest income (946,216)

Wolf Creek nuclear operating investment loss (1,829)

(35,262)

Other income (expense) 1,370,948 (50,831)

$ (4,424,78§1 $ (651,747)

Net margin (deficit)

The accompanying notes are an integral part of these financial statements.

Kansas Electric Power Cooperative, Inc.

Statements of cash flows For the years ended December 31, 2001 and 2000 2001 2000 CASH FLOWS FROM OPERATING ACTIVITIES:

Net margin (deficit) $ (4,424,785) $ (651,747)

Adjustments to reconcile net margin (deficit) to net cash provided by operations Depreciation and amortization 6,773,126 5,803,654 Amortization of nuclear fuel 2,197,183 1,838,316 Amortization of deferred charges 896,436 910,554 Amortization of deferred incremental outage costs 1,827,924 1,451,681 Wolf Creek nuclear operating investment loss 946,216 442,715 Increase in decommissioning liability 212,300 Increase in arbitrage rebate payable 163,445 164,785 Payment of arbitrage rebate payable (798,087)

Payment to Department of Energy for decommissioning (72,943) (64,927)

Changes in assets and liabilities Member accounts receivable 509,966 (735,035)

Materials and supplies inventory (487,853) (3,000)

Other assets and prepaid expenses 63,749 31,658 Accounts payable 706,146 321,023 Payroll and payroll-related liabilities 8,146 14,675 Accrued property taxes 114,552 (73,160)

Accrued interest payable (1,996,220) 1,663,702 (61,133) 185,197 Other long-term liabilities Net cash provided by operating activities 6,578,168 11,300,091 CASH FLOWS FROM INVESTING ACTIVITIES:

Additions to electric plant, net (1,846,293) (6,950,929)

Additions to nuclear fuel (2,523,632) (2,251,251)

Additions to deferred refueling costs (90,839) (2,741,886)

Increase in cash surrender value of life insurance contracts (304,836) (115,426)

Increase in decommissioning fund assets (212,300) (442,715)

Decrease (increase) in other investments (40,044) 667,392 Sales of other investments, net 7,459,150 782,688 Net cash provided (used) in investing activities 2,441,206 (11,052,127)

CASH FLOWS FROM FINANCING ACTIVITIES:

Borrowings from cash surrender value of life insurance contracts 304,836 2,484,967 Repayment of long-term debt (7,272,253) (4,833,290)

Amortization of debt issue costs 399,747 411,024 Net cash used in financing activities (6,567,670) (1,937,299)

Net increase (decrease) in cash and cash equivalents 2,451,704 (1,689,335)

CASH AND CASH EQUIVALENTS AT:

Beginning of year 3,203,938 4,893,273 End of year $ 5,655,642 $ 3,203,938 The accompanying notes are an integral part of these financial statements.

Kansas Electric Power Cooperative, Inc.

Statements of changes in patronage capital For the years ended December 31. 2001 and 2000 Patronage Unallocated Memberships Capital Margin (Loss) Total BALANCE, December 31, 1999 $ 3,100 $11,801,741 $ - $11,804,841 Net deficit - - (651,747) (651,747)

Patronage capital distributions BALANCE, December 31, 2000 3,100 11,801,741 (651,747) 11,153,094 Net deficit - (4,424,785) (4,424,785)

Patronage capital distributions BALANCE, December 31, 2001 $ 3,100 $ 11,801,741 $ (5,076,532) $ 6,728,309 Kansas Electric Power Cooperative, Inc.

Statements of comprehensive income (loss)

For the years ended December 31, 2001 and 2000 2001 2000

$ (4.424,785) $ (651.747)

NET MARGIN (DEFICIT)

OTHER COMPREHENSIVE INCOME:

Available-for-sale securities Unrealized holding gains and losses arising during the year, net 236,052 587,798 of reclass for gains and losses included in net income

$ (4,188,733) $ (63,949)

COMPREHENSIVE INCOME (LOSS)

The accompanying notes are an integral part of these financial statements.

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000

1. Nature of operations Kansas Electric Power Cooperative, Inc. (KEPCo), headquartered in Topeka, Kansas, was incorporated in 1975 as a not-for-profit generation and transmission cooperative (G&T). It is KEPCo's responsibility to procure an adequate and reliable power supply for its 21 distribution rural electric cooperative members pursuant to all requirements of its power supply contracts. KEPCo is governed by a board of trustees representing each of its 21 members, which collectively serves more than 100,000 electric customers in rural Kansas. On January 1, 2002, three cooperative members merged and reduced the total cooperative membership to 21.

KEPCo is under the jurisdiction of the Kansas Corporation Commission (KCC) and was granted a limited certificate of convenience and authority in 1980 to act as a G&T public utility.

2. Summary of significant accounting policies Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

System of accounts KEPCo maintains its accounting records substantially in accordance with the Rural Utilities Service (RUS) Uniform System of Accounts and in accordance with accounting practices prescribed by the KCC.

Utility plant and depreciation Utility plant is stated at cost. The cost of repairs and minor replacements are charged to operating expenses as appropriate. Costs of renewals and betterments are capitalized. The original cost of utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation.

Through January 31, 1987, the provision for depreciation for electric plant in-service was computed on the straight-line method at a 3.44 percent annual composite rate. Effective February 1, 1987, in accordance with an order issued by the KCC, the provision for depreciation is computed on a present-worth (sinking fund) method, which provides for increasing annual provisions over 27.736 years. Pursuant to a KCC rate order dated December 30, 1998, the depreciable life was extended to reflect a full 30 year plant life. The composite rates for the years ended December 31, 2001 and 2000, were 3.18 percent and 2.81 percent, respectively.

Pursuant to a KCC rate order dated March 27, 1992, all additions, betterments and improvements after January 1, 1992, are depreciated over the remaining life of the utility plant on a straight-line basis.

I

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 The provision for depreciation computed on a straight-line basis for electric and other components of a utility plant is as follows:

Transportation and equipment 25 to 33 percent Office furniture and fixtures 10 to 20 percent Leasehold improvements 20 percent Transmission equipment 10 percent Nuclear fuel The cost of nuclear fuel in process of refinement, conversion, enrichment and fabrication is recorded as utility plant asset at original cost and is amortized to nuclear fuel expenses based upon the quantity of heat produced for the generation of electric power. The permanent disposal of spent fuel is the responsibility of the Department of Energy (DOE). KEPCo pays one cent per net MWh of nuclear generation to the DOE for the future disposal service. These disposal costs are charged to nuclear fuel expense.

Cash and cash equivalents All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents and are stated at cost, which approximates market value.

Short-term and other investments Investments in debt securities are classified as available-for-sale in accordance with Statement of Financial Accounting Standards (SFAS) No.

115, "Accounting for Certain Investments in Debt and Equity Securities,"

based on KEPCo's intended use of such securities. Investments in debt securities are carried at fair value based on quoted market prices for those or similar securities, with the unrealized gain/loss included as a separate component of capitalization. In the balance sheet, investments in debt securities with an original maturity greater than three months and a remaining maturity less than one year are presented as current assets, and investments with a remaining maturity greater than one year are presented as long-term investments.

Materials and supplies inventory Materials and supplies inventory are stated at cost determined by the average cost method.

Unamortized debt issue costs Unamortized debt issue costs relate to the issuance of the floating/fixed rate pollution control revenue bonds, mortgage notes payable to the National Rural Utilities Cooperative Finance Corporation (CFC) trusts and fees for repricing the Federal Financing Bank (FFB) debt. These costs are being amortized using the effective interest method over the remaining life of the bonds.

2

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 Decommissioning fund assets/decommissioning liability As of December 31, 2001 and 2000, $4,702,277 and $4,489,977, respectively, have been collected and are being retained in an interest bearing trust fund to be used for the physical decommissioning of Wolf Creek. The trustee invests the decommissioning funds primarily in mutual funds, which are carried at estimated fair market value. During 1989, the KCC extended the estimated useful life of Wolf Creek to 40 years from the original estimates of 30 years only for the determination of decommissioning costs to be recognized for ratemaking purposes. In the year ended December 31, 2000, the KCC approved a 1999 Wolf Creek decommissioning cost study, which increased the estimate of total decommissioning costs to $467 million in 1999 dollars ($28 million KEPCo's share). KEPCo is providing for overall nuclear decommissioning costs using a funding method, which assumes a 3.6 percent rate of inflation and 5.4 percent real rate of return. KEPCo's current provision for decommissioning, based on the 1999 decommissioning study, is being charged to operations over the life of the plant. Such provision totaled

$339,340 and $334,325 for 2001 and 2000, respectively.

On June 30, 2001 the Financial Accounting Standards Board issued its SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No.

143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and the normal operation of long-lived assets. This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This statement is effective for financial statements issued for fiscal years beginning after June 15, 2002.

The Company anticipates adopting SFAS No. 143 on January 1, 2003.

The Company has not determined the impact, if any, that the adoption of this new standard will have on its financial statements.

Cash surrender value of life insurance contracts The following amounts related to Wolf Creek Nuclear Operating Corporation (WCNOC) corporate-owned life insurance contracts, primarily with one highly rated major insurance company, are included in Wolf Creek nuclear operating investments on the balance sheets.

2001 2000 Cash surrender value of contracts $3,332,247 $3,027,411 Borrowings against contracts (3,332,247) (3,027,411)

Net $ - $ -

3

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 Borrowings against contracts include a prepaid interest charge. KEPCo pays interest on these borrowings at a discounted rate of 7.4 percent.

Income taxes As a tax-exempt cooperative, KEPCo is exempt from income taxes under Section 501 (c)(12) of the Internal Revenue Code of 1986, as amended.

Accordingly, provisions for income taxes have not been reflected in the accompanying financial statements.

Rates The KCC has the authority to establish KEPCo's electric rates under state law in Kansas. Rates are established to meet the times-interest-earned ratio and debt-service coverage set forth by the RUS. On June 29, 2001, KEPCo filed an application with KCC requesting a rate increase of approximately $6.5 million, a new rate design and the re-establishment of an energy cost adjustment (ECA) mechanism, which allows KEPCo to pass along increases in certain energy costs to its cooperative members.

On January 17, 2002, the KCC ordered a rate increase of approximately

$6.5 million, including an ECA mechanism, to be effective in rates February 1, 2002. Pursuant to this KCC rate order, the depreciable life of utility generation plant was extended from 40 years to 60 years. In addition, the rate order allowed KEPCo recovery of the $53,454,512 cumulative difference between historical present worth (sinking fund) depreciation and straight-line depreciation (Note 4) over a 15-year period.

Costs associated with the rate case were expensed in the year ended December 31, 2001.

Revenues Revenues from the sale of electricity are recorded based on usage by member cooperatives and customers, and on contracts and scheduled power usages, as appropriate.

Long-lived assets Management reviews long-lived assets for impairment whenever events or changes in circumstances indicating the carrying amount of an asset may not be recoverable. In the event a long-lived asset was determined to be impaired, such asset would be required to be written down to its fair value, with the loss recognized in the statement of revenues and expenses.

Reclassifications KEPCo has reclassified the presentation of certain prior year information to conform with the current year presentation.

4

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000

3. Factors that could affect future operatinci results KEPCo currently applies accounting standards that recognize the economic effects of rate regulation pursuant to SFAS No. 71, "Accounting for the Effect of Certain Types of Regulation," and accordingly, has recorded regulatory assets and liabilities related to its generation, transmission and distribution operations. In the event KEPCo determines that it no longer meets the criteria of SFAS No. 71, the accounting impact could be a noncash charge to operations of an amount that would be material. Criteria that could give rise to the discontinuance of SFAS No. 71 include: (1) increasing competition that restricts KEPCo's ability to establish prices to recover specific costs, and (2) a significant change in the manner rates are set by regulators from a cost-based regulation to another form of regulation. KEPCo periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Any changes that would require KEPCo to discontinue the application of SFAS No. 71 due to increased competition, regulatory changes or other events may significantly impact the valuation of KEPCo's investment in utility plant, its investment in Wolf Creek and necessitate the write-off of regulatory assets. At this time, the effect of competition and the amount of regulatory assets, which could be recovered in such an environment, cannot be predicted.

The 1992 Energy Policy Act began the process of restructuring the United States electric utility industry by permitting the Federal Energy Regulatory Commission to order electric utilities to allow third parties to sell electric power to wholesale customers over their transmission systems. Many states are currently moving toward opening the retail segment to competition. Recent sessions of the Kansas Legislature (1999-2002) did not and have not taken action on industry restructuring. Management will continue to monitor deregulation initiatives, but does not presently expect any actions, which would be unfavorable to KEPCo to be adopted within the next 12 months.

4. Departures from generally accepted accounting principles Effective February 1, 1987, the KCC issued an order to KEPCo requiring the use of present worth (sinking fund) depreciation and amortization. As more fully described in Notes 5 and 9, such depreciation and amortization practices constitute phase-in plans which do not meet the requirements of SFAS No. 92, "Accounting for Phase-In Plans." The effect of these departures is to overstate the following items in the financial statements by the following amounts:

2001 2000 Net utility plant $46,948,793 $45,680,276 Deferred charges 6,505,719 6,338,441 Patronage capital 53,454,512 52,018,717 Net margin 1,435,794 1,904,018 5

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000

5. Wolf Creek Nuclear Generating Station KEPCo owns 6 percent of Wolf Creek, which is located near Burlington, Kansas. The remainder is owned by the Kansas City Power & Light Company (KCPL- 47 percent) and Kansas Gas & Electric Company (KGE - 47 percent). KGE is a wholly owned subsidiary of Western Resources, Inc. KEPCo's undivided interest in Wolf Creek is consolidated on a pro rata basis. Substantially all of KEPCo's utility plant consists of its pro rata share of Wolf Creek. KEPCo is entitled to a proportionate share of the capacity and energy from Wolf Creek, which is used to supply a portion of KEPCo's members' requirements. KEPCo is billed for 6 percent of the operations, maintenance, administrative and general costs, and cost of plant additions related to Wolf Creek.

The KCC declared Wolf Creek commercially operable on September 3, 1985. KEPCo's total investment includes interest and administrative costs during construction.

Effective February 1, 1987, the KCC issued an order to KEPCo to utilize a present worth (sinking fund) depreciation method that does not conform with accounting principles generally accepted in the United States and which constitutes a phase-in plan that does not meet the requirements of SFAS No. 92. If depreciation on electric plant-in-service was calculated using a method in accordance with accounting principles generally accepted in the United States, depreciation expense would be increased and KEPCo's operating margin would be decreased by $1,268,516 and

$1,684,039 for the years ended December 31, 2001 and 2000, respectively. In addition, net utility plant would be decreased and patronage capital would be decreased by $46,948,793 and $45,680,276 as of December 31, 2001 and 2000, respectively. The rate order issued by KCC on January 17, 2002, allowed KEPCo recovery of the $46,948,793 difference between historical present worth (sinking fund) depreciation and straight-line depreciation over a 15-year period.

The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Compact) and selected a site in Nebraska to locate a disposal facility. The Compact Commission selected US Ecology as the license applicant and developer of the site. The generators of waste (nuclear facilities) in those states provided funds for the evaluation of the suitability of the site. KEPCo's portion of the investment for the evaluation of the site on December 31, 2001 was approximately $946,216.

On December 1998, the Nebraska agencies responsible for considering the developer's license application denied the application. Most of the utilities (generators) that had provided the project's pre-construction financing (including WCNOC), along with the Commission and US Ecology filed a federal lawsuit contending Nebraska officials acted in bad faith while handling the license application.

6

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 In May of 1999, the Nebraska legislature passed a law withdrawing Nebraska from the Compact. The withdrawal is not effective for five years.

On August 29, 2001, the Federal District Court ruled that, due to administrative discretion granted to state administrative agencies, the generators cannot claim a property interest against the State in the money spent in an attempt to obtain the license. The Court of Appeals had previously ruled that the generators had no right to sue the State of Nebraska for breach of the Compact's good faith obligation. It is noted, however, that the Commission is pursuing its case against Nebraska for breach of the Compact's good faith obligation and that the generators (including WCNOC) are pursuing a cross-claim to recover their expenditures from the Commission.

In view of those rulings, KEPCo has recognized as a nonoperating expense in 2001 its investment in the Nebraska site.

Even though the Commission has maintained its case against Nebraska, based on the above mentioned rulings, KEPCo no longer believes that it is probable that its investment in the Nebraska site will be recovered.

Accordingly, the loss of the investment has been recognized as a non operating expense in 2001.

Wolf Creek disposes of all classes of its low-level radioactive waste at existing third-party repositories. Should disposal capability become unavailable, Wolf Creek is able to store its low-level radioactive waste in an on-site facility for up to five years under current regulations.

6. Other investments Other investments consist of the following as of December 31:

2001 2000 Fair Fair Cost Value Cost Value Available-for-sale Split-dollar life insurance policy $ 88,543 $ 88,543 $ 59,028 $ 59,028 U.S. government agency securities - - 7,460,000 7,223,948 Included in the capitalization were $0 and $236,052 of unrealized losses on available-for-sale equity securities as of December 31, 2001 and 2000, respectively. KEPCo liquidated all available-for-sale U.S. government agency securities during year ended December 31, 2001.

7. Bond fund reserve KEPCo has entered into a bond covenant whereby KEPCo is required to maintain, with a trustee, a bond fund reserve of approximately $4 million.

This stipulated amount is sufficient to satisfy certain future interest and principal obligations. The amount held in the bond fund reserve is invested 7

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 by the trustee in tax-exempt municipal securities, pursuant to the restrictions of the indenture agreement, which are carried at amortized cost.

8. Investments in associated organizations Investments in associated organizations are carried at cost. At December 31, 2001 and 2000, investments in associated organizations including CFC consisted of the following:

2001 2000 CFC Membership $ 1,000 $ 1,000 Capital term certificates 395,970 395,970 Subordinated term certificates 2,205,000 2,205,000 Patronage capital certificates 1,722 1,937 Other 49,425 47,380 2.5317 $2.51287

9. Deferred charges Disallowed costs Effective October 1, 1985, the KCC issued a rate order relating to KEPCo's investment in Wolf Creek, which disallowed $25,982,921 of KEPCo's investment in Wolf Creek ($18,648,006 net of accumulated amortization as of December 31, 2001). A subsequent rate order, effective February 1, 1987, allows KEPCo to recover these disallowed costs and other costs related to the disallowed portion (recorded as deferred charges) for the period from September 3, 1985, through January 31, 1987, over a 27.736 year period starting February 1, 1987. Pursuant to a KCC rate order dated December 30, 1998, the disallowed portions recovery period was extended to a 30-year period. KEPCo is using present worth (sinking fund) amortization to recover the disallowed costs which enables it to meet the times-interest-earned ratio and debt service requirements in the KCC rate order dated January 30, 1987. The method used by KEPCo constitutes a phase-in plan, which does not meet the requirements of SFAS No. 92. If amortization to recover the disallowed costs was calculated using a method in accordance with accounting principles generally accepted in the United States, amortization of deferred charges would be increased and KEPCo's operating margin would be decreased by $167,278 and $219,979 for the years ended December 31, 2001 and 2000, respectively. In addition, deferred charges would be decreased and patronage capital would be decreased by $6,505,719 and $6,338,441 as of December 31, 2001 and 2000, respectively. The rate order issued by KCC on January 17, 2002, allowed KEPCo recovery of the $6,505,719 difference between historical present worth (sinking fund) depreciation and straight-line depreciation over a 15-year period.

Decommissioning and decontamination assessments The Energy Policy Act of 1992 established a fund to pay for the decommissioning and decontamination of nuclear enrichment facilities 8

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 operated by the DOE. A portion of this fund not to exceed $2.25 billion is to be collected from utilities that have purchased enrichment services from the DOE. This portion is limited to no more than $150 million each year and will be in the form of annual assessments that will not be imposed for more than 15 years. KEPCo has recorded its portion of this liability, which is being paid over 15 years. KEPCo has recorded a related deferred asset of $498,626 and $569,847 as of December 31, 2001 and 2000, respectively, and is being amortized to nuclear fuel expense over the 15 year assessment period.

Deferred incremental outage costs In 1991 the KCC issued an order that allowed KEPCo to defer its 6 percent share of the incremental operating, maintenance and replacement power costs associated with the periodic refueling of Wolf Creek. Such costs are deferred during each refueling outage and are being amortized over the approximate 18-month operating cycle coincident with the recognition of the related revenues.

Other deferred charges KEPCo includes in other deferred charges the early call premium resulting from refinancing the 1988 CFC Grantor Trust Certificates prior to maturity.

This early call premium is amortized using the interest method over the remaining life of the new Grantor Trust Series 1997 certificates.

10. Lon-g-term debt Long-term debt consists of mortgage notes payable to the United States of America acting through the FFB, the CFC and others. Substantially, all of KEPCo's assets are pledged as collateral. The terms of the notes as of December 31 are as follows:

2001 2000 Mortgage notes payable to the FFB at fixed rates varying from 5.501% to 9.206%, payable in quarterly installments through 2018. $102,749,728 $107,421,981 Mortgage notes payable to the Grantor Trust Series 1997 at a rate of 7.522%, payable semiannually, principal payments commenced in 1999 and continuing annually through 2017. 52,690,000 54,090,000 Floating/fixed rate pollution control revenue bonds, City of Burlington, Kansas, Pooled Series 1985C, variable interest rate (ranging from 1.35% to 2.35% at December 31, 2001) payable annually through 2015. 34,300,000 35,500,000 189,739,728 197,011,981 Less- Current portion 6,564,153 7,232,441

$183.175.575 9

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 Aggregate maturities of mortgage notes payable to FFB, Grantor Trust Series 1997 and floating/fixed rate pollution control revenue bonds as of December 31, 2001, are as follows:

Year Amount 2002 $ 6,564,153 2003 7,398,922 2004 8,104,382 2005 8,631,637 2006 9,382,707 Thereafter 149,657,927 Restrictive covenants require KEPCo to design rates that would enable it to maintain a times-interest-earned ratio of at least one-to-one and debt service coverage of at least one-to-one, on average, in at least two out of every three years. The covenants also prohibit distributions of net patronage capital or margins until, after giving effect to any such distribution, total patronage capital equals or exceeds 20 percent of total assets unless such distribution is approved by RUS (Note 16).

In 1997, KEPCo refinanced its mortgage notes payable to the 1988 CFC Grantor Trust through the establishment of a new CFC Grantor Trust Series 1997 (the Series 1997 Trust) by CFC. This refinancing reduced the guaranteed interest rate payable on the mortgage notes to a fixed rate of 7.522 percent through the use of an interest rate swap with JP Morgan Chase Bank (counterparty) that was assigned by KEPCo to the Series 1997 Trust. The mortgage notes payable are pre-payable at any time with no prepayment penalties. However, any termination costs relating to the termination of the assigned interest rate swap, is KEPCo's responsibility.

At December 31, 2001, the termination obligation associated with the assigned swap agreement to early retire the mortgage notes payable is approximately $7.3 million. This fair value estimate is based on information available at December 31, 2001, and is expected to fluctuate in the future based on changes in interest rates and outstanding principal balance.

KEPCo is also exposed to possible credit loss in the event of noncompliance by Morgan to the Swap Agreement. However, KEPCo does not anticipate nonperformance by Morgan.

11. Short-term borrowings As of December 31, 2001, KEPCo had a $10 million unused line of credit outstanding with the CFC. In February 2002, CFC increased the available borrowings from $10 million to $15 million. This line of credit has a term of 12 months. There were no outstanding borrowings at either December 31, 2001, or December 31, 2000.

10

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000

12. Operating lease KEPCo leases office space and equipment under noncancelable operating leases. Future minimum lease payments at December 31, 2001, are as follows:

Year Amount 2002 $19,920 2003 9,472 2004 7,959 2005 3,979 The related rental expenses for 2001 and 2000 were $12,791 and $57,007, respectively.

13. Benefit plans National Rural Electric Cooperative Association (NRECA) Retirement and Security Program KEPCo participates in the NRECA Retirement and Security Program for its employees. All employees are eligible to participate in this program. In the master multiemployer plan, which is available to all members of NRECA, the accumulated benefits and plan assets are not determined or allocated by individual employees. KEPCo's pension expense, under this program, was $171,088 and $148,153 for the years ended December 31, 2001 and 2000, respectively.

NRECA Savings 401(k) Plan Substantially all employees of KEPCo also participate in the NRECA Savings 401(k) Plan. Under the plan, KEPCo contributes an amount not to exceed 5 percent, dependent upon the employee's level of participation, of the respective employee's base pay to provide additional retirement benefits. KEPCo contributed $75,562 and $70,509 to the plan in 2001 and 2000, respectively.

Wolf Creek Nuclear Operating Corporation (WCNOC) retirement plan KEPCo has an obligation to the WCNOC retirement plan for its 6 percent ownership interest in Wolf Creek. This plan provides for benefits upon retirement, normally at age 65. In accordance with the Employee Retirement Income Security Act of 1974, KEPCo has satisfied its minimum funding requirements. Benefits under this plan reflect the employee's compensation, years of service and age at retirement.

Disclosure for pensions is determined under the rules prescribed by SFAS No. 132. The following sets forth KEPCo's share of the plan's charges in benefit obligation, plan assets and funded status as of December 31:

11

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 2001 2000 Changes in benefit obligation Benefit obligation at beginning of year $3,285,875 $2,984,941 Service cost 205,725 202,033 Interest cost 268,067 253,118 Actuarial loss 486,381 109,608 Benefits paid (66,344) (87,414)

Benefit obligation at end of year Plan assets are invested in insurance contracts, corporate bonds, equity securities, United States government securities and short-term investments.

2001 2000 Changes in plan assets Fair value of plan assets at beginning of year $3,081,209 $2,950,410 Actual return on plan assets (160,539) 61,296 Contributions during the year 129,789 156,917 Benefits paid (66,345) (87,414)

Fair value of plan assets at end of year S2_984JI14 Funded status $(1,195,590) $(379,997)

Unrecognized net transition obligation 139,182 (675,851)

Unrecognized prior service cost 72,576 32,682 Unrecognized net gain 34,591 79,833 Accrued benefit cost Actuarial assumptions Discount rate 7.25% 7.75%

Annual salary increase rate 4.80% 5.00%

Long-term rate of return 9.25% 9.25%

KEPCo's share of the net periodic pension costs were as follows for the years ended December 31:

2001 2000 Service cost $205,725 $202,033 Interest cost on projected benefit obligation 268,067 253,118 Expected return on plan assets (289,044) (257,234)

Other (49,052) (34,830)

Total pension expense =15.69e $16308 KEPCo has an obligation to the WCNOC supplemental retirement plan for executives for its 6 percent ownership interest in Wolf Creek. This plan provides for benefits to Wolf Creek executives upon retirement. KEPCo expensed its 6 percent ownership share of $16,481 and $23,130 in 2001 and 2000, respectively, related to this plan.

12

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000

14. Commitments and contingencies Litigation There is a provision in the Wolf Creek operating agreement whereby the owners treat certain claims and losses arising out of the operation of Wolf Creek as a cost to be born by the owners separately (but not jointly) in proportion to their ownership shares. Each of the owners has agreed to indemnify the others in such cases.

As is the case with other electric utilities, KEPCo, from time-to-time, is subject to various actions, which occasionally include punitive damage claims. KEPCo maintains insurance providing liability coverage; however, the insurance companies generally reserve the right to challenge insurance coverage for punitive damage recoveries. As of December 31, 2001, it is the opinion of the general counsel of KEPCo that there is not a significant probability that, as a result of pending or threatened personal injury actions, KEPCo will be liable for payment of actual or punitive damages in an amount material to the financial position of KEPCo.

Nuclear liability and insurance The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.5 billion for a single nuclear incident. If this liability limitation is insufficient, the United States Congress will consider taking whatever action is necessary to compensate the public for valid claims. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million. The remaining balance is provided by an assessment plan mandated by the Nuclear Regulatory Commission (NRC). Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $88.1 million ($5.3 million KEPCo's share) in the event there is a major nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million ($600,000 - KEPCo's share) in retrospective assessments per incident per year.

The Owners carry decontamination liability, premature decommissioning liability and property damage insurance to the Wolf Creek facilities in the amount of $2.8 billion ($168 million - KEPCo's share). This insurance is provided by Nuclear Electric Insurance Limited (NEIL). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC.

KEPCo's share of any remaining proceeds can be used to pay for property damage or decontamination expenses or, if certain requirements are met including decommissioning the plant, toward a shortfall in the decommissioning trust fund.

The Owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves and other NEIL resources, KEPCo may be 13

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000 subject to retrospective assessments under the current policies of approximately $1,366,000 per year.

Although KEPCo maintains various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, KEPCo's insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, could have a materially adverse effect on KEPCo's financial position and results of operations.

Decommissioning insurances KEPCo carries premature decommissioning insurance, which has several restrictions. One of which can only be used if Wolf Creek incurs an accident exceeding $500 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor station site in accordance with a plan approved by the NRC, and to pay for on-site property damages. Once the NRC Property Rule, requiring insurance proceeds to first be used for stabilization and decontamination, has been complied with, the premature decommissioning coverage could pay for the decommissioning fund shortfall in the event an accident at Wolf Creek exceeds $500 million in covered damages and causes Wolf Creek to be prematurely decommissioned.

Nuclear fuel commitments At December 31, 2001, KEPCo's share of Wolf Creek's nuclear fuel commitments were approximately $0.5 million for uranium concentrates and conversion expiring at various times through 2003, $2.9 million for enrichment expiring at various times through 2006 and $7.3 million for fabrication through 2025.

Purchase power commitments KEPCo has purchase power contracts with various utility companies to purchase power when member requirements exceed generation in given service areas. A significant purchase power contract expires in 2003. This contract provided for 34 percent of KEPCo's capacity and 27 percent of KEPCo's purchased power requirements. Currently, KEPCo has replaced approximately one-third of the requirements provided under this expiring contract and is currently reviewing options to replace the remaining requirements.

Generation construction commitments On November 12, 2001, KEPCo entered into an agreement with Martin Tractor Company, Inc., to mutually develop an electricity power generating plant to be completed in 2002 and operated by KEPCo. Current commitment by KEPCo under this agreement is $5.0 million in construction funds.

14

Kansas Electric Power Cooperative, Inc.

Notes to financial statements December 31, 2001 and 2000

15. Fair value of financial instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in SFAS No. 107:

Cash and cash equivalents-The carrying amount approximates the fair value because of the short-term maturity of these investments.

Otherinvestments, decommissioning trust, investments in associated organizationsand bond fund reserve--The fair value of these assets is primarily based on quoted market prices as of December 31, 2001.

Variable-ratedebt-The carrying amount approximates the fair value because of the short-term variable rates of those debt instruments.

Fixed-ratedebt-The fair value of the fixed-rate FFB debt and the fixed rate Series 1997 Trust debt is based on the sum of the estimated value of each issue, taking into consideration the current rates offered to KEPCo for debt of similar remaining maturities.

The estimated fair values of KEPCo's financial instruments are as follows:

December 31, 2001 Carrying Fair Value Value Cash and cash equivalents $ 5,655,642 $ 5,655,642 Investments in associated organizations (including investments in NRUCFC) 2,653,117 2,653,117 Bond fund reserve 4,135,743 4,086,091 Decommissioning trust 4,702,277 4,702,277 Fixed-rate debt 155,439,728 172,711,041 Variable-rate debt 34,300,000 34,300,000

16. Patronage capdital In accordance with KEPCo's by-laws, KEPCo's current margins are to be allocated to members. KEPCo's current policy is to allocate margins to the members based on revenues collected from the members as a percentage of total revenues. If KEPCo's financial statements were adjusted to eliminate the accounting principles generally accepted in the United States, total patronage capital would be negative. As noted in the statements of changes in patronage capital, no patronage capital distributions were made to members in 2001 and 2000.

15

UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31. 2001 OR

[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _ to Commission File Number 1-3523 Western Resources, Inc.

(Exact name of registrant as specified in its charter)

Kansas 48-0290150 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification Number) 818 South Kansas Avenue Topeka, Kansas 66612 (785) 575-6300 (Address, including zip code and telephone number, including area code, of registrant's principal executive offices)

Securities registered pursuant to section 12(b) of the Act:

Title of Each Class Name of each exchange on which registered Common Stock, par value $5.00 per share New York Stock Exchange Securities registered pursuant to section 12(g) of the Act:

Preferred Stock. 4-1/2% Series, $100 par value (Title of Class)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No __

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (x)

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately

$1,239,059,619 at March 14, 2002.

Indicate the number of shares outstanding of each of the registran'ts classes of common stock, as of the latest practicable date.

Class Outstanding at March 14, 2002 Common Stock, par value $5.00 per share 71,415,540 Shares

Documents Incorporated by

Reference:

Part Document III The registrant's definitive proxy statement for the Annual Meeting of Shareholders to be held June 11, 2002.

2

TABLE OF CONTENTS PART I Item 1. Business ........................................................................................................................ 5 Item 2. Properties ...................................................................................................................... 25 Item 3. Legal Proceedings ....................................................................................................... 27 Item 4. Submission of Matters to a Vote of Security Holders ................................................. 27 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ................ 28 Item 6. Selected Financial Data ............................................................................................... 29 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ................................................................................................................ 30 Item 7A. Quantitative and Qualitative Disclosures About Market Risk ....................................... 60 Item 8. Financial Statements and Supplementary Data ........................................................ ..... 61 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial D isclosure ................................................................................................................ III PART III Item 10. Directors and Executive Officers of the Registrant ....................................................... 112 Item 11. Executive Compensation ............................................................................................... 114 Item 12. Security Ownership of Certain Beneficial Owners and Management ............................ 114 Item 13. Certain Relationships and Related Transactions ........................................................... 114 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ............................. 115 Signatures ...................................................................................................................................... 120 3

FORWARD-LOOKING STATEMENTS Certain matters discussed in this Annual Report on Form 10-K are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe," "anticipate," "expect," "plan," "will,"

"may," "could," "estimate," "intend" or words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning:

- capital expenditures,

- earnings,

- liquidity and capital resources,

- litigation,

- possible corporate restructurings, mergers, acquisitions and dispositions,

- compliance with debt and other restrictive covenants,

- interest and dividends,

- Protection One, Inc.'s financial condition and its impact on our consolidated results,

- impairment charges that will be expensed during 2002,

- environmental matters,

- nuclear operations,

- ability to enter new markets successfully and capitalize on growth opportunities in non-regulated businesses,

- events in foreign markets in which investments have been made and

- the overall economy of our service area.

What happens in each case could vary materially from what we expect because of such things as:

- electric utility deregulation,

- ongoing municipal, state and federal activities, such as the Wichita municipalization effort,

- future economic conditions,

- changes in accounting requirements and other accounting matters,

- changing weather,

- rate and other regulatory matters, including the impact of the order to reduce our rates issued on July 25, 2001 by the Kansas Corporation Commission and the impact of the Kansas Corporation Commission's order issued July 20, 2001 and related proceedings, with respect to the proposed separation of Western Resources, Inc.'s electric utility businesses from Westar Industries, Inc.,

- the impact on our service territory of the September 11, 2001 terrorist attacks,

- the impact of Enron Corp.'s bankruptcy on the market for trading wholesale electricity,

- political, legislative and regulatory developments,

- amendments or revisions to our current business and financial plans,

- the consummation of the acquisition of the electric operations of Western Resources, Inc. by Public Service Company of New Mexico and related litigation,

- regulatory, legislative and judicial actions,

- regulated and competitive markets and

- other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all possible factors.

See "Item 1. Business - Risk Factors" for additional information on matters that could impact our expectations. Any forward-looking statement speaks only as of the date such statement was made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

4

PART I ITEM 1. BUSINESS GENERAL Western Resources, Inc. is a publicly traded consumer services company incorporated in 1924 in the State of Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to "the company," "Western Resources," "we," "us," "our" or similar words are to Western Resources, Inc. and its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 640,000 customers in Kansas and monitored security services to over 1.2 million customers in North America and Europe. ONEOK, Inc. (ONEOK), in which we have an approximate 45% ownership interest, provides natural gas transmission and distribution services to approximately 1.4 million customers in Oklahoma and Kansas. Our corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas 66612.

We and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary, provide rate regulated electric service using the name Westar Energy. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek).

Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary, owns our interests in Protection One, Inc. (Protection One), Protection One Europe, ONEOK, Inc. and other non-utility businesses. Protection One, a publicly traded, approximately 87%-owned subsidiary, and Protection One Europe provide monitored security services. Protection One Europe refers collectively to Protection One International, Inc., a wholly owned subsidiary of Westar Industries, and its subsidiaries, including a French subsidiary in which it owns approximately a 99.8%

interest.

SIGNIFICANT BUSINESS DEVELOPMENTS PNM Transaction On November 8, 2000, we entered into an agreement with Public Service Company of New Mexico (PNM),

pursuant to which PNM would acquire our electric utility businesses in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and we are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. Immediately prior to closing, all of the Westar Industries common stock we own would be distributed to our shareholders in exchange for a portion of their Western Resources common stock. At the same time we entered into the agreement with PNM, we and Westar Industries entered into an Asset Allocation and Separation Agreement which, among other things, provided for this split-off and related matters.

On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the Kansas Corporation Commission (KCC) orders discussed below and other KCC orders reducing rates for our electric utility business. PNM believes the orders constitute a material adverse effect and make the condition that the split-off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation.

On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court of the State of New York.

The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of our electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, we filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement.

On January 7, 2002, PNM sent a letter to us purporting to terminate the merger in accordance with the terms of the merger agreement. We have notified PNM that we believe the purported termination of the merger agreement 5

was ineffective and that PNM remains obligated to perform thereunder. We intend to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, we believe the closing of the proposed merger is not likely.

KCC Rate Cases On November 27, 2000, we and KGE filed applications with the KCC for an increase in retail rates. On July 25 and September 5, 2001, the KCC issued orders that reduced our combined electric rates by $15.7 million.

We appealed these orders to the Kansas Court of Appeals, but the KCC orders were upheld. We are evaluating whether to appeal the decision to the Kansas Supreme Court. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Summary of Significant Items - KCC Rate Cases" for further discussion.

KCC Proceedin2s and Orders The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of our electric utility businesses from our non-utility businesses, including the rights offering, and other aspects of our unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving our unregulated businesses are consistent with our obligation to provide efficient and sufficient electric service at just and reasonable rates to our electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement we entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by us to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by our unregulated businesses and whether they should continue to be affiliated with our electric utility business, and our present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying the Asset Allocation and Separation Agreement, prohibiting Westar Industries and us from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent.

On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting us and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed us and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in our capital structure applicable to our electric utility operations, which has the effect of prohibiting us from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed us to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of our non-utility businesses. In its order, the KCC also acknowledged that we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. We appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not final orders and that the District Court lacked jurisdiction to consider the appeal.

Accordingly, the matter was remanded to the KCC for review of the financial plan.

On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that we and the KCC staff make filings addressing whether the filing of applications by us and KGE at the Federal Energy Regulatory Commission (FERC), seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that we not increase the share of debt in our capital structure applicable to our electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC filed a motion to intervene in the proceeding at FERC asserting the same position. We are unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on our ability to refinance 6

indebtedness maturing in the next several years. Our inability to refinance existing indebtedness on a secured basis would likely increase our borrowing costs and adversely affect our results of operations.

The Financial Plan The July 20, 2001 KCC order directed us to present a financial plan to the KCC. We presented a financial plan to the KCC on November 6,2001, which we amended on January 29, 2002. The principal objective of the financial plan is to reduce our total debt as calculated by the KCC to approximately $1.8 billion, a reduction of approximately $1.2 billion. The financial plan contemplates that we will proceed with a rights offering and that, in the event that the PNM merger and related split-off do not close, we will use our best efforts to sell our share of Westar Industries common stock, or shares of our common stock, upon the occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to review the financial plan. We are unable to predict whether or not the KCC will approve the financial plan or what other action with respect to the financial plan the KCC may take.

The financial plan provides that:

- Westar Industries will use its best efforts to sell at least 4.14 million shares of its common stock, representing approximately 5.1% of its outstanding shares, but no more than the number of shares of its common stock (approximately 19.13 million shares) representing 19.9% of its outstanding shares.

After the offering, we would continue to own 77.0 million shares representing between 80.1% and 94.9% of Westar Industries' outstanding shares. The offering will remain open for no less than 45 calendar days.

- In the rights offering, each of our shareholders will receive the right to purchase one share of Westar Industries' common stock for every three shares of our stock held on the record date of the offering.

There will be no over-subscription privilege in the offering. However, each shareholder participating in the offering will be issued, with respect to each right exercised in the offering, a warrant to purchase from Westar Industries two shares of its common stock at the subscription price in the offering, subject to proration so that in no event will we hold less than 80.1% of Westar Industries' outstanding shares.

This right will be exercisable at any time in the 30-day period preceding January 31, 2003.

- So long as we and Westar Industries are tax consolidated, Westar Industries' common stock sold in the offering will have one vote per share and Westar Industries common stock held by us will have 10 votes per share. Any shares sold by us will automatically convert to shares with one vote per share.

- The exercise price in the offering will be a fixed price determined on the day the offer is mailed to shareholders by calculating the "Westar Industries Valuation" as set forth in an exhibit to the plan and then applying a 10% initial public offering discount.

- Westar Industries will have a rescission right through December 31, 2002. This will give Westar Industries the right to repurchase the shares sold in the rights offering at a price equal to the greater of (i) 1.05 times the exercise price, or (ii) the market price at the time of the repurchase offer. The warrants issued to participating shareholders in the offering will expire if the rescission right is exercised. We would not be able to sell any additional shares prior to the expiration of the rescission period.

- The proceeds from the offering (or any other subsequent sale of stock by Westar Industries) and any dividends from the ONEOK common or convertible preferred stock not used in Westar Industries' business or previously committed will be used to purchase in the market our or KGE's currently outstanding debt securities. On February 10, 2003, such debt securities and the balance, if any, of our intercompany payable with Westar Industries will be converted into our common stock at the average trading price for the 20 days prior to conversion, but in no event less than $24 per share. However, if the PNM transaction is not terminated, such funds and the intercompany payable will be transferred by us to Westar Industries to purchase 7.5% Western Resources convertible preferred stock, convertible into our common stock at $30 per share, as provided in the PNM merger agreement. Prior to tax 7

deconsolidation, Westar Industries cannot receive any cash dividends from us, but will instead reinvest those dividends in additional shares of our common stock. Dividends on the convertible preferred stock will be payable in additional preferred shares rather than cash. Westar Industries will use interest received on our and KGE debt securities it purchases as provided above to purchase additional debt securities.

If the PNM transaction is not terminated, the amount of our convertible preferred stock purchased by Westar Industries will not exceed $291 million. Westar Industries will continue to own our common stock it currently owns. Westar Industries will retain its option to purchase Westar Generating, Inc., a wholly owned subsidiary of ours, which owns an interest in the State Line Facility (see "Item 2.

Properties" for a description of this facility and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Information - Related Party Transactions" for a discussion of this purchase option).

Westar Industries will not vote any of our common stock it owns as long as we are tax consolidated.

- Westar Industries will adopt a "poison pill" that will restrict ownership in it to 20% of the shares not owned by us.

The rights offering and subsequent sale of Westar Industries' shares by us pursuant to the plan do not constitute a change in control for our employees under the terms of existing agreements and no agreements will be executed which include a provision under which the offering and sale of Westar Industries' shares by us pursuant to the plan would constitute a change in control.

- We will not sell more than 19.9% of Westar Industries unless we have $1.8 billion or less in short- and long-term debt and all of our and KGE's first mortgage bonds are rated investment grade.

In the event Westar Industries' common stock trades for 45 consecutive trading days at a price that is 15% above the price necessary to reduce our short- and long-term debt to an amount less than $1.8 billion (as measured at the end of the immediately preceding fiscal quarter), we will be required to use our best efforts to sell enough shares in Westar Industries, or us, or a combination of both (at our option), to reduce debt to $1.8 billion. However, in no event shall this obligation be triggered prior to February 1, 2003, unless the PNM transaction is terminated prior to that date. Furthermore, on each annual anniversary of the closing of the rights offering, the amount of debt used to determine whether our obligation has been triggered will increase by $100 million.

- We agree to reduce our total debt by at least $100 million per year each year following the completion of the offering until the separation is consummated.

- Our board of directors will have at least a majority of independent directors following the separation.

Impairment Charge Pursuant to New Accountin2 Rules Effective January 1, 2002, we adopted Statement of Financial Accounting Standard (SFAS) No. 142, "Accounting for Goodwill and Other Intangible Assets," and SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets," which together establish new standards for accounting for goodwill and other long lived assets. Pursuant to these new standards, we will record an impairment charge to write down goodwill and customer accounts to their estimated fair values in the first quarter of 2002. The amount of this charge, net of tax, will be approximately $653.7 million, of which $464.2 million is related to goodwill and $189.5 million is related to customer accounts. For further information on the impairment charge, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Summary of Significant Items - Impairment Charge Pursuant to New Accounting Rules."

8

Ice Storm In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs could run as high as $25 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application.

ELECTRIC UTILITY OPERATIONS General We supply electric energy at retail to approximately 640,000 customers in Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina and Hutchinson. We also supply electric energy at wholesale to the electric distribution systems of 63 Kansas cities and 4 rural electric cooperatives. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, we have power marketing operations which purchase and sell electricity in areas outside of our historical marketing territory.

Our electric sales for the years ended December 31, 2001, 2000 and 1999 were as follows:

2001 2000 1999 (In Thousands)

Residential ..................................... $ 419,492 $ 452,674 $ 407,371 Commercial ................................... 380,277 367,367 356,314 Industrial ....................................... 244,392 252,243 251,391 Wholesale and Interchange ........... 233,129 214,721 174,895 Power M arketing ........................... 408,242 457,178 190,101 System M arketing .......................... 32,192 35,321 3,320 Other ............................................. 50,669 49,629 46,306 Total ......................................... $1.768.393 $1.829.133 S$1,429,69a The following table reflects electric sales volumes, as measured by megawatt hours (MWh), for the years ended December 31, 2001, 2000 and 1999. No amounts are included for power marketing and system marketing sales because these sales are not based on electricity we generate.

2001 2000 1999 (Thousands of MWh)

Residential ..................................... 5,755 6,222 5,551 Comm ercial ................................... 6,742 6,485 6,202 Industrial ....................................... 5,617 5,820 5,743 Wholesale and Interchange ........... 7,547 6,892 5,617 Other ............................................. 107 108 108 Total ......................................... 25.768 ;23;22 Generation Capacity The aggregate net generating capacity of our system is presently 5,947 megawatts (MW). The system has interests in 21 fossil-fuel steam generating units, one combined cycle steam generating unit, one nuclear generating unit, ten combustion peaking turbines, two combined cycle combustion turbines, two diesel generators and two wind generators.

Our aggregate 2001 peak system net load of 4,468 MW occurred on July 30, 2001. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 19% above 9

system peak responsibility at the time of the peak. Our all time peak system net load of 4,528 MW occurred on September 11, 2000.

We have a market-based rate authority from the FERC, under which we buy and sell energy and capacity throughout the United States.

We have agreed to provide generating capacity to other utilities for certain periods as set forth below:

Utility Capacity (MW) Period Ending Oklahoma Municipal Power Authority (OMPA) .................................... 60 December 2013 M idwest Energy, Inc .............................................................................. 60 M ay 2008 125 May2010 Empire District Electric Company (Empire) ........................................... 80 May 2001 162 May2010 McPherson Board of Public Utilities (McPherson) ................................. (a) May 2027 (a) We provide base capacity to McPherson. McPherson provides peaking capacity to us. During 200 1, we provided approximately 74 MW to and received approximately 182 MW from McPherson. The amount of base capacity provided to McPherson is based on a fixed percentage of McPherson's annual peak system load.

We forecast that we will need additional generating capacity of approximately 150 MW by 2006 to serve our customers' expected electricity needs. We will determine how to meet this need at a future date.

Fossil Fuel Generation Fuel Mix:

Coal-fired units comprise 3,349 MW of our total 5,947 MW of generating capacity and the nuclear unit provides 550 MW of capacity. Of the remaining 2,048 MW of generating capacity, units that can bum either natural gas or oil account for 1,964 MW, units that burn only diesel fuel account for 83 MW, and wind turbines account for approximately 1 MW (see "Item 2. Properties").

Based on MMBtus burned, the 2001 and estimated 2002 fuel mix (percent of electricity produced by a specific fuel type) are as follows:

Estimated Fuel 2001 2002 Coal ....................................... 77% 78%

Nuclear .................................. 17% 15%

Gas, Oil or Diesel Fuel .......... 6% 7%

Our fuel mix fluctuates with the operation of the nuclear-powered Wolf Creek (as discussed below under

"- Nuclear Generation"), fuel costs, plant availability and power available on the wholesale market.

Coal:

Jeffrey Enermy Center: The three coal-fired units at Jeffrey Energy Center (JEC) have an aggregate capacity of 1,860 MW (our 84% share). We have a long-term coal supply contract with Amax Coal West, Inc., a subsidiary of RAG America Coal Company, to supply coal to JEC from mines located in the Powder River Basin in Wyoming. The contract expires December 31, 2020. The contract contains a schedule of minimum annual MMBtu delivery quantities. The coal to be supplied is surface mined and has an average Btu content of approximately 8,407 Btu per pound and an average sulfur content of 0.43 lbs/MMBtu (see "- Environmental Matters"). The average cost of coal burned at JEC during 2001 was approximately $1.10 per MMBtu, or $18.57 per ton.

10

Coal is transported from Wyoming under a long-term rail transportation contract with Burlington Northern Santa Fe (BNSF) and Union Pacific (UP) railroads with a term continuing through December 31, 2013.

LaCygne Generating Station: The two coal-fired units at LaCygne Station have an aggregate generating capacity of 681 MW (KGE's 50% share). LaCygne 1 uses a blended fuel mix containing approximately 85% Powder River Basin coal and 15% Kansas/Missouri coal. LaCygne 2 uses Powder River Basin coal. The operator of LaCygne Station, Kansas City Power and Light Company (KCPL), administers the coal and coal.transportation contracts. A portion of the LaCygne I and LaCygne 2 Powder River Basin coal is supplied through several fixed price and spot market contracts that expire at various times through 2003 and is transported under KCPL's Omnibus Rail Transportation Agreement with BNSF and Kansas City Southern Railroad through December 31, 2010.

Additional coal may be acquired on the spot market. The LaCygne 1 Kansas/Missouri coal is purchased from time to time from local Kansas and Missouri producers.

The Powder River Basin coal supplied during 2001 had an average Btu content of approximately 8,527 Btu per pound and an average sulfur content of 0.73 lbs/MMBtu. During 2001, the average cost of all coal burned at LaCygne 1 was approximately $0.86 per MMBtu, or $14.88 per ton. The average cost of coal burned at LaCygne 2 was approximately $0.79 per MMBtu, or $13.47 per ton.

Lawrence and Tecumseh Energy Centers: The coal-fired units located at the Tecumseh and Lawrence Energy Centers have an aggregate generating capacity of 808 MW. In 2001, we obtained coal from Wyoming and Colorado. The Wyoming coal supplied in 2001 had an average Btu content of approximately 8,753 Btu per pound and an average sulfur content of 0.46 lbs/MMBtu. The Colorado coal supplied in 2001 had an average Btu content of approximately 11,030 Btu per pound and an average sulfur content of 0.44 lbs/MMBtu. During 2001, the average cost of all coal burned in the Lawrence units was approximately $1.25 per MMBtu, or $25.19 per ton. The average cost of all coal burned in the Tecumseh units was approximately $1.22 per MMBtu, or $23.76 per ton.

The Wyoming Powder River Basin coal is transported by BNSF railroad and the Colorado coal is transported by BNSF and UP railroads. We have Wyoming coal under contract to support the anticipated operation of these units through the end of 2004. We have a portion of our Wyoming coal needs under a contract that expires in 2004. We may also purchase coal on the spot market.

General: We have entered into all of our coal contracts in the ordinary course of business and do not believe we are substantially dependent upon these contracts. We believe there are other suppliers with plentiful sources of coal available at spot market prices to replace, if necessary, fuel to be supplied pursuant to these contracts.

In the event that we were required to replace our coal agreements, we would not anticipate a substantial disruption of our business although the cost of purchasing coal could increase.

We have entered into all of our coal transportation contracts in the ordinary course of business. Several rail carriers are capable of serving the coal mines from where our coal originates, but several of our generating stations can be served by only one rail carrier. In the event the rail carrier to one of our generating stations fails to provide reliable service, we could experience a short-term disruption of our business. However, due to the obligation of the rail carriers to provide service under the Interstate Commerce Act, we do not anticipate any substantial long-term disruption of our business although the cost of transporting coal could increase.

Natural Gas:

We use natural gas as a primary fuel in our Gordon Evans, Murray Gill, Neosho, Abilene, and Hutchinson Energy Centers, in the gas turbine units at our Tecumseh generating station and in the combined cycle units at the State Line facility. Natural gas is also used as a supplemental fuel in the coal-fired units at the Lawrence and Tecumseh generating stations. Natural gas for all facilities is purchased in the short-term spot market, which supplies the system with the flexible natural gas supply as necessary to meet operational needs.

For Abilene and Hutchinson Energy Centers, we maintain natural gas transportation with Kansas Gas Service Company, a division of ONEOK, under a contract that expires April 30, 2004. For Gordon Evans, Murray Gill, Neosho, Lawrence and Tecumseh Energy Centers, we meet a portion of our natural gas transportation 11

requirements through firm natural gas transportation capacity agreements with Williams Gas Pipelines Central. All of the natural gas transportation requirements for the State Line facility are met through a firm natural gas transportation agreement with Williams Gas Pipelines Central. The firm transportation agreements that serve Gordon Evans, Murray Gill, Lawrence and Tecumseh extend through April 1, 2010. The agreement for the Neosho and State Line facilities extends through June 1, 2016.

Oil:

We use oil as an alternate fuel when economical or when interruptions to natural gas make it necessary. Oil is also used as a start-up fuel at some of our generating stations and as a primary fuel in the Hutchinson No. 4 combustion turbine and in the diesel generators. Oil is obtained by spot market purchases and year-long contracts.

We maintain quantities in inventory to meet emergency requirements and protect against reduced availability of natural gas for limited periods or when the primary fuel becomes uneconomical to bum.

Other Fuel Matters:

Our contracts to supply fuel for our coal-fired and natural gas-fired generating units, with the exception of JEC, do not provide full fuel requirements at the various stations. Supplemental fuel is procured on the spot market to provide operational flexibility and to take advantage of economic opportunities when the price is favorable. We use financial instruments to hedge a portion of our anticipated fossil fuel needs in an attempt to offset the volatility of the spot market. Due to the volatility of these markets, we are unable to determine what the value of these financial instruments will be when the agreements are actually settled. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Information - Market Risk Disclosure" for further information.

The table below provides information relating to the weighted average cost of fuel that we have used (which includes the commodity cost, transportation cost to our facilities and any other associated costs).

2001 2000 1999 KPL Plants Per Million Btu:

Coal ..................................... $ 1.15 $ 1.13 $ 1.09 Gas ...................................... 4.61 3.84 2.66 Oil ....................................... 3.99 3.45 4.17 Per MWh Generation .............. $13.92 $13.61 $12.57 KGE Plants Per Million Btu:

Nuclear ................................ $ 0.44 $ 0.44 $ 0.45 Coal ..................................... 0.95 0.91 0.87 G as ...................................... 3.75 3.34 2.31 O il ....................................... 3.84 3.12 2.11 Per MWh Generation .............. $11.04 $ 11.08 $ 9.83 Nuclear Generation Fuel Supply:

The owners of Wolf Creek have on hand or under contract 100% of their uranium and uranium conversion needs for 2002 and 77% of the uranium and uranium conversion required for operation of Wolf Creek through October 2006. The balance is expected to be obtained through spot market and contract purchases.

12

The owners have under contract 100% of Wolf Creek's uranium enrichment needs for 2002 and 90% of the uranium enrichment required to operate Wolf Creek through October 2006. The balance of Wolf Creek's enrichment needs are expected to be obtained through spot market and contract purchases.

All uranium, uranium conversion and uranium enrichment arrangements have been entered into in the ordinary course of business, and Wolf Creek is not substantially dependent upon these agreements. Despite contraction and consolidation in the supply sector for these commodities and services, Wolf Creek's management believes there are other supplies available to replace, if necessary, these contracts. In the event these contracts were required to be replaced, Wolf Creek's management does not anticipate a substantial disruption of Wolf Creek's operations.

Nuclear fuel is amortized to cost of sales based on the quantity of heat produced (MMBtus) for the generation of electricity.

Radioactive Waste Disposal:

Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered for the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales.

In 1996 and 1997, a U.S. Court of Appeals issued decisions that (1) the NWPA unconditionally obligated the DOE to begin accepting spent fuel for disposal in 1998 and (2) precluded the DOE from concluding that its delay in accepting spent fuel is "unavoidable" under its contracts with utilities due to lack of a repository or interim storage authority.

In May 1998, the Court issued an order in response to the utilities' petitions for remedies for DOE's failure to begin accepting spent fuel for disposal. The Court affirmed its conclusion that the sole remedy for DOE's breach of its statutory obligation under the NWPA is a contract remedy and indicated that the Court will not revisit the matter until the utilities have completed their pursuit of that remedy. Wolf Creek intends to pursue its claims against the DOE.

A permanent disposal site will not be available for the nuclear industry until 2010 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025.

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

Our net investment in the Compact through December 31, 2001 was approximately $7.4 million.

On December 18, 1998, the Nebraska agencies responsible for considering the developer's license application denied the application. The license applicant has sought a hearing on the license denial, but a U.S.

District Court has indefinitely delayed proceedings related to the hearing. In December 1998, most of the utilities that had provided the project's pre-construction financing (including WCNOC) filed a federal court lawsuit contending Nebraska officials acted in bad faith while handling the license application. Shortly thereafter, the Central Interstate Low-Level Radioactive Waste Commission (Commission) (responsible for causing a new disposal facility to be developed within the Compact region) and US Ecology (the license applicant) filed similar claims against Nebraska. In September 1999, the U.S. District Court partially denied and partially granted Nebraska's motions to dismiss the utilities' and US Ecology's cases and denied Nebraska's motion to dismiss the Commission's 13

case. Since that time, the utilities have dismissed their remaining claims against Nebraska for monetary damages, but their claims for equitable relief remain. The Commission's claims for monetary damages and equitable relief also remain, and the parties expect the case to go to trial in the second half of 2002.

In May 1999, the Nebraska legislature passed a bill withdrawing Nebraska from the Compact. In August 1999, the Nebraska governor gave official notice of the withdrawal to the other member states. Withdrawal will not be effective for five years and will not, of itself, nullify the site license proceeding.

Wolf Creek disposes of all classes of its low-level radioactive waste at existing third-party repositories.

Should disposal capability become unavailable, Wolf Creek is able to store its low-level radioactive waste in an on site facility for up to five years under current regulations. Wolf Creek believes that a temporary loss of low-level radioactive waste disposal capability will not affect continued operation of the power plant.

Outages:

Wolf Creek has an 18-month refueling and maintenance schedule which permits uninterrupted operation every third calendar year. An outage began on March 23, 2002. During the outage, electric demand is expected to be met primarily by our other fossil-fueled generating units and by purchased power.

An extended shut-down of Wolf Creek could have a substantial adverse effect on our business, financial condition and results of operations because of higher replacement power and other costs. Although not expected, reacting to safety issues, the Nuclear Regulatory Commission (NRC) could impose an unscheduled plant shut-down due to terrorist or other concerns.

Customer Operations Our Customer Operations segment transports electricity from the generating stations to approximately 640,000 customers in Kansas. It also transports electric energy to the electric distribution systems of 63 Kansas cities and 4 rural electric cooperatives. Customer Operations properties include substations, poles, wire, underground cable systems, and customer meters. Customer Operations' objective is to provide low-cost electricity transportation while maintaining a high level of system reliability and customer service.

We are a member of the Southwest Power Pool (SPP). In February 2002, SPP and the Midwest Independent System Operator, Inc. (MISO) executed a definitive agreement for the consolidation of the two organizations, which is expected to occur in 2003. We anticipate that after the consolidation of SPP and MISO, we will participate in MISO. Among other things, these organizations were formed to maintain transmission system reliability on a regional basis. See "- Competition and Deregulation" below for more information on these organizations.

We are also a member of the SPP transmission tariff, along with ten other transmission providers in the region. Revenues from this tariff are divided among the tariff members based upon calculated impacts to their respective systems. The tariff allows for both finn and non-firm transmission access. We will file a new transmission tariff with MISO as it becomes operational.

Customer Operations also includes the customer service portion of our electric utility business. Customer service includes, among other things, operating our phone center, handling credit and collections, billing, meter reading and field service.

Security and Insurance We have increased the level of security measures at our generation facility sites and various offices, in part due to nationwide terrorist concerns. These measures include, but are not limited to, increased security personnel, utilization of armed guard services, patrolling of company property, restricting access to our properties and implementing emergency training and response procedures.

14

Wolf Creek's management has increased both voluntary and federally-mandated security measures at Wolf Creek. The NRC has required nuclear power plants to be operated at the highest level of security since September 11, 2001. The measures implemented at Wolf Creek include, but are not limited to, increased guard service, no unscheduled public visits and emergency training and response procedures.

The NRC has issued orders to all nuclear plants that make our current voluntary security measures mandatory. The orders also impose new security requirements at U.S. nuclear power plants. Wolf Creek's security costs will increase as a result of these orders.

In addition, there are unfavorable trends in the availability and price of property and casualty insurance primarily due to catastrophic events and the world's financial markets. We anticipate material increases in insurance costs, although the amount of the increase is unknown at this time. Information with respect to insurance coverage applicable to the operations of our nuclear generating facility is set forth in Note 14 of the "Notes to Consolidated Financial Statements."

Competition and Deregulation Electric utilities have historically operated in a rate-regulated environment. Federal and state regulatory agencies having jurisdiction over our rates and services and other utilities have initiated steps that were expected to result in a more competitive environment for utility services. The Kansas Legislature took no action on deregulation in 2001 or 2000.

In a deregulated environment, utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits. Possible types of competition include cogeneration, self generation, retail wheeling, or municipalization. Retail wheeling is the ability of individual customers to choose a power provider other than us and we would provide the transmission service for this power. Kansas does not allow retail wheeling and no such regulation is pending or being considered. However, if retail wheeling were implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. Our rates range from approximately 10% to 20% below the national average for retail customers. Because of these rates, we expect to retain a substantial part of our current volume of sales in a competitive environment.

Increased competition for retail electricity sales may in the future reduce our earnings, which could impact our ability to pay dividends and could have a material adverse impact on our operations and our financial condition.

A material non-cash charge to earnings may be required should we discontinue accounting under SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."

The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted the FERC to order electric utilities to allow third parties to use their transmission systems to sell electric power to wholesale customers. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order No. 2000) encouraging formation of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive markets in bulk power.

After the FERC rejected several attempts by the SPP to seek RTO status, the SPP and MISO agreed in October 2001 to consolidate and form an RTO. In December 2001, the FERC approved this newly formed MISO as the first RTO. The agreement to consolidate was executed in February 2002 and the transaction is expected to close in 2003. This new organization will operate our transmission system as part of an interconnected transmission system encompassing over 120,000 MW of generation capacity located in 20 states. MISO will collect revenues attributable to the use of each member's transmission system, and each member will be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire MISO system.

Although each member will have priority over the use of its own transmission facilities for selling power to its wholesale customers or others, each member will be charged the same uniform transmission rate as other energy suppliers who are able to sell power to them. We intend to file with the FERC and the KCC to transfer control over 15

the operation of our transmission facilities to MISO. We anticipate that FERC Order No. 2000 and our participation in the MISO will not have a material effect on our operations.

For further discussion regarding competition and its potential impact on us, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Information - Electric Utility."

Regulation and Rates As a Kansas electric utility, we are subject to the jurisdiction of the KCC, which has general regulatory authority over our rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts and various other matters. We are also subject to the jurisdiction of the KCC and FERC with respect to the issuance of certain securities. The NRC regulates our nuclear operations.

Additionally, we are subject to the jurisdiction of FERC, which has authority over wholesale sales of electricity, the transmission of electric power and the issuance of certain securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety. We are exempt as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 from all provisions of that Act, except Section 9(a)(2).

On November 27, 2000, we and KGE filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our combined electric rates of $22.7 million, consisting of a

$41.2 million reduction in KGE's rates and an $18.5 million increase in our rates.

On August 9, 2001, we and KGE filed petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the KGE acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and several other issues. On September 5, 2001, the KCC issued an order in response to our motions for reconsideration that increased our rate increase by an additional $7.0 million. The $41.2 million rate reduction in KGE's rates remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions with the Kansas Court of Appeals in an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal this decision to the Kansas Supreme Court.

Additional information with respect to rate matters and regulation is set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Summary of Significant Items - KCC Rate Cases," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

- Other Information - Electric Utility" and Notes 2 and 3 of "Notes to Consolidated Financial Statements."

Environmental Matters We currently hold all federal and state environmental approvals required for the operation of all of our generating units. We believe we are presently in substantial compliance with all air quality regulations (including those pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx)) promulgated by the State of Kansas and the Environmental Protection Agency (EPA).

The JEC and LaCygne 2 units have met: (1) the federal sulfur dioxide standards through the use of low sulfur coal; (2) the federal particulate matter standards through the use of electrostatic precipitators; and (3) the federal NOx standards through boiler design and operating procedures. The JEC units are also equipped with flue gas scrubbers providing additional sulfur dioxide and particulate matter emission reduction capability when needed to meet permit limits.

The Kansas Department of Health and Environment (KDHE) regulations applicable to our other generating facilities prohibit the emission of more than 3.0 pounds of sulfur dioxide per MMBtu of heat input. We meet these 16

standards through the use of low sulfur coal and by all coal-burning facilities being equipped with flue gas scrubbers and/or electrostatic precipitators.

We must comply, and are currently in compliance, with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. We have installed continuous monitoring and reporting equipment to meet the acid rain requirements. We have not had to make any material capital expenditures to meet Phase II sulfur dioxide and nitrogen oxide requirements.

All of our generating facilities are in substantial compliance with the Best Practicable Technology and Best Available Technology regulations issued by the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are administered in Kansas by the KDHE.

Additional information with respect to Environmental Matters is discussed in Note 14 of the "Notes to Consolidated Financial Statements."

MONITORED SERVICES OPERATIONS General We provide property monitoring services through Protection One and Protection One Europe to approximately 1.2 million customers in North America and approximately 62,000 customers in continental Europe.

Revenues are generated primarily from recurring monthly payments for monitoring and maintaining the alarm systems that are installed in customers' homes and businesses. Services are provided to residential (both single family and multifamily residences), commercial and wholesale customers. Currently, North America's customers are primarily in the residential market and Europe's customers are primarily in the commercial market.

In prior years, the strategy for the monitored security business was focused primarily on growing the customer account base to achieve critical mass. Protection One and Protection One Europe grew rapidly by participating in the growth in the alarm industry and by acquiring other alarm companies.

The strategic focus has now shifted to improving returns on invested capital by realizing economies of scale from increasing customer density in the largest urban markets in North America. Protection One plans to accomplish this goal by:

- retaining customers by providing superior customer service from monitoring facilities and branches;

- using its national presence, strategic alliances, and strong local operations to persuade the most desirable residential and commercial prospects to enter into long term agreements with it on terms that permit it to achieve appropriate returns on capital; and

- on a limited basis in 2002 or 2003, acquiring alarm companies and portfolios of alarm accounts pursuant to transactions that meet strategic and financial requirements.

Operations Monitored services operations consist principally of alarm monitoring, customer service functions and branch operations.

Security alarm systems include many different types of devices installed on customers' premises designed to detect or react to various occurrences or conditions, such as intrusion or the presence of fire or smoke. Products range from basic intrusion and fire detection equipment to fully integrated systems with card access, closed circuit television and voice/video monitoring.

Alarm monitoring customer contracts generally have initial terms ranging from two to ten years in duration, and provide for automatic renewals for a fixed period (typically one year) unless one of the parties elects to cancel the contract at the end of its term.

17

Protection One provides monitoring services from six monitoring facilities in North America. Protection One Europe provides monitoring services from facilities in Paris and Vitrolles, France. See "Item 2. Properties" for further information.

In 2001, Protection One substantially completed the installation of the technology platform referred to as MAS, or Monitored Automation Systems, that combines the customer service, monitoring, billing, and collection functions into a single system. The conversion to MAShas enabled Protection One to consolidate monitoring facilities, resulting in operational efficiencies and cost savings. Conversion of the Portland, Maine monitoring facility was completed in January 2002. Currently, approximately 94% of Protection One's North America residential and commercial customer base is served by MAS.

Branch Overations Protection One maintains approximately 60 service branches in North America from which it provides field repair, customer care, alarm response and sales services and seven satellite locations from which it provides field repair services. Protection One Europe maintains approximately 35 sales branch offices in continental Europe, primarily in France.

Customer Acquisition Strategv Protection One's current customer acquisition strategy for North America relies primarily on internally generated sales. In June 2001, Protection One notified most of its remaining domestic dealers that it was terminating its dealer arrangements with them and therefore would not be extending or renewing their contracts. The number of accounts Protection One purchased through its dealer program decreased from 21,817 in 2000 to 7,501 in 2001.

Protection One currently has a salaried and commissioned sales force that utilizes its existing branch infrastructure in approximately 60 markets. In late 2001, Protection One entered into a marketing alliance with BellSouth Telecommunications, Inc. to expand its residential, single-family market.

Protection One's multifamily business utilizes a salaried and commissioned sales force to produce new accounts. It markets its services and products primarily to developers, owners and managers of apartment complexes and other multifamily dwellings. Protection One grows its multifamily business through national and regional advertising, nationwide professional field sales efforts, centralized inbound and outbound sales functions, prospective acquisition marketing efforts and professional industry-related association affiliation.

Protection One continually evaluates its customer creation and marketing strategy, including evaluating each respective channel for economic returns, volume and other factors and may shift its strategy or focus, including the elimination of a particular channel.

Protection One Europe's customer acquisition strategy also relies primarily on internally generated sales.

Protection One Europe uses an internal sales force of approximately 300 employees, which operate out of 35 branch locations in France, Germany, Belgium and the Netherlands. Protection One Europe's salary structure for its internal sales force is heavily reliant on commissions, but contains a portion of fixed salaries. In addition, Protection One Europe owns a telemarketing company, known as Eurocontact, which provides qualified leads to the sales network.

18

Competition The security alarm industry is highly competitive. In North America, there are only four alarm companies that offer services across the U.S. and Canada with the remainder being either large regional or small, privately held alarm companies. Based on total annual revenues in 2000, Protection One believes the top four alarm companies in North America are:

- ADT Security Services, a subsidiary of Tyco International, Ltd. (ADT)

- Protection One

- Brinks Home Security Inc., a subsidiary of The Pittston Services Group of North America

- Honeywell Inc.

In continental Europe, there are a large number of small competitors and a few large regional competitors who have recently been taking steps toward establishing a continental presence. The large regional competitors include the following companies:

- CIPE, a subsidiary of ADT Security Services and Tyco International, Ltd., which is the largest security company in France

- Chubb, a United Kingdom based company which is also a leading security company in France

- Securitas, based in Sweden, which has its principal operations in the guarding industry but is expanding operations in monitored security

- Group 4 Falck, a Danish security company that has significant operations in Scandinavia and has recently expanded into Germany and the Netherlands

- Rentokil Initial, based in the Netherlands which has established operations in France and the United Kingdom Competition in the security alarm industry is based primarily on market visibility, price, reputation for quality of services and systems, services offered and the ability to identify and to solicit prospective customers as they move into homes and businesses. Protection One and Protection One Europe believe that they compete effectively with other national, regional and local security alarm companies due to their ability to offer integrated alarm system installation, monitoring, repair and enhanced services, their reputation for reliable equipment and services and their prominent presence in the areas surrounding their branch offices.

Competitors exist in the market that have greater financial resources than Protection One or Protection One Europe, enabling them to offer higher prices to purchase customer accounts. The effect of such competition may be to reduce the growth of our customer account base as purchase opportunities may be limited by our available resources.

Regulatory Matters A number of local governmental authorities have adopted or are considering various measures aimed at reducing the number of false alarms. Such measures include:

Subjecting alarm monitoring companies to fines or penalties for transmitting false alarms.

Requiring permits for individual alarm systems and revoking permits following a specified number of false alarms.

Imposing fines on alarm customers for false alarms.

Imposing limitations on the number of times the police will respond to alarms at a particular location after a specified number of false alarms.

Requiring further verification of an alarm signal before the police will respond.

Monitored services operations are subject to a variety of other laws, regulations and licensing requirements of both domestic and foreign federal, state and local authorities. In certain jurisdictions, Protection One and Protection One Europe are required to obtain licenses or permits to comply with standards governing employee selection and training, and to meet certain standards in the conduct of its business.

19

The alarm industry is also subject to requirements imposed by various insurance, approval, listing and standards organizations. Depending upon the type of customer served, the type of security service provided, and the requirements of the applicable local governmental jurisdiction, adherence to the requirements and standards of such organizations is mandatory in some instances and voluntary in others.

Protection One's monitoring services advertising and sales practices are regulated in the .United States by both the Federal Trade Commission and state consumer protection laws. In addition, certain administrative requirements and laws of the jurisdictions in which Protection and Protection One Europe operate also regulate such practices. Such laws and regulations include restrictions on the manner in which the sale of security alarm systems is promoted, the obligation to provide purchasers of its alarm systems with certain rescission rights and certain foreign jurisdictions' restrictions on a company's freedom to contract.

The alarm monitoring business utilizes telephone lines and radio frequencies to transmit alarm signals. The cost of telephone lines, and the type of equipment, which may be used in telephone line transmission, are currently regulated by both federal and state governments. The Federal Communications Commission and state public utilities commissions regulate the operation and utilization of radio frequencies. In addition, the laws of certain foreign jurisdictions in which Protection One and Protection One Europe operate regulate the telephone communications with the local authorities.

Risk Management The nature of providing monitored services potentially exposes Protection One and Protection One Europe to greater risks of liability for employee acts or omissions, or system failure, than may be inherent in other businesses. Substantially all alarm monitoring agreements, and other agreements, pursuant to which products and services are sold, contain provisions limiting liability to customers in an attempt to reduce this risk.

Protection One and Protection One Europe carry insurance of various types, including general liability and errors and omissions insurance in amounts considered adequate and customary for the industry and business. Loss experience, and the loss experiences at other security services companies, may affect the availability and cost of such insurance. Certain insurance policies, and the laws of some states and countries, may limit or prohibit insurance coverage for punitive or certain other types of damages, or liability arising from gross negligence.

SEGMENT INFORMATION Financial information with respect to business segments is set forth in Note 24 of the "Notes to Consolidated Financial Statements."

GEOGRAPHIC INFORMATION Geographic information is set forth in Note 24 of the "Notes to Consolidated Financial Statements."

EMPLOYEES As of February 28, 2002, we had approximately 5,600 employees, of which approximately 3,700 were employees of Protection One and Protection One Europe. In the fourth quarter of 2001 and in January 2002, we reduced our utility work force by approximately 600 employees through involuntary and voluntary separation programs. We may replace some of these employees. Protection One reduced its work force by approximately 700 employees in 2001 and in January and February 2002 due to facility consolidations and other cost cutting measures.

We did not experience any strikes or work stoppages during 2001. Our current contract with the International Brotherhood of Electrical Workers extends through June 30, 2002. The contract covers approximately 1,100 employees as of February 28, 2002. We are currently negotiating an extension of the contract.

20

RISK FACTORS You should read the following risk factors in conjunction with discussions of factors discussed elsewhere in this and other of our filings with the Securities and Exchange Commission (SEC). These cautionary statements are intended to highlight certain factors that may affect our financial condition and results of operations and are not meant to be an exhaustive discussion of risks that apply to public companies with broad operations, such as us. Like other businesses, we are susceptible to macroeconomic downturns in the United States or abroad that may affect the general economic climate and our performance or that of our customers. Similarly, the price of our securities is subject to volatility due to fluctuations in general market conditions, differences in our results of operations from estimates and projections generated by the investment community and other factors beyond our control.

We Are a Public Utility Subject to Regulation Which Significantly Impacts Our Business, Results of Operations, Financial Position and Prospects:

We are regulated by the KCC and FERC and other federal and state agencies. See "- Electric Utility Operations - Regulation and Rates." This regulation impacts most aspects of our business and operations.

Throughout this Annual Report on Form 10-K, we have described the impact of regulation and the significant effect it has on our business, financial condition, results of operations, liquidity and prospects. Such regulation is impacted by matters beyond our control, such as general economic conditions, politics and competition, and other matters described under "Forward-Looking Statements." We refer you to "- Significant Business Developments," and the other risk factors below, as well as "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," for a further discussion of some of the more important matters which are currently the subject of, or related to, regulatory concerns.

Municipalization Efforts by Wichita May Affect Operations and Results:

In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system and arrange for its own power supply.

These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize KGE's retail electric utility business in Wichita. KGE will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material.

KGE's franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, KGE will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 23% of our total energy sales.

Fuel and Purchased Power Costs are Included in Retail Rates at a Fixed Level and Increases are not Recovered Automatically:

Fuel and purchased power costs are recovered in retail rates at a fixed test year level. Therefore, to recover fuel and purchased power costs in excess of the costs built into retail rates, we would have to make a rate filing with the KCC, which could be denied in whole or in part. During 2001, we entered into a gas hedging arrangement, designed to eliminate a portion of our risk through July 2004. Any increase in fuel and purchased power costs over the costs recovered through rates would reduce our earnings. Increases could be material.

21

Purchased Power Commodity Prices are Volatile:

The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased and our participation in power trades. If we were unable to generate an adequate supply of electricity for our native load customers, we would purchase power in the wholesale market to the extent it is available or economically feasible to do so and/or implement curtailment or interruption procedures as allowed for in our tariffs and terms and conditions of service. To the extent open positions exist in our power marketing portfolio, we are exposed to fluctuating market prices that may adversely impact our financial position and results of operations. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition.

Hedging and Trading Activities Involve Risks:

We are involved in hedging and trading activities primarily to minimize risk from commodity market fluctuations, capitalize on market knowledge and enhance system reliability. In these activities, we utilize a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, futures, options and swaps providing for payments (or receipt of payments) from counterparties based on the differential between the contract price and a specified index price.

Our hedging and trading activities involve risks, including commodity price risk, interest rate risk and credit risk. Commodity price risk is the risk that changes in commodity prices may impact the price at which we are able to buy and sell electricity and purchase fossil fuels for our generators. These commodities have experienced price volatility in the past and can be expected to do so in the future. This volatility may increase or decrease future earnings.

Interest rate risk is the risk of loss associated with movements in market interest rates. Our exposure to interest rate risk is limited due to the fixed-rate nature of most of our long-term debt. During 2001, we utilized an interest rate swap to manage our exposure to variable interest rates. The swap converted $500 million of variable rate debt to a fixed rate. In the future, we may continue to utilize swaps or other financial instruments to manage interest rate risk.

Credit risk is the risk of loss resulting from non-performance by a counterparty of its contractual obligations. As we continue to expand our power marketing and commodity trading activities, our exposure to credit risk and counterparty default may increase. We maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations. We employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees and standardized master netting agreements that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. See "Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Information

- Market Risk Disclosure" for further discussion.

Results actually achieved from these activities could vary materially from intended results and could materially affect our financial results.

Current Levels of Debt Could Adversely Affect Our Business:

We have a large amount of consolidated indebtedness. As of December 31, 2001, we had outstanding total indebtedness of approximately $3.4 billion, of which approximately $2.9 billion was the obligation of our Westar Energy operations. A large amount of indebtedness could have a negative impact on, among other things, our ability to obtain additional financing in the future for working capital, capital expenditures and general corporate purposes and our ability to withstand a downturn in our business or the economy in general.

The indentures governing our long-term indebtedness require us to satisfy certain financial conditions in order to borrow additional funds. These covenants require, among other things, that we maintain certain leverage and interest coverage ratios. We are in compliance with these covenants. A breach of any of the covenants could 22

result in an event of default, which would allow the lenders to declare all amounts outstanding immediately due and payable.

For information regarding a financial plan that was filed with the KCC that details our current plans for debt reduction, see "- Significant Business Developments - KCC Proceedings and Orders" and "- Significant Business Developments - The Financial Plan" above.

Strategic Transactions May Not Be Completed:

Our strategic plans include the acquisition of our electric utility businesses by PNM and the split-off of Westar Industries to our shareholders. Prior to the completion of these transactions, Westar Industries would sell a portion of its common stock in a rights offering to our shareholders. The completion of these transactions is subject to the satisfaction of various conditions, including the receipt of shareholder and regulatory approvals in the case of the PNM transaction. We believe the completion of the proposed transaction with PNM is not likely. See "SignificantBusiness Developments - PNM Transaction" above for more information.

The Separation of Westar Industries Would Impact Results of Operations:

The financing plan we have filed with the KCC proposes a rights (and warrants) offering of Westar Industries common stock to our shareholders. The financing plan also contemplates (and in certain circumstances requires) a sale of all, or some of, the Westar Industries common stock we own following the rights (and warrants) offering. If a Westar Industries rights offering is completed, we would record a non-cash charge against income equal to the difference between the book value of the portion of our investment in Westar Industries sold in the rights offering and the offering proceeds received by Westar Industries. Similarly, if a split-off or sale of all or part of Westar Industries were completed, we would record a non-cash charge against income equal to the difference between the book value of our remaining investment in Westar Industries and the fair market value of the shares of Westar Industries common stock distributed to our shareholders or sold. We are unable to determine the amount of the charges at this time because the subscription price in the rights offering has not been determined and the fair market value of the common stock of Westar Industries distributed in the split-off or sale of Westar Industries common stock will be determined at the time it occurs. However, the charges could be material and may have a material adverse effect on our operating results in the period recorded. See "- Significant Business Developments

- The Financial Plan" above for more information.

Monitored Services Has Had a History of Losses which are Likely to Continue:

Our monitored services segment incurred losses before interest and taxes of $126.1 million in 2001, $91.4 million in 2000 and $20.7 million in 1999. These losses reflect, among other factors:

- lower revenues due to a smaller customer base;

- substantial charges incurred for amortization of purchased customer accounts and goodwill;

- interest incurred on indebtedness;

- other charges required to manage operations; and

- costs associated with the integration of acquisitions.

We anticipate that Protection One will also continue to incur substantial interest expense because of its substantial debt. We do not expect the monitored services segment to attain profitable operations in the foreseeable future.

Monitored Services Loses Customers Over Time:

Protection One and Protection One Europe experience the loss of accounts, referred to as attrition, as a result of, among other factors, relocation of customers, adverse financial and economic conditions, competition from other alarm service companies, and customer service and operational difficulties with the integration of acquired customers. Prior to 2000, the effects of the gross number of lost customers were offset by a combination of factors that resulted in an overall increase in the number of customers and revenue, including acquiring alarm account 23

portfolios, purchasing accounts from dealers, adding new accounts from customers who moved into premises previously occupied by prior customers in which security alarm systems were installed, adding accounts for which Protection One obtained a guarantee from the seller that allowed Protection One to "put" back to the seller cancelled accounts, and revenues from price increases and the sale of enhanced services. In 2001 and 2000, Protection One's customer acquisition strategies did not replace accounts lost as a result of attrition. This is due primarily to a move from reliance on a dealer program to generate customer accounts to reliance on internally generated sales. The failure of Protection One and Protection One Europe's customer acquisition strategies to increase. the number of new accounts, or the inability of Protection One and Protection One Europe to reduce attrition levels, could have a material adverse effect on their businesses, financial conditions and results of operations.

Monitored Services Will Record an Impairment Charge in the First Quarter of 2002 and Additional Charges May be Recorded in the Future:

In the first quarter of 2002, the monitored services segment will record an impairment charge to write down goodwill and customer accounts to their estimated fair values. The amount of this charge net of tax will be approximately $653.7 million, of which $464.2 million is related to goodwill and $189.5 million is related to customer accounts. For further information on the impairment charge, see Note 25 of the "Notes to Consolidated Financial Statements." After this write down is recorded, we will still have material amounts of goodwill and customer accounts recorded on our consolidated balance sheet. The remaining amount of goodwill will be required to be tested annually for impairment. Customer accounts will be required to be tested upon certain triggering events, which include recurring operating losses, adverse business conditions, declines in market values and other matters that negatively impact value. If the monitored services segment fails future impairment tests for either goodwill or customer accounts, we will be required to recognize additional impairment charges on these assets in the future.

The Impact of Protection One Class Action Litigation May Be Material:

We, Westar Industries, Protection One and its subsidiary Protection One Alarm Monitoring, Inc.

(Protection One Alarm Monitoring) and certain present and former officers and directors of Protection One, are defendants in a purported class action litigation pending in the United States District Court for the Central District of California brought on behalf of shareholders of Protection One. The plaintiffs are seeking unspecified compensatory damages based on allegations that various statements concerning Protection One's financial results and operations for 1997, 1998, 1999 and the first three quarters of 2000 were false and misleading. Protection One and we cannot currently predict the impact of this litigation, which could be material. See "Item 3. Legal Proceedings" and Note 16 of the "Notes to Consolidated Financial Statements" for more information.

24

ITEM 2. PROPERTIES ELECTRIC UTILITY FACILITIES Year Principal Unit Capacity Name Unit No. Installed Fuel (MW) Segment Abilene Energy Center, Combustion Turbine 1 1973 Gas 71.0 Fossil Generation Gordon Evans Energy Center:

Steam Turbines 1 1961 Gas-Oil 151.0 Fossil Generation 2 1967 Gas-Oil 383.0 Fossil Generation Combustion Turbines 1 2000 Gas-Oil 80.0 Fossil Generation 2 2000 Gas-Oil 80.0 Fossil Generation 3 2001 Gas-Oil 154.0 Fossil Generation Diesel Generator 1 1969 Diesel 3.0 Fossil Generation Hutchinson Energy Center:

Steam Turbines 1 1950 Gas 17.0 Fossil Generation 2 1950 Gas 16.0 Fossil Generation 3 1951 Gas 31.0 Fossil Generation 4 1965 Gas 175.0 Fossil Generation Combustion Turbines 1 1974 Gas 52.0 Fossil Generation 2 1974 Gas 54.0 Fossil Generation 3 1974 Gas 54.0 Fossil Generation 4 1975 Diesel 77.0 Fossil Generation Diesel Generator 1 1983 Diesel 3.0 Fossil Generation Jeffrey Energy Center (84%):

Steam Turbines I (a) 1978 Coal 625.0 Fossil Generation 2 (a) 1980 Coal 612.0 Fossil Generation 3 (a) 1983 Coal 623.0 Fossil Generation Wind Turbines 1 (a) 1999 0.6 Fossil Generation 2 (a) 1999 0.6 Fossil Generation LaCygne Station (50%):

Steam Turbines I (a) 1973 Coal 344.0 Fossil Generation 2 (b) 1977 Coal 337.0 Fossil Generation Lawrence Energy Center:

Steam Turbines 3 1954 Coal 57.0 Fossil Generation 4 1960 Coal 119.0 Fossil Generation 5 1971 Coal 388.0 Fossil Generation Murray Gill Energy Center:

Steam Turbines 1 1952 Gas-Oil 43.0 Fossil Generation 2 1954 Gas-Oil 74.0 Fossil Generation 3 1956 Gas-Oil 112.0 Fossil Generation 4 1959 Gas-Oil 107.0 Fossil Generation Neosho Energy Center:

Steam Turbine 3 1954 Gas--Oil 69.0 Fossil Generation State Line (40%):

Combined Cycle 2-1 (a) 2001 Gas 60.0 Fossil Generation 2-2 (a) 2001 Gas 60.0 Fossil Generation 2-3 (a) 2001 Gas 80.0 Fossil Generation Tecumseh Energy Center:

Steam Turbines 7 1957 Coal 86.0 Fossil Generation 8 1962 Coal 158.0 Fossil Generation Combustion Turbines 1 1972 Gas 20.0 Fossil Generation 2 1972 Gas 21.0 Fossil Generation Wolf Creek Generating Station (47%):

Nuclear I (a) 1985 Uranium 550.0 Nuclear Generation Total 59472 (a) We jointly own Jeffrey Energy Center (84%), LaCygne I generating unit (50%), Wolf Creek Generating Station (47%) and State Line (40%). Unit capacity amounts reflect Western Resources' ownership only.

(b) In 1987, KGE entered into a sale-leaseback transaction involving its 50% interest in the LaCygne 2 generating unit.

25

We own approximately 6,700 miles of transmission lines, approximately 25,000 miles of overhead distribution lines and approximately 3,000 miles of underground distribution lines. (These properties are part of the Customer Operations segment.)

Financing Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued and are outstanding.

MONITORED SERVICES FACILITIES Protection One maintains its executive offices at 818 South Kansas Avenue, Topeka, Kansas 66612.

Protection One and Protection One Europe operate primarily from the following facilities, although Protection One also leases office space for approximately 60 service branch offices and seven satellite branches in North America and Protection One Europe leases offices for approximately 35 sales branch offices in continental Europe.

Protection One:

Size Location (Sq. ft.) Lease/Own Principal Purpose United States:

Addison, TX (a) .......................... 28,512 Lease Monitoring facility/Multifamily administrative headquarters Irving, TX (a) .............................. 53,750 Lease Monitoring facility/administrative headquarters Orlando, FL ................................. 11,020 Lease Wholesale monitoring facility Portland, ME ............................... 9,000 Lease Monitoring facility/local branch Topeka, KS .................................. 17,703 Lease Financial/administrative headquarters Wichita, KS ................................. 50,000 Own Monitoring facility/administrative functions Canada:

Ottawa, ON ................................. 7,937 Lease Monitoring facility/administrative headquarters Vancouver, BC ............................ 5,177 Lease Monitoring facility Protection One Europe:

Size Location (Sq. ft.) Lease/Own Principal Purpose Europe:

Paris, France ................................ 3,498 Lease Financial/Administrative offices/Monitoring facility Vitrolles, France .......................... 27,000 Lease Administrative/Monitoring facility Dusseldorf, Germany ................... 7,800 Lease Administrative/Warehouse Brussels, Belgium ........................ 14,400 Lease Administrative/Warehouse (a) In 2002, the administrative headquarters and monitoring operations for Protection One's Network Multifamily (Multifamily) segment will be relocated to the Irving, Texas facility.

26

ITEM 3. LEGAL PROCEEDINGS The SEC commenced a private investigation in 1997 relating to, among other things, the timeliness and adequacy of disclosure filings with the SEC by us with respect to securities of ADT Ltd. We have cooperated with the SEC staff in this investigation.

We, Westar Industries, Protection One, Protection One Alarm Monitoring and certain present and former officers and directors of Protection One are defendants in a purported class action litigation pending in the United States District Court for the Central District of California, "Alec Garbini, et al v. Protection One, Inc., et al," No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999, four pending purported class actions were consolidated into a single action. On February 27, 2001, plaintiffs filed a Third Consolidated Amended Class Action Complaint (Third Amended Complaint). Plaintiffs purported to bring the action on behalf of a class consisting of all purchasers of publicly traded securities of Protection One, including common stock and bonds, during the period of February 10, 1998 through February 2, 2001. The Third Amended Complaint asserted claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934 against Protection One, Protection One Alarm Monitoring, and certain present and former officers and directors of Protection One based on allegations that various statements concerning Protection One's financial results and operations for 1997, 1998, 1999 and the first three quarters of 2000 were false and misleading and not in compliance with generally accepted accounting principles. Plaintiffs alleged, among other things, that former employees of Protection One have reported that Protection One lacked adequate internal accounting controls and that certain accounting information was unsupported or manipulated by management in order to avoid disclosure of accurate information. The Third Amended Complaint further asserted claims against us and Westar Industries as controlling persons under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. A claim was also asserted under Section 11 of the Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP. The Third Amended Complaint sought an unspecified amount of compensatory damages and an award of fees and expenses, including attorneys' fees. On June 4, 2001, the District Court dismissed plaintiffs' claims under Sections 10(b) and 20(a) of the Securities Exchange Act. The Court granted plaintiffs leave to replead such claims. The Court also dismissed all claims brought on behalf of bondholders with prejudice. The Court also dismissed plaintiffs' claims against Arthur Andersen and the plaintiffs have appealed that dismissal. On February 22, 2002, plaintiffs filed a Fourth Consolidated Amended Class Action Complaint. The new complaint realleges claims on behalf of purchasers of common stock under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The defendants have until April 5, 2002 to respond to the new complaint. Protection One and we cannot predict the impact of this litigation, which could be material.

We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provision has been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect upon our overall financial position or results of operations.

See also Notes 3 and 15 of the "Notes to Consolidated Financial Statements" for discussion of FERC proceedings and the lawsuit PNM filed against us and the KCC regulatory proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of our security holders through the solicitation of proxies or otherwise during the fourth quarter of 2001.

27

PART H ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS STOCK TRADING Our common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of March 14, 2002, there were 35,839 common shareholders of record. For information regarding quarterly common stock price ranges for 2001 and 2000, see Note 27 of the "Notes to Consolidated Financial Statements."

DIVIDENDS Holders of our common stock are entitled to dividends when and as declared by our board of directors.

However, prior to the payment of common dividends, dividends must be first paid to the holders of preferred stock based on the fixed dividend rate for each series and our obligations with respect to mandatorily redeemable preferred securities issued by subsidiary trusts must be met.

Quarterly dividends on common stock and preferred stock normally are paid on or about the first of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Our board of directors reviews its common stock dividend policy from time to time. Among the factors the board of directors considers in determining its dividend policy are earnings, cash flows, capitalization ratios, regulation, competition and financial loan covenants. In March 2000, we announced a quarterly dividend of $0.30 per share (an indicated dividend rate of $1.20 per share on an annual basis). We expect to maintain the dividend at this level in 2002. Our agreement with PNM prohibits an increase in the dividend paid on our common stock without the consent of PNM.

Our Articles of Incorporation contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock at the current rate.

For information regarding quarterly dividend declarations for 2001 and 2000, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." See also Note 18 of the "Notes to Consolidated Financial Statements" included herein.

28

ITEM 6. SELECTED FINANCIAL DATA For the Year Ended December 31, 2001 2000 1999(a) 1998(b) 1997(c)

(In Thousands)

Income Statement Data:

S ales ............................................................ S 2,186,262 S 2,368,476 $2,030,087 S 2,034,054 $ 2,151,765 Net income (loss) before extraordinary gain and accounting change ............................ (62,726) 91,050 2,554 34,058 498,652 Earnings (loss) available for common stoc k ....................................................... (21,771) 135,352 13,167 32,058 493,733 As of December 31, 2001 2000 1999(a) 1998(b) 1997(c)

(In Thousands)

Balance Sheet Data:

Total assets .................................................. S 7,513,065 S 7,801,720 $ 7,989,892 $ 7,929,776 $ 6,945,350 Long-term debt, net, and other mandatorily redeem able securities .............................. 3,198,382 3,457,849 3,103,066 3,283,064 2,391,889 For the Year Ended December 31.

2001 2000 1999(a) 1998(b) 1997(c)

Common Stock Data:

Basic and diluted earnings (losses) per share available for common stock before extraordinary gain and accounting chan ge .................................................... S (0.90) $ 1.30 $ 0.02 5 0.46 $ 7.58 Basic and diluted earnings (losses) per share available for common stock .................... S (0.31) $ 1.96 $ 0.20 $ 0.48 S 7.58 Dividends per share (d) ......................... S 1.20 S 1.44 S 2.14 $ 2.14 $ 2.10 Book value per share ................................... S 25.60 $ 27.20 $ 28.03 S 29.21 S 30.86 Average shares outstanding (000's) ............. 70,650 68,962 67,080 65,634 65,128 (a) Information reflects the impairment of marketable securities and the change to an accelerated amortization method for the monitored services segment's customer accounts.

(b) Information reflects exit costs associated with international power development activities.

(c) Information reflects the gain on the sale of Tyco common shares, our strategic alliance with ONEOK and the acquisition of Protection One.

(d) In March 2000. we announced a new dividend policy. See "Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

- Dividends."

29

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION In Management's Discussion and Analysis, we discuss the general financial condition, significant annual changes and the operating results for us and our subsidiaries. We explain:

- what factors impact our business,

- what our earnings and costs were in 2001, 2000 and 1999,

- why these earnings and costs differ from year to year,

- how our earnings and costs affect our overall financial condition,

- what our capital expenditures were for 2001,

- what we expect our capital expenditures to be for the years 2002 through 2004,

- how we plan to pay for these future capital expenditures,

- critical accounting policies, and

- any other items that particularly affect our financial condition or earnings.

As you read Management's Discussion and Analysis, please refer to our consolidated financial statements and the notes thereto, which show our operating results.

SUMMARY

OF SIGNIFICANT ITEMS PNM Transaction On November 8, 2000, we entered into an agreement with Public Service Company of New Mexico (PNM),

pursuant to which PNM would acquire our electric utility businesses in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and we are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. Immediately prior to closing, all of the Westar Industries common stock we own would be distributed to our shareholders in exchange for a portion of their Western Resources common stock. At the same time we entered into the agreement with PNM, we and Westar Industries entered into an Asset Allocation and Separation Agreement which, among other things, provided for this split-off and related matters.

On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the Kansas Corporation Commission (KCC) orders discussed below and other KCC orders reducing rates for our electric utility business. PNM believes the orders constitute a material adverse effect and make the condition that the split-off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation.

On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court of the State of New York.

The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of our electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, we filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement.

On January 7, 2002, PNM sent a letter to us purporting to terminate the merger in accordance with the terms of the merger agreement. We have notified PNM that we believe the purported termination of the merger agreement was ineffective and that PNM remains obligated to perform thereunder. We intend to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, we believe the closing of the proposed merger is not likely.

30

KCC Rate Cases On November 27, 2000, we and KGE filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our combined electric rates of $22.7 million, consisting of a

$41.2 million reduction in KGE's rates and an $18.5 million increase in our rates.

On August 9, 2001, we and KGE filed petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the KGE acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and several other issues. On September 5, 2001, the KCC issued an order in response to our motions for reconsideration that increased our rate increase by an additional $7.0 million. The $41.2 million rate reduction in KGE's rates remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions with the Kansas Court of Appeals in an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal this decision to the Kansas Supreme Court.

KCC Proceedings and Orders The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of our electric utility businesses from our non-utility businesses, including the rights offering, and other aspects of our unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving our unregulated businesses are consistent with our obligation to provide efficient and sufficient electric service at just and reasonable rates to our electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement we entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by us to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by our unregulated businesses and whether they should continue to be affiliated with our electric utility business, and our present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying the Asset Allocation and Separation Agreement, prohibiting Westar Industries and us from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent.

On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting us and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed us and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in our capital structure applicable to our electric utility operations, which has the effect of prohibiting us from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed us to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of our non-utility businesses. In its order, the KCC also acknowledged that we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. We appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not final orders and that the District Court lacked jurisdiction to consider the appeal.

Accordingly, the matter was remanded to the KCC for review of the financial plan.

On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that we and the KCC staff make filings addressing whether the filing of applications by us and KGE at the Federal Energy Regulatory Commission (FERC), seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that we not increase the share of debt in our capital structure applicable to our electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC filed a motion to intervene in the 31

proceeding at FERC asserting the same position. We are unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on our ability to refinance indebtedness maturing in the next several years. Our inability to refinance existing indebtedness on a secured basis would likely increase our borrowing costs and adversely affect our results of operations.

The Financial Plan The July 20, 2001 KCC order directed us to present a financial plan to the KCC. For details of the financial plan, see Note 15 of the "Notes to Consolidated Financial Statements."

Extraordinary Gain on Extinguishment of Debt During the last three years, Protection One and our bonds were repurchased in the open market and extraordinary gains were recognized on the retirement of these bonds of $23.2 million in 2001, $49.2 million in 2000 and $13.4 million in 1999, net of tax. From January 1, 2002 through February 2002, a gain of $3.6 million, net of tax, was recognized on the repurchase of Protection One and our bonds.

Impairment Charge Pursuant to New Accounting Rules Effective January 1, 2002, we adopted the new accounting standards Statement of Financial Accounting Standard (SFAS) No. 142, "Accounting for Goodwill and Other Intangible Assets," and SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets." SFAS No. 142 establishes new standards for accounting for goodwill. SFAS No. 142 continues to require the recognition of goodwill as an asset, but discontinues amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards.

SFAS No. 144 establishes a new approach to determining whether our customer account asset is impaired.

The approach no longer permits us to evaluate our customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of the goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream to be used under SFAS No. 144 is limited to the future estimated undiscounted cash flows of our existing customer accounts. Additionally, the new rule no longer permits us to include estimated cash flows from forecasted customer additions. If the undiscounted cash flow stream from existing customer accounts is less than the combined book value of customer accounts and goodwill, an impairment charge is required.

The new rule substantially reduces the net undiscounted cash flows used for impairment evaluation purposes as compared to the previous accounting rules. The undiscounted cash flow stream has been reduced from the 16-year remaining life of the goodwill to the nine-year remaining life of customer accounts for impairment evaluation purposes and does not include estimated cash flows from forecasted customer additions.

32

To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of goodwill and customer accounts. Based on this analysis, during the first quarter of 2002, we will record a non-cash net charge of approximately $653.7 million, of which $464.2 million is related to goodwill and

$189.5 million is related to customer accounts. The charge is detailed as follows:

Impairment of Impairment of Goodwill Customer Accounts Total (In Thousands)

Protection One ................................. $ 498,921 $ 334,064 $ 832,985 Protection One Europe ..................... 80,104 -- 80,104 Total pre-tax impairment ................. $ 579025 $ 334,06 913,089 Income tax benefit ........................... (173,650)

M inority interest .............................. (85.713)

Net charge ........................................ .$ 653,726 The impairment charge for goodwill will be reflected in our consolidated statement of income as a cumulative effect of a change in accounting principle. The impairment charge for customer accounts will be reflected in our consolidated statement of income as an operating cost. These impairment charges reduce the recorded value of these assets to their estimated fair values at January 1, 2002.

In 2001, we recorded approximately $57.1 million of goodwill amortization expense. We will no longer be permitted to amortize goodwill to income because of adoption of the new goodwill rule. In 2001, we recorded approximately $153.0 million of customer account amortization expense. Future customer account amortization expense will also be reduced as a result of the impairment charge.

We will be required to perform impairment tests for our monitored services segment for long-lived assets prospectively as long as it continues to incur recurring losses or for other matters that may negatively impact its businesses. Goodwill will be required to be tested each year for impairment. Declines in market values of our monitored services businesses or the value of customer accounts that may be incurred prospectively may require additional write down of these assets in the future.

Estimated Lives of Customer Accounts to Chanae Based on Customer Account Lifing Study Results Protection One is currently evaluating the estimated life and amortization rates for customer accounts, given the results of a lifmg study performed by a third party appraisal firm in the first quarter of 2002. Any change in its amortization rate or estimated life will be determined in the first quarter of 2002 and accounted for prospectively as a change in estimate.

Work Force Reductions In late 200 1, we reduced our utility work force by approximately 200 employees through involuntary separations and recorded a severance-related net charge of approximately $14.3 million. In 2001, Protection One also reduced its work force by approximately 500 employees in connection with facility consolidations and recorded a severance-related net charge of approximately $3.1 million.

In the first quarter of 2002, we further reduced our utility work force by approximately 400 employees through a voluntary separation program. We expect to record a net charge of approximately $21.1 million in the first quarter of 2002 related to this program. We may replace some of these employees. Protection One also reduced its work force by approximately 200 employees in connection with facility consolidations and expects to record a net severance charge of approximately $0.5 million in the first quarter of 2002.

33

Ice Storm In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs could run as high as $25 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application.

Marketable Securities During the fourth quarter of 1999, we decided to sell our remaining marketable security investments in paging industry companies. These securities were classified as available-for-sale; therefore, changes in market value were historically reported as a component of other comprehensive income. The market value for these securities declined during the last six to nine months of 1999. We determined that the decline in value of these securities was other than temporary and a charge to earnings for the decline in value was required at December 31, 1999.

Therefore, a non-cash charge of $76.2 million was recorded in the fourth quarter of 1999 and is presented separately in the accompanying consolidated statements of income.

During the first quarter of 2000, we sold the remainder of our portfolio of paging company securities. We realized a gain of $24.9 million on these sales. This gain was largely attributable to a general increase in the market value of paging companies triggered by an announcement made by one paging company in February 2000 that had a favorable impact on the market value of public paging company securities.

During 2000, we sold our equity investment in a gas compression company and realized a pre-tax gain of

$91.1 million.

During 2001, we wrote down the cost basis of certain equity securities to their fair value. The fair value of these equity securities had declined below our cost basis, and we determined that the decline was other than temporary. The amount of the write down totaled $11.1 million, of which $9.6 million related to a cost method investment. The write down is included in other income (expense).

CRITICAL ACCOUNTING POLICIES Our discussion and analysis of results of operations and financial condition are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (GAAP). The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, investments, customer accounts, goodwill, intangible assets, income taxes, pensions and other post-retirement benefits, and contingencies and litigation. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

Note 2 of the "Notes to Consolidated Financial Statements" includes a summary of the significant accounting policies and methods used in the preparation of our consolidated financial statements. The following is a brief description of the more significant accounting policies and methods used by us.

Regulatory Accounting We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent.

34

Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. We have recorded these regulatory assets and liabilities in accordance with SFAS No. 71. If we were required to terminate application of SFAS No. 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in our consolidated statements of income at that time. As of December 31, 2001, this would reduce our earnings by $352.0 million, net of applicable income taxes.

SFAS No. 71 applies to our fossil generation, nuclear generation, and customer operations business segments. We do not anticipate the discontinuation of SFAS No. 71 in the foreseeable future. See "- Other Information - Electric Utility - Competition and Deregulation" and "- Other Information -Electric Utility

- Stranded Costs" for additional discussion of the application of SFAS No. 71.

Revenue Reco2nition Energy Sales:

Energy sales are recognized as services are rendered and include an estimate for energy delivered but unbilled at the end of each year, except for power marketing. Power marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales in our consolidated statements of income. The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheets.

We primarily use quoted market prices to value our power marketing and energy trading contracts. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The market prices used to value these transactions reflect our best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. Results actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results. Financially settled trading transactions are reported on a net basis, reflecting the financial nature of these transactions. Physically settled trading transactions are recorded on a gross basis in operating revenues and fuel and purchased power expense.

Monitored Services Revenues:

Monitored services revenues are recognized when security services are provided. Installation revenue, sales revenues on equipment upgrades and direct costs of installations and sales are deferred for residential customers with service contracts. For commercial customers and national account customers, revenue recognition is dependent upon each specific customer contract. In instances when the company sells the equipment outright, revenues and costs are recognized in the period incurred. In cases where there is no outright sale, revenues and direct costs are deferred and amortized.

Deferred installation revenues and system sales revenues will be recognized over the expected useful life of the customer. Deferred costs in excess of deferred revenues will be recognized over the contract life. To the extent deferred costs are less than deferred revenues, such costs are recognized over the customers' estimated useful life.

Deferred revenues also result from customers who are billed for monitoring, extended service protection and patrol and response services in advance of the period in which such services are provided, on a monthly, quarterly or annual basis.

Depreciation Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group 35

rates that approximated 3.03% during 2001, 2.99% during 2000 and 2.92% during 1999. In its rate order of July 25, 2001, the KCC extended the recovery period for our generating assets, including Wolf Creek, for regulatory rate making purposes. The impact of this decision reduced our retail electric rates by approximately $17.6 million on an annual basis. We intend to file an application for an accounting authority order with the KCC to allow the creation of a regulatory asset for the difference between our book and regulatory depreciation. We cannot predict whether the KCC will approve our application.

Non-utility property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the related assets. We periodically evaluate our depreciation rates considering the past and expected future experience in the operation of our facilities.

Depreciable lives of property, plant and equipment are as follows:

Utility:

Fossil generating facilities ....................................... 10 to 48 years Nuclear generating facilities .................................... 38 years Transmission facilities ............................................. 27 to 65 years Distribution facilities ............................................... 14 to 65 years O ther ........................................................................ 3 to 50 years Non-utility:

Buildings .................................................................. 40 years Installed system s ...................................................... 10 years Furniture, fixtures and equipment ............................ 5 to 10 years Leasehold improvements ......................................... 5 to 10 years Vehicles ................................................................... 5 years Data processing and telecommunications ................ 1 to 7 years Valuation of Customer Account Intangible Assets Customer accounts are stated at cost. Goodwill represents the excess of the purchase price over the fair value of net assets acquired by Protection One and Protection One Europe. These assets are tested for impairment in accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," on a periodic basis or as circumstances warrant. For purposes of this impairment testing, goodwill is considered to be directly related to the acquired customer accounts. Factors we consider important that could trigger an impairment review include the following:

- high levels of customer attrition;

- continuing recurring Monitored Services losses; and

- declines in the market value of Protection One's publicly traded equity and debt securities.

An impairment would be recognized when the undiscounted expected future operating cash flows by customer pool derived from customer accounts is less than the carrying value of capitalized customer accounts and related goodwill. Protection One and Protection One Europe have performed impairment tests on their customer account assets and goodwill as of December 31, 2001. These tests have indicated that future estimated undiscounted cash flows exceeded the sum of the recorded balances for customer accounts and goodwill. See "- Summary of Significant Items - Impairment Charge Pursuant to New Accounting Rules" for a discussion of the impairment recorded on these assets in the first quarter of 2002 pursuant to the adoption of new accounting rules.

Income Taxes As part of the process of preparing our consolidated financial statements we are required to estimate our income taxes in each of the jurisdictions in which we operate. Significant management judgment is required in determining our provision for income taxes and our deferred tax assets and liabilities. This process involves us estimating our actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation and amortization, for tax and accounting purposes. These differences result 36

in deferred tax assets and liabilities, which are included within our consolidated balance sheet. We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income. To the extent we believe that recovery is not likely, we must establish a valuation allowance. At the current time, we believe our deferred tax assets will be recovered from future taxable income. In the event that actual results differ from these estimates, or we adjust these estimates in future periods, we may need to establish a valuation allowance that could materially impact our financial position and results of operations Cumulative Effect of Accounting Change Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). We use derivative instruments (primarily swaps, options and futures) to manage interest rate exposure and the commodity price risk inherent in fossil fuel purchases and electricity sales. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our consolidated balance sheet as either an asset or liability measured at fair value.

Changes in a derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Cash flows from derivative instruments are presented in net cash flows from operating activities.

Derivative instruments used to manage commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities.

Prior to January 1, 2001, gains and losses on our derivatives used for managing commodity price risk were deferred until settlement. These derivatives were not designated as hedges under SFAS No. 133. Accordingly, on January 1, 2001, we recognized an unrealized gain of $18.7 million, net of $12.3 million of tax. This gain is presented on our consolidated statement of income as a cumulative effect of a change in accounting principle.

After January 1, 2001, changes in fair value of all derivative instruments used for managing commodity price risk that are not designated as hedges are recognized in revenue as discussed above under "- Revenue Recognition - Energy Sales." Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings.

OPERATEIG RESULTS Western Resources Consolidated 2001 compared to 2000:

We reported losses per share of $0.31 in 2001 compared to earnings per share of $1.96 in 2000. This decrease resulted from decreased electricity sales caused by milder weather, the decrease in electric rates in accordance with the July 25, 2001 KCC rate order, higher operating losses at Protection One and Protection One Europe, and the fourth quarter charge related to a work force reduction. Additionally, investment earnings and the extraordinary gains on the retirement of debt were lower in 2001 than in 2000.

2000 compared to 1999:

Earnings per share were $1.96 in 2000 compared to $0.20 in 1999. This increase is primarily attributable to increased earnings from the sale of investments and the extraordinary gain on the retirement of Protection One bonds. This increase was partially offset by a change in the estimated life of goodwill and operating losses from our monitored services segment.

37

Business Segments Our business is segmented based on differences in products and services, production processes and management responsibility. Based on this approach, we have identified five reportable segments: Fossil Generation, Nuclear Generation, Customer Operations, Monitored Services and Other. The Fossil Generation, Nuclear Generation and Customer Operations segments comprise our electric utility business. Fossil Generation produces power for sale internally to the Customer Operations segment and externally to wholesale customers. A component of our Fossil Generation segment is power marketing, which attempts to minimize commodity price risk associated with fuel purchases and purchased power requirements. Power marketing also attempts to maximize utilization of generation capacity and enhance system reliability through sales to external customers as discussed further below.

Nuclear Generation represents our 47% ownership in the Wolf Creek Generating Station (Wolf Creek). This segment has only internal sales because it provides all of its power to its co-owners. The Customer Operations segment consists of the transmission and distribution of power to our retail customers in Kansas and the customer service provided to these customers and the transmission of wholesale energy. Monitored Services is comprised of our security alarm monitoring business in North America and Europe. Other includes a 45% interest in ONEOK, investments in international power generation facilities and other investments, which in the aggregate are not material to our business or results of operations.

We manage our business segments' performance based on their earnings before interest and taxes (EBIT).

EBIT does not represent cash flow from operations as defined by GAAP, should not be construed as an alternative to operating income and is indicative neither of operating performance nor cash flows available to fund our cash needs.

Items excluded from EBIT are significant components in understanding and assessing our financial performance.

We believe presentation of EBIT enhances an understanding of financial condition, results of operations and cash flows because EBIT is used by us to satisfy our debt service obligations, capital expenditures and other operational needs, as well as to provide funds for growth. Our computation of EBIT may not be comparable to other similarly titled measures of other companies.

Electric Utility:

Our electric utility operations supply electric energy at retail to approximately 640,000 customers in Kansas. These customers are classified as residential, commercial and industrial as defined in our tariffs. Sales classifications and the related descriptions for our remaining electricity sales are as follows:

- Wholesale and Interchange: Sales consist of electric energy supplied to the electric distribution systems of 63 Kansas cities and 4 rural electric cooperatives. It also includes contracts for the sale, purchase or exchange of electricity with other utilities and/or marketers.

- Power Marketing: Sales made in areas outside of our historical marketing territory. These sales are non-asset based, which means that we do not use power produced by our generating facilities for these sales.

- System Marketing: Financial transactions entered into on behalf of system requirements.

- Other: Includes public street and highway lighting and miscellaneous electric revenues.

Many things will affect our future electric sales. Our regulated electric utility sales are significantly impacted by such things as the weather, regulation (including rate regulation), customer conservation efforts, wholesale demand, the overall economy of our service area, the City of Wichita's attempt to create a municipal electric utility, and competitive forces. Our sales are impacted by demand outside our service territory, the cost of fuel and purchased power, price volatility and available generation capacity.

38

Our electric sales for the last three years ended December 31 are as follows:

2001 2000 1999 (In Thousands)

Residential ..................................... $ 419,492 $ 452,674 $ 407,371 Comm ercial ................................... 380,277 367,367 356,314 Industrial ....................................... 244,392 252,243 251,391 Other ............................................. 50,669 49,629 46,306 Total retail ................................ $1,094,830 $1,121,913 $1,061,382 Wholesale and Interchange ........... 233,129 214,721 174,895 Power M arketing ........................... 408,242 457,178 190,101 System M arketing .......................... 32.192 35,321 3,320 Total ......................................... $1,768.393 S1.829.133 $1,429,69a The following tables reflect changes in electric sales volumes, as measured by megawatt hours (MWh), for the years ended December 31, 2001, 2000 and 1999. No amounts are included for power marketing and system marketing sales because these sales are not based on electricity we generate.

2001 2000  % Change (Thousands of MWh)

Residential ..................................... 5,755 6,222 (7.5)

Comm ercial ................................... 6,742 6,485 4.0 Industrial ....................................... 5,617 5,820 (3.5)

Other ............................................. 107 108 (0.9)

Total retail ................................ 18,221 18,635 (2.2)

Wholesale and Interchange ........... 7.547 6.892 9.5 Total ......................................... 25.76f8 0.9 2000 1999 (Thousands of MWh)

Residential ..................................... 6,222 5,551 12.1 Comm ercial ................................... 6,485 6.202 4.6 Industrial ....................................... 5,820 5,743 1.3 Other ............................................. 108 108 Total retail ................................ 18,635 17,604 5.9 Wholesale and Interchange ........... 6.892 5.617 22.7 Total ......................................... 25.527 9.9 2001 compared to 2000: Energy sales decreased $60.7 million, or 3%. Residential sales declined 7% and power marketing sales declined 11%. Residential sales decreased due to weather conditions and our rate decrease, while power marketing sales decreased because of lower prices and more power available in the market. Cost of sales increased $5.3 million, or 1%, over 2000. As a result gross profit decreased $66.0 million, or 7%.

This decline in gross profit is partly due to how we were required to record a gain on certain fuel derivatives acquired in 2000 to mitigate the risk of changing prices on our natural gas fuel requirements. Prior to the adoption of SFAS No. 133 on January 1, 2001, gains and losses on these fuel derivatives were deferred until settlement and reflected in gross profit at that time. However, upon adoption of SFAS No. 133, we were required to report our

$31.0 million gain on these contracts as of that date as a cumulative effect of a change in accounting principle. This gain is reported on our consolidated statements of income on a net-of-tax basis below income tax expense. We are not permitted to reflect the cumulative effect of an accounting change in gross profit. As a result, the benefit of our efforts in 2000 to mitigate the risk of price changes on our 2001 fuel requirements is not reflected in gross profit.

39

Had we been permitted to classify this as a reduction to cost of sales, our $66.0 million decline in gross profit would have been reduced by $31.0 million. All gains and losses after January 1, 2001 on our fuel derivatives that are not designated as hedges are reflected in gross profit.

2000 compared to 1999: Electric operations gross profit increased $28.3 million, or 3%. The increase is due primarily to increased power marketing sales. Electric operations gross profit as a percentage of sales decreased to 54% from 67% primarily due to higher fuel and purchased power prices. (See "- Other Information - Market Risk Disclosure" for further discussion.)

Additionally, we experienced a 12% increase in residential sales volumes and a 23% increase in wholesale and interchange sales volumes. The increase in residential sales was primarily due to increased demand caused by warm weather. Cooling-degree days increased by 27%. The increase in wholesale and interchange sales volumes was primarily due to increased wholesale market opportunities.

Items included in energy cost of sales are fuel expense, purchased power expense (electricity we purchase from others for resale) and power marketing expense. Partially offsetting the higher sales was an increase of $371.2 million in cost of sales primarily due to higher power marketing expense of $263.0 million and increased fuel and purchased power expenses of approximately $75.1 million. Fuel and purchased power expenses were higher primarily due to increased commodity prices, increased demand from retail customers because of warmer weather and higher wholesale and interchange sales volumes.

Fossil Generation:

Fossil Generation's external sales consist of the power produced and purchased for sale to wholesale customers and includes power marketing sales, system marketing sales and wholesale and interchange sales. Internal sales consist of the power produced for sale to Customer Operations. Details concerning our earnings before interest and taxes attributable to fossil generation are as follows.

For the years ended December 31, 2001 2000 1999 (In Thousands)

Fossil Generation:

External sales ................................... $667,953 $705,536 $365,311 Internal sales (a) .............................. 560,528 572,533 546,683 Depreciation and amortization ......... 65,875 60,331 55,320 EBIT (b) .......................................... 120,530 202,744 219,087 (a) When sales are made between the segments, the internal transfer price is determined by us using internally developed transfer pricing estimates that, while not based on market rates, represent what we believe would be market prices for capacity and energy.

(b) EBIT for 2001 does not include the unrealized gain on derivatives reported as a cumulative effect of a change in accounting principle as explained above. If the effect had been included, EBIT for the Fossil Generation segment for the year ended December 31, 2001 would have been $151.6 million.

2001 compared to 2000: External sales decreased $37.6 million primarily due to a decrease in power marketing sales of $48.9 million, or 11%, and a decrease in system marketing sales of $3.1 million, or 9%. These decreases were partially offset by an increase in wholesale and interchange sales of $18.4 million, or 9%. The decrease in power marketing sales was primarily due to lower market demand and prices. EBIT decreased $82.2 million primarily due to decreased sales, a $30.8 million non-cash mark-to-market adjustment on fuel derivatives and increased fuel and purchased power expenses. Had SFAS No. 133 permitted us to include the cumulative gain effect in gross profit, EBIT would have decreased $51.2 million.

2000 compared to 1999: External sales increased $340.2 million primarily due to power marketing sales, which increased by $267.1 million, wholesale and interchange sales, which increased by $39.8 million, and system 40

marketing sales, which increased by $32.0 million. Since 1997, we have gradually increased the size of our power trading operation in an effort to better utilize our market knowledge and to mitigate the risk associated with energy prices.

While sales increased significantly, EBIT was $16.3 million lower because of higher cost of sales. Cost of sales was $371.2 million higher primarily due to higher power marketing expense of $263.0 million, increased fuel and purchased power expenses of approximately $71.6 million and system marketing transaction.costs of approximately $33.1 million.

Fuel and purchased power expenses were higher primarily due to increased commodity prices, increased demand from retail customers because of warmer weather and higher wholesale and interchange sales volumes.

The cost of fuel in 2000 was significantly affected by increased gas costs of $13.3 million (despite a 9%

reduction in MMBtu of gas burned). Our average natural gas price increased 45% during the year compared to 1999. Additionally, coal costs increased by $35.1 million, primarily due to increasing the quantities of coal burned in our efforts to minimize gas costs, and cost of oil increased $7.2 million, primarily due to increased price and increasing the quantities of oil burned. See "- Other Information - Market Risk Disclosure" for further discussion.

Nuclear Generation:

Nuclear Generation has only internal sales because all of its power is provided to its co-owners: KGE, Kansas City Power and Light Company (KCPL) and Kansas Electric Power Cooperative, Inc. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek. Details concerning our earnings before interest and taxes attributable to our nuclear generation are as follows:

For the years ended December 31, 2001 2000 1999 (In Thousands)

Nuclear Generation:

Internal sales (a) .............................. $117,659 $107,770 $108,445 Depreciation and amortization ......... 41,046 40,052 39,629 Earnings (losses) before interest and taxes .................................... (19,078) (24,323) (25,214)

(a) When sales are made between the segments, the internal transfer price is determined by us using internally developed transfer pricing estimates that, while not based on market rates, represent what we believe would be market prices for capacity and energy.

Wolf Creek operated the entire year of 2001 without any refueling outages. Wolf Creek shut down for 38 days beginning on September 29, 2000 for its eleventh scheduled refueling and maintenance outage. Internal sales and EBIT increased during 2001 since the unit operated more during 2001 than during 2000. During 1999, there was a 36-day refueling and maintenance outage at Wolf Creek. Since both 2000 and 1999 had refueling outages, the change in internal sales and EBIT between 2000 and 1999 was immaterial.

Wolf Creek has a scheduled refueling and maintenance outage approximately every 18 months. An outage began on March 23, 2002. During an outage, Wolf Creek produces no power for its co-owners; therefore internal sales, EBIT and nuclear fuel expense decrease.

Customer Operations:

Customer Operations' external sales consist of the transmission and distribution of power to our electric retail and wholesale customers. Internal sales consist of the intra-segment transfer price charged to Fossil Generation and Nuclear Generation for the use of the distribution lines and transformers.

41

For the years ended December 31, 2001 2000 1999 (In Thousands)

Customer Operations:

External sales ................................... $1,100,443 $1,123,590 $1,064,385 Internal sales (a) .............................. 317,056 291,927 293,522 Depreciation and amortization ......... 78,235 75,419 71,717 EBIT ................................................ 131,917 171,872 145,603 (a) When sales are made between the segments, the internal transfer price is determined by us using internally developed transfer pricing estimates that, while not based on market rates, represent what we believe would be market prices for capacity and energy.

2001 compared to 2000: External sales decreased $23.1 million, or 2%, and EBIT decreased $40.0 million, or 23%, as a result of less favorable weather conditions and rate reductions ordered by the KCC. Weather conditions resulted in an approximate 8% decrease in residential sales volumes. In our service territory, the heating season of 2001 was warmer than the heating season of 2000, which caused customers to use less energy heating their homes during the winter. Additionally, the cooling season of 2001 was cooler than in 2000, which caused customers to use less energy to cool their homes during the summer.

2000 compared to 1999: External sales increased $59.2 million, or 6% and EBIT increased $26.3 million, or 18%. We experienced a 12% increase in residential sales volumes primarily due to a 27% increase in cooling degree days and a 15% increase in heating-degree days, which increased the demand for power on our system.

Monitored Services:

Protection One and Protection One Europe comprise our monitored services business segment. The results discussed below reflect Monitored Services on a stand-alone basis. These results do not take into consideration Protection One's minority interest of approximately 13% at December 31, 2001 and 15% at December 31, 2000 and 1999. Details concerning our earnings before interest and taxes attributable to our monitored services segment are as follows:

For the years ended December 31, 2001 2000 1999 (In Thousands)

External sales ................................... $ 416,509 $ 537,859 $ 599,105 Depreciation and amortization ......... 228,123 248,414 233,906 Earnings (losses) before interest and taxes .................................... (126,076) (91,370) (20,675) 2001 compared to 2000: Sales decreased $121.4 million primarily due to a decline in Monitored Services' average customer base and the disposition of certain operations. Monitored Services experienced a net decline of 267,347 customers in 2001. This decrease in customers is primarily attributable to customer attrition and a decrease of 63,875 customers due to the disposition of operations. Additionally, the number of Protection One customers declined by 62,443 customers due to the conversion of accounts to a common billing and monitoring system. This new system reports number of customer accounts on the basis of one customer for every location provided service even if Protection One has separate contracts to provide multiple services at that location. Previous systems utilized a number of different billing and monitoring software programs, some of which would count each separate contracted service as a separate account regardless of the location. Protection One's customer acquisition strategies have not been able to generate accounts in a sufficient volume at an acceptable cost to replace accounts lost through attrition. See "- Other Information - Monitored Services - Attrition" below for discussion regarding attrition.

Protection One expects this trend will continue until the efforts it is making to acquire new accounts and reduce attrition become more successful than they have been to date. Until it is able to reverse this trend, net losses of customer accounts will materially and adversely affect its business, financial condition and results of operations. In 42

2001, Protection One focused on the completion of its infrastructure projects, cost reductions, the development of cost effective marketing programs and the generation of positive cash flow.

Loss before interest and taxes increased $34.7 million due primarily to the decrease in sales. Cost of sales decreased $41.6 million primarily due to the discontinuation of Protection One's Patrol services in May 2001, consolidation of Protection One customer monitoring facilities, a reduction of Protection One's telecommunications expense, consolidation of monitoring and customer service functions and the decline in customer accounts caused by dispositions of operations and attrition. See "- Other Information - Monitored Services - Attrition" below for additional information.

2000 compared to 1999: Sales decreased $61.0 million primarily due to a decline in customer base and the effect of the adoption of Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition." Adoption of SAB No.

101 reduced revenue by $10.9 million. In North America, Protection One had a net decrease of 141,527 customers in 2000 as compared to a net increase of 8,595 customers in 1999. The decrease in customers is primarily attributable to the fact that Protection One's present customer acquisition strategies were not able to generate accounts in a sufficient volume at acceptable costs to replace accounts lost through attrition. Protection One expects this trend will continue until the efforts it is making to acquire new accounts and reduce attrition become more successful than they have been to date. Until Protection One is able to reverse this trend, net losses of customer accounts will materially and adversely affect its business, financial condition and results of operations. In 2000, Protection One focused on the completion of its infrastructure projects, the development of cost effective marketing programs, the development of its commercial business and the generation of positive cash flow. Protection One Europe had a net increase of 9,115 customers. The increase was primarily due to internal marketing efforts.

Losses before interest and taxes increased $70.7 million due to lower sales, higher cost of sales and lower other income. Cost of sales increased $5.7 million due to increased compensation costs for additional personnel hired at Protection One's monitoring centers, an increase in the cost of parts and materials, and increased vehicle costs. Other income decreased because Protection One recorded a $17.2 million gain on the sale of the Mobile Services Group in the third quarter of 1999.

Depreciation and amortization expense increased by $14.5 million primarily due to the change in the estimated life of goodwill which was reduced from 40 years to 20 years.

Operating and maintenance expense decreased $13.6 million primarily due to declines in third party monitoring costs, signs and decals, printing and compensation expenses. These decreases are a direct result of the significant decline in the number of new accounts acquired during 2000 primarily due to the restructuring of Protection One's dealer program.

WESTERN RESOURCES CONSOLIDATED The following discussion addresses changes in other items affecting net income but not affecting gross profit. Where a specific distinction based on segment cannot be determined for the items below, an allocation percent is used to determine the amounts to be applied to the segments for the calculation of EBIT. Since actual amounts for these items are not maintained by segment, they are discussed below in relation to the company as a whole, rather than as they may relate to specific reporting segments.

Operating Expenses 2001 compared to 2000:

In 2001, operating expenses increased $12.7 million primarily as a result of approximately $8.7 million of costs associated with the PNM transaction, approximately $28.5 million in employee-severance costs related to the work force reductions, and approximately $13.1 million associated with the dispositions of monitored services operations. Partially offsetting these increased costs were decreases in Monitored Services' depreciation and amortization expense of $20.3 million and reduced acquisition expenses of $7.8 million. The decline in depreciation 43

and amortization expense is primarily due to the accelerated depreciation of the billing and general ledger system Protection One used in 2000 and the change in the method of amortization utilized. The reduction in acquisition expense is primarily due to the reduced level of account acquisitions in 2001 as compared to 2000.

2000 compared to 1999:

Operating expenses increased $13.7 million primarily due to increased depreciation and amortization expense of $22.7 million, of which $14.5 million relates to Monitored Services operations. Offsetting this increase is a $17.6 million charge in 1999 for deferred KCPL merger costs related to termination of the KCPL merger. Selling, general and administrative expenses were also higher due to a reduction of $5.6 million in 1999 related to international power development costs.

Other Income (Expense) 2001 compared to 2000:

Other income was $57.6 million in 2001 compared to $201.0 million in 2000. Other income in 2001 includes $41.8 million of ONEOK investment income, a $5.3 million pre-tax gain related to the sale of Paradigm Direct LLC (Paradigm) and $7.6 million of interest income. These earnings were partially offset by impairment charges of $ 11.1 million recorded for declines in the value of marketable securities and other investments that were considered other than temporary in nature. The other income in 2000 includes $45.3 million of ONEOK investment income, a $91.1 million pre-tax gain on the sale of our investment in a gas compression company, a $24.9 million pre-tax gain on the sale of investments in paging companies, $7.8 million in equity earnings on investments and $9.8 million of interest income.

2000 compared to 1999:

Other income increased $214.4 million primarily due to gains recorded in 2000 of $91.1 million on the sale of our remaining investment in a gas compression company and $24.5 million on the sale of marketable securities.

During 1999, a special charge of $76.2 million was recorded related to our paging securities portfolio and a gain of

$17.2 million was recorded on the sale of Protection One's Mobile Services Group.

Interest Expense 2001 compared to 2000:

Interest expense decreased $21.3 million due to lower interest rates and lower outstanding debt at Protection One. The weighted average interest rate on our revolving credit facility declined to 3.44% at December 31, 2001 from 8.11% at December 31, 2000.

2000 compared to 1999:

We retired long-term debt during 2000 and 1999, causing long-term debt interest expense to decrease by

$10.0 million for the year ended December 31, 2000. The retirements included Western Resources' first mortgage bonds of $125 million in 1999 and $75 million in 2000. In the fourth quarter of 1999 and during 2000, Protection One retired bonds with an aggregate face value of $237.9 million. For more information, see "- Liquidity and Capital Resources" below.

Short-term debt interest expense was $5.5 million higher due to increased short-term borrowings under our credit facilities. The majority of this short-term debt was repaid in the third quarter of 2000 with proceeds from the

$600 million term loan.

44

Income Taxes 2001 compared to 2000:

Income taxes decreased $126.9 million in 2001 compared to 2000. This was primarily due to the decreased earnings before income taxes in 2001 resulting from the factors discussed previously. Our overall effective tax rate changed from a 33.6% expense in 2000 to a 56.3% benefit in 2001. The change in our effective tax rate was primarily due to decreased earnings before income taxes in 2001. The tax benefit from decreased earnings combined with our net tax benefits from dividends received, low income housing tax credits, the amortization of prior years' investment tax credits, the amortization of non-deductible goodwill, and the tax benefits from corporate-owned life insurance created this change in the effective tax rate.

2000 compared to 1999:

Income taxes increased $78.3 million in 2000 compared to 1999. This was primarily due to the increased earnings before income taxes in 2000 resulting from the factors discussed previously. Our overall effective tax rate increased from a 108.6% benefit in 1999 to a 33.6% expense in 2000. The increase in our effective tax rate was primarily due to increased earnings before income taxes in 2000. This increase in earnings before income taxes reduces the impact of our net tax benefits (as mentioned previously) on the effective tax rate.

LIQUIDITY AND CAPITAL RESOURCES Overview Most of our cash requirements consist of capital expenditures and maintenance costs associated with the electric utility business, cash needs of our monitored services business, debt service and cash payments of common stock dividends. Our ability to attract necessary financial capital on reasonable terms is critical to our overall business plan. Historically, we have paid for these items with cash from operations and the issuance of stock or long- or short-term debt. Our ability to provide the cash, stock or debt to fund our capital expenditures depends upon many things, including available resources, our financial condition and current market conditions.

We had $96.7 million in cash and cash equivalents at December 31, 2001. We consider cash equivalents to be highly liquid investments with a maturity of three months or less when purchased. We also had $14.8 million of restricted cash classified as a current asset. The current asset portion of our restricted cash consists primarily of cash held in escrow as required by certain letters of credit. In addition, we had $38.5 million of restricted cash classified as a long-term asset. The long-term restricted cash consists primarily of $34.1 million cash held in escrow as required by the terms of a pre-paid capacity and transmission agreement and $4.4 million cash used to collateralize letters of credit and cash held in escrow.

At December 31, 2001, current maturities of long-term debt increased $118.8 million from 2000 primarily because $100 million of our first mortgage bonds due August 15, 2002 were moved to current maturities.

On June 28, 2000, we entered into a $600 million, multi-year term loan that replaced two revolving credit facilities that matured on June 30, 2000. We had $591 million outstanding on the term loan at December 31, 2001.

The term loan is secured by our and KGE's first mortgage bonds and has a maturity date of March 17, 2003. The term loan agreement contains requirements for maintaining certain consolidated leverage ratios, interest coverage ratios and consolidated debt to capital ratios. At December 31, 2001, we were in compliance with all of these requirements. In January 2002, we repaid $44 million of the term loan with the proceeds of our sale of investments in low income housing tax credit partnerships. The outstanding balance of the term loan after this prepayment was

$547 million. In March 2002, we entered into an amendment to the term loan that adds to the calculation of consolidated earnings before interest, taxes, depreciation and amortization, the severance costs incurred in the fourth quarter of 2001 and the first quarter of 2002 related to our work force reductions, and maintains the current maximum consolidated leverage ratio of 5.75 to 1.0 through the maturity date of the term loan in March 2003. We expect to be in compliance with all covenants through the remaining term of this agreement.

45

Maturities of the term loan through March 17, 2003 are as follows:

Principal Year Amount (In Thousands) 2002 $ 6,000 2003 541,000 Interest on the term loan is payable on the expiration date of each borrowing under the facility or quarterly if the term of the borrowing is greater than three months. For the year ended December 31, 2001, the weighted average interest rate on the term loan, including amortization of fees and interest swaps was 7.9%.

Effective October 4, 2001, we entered into a $500 million interest rate swap agreement with a term of two years. The effect of the swap agreement is to fix the annual interest rate on the term loan at 6.18%. At December 31, 2001, the variable rate associated with this debt was 4.68%. This reduces our interest rate exposure due to variable rates. The swap is being accounted for as a cash flow hedge.

We also have an arrangement with certain banks to provide a revolving credit facility on a committed basis totaling $500 million. The facility is secured by our and KGE's first mortgage bonds and matures on March 17, 2003. Borrowings on this facility were $222.3 million at December 31, 2001 and $366.0 million at March 21, 2002.

Under the terms of the agreement, we are required, among other restrictions, to maintain a total debt to total capitalization ratio of not greater than 65% at all times. We are in compliance with this covenant. At December 31, 2001, the capitalization ratio was 61.4%. Under the terms of the facility, the impairment charge to be recorded in the first quarter of 2002 will not affect compliance with this covenant in future periods.

We have registered securities for sale with the Securities and Exchange Commission (SEC). As of December 31, 2001, these included $400 million of unsecured senior notes, $500 million of our first mortgage bonds, $50 million of KGE first mortgage bonds and approximately 11.2 million of our common shares.

Our ability to issue additional debt and equity securities is restricted under limitations imposed by the Articles of Incorporation and the Mortgage and Deed of Trusts of Western Resources and KGE.

Our mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain reftndings) unless our unconsolidated net earnings available for interest, depreciation and property retirement (which as defined, does not include earnings or losses attributable to the ownership of securities of subsidiaries), for a period of 12 consecutive months within 15 months preceding the issuance, are not less than the greater of twice the annual interest charges on, or 10% of the principal amount of, all first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. As of December 31, 2001, no additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with refundings.

KGE's mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless KGE's net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than either two and one-half times the annual interest charges on, or 10% of the principal amount of, all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. As of December 31, 2001, approximately $279 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage.

46

The table below shows the projected future cash payments for our contractual obligations existing at December 31, 2001:

At December 31, 2001: Payments Due by Period Contractual Obligations Total 2002 2003 -2004 2005-2006 Thereafter (Dollars in Thousands)

Long-term debt .................................................... $3,138,958 $ 160,576 S 1,079M542 S 406,871 S 1,491,969 Operating leases .................................................. 830,771 69,897 125,264 119,292 516,318 Fossil fuel ............................................................ 2,099,778 229,675 323,945 213,718 1,332,440 Nuclear fuel ......................................................... 84,038 27,449 10,389 46,200 Unconditional purchase obligations (a) ................ 10,150 4 060 6 090 Total contractual obligations ....................... $6J._63_695 S_4_4_208 $l,562 2 _ S_50.210 $3,3_86U27 (a) Represents Protection One's contract tariff for telecommunication services.

The table below shows our total commercial commitments and the expected expiration per period:

At December 31, 2001: Amount of Commitment Expiration Per Period Total Amounts Other Commercial Commitments Committed 2002 2003 -2004 2005 -2006 Thereafter (Dollars in Thousands)

Lines of credit ..................................................... S 507,000 S 7,000 S 500,000 Standby letters of credit ...................................... 12,687 9,937 S -- 2,750 Total commercial commitments ................. $E5J9.68_7 S_ 00 0.0 $__ _--_ _S 2 ,750 Credit Ratin2s Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and Moody's Investors Service (Moody's) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies' assessment of our ability to pay interest and principal on these securities. On June 1, 2001, Moody's placed our ratings under review with direction uncertain. On October 19, 200 1, S&P removed us from its CreditWatch listing and changed our and KGE's ratings outlook to "negative." On November 7, 2001, S&P reaffirmed its negative outlook for us.

As of March 14, 2002, ratings with these agencies are as follows:

Western Resources Western KGE Protection One Protection One Mortgage Resources Mortgage Senior Senior Bond Unsecured Bond Unsecured Subordinated Rating Debt Rating Debt Unsecured Debt S&P .............. BBB BB BB+ B CCC+

Fitch ............. BB+ BB BB+ B CCC+

M oody's ........ Bal Ba2 Bal B3 Caa2 In general, declines in our credit ratings make debt financing more costly and more difficult to obtain on terms which are economically favorable to us.

Credit rating agencies are applying more stringent guidelines when rating utility companies due to increasing competition and utility investment in non-utility businesses. We do not have any credit rating conditions in any of the agreements under which our debt has been issued.

Sale of Accounts Receivable On July 28, 2000, we entered into an asset-backed securitization agreement under which we periodically transfer an undivided percentage ownership interest in a revolving pool of our accounts receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a 47

special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities." The agreement was renewed on July 26, 2001, and is annually renewable upon agreement by all parties.

Under the terms of the agreement, we may transfer accounts receivable to the bankruptcy-remote SPE and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million (and upon request, subject to certain conditions, up to $175 million), in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned and consolidated. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE's receivables, including delinquency rates and debtor concentrations. We service the receivables transferred to the SPE and receive a servicing fee. These servicing fees are eliminated in consolidation.

Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit resulting in an adjustment to the outstanding conduit interest.

We record administrative expense on the undivided interest owned by the conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the year ended December 31, 2000. These expenses are included in other income (expense) in our consolidated statements of income.

The outstanding balance of SPE receivables was $43.3 million at December 31, 2001 and $85.5 million at December 31, 2000, which is net of an undivided interest of $100.0 million and $115.0 million in receivables sold by the SPE to the conduit. Our retained interest in the SPE's receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit's ownership interest in the SPE's receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit, and to absorb all credit losses incurred on any of the SPE's receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets.

Cash Flows from (used in) Operating Activities Our primary sources of operating cash flows are the operations of our electric utility and monitored services businesses and dividends from our ONEOK investment. Cash flows from operating activities decreased $187.0 million to $224.8 million in 2001, from $411.8 million in 2000. This decrease is mostly attributable to changes in our working capital. Operating cash flows in 2001 also decreased due to the continued decline in Protection One's and Protection One Europe's customer base, which reduces our recurring monthly cash flow stream. Operating cash flows also decreased in 2001 as we purchased additional coal to restock our inventory from the levels that existed in December 2000.

Cash flows from operating activities increased $43.3 million to $411.8 million in 2000, from $368.4 million in 1999. This increase is mostly attributable to the initial sale of accounts receivable in June 2000 offset by a decrease in utility gross margin percentage for 2000 compared to 1999. The decrease in gross margin percentage negatively affected operating cash flows as our cost of sales for the utility increased at a greater rate than sales in 2000 due to increasing fuel prices and an increase in the use of purchased power.

Cash Flows from (used in) Investing Activities In general, cash used for investing purposes relates to the growth and maintenance of the operations of our utility and monitored services businesses. The utility business is capital intensive and requires significant investment in plant on an annual basis. We spent $227.0 million in 2001 and $285.4 in 2000 on net additions to utility property, plant and equipment, including $52.2 million in 2001 and $87.7 million in 2000 on new generation projects. This was in addition to our normal maintenance requirements. The monitored services business also requires significant capital investment related to the acquisition of customer accounts. Investment in customer accounts in 2001 and 2000 amounted to $36.5 million and $47.3 million, respectively.

Investing cash flows were also impacted significantly by the sale of marketable security investments and the 48

dispositions of non-strategic monitored services businesses. These activities produced cash of $50.8 million and

$218.6 million in 2001 and 2000, respectively. We do not expect these to be sources of significant cash in 2002.

Investing activities in 1999 required significantly more cash than in 2000 because Protection One invested

$268.4 million in the purchase of customer accounts and security alarm businesses.

Cash Flows from (used in) Financing Activities We had a net cash flows from financing activities of $24.5 million in 2001 compared to net cash flows used in financing activities of $328.0 million in 2000. In 2001, an increase in short-term debt was the principal source of cash flows from financing activities. Cash from financing activities was used to fund our required investment in operations, the retirement of Protection One's long-term debt, and the payment of dividends on our common stock.

In 2000, we reduced our annual dividend from $2.14 to $1.20 per share. This reduction, and continued reinvestment of dividends by our shareholders through the dividend reinvestment program, resulted in a significant reduction in our net cash dividend requirements.

Future Cash Requirements We believe that internally generated funds and access to capital markets will be sufficient to meet our operating and capital expenditure requirements, debt service and dividend payments through at least the year 2004.

Uncertainties affecting our ability to meet these requirements include the factors affecting sales described above, the impact of inflation on operating expenses, regulatory actions, the impact of the rate reduction, our ability to consummate the financial plan furnished to the KCC and to refinance our outstanding debt discussed under

"- Summary of Significant Items - KCC Proceedings and Orders" above, compliance with future environmental regulations, municipalization efforts by the City of Wichita and the impact of our monitored services' operations and financial condition.

Additionally, our ability to access capital markets will affect the new and existing credit agreements we have available to meet our operating and capital expenditure requirements, debt service and dividend payments. We have $160.6 million of long-term debt that will mature in 2002 and $715.4 million of long-term debt and a $500 million revolving credit facility that will mature in 2003. Additionally, we have $384.3 million of putable/callable bonds that may either mature in August 2003 or be remarketed and repriced at current rates and which will mature in 2018. We believe we will be successful in refinancing these obligations but can give no assurance that these financings will be completed at similar costs to maturing debt.

We forecast that we will need additional generating capacity of approximately 150 MW by 2006 to serve our customer's expected electricity needs. We will determine how to meet this need at a future date.

Our business requires significant capital investments. We currently expect that through the year 2004, we will need cash mostly for:

- Ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service.

- Improving operations within the monitored services business and the acquisition of customer accounts.

Capital expenditures for 2001 and anticipated capital expenditures for 2002 through 2004 are as follows:

Fossil Nuclear Customer Monitored Generation Generation Operations Services Total (In Thousands) 2001 ............. $ 116,595 $ 27,349 $ 83,052 $ 45,944 $ 272,940 2002 ............. 58,000 10,000 86,800 41,100 195,900 2003 ............. 70,100 30,100 86,800 43,800 230,800 2004 ............. 69,400 30,100 86,800 47,500 233,800 49

These estimates are prepared for planning purposes and will be revised from time to time. See Note 2 of the "Notes to Consolidated Financial Statements." Actual expenditures will differ from our estimates.

Maturities of long-term debt as of December 31, 2001 are as follows:

Principal Year Amount (In Thousands) 2002 (a ....................... $ 160,576 2003 ............................ 715,414 2004 ............................ 364,128 2005 ............................ 306,414 2006 ............................ 100,457 Thereafter ................... 1,491,969

$3,138,958&

(a) Amount due includes $38.5 million related to the sale of investments required to be repaid under the mandatory prepayment provisions of our credit agreement.

Capital Structure Our capital structure at December 31, 2001 and 2000 was as follows:

Pro forma 2001 2000 2001 (a)

Shareholders' equity ................................................................................ 36% 35% 26%

Preferred stock ........................................................................................ I 1 1 Western Resources obligated mandatorily redeemable preferred securities of subsidiary trust holding solely company subordinated debentures ................................................................... 4 4 5 Long-term debt, net ................................................................................. 59 60 68 Total ................................................................................................ 10Q% 10Q0% 100%

(a) Subsequent to December 31, 2001, we recorded an impairment of our goodwill and customer accounts as more fully described in "- Summary of Significant Items - Impairment Charge Pursuant to New Accounting Rules." Had that charge occurred prior to year-end, our 2001 capital structure would have been as shown above in the "Pro forma 2001" column.

Dividend Policy Our board of directors reviews our dividend policy from time to time. Among the factors the board of directors considers in determining our dividend policy are earnings, cash flows, capitalization ratios, competition and financial loan covenants. Provisions in our Articles of Incorporation contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock at the current rate. Our agreement with PNM prohibits an increase in the dividend paid on our common stock without the consent of PNM.

Debt and Eouitv Repurchase Plans Westar Industries and Protection One may, from time to time, purchase Protection One's debt and equity securities in the open market or through negotiated transactions. We, Westar Industries and Protection One may also 50

purchase our debt and equity. The timing and terms of purchases and the amount of debt or equity actually purchased will be determined based on market conditions and other factors.

OTHER INFORMATION Electric Utility City of Wichita Municipalization Effort:

In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system and arrange for its own power supply.

These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize KGE's retail electric utility business in Wichita. KGE will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material.

KGE's franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, KGE will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita, metropolitan area account for approximately 23% of our total energy sales.

FERC Proceedings:

On September 12, 2001, we filed a settlement between the FERC staff and Westar Generating, Inc. (Westar Generating), the wholly owned subsidiary that owns our interests in the State Line generating facility. The settlement establishes the rate at which we will buy power from Westar Generating. FERC has jurisdiction over the establishment of this rate because of our affiliate relationship with Westar Generating. We continue to work toward a global settlement with the KCC, the only other active party, but can make no assurance on a resolution.

In September 1999, the City of Wichita filed a complaint with FERC against us alleging improper affiliate transactions between our KPL division and KGE. The City of Wichita asked that FERC equalize the generation costs between KPL and KGE, in addition to other matters. After hearings on the case, a FERC administrative law judge ruled in our favor confirming that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. On January 5, 2001, we filed a brief opposing the City's position. On November 23, 2001, FERC issued an order affirming the judge's decision. We anticipate no further activity regarding this complaint because the City of Wichita's time to appeal FERC's order has expired.

Competition and Deregulation:

Electric utilities have historically operated in a rate-regulated environment. Federal and state regulatory agencies having jurisdiction over our rates and services and other utilities have initiated steps that were expected to result in a more competitive environment for utility services. The Kansas Legislature took no action on deregulation in 2001 or 2000.

In a deregulated environment, utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits. Possible types of competition include cogeneration, self generation, retail wheeling, or municipalization. Retail wheeling is the ability of individual customers to choose a 51

power provider other than us and we would provide the transmission service for this power. Kansas does not allow retail wheeling and no such regulation is pending or being considered. However, if retail wheeling were implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. Our rates range from approximately 10% to 20% below the national average for retail customers. Because of these rates, we expect to retain a substantial part of our current volume of sales in a competitive environment.

Increased competition for retail electricity sales may in the future reduce our earnings, which could impact our ability to pay dividends and could have a material adverse impact on our operations and our financial condition.

A material non-cash charge to earnings may be required should we discontinue accounting under SFAS No. 71. See

"- Stranded Costs" below for additional information regarding SFAS No. 71.

The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted the FERC to order electric utilities to allow third parties the use of their transmission systems to sell electric power to wholesale customers. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order No. 2000) encouraging formation of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive markets in bulk power.

After the FERC rejected several attempts by the Southwest Power Pool (SPP) to seek RTO status, the SPP and the Midwest Independent System Operator (MISO) agreed in October 2001 to consolidate and form an RTO. In December 2001, the FERC approved this newly formed MISO as the first RTO. The agreement to consolidate was executed in February 2002 and the transaction is expected to close in 2003. This new organization will operate our transmission system as part of an interconnected transmission system encompassing over 120,000 MW of generation capacity located in 20 states. MISO will collect revenues attributable to the use of each member's transmission system, and each member will be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire MISO system. Although each member will have priority over the use of its own transmission facilities for selling power to its wholesale customers or others, each member will be charged the same uniform transmission rate as other energy suppliers who are able to sell power to them. We intend to file with the FERC and the KCC to transfer control over the operation of our transmission facilities to MISO. We anticipate that FERC Order No. 2000 and our participation in the MISO will not have a material effect on our operations.

Stranded Costs:

The definition of stranded costs for a utility business is the investment in and carrying costs on property, plant and equipment and other regulatory assets that exceed the amount that can be recovered in a competitive market. We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our fossil generation, nuclear generation and customer operations. If we determine that we no longer meet the criteria of SFAS No. 71, we may have a material extraordinary non-cash charge to earnings. Reasons for discontinuing SFAS No. 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred, a significant change by regulators from a cost-based rate regulation to another form of rate regulation and the impact should the City of Wichita municipalization efforts be successful. We periodically review SFAS No. 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS No. 71 accounting treatment based upon competitive or other events, such as the successful municipalization efforts by areas we serve, the value of our net regulatory assets and our utility plant investments, particularly Wolf Creek, may be significantly impacted.

Regulatory changes, including competition or successful municipalization efforts by the City of Wichita, could adversely impact our ability to recover our investment in these assets. As of December 31, 2001, we have recorded regulatory assets that are currently subject to recovery in future rates of approximately $358.0 million. Of this amount, $221.4 million is a receivable for income tax benefits previously passed on to customers. The remainder of the regulatory assets are items that may give rise to stranded costs, including debt issuance costs, deferred employee benefit costs, deferred plant costs, and coal contract settlement costs.

52

In a competitive environment or because of such successful municipalization efforts, we may not be able to fully recover our entire investment in Wolf Creek. KGE presently owns 47% of Wolf Creek. We may also have stranded costs from an inability to recover our environmental remediation costs and long-term fuel contract costs in a competitive environment. If we determine that we have stranded costs and we cannot recover our investment in these assets, our future net utility income will be lower than our historical net utility income has been unless we compensate for the loss of such income with other measures.

Nuclear Decommissioning:

Decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant. The Nuclear Regulatory Commission (NRC) will terminate a plant's license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund decommissioning. These plans are designed so that funds required for decommissioning will be accumulated during the estimated remaining life of the related nuclear power plant.

We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs, which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund.

On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost Study on April 26, 2000. Based on the study, our share of Wolf Creek's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $631 million during the period 2025 through 2034, or approximately $221 million in 1999 dollars.

These costs include decontamination, dismantling and site restoration and were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1999 of 26 years. The actual decommissioning costs may vary from the estimates because of changes in the assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs for labor, materials and equipment. On May 26, 2000, we filed an application with the KCC requesting approval of the funding of our decommissioning trust on this basis. Approval was granted by the KCC on September 20, 2000.

Decommissioning costs are currently being charged to operating expense in accordance with prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated $4.0 million in 2001 and will increase annually to $5.5 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.8%.

Our investment in the decommissioning fund, including reinvested earnings, approximated $66.6 million at December 31, 2001 and $64.2 million at December 31, 2000. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability.

Asset Retirement Obligations:

In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When it is initially recorded, we will capitalize the estimated asset retirement obligation by increasing the carrying amount of the related long-lived asset. The liability will be accreted to its present value each period and the capitalized cost will be depreciated over the life of the asset.

The standard is effective for fiscal years beginning after June 15, 2002. We expect to adopt this standard January 1, 2003. This standard will impact the way we currently account for the decommissioning of Wolf Creek. In addition to the accounting for the Wolf Creek decommissioning, we are also reviewing what impact this pronouncement will have on our current accounting practices and our results of operations as it relates to other asset retirement obligations we may identify. The impact is unknown at this time. We do not believe that such changes, if required, 53

would adversely affect our operating results due to our current ability to recover decommissioning costs through rates.

Monitored Services Attrition:

Customer attrition has a direct impact on the results of our monitored security operations since it affects its revenues, amortization expense and cash flow. In some instances, estimates are used to derive attrition data.

Adjustments are made to lost accounts primarily for the net change, either positive or negative, in the wholesale base and for accounts which are covered under a purchase price holdback and are "put" back to the seller. The gross accounts lost during a period are reduced by the amount of the guarantee provided for in the purchase agreements with sellers. In some cases, the amount of the purchase holdback may be less than actual attrition experience. The gross accounts lost during a period are not reduced by "move in" accounts, which are accounts where a new customer moves into a home installed with a Protection One security system and vacated by a prior customer, or "competitive takeover" accounts, which are accounts where the owner of a residence monitored by a competitor requests that we provide monitoring services. The decreases due to the conversions to MAS were excluded in the calculation of attrition for the periods indicated below.

For the year ended December 31, 2001, gross accounts lost were further reduced by 126,318 customers for account dispositions and for adjustments resulting from the conversion of Protection One's Wichita, Hagerstown, Beaverton and Irving billing and monitoring systems to a new technology platform, MAS. The conversion adjustments relate to how a customer is defined and the transition of that definition from one system to another in Protection One's new billing and monitoring system, referred to as MAS, or Monitored Automation Systems, which reports number of accounts on the basis of one for every location Protection One provides service even if it has separate contracts to provide multiple services at that location. Protection One anticipates further adjustments, which could be either positive or negative, from the conversion of its Portland, Maine monitoring station to MAS in 2002. These conversions are substantially complete at the present time.

Actual attrition experience shows that the relationship period with any individual customer can vary significantly. Customers discontinue service for a variety of reasons, including relocation, service issues and cost.

A portion of the acquired customer base can be expected to discontinue service every year. Any significant change in the pattern of historical attrition experience would have a material effect on Monitored Services' results of operations.

Attrition is monitored each quarter based on a quarterly annualized and trailing twelve-month basis. This method utilizes the average customer account base for the applicable period in measuring attrition. Therefore, in periods of customer account growth, customer attrition may be understated and in periods of customer account decline, customer attrition may be overstated.

Customer attrition for the years ended December 31, 2001 and 2000 is summarized below.

Customer Account Attrition December 31, 2001 December 31, 2000 Annualized Trailing Annualized Trailing Fourth Twelve Fourth Twelve Quarter Month Quarter Month Protection One ............................. 18.1% 15.2% 15.0% 14.0%

Protection One Europe (a) ............ 11.4% 10.9% 11.6% 10.9%

(a) United Kingdom operations were disposed of in June 2001.

Our monitored services segment had a net decrease of 267,347 customers from December 31, 2000 to December 31, 2001. The number of customers decreased primarily because Monitored Services' customer acquisition strategies were not able to generate accounts in a sufficient volume at acceptable costs to replace 54

accounts lost through attrition. We expect that this trend will continue until the efforts being made to acquire new accounts at acceptable costs and reduce attrition become more successful than they have been to date. Until this trend has been reversed, net losses of customer accounts will materially and adversely affect monitored services' business, financial condition, results of operations and prospects.

Related Party Transactions Below we describe significant transactions between us and Westar Industries and other subsidiaries and related parties. We have disclosed significant transactions even if these have been eliminated in the preparation of our consolidated results and financial position since our proposed financial plan, as discussed in Note 15 in the "Notes to Consolidated Financial Statements," calls for a split-off of Westar Industries from us to occur in the future.

We cannot predict whether the KCC will approve the plan and if so whether we will be successful in executing the plan.

We and ONEOK have shared services agreements in which we provide and bill one another for facilities, utility field work, information technology, customer support and bill processing. Payments for these services are based on various hourly charges, negotiated fees and out-of-pocket expenses.

2001 2000 1999 (In Thousands)

Charges to ONEOK ................................ $8,202 $8,463 $8,876 Charges from ONEOK ............................ 3,279 3,420 3,322 Net receivable from ONEOK, outstanding at December 31 ............... 1,424 1,205 1,506 In 1999, we and Protection One entered into a service agreement pursuant to which we provide administrative services, including accounting, human resources, legal, facilities and technology services on a year to year basis. Fees for these services are based upon various hourly charges, negotiated fees and out-of-pocket expenses. Protection One incurred charges of $8.1 million in 2001, $7.3 million in 2000 and $2.0 million in 1999.

These intercompany charges have been eliminated in consolidation.

We had a payable to Westar Industries of approximately $67.7 million at December 31, 2001 on which we paid interest at the rate of 8.5% per annum. On February 28, 2001, Westar Industries converted $350.0 million of the then outstanding payable balance into approximately 14.4 million shares of our common stock, representing 16.9% of our outstanding common stock after conversion. These shares are reflected as treasury stock in our consolidated balance sheets. During the first quarter of 2002, we repaid the remaining balance owed to Westar Industries. The proceeds were used by Westar Industries to purchase our outstanding debt in the open market. At February 28. 2002. Westar Industries owned $118.7 million of our debt. Amounts outstanding and interest earned by Westar Industries have been eliminated in our consolidated financial statements. See Note 2, "Summary of Significant Accounting Policies - Principles of Consolidation" of the "Notes to Consolidated Financial Statements."

Westar Industries is the lender under Protection One's senior credit facility. On November 1, 2001, this facility was amended to, among other things, extend the maturity date to January 3, 2003, and provide for a quarterly fee for financial advisory and management services equal to 1/8% of Protection One's consolidated total assets at the end of each quarter, beginning with the quarter ending March 31, 2002. As of March 14, 2002, approximately

$145.5 million was drawn under the facility. On March 25, 2002, Westar Industries further amended the facility to increase the amount of the facility to $180 million. Amounts outstanding have been eliminated in our consolidated financial statements.

We have a tax sharing agreement with Protection One. This pro rata tax sharing agreement allows Protection One to be reimbursed for current tax benefits utilized in our consolidated tax return. We and Protection One are eligible to file on a consolidated basis for tax purposes as long as we maintain an 80% ownership interest in Protection One. We reimbursed Protection One $11.8 million for tax year 2001 and $7.4 million for tax year 2000 for the tax benefit.

55

During 2001, Westar Industries purchased $37.9 million face value of Protection One bonds on the open market. In October 2001, $27.6 million of these bonds were transferred to Protection One in exchange for cash. In 200 1, we recognized an extraordinary gain from the purchase of Protection One bonds of $22.3 million, net of tax of

$12.0 million. During 2000, Westar Industries purchased $170.0 million face value of Protection One bonds on the open market. In exchange for cash and the settlement of certain intercompany payables and receivables, $103.9 million of these debt securities were transferred to Protection One. The balance of the bonds was sold to Protection One in March 2001. No gain or loss was recognized on these transactions.

In the latter part of 2001 through February 28, 2002, Protection One purchased approximately $1.8 million of our preferred stock in open market purchases. These purchases have been accounted for as retirements.

During 2001, we extended loans to our officers for the purpose of purchasing shares of our common stock on the open market. The loans are unsecured and contain a variable interest rate that is equal to our short term borrowing rate. Interest is payable quarterly. The loans mature and become due on December 4, 2004. The balance outstanding at December 31, 2001 was approximately $2.0 million and is classified as a reduction to shareholders' equity in the accompanying consolidated balance sheet. The maximum amount of loans authorized is $7.9 million.

During the fourth quarter of 2001, KGE entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One for approximately $0.5 million. The sales price was determined by management based on three independent appraisers' findings.

On February 29, 2000, Westar Industries purchased the European operations of Protection One, and certain investments held be a subsidiary of Protection One for an aggregate purchase price of $244 million. Westar Industries paid approximately $183 million in cash and transferred Protection One debt securities with a market value of approximately $61 million to Protection One. Westar Industries has agreed to pay Protection One a portion of the net gain, if any, on a subsequent sale of the European businesses on a declining basis over the four years following the closing. Cash proceeds from the transaction were used to reduce the outstanding balance owed to Westar Industries on Protection One's revolving credit facility. No gain or loss was recorded on this intercompany transaction and the net book value of the assets was unaffected.

If the KCC approves our financial plan, at the closing of the proposed rights offering, we would enter into an option agreement that grants Westar Industries an option to purchase the stock of Westar Generating, Inc., a wholly owned subsidiary that owns our interest in the State Line generating facility. The option would be exercisable at any time during the three year period following execution of the agreement, subject to extension for two additional one year periods. The option price is based on net book value at the time of exercise. The option would be exercisable only if Westar Industries is unable to obtain a permanent exemption from registration under the Investment Company Act of 1940.

Other New Accounting Standards In July 2001, FASB issued SFAS No. 141, "Business Combinations." SFAS No. 141 establishes that all business combinations will be accounted for using the purchase method. Use of the pooling-of-interests method is no longer allowed. The provisions of SFAS No. 141 are effective for all business combinations initiated after June 30, 2001 and all business combinations accounted for using the purchase method for which the date of acquisition is July 1, 2001 or later.

Market Risk Disclosure Market Price Risks:

We are exposed to market risk, including market changes, changes in commodity prices, equity instrument investment prices and interest rates.

56

Conmnodity Price Exposure:

We engage in both trading and non-trading activities in our commodity price risk management activities.

We trade electricity, coal, natural gas and oil. We utilize a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, options, swaps requiring payments (or receipt of payments) from counterparties based on the differential between specified prices for the related commodity and futures traded on electricity, natural gas and oil.

We are involved in trading activities primarily to minimize risk from market fluctuations, capitalize on our market knowledge and enhance system reliability. Net open positions exist or are established due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have open positions, we were exposed to the risk that fluctuating market prices could adversely impact our financial position or results from operations. In 2002, we expect to trade coal, natural gas and oil fossil fuel types as well as electricity.

We manage and measure the exposure of our trading portfolio using a variance/covariance value-at-risk (VAR) model. VAR measures the total risk, in dollars, of our entire trading portfolio. VAR also measures how much capital we are willing to put at risk to conduct trades. VAR acts as a metric to gauge trading risk. VAR measures the worst expected loss over a given time interval under normal market conditions at a given confidence level. The VAR computations are based on an historical simulation, which utilizes price movements over a specified period to simulate forward price curves in the energy markets to estimate the size of future potential losses. The quantification of market risk using VAR methodologies represents a consistent measure of an estimate of reasonably possible net losses in earnings that would be recognized on its portfolio assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. In addition to VAR, we employ additional risk control processes such as stress testing, daily loss limits, and commodity position limits. We expect to use the same VAR model and control processes in 2002.

The use of the VAR method requires a number of key assumptions including the selection of a confidence level for losses and the estimated holding period. We express VAR as a potential dollar loss based on a 95%

confidence level using a one-day holding period. The calculation includes derivative commodity instruments used for both trading and risk management purposes. The high, low and average VAR amounts for 2001 were $5.3 million, S0.2 million and $2.4 million, respectively, and for 2000 were $0.7 million, $0.04 million and $0.3 million, respectively.

The VAR amounts increased from 2000 due to the inclusion of additional trading and hedging activities in the VAR model during 2001. Prior to the January 1, 2001 adoption of SFAS No. 133, power marketing and natural gas contracts not designated as hedges were included in the VAR calculations. After January 1, 2001, we included asset-based transactions that did not qualify for hedge accounting treatment. Also in 2001, we began to trade coal in our asset-based portfolio. Excluded from the calculation is the gas hedge, which is discussed below in "- Fair Value of Contracts - Gas Hedge and Interest Rate Swap."

We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks which management policy dictates. The counterparties in our portfolio are primarily large energy marketers and major utility companies. The creditworthiness of our counterparties could positively or negatively impact our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management's view, minimize overall credit risk.

We are also exposed to commodity price changes outside of trading activities. We use derivatives for non trading purposes primarily to reduce exposure relative to the volatility of market prices. From 2000 to 2001, we experienced a 2% decrease in the average price per MW of electricity purchased for utility operations. However, purchased power markets are volatile and if we were to have a 10% increase from 2001 to 2002, given the amount of power purchased for utility operations during 2001, we would have exposure of approximately $5.3 million of operating income. Due to the volatility of the power market, past prices cannot be used to predict future prices.

57

We use a mix of various fuel types, including coal and natural gas, to operate our system, which helps lessen our risk associated with any one fuel type. A significant portion of our coal requirements are under long-term contract, which removes most of the price risk, associated with this commodity type. However, from January 1, 2001 to December 31, 2001, we experienced a 10% increase in our average cost for natural gas purchased for utility operations, or an increase of $0.34 per MMBtu. The higher natural gas prices increased our total cost of gas purchased during 2001 by approximately $3.7 million, although we decreased the quantity burned by 5.0 million MMBtu. If we were to have a similar increase from 2001 to 2002, we would have exposure of approximately $4.1 million of operating income. Based on MMBtus of natural gas and fuel oil burned during 2001, we had exposure of approximately $6.5 million of operating income for a 10% change in average price paid per MMBtu. Due to the volatility of natural gas prices, past prices cannot be used to predict future prices.

During the first quarter of 2001, spot market prices for western coal markets increased significantly.

Although the spot market prices have fallen back to previous levels, the increase impacted fuel prices of coal received under contracts for the portion that was indexed to or purchased on the spot market. This affected and will continue to affect our inventory price of coal for our LaCygne Generating Station and Lawrence and Tecumseh Energy Centers.

Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers will consume. Quantities of fossil fuel used for generation could vary dramatically year to year based on the individual fuel's availability, price, deliverability, unit outages and nuclear refueling. Our customers' electricity usage could also vary dramatically year to year based on the weather or other factors.

Interest Rate Exposure:

We have approximately $1.0 billion of variable rate debt and current maturities of fixed rate debt as of December 31, 2001. A 100 basis point change in each debt series' benchmark rate at December 31, 2001, used to set the rate for such series would impact net income on an annual basis by approximately $2.6 million after tax.

Effective October 4, 2001, we entered into a $500 million interest rate swap agreement with a term of two years. The effect of the swap agreement is to fix the annual interest rate on the term loan at 6.18%. At December 31, 2001, the variable rate associated with this debt was 4.68%. This reduces our interest rate exposure due to variable rates. The swap is being accounted for as a cash flow hedge.

Foreign Currency Exchange Rates:

We have foreign operations with functional currencies other than the United States dollar. As of December 31, 2001, the unrealized loss on currency translation, presented as a separate component of shareholders' equity and reported within other comprehensive income, was approximately $3.8 million pretax. A 10% change in the currency exchange rates would have an immaterial effect on other comprehensive income.

Decline in Equity Price Risk:

During 2000, our balance in marketable securities declined approximately $173.2 million from December 31, 1999, due to the sale of a significant portion of our marketable security portfolio. Since we no longer have a significant amount invested in marketable securities, we do not expect to be materially impacted by changes in the market prices of our remaining investments.

Hedging Activity:

We also use financial instruments to hedge a portion of our anticipated fossil fuel needs. At the time we enter into these transactions, we are unable to determine what the value will be when the agreements are actually settled.

58

In an effort to mitigate fuel commodity price market risk, we use hedging arrangements to minimize our exposure to increased coal, natural gas and oil prices. Our future exposure to changes in fossil fuel prices will be dependent upon the market prices and the extent and effectiveness of any hedging arrangements we enter.

During the third quarter of 2001, we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases in order to protect us and our customers from adverse price fluctuations in the natural gas market. We are using futures and swap contracts with a total notional volume of 39,000,000 MMBtu and terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. Based on our best estimate of generating needs, we believe we have hedged 75% of our system requirements through this hedge. We have designated these hedging relationships as cash flow hedges in accordance with SFAS No. 133.

The following table summarizes the effects our natural gas hedge and our interest rate swap had on our financial position and results of operations for 200 1:

Total Natural gas Interest Rate Cash Flow Hedge (a) Swap Hedges (Dollars in Thousands)

Fair value of derivative instruments:

Current .............................................................................. $ (9,988) S - $ (9,988)

Long-term ......................................................................... . (8.844) (2,656) (11,500)

Total .......................................................................... $ (18,832) $ S (21.488)

Amounts in accumulated other comprehensive income ......... $ (29,079) $ (2,656) S (31,735)

Hedge ineffectiveness ............................................................ 2,551 - 2,551 Estimated income tax benefit ................................................. 10,552 L057 11.609 Net Comprehensive Loss ............................................. (15,976) L 1599) 17575)

Anticipated reclassifications to earnings during 2002 (b) ...... $ 9,988 $ - $ 9,988 Duration of hedge designation as of December 31, 2001 ...... 31 months 22 months (a) Natural gas hedge liabilities are classified in the balance sheet as energy trading contracts. Gas prices have dropped since we entered into these hedging relationships. Due to the volatility of gas commodity prices, it is probable that gas prices will increase and decrease over the 31 months that these relationships are in place.

(b) The actual amounts that will be reclassified to earnings could vary materially from this estimated amount due to changes in market conditions.

Fair Value of Energv Trading Contracts The tables below show the difference between the market value and the notional values of energy trading contracts outstanding at December 31, 2001, their sources and maturity periods:

Fair Value of Contracts (In Thousands)

Net fair value of contracts outstanding at the beginning of the period ........................................................ $ 39,520 Contracts realized or otherwise settled during the period ........................................................................... (24,732)

Fair value of new contracts entered into during the period .......................................................................... (12,479)

Fair value of contracts outstanding at the end of the period ........................................................................ . 52.3O 9 59

Fair Value of Contracts at End of Period Maturity Maturity in Total Less Than Maturity Maturity Excess of Source of Fair Value Fair Value 1 Year 1-3 Years 4-5 Years 5 Years (In Thousands)

Prices actively quoted (futures) .................................... S (422) $ 160 $ (582) $ - S Prices provided by other external sources (swaps and forwards) ............................................ (2,060) (2,028) (32)

Prices based on models and other valuation models (options and other) ................................... 4791 5,495 (7 S 3&,62L7 $ý3 $ -- S_ -

Total fair value of contracts outstanding ...................... _230_9 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information relating to market risk disclosure is set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Information" included herein.

60

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS PAGE Report of Independent Public Accountants .............................................................................................. 62 Financial Statements:

Western Resources, Inc. and Subsidiaries:

Consolidated Balance Sheets, December 31, 2001 and 2000 ................................................... 63 Consolidated Statements of Income (Loss) for the years ended December 31, 2001, 2000 and 1999 ................................................................................... 64 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2001, 2000 and 1999 ................................................................................... 65 Consolidated Statements of Cash Flows for the years ended Decem ber 31, 2001, 2000 and 1999 ................................................................................... 66 Consolidated Statements of Shareholders' Equity for the years ended December 31, 2001, 2000 and 1999 ................................................................................... 67 Notes to Consolidated Financial Statements ..................................................................................... 68 Financial Schedules:

Schedule II - Valuation and Qualifying Accounts ............................................................................ 119 SCHEDULES OMITTED The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in our consolidated financial statements and schedules presented:

I, 111, IV, and V.

61

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Western Resources, Inc.:

We have audited the accompanying consolidated balance sheets of Western Resources, Inc. and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, cash flows, and shareholders' equity for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States.

Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Western Resources, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

As explained in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.

Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. Schedule II - Valuation and Qualifying Accounts is presented for purposes of complying with the Securities and Exchange Commission rules and is not part of the basic financial statements. The schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN LLP Kansas City, Missouri, March 27, 2002 62

WESTERN RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)

December 31, 2001 2000 ASSETS CURRENT ASSETS:

Cash and cash equivalents ............................................................................................................. S 96,691 S 8,762 Restricted cash .............................................................................................................................. 14,795 10,915 Accounts receivable, net ............................................................................................................... 112,864 152,165 Inventories and supplies, net ........................................................................................................ 145,099 101,303 Energy trading contracts ................................................................................................................ 71,421 185,364 Deferred tax assets ........................................................................................................................ 27,817 34,512 Prepaid expenses and other ........................................................................................................... 41,331 43,049 Total Current Assets .................................................................................... ...................... 510,018 536,070 PROPERTY, PLANT AND EQUIPMENT, NET................................... ............................ 4,042,852 3,993,438 OTHER ASSETS:

Restricted cash .............................................................................................................................. 38,515 47,168 Investm ent in O N EO K .................................................................................................................. 598,929 591,173 Custom er accounts, net ................................................................................................................. 830,708 1,005,505 G oodwill, net ................................................................................................................................ 884,786 976,102 Regutlatory assets .......................................................................................................................... 358,025 327,350 Energy trading contracts ................................................................................................................ 15,247 15,883 O ther ............................................................................................................................................. 233 985 309.031 Total Other Assets ............................................................................................................ . 2,960,195 3,272,212 TOTAL ASSETS ................................................................................................................................. S *L S7 , !801.720 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES:

Current m aturities of long-term debt ............................................................................................. S 160,576 S 41,825 Short-term debt ............................................................................................................................. 222,300 35,000 Accounts payable .......................................................................................................................... 125,285 154,654 Accrued liabilities ......................................................................................................................... 181,671 206,959 Accrued incom e taxes ................................................................................................................... 39,770 53,834 D eferred security revenues ........................................................................................................... 48,461 73,585 Energy trading contracts ................................................................................................................ 67,859 191,673 Other............................................................................................................................................. 57,459 56 600 Total Current Liabilities .................................................................................................... 903 381 814 130 LONG-TERM LIABILITIES:

Long-term debt, net ....................................................................................................................... 2,978,382 3,237,849 Western Resources obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely com pany subordinated debentures ..................................................................... 220,000 220,000 D eferred incom e taxes and investm ent tax credits ......................................................................... 924,178 954,595 M inority interests .......................................................................................................................... 166,850 184,591 Deferred gain from sale-leaseback ............................................................................................... 174,466 186,294 Energy trading contra cts ................................................................................................................ 16,500 1,096 Other ............................................................................................................................................. 285,247 271 745 Total Long-Term Liabilities ............................................................................................... 4,765,623 5,056,170 COMMITMENTS AND CONTINGENCIES (NOTE 14)

SHAREHOLDERS' EQUITY:

Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued 248.576 shares: outstanding 239,364 shares and 248,576 shares, respectively .......................... 23,936 24,858 Common stock, par value $5 per share; authorized 150,000,000 shares; issued 86,205,417 shares and 70,082,314 shares, respectively ............................................................................... 431,027 350,412 Paid-in capital ............................................................................................................................... 1,196,763 868,166 Unearned com pensation ................................................................................... . ............................ (21,920) (18,066)

Loans to officers ........................................................................................................................... (1,973)

Retained earnings .......................................................................................................................... 606,502 714,454 Treasury stock, at cost, 15,097,987 and 0 shares, respectively ....................................................... (364,901)

Accum ulated other com prehensive loss, net ................................................................................. (25,373) (8. 404)

Total Shareholders' Equity ................................................................................................. 1,844,061 1 931 420 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ............................................................. . 7.5.13.0 65IL72K The accompanying notes are an integral part of these consolidated fmancial statements.

63

WESTERN RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Dollars in Thousands, Except Per Share Amounts)

Year Ended December 31, 2001 2000 1999 SALES:

Energy ....................................................................................................................... S 1,768,393 $ 1,829,133 $ 1,429,698 M onitored Services ................................................................................................... 417.869 539,343 600 389 Total Sales ................................................................................................. 2,186,262 2,368,476 2,030,087 COST OF SALES:

Energy ....................................................................................................................... 855,292 850,018 478,837 M onitored Services ................................................................................................... 144,258 185,814 180,109 Total Cost of Sales ..................................................................................... 999,550 1,035,832 658,946 G RO SS PRO FIT ........................................................................................................... 1,186,712 1,332,644 1,371,141 OPERATING EXPENSES:

Operating and maintenance ....................................................................................... 349,413 337,481 337,081 Depreciation and amortization ................................................................................... 413,642 426,369 403,669 Selling, general and administrative ............................................................................ 334,862 343,163 334,977 Dispositions of monitored services operations ........................................................... 13,056 -

M erger costs .............................................................................................................. 8,693 - 17,600 Total Operating Expenses .......................................................................... 1,119,666 1,107,013 1,093,327 INCOME FROM OPERATIONS .................................................................................. 67,046 225,631 277,814 OTHER INCOME (EXPENSE):

Investm ent earnings ................................................................................................... 52,634 192,423 35,979 Impairment of investments ........................................................................................ (11,075) - (76,166)

M inority interests ...................................................................................................... 11,621 8,625 12,600 O ther ......................................................................................................................... 4,397 - 14,234 Total Other Income (Expense) .................................................................. 57,577 201,048 (13,353)

EARNINGS BEFORE INTEREST AND TAXES ......................................................... 124,623 426,679 264.461 INTEREST EXPENSE:

Interest expense on long-term debt ............................................................................ 227,601 226,419 236,417 Interest expense on short-term debt and other ............................................................ 40,623 63,149 57,687 Total interest Expense ................................................................................ 268,224 289,568 294.104 EARNINGS (LOSS) BEFORE INCOME TAXES ........................................................ (143,601) 137,111 (29,643)

Income tax expense (benefit) ......................................................................................... (80,875) 46,061 (32,197)

NET INCOME (LOSS) BEFORE EXTRAORDINARY GAIN AND ACCOUNTING C H AN G E .................................................................................................................. (62,726) 91,050 2,554 Extraordinary gain, net of tax of S12,571, $26,514, and $6,322 ..................................... 23,156 49,241 11,742 Cumulative effect of accounting change, net of tax of $12,347 and $1,097 .................... 18,694 (3,810)

NET INCOME (LOSS) . ............................ ............................................... (20,876) 136,481 14,296 Preferred dividends ....................................................................................................... 895 1,129 1,129 EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK ...................... L (21.71) S 135.352 $ 13. 167 Average common shares outstanding ............................................................................. 70,649,969 68,962,245 67,080,281 BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARES OUTSTANDING:

Basic and diluted earnings (losses) available before extraordinary gain and accounting change................................................................................................. S (0.90) $ 1.30 $ 0.02 Extraordinary gain, net of tax .................................................................................... 0.33 0.71 0.18 Accounting change, net of tax ................................................................................... 0.26 (0.05)

Basic and diluted earnings (losses) available after extraordinary gain and accounting change ................................................................................................. .3 $ 1.96 $_ 0.20 DIVIDENDS DECLARED PER COMMON SHARE ................................................... $ 1.20 S 1.435 $ 2.14 The accompanying notes are an integral part of these consolidated financial statements.

64

WESTERN RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

Year Ended December 31, 2001 2000 1999 N ET INC O M E (LO SS) ................................................................... S(20,876) S136 481 S14,296 OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:

Unrealized holding (losses) gains on marketable securities arising during the period ....................................................... S (592) S 43,174 $(55,420)

Adjustment for losses (gains) included in net income ................ 3 336 2,744 (114,948) (71.774) 102,417 46,997 Unrealized holding losses on cash flow hedges arising during the period .................................................................. (31,735)

Adjustment for losses included in net income ........................... 2 551 (29,184) -

Minimum pension liability adjustment .................................... (6,712)

Foreign currency translation adjustment .................................... 2,568 (9,376) (115)

Incom e tax benefit ................................................................ 13,615 34,958 (18,602)

Total other comprehensive (loss) gain, net of tax .......... (16,969) 46 192) 28 280 COMPREHENSIVE INCOME (LOSS) .................................... .. 3.845) &.2-H 542276 The accompanying notes are an integral part of these consolidated financial statements.

65

WESTERN RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)

Year Ended December 31 2001 2000 1999 CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:

Net income (loss) ................................................................................................................. (20,876) $ 136,481 S 14,296 Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Extraordinary gain ................................................................................................................ (23,156) (49,241) (11,742)

Cumulative effect of accounting change ............................................................................... (18,694) 3,810 Depreciation and amortization .............................................................................................. 413,642 426,369 403,669 Amortization of deferred gain from sale-leaseback ............................................................... (11,828) (11,828) (11,828)

Net changes in energy trading assets and liabilities .............................................................. 6,552 7,497 (1,188)

Equity in earnings from investments .................................................................................... (4,721) (11,219) (8,199)

Loss on dispositions of monitored services operations .......................................................... 13,056 -

Impairment on investments .................................................................................................. 11,075 - 76,166 (Gain) loss on sale of marketable securities .......................................................................... 1,861 (114,948) 26,251 M inority interests ................................................................................................................. (11,621) (8,625) (12,600)

Gain on sale of investments ..................................................................................................- (9,562) (17,249)

Accretion of discount note interest ....................................................................................... (2,247) (6,237) (6,799)

Net deferred taxes ................................................................................................................ (35,024) (29,744) (15,825)

Deferred merger costs .......................................................................................................... 8,693 - 17,600 Changes in working capital items, net of acquisitions and dispositions:

Restricted cash .............................................................................................................. (3,880) (22,630) (16,154)

Accounts receivable, net ................................................................................................ 36,213 77,873 (3,824)

Inventories and supplies, net .......................................................................................... (45,572) 12,282 (15,024)

Prepaid expenses and other ........................................................................................... 231 (10,314) (2,571)

Accounts payable .......................................................................................................... (26,865) 44,172 5,000 Accrued liabilities .......................................................................................................... (19,783) (19,457) (20,152)

Accrued income taxes ................................................................................................... (14,064) 13,506 7,386 Deferred security revenues ............................................................................................ (8,154) (2,065) 3,479 Changes in other assets and liabilities .................................................................................. (20.006) (14.358) (42.251)

Cash flows from operating activities ................................................................ 224,832 411,762 36844 1 CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:

Additions to property, plant and equipment, net ................................................................... (236,452) (308,073) (275,744)

Customer account acquisitions ............................................................................................. (36,488) (35,513) (241,000)

Security alarm monitoring acquisitions, net of cash acquired ...............................................- (11,748) (27,409)

Purchases of marketable securities ....................................................................................... - - (12,003)

Proceeds from sale of marketable securities ......................................................................... 2,829 218,609 73,456 Proceeds from dispositions of monitored services operations .............................................. 47,974 -

Proceeds from sale of other investments, net of purchases ................................................... 60,725 50,688 15,556 Cash flows used in investing activities ............................................................. (161412) (86.037) (467.144)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:

Short-term debt, net ............................................................................................................. 188,907 (670,421) 392,949 Proceeds of long-term debt ................................................................................................... 26,925 610,045 16,000 Retirements of long-term debt .............................................................................................. (128,997) (208,952) (198,021)

Issuance of officer loans ....................................................................................................... (1,973) -

Issuance of common stock, net ............................................................................................. 19,384 27,441 43,245 Cash dividends paid ............................................................................................................ (85,547) (98,827) (145,033)

Preferred stock redemption .................................................................................................. (547)

Acquisition of treasury stock ................................................................................................ (866) (9,187) (15,791)

Reissuance of treasury stock ............................................................................................... 7.223 21 898 -

Cash flows from (used in) financing activities .................................................. 24,509 (328.003) 93349 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .............................. 87,929 (2,278) (5,354)

CASH AND CASH EQUIVALENTS:

Beginning of period ............................................................................................................. 8,762 11,040 16,394 End of period ....................................................................................................................... $ 96. 691 The accompanying notes are an integral part of these consolidated financial statements.

66

WESTERN RESOURCES, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Dollars in Thousands)

Cumulative Accumulated Preferred and Other Preference Common Paid-in Unearned Loans to Retained Treasury Comprehensive Stock Stock Capital Compensation Officers Earnings Stock Income Total BALANCE, December 31, 1998... S 24,858 S 329,548 $ 777,401 S (2,064) S - $810,617 S -- $ 9,508 51,949,868 N et incom e ................................... - - 14,296 - - 14,296 Dividends on preferred and preference stock ....................... (1,129) (1,129)

Issuance of common stock ............ - 11,960 44,906 56,866 Dividends on common stock ......... (143,904) (143.904)

Unrealized gain on marketable securities .................................. ... 46,997 46,997 Currency translation adjustment .... -...... (115) (115)

Tax benefit ................................... S..-.... (18,602) (18,602)

Acquisition of treasury stock ......... . .-- - . (15,791) (15,791)

Grant of restricted stock ................ -- 4,333 (4,333) ....

Amortization of restricted stock .... - -- -7 JUL ...

BALANCE, December 31. 1999... S 24,858 $ 341,508 $ 826,640 S (5,695) S - S679,880 S (15,791) S 37,788 $1,889,188 N et incom e ................................... - - - - 136,481 - - 136,481 Dividends on preferred and preference stock ........................ -..... - (1,129) - - (1,129)

Issuance of common stock ........... - 8,904 18,537 ..... 27,441 Dividends on common stock ......... . .- -. (97,698) - (-97,698)

Unrealized loss on marketable securities .................................. -....... (71,774) (71.774)

Currency translation adjustment .... S....... (9,376) (9.376)

Tax benefit .................................... -..-.... 34,958 34,958 Acquisition of treasury stock ......... -...... (9,187) - (9,187)

Issuance of treasury stock ............. ..-

-- (3,080) 24,978 - 21,898 Grant of restricted stock ................ - - 22,989 (22,989) - - -

Amortization of restricted stock .... - - - 10,618 - - - - 10,618 BALANCE, December 31, 2000. S 24,858 S 350,412 S 868,166 S (18,066) $ - 5714,454 S - S (8,404) 51,931,420 N et incom e ................. - - - - (20,876) - - (20,876)

Dividends on preferred and preference stock......... - - - (1,129) - - (1,129)

Issuance of common stock ........ - 80,615 298,236 - - - (358,805) - 20,046 Dividends on common stock .... - .-.. (84.474) - - (84,474)

Retirement of preferred stock..... (922) ... . 375 - - (547)

Issuance of officer loans ............ -. . .. (1,973) - - - (1,973)

Unrealized gain on marketable securities ................................ - - - 2,744 2,744 Unrealized loss on cash flow h ed ges .............................. - - - (29,184) (29,184)

Minimum pension liability adjustm ent ................................ - - - (6,712) (6.712)

Currency translation adjustment .... - - - 2,568 2,568 T ax benefit ................................... -- (141) - 13,615 13,474 Acquisition of treasury stock ......... -. . ..- (866) - (866)

Issuance of treasury stock .............. -..... (1,707) 9,340 - 7,633 Cancellation of restricted stock - 14,570 - - - (14,570) -

Grant of restricted stock ................ -- - 15,791 (15,791) .

Amortization of restricted stock.... - - - 11,937 . . .. 11,937 BALANCE, December 31, 2001 --- S 23,936 S 431,027 $1,196,763 S (21,920) S(1,973) $606,502 $(364,901) S (25,373) $1,844,061 The accompanying notes are an integral part of these consolidated financial statements.

67

WESTERN RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS Western Resources, Inc. is a publicly traded consumer services company incorporated in 1924 in the State of Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to "the company," "Western Resources," "we," "us," "our" or similar words are to Western Resources, Inc., and its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 640,000 customers in Kansas and monitored security services to over 1.2 million customers in North America and Europe. ONEOK, Inc. (ONEOK), in which we have an approximate 45% ownership interest, provides natural gas transmission and distribution services to approximately 1.4 million customers in Oklahoma and Kansas. Our corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas 66612.

We and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary, provide rate regulated electric service using the name Westar Energy. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek).

Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary, owns our interests in Protection One, Inc. (Protection One), Protection One Europe, ONEOK, Inc. and other non-utility businesses. Protection One, a publicly traded, approximately 87% -owned subsidiary, and Protection One Europe provide monitored security services. Protection One Europe refers collectively to Protection One International, Inc., a wholly owned subsidiary of Westar Industries, and its subsidiaries, including a French subsidiary in which it owns approximately a 99.8%

interest.

2.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (GAAP). Our consolidated financial statements include all operating divisions and majority owned subsidiaries for which we maintain controlling interests. Common stock investments that are not majority owned are accounted for using the equity method when our investment allows us the ability to exert significant influence. Undivided interests in jointly-owned generation facilities are consolidated on a pro rata basis.

All material intercompany accounts and transactions have been eliminated in consolidation.

Use of Management's Estimates The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Regulatory Accounting We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent.

68

Cash and Cash Equivalents We consider highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Restricted Cash Restricted cash consists of cash used to collateralize letters of credit and cash held in escrow, primarily related to supporting our power trading transactions.

Inventories and Supplies Inventories and supplies for our utility business are stated at average cost. Inventories for our monitored services segment, comprised of alarm systems and parts, are stated at the lower of average cost or market.

Property, Plant and Equipment Property, plant and equipment is stated at cost. For utility plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision, and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds used to finance construction projects. The AFUDC rate was 9.01% in 2001, 7.39% in 2000 and 6.00% in 1999. The cost of additions to utility plant and replacement units of property are capitalized. Interest capitalized into construction in progress was $8.7 million in 2001, $9.4 million in 2000 and $4.4 million in 1999.

Maintenance costs and replacement of minor items of property are charged to expense as incurred.

Incremental costs incurred during scheduled Wolf Creek refueling and maintenance outages are deferred and amortized monthly over the unit's operating cycle, normally about 18 months. For utility plant, when units of depreciable property are retired, the original cost and removal cost, less salvage value, are charged to accumulated depreciation.

In accordance with regulatory decisions made by the Kansas Corporation Commission (KCC), the acquisition premium of approximately $801 million resulting from the acquisition of KGE in 1992 is being amortized over 40 years. The acquisition premium is classified as electric plant in service. Accumulated amortization for the KGE acquisition totaled $128.3 million as of December 31, 2001 and $108.2 million as of December 31, 2000.

Depreciation Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group rates that approximated 3.03% during 2001, 2.99% during 2000 and 2.92% during 1999. In its rate order of July 25, 2001, the KCC extended the recovery period for our generating assets, including Wolf Creek, for regulatory rate making purposes. The impact of this decision reduced our retail electric rates by approximately $17.6 million on an annual basis. We intend to file an application for an accounting authority order with the KCC to allow the creation of a regulatory asset for the difference between our book and regulatory depreciation. We cannot predict whether the KCC will approve our application.

Non-utility property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the related assets. We periodically evaluate our depreciation rates considering the past and expected future experience in the operation of our facilities.

69

Depreciable lives of property, plant and equipment are as follows:

Utility:

Fossil generating facilities ....................................... 10 to 48 years Nuclear generating facilities .................................... 38 years Transmission facilities ............................................. 27 to 65 years Distribution facilities ............................................... 14 to 65 years O ther ........................................................................ 3 to 50 years Non-utility:

Buildings .................................................................. 40 years Installed systems ...................................................... 10 years Furniture, fixtures and equipment ............................ 5 to 10 years Leasehold improvements ......................................... 5 to 10 years Vehicles ................................................................... 5 years Data processing and telecommunications ................ 1 to 7 years Nuclear Fuel Our share of the cost of nuclear fuel in process of refinement, conversion, enrichment and fabrication is recorded as an asset in property, plant and equipment on our consolidated balance sheets at original cost and is amortized to cost of sales based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor was $35.6 million at December 31, 2001 and $18.6 million at December 31, 2000. Spent fuel charged to cost of sales was $22.1 million in 2001, $19.6 million in 2000 and $20.1 million in 1999.

Customer Accounts Customer accounts are stated at cost. The cost includes amounts paid to dealers and the estimated fair value of accounts acquired in business acquisitions. Internal costs incurred in support of acquiring customer accounts are expensed as incurred.

Prior to the third quarter of 1999, Protection One and Protection One Europe amortized their customer accounts by using the straight-line method over a ten-year life, except for accounts acquired from Westinghouse for which an eight-year 120% declining balance was applied. The choice of an amortization life was based on estimates and judgments about the amounts and timing of expected future revenues from these assets and average customer account life. Selected periods were determined because, in Protection One's and Protection One Europe's opinion, they would adequately match amortization cost with anticipated revenue.

Protection One and Protection One Europe conducted a comprehensive review of their amortization policy during the third quarter of 1999, prior to Westar Industries' acquisition of Protection One Europe. As a part of this review, Protection One and Protection One Europe hired an independent appraisal firm to perform a lifing study on customer accounts. This review was performed specifically to evaluate the historic amortization policy in light of the inherent declining revenue curve over the life of a pool of customer accounts and Protection One's historical attrition experience. After completing the review, Protection One identified three distinct pools, each of which had distinct attributes that effect differing attrition characteristics. The pools corresponded to Protection One's North America, Multifamily and Europe business segments. For the North America and Europe pools, the results of the lifmg study indicated that Protection One could expect attrition to be greatest in years one through five of asset life and that a change from a straight-line to a declining balance (accelerated) method would more closely match future amortization cost with the estimated revenue stream from these assets. Protection One and Protection One Europe elected to change to that method, except for Protection One accounts acquired in the Westinghouse acquisition that were utilizing an eight-year accelerated method. No change was made in the method used for the Multifamily pool.

70

Protection One's and Protection One Europe's amortization rates consider the average estimated remaining life and historical and projected attrition rates. The amortization method for each customer pool is as follows:

Pool Method North America:

Acquired Westinghouse customers ............................ Eight-year 120% declmning balance Other customers ......................................................... Ten-year 130% declining balance Europe ............................................................................. Ten-year 125% declining balance M ultifam ily ..................................................................... Ten-year straight-line Adoption of the declining balance method effectively shortens the estimated expected average customer life for these customer pools, and does so in a way that does not make it possible to distinguish the effect of a change in method (straight-line to declining balance) from the change in estimated lives. In such cases, GAAP requires that the effect of such a change be recognized in operations in the period of the change, rather than as a cumulative effect of a change in accounting principle. Protection One changed to the declining balance method in the third quarter of 1999 for Europe customers and the North America customers that had been amortized on a straight-line basis.

Accordingly, the effect of the change in accounting principle increased Protection One's amortization expense reported in the third quarter of 1999 by approximately $40 million. Accumulated amortization would have been approximately $34 million higher through the end of the second quarter of 1999 if the declining balance method had been used historically.

In accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long Lived Assets to Be Disposed Of," long-lived assets held and used by Protection One and Protection One Europe are evaluated for recoverability on a periodic basis or as circumstances warrant. An impairment would be recognized when the undiscounted expected future operating cash flows by customer pool derived from customer accounts is less than the carrying value of capitalized customer accounts and related goodwill. See Note 25 below for information regarding SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets," which replaces SFAS No. 121 as of January 1, 2002.

Goodwill has been recorded in business acquisitions where the principal asset acquired was the recurring revenues from the acquired customer base. For purposes of the impairment analysis, goodwill has been considered directly related to the acquired customers.

Due to the customer attrition experienced in 2001, 2000 and 1999, the decline in market value of Protection One's publicly traded equity and debt securities and because of recurring losses, Protection One and Protection One Europe performed impairment tests on their customer account assets and goodwill in 2001, 2000 and 1999. These tests indicated that future estimated undiscounted cash flows exceeded the sum of the recorded balances for customer accounts and goodwill.

See Note 25 below for information regarding an impairment recorded in 2002 pursuant to new accounting rules.

Goodwill Goodwill represents the excess of the purchase price over the fair value of net assets acquired by Protection One and Protection One Europe. Protection One and Protection One Europe changed their estimated goodwill life from 40 years to 20 years as of January 1, 2000. After that date, remaining goodwill, net of accumulated amortization, is being amortized over its remaining useful life based on a 20-year life. As a result of this change in estimate, goodwill amortization expense for the year ended December 31, 2000 increased by approximately $33.0 million. The resulting reduction to net income for 2000 was $26.1 million or a decrease in earnings per share of

$0.38.

71

The carrying value of goodwill was included in the evaluations of recoverability of customer accounts. No reduction in the carrying value was necessary at December 31, 2001 or 2000.

Goodwill accumulated amortization was $170.0 million at December 31, 2001 and $118.6 million at December 31, 2000. Goodwill amortization expense was $57.1 million for the year ended 2001, $61.4 million for 2000 and $31.6 million for 1999. Beginning January 1, 2002, goodwill will no longer be amortized. New accounting rules to be adopted on January 1, 2002 do not permit goodwill amortization and require an annual impairment test.

See Note 25 below for information regarding an impairment recorded in 2002 pursuant to new accounting rules.

Regulatory Assets and Liabilities Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. We have recorded these regulatory assets and liabilities in accordance with SFAS No. 71. If we were required to terminate application of SFAS No. 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in our consolidated statements of income at that time. Our earnings would be reduced by the total amount in the table below, net of applicable income taxes. Regulatory assets and liabilities reflected in our consolidated financial statements are as follows:

As of December 31, 2001 2000 (In Thousands)

Recoverable income taxes .................................................. $221,373 $187,308 Debt issuance costs ............................................................. 58,054 63,263 Deferred employee benefit costs ......................................... 32,687 36,251 Deferred plant costs ............................................................ 29,499 29,921 Other regulatory assets ....................................................... 16,412 10,607 Total regulatory assets .................................................. 358.025 $327350 Total regulatory liabilities ............................................. $ 1978

- Recoverable income taxes: Recoverable income taxes represent amounts due from customers for accelerated tax benefits which have been previously flowed through to customers and are expected to be recovered in the future as the accelerated tax benefits reverse.

- Debt issuance costs: Debt reacquisition expenses are amortized over the remaining term of the reacquired debt or, if refinanced, the term of the new debt. Debt issuance costs are amortized over the term of the associated debt.

- Deferred employee benefit costs: Deferred employee benefit costs represent post retirement and post-employment expenses in excess of amounts paid that are to be recovered over a period of five years as authorized by the KCC.

- Deferred plant costs: Costs related to the Wolf Creek nuclear generating facility.

We expect to recover all of the above regulatory assets in rates charged to customers. A return is allowed on deferred plant costs and coal contract settlement costs (included in "Other regulatory assets" in the table above).

72

Cash Surrender Value of Life Insurance The following amounts related to corporate-owned life insurance policies (COLI) are recorded in other long-term assets on our consolidated balance sheets at December 31:

2001 2000 (In Millions)

Cash surrender value of policies (a) ........................................ $ 772.8 $ 705.4 Borrowings against policies ..................................................... (723.6) (665.9 C O LI, net ......................................................................... $__49.2 S _39.5 (a) Cash surrender value of policies as presented represents the value of the policies as of the end of the respective policy years and not as of December 31, 2001 and 2000.

Income is recorded for increases in cash surrender value and net death proceeds. Interest incurred on amounts borrowed is offset against policy income. Income recognized from death proceeds is highly variable from period to period. Death benefits recognized as other income approximated $2.7 million in 2001, $0.9 million in 2000 and $1.4 million in 1999.

Minority Interests Minority interests represent the minority shareholders' proportionate share of the shareholders' equity and net loss of Protection One and Protection One Europe.

Revenue Recognition Energy Sales:

Energy sales are recognized as services are rendered and include an estimate for energy delivered but unbilled at the end of each year, except for power marketing. Power marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales in our consolidated statements of income. The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheet.

We primarily use quoted market prices to value our power marketing and energy trading contracts. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The market prices used to value these transactions reflect our best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. Results actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results. Financially settled trading transactions are reported on a net basis, reflecting the financial nature of these transactions. Physically settled trading transactions are recorded on a gross basis in operating revenues and fuel and purchased power expense.

Monitored Services Revenues:

Monitored services revenues are recognized when security services are provided. Installation revenue, sales revenues on equipment upgrades and direct costs of installations and sales are deferred for residential customers with service contracts. For commercial customers and national account customers, revenue recognition is dependent upon each specific customer contract. In instances when the company sells the equipment outright, revenues and costs are recognized in the period incurred. In cases where there is no outright sale, revenues and direct costs are deferred and amortized.

73

.I

Deferred installation revenues and system sales revenues will be recognized over the expected useful life of the customer. Deferred costs in excess of deferred revenues will be recognized over the contract life. To the extent deferred costs are less than deferred revenues, such costs are recognized over the customers' estimated useful life.

Deferred revenues also result from customers who are billed for monitoring, extended service protection and patrol and response services in advance of the period in which such services are provided, on a monthly, quarterly or annual basis.

Income Taxes Our consolidated financial statements use the liability method to reflect income taxes. Deferred tax assets and liabilities are recognized for temporary differences in amounts recorded for financial reporting purposes and their respective tax bases. We amortize deferred investment tax credits over the lives of the related properties.

Foreign Currency Translation The assets and liabilities of our foreign operations are translated into United States dollars at current exchange rates and revenues and expenses are translated at average exchange rates for the year.

Cumulative Effects of Accounting Changes Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). We use derivative instruments (primarily swaps, options and futures) to manage interest rate exposure and the commodity price risk inherent in fossil fuel purchases and electricity sales. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our consolidated balance sheet as either an asset or liability measured at fair value.

Changes in a derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Cash flows from derivative instruments are presented in net cash flows from operating activities.

Derivative instruments used to manage commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities.

Prior to January 1, 2001, gains and losses on our derivatives used for managing commodity price risk were deferred until settlement. These derivatives were not designated as hedges under SFAS No. 133. Accordingly, on January 1, 2001, we recognized an unrealized gain of $18.7 million, net of $12.3 million of tax. This gain is presented on our consolidated statement of income as a cumulative effect of a change in accounting principle.

After January 1, 2001, changes in fair value of all derivative instruments used for managing commodity price risk that are not designated as hedges are recognized in revenue as discussed above under "- Revenue Recognition - Energy Sales." Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings.

In the fourth quarter of 2000, we adopted Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition," which had a retroactive effective date of January 1, 2000. The impact of this accounting change generally required deferral of certain monitored security services sales for installation revenues and direct sales related expenses. Deferral of these revenues and costs is generally necessary when installation revenues have been received and a monitoring contract to provide future service is obtained.

The cumulative effect of the change in accounting principle was approximately $3.8 million, net of tax benefits of $1.1 million and is related to changes in revenue recognition at Protection One Europe. Prior to the adoption of SAB No. 101, Protection One Europe recognized installation revenues and related expenses upon completion of the installation.

74

Supplemental Cash Flow Information Cash paid for interest and income taxes for each of the years ended December 31, are as follows:

2001 2000 1999 (In Thousands)

Interest on financing activities, net of amount capitalized ................. S 306,865 $ 310,345 $ 298,802 Incom e taxes ..................................................................................... 5,811 28,75 1 784 Reclassifications Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.

3. RATE MATTERS AND REGULATION KCC Rate Proceedings On November 27, 2000, we and KGE filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our combined electric rates of $22.7 million, consisting of a

$41.2 million reduction in KGE's rates and an $18.5 million increase in our rates.

On August 9, 2001, we and KGE filed petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the KGE acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and several other issues. On September 5, 200 1, the KCC issued an order in response to our motions for reconsideration that increased our rate increase by an additional $7.0 million. The $41.2 million rate reduction in KGE's rates remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions with the Kansas Court of Appeals in an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal this decision to the Kansas Supreme Court.

KCC Investigation and Order See Note 15 for a discussion of the order issued by the KCC on July 20, 2001 in the KCC's docket investigating the proposed separation of our electric utility businesses from our non-utility businesses and other aspects of our unregulated businesses.

FERC Proceedings On September 12, 2001, we filed a settlement between the Federal Energy Regulatory Commission (FERC) staff and Westar Generating, Inc. (Westar Generating), the wholly owned subsidiary that owns our interests in the State Line generating facility. The settlement establishes the rate at which we will buy power from Westar Generating. FERC has jurisdiction over the establishment of this rate because of our affiliate relationship with Westar Generating. We continue to work toward a global settlement with the KCC, the only other active party, but can make no assurance on a resolution.

In September 1999, the City of Wichita filed a complaint with FERC against us alleging improper affiliate transactions between our KPL division and KGE. The City of Wichita asked that FERC equalize the generation costs between KPL and KGE, in addition to other matters. After hearings on the case, a FERC administrative law judge ruled in our favor confirming that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. On January 5, 2001, we 75

filed a brief opposing the City's position. On November 23, 2001, FERC issued an order affirming the judge's decision. The City of Wichita's time to appeal FERC's order has expired.

4. ACCOUNTS RECEIVABLE Our accounts receivable on our consolidated balance sheets are comprised as follows:

December 31, 2001 2000 (In Thousands)

Gross accounts receivable ..................................... $189,254 $ 254,743 Allowance for uncollectable accounts (a) .............. (19,121) (45,816)

Unbilled energy receivables .................................. 42,731 58,238 Accounts receivable sale program ......................... (100,000) (115,000)

Accounts receivable, net ........................................ $852.165 (a) The decrease in allowance for uncollectable accounts is primarily due to the write off of Protection One customer accounts in 2001.

On July 28, 2000, we entered into an asset-backed securitization agreement under which we periodically transfer an undivided percentage ownership interest in a revolving pool of our accounts receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities." The agreement was renewed on July 26, 2001, and is annually renewable upon agreement by all parties.

Under the terms of the agreement, we may transfer accounts receivable to the bankruptcy-remote SPE and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million (and upon request, subject to certain conditions, up to $175 million), in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned and consolidated. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE's receivables, including delinquency rates and debtor concentrations. We service the receivables transferred to the SPE and receive a servicing fee. These servicing fees are eliminated in consolidation.

Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit resulting in an adjustment to the outstanding conduit interest.

We record administrative expense on the undivided interest owned by the conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the year ended December 31, 2000. These expenses are included in other income (expense) in our consolidated statements of income.

The outstanding balance of SPE receivables was $43.3 million at December 31, 2001 and $85.5 million at December 31, 2000, which is net of an undivided interest of $100 million and $115.0 million in receivables sold by the SPE to the conduit. Our retained interest in the SPE's receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit's ownership interest in the SPE's receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit, and to absorb all credit losses incurred on any of the SPE's receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets.

76

5. FINANCIAL LNSTRUMENTS The carrying values and estimated fair values of our financial instruments are as follows:

Carrying Value Fair Value As of December 31, 2001 2000 2001 2000 (In Thousands)

Fixed-rate debt, net of current maturities (a) ................................. $2,418,838 $2,518,415 $2,229,998 $2,218,711 Other mandatorily redeemable securities (a) .................................. 220,000 220,000 190,960 182,232 (a) Fair value is estimated based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions.

The recorded amounts of accounts receivable and other current financial instruments approximate fair value. Cash and cash equivalents, short-term borrowings and variable-rate debt are carried at cost, which approximates fair value and are not included in the table above.

The fair value estimates presented herein are based on information available at December 31, 2001 and 2000. These fair value estimates have not been comprehensively revalued for the purpose of these consolidated financial statements since that date and current estimates of fair value may differ significantly from the amounts presented herein.

Derivative Instruments and Hedge Accounting We use derivative financial instruments primarily to manage risk as it relates to changes in the prices of commodities including natural gas, coal and electricity and changes in interest rates. We also use certain derivative instruments for trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power and fossil fuel markets. Derivative instruments used to manage commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities.

Energy Trading Activities:

We trade energy commodity contracts daily. Within the trading portfolio, we take certain positions to hedge physical sale or purchase contracts and we take certain positions to take advantage of market trends and conditions. We record most energy contracts, both physical and financial, at fair value. Changes in value are reflected in our consolidated statement of income. We use all forms of financial instruments, including futures, forwards, swaps and options. Each type of financial instrument involves different risks. We believe financial instruments help us manage our contractual commitments, reduce our exposure to changes in cash market prices and take advantage of selected market opportunities. We refer to these transactions as energy trading activities.

Although we generally attempt to balance our physical and financial contracts in terms of quantities and contract performance, net open positions typically exist. We will at times create a net open position or allow a net open position to continue when we believe that future price movements will increase the portfolio's value. To the extent we have an open position, we are exposed to fluctuating market prices that may adversely impact our financial position or results from operations.

The prices we use to value price risk management activities reflect our best estimate of fair values considering various factors, including closing exchange and over-the-counter quotations, time value of money and price volatility factors underlying the commitments. We adjust prices to reflect the potential impact of liquidating 77

our position in an orderly manner over a reasonable period of time under present market conditions. We consider a number of risks and costs associated with the future contractual commitments included in our energy portfolio, including credit risks associated with the financial condition of counterparties and the time value of money. We continuously monitor the portfolio and value it daily based on present market conditions.

Future changes in our creditworthiness and the creditworthiness of our counterparties may change the value of our portfolio. We adjust the value of contracts and set dollar limits with counterparties based on our assessment of their credit quality.

Non-Trading Activities - Derivative Instruments and Hedging Activities:

We use derivative financial instruments to reduce our exposure to adverse fluctuations in commodity prices, interest rates, and other market risks. When we enter into a financial instrument, we formally designate and document the instrument as a hedge of a specific underlying exposure, as well as the risk management objectives and strategies for undertaking the hedge transaction. Because of the high degree of correlation between the hedging instrument and the underlying exposure being hedged, fluctuations in the value of the derivative instruments are generally offset by changes in the value or cash flows of the underlying exposures being hedged.

We record derivatives used for hedging commodity price risk in our consolidated balance sheets at fair value as energy trading contracts. The effective portion of the gain or loss on a derivative instrument designated as a cash flow hedge is reported as a component of accumulated other comprehensive income (loss). This amount is reclassified into earnings in the period during which the hedged transaction affects earnings. Effectiveness is the degree to which gains and losses on the hedging instruments offset the gains and losses on the hedged item. The ineffective portion of the hedging relationship is recognized currently in earnings.

The fair values of derivatives used to hedge or modify our risks fluctuate over time. These fair value amounts should not be viewed in isolation, but rather in relation to the fair values or cash flows of the underlying hedged transactions and the overall reduction in our risk relating to adverse fluctuations in interest rates, commodity prices and other market factors. In addition, the net income effect resulting from our derivative instruments is recorded in the same line item within our consolidated statements of income as the underlying exposure being hedged. We also formally assess, both at the inception and at least quarterly thereafter, whether the financial instruments that are used in hedging transactions are effective at offsetting changes in either the fair value or cash flows of the related underlying exposures. Any ineffective portion of a financial instrument's change in fair value is immediately recognized in net income.

The notional volumes and terms of commodity contracts used for trading and non-trading purposes are as follows at December 31, 2001 and 2000:

December 31, 2001 Fixed Price Fixed Price Maximum Pavor Receiver Term in Years Electricity (MWh's) .......................... 3,942,352 2,976,504 4 Natural gas and oil (MMBtus) .......... 124,632,157 81,702,324 3 Coal (MMBtus) ................................ 245,667,419 237,819,001 3 December 31, 2000 Fixed Price Fixed Price Maximum Payor Receiver Term in Years Electricity (MWh's) .......................... 4,229,100 4,100,448 4 Natural gas and oil (MMBtus) .......... 113,030,679 80,754,417 3 Coal (MMBtus) ................................

78

The following table presents the fair values of energy transactions by commodity at December 31, 2001 and 2000:

Energy Trading Contract Energy Trading Contract Assets Liabilities 2001 2000 2001 2000 (In Thousands)

Electricity $ 26,087 $ 108,726 $ 17,721 $ 104,337 Natural gas and oil 37,884 92,521 42,068 88,432 Coal 22,697 - 24.570 -

Total M3201,247 2 $ 192,769 During the third quarter of 2001, we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases in order to protect us and our customers from adverse price fluctuations in the natural gas market. We are using futures and swap contracts with a total notional volume of 39,000,000 MMBtu and terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. Based on our best estimate of generating needs, we believe we have hedged 75% of our system requirements through this hedge. We have designated these hedging relationships as cash flow hedges in accordance with SFAS No. 133.

Effective October 4, 2001, we entered into a $500 million interest rate swap agreement with a term of two years. The effect of the swap agreement is to fix the annual interest rate on the term loan at 6.18%. At December 31, 2001, the variable rate associated with this debt was 4.68%. This reduces our interest rate exposure due to variable rates. The swap is being accounted for as a cash flow hedge.

The following table summarizes the effects our natural gas hedge and our interest rate swap had on our financial position and results of operations for 2001:

Total Natural gas Interest Rate Cash Flow Hedge (a) Swap Hedges (Dollars in Thousands)

Fair value of derivative instruments:

Current .............................................................................. S (9,988) $ - $ (9,988)

Long-term ......................................................................... (8.844) (2.656) (11,500)

T otal ............................................................................ ) (2.656) $ (21,488)

Amounts in accumulated other comprehensive income ......... $ (29,079) $ (2,656) $ (31,735)

H edge ineffectiveness ............................................................ 2,551 - 2,551 Estimated income tax benefit ................................................. 10,552 1,057 11.609 Net Comprehensive Loss ............................................. $ (15,976) & _1i5_99) $ (17,575 Anticipated reclassifications to earnings during 2002 (b) ...... $ 9,988 $ - $ 9,988 Duration of hedge designation as of December 31, 2001 ...... 31 months 22 months (a) Natural gas hedge liabilities are classified in the balance sheet as energy trading contracts. Gas prices have dropped since we entered into these hedging relationships. Due to the volatility of gas commodity prices, it is probable that gas prices will increase and decrease over the 31 months that these relationships are in place.

(b) The actual amounts that will be reclassified to earnings could vary materially from this estimated amount due to changes in market conditions.

79

6. PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at December 31:

2001 2000 (In Thousands)

Electric plant in service .................................................. $6,289,316 $5,987,920 Less - Accumulated depreciation .................................... 2,404,478 2,274.940 3,884,838 3,712,980 Construction work in progress ........................................ 63,927 189,853 Nuclear fuel, net ............................................................. 33,883 30,791 3,982,648 Net utility plant ........................................................... 3,933,624 Non-utility plant in service ............................................. 115,682 113,040 Less accumulated depreciation ....................................... 55,478 53,226 N et property, plant and equipment ..............................

Our depreciation expense on property, plant and equipment was $203.5 million in 2001, $201.7 million in 2000 and $186.1 million in 1999.

7. JOINT OWNERSHIP OF UTILITY PLANTS Our Ownership at December 31, 2001 In-Service Accumulated Net Ownership Dates Investment Depreciation MW Percent (Dollars in Thousands)

LaCygne 1 .................. (a) June 1973 $ 188,277 $120,300 344.0 50 Jeffrey 1...................... (b) July 1978 306,136 148,000 625.0 84 Jeffrey 2 ...................... (b) May 1980 312,803 134,322 612.0 84 Jeffrey 3 ...................... (b) May 1983 411,582 179,867 623.0 84 Jeffrey wind 1 ............. (b) May 1999 874 98 0.6 84 Jeffrey wind 2 ............. (b) May 1999 873 97 0.6 84 W olf Creek ................. (c) Sept. 1985 1,387,391 528,268 550.0 47 State Line .................... (d) June 2001 105,391 2,108 200.0 40 (a) Jointly owned with Kansas City Power and Light Company (KCPL)

(b) Jointly owned with Aquila, Inc.

(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

(d) Jointly owned with Empire District Electric Company (EDE)

Amounts and capacity presented above represent our share. Our share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity) sold and leased back to KGE in 1987, are included in operating expenses on our consolidated statements of income. Our share of other transactions associated with the plants is included in the appropriate classification in our consolidated financial statements.

80

8. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD Our investments that are accounted for by the equity method are as follows:

Ownership at Equity Earnings, December 31 Investment at December 31, Year Ended December 31, 2001 2001 2000 2001 2000 (Dollars in Thousands)

ONEOK (a) .................................................... 45% $S598,929 $ 591,173 S 4,721 S 8,213 International companies and joint ventures (b) ................................................. 9% to 50% 1,976 13,514 2,334 3,394 (a) We also received approximately S40 million of preferred and common dividends in both 2001 and 2000. ONEOK equity earnings for 2001 decreased due to charges recorded for Enron Corp. exposure and for certain regulatory issues ONEOK has in Oklahoma.

(b) Investment is aggregated. Individual investments are not material.

During 2001, we disposed of our portfolio of affordable housing tax credit limited partnerships. We recorded earnings on these partnerships, including equity in earnings and loss on disposal, of $4.4 million.

The following is summarized unaudited ONEOK financial information related to our investment in ONEOK:

As of December 31.

2001 2000 (In Thousands)

Balance Sheet:

Current assets .......................................... $1,561,969 $3,324,959 Non-current assets ................................... 4,317,190 4,035,386 Current liabilities ..................................... 1,818,417 3,526,561 Long-term debt, net ................................. 1,498,012 1,336,082 Other deferred credits and other liabilities .............................................. 1,297,440 1,272,745 Equity ...................................................... 1,265,290 1,224,957 For the Year Ended December 31.

2001 2000 (In Thousands)

Income Statement:

Revenues ................................................. $6,803,146 $6,642,858 Gross profit .............................................. 908,785 797,132 Income before cumulative effect of a change in accounting principle .......... 103,716 143,492 N et incom e .............................................. 101,565 145,607 At December 31, 2001, our ownership interest in ONEOK was comprised of approximately 4.7 million common shares and approximately 19.9 million convertible preferred shares, each share of which is convertible into two shares of ONEOK common stock. If all the preferred shares were converted, we would then own approximately 45% of ONEOK's common shares outstanding.

ONEOK earnings for 2001 include a pretax charge of $34.6 million for unrecovered gas costs from the winter of 2000/2001 and a $37.4 million pretax charge related to the Enron Corp. bankruptcy. The charge for the outstanding gas costs is a result of the Oklahoma Corporation Commission order denying ONEOK the right to collect a portion of gas costs incurred during the winter of 2000/2001. Gas prices increased significantly in this period due to high demand and a perceived supply shortage. The charges related to Enron Corp.'s bankruptcy are due to Enron Corp.'s non-payment of both financial and physical natural gas positions for November and December of 2001. These charges also include the value of forward natural gas positions on ONEOK's termination of natural 81

gas contracts in early January 2002. These contracts were related to physical commodity sales and storage management activities.

9. MONITORED SERVICES' CUSTOMER ACCOUNTS The following is a rollforward of the investment in customer accounts (at cost) of the monitored services segment for the following years:

December 31, 2001 2000 (In Thousands)

Beginning customer accounts, net .................................. $1,005,505 $1,122,585 Acquisition of customer accounts ................................... 17,482 54,993 Amortization of customer accounts ................................ (153,019) (163,297)

Sale of accounts .............................................................. (42,246)

Purchase holdbacks and other ........................................ 2,986 (8,776)

Ending customer accounts, net .................................. 1.005.505 Accumulated amortization of the investment in customer accounts at December 31, 2001 was $630.5 million and $493.4 million at December 31, 2000. Customer account amortization expense was $153.0 million for 2001, $163.3 million for 2000, and $186.0 million for 1999.

During 2001, the monitored services segment's attrition, along with its change in focus from growth to strengthening operations, dispositions of certain accounts and Protection One's conversion to MAS, resulted in a net loss of 267,347 customers or a 17.8% decrease in its customer base from January 1, 2001. This was the primary cause of Protection One's $59.9 million decline in monitoring and related service revenues in its North America segment from January 1, 2001. Protection One expects this trend will continue until the efforts it is making to acquire new accounts and reduce its rate of attrition become more successful than they have been to date. Until Protection One is able to reverse this trend, net losses of customer accounts will materially and adversely affect our business, financial position and results of operations.

10. SHORT-TERM DEBT We have an arrangement with certain banks to provide a revolving credit facility on a committed basis totaling $500 million. The facility is secured by our and KGE's first mortgage bonds and matures on March 17, 2003. We also have arrangements with certain banks to provide unsecured short-term lines of credit on a committed basis totaling approximately $7.0 million. As of December 31, 2001, borrowings on these facilities were $222.3 million.

The agreements provide us with the ability to borrow at different market-based interest rates. We pay commitment or facility fees in support of these lines of credit. Under the terms of the agreements, we are required, among other restrictions, to maintain a total debt to total capitalization ratio of not greater than 65% at all times. We are in compliance with this covenant. At December 31, 2001, the capitalization ratio was 61.4%. Under the terms of the facility, the impairment charge to be recorded in the first quarter of 2002 will not affect compliance with this covenant in future periods.

82

Information regarding our short-term borrowings is as follows:

As of December 31.

2001 2000 (Dollars in Thousands)

Borrowings outstanding at year end:

C redit agreem ent ..................................................................... $222,300 $ 35,000 Weighted average interest rate on debt outstanding at year end ...... 3.44% 8.i I%

Weighted average short-term debt outstanding during the year ...... $123,131 $402,845 Weighted daily average interest rates during the year, including fees .................................................................... 6.58% 7.92%

Our interest expense on short-term debt and other was $40.6 million in 2001, $63.1 million in 2000 and

$57.7 million in 1999.

83

11. LONG-TERM DEBT Long-term debt outstanding is as follows at December 31:

2001 2000 (In Thousands)

Western Resources First mortgage bond series:

7 1/4% due 2002 .................................................................................. $ 100,000 S 100,000 8 1/2% due 2022 .................................................................................. 125,000 125,000 7.65% due 2023 ................................................................................... 100,000 100,000 325,000 325,000 Pollution control bond series:

Variable due 2032, 1.43% at December 31,2001 ................................ 45,000 45,000 Variable due 2032, 1.70% at December 31,2001 ................................ 30,500 30,500 6% due 2033 ........................................................................................ 58,340 58,410 133,840 133,910 6 7/8% unsecured senior notes due 2004 .................................................... 355,560 370,000 7 1/8% unsecured senior notes due 2009 .................................................... 150,000 150,000 6.80% unsecured senior notes due 2018 ..................................................... 28,104 28,977 6.25% unsecured senior notes due 2018, putable/callable 2003 .................. 384,300 400,000 Senior secured term loan due 2003, variable rate of 7.9% at D ecember 31, 2001 ............................................................................... 591,000 600,000 Other long-term agreements ........................................................................ 5,830 16,889 1,514,794 1,565,866 KGE First mortgage bond series:

7.60% due 2003 ................................................................................... 135,000 135,000 6 1/2% due 2005 .................................................................................. 65,000 65,000 6.20% due 2006 ................................................................................... 100,000 100,000 300,000 300,000 Pollution control bond series:

5.10% due 2023 ................................................................................... 13,493 13,623 Variable due 2027, 1.35% at December 31,2001 ................................ 21,940 21,940 7.0% due 2031 ..................................................................................... 327,500 327,500 Variable due 2032, 1.5% at December 31, 2001 .................................. 14,500 14,500 Variable due 2032, 1.53% at December 31, 2001 ................................ 10,000 10,000 387,433 387,563 Protection One Convertible senior subordinated notes due 2003, fixed rate 6.75% ............. 23,770 23,785 Senior subordinated discount notes due 2005, effective rate 11.8% ............ 33,520 42,887 Senior unsecured notes due 2005, fixed rate 7.375% .................................. 203,650 204,650 Senior subordinated notes due 2009, fixed rate 8.125% .............................. 174,840 255,740 Other ................................................................................................. ........ 898 267 436,678 527 329 Protection One Europe CET recourse financing agreements, average effective rate 13.17%(a) ....... 34,931 33,512 Unamortized debt premium (b) ....................................................................... 12,837 13,541 Less:

Unamortized debt discount (b).................................................................... 6,555 7,047 Long-term debt due within one year ............................................................ 160.576 41,825 Long-term debt, net .............................................................................. QU L M ________

(a) Agreements mature on various dates not exceeding four years.

(b) Debt premiums, discounts and expenses are being amortized over the remaining lives of each issue.

The amount of our first mortgage bonds authorized by our Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited. The amount of KGE's first mortgage bonds authorized by the KGE Mortgage and 84

Deed of Trust, dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion, unless amended. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions of each mortgage.

Our unsecured debt represents general obligations that are not secured by any of our properties or assets.

Any unsecured debt will be subordinated to all of our secured debt, including the first mortgage bonds. The notes are structurally subordinated to all secured and unsecured debt of our subsidiaries.

We have material amounts of debt maturing over the next one to two years (see also Note 10 above). This debt will need to be refinanced. We are evaluating strategies for refinancing this debt.

On June 28, 2000, we entered into a $600 million, multi-year term loan that replaced two revolving credit facilities that matured on June 30, 2000. We had $591 million outstanding on the term loan at December 31, 2001.

The term loan is secured by our and KGE's first mortgage bonds and has a maturity date of March 17, 2003. The term loan agreement contains requirements for maintaining certain consolidated leverage ratios, interest coverage ratios and consolidated debt to capital ratios. At December 31, 2001, we were in compliance with all of these requirements. In January 2002, we repaid $44 million of the term loan with the proceeds of our sale of investments in low income housing tax credit partnerships. The outstanding balance of the term loan after this prepayment was

$547 million. In March 2002, we entered into an amendment to the term loan that adds to the calculation of consolidated earnings before interest, taxes, depreciation and amortization, the severance costs incurred in the fourth quarter of 2001 and the first quarter of 2002 related to our work force reductions, and maintains the current maximum consolidated leverage ratio of 5.75 to 1.0 through the maturity date of the term loan in March 2003. We expect to be in compliance with all covenants through the remaining term of this agreement.

Maturities of the term loan through March 17, 2003, are as follows:

Principal Amount Year (In Thousands) 2002 ............................................ $ 6,000 2003 ........................................... 541.000

$ 547.,000 Interest on the term loan is payable on the expiration date of each borrowing under the facility or quarterly if the term of the borrowing is greater than three months. The weighted average interest rate, including amortization of fees, on the term loan for the year ending December 31, 2001, was 7.9%.

Maturities of long-term debt as of December 31, 2001 are as follows:

Principal Amount As of December 3 1, (In Thousands) 2002 (a) ................................ $ 160,576 2003 ...................................... 715,414 2004 ...................................... 364,128 2005 ...................................... 306,414 2006 ...................................... 100,457 Thereafter ............................ 1,491.969

$3.138.958 (a) Amount due includes $38.5 million related to the sale of investments required to be repaid under the mandatory prepayment provisions of our credit agreement.

Our interest expense on long-term debt was $227.6 million in 2001, $226.4 million in 2000 and $236.4 million in 1999.

85

In 1998, Protection One issued $350 million of unsecured Senior Subordinated Notes due 2009. As a result of the completion of a registered offer to exchange a new series of 8.125% Series B Senior Subordinated Notes for a like amount of Protection One's outstanding 8.125% Senior Subordinated Notes, effective June 1, 2001 the annual interest rate on all of such outstanding notes decreased from 8.625% to 8.125%. Because the exchange offer was not completed within six months of the issuance date, Protection One had been paying an additional 0.5% interest penalty since June 1999. At the time of the exchange, the resulting annual interest savings were $1.2 million. The notes are redeemable at Protection One's option, in whole or in part, at a predefined price. Interest on these notes is payable semi-annually on January 15 and July 15.

In 1998, Protection One issued $250 million of Senior Unsecured Notes. Interest is payable semi-annually on February 15 and August 15. The notes are redeemable at Protection One's option, in whole or in part, at a predefined price.

In 1995, Protection One issued $166 million of Unsecured Senior Subordinated Discount Notes with a fixed interest rate of 13.625%. Interest payments began in 1999 and are payable semi-annually on June 30 and December

31. In connection with the acquisition of Protection One in 1997, these notes were restated to fair value. As of June 30, 2000, the notes became redeemable at Protection One's option, at a specified redemption price.

In 1996, Protection One issued $103.5 million of Convertible Senior Subordinated Notes. Interest is payable semi-annually on March 15 and September 15. The notes are convertible at any time at a conversion price of $11.19 per share. As of September 19, 1999, the notes became redeemable, at Protection One's option, at a specified redemption price.

During the last three years, Protection One and our bonds were repurchased in the open market and extraordinary gains were recognized on the retirement of these bonds of $23.2 million in 2001, $49.2 million in 2000 and $13.4 million in 1999, net of tax. From January 1, 2002 through February 2002, a gain of $3.6 million, net of tax, was recognized on the repurchase of Protection One and our bonds.

Protection One Europe has recognized as a financing transaction cash received through the sale of security equipment and future cash flows to be received under security equipment operating lease agreements with customers to a third-party financing company.

Protection One's debt instruments contain financial and operating covenants which may restrict its ability to incur additional debt, pay dividends, make loans or advances and sell assets. At December 31, 2001, Protection One was in compliance with its debt covenants.

The indentures governing all of Protection One's debt securities require that Protection One offer to repurchase the securities in certain circumstances following a change of control.

12. EMPLOYEE BENEFIT PLANS Pension We maintain qualified noncontributory defined benefit pension plans covering substantially all utility employees. Pension benefits are based on years of service and the employee's compensation during the five highest paid consecutive years out of ten before retirement. Our policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code. We also maintain a non-qualified Executive Salary Continuation Program for the benefit of certain management employees, including executive officers.

86

Post-retirement Benefits We accrue the cost of post-retirement benefits, primarily medical benefit costs, during the years an employee provides service.

The following tables summarize the status of our pension and other postretirement benefit plans:

Pension Benefits Post-retirement Benefits December 31, 2001 2000 2001 2000 (In Thousands)

Change in Benefit Obligation:

Benefit obligation, beginning of year .......................... $ 383,403 $ 350,749 S 102,530 S 79,287 Service cost ................................................................ 9,042 7,964 1,477 1,344 Interest cost ................................................................ 28,783 26,901 7,344 7,158 Plan participants' contributions ................................... - - 1,189 1,130 Benefits paid .............................................................. (23,982) (20,337) (7,741) (6,476)

Assumption changes ................................................... 39 19,350 587 5,038 Actuarial losses (gains) ............................................... 21,662 (2,491) 2,697 15,049 Curtailments, settlements and special term benefits .... 4867 1,267 547 -

Benefit obligation, end of year .................................... *423814 5.J3A3 _IS..630 5-02J3_0 Change in Plan Assets:

Fair value of plan assets, beginning of year ................ S 490,173 S 506,995 S 394 5 261 Actual return on plan assets ........................................ (2,144) 1,448 19 17 Employer contribution ................................................ 3,015 2,067 6,716 5,462 Plan participants' contributions ................................... - - 1,189 1,130 Benefits paid .............................................................. (23,982) (20,337) (7,741) (6,476)

Fair value of plan assets, end of year .......................... 4L0k 2 5 9013 jS. 77 J____3_9 Fundedstatus ............................................................. $ 43,248 S 106,770 S (108,053) S (102,136)

Unrecognized net (gain)/loss ...................................... (65,477) (141,443) 14,447 11,904 Unrecognized transition obligation, net ...................... 141 174 44,195 48,183 Unrecognized prior service cost .................................. 24,071 29,538 (2,79) (26.4)

Prepaid (accrued) postretirement benefit costs ............ - 5208 * )

Amounts recognized in the statement of financial position consist of:

Prepaid benefit cost ................................................... S 19,687 S 9,712 5 N/A S N/A Accrued benefit liability ............................................. (17,704) (14,673) (52,208) (45,313)

Additional minimum liability ..................................... (7,370) - N/A N/A Intangible asset ........................................................... 658 - N/A N/A Accumulated other comprehensive income ................. 6,712 N/A N/A Net amount recognized ............................................... 5 .9486)

Actuarial Assumptions:

Discount rate ............................................................. 7.25% 7.25-7.75% 7.25% 7.25-7.75%

Expected rate of return ............................................... 9.0-9.25% 9.00-9.25% 9.0-9.25% 9.00-9.25%

Compensation increase rate ....................................... 4.0-5.0% 4.25-5.00% 4.0-5.0% 4.50-5.00%

Components of net periodic (benefit) cost:

Service cost ................................................................ S 9,042 S 7,972 S 1,477 $ 1,344 Interest cost ................................................................ 28,783 26,977 7,344 7,157 Expected return on plan assets .................................... (43,001) (39,143) (36) (24)

Amortization of unrecognized transition obligation, net ........................................................ 34 35 3,987 3,988 Amortization of unrecognized prior service costs ....................................................................... 3,317 3,316 (466) (466)

Amortization of (gain)/loss, net ................................. (8,327) (9,427) 794 457 O ther ......................................................................... - 9 -

Curtailments, settlements and special term benefits .... 6 133 -

Net periodic (benefit) cost .......................................... S)$L2A5)6 For measurement purposes, an annual health care cost growth rate of 5.25%-6.0% was assumed for 2001.

The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate 87

by 1% each year would increase the present value of the accumulated projected benefit obligation by $2.5 million and the aggregate of the service and interest cost components by $0.2 million. A 1% decrease in the trend rate would decrease the present value of the accumulated projected benefit obligation by $2.4 million and the aggregate of the service and interest cost components by $0.2 million.

Savings Plans We maintain savings plans in which substantially all employees participate, with the exception of Protection One and Protection One Europe employees. We match employees' contributions with Western Resources' stock up to specified maximum limits. Our contributions to the plans are deposited with a trustee and are invested in one or more funds, including the company stock fund. Our contributions were $4.4 million for 2001, $3.9 million for 2000 and $3.7 million for 1999.

In 1999, we established a qualified employee stock purchase plan, the terms of which allow full-time non union employees to participate in the purchase of designated shares of our common stock at no more than a 15%

discounted price. Our employees purchased 67,519 shares in 2001, pursuant to this plan, at an average price per share of $14.55625. In 2000, employees purchased 249,050 shares at an average price per share of $13.9984. A total of 1,250,000 shares of common stock have been reserved for issuance under this program.

Protection One also maintains a savings plan. Contributions, made at Protection One's election, are allocated among participants based upon the respective contributions made by the participants through salary reductions during the year. Protection One's matching contributions may be made in Protection One common stock, in cash or in a combination of both stock and cash. Protection One's matching cash contribution to the plan was approximately $1.1 million for 2001, $0.7 million for 2000 and $0.9 million for 1999.

Protection One maintains a qualified employee stock purchase plan that allows eligible employees to acquire shares of Protection One common stock at periodic intervals through their accumulated payroll deductions.

A total of 1,650,000 shares of common stock have been reserved for issuance in this program and a total of 912,186 shares have been issued including the issuance of 489,791 shares in January 2002.

Stock Based Compensation Plans We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which utility employees are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and board members (Plan Participants). Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, restricted shares, restricted share units (RSUs), performance shares and performance share units to Plan Participants. Up to five million shares of common stock may be granted under the LTISA Plan.

During 2001, 579,915 RSUs were granted to a broad-based group of over 1,000 non-union employees.

Each RSU represents a right to receive one share of our common stock at the end of the restricted period assuming performance criteria are met. During 2000, 710,352 RSUs were granted. Also in 2000, non-union employees were offered the opportunity to exchange their stock options for RSUs of approximately equal economic value. As a result, 2,246,865 stock options were canceled in 2000 in exchange for 614,741 RSUs. We granted a total of 152,000 restricted shares in 1999. The grant of restricted stock is shown as a separate component of shareholders' equity.

Unearned compensation is being amortized to expense over the vesting period. This compensation expense is shown as a separate component of shareholders' equity.

Another component of the LTISA Plan is the Executive Stock for Compensation program where in the past eligible employees were entitled to receive RSUs in lieu of cash compensation at the end of a deferral period. The Executive Stock for Compensation program was modified in 2001 to pay a portion of current compensation in the form of stock. In 2001, eligible employees were issued 31,881 shares of common stock representing $0.7 million of compensation. In 2000, 95,000 RSUs were awarded in lieu of $1.3 million in cash compensation. In 1999, 35,000 RSUs were awarded in lieu of $0.7 million of cash compensation. Dividend equivalents accrue on the awarded RSUs. Dividend equivalents are the right to receive cash equal to the value of dividends paid on our common stock.

88

Stock options and RSUs under the LTISA plan are as follows:

As of December 31, 2001 2000 1999 Weighted Weighted Weighted Average Average Average Shares Exercise Shares Exercise Shares Exercise (Thousands) Price (Thousands) Price (Thousands) Price Outstanding, beginning of year ................... 2,105.6 $ 22.583 2,418.6 S 34.139 1,590.7 S 36.106 Granted ....................................................... 649.4 24.75 1,953.1 15.513 981.6 30.613 Exercised .................................................... (278.2) 19.05 (0.5) 15.625 Forfeited ..................................................... (21.7) 17.86 (2,265.6) 28.827 (153.7) 31.985 Outstanding, end of year ............................. 2,455.1 S 24.56 2_105.6 S 22.583 2,418*6 $ 34.139 Weighted-average fair value of awards granted during the year ................. S 24.08 S 11.28 S 8.22 Stock options and RSUs issued and outstanding at December 31, 2001 are as follows:

Number Weighted Weighted Range of Issued Average Average Exercise and Contractual Exercise Price Outstanding Life in Years Price Options - Exercisable:

2000 .......................................................................... S 15.3125 3,494 9 S 15.31 19 9 9 .......................................................................... 27.8125-32.125 28,546 8 29.44 19 9 8 . .................................. ..................................... 38.625-43.125 218,380 7 40.97 19 9 7 .......................................................................... 30.750 185,630 6 30.75 19 9 6 .......................................................................... 29.250 90 290 5 29.25 526,340 Options - Not Exercisable:

2 0 0 0 .......................................................................... $ 15.3125 14,273 9 $15.31 19 9 9 .......................................................................... 27.8125-32.125 11,660 8 29.44 25 933 Range of Fair Value at Grant Date Restricted share units:

2001 ..................................................................... $21.600-S24.200 576,470 2000 .......................................................................... 15.3125-19.875 1,037,893 19 9 9 .......................................................................... 27.8125-32.125 152,000 19 9 8 .......................................................................... 38.625 136,500 1 902 863 Total issued ........................................................... 4_2ASA6 An equal number of dividend equivalents were issued to recipients of stock options and RSUs. Recipients of RSUs receive dividend equivalents when dividends are paid on shares of company stock. The value of each dividend equivalent related to stock options is calculated by accumulating dividends that would have been paid or payable on a share of company common stock. The dividend equivalents, with respect to stock options, expire after nine years from date of grant. The weighted-average grant-date fair value of the dividend equivalents on stock options was $6.28 in 2001 and $6.27 in 2000.

89

The fair value of stock options and dividend equivalents were estimated on the date of grant using the Black-Scholes option-pricing model. The model assumed the following at December 31, 2000. There were no options granted in 2001.

2000 Dividend yield ........................................... 6.32%

Expected stock price volatility .................. 16.42%

Risk-free interest rate ................................ 5.79%

Remaining expected option life ................ 5 years Protection One Stock Warrants and Options Protection One has outstanding stock warrants and options that were considered reissued and exercisable upon our acquisition of Protection One on November 24, 1997. The 1997 Long-Term Incentive Plan (the LTIP),

approved by the Protection One stockholders on November 24, 1997, provides for the award of incentive stock options to directors, officers and key employees. Under the LTIP, 4.2 million shares of Protection One are reserved for issuance, subject to such adjustment as may be necessary to reflect changes in the number or kinds of shares of common stock or other securities of Protection One. The LTIP provides for the granting of options that qualify as incentive stock options under the Internal Revenue Code and options that do not so qualify.

Options issued since 1997 have a term of 10 years and vest ratably over 3 years. The purchase price of the shares issuable pursuant to the options is equal to (or greater than) the fair market value of the common stock at the date of the option grant.

A summary of warrant and option activity for Protection One common stock from December 31, 1999 through December 31, 2001 is as follows:

December 31.

2001 2000 1999 Weighted- Weighted- Weighted Average Average Average Shares Exercise Shares Exercise Shares Exercise (Thousands) Price (Thousands) Price (Thousands) Price Outstanding, beginning of year ........... 4,404.6 $ 6.058 3,788.1 $ 7.232 3,422.7 $ 7.494 Granted ............................................... 1,880.5 1.327 922.5 1.436 1,092.9 7.905 Exercised ............................................ (59.7) 2.490 (5.4) 3.890 -

Forfeited ............................................. (555.3) 4.941 (300.6) 6.698 (727.5) 10.125 Outstanding, end of year ..................... 5&MI 4.281 4A404.6 6.058 .328 7.232 90

Stock options and warrants of Protection One issued and outstanding at December 31, 2001 are as follows:

Number Weighted Weighted Range of Issued Average Average Exercise and Contractual Exercise Price Outstanding Life in Years Price Exercisable:

Fiscal 1995 ..................... S6,375 - $6.500 130,800 3 $6.4954 Fiscal 1996 ..................... 8.000 - 15.000 438,400 4 10.0478 Fiscal 1997 .................... 9.500 - 15.000 209,000 5 11.9565 Fiscal 1998 ..................... 11.000 812,500 6 11.0000 Fiscal 1999 ..................... 5.250 - 8.9275 355,606 7 8.4857 Fiscal 2000 ..................... 1.4375 153,372 8 1.4375 1993 Warrants ................ 0.167 428,400 2 0.1670 1995 Note W arrants ....... 3.890 780,_837 3 3.8900 Total ...................... 3,308,915 Not Exercisable:

1999 options ................... $5.2500 - $8.9275 165,008 7 S8.4857 2000 options ................... 1.4375 315,648 8 1.4375 2001 options ................... 0.8750 - 1.480 16880,541 9 1.3273 Total ...................... 2,361,197 Total outstanding ................ -5zg-oAý2 The weighted average fair value of options for Protection One stock granted by Protection One during 2001, 2000 and 1999 estimated on the date of grant were $1.88, $1.13 and $5.41. The fair value was calculated using the following assumptions:

Year Ended December 31 2001 2000 1999 Expected stock price volatility ................ 83.92% 92.97% 64.06%

Risk free interest rate .............................. 4.95% 4.87% 6.76%

Expected option life ................................ 7 years 6 years 6 years Effect of Stock-Based Compensation on Earnings Per Share We account for both our and Protection One's plans under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and the related interpretations. Had compensation expense been determined pursuant to SFAS No. 123, "Accounting for Stock-Based Compensation," we would have recognized additional compensation costs during 2001, 2000 and 1999 as shown in the table below.

Year Ended December 31, 2001 2000 1999 (In Thousands, Except Per Share Amounts)

Earnings (loss) available for common stock (a):

As reported ............................................................. $ (21,771) $135,352 $ 13.167 Pro forma ............................................................... (21,259) 134,274 10,699 Basic and diluted earnings (losses) per common share (a):

As reported ............................................................. $ (0.31) $ 1.96 $ 0.20 Pro forma ............................................................... $ (0.30) 1.95 0.16 (a) Represents consolidated Western Resources.

91

Split Dollar Life Insurance Program We have established a split dollar life insurance program for our benefit and the benefit of certain of our executives. Under the program, we have purchased life insurance policies on which the executive's beneficiary is entitled to a death benefit in an amount equal to the face amount of the policy reduced by the greater of (i) all premiums paid by the company or (ii) the cash surrender value of the policy, which amount, at the death of the executive, will be returned to us. We retain an equity interest in the death benefit and cash surrender value of the policy to secure this repayment obligation.

Subject to certain conditions, each executive may transfer to us their interest in the death benefit based on a predetermined formula, beginning no earlier than the first day of the calendar year following retirement or three years from the date of the policy. The liability associated with this program was $18.6 million as of December 31, 2001 and $19.1 million as of December 31, 2000. The obligations under this program can increase and decrease based on our total return to shareholders and payments to plan participants. This liability decreased approximately

$0.5 million in 2001 primarily due to balance adjustments and $12.8 million in 2000 due primarily to payments to plan participants. In 1999, the liability decreased approximately $10.5 million based on our total return to shareholders. Under current tax rules, payments to active employees in exchange for their interest in the death benefits may not be fully deductible by us for income tax purposes. Subsequent to December 31, 200 1, this liability was reduced by a payment of $4.6 million pursuant to the plan.

13. INCOME TAXES Income tax expense (benefit) is composed of the following components at December 31:

2001 2000 1999 (In Thousands)

Current income taxes:

Federal ....................................................... $(21,942) $ 39,747 $ 12,996 State ........................................................... (186) 10,131 9,622 Deferred income taxes:

Federal ....................................................... (28,363) 18,060 (35,857)

State ........................................................... 1,180 9,585 (6,582)

Investment tax credit amortization ................ (6,646) (6,045) (6.054)

Total ...................................................... (55,957) 71,478 (25,875)

Less taxes classified in:

Extraordinary gain ...................................... 12,571 26,514 6,322 Cumulative effect of accounting change ..... 12,347 (1,097)

Total income tax (benefit) expense ............. 4_$.197 92

Under SFAS No. 109, "Accounting for Income Taxes," temporary differences gave rise to deferred tax assets and deferred tax liabilities summarized in the following table.

December 31.

2001 2000 (In Thousands)

Deferred tax assets:

Deferred gain on sale-leaseback .................................................. $ 76,806 S 82,013 Customer accounts ....................................................................... 60,023 49,853 General business credit carryforward (a) ..................................... 28,494 11,012 Accrued liabilities ........................................................................ 23,511 21,108 Disallowed plant costs ................................................................. 16,650 17,758 Long-term energy contracts ......................................................... 13,538 14,209 Other ......................................................................................... 115,874 110,261 Total deferred tax assets ........................................................... 334 896 $ 306,214 Deferred tax liabilities:

Accelerated depreciation ............................................................. S 617,682 $ 627,024 Acquisition premium ................................................................... 267,161 275,159 Deferred future incom e taxes ....................................................... 222,071 188,006 Investment tax credits .................................................................. 84,900 91,546 Other ............................................................................................ 39,443 44,562 Total deferred tax liabilities ..................................................... $1.23 1,257 5 1,226,297 (a) Balance represents unutilized tax credits generated from affordable housing partnerships in which we sold the majority of our interests in 2001. These credits expire beginning 2019 through 2021.

Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows:

December 3 1.

2001 2000 (In Thousands)

Current deferred tax assets, net ................. $ 27,817 $ 34,512 Non-current deferred tax liabilities, net .... 924.178 954.595 Net deferred tax liabilities ......................... $ 896.361 $920,083 In accordance with various rate orders, we have not yet collected through rates certain accelerated tax deductions, which have been passed on to customers. We believe it is probable that the net future increases in income taxes payable will be recovered from customers. We have recorded a regulatory asset for these amounts.

These assets are also a temporary difference for which deferred income tax liabilities have been provided. This liability is classified above as deferred future income taxes.

93

The effective income tax rates set forth below are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective tax rates and the federal statutory income tax rates are as follows:

For the Year Ended December 31, 2001 2000 1999 Effective income tax rate ........................................................... (56.3)% 33.6% (108.6)%

Effect of:

State income taxes .................................................................. 0.6 (9.4) (7.1)

Amortization of investment tax credits ................................... 4.6 4.4 20.4 Corporate-owned life insurance policies ................................ 9.5 8.4 28.0 Affordable housing tax credits ............................................... 6.8 7.8 31.3 Accelerated depreciation flow through and amortization ....... (0.1) (4.9) (12.2)

Dividends received deduction ................................................ 7.1 7.1 34.3 Amortization of goodwill ....................................................... (10.6) (13.0) (19.3)

O ther ....................................................................................... 3.4 1.0 (1.8)

Statutory federal income tax rate ................................................ (  % 35.0%  %

14. COMMITMENTS AND CONTINGENCIES Municipalization Efforts by Wichita In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system and arrange for its own power supply.

These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 200 1, the City of Wichita announced its intention to proceed with its attempt to municipalize KGE's retail electric utility business in Wichita. KGE will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material.

KGE's franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, KGE will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 23% of our total energy sales.

Purchase Orders and Contracts As part of our ongoing operations and construction program, we have commitments under purchase orders and contracts, excluding fuel (which is discussed below under "- Fuel Commitments,") that have an unexpended balance of approximately $98.4 million at December 31, 2001.

Manufactured Gas Sites We have been associated with 15 former manufactured gas sites located in Kansas that may contain coal tar and other potentially harmful materials. We and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement governing all future work at these sites. The terms of the consent agreement will allow us to investigate these sites and set remediation priorities based on the results of the investigations and risk analysis. At December 31, 2001, the costs incurred for preliminary site investigation and risk assessment have been 94

minimal. In accordance with the terms of the strategic alliance with ONEOK, ownership of twelve of these sites and the responsibility for clean-up of these sites were transferred to ONEOK. The ONEOK agreement limits our future liability associated with these sites to an immaterial amount. Our investment earnings from ONEOK could be impacted by these costs.

Superfund Sites In December 1999, we were identified as one of more than 1,000 potentially responsible parties at an EPA Superfund site in Kansas City, Kansas (Kansas City site). We have previously been associated with other Superfund sites for which our liability has been classified as de minimis, or insignificant, and any potential obligations have been settled at minimal cost. Since 1993, we have settled Superfund obligations at three sites for a total of $141,300.

We were notified in 2001 that one site was issued an EPA "Notice of Completion of Work" and final oversight costs have been paid out of the existing joint responsible party account, which has an adequate balance to cover this expense. This effectively closes this site and we can expect a refund in 2002 of our share of the remaining funds in this account. Our obligation, if any, at the Kansas City site is expected to be limited based upon previous experience and the limited nature of our business transactions with the previous owners of the site. In the opinion of our management, the resolution of this matter is not expected to have a material impact on our financial position or results of operations.

Clean Air Act We must comply with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. We have installed continuous monitoring and reporting equipment to meet the acid rain requirements. Material capital expenditures have not been required to meet Phase II sulfur dioxide and nitrogen oxide requirements.

Nuclear Decommissioning We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs, which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund.

On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost Study on April 26, 2000. Based on the study, our share of Wolf Creek's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $631 million during the period 2025 through 2034, or approximately $221 million in 1999 dollars.

These costs include decontamination, dismantling and site restoration and were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1999 of 26 years. The actual decommissioning costs may vary from the estimates because of changes in the assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs of labor, materials and equipment. On May 26, 2000, we filed an application with the KCC requesting approval of the funding of our decommissioning trust on this basis. Approval was granted by the KCC on September 20, 2000.

Decommissioning costs are currently being charged to operating expense in accordance with prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated S4.0 million in 2001 and will increase annually to $5.5 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.8%.

Our investment in the decommissioning fund is recorded at fair value, including reinvested earnings. It approximated $66.6 million at December 31, 2001 and $64.2 million at December 31, 2000. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability.

95

Storage of Spent Nuclear Fuel Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation produced for the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales.

A permanent disposal site will not be available for the nuclear industry until 2010 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025.

Asset Retirement Obligations In August 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When it is initially recorded, we will capitalize the estimated asset retirement obligation by increasing the carrying amount of the related long-lived asset. The liability will be accreted to its present value each period and the capitalized cost will be depreciated over the life of the asset. The standard is effective for fiscal years beginning after June 15, 2002. We expect to adopt this standard January 1, 2003. This standard will impact the way we currently account for the decommissioning of Wolf Creek. In addition to the accounting for the Wolf Creek decommissioning, we are also reviewing what impact this pronouncement will have on our current accounting practices and our results of operations as it relates to other asset retirement obligations we may identify. The impact is unknown at this time.

Nuclear Insurance The Price-Anderson Act, originally passed by Congress in 1957 and most recently amended in 1988, requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two levels. The primary level provides liability insurance coverage of $200 million. If this amount is not sufficient to cover claims arising from an accident, the second level - Secondary Financial Protection - applies. For the second level, each licensed nuclear unit must pay a retroactive premium equal to its proportionate share of the excess loss, up to a maximum of $88.1 million per unit per accident.

Currently, 106 nuclear units are participating in the Secondary Financial Protection program - 103 operating units and three closed units that still handle used nuclear fuel. The number of units participating in the program will be reduced as decommissioned units apply for and receive exemptions. Nuclear power plants provide a total of $9.5 billion in insurance coverage to compensate the public in the event of a nuclear accident. Taxpayers and the federal government pay nothing for this coverage.

The Nuclear Regulatory Commission (NRC) was required to submit a report to Congress, which was submitted in September 1998 and describes the benefits that the act provides to the public. It also recommends that the act be extended for an additional ten years. The DOE submitted a report to Congress in March 1999, recommending renewal of the act.

Bipartisan legislation was introduced in the 106th Congress in the Senate providing a simple renewal of Price-Anderson based on the DOE and NRC reports. The nuclear industry supports such a legislative approach for consideration early in the 107th Congress.

96

Unless Congress renews the Price-Anderson Act, it will expire in part on August 1, 2002 as follows:

- The only part of Price-Anderson that expires on August 1, 2002, is the authority of the NRC and the DOE to enter into new indemnity agreements after that date. Existing indemnity agreements would continue in full force and effect.

- Without renewal, new nuclear power plants could not be covered, nor could new DOE contracts have the indemnity provision (including the proposed high-level radioactive waste disposal site in Yucca Mountain, Nevada).

The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.5 billion for a single nuclear incident. If this liability limitation is insufficient, the United States Congress will consider taking whatever action is necessary to compensate the public for valid claims. However, on February 2, 2002, the United States Senate announced that it is considering discontinuing the federal insurance provision.

The Wolf Creek owners have purchased the maximum available private insurance of $200 million. The remaining balance is provided by an assessment plan mandated by the NRC. Under this plan, the owners are jointly and severally subject to a retrospective assessment of up to $88.1 million in the event there is a major nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million in retrospective assessments per incident, per year.

The owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion our share). This insurance is provided by Nuclear Electric Insurance Limited (NEIL). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or decontamination expenses or, if certain requirements are met including decommissioning the plant, toward a shortfall in the decommissioning trust fund.

The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves and other NEIL resources, we may be subject to retrospective assessments under the current policies of approximately $10.7 million per year.

Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on our financial condition and results of operations.

Fuel Commitments To supply a portion of the fuel requirements for our generating plants, we have entered into various commitments to obtain nuclear fuel and coal. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 2001, WCNOC's nuclear fuel commitments (our share) were approximately $3.2 million for uranium concentrates expiring in 2003, $0.6 million for conversion expiring in 2003,

$22.7 million for enrichment expiring at various times through 2006 and $57.5 million for fabrication through 2025.

At December 31, 2001, our coal and coal transportation contract commitments in 2001 dollars under the remaining terms of the contracts were approximately $2.0 billion. The largest contract expires in 2020, with the remaining contracts expiring at various times through 2013.

At December 31, 2001, our natural gas transportation commitments in 2001 dollars under the remaining terms of the contracts were approximately $56.8 million. The natural gas transportation contracts provide firm 97

service to several of our gas burning facilities and expire at various times through 2010, except for one contract that expires in 2016.

Energy Act As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment decontamination and decommissioning fund. Our portion of the assessment for Wolf Creek is approximately $9.6 million, payable over 15 years. Such costs are recovered through the ratemaking process.

15. PNM MERGER AND SPLIT-OFF OF WESTAR INDUSTRIES PNM Transaction On November 8, 2000, we entered into an agreement with Public Service Company of New Mexico (PNM),

pursuant to which PNM would acquire our electric utility businesses in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and we are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. Immediately prior to closing, all of the Westar Industries common stock we own would be distributed to our shareholders in exchange for a portion of their Western Resources common stock. At the same time we entered into the agreement with PNM, we and Westar Industries entered into an Asset Allocation and Separation Agreement which, among other things, provided for this split-off and related matters.

On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the KCC orders discussed below and other KCC orders reducing rates for our electric utility business. PNM believes the orders constitute a material adverse effect and make the condition that the split off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation.

On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court of the State of New York.

The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of our electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, we filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement.

On January 7, 2002, PNM sent a letter to us purporting to terminate the merger in accordance with the terms of the merger agreement. We have notified PNM that we believe the purported termination of the merger agreement was ineffective and that PNM remains obligated to perform thereunder. We intend to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, we believe the closing of the proposed merger is not likely.

KCC Proceedings and Orders The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of our electric utility businesses from our non-utility businesses, including the rights offering, and other aspects of our unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving our unregulated businesses are consistent with our obligation to provide efficient and sufficient electric service at just and reasonable rates to our electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement we entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by us to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by our unregulated businesses and whether they should continue to be affiliated with our electric utility business, and our present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying 98

the Asset Allocation and Separation Agreement, prohibiting Westar Industries and us from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent.

On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting us and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed us and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in our capital structure applicable to our electric utility operations, which has the effect of prohibiting us from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed us to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of our non-utility businesses. In its order, the KCC also acknowledged that we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. We appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not final orders and that the District Court lacked jurisdiction to consider the appeal.

Accordingly, the matter was remanded to the KCC for review of the financial plan.

On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that we and the KCC staff make filings addressing whether the filing of applications by us and KGE at FERC, seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that we not increase the share of debt in our capital structure applicable to our electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC filed a motion to intervene in the proceeding at FERC asserting the same position. We are unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on our ability to refinance indebtedness maturing in the next several years. Our inability to refinance existing indebtedness on a secured basis would likely increase our borrowing costs and adversely affect results of operations.

The Financial Plan The July 20, 2001 KCC order directed us to present a financial plan to the KCC. We presented a financial plan to the KCC on November 6, 2001, which we amended on January 29, 2002. The principal objective of the financial plan is to reduce our total debt as calculated by the KCC to approximately $1.8 billion, a reduction of approximately $1.2 billion. The financial plan contemplates that we will proceed with a rights offering and that, in the event that the PNM merger and related split-off do not close, we will use our best efforts to sell our share of Westar Industries common stock, or shares of our common stock, upon the occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to review the financial plan. We are unable to predict whether or not the KCC will approve the financial plan or what other action with respect to the financial plan the KCC may take.

The financial plan provides that:

- Westar Industries will use its best efforts to sell at least 4.14 million shares of its common stock, representing approximately 5.1% of its outstanding shares, but no more than the number of shares of its common stock (approximately 19.13 million shares) representing 19.9% of its outstanding shares.

After the offering, we would continue to own 77.0 million shares representing between 80.1% and 94.9% of Westar Industries' outstanding shares. The offering will remain open for no less than 45 calendar days.

- In the rights offering, each of our shareholders will receive the right to purchase one share of Westar Industries' common stock for every three shares of our stock held on the record date of the offering.

There will be no over-subscription privilege in the offering. However, each shareholder participating in the offering will be issued, with respect to each right exercised in the offering, a warrant to purchase 99

from Westar Industries two shares of its common stock at the subscription price in the offering, subject to proration so that in no event will we hold less than 80.1% of Westar Industries' outstanding shares.

This right will be exercisable at any time in the 30-day period preceding January 31, 2003.

So long as we and Westar Industries are tax consolidated, Westar Industries' common stock sold in the offering will have one vote per share and Westar Industries common stock held by us will have 10 votes per share. Any shares sold by us will automatically convert to shares with one vote per share.

The exercise price in the offering will be a fixed price determined on the day the offer is mailed to shareholders by calculating the "Westar Industries Valuation" as set forth in an exhibit to the plan and then applying a 10% initial public offering discount.

Westar Industries will have a rescission right through December 31, 2002. This will give Westar Industries the right to repurchase the shares sold in the rights offering at a price equal to the greater of (i) 1.05 times the exercise price, or (ii) the market price at the time of the repurchase offer. The warrants issued to participating shareholders in the offering will expire if the rescission right is exercised. We would not be able to sell any additional shares prior to the expiration of the rescission period.

The proceeds from the offering (or any other subsequent sale of stock by Westar Industries) and any dividends from the ONEOK common or convertible preferred stock not used in Westar Industries' business or previously committed will be used to purchase in the market our or KGE's currently outstanding debt securities. On February 10, 2003, such debt securities and the balance, if any, of our intercompany payable with Westar Industries will be converted into our common stock at the average trading price for the 20 days prior to conversion, but in no event less than $24 per share. However, if the PNM transaction is not terminated, such funds and the intercompany payable will be transferred by us to Westar Industries to purchase 7.5% Western Resources convertible preferred stock, convertible into our common stock at $30 per share, as provided in the PNM merger agreement. Prior to tax deconsolidation, Westar Industries cannot receive any cash dividends from us, but will instead reinvest those dividends in additional shares of our common stock. Dividends on the convertible preferred stock will be payable in additional preferred shares rather than cash. Westar Industries will use interest received on our and KGE debt securities it purchases as provided above to purchase additional debt securities.

If the PNM transaction is not terminated, the amount of our convertible preferred stock purchased by Westar Industries will not exceed $291 million. Westar Industries will continue to own our common stock it currently owns. Westar Industries will retain its option to purchase Westar Generating, Inc., a wholly owned subsidiary of ours, which owns an interest in the State Line Facility (see "Item 2.

Properties" for a description of this facility and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Information - Related Party Transactions" for a discussion of this purchase option).

Westar Industries will not vote any of our common stock it owns as long as we are tax consolidated.

Westar Industries will adopt a "poison pill" that will restrict ownership in it to 20% of the shares not owned by us.

The rights offering and subsequent sale of Westar Industries' shares by us pursuant to the plan do not constitute a change in control for our employees under the terms of existing agreements and no agreements will be executed which include a provision under which the offering and sale of Westar Industries' shares by us pursuant to the plan would constitute a change in control.

We will not sell more than 19.9% of Westar Industries unless we have $1.8 billion or less in short- and long-term debt and all of our and KGE's first mortgage bonds are rated investment grade.

100

In the event Westar Industries' common stock trades for 45 consecutive trading days at a price that is 15% above the price necessary to reduce our short- and long-term debt to an amount less than $1.8 billion (as measured at the end of the immediately preceding fiscal quarter), we will be required to use our best efforts to sell enough shares in Westar Industries, or us, or a combination of both (at our option), to reduce debt to $1.8 billion. However, in no event shall this obligation be triggered prior to February 1, 2003, unless the PNM transaction is terminated prior to that date. Furthermore, on each annual anniversary of the closing of the rights offering, the amount of debt used to determine whether our obligation has been triggered will increase by $100 million.

We agree to reduce our total debt by at least $100 million per year each year following the completion of the offering until the separation is consummated.

Our board of directors will have at least a majority of independent directors following the separation.

16. LEGAL PROCEEDINGS The Securities and Exchange Commission (SEC) commenced a private investigation in 1997 relating to, among other things, the timeliness and adequacy of disclosure filings with the SEC by us with respect to securities of ADT Ltd. We have cooperated with the SEC staff in this investigation.

We, Westar Industries, Protection One, its subsidiary Protection One Alarm Monitoring, Inc. (Protection One Alarm Monitoring) and certain present and former officers and directors of Protection One are defendants in a purported class action litigation pending in the United States District Court for the Central District of California, "Alec Garbini, et al v. Protection One, Inc., et al," No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999, four pending purported class actions were consolidated into a single action. On February 27, 2001, plaintiffs filed a Third Consolidated Amended Class Action Complaint (Third Amended Complaint). Plaintiffs purported to bring the action on behalf of a class consisting of all purchasers of publicly traded securities of Protection One, including common stock and bonds, during the period of February 10, 1998 through February 2, 2001. The Third Amended Complaint asserted claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934 against Protection One, Protection One Alarm Monitoring, and certain present and former officers and directors of Protection One based on allegations that various statements concerning Protection One's financial results and operations for 1997, 1998, 1999 and the first three quarters of 2000 were false and misleading and not in compliance with generally accepted accounting principles. Plaintiffs alleged, among other things, that former employees of Protection One have reported that Protection One lacked adequate internal accounting controls and that certain accounting information was unsupported or manipulated by management in order to avoid disclosure of accurate information. The Third Amended Complaint further asserted claims against us and Westar Industries as controlling persons under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. A claim was also asserted under Section 11 of the Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP. The Third Amended Complaint sought an unspecified amount of compensatory damages and an award of fees and expenses, including attorneys' fees. On June 4, 2001, the District Court dismissed plaintiffs' claims under Sections 10(b) and 20(a) of the Securities Exchange Act. The Court granted plaintiffs leave to replead such claims. The Court also dismissed all claims brought on behalf of bondholders with prejudice. The Court also dismissed plaintiffs' claims against Arthur Andersen and the plaintiffs have appealed that dismissal. On February 22, 2002, plaintiffs filed a Fourth Consolidated Amended Class Action Complaint. The new complaint realleges claims on behalf of purchasers of common stock under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The defendants have until April 5, 2002 to respond to the new complaint. Protection One and we cannot predict the impact of this litigation, which could be material.

We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provision has been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect upon our overall financial position or results of operations. See also Notes 3 and 15 for discussion of FERC proceedings and the lawsuit PNM filed against us and the KCC regulatory proceedings.

101

17. LEASES At December 31, 2001, we had leases covering various property and equipment. Rental payments for operating leases ranging from 1 to 17 years and estimated rental commitments are as follows:

LaCygne 2 Total Year Ended December 31, Lease (a) Leases (In Thousands)

Rental payments:

1999 ....................................................................... $ 34,598 $ 71,771 2000 ....................................................................... 34,598 71,232 2001 ....................................................................... 34,598 75,259 Future commitments:

2002 ....................................................................... $ 34,598 $ 69,897 2003 ....................................................................... 39,420 66,772 2004 ....................................................................... 34,598 58,492 2005 ....................................................................... 38,013 57,983 2006 ....................................................................... 42,287 61,309 Thereafter ............................................................... 422,318 516,318 Total future commitments ................................... .$ 611,234 $830.771 (a) LaCygne 2 lease amounts are included in total leases.

In 1987, KGE sold and leased back its 50% undivided interest in the LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50%

undivided interest. KGE remains responsible for its share of operation and maintenance costs and other related operating costs of LaCygne 2. The lease is an operating lease for financial reporting purposes. We recognized a gain on the sale, which was deferred and is being amortized over the initial lease term.

In 1992, we deferred costs associated with the refinancing of the secured facility bonds of the Trustee and owner of LaCygne 2. These costs are being amortized over the life of the lease and are included in operating expense.

18. COMMON STOCK, PREFERRED STOCK AND OTHER MANDATORILY REDEEMABLE SECURITIES Our Restated Articles of Incorporation, as amended, provide for 150,000,000 authorized shares of common stock. At December 31, 2001, 86,205,417 shares were issued and outstanding, including shares owned by Westar Industries.

We have a Direct Stock Purchase Plan (DSPP). Shares issued under the DSPP may be either original issue shares or shares purchased on the open market. During 2001, a total of 16,643,403 shares were purchased from the company through the issuance of 16,123,103 original issue shares and 520,300 treasury shares. Of the total shares purchased from us in 2001, 15,047,987 were acquired by Westar Industries and the balance of the shares were for the DSPP, ESPP, 401 (k) match and other stock based plans operated under the 1996 Long-Term Incentive and Share Award Plan. At December 31, 2001, 4,300,577 shares were available under the DSPP registration statement.

In 2000, we purchased 540,000 shares of our common stock at an average price of $17.01. All of these shares were reissued during the year.

102

Preferred Stock Not Subject to Mandatory Redemption The cumulative preferred stock is redeemable in whole or in part on 30 to 60 days notice at our option.

Total Principal Call Amount Rate Outstanding Price Premium to Redeem (Dollars in Thousands) 4.500% $13,445 108.00% $1,076 $14,521 4.250% 5,841 101.50% 88 5,929 5.000% 4,650 102.00% 93 4,743 The provisions of our Restated Articles of Incorporation, as amended, contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met.

Other Mandatorily Redeemable Securities On December 14, 1995, Western Resources Capital I, a wholly owned trust, issued 4.0 million preferred securities of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A, for $100 million. The trust interests are redeemable at the option of Western Resources Capital I on or after December 11, 2000, at $25 per preferred security plus accrued interest and unpaid dividends. Holders of the securities are entitled to receive distributions at an annual rate of 7-7/8% of the liquidation preference value of $25. Distributions are payable quarterly and are tax deductible by us. These distributions are recorded as interest expense. The sole asset of the trust is $103 million principal amount of 7-7/8% Deferrable Interest Subordinated Debentures, Series A due December 11, 2025.

On July 31, 1996, Western Resources Capital II, a wholly owned trust, of which the sole asset is subordinated debentures of ours, sold in a public offering, 4.8 million shares of 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B, for $120 million. The trust interests are redeemable at the option of Western Resources Capital II, on or after July 31, 2001, at $25 per preferred security plus accumulated and unpaid distributions. Holders of the securities are entitled to receive distributions at an annual rate of 8-1/2% of the liquidation preference value of $25. Distributions are payable quarterly and are tax deductible by us. These distributions are recorded as interest expense. The sole asset of the trust is $124 million principal amount of 8-1/2%

Deferrable Interest Subordinated Debentures, Series B due July 31, 2036.

In addition to our obligations under the Subordinated Debentures discussed above, we have agreed to guarantee, on a subordinated basis, payment of distributions on the preferred securities. These undertakings constitute a full and unconditional guarantee by us of the trust's obligations under the preferred securities.

Treasury Stock At December 31, 2001, all of our treasury stock was owned by Westar Industries, except for 50,000 shares owned by Protection One.

103

19. RELATED PARTY TRANSACTIONS Below we describe significant transactions between us and Westar Industries and other subsidiaries and related parties. We have disclosed significant transactions even if these have been eliminated in the preparation of our consolidated results and financial position since our proposed financial plan, as discussed in Note 15, calls for a split-off of Westar Industries from us to occur in the future. We cannot predict whether the KCC will aprove the plan and if so whether we will be successful in executing the plan.

We and ONEOK have shared services agreements in which we provide and bill one another for facilities, utility field work, information technology, customer support and bill processing. Payments for these services are based on various hourly charges, negotiated fees and out-of-pocket expenses.

2001 2000 1999 (In Thousands)

Charges to ONEOK ................................ $8,202 $8,463 $8,876 Charges from ONEOK ............................ 3,279 3,420 3,322 Net receivable from ONEOK, outstanding at December 31 ............... 1,424 1,205 1,506 In 1999, we and Protection One have entered into a service agreement pursuant to which we provide administrative services, including accounting, human resources, legal, facilities and technology services on a year to year basis. Fees for these services are based upon various hourly charges, negotiated fees and out-of-pocket expenses. Protection One incurred charges of $8.1 million in 2001, $7.3 million in 2000 and $2.0 million in 1999.

These intercompany charges have been eliminated in consolidation.

We had a payable to Westar Industries of approximately $67.7 million at December 31, 2001 on which we paid interest at the rate of 8.5% per annum. On February 28, 2001, Westar Industries converted $350.0 million of the then outstanding payable balance into approximately 14.4 million shares of our common stock, representing 16.9% of our outstanding common stock after conversion. These shares are reflected as treasury stock in our consolidated balance sheets. During the first quarter of 2002, we repaid the remaining balance owed to Westar Industries. The proceeds were used by Westar Industries to purchase our outstanding debt in the open market. At February 28, 2002, Westar Industries owned $118.7 million of our debt. Amounts outstanding and interest earned by Westar Industries have been eliminated in our consolidated financial statements. See Note 2 "Summary of Significant Accounting Policies - Principles of Consolidation."

Westar Industries is the lender under Protection One's senior credit facility. On November 1, 2001, this facility was amended to, among other things, extend the maturity date to January 3, 2003, and provide for a quarterly fee for financial advisory and management services equal to 1/8% of Protection One's consolidated total assets at the end of each quarter, beginning with the quarter ending March 31, 2002. As of December 31, 2001, approximately

$137.5 million was drawn under the facility. On March 25, 2002, Westar Industries further amended the facility to increase the amount of the facility to $180 million. Amounts outstanding have been eliminated in our consolidated financial statements.

We have a tax sharing agreement with Protection One. This pro rata tax sharing agreement allows Protection One to be reimbursed for current tax benefits utilized in our consolidated tax return. We and Protection One are eligible to file on a consolidated basis for tax purposes as long as we maintain an 80% ownership interest in Protection One. We reimbursed Protection One $11.8 million for tax year 2001 and $7.4 million for tax year 2000 for the current tax benefit.

During 2001, Westar Industries purchased $37.9 million face value of Protection One bonds on the open market. In October 2001, $27.6 million of these bonds were transferred to Protection One in exchange for cash. In 2001, we recognized an extraordinary gain from the purchase of Protection One bonds of $22.3 million, net of tax of

$12.0 million. During 2000, Westar Industries purchased $170.0 million face value of Protection One bonds on the open market. In exchange for cash and the settlement of certain intercompany payables and receivables, $103.9 104

million of these debt securities were transferred to Protection One. The balance of the bonds was sold to Protection One in March 2001. No gain or loss was recognized on these transactions.

In the latter part of 2001 through February 28, 2002, Protection One purchased approximately $1.8 million of our preferred stock in open market purchases. These purchases have been accounted for as retirements.

During 2001, we extended loans to our officers for the purpose of purchasing shares of our common stock on the open market. The loans are unsecured and contain a variable interest rate that is equal to our short term borrowing rate. Interest is payable quarterly. The loans mature and become due on December 4, 2004. The balance outstanding at December 31, 2001 was approximately $2.0 million and is classified as a reduction to shareholders' equity in the accompanying consolidated balance sheet. The maximum amount of loans authorized is $7.9 million.

During the fourth quarter of 2001, KGE entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One for approximately $0.5 million. The sales price was determined by management based on three independent appraisers' findings.

On February 29, 2000, Westar Industries purchased the European operations of Protection One, and certain investments held be a subsidiary of Protection One for an aggregate purchase price of $244 million. Westar Industries paid approximately $183 million in cash and transferred Protection One debt securities with a market value of approximately $61 million to Protection One. Westar Industries has agreed to pay Protection One a portion of the net gain, if any, on a subsequent sale of the European businesses on a declining basis over the four years following the closing. Cash proceeds from the transaction were used to reduce the outstanding balance owed to Westar Industries on Protection One's revolving credit facility. No gain or loss was recorded on this intercompany transaction and the net book value of the assets was unaffected.

If the KCC approves our financial plan, at the closing of the proposed rights offering, we would enter into an option agreement that grants Westar Industries an option to purchase the stock of Westar Generating, Inc., a wholly owned subsidiary that owns our interest in the State Line generating facility. The option would be exercisable at any time during the three year period following execution of the agreement, subject to extension for two additional one year periods. The option price is based on net book value at the time of exercise. The option would be exercisable only if Westar Industries is unable to obtain a permanent exemption from registration under the Investment Company Act of 1940.

20. WORK FORCE REDUCTIONS In late 2001, we reduced our utility work force by approximately 200 employees through involuntary separations and recorded a severance-related net charge of approximately $14.3 million. In 2001, Protection One also reduced its work force by approximately 500 employees in connection with facility consolidations and recorded a severance-related net charge of approximately $3.1 million.

In the first quarter of 2002, we further reduced our utility work force by approximately 400 employees through a voluntary separation program. We expect to record a net charge of approximately $21.1 million in the first quarter of 2002 related to this program. We may replace some of these employees. Protection One also reduced its work force by approximately 200 employees in connection with facility consolidations and expects to record a net severance charge of approximately $0.5 million in the first quarter of 2002.

21. MONITORED SERVICES DISPOSITIONS In 2001, Protection One and Protection One Europe disposed of certain monitored security operations for approximately $48.0 million and we recorded a pre-tax loss of $13.1 million.

105

In 1999, Protection One sold the assets that comprised its Mobile Services Group. Cash proceeds of this sale approximated $20 million and Protection One recorded a pre-tax gain of approximately $17 million. This gain is reflected in Other Income on our consolidated statements of income.

22. INTERNATIONAL POWER DEVELOPMENT COSTS In 1998 we made a decision to terminate the employment of all employees, close offices, discontinue all development activities, and terminate all other matters related to the activity of The Wing Group. These activities were substantially completed by December 31, 1999. The actual costs incurred during 1999 to complete the exit plan approximated $16.9 million, which was $5.6 million less than the amount estimated and charged to income in 1998. This was accounted for as a change in estimate in 1999. The excess accrual was credited to income in 1999 and reduced our selling, general and administration costs for that period.

23. MARKETABLE SECURITIES During the last three years, we sold substantially all of our investments in marketable securities. These securities were classified as available-for-sale. Realized gains and losses are included in earnings and were derived using the specific identification method. The following table summarizes our marketable security sales for the years ended December 31, 2001, 2000 and 1999:

Marketable Security Sales 2001 2000 1999 (Dollars in Thousands)

Sales proceeds $ 2,829 $ 218,609 $ 73,456 Realized gains (a) - 115,987 12,587 Realized losses 1,861 1,039 38,838 (a) During 2000, we sold our equity investment in a gas compression company and realized a pre-tax gain of $91.1 million.

In 1999, we determined that the decline in value of our investments in paging industry companies was other than temporary and a charge to earnings for the decline in value was required. This non-cash charge of $76.2 million was recorded in the fourth quarter of 1999 and is presented separately in our consolidated statements of income.

In February 2000, one of the paging companies we held an interest in made an announcement that significantly increased the market value of paging company securities general. During the first quarter of 2000, we sold the remainder of these securities for a gain of $24.9 million.

During 2001, we wrote down the cost basis of certain equity securities to their fair value. The fair value of these equity securities had declined below our cost basis, and we determined that the decline was other than temporary. The amount of the write down totaled $11.1 million, of which $9.6 million related to a cost method investment. The write down is included in other income (expense).

24. SEGMENTS OF BUSINESS In 1998, we adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This statement requires us to define and report our business segments based on how management currently evaluates its business. Our business is segmented based on differences in products and services, production processes and management responsibility. Based on this approach, we have identified five reportable segments:

Fossil Generation, Nuclear Generation, Customer Operations, Monitored Services and Other. The Fossil Generation, Nuclear Generation and Customer Operations segments comprise our electric utility business. Fossil 106

Generation produces power for sale internally to the Customer Operations segment and externally to wholesale customers. A component of our Fossil Generation segment is power marketing, which attempts to minimize commodity price risk associated with fuel purchases and purchased power requirements. Power marketing also attempts to maximize utilization of generation capacity and enhance system reliability through sales to external customers as discussed further below. Nuclear Generation represents our 47% ownership in the Wolf Creek Generating Station (Wolf Creek). This segment has only internal sales because it provides all of its power to its co owners. The Customer Operations segment consists of the transmission and distribution of power to our retail customers in Kansas and the customer service provided to these customers and the transmission of wholesale energy.

Monitored Services is comprised of our security alarm monitoring business in North America and Europe. Other includes a 45% interest in ONEOK, investments in international power generation facilities and other investments, which in the aggregate are not material to our business or results of operations.

The accounting policies of the segments are substantially the same as those described in Note 2 "Summary of Significant Accounting Policies." Segment performance is based on earnings before interest and taxes (EBIT).

Unusual items, such as charges to income and changes in accounting principle, may be excluded from segment performance depending on the nature of the charge or income. Interest expense is excluded from the segment analysis. Our ONEOK investment, marketable securities investments and other equity method investments do not represent operating segments of ours. We have no single external customer from whom we receive ten percent or more of our revenues.

Year Ended December 31. 2001 Eliminating/

Fossil Nuclear Customer Monitored Reconciling Generation(a) Generation Operations Services Other Items Total (In Thousands)

External sales .................. $ 667,953 $ - $1,100,443 $ 416,509 S 1,360 S (3) S2,186,262 Internal sales ................... 560,528 117,659 317,056 - (995,243)

Depreciation and amortization ............... 65,875 41,046 78,235 228,123 363 -- 413,642 Earnings (loss) before interest and taxes and cumulative effect of accounting change ...... 120,530 (19,078) 131,917 (126,076) 32,651 (15,321) 124,623 Interest expense .............. 268,224 Earnings (loss) before income taxes .............. (143,601)

Additions to property, plant and equipment... 116,595 27,349 83,052 9,456 -- 236,452 Customer account acquisitions ................ -- 36,488 -- 36,488 Identifiable assets ........... 1,733,743 1,042,563 1,843,865 1,887,210 1,005,684 - 7,513,065 107

Year Ended December 31, 2000 Eliminating/

Fossil bNuclear Customer Monitored Reconciling Generation Gt eneration _oeranons Services Other (c) Items (N) Total (In Thousands)

External sales .................... S 705,536 S - $1,123,590 S 537,859 $ 1,484 S 7 $2,368,476 Internal sales ..................... 572,533 107,770 291,927 (972,230)

Depreciation and amortization ................. 60,331 40,052 75,419 248,414 2,116 37 426,369 Earnings (loss) before interest and taxes .......... 202,744 (24,323) 171,872 (91,370) 189,289 (21,533) 426,679 Interest expense ................ 289,568 Earnings before income taxes ............................ 137,111 Additions to property, plant and equipment ..... 162,570 25,877 96,984 20,070 2,572 -- 308,073 Customer account acquisitions .................. -- 47,261 47,261 Identifiable assets.............. 1,658.986 1,064,817 1,893,884 2,175,381 1,008,654 (2) 7,801,720 Year Ended December 31, 1999 Eliminating/

Fossil 1N iuclear Customer Monitored Reconciling Generation Ge neration Operations Services Other (d) Items Nb) Total (In Thousands)

External sales .................... S 365,311 S - S1,064,385 $ 599,105 S 1,284 $ 2 $2,030,087 Internal sales ..................... 546,683 108,445 293,522 - (948,650)

Depreciation and amortization ................. 55,320 39,629 71,717 233,906 3,007 90 403,669 Earnings (loss) before interest and taxes .......... 219,087 (25,214) 145,603 (20,675) (28,088) (26,252) 264,461 Interest expense ................ 294,104 Earnings (loss) before income taxes ................ (29,643)

Additions to property, plant and equipment ..... 143,904 10,036 89,162 12,437 20,205 - 275,744 Customer account acquisitions .................. -- 268,409 -- 268,409 Identifiable assets ............. 1,476,716 1,083,344 1,783,937 2,539,921 1,165,145 (59,171) 7,989,892 (a) EBIT shown above for Fossil Generation does not include the unrealized gain on derivatives reported as a cumulative effect of a change in accounting principle. If the effect had been included, EBIT for the Fossil Generation segment for the year ended December 31,2001 would have been $151.6 million.

(b) Identifiable assets include eliminating and reclassing balances to consolidate the monitored services business.

(c) EBIT includes the gain on the sale of our investment in a gas compression company of $91.1 million and the gain on the sale of other marketable securities of $24.9 million.

(d) EBIT includes investment earnings of $36.0 million, an impairment of marketable securities of $76.2 million and the write-off of deferred costs of S 17.6 million.

108

Geographic Information Our sales and property, plant and equipment are as follows:

For the Year Ended December 31, 2001 2000 1999 (In Thousands)

External sales:

United States operations ....................... $2,102,598 $2,254,105 $1,859,008 International operations ........................ 83,664 114,371 171.079 Total ................................................ $2.186.262 $2,368,476 $2.030.087 As of December 31, 2001 2000 1999 (In Thousands)

Property, plant and equipment, net:

United States operations ....................... $4,038,648 $3,984,858 $3,880,865 International operations ........................ 4,204 8,580 8,579 Total .............................................. $4.042.852 $3.993.438

25. IMPAIRMENT CHARGE PURSUANT TO NEW ACCOUNTING RULES Effective January 1, 2002, we adopted the new accounting standards SFAS No. 142, "Accounting for Goodwill and Other Intangible Assets," and SFAS No. 144, "Accounting for the Impairment and Disposal of Long Lived Assets." SFAS No. 142 establishes new standards for accounting for goodwill. SFAS No. 142 continues to require the recognition of goodwill as an asset, but discontinues amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards.

SFAS No. 144 establishes a new approach to determining whether our customer account asset is impaired.

The approach no longer permits us to evaluate our customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of the goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream to be used under SFAS No. 144 is limited to the future estimated undiscounted cash flows of our existing customer accounts. Additionally, the new rule no longer permits us to include estimated cash flows from forecasted customer additions. If the undiscounted cash flow stream from existing customer accounts is less than the combined book value of customer accounts and goodwill, an impairment charge is required.

The new rule substantially reduces the net undiscounted cash flows used for impairment evaluation purposes as compared to the previous accounting rules. The undiscounted cash flow stream has been reduced from the 16-year remaining life of the goodwill to the nine-year remaining life of customer accounts for impairment evaluation purposes and does not include estimated cash flows from forecasted customer additions.

109

To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of goodwill and customer accounts. Based on this analysis, during the first quarter of 2002, we will record a non-cash net charge of approximately $653.7 million, of which $464.2 million is related to goodwill and

$189.5 million is related to customer accounts. The charge is detailed as follows:

Impairment of Impairment of Goodwill Customer Accounts Total (In Thousands)

Protection One ................................. $ 498,921 $ 334,064 $ 832,985 Protection One Europe ..................... 80,104 - 80.104 Total pre-tax impairment ................. $ 579,025 913,089 Income tax benefit ........................... (173,650)

M inority interest .............................. (85.713)

N et charge ........................................ 26 The impairment charge for goodwill will be reflected in our consolidated statement of income as a cumulative effect of a change in accounting principle. The impairment charge for customer accounts will be reflected in our consolidated statement of income as an operating cost. These impairment charges reduce the recorded value of these assets to their estimated fair values at January 1, 2002.

In 2001, we recorded approximately $57.1 million of goodwill amortization expense. We will no longer be permitted to amortize goodwill to income because of adoption of the new goodwill rule. In 2001, we recorded approximately $153.0 million of customer account amortization expense. Future customer account amortization expense will also be reduced as a result of the impairment charge.

We will be required to perform impairment tests for our monitored services segment for long-lived assets prospectively as long as it continues to incur recurring losses or for other matters that may negatively impact its businesses. Goodwill will be required to be tested each year for impairment. Declines in market values of our monitored services businesses or the value of customer accounts that may be incurred prospectively may require additional write down of these assets in the future.

Estimated Lives of Customer Accounts to Change Based on Customer Account Lif'mg Study Results Protection One is currently evaluating the estimated life and amortization rates for customer accounts, given the results of a lifing study performed by a third party appraisal firm in the first quarter of 2002. Any change in its amortization rate or estimated life will be determined in the first quarter of 2002 and accounted for prospectively as a change in estimate.

26. SUBSEQUENT EVENTS Ice Storm In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs could run as high as $25 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application.

110

27. QUARTERLY RESULTS (UNAUDITED)

The amounts in the table are unaudited but, in the opinion of management, contain all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results of such periods. Our electric business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.

First Second Third Fourth (In Thousands, Except Per Share Amounts) 2001 Sales .......................................................... $560,741 $522,901 $667,068 $435,552 Gross profit ............................................... 290,162 285,597 357,077 253,876 Net income (loss) before extraordinary gain and accounting change ................... (19,187) (36,014) 26,722 (34,247)

Net income (loss) ...................................... 4,450 (30,188) 35,976 (31,114)

Earnings (loss) per share available for common stock before extraordinary gain and accounting change:

Basic ............................................... $ (0.28) $ (0.51) $ 0.38 $ (0.49)

Diluted ............................................ $ (0.28) $ (0.51) $ 0.37 $ (0.48)

Cash dividend per common share .............. $ 0.30 $ 0.30 $ 0.30 $ 0.30 Market price per common share:

High ................................................ $ 25.875 $ 25.820 $ 22.900 $ 17.801 Low ................................................. $ 21.800 $ 20.000 $ 15.620 $ 16.000 2000 Sales .......................................................... $481,699 $546,607 $759,562 $580,608 Gross profit ............................................... 306,760 331,889 395,534 298,461 Net income (loss) before extraordinary gain and accounting change ................... 39,801 23,565 53,991 (26,307)

Net income (loss) ...................................... 54,483 40,912 60,707 (19,621)

Earnings (loss) per share available for common stock before extraordinary gain and accounting change:

Basic ............................................... $ 0.58 $ 0.34 $ 0.78 $ (0.40)

Diluted ............................................ $ 0.58 $ 0.34 $ 0.77 $ (0.39)

Cash dividend per common share .............. $ 0.535 $ 0.30 $ 0.30 $ 0.30 Market price per common share:

High ................................................ $ 18.313 $ 17.813 $ 21.953 $ 25.875 Low ................................................. $ 15.313 $ 14.688 $ 15.375 $ 20.438 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.

111

PART HI ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information relating to our Directors required by Item 10 is set forth in our definitive proxy statement to be filed with the SEC for our 2002 Annual Meeting of Shareholders to be held on June 11, 2002. Such information is incorporated herein by reference to the material appearing under the caption "Election of Directors" in the proxy statement to be filed by us with the SEC. 112

EXECUTIVE OFFICERS OF THE COMPANY Other Offices or Positions Name Age Present Office Held During the Past Five Years David C. Wittig 46 Chairman of the Board (since January 1999)

Chief Executive Officer (since July 1998) and President (since March 1996)

Douglas T. Lake 51 Director Bear Stearns & Co., Inc.

(since October 2000) Senior Managing Director Executive Vice President, (1995 to August 1998)

Chief Strategic Officer (since September 1998)

Richard A. Dixon 58 Senior Vice President, Customer Western Resources, Inc.

Operations (since October 2001) Vice President, Transmission Services (May 2000 to October 2001)

Executive Director, System Operations (January 1999 to April 2000)

Executive Director, Transmission Services (September 1996 to December 1998)

Paul R. Geist 38 Senior Vice President, Chief Financial Western Resources, Inc.

Officer and Treasurer (since October Vice President, Corporate Development 2001) (February 2001 to October 2001)

Executive Director, Corporate Strategy (November 1999 to February 2001)

Panera Bread Company Vice President - Finance (October 1998 to November 1999)

Houlihan's Restaurant Group, Inc.

Executive Vice President - Chief Financial Officer (1997 to October 1998) Vice President/Controller (1995 to 1997)

Shane A. Mathis 31 Senior Vice President, Commodity Western Resources, Inc.

Strategy (since October 2001) Vice President, Commodity Strategy (October 2000 to October 2001)

Vice President, Risk Management (May 2000 to October 2000)

Executive Director, Gas and Liquids (March 2000 to May 2000)

Executive Director, Risk Management (January 1998 to March 2000)

Director, Energy Trading (January 1998 to August 1998)

Senior Strategist (February 1997 to January 1998)

Merrill Lynch Financial Consultant (1995 to February 1997)

Douglas R. Sterbenz 38 Senior Vice President, Generation and Western Resources, Inc.

Marketing (since October 200 1) Manager, Bulk Power Marketing (August 1998 to October 200 1)

Energy Trader (May 1997 to July 1998)

Questar Energy Trading Director, Power Marketing (April 1996 to May 1997) 113

ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 is set forth in our definitive proxy statement to be filed with the SEC for our 2002 Annual Meeting of Shareholders to be held on June 11, 2002. Such information is incorporated herein by reference to the material appearing under the captions "Information Concerning the Board of Directors,"

"Executive Compensation," "Compensation Plans," and "Human Resources Committee Report" in the proxy statement to be filed by us with the SEC.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by Item 12 is set forth in our definitive proxy statement to be filed with the SEC for our 2002 Annual Meeting of Shareholders to be held on June 11, 2002. Such information is incorporated herein by reference to the material appearing under the caption "Beneficial Ownership of Voting Securities" in the proxy statement to be filed by us with the SEC.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None.

114

PART IV ITEM 14. EXHIBITS. FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K FINANCIAL STATEMENTS INCLUDED HEREIN Report of Independent Public Accountants Consolidated Balance Sheets, December 31, 2001 and 2000 Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Comprehensive Income for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Shareholders' Equity for the years ended December 31, 2001, 2000 and 1999 Notes to Consolidated Financial Statements SCHEDULES Schedule II - Valuation and Qualifying Accounts Schedules omitted as not applicable or not required under the Rules of regulation S-X: I, III, IV, and V REPORTS ON FORM 8-K FILED DURING THE QUARTER ENDED DECEMBER 31, 2001:

Form 8-K filed October 16, 2001 - Announcement that PNM filed a lawsuit against us in New York court seeking monetary damages for breach of representation and seeking, among other things, to terminate the merger agreement.

Form 8-K filed October 26, 2001 - Announcement of changes in our Direct Stock Purchase Plan.

Form 8-K filed November 6, 2001 - Announcement that we filed a financial plan with the KCC.

Form 8-K filed November 20, 2001 - Announcement that we filed a lawsuit against PNM in New York court seeking substantial damages for PNM's breach of the merger agreement.

Form 8-K filed December 6, 2001 - Announcement of our expected 2002 operating results.

115

EXHIBIT INDEX All exhibits marked "I"are incorporated herein by reference. All exhibits marked by an asterisk are management contracts or compensatory plans or arrangements required to be identified by Item 14(a)(3) of Form 10-K.

Description 2(a) -Agreement and Plan of Restructuring and Merger, dated as of November 8, 2000 among the company, I Public Service Company of New Mexico, HVOLT Enterprises, Inc., HVK, Inc., and HVNM, Inc.

(filed as Exhibit 99.1 to the November 17, 2000 Form 8-K) 3(a) -By-laws of the company, as amended March 16, 2000 (filed as Exhibit 3(a) to December 1999 Form I 10-K) 3(b) -Restated Articles of Incorporation of the company, as amended through May 25, 1988 (filed as I Exhibit 4 to Registration Statement, SEC File No. 33-23022) 3(c) -Certificate of Amendment to Restated Articles of Incorporation of the company dated March 29, I 1991.

3(d) -Certificate of Designations for Preference Stock, 8.5% Series, without par value, dated March 31, I 1991 (filed as Exhibit 3(d) to December 1993 Form 10-K) 3(e) -Certificate of Correction to Restated Articles of Incorporation of the company dated December 20, I 1991 (filed as Exhibit 3(b) to December 1991 Form 10-K) 3(f) -Certificate of Designations for Preference Stock, 7.58% Series, without par value, dated April 8, I 1992, (filed as Exhibit 3(e) to December 1993 form 10-K) 3(g) -Certificate of Amendment to Restated Articles of Incorporation of the company dated May 8, 1992 I (filed as Exhibit 3(c) to December 31, 1994 Form 10-K) 3(h) -Certificate of Amendment to Restated Articles of Incorporation of the company dated May 26, 1994 I (filed as Exhibit 3 to June 1994 Form 10-Q) 3(i) -Certificate of Amendment to Restated Articles of Incorporation of the company dated May 14, 1996 I (filed as Exhibit 3(a) to June 1996 Form 10-Q) 3(j) -Certificate of Amendment to Restated Articles of Incorporation of the company dated May 12, 1998 I (filed as Exhibit 3 to March 1998 Form 10-Q) 3(k) -Form of Certificate of Designations for 7.5% Convertible Preference Stock (filed as Exhibit 99.4 to I November 17, 2000 Form 8-K) 4(a) -Deferrable Interest Subordinated Debentures dated November 29, 1995, between the company and I Wilmington Trust Delaware, Trustee (filed as Exhibit 4(c) to Registration Statement No. 33-63505) 4(b) -Mortgage and Deed of Trust dated July 1, 1939 between the company and Harris Trust and Savings I Bank, Trustee (filed as Exhibit 4(a) to Registration Statement No. 33-21739) 4(c) -First through Fifteenth Supplemental Indentures dated July 1, 1939, April 1, 1949, July 20, 1949, I October 1, 1949, December 1, 1949, October 4, 1951, December 1, 1951, May 1, 1952, October 1, 1954, September 1, 1961, April 1, 1969, September 1, 1970, February 1, 1975, May 1, 1976 and April 1, 1977, respectively (filed as Exhibit 4(b) to Registration Statement No. 33-21739) 4(d) -Sixteenth Supplemental Indenture dated June 1, 1977 (filed as Exhibit 2-D to Registration Statement I No. 2-60207) 4(e) -Seventeenth Supplemental Indenture dated February 1, 1978 (filed as Exhibit 2-E to Registration I Statement No. 2-61310) 4(f) -Eighteenth Supplemental Indenture dated January 1, 1979 (filed as Exhibit (b) (1)-9 to Registration I Statement No. 2-64231) 4(g) -Nineteenth Supplemental Indenture dated May 1, 1980 (filed as Exhibit 4(f) to Registration Statement I No. 33-21739) 4(h) -Twentieth Supplemental Indenture dated November 1, 1981 (filed as Exhibit 4(g) to Registration I Statement No. 33-21739) 4(i) -Twenty-First Supplemental Indenture dated April 1, 1982 (filed as Exhibit 4(h) to Registration I Statement No. 33-21739) 4(j) -Twenty-Second Supplemental Indenture dated February 1, 1983 (filed as Exhibit 4(i) to Registration I Statement No. 33-21739) 116

4(k) -Twenty-Third Supplemental Indenture dated July 2, 1986 (filed as Exhibit 4(j) to Registration I Statement No. 33-12054) 4(l) -Twenty-Fourth Supplemental Indenture dated March 1, 1987 (filed as Exhibit 4(k) to Registration I Statement No. 33-21739) 4(m) -Twenty-Fifth Supplemental Indenture dated October 15, 1988 (filed as Exhibit 4 to the September I 1988 Form 10-Q) 4(n) -Twenty-Sixth Supplemental Indenture dated February 15, 1990 (filed as Exhibit 4(m) to the I December 1989 Form 10-K) 4(o) -Twenty-Seventh Supplemental Indenture dated March 12, 1992 (filed as Exhibit 4(n) to the December I 1991 Form 10-K) 4(p) -Twenty-Eighth Supplemental Indenture dated July 1, 1992 (filed as Exhibit 4(o) to the December I 1992 Form 10-K) 4(q) -Twenty-Ninth Supplemental Indenture dated August 20, 1992 (filed as Exhibit 4(p) to the December I 1992 Form 10-K) 4(r) -Thirtieth Supplemental Indenture dated February 1, 1993 (filed as Exhibit 4(q) to the December 1992 I Form 10-K) 4(s) -Thirty-First Supplemental Indenture dated April 15, 1993 (filed as Exhibit 4(r) to Registration I Statement No. 33-50069) 4(t) -Thirty-Second Supplemental Indenture dated April 15, 1994 (filed as Exhibit 4(s) to the December I 31, 1994 Form 10-K) 4(u) -Thirty-Fourth Supplemental Indenture dated June 28, 2000 (filed as Exhibit 4(v) to the December 31, I 2000 Form 10-K) 4(v) -Debt Securities Indenture dated August 1, 1998 (filed as Exhibit 4.1 to the June 30, 1998 Form 10-Q) I 4(w) -Form of Note for $400 million 6.25% Putable/Callable Notes due August 15, 2018, Putable/Callable I August 15, 2003 (filed as Exhibit 4.2 to the June 30, 1998 Form 10-Q)

Instruments defining the rights of holders of other long-term debt not required to be filed as Exhibits will be furnished to the Commission upon request.

10(a) -Long-Term Incentive and Share Award Plan (filed as Exhibit 10(a) to the June 1996 Form 10-Q)* I 10(b) -Form of Employment Agreements with Messers. Grennan, Koupal, Lake, Terrill, Wittig and Ms. I Sharpe (filed as Exhibit 10(b) to the December 31, 2000 Form 1o-K)*

10(c) -A Rail Transportation Agreement among Burlington Northern Railroad Company, the Union Pacific I Railroad Company and the Company (filed as Exhibit 10 to the June 1994 Form 10-Q) 10(d) -Agreement between the company and AMAX Coal West Inc. effective March 31, 1993 (filed as I Exhibit 10(a) to the December 31, 1993 Form 10-K) 10(e) -Agreement between the company and Williams Natural Gas Company dated October 1, 1993 (filed as I Exhibit 10(b) to the December 31, 1993 Form 10-K) 10(f) -Deferred Compensation Plan (filed as Exhibit 10(i) to the December 31, 1993 Form 10-K)* I 10(g) -Short-term Incentive Plan (filed as Exhibit 10(k) to the December 31, 1993 Form 10-K)* I 10(h) -Outside Directors' Deferred Compensation Plan (filed as Exhibit 10(1) to the December 31, 1993 I Form 10-K)*

10(i) -Executive Salary Continuation Plan of Western Resources, Inc., as revised, effective September 22, I 1995 (filed as Exhibit 10(j) to the December 31, 1995 Form Io-K)*

10(j) -Letter Agreement between the company and David C. Wittig, dated April 27, 1995 (filed as Exhibit I 10(m) to the December 31, 1995 Form 10-K)*

10(k) -Form of Shareholder Agreement between New ONEOK and the company (filed as Exhibit 99.3 to the I December 12, 1997 Form 8-K) 10(1) -Form of Split Dollar Insurance Agreement (filed as Exhibit 10.3 to the June 30, 1998 Form 10-Q)* I 10(m) -Amendment to Letter Agreement between the company and David C. Wittig, dated April 27, 1995 I (filed as Exhibit 10 to the June 30, 1998 Form 10-Q/A)*

10(n) -Letter Agreement between the company and Douglas T. Lake, dated August 17, 1998

• I 10(o) -Form of Change of Control Agreement with officers of the company (filed as Exhibit 10(o) to the I December 31, 2000 Form 10-K)*

117

10(p) -Amendment to Outside Directors' Deferred Compensation Plan dated May 17, 2001 (filed as Exhibit 10(p) to the December 31, 2000 Form 10-K)*

10(q) -Asset Allocation and Separation Agreement, dated as of November 8, 2000, between the company and Westar Industries, Inc. (filed as Exhibit 99.2 to the November 17, 2000 Form 8-K) 10(r) -Form of loan agreement with officers of the company*

12 -Computations of Ratio of Consolidated Earnings to Fixed Charges 21 -Subsidiaries of the Registrant 23 -Consent of Independent Public Accountants, Arthur Andersen LLP 99(a) -Press release issued August 13, 2001 by PNM announcing that talks to modify our transaction with PNM have been discontinued (filed as Exhibit 99.1 to the June 30, 2001 Form 10-Q) 99(b) -Press release issued August 13, 2001 by Western Resources responding to PNM's announcement of discontinued talks (filed as Exhibit 99.2 to the June 30, 2001 Form 10-Q) 99(c) -Letter to the SEC of assurances given by Arthur Andersen LLP regarding their audit of December 31, 2001 financial statements to the company 118

WESTERN RESOURCES, INC.

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Dollars in Thousands)

Balance at Charged to Balance Beginning Costs and at End Description of Period Expenses Deductions of Period (In Thousands)

Year ended December 31, 1999 Allowances deducted from assets for doubtful accounts (a) ........................ $ 29,544 $24,302 $(18,081) $35,765 Monitored services special charge (b).. 1,025 - (1,025)

Accrued exit fees, shut-down and severance costs (c) ............................ 22,900 (5,632) (16,888) 380 Year ended December 31, 2000 Allowances deducted from assets for doubtful accounts (a) ........................ 35,765 23,690 (13,639) 45,816 Accrued exit fees, shut-down and severance costs ................................. 380 -- 380 Year ended December 31, 2001 Allowances deducted from assets for doubtful accounts (a) ........................ 45,816 7,075 (33,770) 19,121 Accrued exit fees, shut-down and severance costs (d) ............................ 380 - (337) 43 (a) Deductions are the result of write-offs of accounts receivable.

(b) Consists of costs to close duplicate facilities and severance and compensation benefits.

(c) See Note 22 of the "Notes to Consolidated Financial Statements" for further information.

(d) Deductions are the result of payment of accrued severance costs.

119

SIGNATURE Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

WESTERN RESOURCES, INC.

Date:

S Anril 1* ....

1-* 2002 By: /s/ Paul R. Geist Paul R. Geist, Senior Vice President, Chief Financial Officer and Treasurer SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature Title Date Is/ DAVID C. WITTIG Chairman of the Board, President and April 1, 2002 (David C. Wittig) Chief Executive Officer (Principal Executive Officer)

/s/ PAUL R. GEIST Senior Vice President, Chief April 1, 2002 (Paul R. Geist) Financial Officer and Treasurer (Principal Financial and Accounting Officer)

/s/ FRANK J. BECKER Director April 1, 2002 (Frank J. Becker)

/s/ GENE A. BUDIG Director Aprill,2002 (Gene A. Budig)

/s/ CHARLES Q. CHANDLER, IV Director April 1,2002 (Charles Q. Chandler, IV)

/s/ JOHN C. DICUS Director April 1, 2002 (John C. Dicus)

Is! R. A. EDWARDS III Director April 1, 2002 (R. A. Edwards III)

Is! DOUGLAS T. LAKE Director April 1,2002 (Douglas T. Lake)

/s/ JOHN C. NETTLES, JR. Director April 1, 2002 (John C. Nettles, Jr.)

120

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 or TRANSITION REPORT PURSUANT SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address and Telephone Number Identification Number 03-33207 GREAT PLAINS ENERGY INCORPORATED 43-1916803 (A Missouri Corporation) 1201 Walnut Street Kansas City, Missouri 64106 (816) 556-2200 1-107 KANSAS CITY POWER & LIGHT COMPANY 44-0308720 (A Missouri Corporation) 1201 Walnut Street Kansas City, Missouri 64106 (816) 556-2200 Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is registered on the New York Stock Exchange:

Registrant Title of each class Great Plains Energy Incorporated Cumulative Preferred Stock par value $100 per share 3.80%

Cumulative Preferred Stock par value $100 per share 4.50%

Cumulative Preferred Stock par value $100 per share 4.35%

Common Stock without par value Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to the Form 10-K. X On February 21, 2002, Great Plains Energy Incorporated had 61,873,052 shares of common stock outstanding. The aggregate market value of the common stock held by nonaffiliates of Great Plains Energy Incorporated (based upon the closing price of the Company's common stock on the New York Stock Exchange on February 21, 2002) was approximately

$1,567,357,394.

Documents Incorporated by Reference Portions of the 2002 Proxy Statement of Great Plains Energy Incorporated to be filed with the Securities and Exchange Commission are incorporated by reference in Part Ill of this report.

TABLE OF CONTENTS Page Number Cautionary Statements Regarding Forward-Looking Information ii Glossary of Terms iii PART I Item 1 Business 1 Item 2 Properties 9 Item 3 Legal Proceedings 10 Item 4 Submission of Matters to a Vote of Security Holders 11 PART II Item 5 Market for Registrant's Common Equity and Related Stockholder Matters 11 Item 6 Selected Financial Data 12 Item 7 Management's Discussion and Analysis of Financial Condition and Results of 13 Operation Item 7A Quantitative and Qualitative Disclosures About Market Risks 32 Item 8 Financial Statements and Supplementary Data 34 Item 9 Changes in and Disagreements With Accountants on Accounting and 86 Financial Disclosure PART III Item 10 Directors and Executive Officers of the Registrants 86 Item 11 Executive Compensation 86 Item 12 Security Ownership of Certain Beneficial Owners and Management 86 Item 13 Certain Relationships and Related Transactions 86 PART IV Item 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K 87

Great Plains Energy Incorporated and Kansas City Power & Light Company separately file this combined Form 10-K. 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.

This report should be read in its entirety. No one section of the report deals with all aspects of the subject matter.

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

• future economic conditions in the regional, nationaland internationalmarkets

• state, federal and foreign regulation

• weather conditions including weather-relateddamage

• cost of fuel

• financial market conditions including, but not limited to, changes in interest rates

• inflation rates

• increasedcompetition including, but not limited to, the deregulationof the electric utility industry and the entry of new competitors

• ability to carryout marketing and sales plans

• ability to achieve generation planning goals and the occurrenceof unplannedgeneration outages

• nuclearoperations

• ability to enter new markets successfully and capitalize on growth opportunities in nonregulated businesses

• adverse changes in applicable laws, regulationsor rules governing environmental regulations (including air quality), tax or accounting matters

• delays in the anticipatedin-service dates of additionalgenerating capacity

• performance of projects undertaken by our non-regulatedbusinesses and the success of efforts to invest in and develop new opportunities

• availabilityand cost of capital and

• other risks and uncertainties.

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

ii

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

Abbreviation or Acronym Definition APB Accounting Principles Board Clean Air Act Clean Air Act Amendments of 1990 C02 Carbon Dioxide Consolidated KCP&L KCP&L and its subsidiary HSS DIP Debtor-in-Possession DTI DTI Holdings, Inc. and its subsidiary Digital Teleport Inc.

DOE Department of Energy EIRR bonds Environmental Improvement Revenue Refunding bonds EPA Environmental Protection Agency EPS Earnings per share FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GAAP Generally Accepted Accounting Principles IBEW International Brotherhood of Electrical Workers IOUs Investor owned utilities GPP Great Plains Power Incorporated, a subsidiary of Great Plains Energy Incorporated HSS Home Service Solutions Inc., a subsidiary of KCP&L KCC The State Corporation Commission of the State of Kansas KCP&L Kansas City Power & Light Company, a regulated electric utility subsidiary of Great Plains Energy Incorporated MACT Maximum Achievable Control Technology MISO Midwest Independent System Operator MPSC Missouri Public Service Commission mw Megawatt NEIL Nuclear Electric Insurance Limited NO, Nitrogen Oxide NRC Nuclear Regulatory Commission PCBs Polychlorinated biphenyls PUHCA Public Utility Holding Company Act of 1935 RSAE R.S. Andrews Enterprises, Inc. a consumer services company in which HSS owns a 72% equity interest RTO Regional Transmission Organization SEC Securities and Exchange Commission SPP Southwest Power Pool SFAS Statement of Financial Accounting Standards Superfund law Federal Comprehensive Environmental Response, Compensation and Liability Act WCNOC Wolf Creek Nuclear Operating Corporation iii

PART I ITEM 1. BUSINESS Organization On October 1, 2001, Great Plains Energy Incorporated (Great Plains Energy), a Missouri corporation incorporated in 2001, became the sole owner of all the common stock of Kansas City Power & Light Company (KCP&L), a public utility subsidiary. As a result of this ownership, Great Plains Energy is considered a utility holding company registered with and subject to the regulation of the Securities Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended

_(PUHCA). Great Plains Energy does not own or operate any significant assets other than the stock of its subsidiaries. Other wholly-owned subsidiaries in addition to KCP&L are KLT Inc. and Great Plains Power Incorporated (GPP).

KCP&L, incorporated in Missouri in 1922, engages in the generation, transmission, distribution and sale of electricity. KCP&L, headquartered in downtown Kansas City, Missouri, has approximately 474,000 customers located in all or portions of 23 counties in western Missouri and eastern Kansas.

KCP&L contributed approximately 66% of Great Plains Energy's revenue in 2001. About 58% of KCP&L's retail revenues in 2001 were from Missouri customers and the remainder from Kansas customers. Customers included approximately 419,000 residences, 53,000 commercial firms, and 2,000 industrials, municipalities and other electric utilities. Retail electric revenues accounted for approximately 90% of KCP&L's total electric revenues in 2001. Wholesale firm power, bulk power sales and miscellaneous electric revenues accounted for the remainder of utility revenues.

KCP&L is regulated by the Public Service Commission of the State of Missouri (MPSC), the State Corporation Commission of the State of Kansas (KCC), the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and certain other governmental regulatory bodies as to various phases of its operations, including rates, service, safety and nuclear plant operations, environmental matters and issuances of securities. KCP&L's retail electric rates are set by the MPSC and the KCC. KCP&L currently has no rate proceeding pending in either state; however, the moratorium on rate changes in Missouri will expire on March 1, 2002. KCP&L is also subject to regulation as a subsidiary of a registered holding company under PUHCA.

KLT Inc., formed in 1992, is an investment company that holds interests in three primary unregulated energy-related businesses: KLT Energy Services Inc., KLT Gas Inc., and KLT Telecom Inc. See further information appearing in "Unregulated Businesses" on page 5. KLT Inc. was transferred to Great Plains Energy by KCP&L in connection with the corporate reorganization on October 1, 2001.

KLT Inc. contributed approximately 29% of Great Plains Energy's revenues in 2001.

GPP, formed in 2001, is focusing on the development, production and trading of wholesale electric capacity and energy. GPP has made no investments to date.

Financial information regarding Great Plains Energy's operating segments is contained in "Notes to Consolidated Financial Statements" "Note 9" on page 67.

Current Developments The electric utility industry in our twenty-three county service territory has been relatively stable for many years. In recent years there have been a number of developments in the industry aimed at

-restructuring and increasing competition. These initiatives have not been adopted in the states of Missouri and Kansas. In many parts of the country, generating assets have become deregulated with power sold to utilities on a competitive basis, transmission assets have become subject to the control 1

- ____ of an independent system operator and distribution systems have remained regulated. We believe that our current holding company structure, combined with the formation of GPP, positions us to operate successfully in the changing environment. We are supporting legislation in Missouri that would allow utilities to transfer generation assets to affiliated generating companies such as GPP. Great Plains Energy is also supporting the proposed federal comprehensive energy legislation and the repeal of PUHCA.

The FERC recently ordered investor owned utilities to join a Regional Transmission Organization (RTO) by December 19, 2001. In the last open meeting held in 2001, FERC lifted this deadline and has not set another. Investor owned utilities (IOUs) are still encouraged to join a RTO, and FERC requires this membership for market based rate authority. KCP&L is involved with the development and is positioned to become a member of a Midwest RTO that would result from the consolidation of the Midwest Independent System Operator and the Southwest Power Pool.

Capital Program and Financing For information on the Company's capital program and financial needs, see Item 7 "Management's Discussion and Analysis of Financial Conditions and Results of Operations" "Capital Requirements and Liquidity" on page 27 and "Notes to Consolidated Financial Statements" "Notes 12 and 13" on page 72.

Regulated Business The following describes KCP&L's regulated electric utility operations and activities which is Great Plains Energy's primary business segment.

Fuel Supply KCP&L's principal sources of fuel for electric generation are coal and nuclear fuel. KCP&L expects to satisfy about 97% of the 2002 fuel requirements from these sources with the remainder provided by natural gas, oil and steam. The 2001 and estimated 2002 fuel mix, based on total Btu generation, are as follows:

Estimated Fuel 2001 2002 Coal 69% 74%

Nuclear 28% 23%

Other 3% 3%

Coal KCP&L's average cost per million Btu of coal burned, excluding fuel handling costs, was $0.84 in 2001,

$0.85 in 2000, and $0.82 in 1999.

During 2002, approximately 11.2 million tons of coal are projected to be burned at KCP&L's generating units including jointly owned units. This amount reflects increased coal use in 2002 due to the completion in June 2001 of the new 650 mw Hawthorn 5 unit. KCP&L has entered into coal-purchase contracts with various suppliers in Wyoming's Powder River Basin, the nation's principal supplier of low-sulfur coal. These contracts, with expiration dates in 2002 and 2003, will satisfy approximately 95% of the projected coal requirements for 2002 and 40% for 2003.

2

Nuclear KCP&L owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for the Wolf Creek Generating Station (Wolf Creek). WCNOC has on hand or under contract 83% of the uranium required to operate Wolf Creek through March 2005. The balance is expected to be obtained through contract and spot market purchases.

As of December 31, 2001, KCP&L's portion of Wolf Creek nuclear fuel contracts included costs of

$22.7 million for enrichment through 2006, $57.5 million for fabrication through 2025 and $3.8 million for uranium and conversion through 2003.

-Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to fuel expense. We cannot predict when a permanent disposal site may be available. Wolf Creek has recently completed an on-site storage facility that is expected to hold all spent fuel generated at the plant through the end of its licensed life in 2025.

The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated the development of low level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Compact) and selected a site in Nebraska to locate a disposal facility. Nebraska officials opposed the facility and Nebraska has given notice of withdrawal from the Compact. Currently, the low-level waste from Wolf Creek is being processed and disposed of in other federally-approved facilities.

Purchased Power At times, KCP&L purchases power to meet the requirements of its customers. While we believe we can obtain enough purchased power to meet any future needs, price and availability of the purchases may be significantly impacted during periods of excessive demand.

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

KCP&L operates in an environmentally responsible manner and seeks to use current technology to avoid and treat contamination. KCP&L regularly conducts environmental audits designed to ensure compliance with governmental regulations and to detect contamination. Governmental bodies, however, may impose additional or more rigid environmental regulations that could require substantial changes to operations or facilities at a significant cost. Expenditures made in 2001 to comply with environmental laws and regulations were not material in amount and are not expected to be material in the upcoming years with the exception of the issues discussed below.

3

Air Monitoring Equipment and Certain Air Toxic Substances In July 2000, the National Research Council published its findings of a study under the Clean Air Act Amendments of 1990 (The Clean Air Act) which stated that power plants that burn fossil fuels, particularly coal, generate the greatest amount of mercury emissions. As a result, in December 2000, the United States Environmental Protection Agency (EPA) announced it would propose Maximum Achievable Control Technology (MACT) requirements to reduce mercury emissions by December 2003 and issue final rules by December 2004. KCP&L cannot predict the likelihood or compliance costs of such regulations.

Air ParticulateMatter In July 1997, the EPA revised ozone and particulate matter air quality standards creating a new eight-hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns in diameter. These standards were challenged in the U. S. Court of Appeals for the District of Columbia (Appeals Court) that decided against the EPA. Upon appeal, the U. S. Supreme Court reviewed the standards and remanded the case back to the Appeals Court for further review, including a review of whether the standards were arbitrary and capricious. The Appeals Court has not rendered a decision, and the new particulate standards have not been finalized. Without implementation of the regulations, the outcome cannot be determined, but the impact on KCP&L and all other utilities that use fossil fuels could be substantial. In addition, the EPA is conducting a three-year study of fine particulate ambient air levels. Until this testing and review period has been completed, KCP&L cannot determine additional compliance costs, if any, associated with the new particulate regulations.

Nitrogen Oxide The EPA announced in 1998 regulations implementing reductions in NO, emissions. These regulations initially called for 22 states, including Missouri, to submit plans for controlling NO, emissions. The regulations require a significant reduction in NO, emissions from 1990 levels at KCP&L's Missouri coal-fired plants by the year 2003.

In December 1998, KCP&L and several other western Missouri utilities filed suit against the EPA over the inclusion of western Missouri in the NO, reduction program based on the 1-hour NO, standard. On March 3, 2000, a three-judge panel of the District of Columbia Circuit of the U.S. Court of Appeals sent the NOx rules related to Missouri back to the EPA, stating the EPA failed to prove that fossil plants in the western part of Missouri significantly contribute to ozone formation in downwind states. On March 5, 2001, the U.S. Supreme Court denied certiorari, making the decision of the Court of Appeals final.

This decision will likely delay the implementation of new NO, regulations by the EPA in the western portion of Missouri for some time.

If required to be implemented, KCP&L would need to incur significant capital costs, purchase power or purchase NOx emission allowances. Preliminary analysis of the regulations indicates that selective catalytic reduction technology, as well as other changes, may be required for some of the KCP&L units. Currently, KCP&L estimates that additional capital expenditures to comply with these regulations could range from $40 million to $60 million. Operations and maintenance expenses could also increase by more than $2.5 million per year. KCP&L continues to refine these preliminary estimates and explore alternatives. The ultimate cost of these regulations, if any, could be significantly different from the amounts estimated above.

4

Carbon Dioxide At a December 1997 meeting in Kyoto, Japan, delegates from 167 nations, including the United States, agreed to a treaty (Kyoto Protocol) that would require a seven percent reduction in United States carbon dioxide (C02) emissions below 1990 levels. Although the United States agreed to the Kyoto Protocol, the treaty has not been sent to Congress for ratification. The financial impact on KCP&L of future requirements in the reduction of CO 2 emissions cannot be determined until specific regulations are adopted.

Unregulated Businesses The following describes the operations and activities of our unregulated subsidiaries. For further

information, see Item 7 "Management's Discussion and Analysis of Financial Conditions and Results of Operations".

KLT Inc. has five wholly-owned direct subsidiaries:

" KLT Energy Services Inc. is an investor in companies which provide products and services to commercial and industrial customers to control the amount, cost and quality of electricity.

KLT Energy Services Inc. has a majority interest in Strategic Energy, L.L.C., an energy services provider that supplies electricity to retail end-users in deregulated markets.

Strategic Energy currently acts as an energy manager to approximately 19,500 commercial and small manufacturing accounts in Pennsylvania, Ohio, Texas, New York, Massachusetts and California.

"* KLT Gas Inc., headquartered in Houston, Texas, is an investor in natural gas producing properties and companies.

KLT Gas Inc. is primarily focused on creating value through early stage coal bed methane property discovery, development and divestiture. As of December 31, 2001, it directly owned over 250,000 net mineral acres of coal bed methane properties primarily in Wyoming, Colorado, Nebraska and Kansas. FAR Gas Acquisitions Corporation, a wholly-owned subsidiary of KLT Inc. Gas Inc., holds limited partnership interests in coal bed methane gas well properties.

" KLT Telecom Inc. is an investor in communications and information technology.

KLT Telecom's primary investment is an 84% ownership of DTI Holdings, Inc., the parent company of Digital Teleport, Inc. (DTI). DTI is a facilities-based telecommunications company based in St. Louis, Missouri, that focuses on providing access and connectivity to underserved secondary and tertiary markets. On December 31, 2001, DTI filed voluntary petitions for reorganization under Chapter 11 of the U.S. bankruptcy code, and DTI continues to conduct its business operations while it restructures its financial obligations. See further information appearing in Item 7 "Management's Discussion and Analysis of Financial Conditions and Results of Operations" "Subsidiary of KLT Telecom Files for Bankruptcy - DTI" on page 23.

" KLT Investments Inc. is a passive investor in affordable housing investments that generate tax credits.

" KLT Investments II Inc. is a passive investor in economic and community-development and energy-related projects.

5

KCP&L has one unregulated wholly-owned subsidiary, Home Service Solutions Inc. (HSS), which has invested in two companies. See information appearing in Item 7. ",Management's Discussion and Analysis of Financial Conditions and Results of Operations",, ,HSS Operations", on page 21.

" R. S. Andrews Enterprises,Inc. (RSAE), headquartered in Atlanta, Georgia, provides energy-related residential services. HSS increased its ownership interest in RSAE from 49%

in 2000 to 72% in 2001.

"* Worry Free Service, Inc., a participant in electrical and energy-related services to residential users (owned 100% by HSS).

Employees On December 31, 2001, Great Plains Energy and its wholly-owned subsidiaries had 2,258 employees.

Of this number, 2,248 were employees of KCP&L and 10 were employees of KLT Inc. Of the KCP&L employees, 1,397 were represented by three local unions of the International Brotherhood of Electrical Workers (IBEW). KCP&L has labor agreements with Local 1613, representing clerical employees (which expires March 31, 2002), with Local 1464, representing outdoor workers (which expires January 31, 2003), and with Local 412, representing power plant workers (which expires February 29, 2004).

Executive Officers of the Registrants Year Assumed First Officer Name Aqe Positions Currently Held Position Bernard J. Beaudoin 61 Chairman of the Board, President and 1984 Chief Executive Officer - Great Plains Energy Incorporated Chairman of the Board, President and Chief Executive Officer - Kansas City Power & Light Company Chairman of the Board - Great Plains Power Incorporated Andrea F. Bielsker 43 Vice President - Finance, Chief 1996 Financial Officer and Treasurer Great Plains Energy Incorporated Vice President - Finance, Chief Financial Officer and Treasurer Kansas City Power & Light Company 6

Frank L. Branca 54 Vice President - Generation 1989 Services - Kansas City Power & Light Company President - Kansas City Power &

Light Company Power Division John J. DeStefano 52 Vice President - Finance - Great 1989 Plains Power Incorporated William H. Downey1 56 Executive Vice President - Great 2000 Plains Energy Incorporated President - Kansas City Power &

Light Company Delivery Division 2

Stephen T. Easley 46 President and Chief Executive 2000 Officer - Great Plains Power Incorporated William P. Herdegen 1113 47 Vice President - Distribution 2001 Operations - Kansas City Power &

Light Company Delivery Division Jeanie S. Latz 50 Senior Vice President - Corporate 1991 Services and Secretary - Great Plains Energy Incorporated Secretary - Kansas City Power &

Light Company Nancy J. Moore 52 Vice President - Customer Services 2000 Kansas City Power & Light Company Delivery Division Douglas M. Morgan 59 Vice President - Information 1994 Technology and Support Services Great Plains Energy Incorporated 4

Brenda Nolte 49 Vice President - Public Affairs - Great 2000 Plains Energy Incorporated 1 Mr. Downey was Presidentof Unicom Energy Services Company Inc. from 1997-1999; and Vice Presidentof Commonwealth Edison Company from 1992-1999.

2 Mr. Easley was Directorof Construction at KCP&L from October 1999-April 2000; Assistant to the Chief FinancialOfficer at KCP&L in 1999; and Vice President,Business Development Americas with KL T Power Inc. from March 1996-November 1998.

3 Mr. Herdegen was Chief OperatingOfficer at Laramore, Douglass and Popham in 2001 and Vice President and Directorof UtilitiesPracticeand System Development Integration, a consulting company, from 1999 to 2001; and held various positions at Commonwealth Edison during 1976-1999.

4 Ms. Nolte was Vice President, CorporateAffairs, with AMC Entertainmentfrom 1997-2000; Director, Center for Regional Development with Midwest Research Institute in 1997; and Public Affairs Officer with Payless Cashways from 1987-1997.

7

5 Gregory Orman 33 President and Chief Executive Officer 2000 KLT Inc.

William G. Riggins 43 General Counsel - Great Plains 2000 Energy Incorporated Neil A. Roadman 56 Controller - Great Plains Energy 1980 Incorporated Controller - Kansas City Power &

Light Company Richard A. Spring 47 Vice President - Transmission 1994 Services - Kansas City Power & Light Company Delivery Division Andrew B. Stroud, Jr.6 43 Vice President - Human Resources 2001 Great Plains Energy Incorporated Bailus M. Tate 55 Vice President - Administration 1994 Kansas City Power & Light Company Power Division All of the above individuals have been officers or employees in a responsible position with the Company for the past five years except as noted in the footnotes. The term of office of each officer commences with his or her appointment by the Board of Directors and ends at such time as the Board of Directors may determine.

' Mr. Orman was Presidentand Chief Executive Officer Custom Energy LLC from 1997 to 1999; and Chairman and Chief Executive Officer of Environmental Lighting Concepts Inc. from 1994-1997.

' Mr. Stroud was Vice President-GlobalHuman Resources of Evenflo Company, Inc. in 2000-2001; and held various management positions at PepsiCo during 1991-2000.

8

ITEM 2. PROPERTIES KCP&L Generation Resources KCP&L's generating facilities consist of the following:

Estimated 2002 Year Megawatt (mw) Primary Unit Completed Capacity Fuel Existing Units Base Load Wolf Creek(a) 1985 550(b) Nuclear latan 1980 469(b) Coal LaCygne 2 1977 337(b) Coal LaCygne 1 1973 344(b) Coal Hawthorn 9(c) 2000 137 Gas Hawthorn 6(d) 1997 132 Gas Hawthorn 5(e) 1969 575 Coal Montrose 3 1964 176 Coal Montrose 2 1960 164 Coal Montrose 1 1958 170 Coal Peak Load Hawthorn 8(d) 2000 77 Gas Hawthorn 7(d) 2000 77 Gas Northeast 13 and 14(d) 1976 114 Oil Northeast 17 and 18(d) 1977 117 Oil Northeast 15 and 16(d) 1975 116 Oil Northeast 11 and 12(d) 1972 111 Oil Northeast Black Start Unit 1985 2 Oil Grand Avenue (2 units) 1929 & 1948 65 Gas Total 3.7*3 (a) This unit is one of KCP&L's principal generating facilities and has the lowest fuel cost of any of its generating facilities. An extended shutdown of the unit could have a substantial adverse effect on the operations of KCP&L and its financial condition.

(b) KCP&L's share of jointly-owned unit.

(c) Heat Recovery Steam Generator portion of combined cycle.

(d) Combustion turbines.

(e) On February 17, 1999, an explosion occurred at the Hawthorn Generating Station. The station returned to commercial operation on June 20, 2001.

KCP&L's maximum system net hourly summer peak load of 3,374 mw occurred on August 28, 2000.

The maximum winter peak load of 2,382 mw occurred on December 18, 2000.

KCP&L owns the Hawthorn Station (Jackson County, Missouri), Montrose Station (Henry County, Missouri), Northeast Station (Jackson County, Missouri) and two Grand Avenue Station turbine generators (Jackson County, Missouri). KCP&L also owns 50% of the 688-mw LaCygne 1 Unit and 674-mw LaCygne 2 Unit in Linn County, Kansas; 70% of the 670-mw latan Station in Platte County, Missouri; and 47% of the 1,170 mw Wolf Creek in Coffey County, Kansas.

9

KCP&L Transmission and Distribution Resources KCP&L's electric transmission system interconnects with systems of other utilities to permit bulk power transactions with other electricity suppliers. KCP&L owns approximately 1,700 miles of transmission lines, approximately 8,900 miles of overhead distribution lines, and approximately 3,400 miles of underground distribution lines. KCP&L has all the franchises necessary to sell electricity within the territories from which substantially all of its gross operating revenue is derived.

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

Substantially all of the fixed property and franchises of KCP&L, which consists principally of electric generating stations, electric transmission and distribution lines and systems, and buildings subject to exceptions and reservations, are subject to a General Mortgage Indenture and Deed of Trust dated as of December 1, 1986.

KLT Gas Inc.

As of December 31, 2001, KLT Gas Inc. owned approximately 250,000 net mineral acres in Wyoming, Colorado, Texas, Kansas and Nebraska. KLT Gas Inc. has completed four pilots and is currently production testing these prospects to determine their economic viability. Subsequent to year-end, KLT Gas Inc. acquired additional mineral leases covering approximately 18,000 net acres in Colorado thereby establishing a new prospect area. KLT Gas Inc. expects to begin testing this prospect by year-end.

ITEM 3. LEGAL PROCEEDINGS Patricia S. Lang, et al. on behalf of herself and all others similarly situated v. Kansas City Power & Light Company. On October 8, 1999, a First Amended Class Action Complaint was filed against KCP&L in the United States District Court, Western District of Missouri (the Court) by Patricia Lang (the Plaintiff). The complaint, filed as a class action on behalf of Plaintiff and all other current and former African American employees, alleged that Plaintiff and the members of the proposed class were subjected to a hostile and offensive working environment, denied promotional opportunities, compensated less than similarly or less qualified Caucasian employees, and were disciplined and/or terminated for complaining about allegedly racially discriminatory practices by KCP&L. The complaint sought a monetary award for alleged lost wages and fringe benefits, alleged wage differentials, as well as punitive damages, attorneys fees and costs of the action together with an injunction to prohibit KCP&L from retaliating against the litigants and to continue court monitoring of KCP&L's compliance with anti-discrimination laws. On March 1, 2001, the Court denied Plaintiff's motion to certify a class action of African-American employees in the race discrimination case. The Plaintiff appealed this decision and on April 10, 2001, the United States Court of Appeals for the 8th Circuit (the 8th Circuit Court of Appeals) denied the appeal. On January 11, 2002, the Court dismissed Plaintiff's individual case on summary judgment. On February 8, 2002, Plaintiff appealed both the decision dismissing her individual case on summary judgment and the order denying her motion for class certification to the 8th Circuit Court of Appeals.

10

DTI Chapter 11 Reorganization Proceedings Pending in the United States Bankruptcy Court for the Eastern District of Missouri (Bankruptcy Court) is the bankruptcy reorganization proceedings filed on December 31, 2001, by DTI and its Virginia subsidiary in Case Nos. 01-54369-399, 01-54370-399 and 01-54371-399. These proceedings have been consolidated for joint procedural administration. DTI is continuing to conduct its business operations while it restructures its financial obligations. KLT Telecom Inc. is a creditor in the proceedings and has agreed to provide Debtor in Possession financing in amounts up to $5 million to DTI pending approval by the Bankruptcy Court.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS During the fourth quarter, no matter was submitted to a vote of security holders through the solicitation of proxies or otherwise for either Great Plains Energy or KCP&L.

PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Great Plains Energy Great Plains Energy common stock is listed on the New York Stock Exchange under the symbol GXP.

Prior to October 1, 2001, the Company was listed on the New York Stock Exchange under the symbol KLT. At December 31, 2001, Great Plains Energy's common stock was held by 18,393 shareholders of record. Information relating to market prices and cash dividends on Great Plains Energy's common stock is set forth below:

Common Stock Price Range ($)

2000 2001 Quarter H igh Low High Low First 29 20.875 27.56 23.60 Second 28.75 22.50 26.75 23.63 Third 28.75 23.5625 26.13 23.70 Fourth 28.1875 23.8125 27.35 23.19 Common Stock Dividends Declared Quarter 2000 2001 2002 First $0.415 $0.415 $0.415 Second 0.415 0.415 Third 0.415 0.415 Fourth 0.415 0.415 Great Plains Energy's Articles of Incorporation contain certain restrictions on the payment of dividends on Great Plains Energy's common stock in the event common equity falls to 25% of total capitalization.

If preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect members to the Board of Directors.

KCP&L Great Plains Energy holds all the outstanding shares of KCP&L's common stock.

11

ITEM 6. SELECTED FINANCIAL DATA Year Ended December 31 2 0 0 1 (bl 2 0 0 0 ()1 1 9 9 9 (bl 1998(c) 1997(1c)

(dollars in millions except per share amounts)

Great Plains Energy (a)

Operating revenues $1,462 $1,116 $ 921 $ 973 $ 917 Income (loss) before extraordinary item and cumulative effect of changes in accounting principles (d) $ (40) $ 129 $ 82 $ 121 $ 77 Net income (loss) $ (24) $ 159 $ 82 $ 121 $ 77 Basic and diluted earnings (loss) per common share before extraordinary item and cumulative effect of changes in accounting principles $ (0.68) $ 2.05 $ 1.26 $ 1.89 $ 1.18 Basic and diluted earnings (loss) per common share $ (0.42) $ 2.54 $ 1.26 $ 1.89 $ 1.18 Total assets at year end $3,464 $3,294 $ 2,990 $3,012 $3,058 Total mandatorily redeemable preferred securities $ 150 $ 150 $ 150 $ 150 $ 150 Total redeemable preferred stock and long term debt (including current maturities) $1,195 $1,136 $ 815 $ 913 $1,008 Cash dividends per common share $ 1.66 $ 1.66 $ 1.66 $ 1.64 $ 1.62 Consolidated KCP&L (a)

Operating revenues $1,351 $1,116 $ 921 $ 973 $ 917 Income before extraordinary item and cumulative effect of changes in accounting principles (d) $ 104 $ 129 $ 82 $ 121 $ 77 Net income $ 120 $ 159 $ 82 $ 121 $ 77 Total assets at year end $ 3,146 $ 3,294 $ 2,990 $ 3,012 $ 3,058 Total mandatorily redeemable preferred securities $ 150 $ 150 $ 150 $ 150 $ 150 Total redeemable preferred stock and long term debt (including current maturities) $1,164 $1,136 $ 815 $ 913 $1,008 j*l I

• I Great Plains Energy's consolidated financial statements include consolidated KCP&L, KLT Inc. and GPP. KCP&L's consolidated financial statements include its wholly owned subsidiary HSS. In addition, KCP&L's consolidated results of operations include KLT Inc. and GPP for all periods prior to the October 1, 2001 formation of the holding company.

(b) See Management's Discussion for explanation of 2001, 2000 and 1999 results.

(c) KCP&L incurred significant merger-related costs of $15 million in 1998 and $60 million in 1997. Included in 1997 merger expense is the $53 million payment to UtiliCorp United (UtiliCorp) for terminating the merger with UtiliCorp and agreeing to a merger with Western Resources Inc. Subsequently, the planned merger with Western Resources Inc. was terminated.

(d) In 2001, this amount is before the $15.9 million after taxes extraordinary gain on early extinguishment of debt. For further information, see Note 17 to the consolidated financial statements. In 2000, this amount is before the $30.1 million after taxes cumulative effect of changes in pension accounting. For further information, see Note 3 to the consolidated financial statements.

12

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 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 Financial Statements and Notes. Note 9.

Segment and Related Information summarizes the income statement by segment.

Great Plains Energy Incorporated Effective October 1, 2001, Great Plains Energy became the holding company of the following subsidiaries:

"* KCP&L, an integrated electric utility in the states of Missouri and Kansas, focused on providing reliable, low-cost electricity to retail customers; HSS, an unregulated subsidiary of KCP&L, holds investments in businesses primarily in residential services;

"* GPP, a competitive generator that will focus on development, production and trading of wholesale electric capacity and energy; and

"* KLT Inc., an investment company focusing on energy-related ventures that are unregulated with high growth potential.

Effective October 1, 2001, all outstanding KCP&L shares are exchanged one for one for shares of Great Plains Energy shares. The Great Plains Energy trading symbol "GXP" replaced the KCP&L trading symbol "KLT" on the New York Stock Exchange.

13

Great Plains Energy Consolidated Earnings Overview Great Plains Energy's earnings decreased from $157.1 million, or $2.54 per share in 2000, to a loss of

$25.8 million, or $(0.42) per share, in 2001. The decrease is primarily a result of a $195.8 million net write-off related to the bankruptcy filing of DTI as discussed below. The following table provides an overview of the contributions to earnings for the years ended December 31, 2001, 2000 and 1999.

2001 2000 1999 EPS summary Consolidated KCP&L KCP&L, excluding cumulative effect $1.57 $0.91 $1.34 Cumulative effect of changes in pension accounting - 0.49 KCP&L 1.57 1.40 1.34 HSS (0.09) (0.22) (0.06)

Consolidated KCP&L 1.48 1.18 1.28 KLT Inc.

Excluding extraordinary item (2.14) 1.36 (0.02)

Extraordinary item:

Early extinguishment of debt 0.26 -

KLT Inc. (1.88) 1.36 (0.02)

GPP and other (0.02)

Reported Consolidated EPS $(0.42) $ 2.54 $1.26 Effective January 1, 2000, KCP&L changed its methods of amortizing unrecognized net gains and losses and determination of expected return related to its accounting for pension expense. Accounting principles required KCP&L to record the cumulative effect of these changes increasing 2000 earnings by $30.1 million ($0.49 per share) in 2000. Adoption of the new methods of accounting for pensions could lead to greater fluctuations in pension expense in the future. The portions of the cumulative effect of pension accounting changes attributable to KLT Inc. and HSS are immaterial and, therefore, were not allocated to these subsidiaries.

On February 1, 2001, DTI, an equity investment of KLT Telecom on that date, completed a tender offer for 50.4% of its outstanding senior discount notes. This transaction resulted in a $15.9 million ($0.26 per share) extraordinary gain on the early extinguishment of debt.

For further discussion regarding each segment's contribution to consolidated EPS, see its respective Earnings Overview section below.

ConsolidatedKCP&L The following discussion of KCP&L's results of operations excludes the results of operations for KLT Inc., which was transferred to Great Plains Energy on October, 2001, and discusses HSS separately.

KCP&L's Consolidated Income Statement, however, includes KLT Inc.'s results of operations for the nine-months ended September 30, 2001, and HSS' results of operations. Consequently, the KCP&L discussion should be read in conjunction with the information provided in Note 9 of the notes to consolidated financial statements which provides financial information for the relevant periods for KCP&L, HSS and KLT Inc. separately.

14

KCP&L Operations KCP&L Business Overview KCP&L, a regulated utility, consists of two business units - power and delivery.

The power business unit has over 3,700 megawatts of generating capacity. The rebuild of the boiler at Hawthorn No. 5 was completed and the unit was returned to commercial operation on June 20, 2001.

During 2001, KCP&L entered into a $200 million, five-year construction and operating lease transaction for five combustion turbines that will add 385 megawatts of peaking capacity. Site preparation will begin in 2002 for the arrival of the first combustion turbine in 2003. The operating lease may be amended to transfer the right to use some or all of the units to GPP. If transferred, a significant portion of the output from some of these units may be sold to KCP&L.

The delivery business unit consists of transmission and distribution facilities that serve over 474,000 customers as of December 31, 2001. Load growth increased annually by approximately 2.0% to 2.5%

through increased customer usage and additional customers. Rates charged for electricity are below the national average and its reliability of service is above the national average.

KCP&L is regulated and follows SFAS No. 71, which applies to regulated entities with rates that are designed to recover the costs of providing service. Accordingly, KCP&L defers on the balance sheet items when allowed by a commission's rate order or when it is probable, based on regulatory past practices, that future rates will recover the amortization of the deferred costs. If SFAS No. 71 were not applicable, regulatory assets would be written off. At December 31, 2001, KCP&L had $124.4 million of unamortized regulatory assets.

KCP&L had an obligation, under FERC Order 2000, to join a FERC approved RTO by December 19, 2001. RTOs combine regional transmission operations of utility businesses into an organization that schedules transmission services and monitors the energy market to ensure regional transmission reliability and non-discriminatory access. However, during the fourth quarter of 2001, the FERC lifted its deadline and has not yet set another. KCP&L is a member of the SPP. In July 2001, the FERC rejected the SPP RTO proposal. On December 19, 2001, the FERC approved the RTO proposal submitted by the MISO. The SPP and the MISO announced plans to consolidate the two organizations to create a larger Midwestern RTO based on the December ruling. The SPP and the MISO will vote on this consolidation in the first quarter of 2002. The Midwestern RTO, a non-profit organization, would operate in twenty states and one Canadian province.

15

KCP&L Earnings Overview KCP&L contributed EPS of $1.57 for 2001, compared to $0.91 for 2000, excluding the cumulative effect of changes in pension accounting, and $1.34 for 1999. The following table and discussion highlight significant factors affecting the changes in KCP&L's EPS contribution for the periods indicated.

2001 2000 compared compared to to 2000 1999 Revenue, net of fuel and purchased power expense $0.45 $0.19 Replacement power insurance 0.04 (0.04)

Other operation and maintenance expense, including administrative and general expenses 0.13 (0.30)

Increased depreciation (0.12) (0.06)

Receivables write-off of one of KCP&L's major customers 0.02 (0.04)

Increased interest charges (0.15) (0.06)

Proposed IRS adjustment regarding corporate owned life insurance (see Note 18 to the consolidated financial statements) 0.21 (0.21)

Other 0.08 0.09 Total $0.66 $(0.43)

KCP&L's EPS contributions in 2001 compared to 2000 and 2000 compared to 1999 were impacted significantly by the Hawthorn No. 5 boiler explosion in February 1999, the rebuild of the unit and its subsequent return to commercial operation in June 2001. One of KCP&L's major customers closed its Kansas City plant in 2001. Warmer summer weather and colder winter weather in 2000 compared to 1999, partially offset by costly purchased power during the July 1999 heat storm, resulted in increased EPS in 2000.

KCP&L Megawatt-hour (mwh) Sales and Electric Sales Revenues 2001 compared to 2000 2000 compared to 1999 Mwh Revenues Mwh Revenues Retail Sales: (revenue change in millions)

Residential - $ (3.3) 10  % $ 28.0 Commercial 2 % 5.6 7  % 19.2 Major industrial customer (84) % (22.9) (6) % 7.5 Industrial - other (3) % (0.8) 1  % 0.3 Other 3 % 0.1 9  % 0.4 Total retail (3)% (21.3) 6  % 55.4 Sales for resale:

Bulk power sales 116 % 35.1 (25) % (5.6)

Other (3)% (0.3) 4% 0.4 Total 9% 13.5 2% 50.2 Other revenues 2.0 4.4 KCP&L electric sales revenues $15.5 $ 54.6 Excluding the impact of the loss of one of KCP&L's major industrial customers, retail revenues and mwh sales remained relatively consistent in 2001 compared to 2000. Extremely mild weather during the second half of 2001 more than offset the colder winter and warmer spring and early summer weather experienced in the first half of 2001 and continued load growth. Load growth is a result of 16

higher usage-per-customer and the addition of new customers. The average number of both residential and commercial customers increased about 2% in 2001 as compared to 2000. The major industrial customer declared bankruptcy on February 7, 2001 and closed its Kansas City, Missouri facilities on May 25, 2001. Less than 1% of revenues include an automatic fuel adjustment provision.

In 2000, retail revenues reached their highest level in KCP&L's history. Retail mwh sales increased in 2000 compared to 1999 primarily due to the impacts of weather and continued load growth. Although mwh sales for a major industrial customer discussed above decreased in 2000 compared to 1999, revenues increased because KCP&L was able to pass through its higher costs of fuel and purchased power under a contract with the customer.

In 1999, the MPSC approved a stipulation and agreement that called for KCP&L to reduce its annual Missouri electric revenues by 3.2%, or about $15 million effective March 1, 1999.

Bulk power sales vary with system requirements, generating unit and purchased power availability, fuel costs and requirements of other electric systems. The significant increase in bulk power mwh sales in 2001 compared to 2000 was primarily attributable to the return of Hawthorn No. 5 to commercial operation in June 2001. The average price per mwh of bulk power sales decreased 7% in 2001 compared to 2000, partially offsetting the effect of the increased bulk power mwh sales on revenues.

The unavailability of Hawthorn No. 5 contributed to decreased bulk power mwh sales of 25% in 2000 compared to 1999. However, the average price per mwh of bulk power sales in 2000 increased 17%

from 1999, partially offsetting the effect of lower bulk power mwh sales on revenues.

KCP&L Fuel and Purchased Power Fuel costs increased $10.7 million in 2001 compared to 2000 primarily due to a 14% increase in mwh's generated partially offset by a 9% reduction in the fuel cost per mmBtu. The increase in mwh's generated is primarily due to Hawthorn No. 5, a coal-fired unit, returning to operation in June 2001 and the impact of the scheduled 2000 outage at Wolf Creek, a nuclear unit. The additional availability of these two units in 2001 decreased the need for generation from natural gas and oil-fired units. Coal and nuclear fuel have a significantly lower cost per mmBtu than natural gas and oil.

Fuel costs increased by $23.8 million in 2000 compared to 1999 primarily due to the addition of gas fired generation and higher costs per mmBtu of natural gas and oil. In 2000, KCP&L added 294 megawatts of natural gas-fired generation with the completion of Hawthorn Nos. 7, 8 and 9. This increase in generation capacity replaced more expensive purchased power contracts. In addition, the price of natural gas and oil increased considerably in 2000 resulting in a $13 million increase in 2000 fuel cost, compared to 1999.

In both 2001 and 2000, fossil plants represented about 70% of total generation and the nuclear plant about 30%. Nuclear fuel costs per mmBtu remain substantially less than the mmBtu price of coal.

KCP&L expects its cost of nuclear fuel to remain fairly constant through the year 2003. KCP&L's procurement strategies continue to provide delivered coal costs below the regional average.

Purchased power expenses decreased $40.5 million in 2001 compared to 2000 primarily due to a 38%

decrease in mwh's purchased in 2001 compared to 2000. The decrease in mwh's purchased was primarily due to the increased availability of KCP&L's generating units during 2001 compared to 2000.

Increased generation capacity also allowed KCP&L to reduce its cost of purchased capacity by $7.6 million in 2001 as compared to 2000. In addition, purchased power average prices were down 4% in 2001 compared to 2000. However, the cost per mwh for purchased power is still significantly higher than the fuel cost per mwh of coal and nuclear generation.

17

Purchased power expenses increased $11.0 million in 2000 compared to 1999 primarily due to the unavailability of Hawthorn No. 5 and higher customer demand. In addition, excluding the impact of the July 1999 heat storm, the cost per mwh of purchased power increased by 66% in 2000 from 1999 resulting in higher purchased power energy costs.

KCP&L Other (including operating, maintenance and general taxes)

KCP&L's other expenses decreased $17.3 million in 2001 compared to 2000 primarily due to the following:

• replacement power insurance was not necessary for the summer months of 2001 because of the availability of Hawthorn No. 5;

• less customer information system software consulting in 2001;

• less advertising in 2001;

• reduced compensation expense;

• decreased net periodic pension cost of approximately $5 million.

KCP&L's pension benefit accounting principles, as discussed in Note 3 to the consolidated financial statements, can result in large fluctuations in pension expenses. The fair value of the pension plan assets at December 31, 2001, decreased $170 million from the December 31, 2000, plan year. This decrease will cause a reduction in the expected return on plan assets for 2002, which will have a $15 million unfavorable impact on 2002 net periodic benefit cost.

KCP&L's other expenses increased $29.9 million in 2000 compared to 1999 primarily due to the following:

"* Production expenses increased because of the cost of replacement power insurance incurred during the summer months of 2000, energy costs incurred during the test runs at Hawthorn Nos. 7, 8 and 9 and increased production training costs. Production expenses also increased due to operating and lease expenses for Hawthorn No. 6, which was placed into commercial operation in July 1999, and higher operating expenses at certain generating units. Partially offsetting this increase was a decrease in operating expenses at the Wolf Creek Generating Station, a nuclear unit.

"* Administrative and general expenses increased primarily due to increased salary expenses for implementation of system applications and increased legal costs partially offset by decreased pension expense.

"* Production maintenance expenses increased $6.8 million in 2000 primarily due to the timing of scheduled maintenance at KCP&L's generating units.

"* Distribution expenses increased primarily due to $3.5 million of costs incurred as a result of July and August 2000 storm damage.

"* Expenses decreased about $4 million because of the October 1999 sale of accounts receivable to KCP&L Receivable Corporation and the resulting change in recording bad debt expenses from operating expenses - other to other income and expenses subsequent to the sale.

Depreciation KCP&L's depreciation expense increased $12.0 million in 2001 compared to 2000 primarily due to the completion of the rebuild of the Hawthorn No. 5 unit, a full year of depreciation during 2001 on the Hawthorn No. 7, 8 and 9 units that were placed in service mid-2000 and depreciation on computer software capitalized during 2001. In addition, in the fourth quarter of 2001, KCP&L began depreciating the Hawthorn No. 6 combustion turbine unit after paying $40.8 million to exercise its purchase option under the previous lease agreement.

KCP&L Interest Charges KCP&L's interest charges increased $15.3 million in 2001 compared to 2000 primarily because of an increase in long-term debt interest expense and a decrease in the allowance for borrowed funds used during construction, partially offset by a decrease in short-term debt interest expense. KCP&L's 18

interest charges increased $6.4 million in 2000 compared to 1999 primarily because of increased long term and short-term debt interest expense partially offset by increased allowance for borrowed funds used during construction.

Long-term debt KCP&L's long-term debt interest expense increased $12.3 million in 2001 compared to 2000 reflecting higher average levels of outstanding long-term debt, partially offset by the impact of decreases in variable interest rates. The higher average levels of debt primarily reflect the issuances of long-term debt in 2000 and $150 million of unsecured, fixed-rate senior notes issued in November 2001, partially offset by $80.0 million of scheduled debt repayments.

KCP&L's long-term debt interest expense increased $7.9 million in 2000 compared to 1999 reflecting higher average levels of outstanding long-term debt and higher average interest rates on variable rate debt. The higher average levels of debt primarily reflected the $200 million of unsecured, floating rate medium-term notes issued in March 2000 and the $250 million of unsecured fixed-rate senior notes issued in December 2000, partially offset by $52.5 million of scheduled debt repayments.

Capitalizedinterest Allowance for borrowed funds used during construction decreased $3.0 million in 2001 compared to 2000 because of decreased construction work in progress due primarily to the completion of the Hawthorn No. 5 rebuild. Allowance for borrowed funds used during construction increased $8.8 million in 2000 compared to 1999 because of increased construction work in progress, primarily due to the rebuild of Hawthorn No. 5.

Short-term debt Interest expense on short-term debt decreased $2.2 million in 2001 compared to 2000 primarily due to lower interest rates on commercial paper, partially offset by higher average levels of outstanding commercial paper during 2001 compared to 2000. KCP&L had $62.0 million of commercial paper outstanding at December 31, 2001.

Short-term debt interest expense increased $7.9 million in 2000 compared to 1999 reflecting higher average levels of outstanding short-term debt. KCP&L primarily used the proceeds from the 2000 issuance of senior notes to reduce the outstanding commercial paper to $55.6 million at December 31, 2000.

Wolf Creek Wolf Creek represents about 15% of KCP&L's generating capacity. The plant's operating performance has remained strong over the last three years, contributing about 29% of KCP&L's annual mwh generation while operating at an average capacity of 93%. Wolf Creek has the lowest fuel cost per mmBtu 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's next refueling and maintenance outage is scheduled for the spring of 2002 and is estimated to be a 30-day outage.

The American Institute of Certified Public Accountants (AICPA) has issued a proposed Statement of Position, "Accounting for Certain Costs and Activities Related to Property, Plant and Equipment." This proposed statement would prohibit the accrual of KCP&L's cost associated with Wolf Creek's refueling and maintenance outages. However, as long as KCP&L is regulated under SFAS No. 71, management believes that KCP&L will be able to continue to accrue the costs evenly over the unit's operating cycle. If SFAS No. 71 were not applicable and the AICPA issued such guidance, KCP&L 19

would be required to recognize costs associated with the refueling and maintenance as incurred. This treatment would add volatility to KCP&L's results of operations due to the 18-month refueling cycle.

Wolf Creek's assets represent about 34% of KCP&L's assets and its operating expenses represent about 19% 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 to, and delays to, development of a low-level radioactive waste disposal facility (see Note 6 to the consolidated financial statements for additional information). An inabilily 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, 2001. 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 6 to the consolidated financial statements.

Hawthorn No. 5 On June 20, 2001, Hawthorn No. 5 was returned to commercial operation. The coal-fired unit has a capacity of 575 megawatts and was rebuilt following a February 1999 explosion that destroyed the boiler. Hawthorn No. 5 has been recognized nationally, in the National Energy Policy Report sent to President Bush for its use of best available pollution control technology. Under KCP&L's property insurance coverage, KCP&L received an additional $30 million in insurance recoveries in 2001, increasing the total insurance recoveries received to date to $160 million. The recoveries have been recorded as an increase in accumulated depreciation on the consolidated balance sheet.

Expenditures, excluding capitalized interest, for rebuilding Hawthorn No. 5 were $35.6 million in 1999,

$207.6 million in 2000, and $72.9 million in 2001. These amounts do not reflect insurance proceeds received to date or future proceeds to be received.

KCP&L Projected Construction Expenditures Total utility capital expenditures, excluding allowance for funds used during construction, were $262.0 million in 2001. The utility construction expenditures are projected for the next five years as follows:

Projected Construction Expenditures 2002 2003 2004 2005 2006 Total (millions)

Generating facilities $ 37 $ 31 $ 32 $ 25 $ 23 $148 Nuclear fuel 1 21 21 - 22 65 Distribution and transmission facilities 82 83 85 75 87 412 General facilities 18 10 10 11 10 59 Total $138 $145 $148 $111 $ 142 $684 This construction expenditure plan is subject to continual review and change.

Peaking capacity totaling 385 megawatts is being added pursuant to a $200 million construction and operating lease transaction.

20

January 2002 Ice Storm At the end of January 2002, the most damaging ice storm in Kansas City history caused roughly 285,000 customer outages throughout the KCP&L service territory. Currently, KCP&L does not have an estimate of the cost of the 2002 storm and has not determined how it will account for the costs. The cost to repair damage from the storm is expected to substantially exceed the $13 million incurred because of the 1996 snowstorm. The 2002 storm compared to the 1996 storm had 100,000 more customers out of service, took longer to return service to all of the affected customers and utilized twice the number of outside crews.

HSS Operations HSS, an unregulated subsidiary of KCP&L, holds investments in businesses primarily in residential services. HSS is comprised of two subsidiaries, RSAE and Worry Free Services, Inc.

In 2001, HSS increased its ownership in RSAE, a consumer services company headquartered in Atlanta, Georgia, from 49% to 72%. Accordingly, HSS changed its method of accounting for RSAE from the equity method to consolidation. As a result, HSS includes RSAE's assets and liabilities including goodwill incurred by RSAE in its financial statements. Management currently does not anticipate the January 1, 2002, adoption of SFAS No. 142, "Goodwill and Other Intangible Assets" will require an impairment of the $23.0 million recorded goodwill at December 31, 2001. However, a decline in the fair value of RSAE's net assets would cause an impairment of goodwill and HSS would have to write-off the amount of goodwill impaired. Worry Free Service, Inc., a wholly owned subsidiary of HSS, assists residential customers in obtaining financing primarily for heating and air conditioning equipment.

KCP&L's investment in HSS was $46.9 million at December 31, 2001, and $46.3 million at December 31, 2000. During 2001, HSS' loss decreased to $5.6 million ($0.09 per share) from $13.5 million

($0.22 per share) in 2000. HSS' loss in 1999 was $3.7 million ($0.06 per share). HSS' decreased loss in 2001 compared to 2000 was primarily due to a $12.2 million write-down of its investment in RSAE during 2000. Through December 31, 2001, KCP&L's accumulated losses were $23.6 million on its investment in HSS. Due to its consolidation of RSAE beginning in 2001, HSS' consolidated assets increased to $53.9 million at December 31, 2001, from $25.3 million at December 31, 2000.

During 2001, HSS recorded a $7.2 million loss from its investment in RSAE resulting in a negative investment. The minority interest in RSAE has been reduced to zero as a result of these losses.

Accordingly, as long as RSAE is consolidated, any future losses by RSAE will be recorded in HSS' income statement at 100% which will further decrease the investment below zero.

HSS has loaned RSAE $1.3 million ($0.3 million in December 2001 and $1.0 million in January 2002).

RSAE used the proceeds to fund operations. HSS expects repayment from RSAE during the first quarter of 2002 when RSAE obtains additional third party financing. Currently, RSAE has $20.4 million outstanding of third party financing which is supported by Great Plains Energy through an agreement that ensures adequate capital to operate RSAE.

KLT Inc. Operations KLT Inc. Business Overview KLT Inc. is an unregulated subsidiary that pursues energy-related ventures in higher growth businesses. Existing ventures include natural gas development and production, energy services and affordable housing limited partnerships. The Company's cash investment in KLT Inc. was

$150.0 million at December 31, 2001, and $119.0 million at December 31, 2000.

21

Natural Gas Development and Production - KLT Gas KLT Gas' business strategy is to acquire and develop early stage coalbed methane properties. KLT Gas believes that coalbed methane production provides an economically attractive alternative source of supply to meet the growing demand for natural gas in North America and has built a knowledge base in coalbed methane production and reserves evaluation. Therefore, KLT Gas focuses on coalbed methane - a niche in the natural gas industry where it believes its expertise provides a competitive advantage. Because it has a longer, predictable reserve life and lower development cost, coalbed methane is inherently lower risk than conventional gas exploration.

Although gas prices have been volatile recently, KLT Gas continues to believe that the long-term future price scenarios for natural gas appear strong. Environmental concerns and the increased demand for natural gas for new electric generating capacity are contributing to this projected growth in demand.

KLT Gas' properties are located in Colorado, Texas, Wyoming, Kansas, and Nebraska. These leased properties cover approximately 220,000 undeveloped acres. The development of this acreage is in accordance with KLT Gas' exploration plan and capital budget. KLT Gas estimates capital expenditures of about $37 million, $42 million, $38 million and $20 million for the years 2002 through 2005, respectively. The timing of the development may vary from current plans based upon obtaining the required environmental and regulatory approvals and permits.

Energy Management Service - Strategic Energy Strategic Energy is an energy management services provider that operates in several deregulated electricity markets, including Pennsylvania, southern California, Ohio, New York, Massachusetts and Texas. In 2001, KLT Energy Services exchanged with an energy services company preferred stock of

$4.7 million in that company for additional ownership in Strategic Energy. This transaction increased KLT Energy Services ownership of Strategic Energy from 72% to 83%.

Strategic Energy acts as an energy manager in deregulated markets on behalf of approximately 19,500 commercial and small manufacturing accounts. One to five year contracts are entered into with customers to supply and manage their energy needs. In return, they receive an ongoing management fee plus the contracted price for the electricity and natural gas. Natural gas retail service was phased out in the fourth quarter of 2001.

Strategic Energy is exposed to credit risk arising from counterparties from whom it purchases physical commodities, as unrealized gains or losses may accrue in physical contracts if a supplier is unable to fulfill its obligations. Strategic Energy manages counterparty credit risk exposure through a disciplined risk management policy.

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. Supplying electricity to retail customers under fixed rate contracts requires Strategic Energy to match customers' demand with fixed price purchases. In certain markets where Strategic Energy operates, there is limited availability of forward fixed price power contracts. By entering into swap contracts for a portion of its forecasted purchases in these markets, the future purchase price of electricity is effectively fixed under these swap contracts. The swap contracts limit the unfavorable effect that price increases will have on electricity purchases.

Under SFAS No. 133, the majority of the swap agreements are designated as cash flow hedges resulting in the difference between the market value of energy and the hedge value being recorded as comprehensive income(loss). At December 31, 2001, the accumulated comprehensive loss, net of income taxes and minority interest, reflected in Great Plains Energy's consolidated statement of capitalization reflected a $11.7 million loss related to such cash flow hedges. However, most of the energy hedged with the swaps has been sold to customers through contracts at prices different than 22

the fair market value used to value the swaps. Therefore, Strategic Energy does not anticipate incurring any of the losses represented in comprehensive income.

Strategic Energy's customer base is very diverse. Customers include numerous Fortune 500 companies, school districts, and governmental entities. Based on current signed contracts and expected usage, Strategic Energy forecasts a peak load of 2,268 megawatts. The largest concentration of the forecasted load, 817 megawatts, is in southern California.

Subsidiaryof KL T Telecom Files for Bankruptcy - D TI The accounting treatment related to DTI and its bankruptcy is complex and is addressed in greater detail in note 17 to the consolidated financial statements; consequently, note 17 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.

In 1997, KLT Telecom originally purchased, for $45 million, a 47% equity ownership of DTI, a facilities based, telecommunications company headquartered in St. Louis. DTI's operating losses reduced this original equity investment to zero by June 2000. In February 2001, KLT Telecom made an additional

$40 million investment in DTI, increasing its ownership to 83.6% and a $94 million loan to DTI Holdings. In February 2001, KLT Telecom also made a commitment to obtain or arrange a $75 million revolving credit facility for Digital Teleport Inc. KLT Telecom loaned Digital Teleport Inc. $47 million during 2001 under this and other arrangements. DTI intended to refinance part of these loans.

However, a new senior credit facility from bank lenders was not possible due to, among other things, the downturn in the telecommunications industry.

Starting in the second quarter of 2001, DTI conserved cash by more narrowly focusing its strategy to providing connectivity in secondary and tertiary markets in a five state region. DTI actively explored its strategic alternatives including a merger, sale of assets and all other types of recapitalization including bankruptcy. DTI originally thought that the industry downturn would be only temporary. However, during the fourth quarter the combination of a lack of additional financing, continued decline of the telecommunication industry, and the cash requirements of maintaining its long-haul assets resulted in DTI making the decision to abandon its long-haul assets and file for reorganization under Chapter 11 of the U.S. Bankruptcy Code on December 31, 2001.

Because of the bankruptcy, a $195.8 million net write-off is included in (Gain) Loss on Property in operating expenses on Great Plains Energy's Consolidated Statement of Income. A corresponding tax benefit of $55.8 million is included in income taxes. The net impact of the bankruptcy to income is a

$140.0 million ($2.27 per share) reduction.

Income taxes reported for 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. If additional DTI assets are abandoned or sold during the bankruptcy process, or additional tax losses not already reflected are incurred by DTI, future tax benefits will be recorded.

23

KLT Inc. Earnings Overview The following table and discussion highlight significant factors affecting KLT Inc.'s effect on consolidated EPS for the years ended 2001, 2000 and 1999.

2001 2000 1999 KL T Inc. EPS summary Strategic Energy $ 0.35 $ 0.09 $ 0.03 DTI Operations subsequent to 2/8/01 (0.54) -

Gain on early extinguishment of debt and equity losses prior to majority ownership 0.26 (0.14) (0.24)

KLT Gas Operations 0.04 0.18 0.05 Sale of gas properties 0.19 1.10 KLT Investments 0.11 0.22 0.20 Other (0.02) (0.09) (0.06)

KLT Inc. before net write-off of investment in DTI 0.39 1.36 (0.02)

Net write-off of investment in DTI (2.27)

KLT Inc. EPS $ (1.88) $ 1.36 $ (0.02)

Strategic Energy Strategic Energy's increase in earnings per share for 2001 compared to 2000 is due to continued strong growth in its electric energy management business and a significant increase over the prior year in wholesale bulk power sales, which have a considerably higher gross margin (revenues less cost of energy supplied) than Strategic Energy's retail electric sales.

KL T Gas During 2001, KLT Gas sold its 50% equity ownership in Patrick KLT Gas, LLC for $42.3 million, resulting in an after tax gain of $12.0 million ($0.19 per share). During 2000, KLT Gas sold producing natural gas properties for $237.2 million, resulting in an after tax gain of $68.0 million ($1.10 per share).

KLT Investments During 2001, KLT Investments recorded a reduction to its investments in affordable housing limited partnerships of $13.5 million before taxes ($0.14 per share). The reduction for 2000 was $2.4 million before taxes ($0.02 per share).

Other During 2001, KLT Energy Services recorded a write-off of its $6.2 million ($0.06 per share) investment in the common stock of Bracknell Corporation due to a decline in its share price and the bankruptcy filing of one of Bracknell Corporation's subsidiaries. In 2000, KLT Inc. realized losses on its investment in CellNet Data Systems Inc. of $4.8 million before taxes ($0.05 per share).

24

KLT Inc. Revenues 2001 2000 compared compared to to 2000 1999 (millions)

DTI $ 15.9 $

Strategic Energy Electric - Retail 255.9 57.4 Electric - Bulk Power Sales 30.4 52.3 Gas (4.0) 19.9 KLT Gas (30.2) 13.2 Other 0.1 (3.5)

Total $ 268.1 $139.3 Strategic Energy's retail revenues increased in 2001 compared to 2000 due to continued strong growth in its electric energy management business. Strategic Energy currently serves approximately 19,500 commercial and small manufacturing accounts, an increase of about 12,500 accounts from the beginning of 2001. In addition, based on current signed contracts and expected usage, Strategic Energy forecasts a peak load of 2,268 megawatts compared to a peak load of 1,300 megawatts in 2001 and a peak load of 400 megawatts in 2000.

Strategic Energy's bulk power sales revenues increased in 2001 compared to 2000 due to large block sales of power purchased under an option to purchase up to 270 megawatts of power at $21 per mwh through the end of 2001. Strategic Energy also purchases energy in the wholesale markets to meet its customers' energy needs. On occasion, Strategic Energy must purchase small blocks of power prior to the sales contract in order to quote stable pricing to potential new customers. Power purchased in excess of retail sales is sold in the wholesale markets.

Strategic Energy's retail, bulk power sales, and gas revenues increased in 2000 compared to 1999 due to KLT Energy Services increasing its ownership interest in Strategic Energy to 72% (69% of the voting interest) during 2000, from a 56% ownership interest (49% of the voting interest) during 1999. Thus, KLT Energy Services reported Strategic Energy on a consolidated basis for 2000, in contrast to reporting Strategic Energy as an equity method investment for 1999.

KLT Gas revenues decreased in 2001 compared to 2000 primarily due to the sale of producing natural gas properties in the third and fourth quarters of 2000 and the effect of gas hedging activities. KLT Gas unwound the majority of its gas hedge derivatives with an offsetting swap transaction during the second quarter of 2001. The fair market value of the swap has been recorded in gas revenues. KLT Gas revenues increased in 2000 compared to 1999 primarily due to higher production levels in 2000 and higher average prices for natural gas sold.

Gains and Losses on Property KLT Inc.'s loss on property for 2001 includes the $195.8 million DTI bankruptcy net write-off, partially offset by a $20.1 million before tax gain on KLT Gas' sale of its 50% equity ownership in Patrick KLT Gas, LLC. KLT Inc.'s gain on property for 2000 includes a $110.6 million before tax gain on KLT Gas' sale of producing natural gas properties.

Other Income and Expenses The unfavorable changes in other income and expenses for 2001 compared to 2000 were primarily due to KLT Investments Inc.'s $13.5 million reduction in affordable housing limited partnerships and KLT Energy Service's $6.2 million write-off of an investment in the common stock of Bracknell Corporation.

The unfavorable changes in other income and expenses for 2000 compared to 1999 were primarily due 25

to minority interests in Strategic Energy recorded in 2000 of $4.4 million when KLT Energy Services began consolidating Strategic Energy in 2000 and $4.8 million of realized losses on the write-off of an investment in CellNet Data Systems Inc. These decreases were partially offset by an increase in interest and dividend income of $4.2 million and unrealized gains of $3.8 million on trading securities acquired in 2000.

KLT Inc. Taxes KLT Inc. income taxes for 2001 include a $55.8 million tax benefit from the net write-off of its investment in DTI and accrued tax credits of $25.1 million related to investments in affordable housing limited partnerships and natural gas properties. KLT Inc.'s income taxes increased in 2000 compared to 1999 primarily because of $42.6 million in income tax expense incurred by KLT Gas on the gain from the sale of natural gas producing properties, partially offset by accrued tax credits of $26.7 million related to investments in affordable housing limited partnerships and natural gas properties.

Great PlainsPower Operations GPP will focus on developing and acquiring fossil fuel-fired electric generation in the central part of the U.S. GPP announced an agreement with the boiler and air quality control equipment vendor and construction firm, Babcock and Wilcox, and the design and engineering firm, Burns and McDonnell, to conduct the design and development study for a coal-fired plant. This is the same team that rebuilt Hawthorn No. 5.

Other ConsolidatedDiscussion Significant Balance Sheet Changes (December 31, 2001 compared to December 31, 2000)

"* Great Plains Energy receivables increased $36.8 million primarily due to the strong growth in Strategic Energy's electric energy management business partially offset by the decrease in KCP&L receivables because of the mild winter and sale of an additional $10.0 million of receivables pursuant to its existing revolving accounts receivable sale agreement. KCP&L receivables also decreased because of the effects of the formation of the holding company through which KCP&L dividended its ownership of KLT Inc. to Great Plains Energy.

"* Great Plains Energy and consolidated KCP&L equity securities decreased $18.6 million primarily due to KLT Gas' sale of $12.3 million of stock in Evergreen Resources, Inc. and the write-off of an equity security that KLT Energy Services held.

"* Great Plains Energy current income taxes reflects the tax benefit from the write-down of KLT Inc.'s investment in DTI.

"* Great Plains Energy affordable housing limited partnerships decreased $17.0 million due to a reduction of KLT's investments in affordable housing limited partnerships. Consolidated KCP&L decreased because of the formation of the holding company.

"* Great Plains Energy gas property and investments decreased $4.3 million primarily due to KLT Gas' sale of its 50% equity ownership in Patrick KLT Gas, LLC partially offset by additions to gas property. Consolidated KCP&L decreased because of the formation of the holding company.

"* Great Plains Energy other nonutility property and investments decreased $17.1 million due to the sale by KLT Inc. of various other investments and the exchange of $4.7 million preferred stock in an energy services company for an additional ownership in Strategic Energy.

Consolidated KCP&L also decreased because of the formation of the holding company.

"* Great Plains Energy and consolidated KCP&L combined electric utility plant and construction work in progress increased $241.4 million primarily due'to expenditures and capitalized interest of $83.3 million at Hawthorn No. 5 to rebuild the boiler and $191.6 million for other utility capital 26

expenditures. The completion of rebuilding the boiler at Hawthorn No. 5 resulted in a transfer of $337.0 million from construction work in progress to electric plant.

• Great Plains Energy and consolidated KCP&L prepaid pension costs increased $20.0 million due to negative pension expense.

• Great Plains Energy goodwill increased because HSS increased its ownership and began consolidating RSAE. For consolidated KCP&L, this increase was partially offset by the decrease caused by the formation of the holding company.

• Great Plains Energy and consolidated KCP&L other deferred charges increased $19.3 million primarily due to an $18.3 million intangible pension asset recorded by KCP&L due to a significant decline in the market value of pension plan assets.

"* Great Plains Energy notes payable of $144.4 million includes $124.0 million relating to short term notes held by Great Plains Energy for a bridge credit facility and $20.4 million related to the consolidation of RSAE.

"* Great Plains Energy and KCP&L current maturities of long-term debt increased primarily because of a $227.0 million increase in the current portion of KCP&L's medium-term notes offset by $80.0 million of maturing medium-term notes.

"* Great Plains Energy other current liabilities increased primarily because of accruing for Strategic Energy derivatives.

"* Great Plains Energy other deferred credits increased $50.2 million due to $11.8 million of Strategic Energy's long term derivatives, $20.6 million of KLT Telecom's negative investment related to the DTI bankruptcy (see note 17) and $20.0 million minimum pension liability recorded by KCP&L due to a significant decline in the market value of pension plan assets.

Capital Requirements and Liquidity Great Plains Energy is a holding company that operates through its subsidiaries and has no material assets other than the stock of its subsidiaries. Great Plains Energy's ability to make payments on its debt securities and its ability to pay dividends is dependent on its receipt of dividends from its subsidiaries or proceeds from the sale of its securities.

Great Plains Energy's liquid resources at December 31, 2001, included cash flows from operations of subsidiaries and $139.3 million of unused bank lines of credit. The unused lines consisted of $134.0 million from KCP&L's short-term bank lines of credit, $0.3 million from RSAE's bank credit agreement, and $5.0 million from Great Plains Energy's bridge credit facility.

KLT Inc.'s bank credit agreement balance of $99.5 million was repaid October 3, 2001, with proceeds from Great Plains Energy's $129 million bridge credit facility which terminates on February 28, 2002.

Great Plains Energy is currently negotiating a 364-day revolving credit facility with a group of banks to replace the bridge facility. The new facility will be for up to $225 million and will be used for general corporate purposes. Both the bridge facility and the new facility contain a Material Adverse Change (MAC) clause that requires Great Plains Energy to represent, prior to receiving any funding, that no MAC has occurred. Great Plains Energy's available liquidity under both facilities is not impacted by a decline in credit ratings unless the downgrade occurs in the context of a merger, consolidation or sale.

KCP&L's primary sources of liquidity are cash flows from operations and bilateral credit lines with ten banks (as of December 31, 2001). KCP&L uses these lines to provide support for its issuance of commercial paper, $62.0 million of which was outstanding at the end of 2001. These bank facilities are each for a 364-day term and mature at various times throughout the year. With two exceptions, KCP&L does not have MAC clauses in these agreements. In those cases, KCP&L is required to represent, as a condition to renewing the facilities, that no MAC has occurred from the most recent quarter-end to the closing date of the renewal. In these instances, a MAC subsequent to closing does not impact available liquidity for the remaining term of the renewed facility. 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.

27

Great Plains Energy's consolidated statements of cash flows include consolidated KCP&L, KLT Inc.

and GPP. KCP&L's consolidated statements of cash flows include its wholly owned subsidiary HSS.

In addition, 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 presentation of prior years statements of cash flows for Great Plains Energy is provided for comparative purposes and is identical to the statements of cash flows for consolidated KCP&L, prior to the formation of the holding company, presented for those years. The effect of DTI on the statements of cash flows is detailed in Note 2 to the consolidated financial statements.

Great Plains Energy and consolidated KCP&L generated positive cash flows from operating activities for 2001. The increase for Great Plains Energy and consolidated KCP&L over 2000 is directly attributable to increased net income before non-cash expenses. The increased net income before non-cash expenses was partially offset by 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. Also, the timing of the Wolf Creek outage affects the refueling outage accrual, deferred income taxes and amortization of nuclear fuel. Cash from operating activities increased in 2000 from 1999 primarily due to changes in certain working capital items. In addition, the buyout of a fuel contract; the refund of amounts accrued for the Kansas rate refunds; and a payment of

$19 million to the IRS to settle certain outstanding issues decreased cash flows from operating activities in 1999. Partially offsetting these changes for 2000, net income before non-cash expenses decreased.

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. With KCP&L's 2001 completion of the rebuild of Hawthorn No. 5, utility capital expenditures decreased $139.0 million and the allowance for borrowed funds used during construction decreased $3.0 million. Cash used for purchases of investments and nonutility property in 2001 compared to 2000 increased primarily reflecting KLT Telecom's investments in DTI and DTI purchases of telecommunications property, partially offset by KLT Gas' investments in gas properties during 2000. Proceeds from the sale of properties decreased significantly because the proceeds from the sale of KLT Gas properties in 2000 more than offset the 2001 sale. Cash used for investing activities increased in 2000 compared to 1999 reflecting increased utility capital expenditures for construction projects at the Hawthorn generating station, increased purchases by KLT Gas of natural gas investments and KLT Energy Services' exercise of its option to acquire common stock of a publicly-traded company. Proceeds from the sales of KLT Gas properties reduced cash used for investing activities in 2000.

Cash from Great Plains Energy financing activities increased in 2001 compared to 2000 primarily because short-term borrowings increased $140.7 million in 2001 compared to a $183.1 million decrease in 2000. However, this change in short-term borrowings was partially offset by a decrease in long-term debt issuances, net of repayments. Cash from consolidated KCP&L financing activities increased similarly, but exclude the repayment of KLT Inc.'s bank credit agreement and the increase in short term borrowings for the Great Plains Energy bridge loan discussed above. KCP&L issued $150 million of unsecured senior notes in November 2001. Cash from financing activities increased in 2000 primarily because KCP&L issued $200 million of unsecured medium-term notes and $250 million of unsecured senior notes in 2000. KLT Gas borrowed $51 million on a new bank credit agreement and repaid the amount in full in 2000. Also, KCP&L's scheduled debt repayments were about $17 million lower in 2000 than in 1999. Furthermore, KCP&L's short-term borrowings increased in 2000.

However, the increase was more than offset by the repayment with proceeds from the unsecured note issuances. Partially offsetting these increases, KLT Inc. repaid borrowings on its bank credit agreement, which was $61.0 million at December 31, 1999, with proceeds from the sales of KLT Gas properties.

28

The Company's common dividend payout ratio was 104% (excluding the extraordinary item and the DTI net write-off) in 2001, 81% (excluding the cumulative effect of changes in accounting principles) in 2000, and 132% in 1999. See the Earnings Overview sections for discussion of significant factors impacting EPS in 2001, 2000 and 1999.

KCP&L expects to meet day-to-day operations, construction requirements (excluding new generating capacity) and dividends 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, refinancings and/or short-term debt.

The Company may issue additional debt and/or additional equity to finance growth or take advantage of new opportunities.

As reflected in the contractual obligations tables below, consolidated KCP&L has $227.4 million of long-term debt maturing in 2002. Consolidated KCP&L plans to register up to $450 million during the first quarter of 2002, a portion of which is expected to be issued to refinance its current maturities. Any proceeds from additional issuances may be used to refinance other debt securities or for general corporate purposes.

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

Payments Due by Period Great Plains Energy Contractual 2003- 2005 Cash Obligations Total 2002 2004 2006 After 2006 (millions)

Long-term debt, including current maturities (c) $1,195.6 $ 238.8 $ 91.3 $ 304.0 $ 561.5 Lease obligations (a) 244.0 22.7 51.3 49.6 120.4 Other long-term obligations, net (b) 1,180.2 436.8 473.9 185.6 83.9 Total contractual obligations $ 2,619.8 $ 698.3 $ 616.5 $ 539.2 $ 765.8 Payments Due by Period Consolidated KCP&L 2003- 2005 Contractual Cash Obligations Total 2002 2004 2006 After 2006 (millions)

Long-term debt, including current maturities (C) $1,164.5 $ 227.4 $ 77.3 $ 299.1 $ 560.7 Lease obligations (a) 239.8 21.5 49.9 48.8 119.6 Other long-term obligations, net (b) 265.2 70.5 84.5 26.3 83.9 Total contractual obligations $1,669.5 $ 319.4 $ 211.7 $ 374.2 $ 764.2 (a) Includes capital and operating lease obligations; capital lease obligations are not material. Also includes 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 $1.9 million per year ($27.0 million total). Excludes commitment to either purchase leased combustion turbines at termination of the construction leasing arrangement for a price equal to amounts expended by the Lessor or sell the turbines on behalf of the Lessor while guaranteeing the Lessor's receipt of an amount equal to 83.21% of amounts expended.

(b) Includes commitments for KCP&L's share under contracts for acquisition of coal, natural gas, and nuclear fuel including

$3.4 million DOE assessment; net capacity purchases and sales for KCP&L. Great Plains Energy also includes Strategic Energy's purchased power commitments.

(c) Excludes $0.7 million discount on senior notes. EIRR bonds classified as current liabilities of $106.5 million due 2015 and $81 million due 2017 are included here on their final due date. (See note 13 to the consolidated financial statements.)

29

Amount of commitment expiration per period Other Commercial 2003- 2005 Commitments Outstanding Total 2002 2004 2006 After 2006 (millions)

Consolidated KCP&L Guarantees $ 14.7 $ 1.8 $ 3.6 $ 3.4 $ 5-9 Great Plains Energy Guarantees, including consolidated KCP&L $247.1 $190.6 $ 3.6 $ 3.4 $ 49.5 KLT Inc. has provided $195.7 million of guarantees to support Strategic Energy power purchases and regulatory requirements. Strategic Energy's power supply contracts are up to 5 years with an average duration of 2.7 years. As of December 31, 2001, KLT Inc.'s guarantees related to Strategic Energy are as follows:

"* Direct guarantees to counterparties totaling $63.4 million, with varying expiration dates

"* Guarantees to the issuers of surety bonds totaling $110.0 million, all of which expire in 2002

"* Guarantees related to Letters of Credit totaling $22.3 million, all of which expire in 2002 KLT Inc. has guaranteed a construction performance bond of $14.7 million of a contractor. RSAE has a $22 million line of credit with a commercial bank, which Great Plains Energy supports through an agreement that ensures adequate capital to operate RSAE. KCP&L is contingently liable for guaranteed energy savings under agreements with several customers KCP&L has entered agreements guaranteeing an aggregate value of approximately $14.7 million over the next nine years. In most cases a subcontractor would indemnify KCP&L for any payments made by KCP&L under these guarantees.

In 1999, KCP&L entered into a revolving agreement to sell all of its right, title and interest in the majority of its customer accounts receivable to KCP&L Receivable Corporation, a special purpose entity established to purchase customer accounts receivable from KCP&L expiring in October 2002.

The Company expects the agreement to be renewed annually. KCP&L Receivable Corporation has sold receivable interests to outside investors. In consideration of the sale, KCP&L received $60 million in cash in 2000 increasing to $70 million in 2001 and the remaining balance in the form of a subordinated note from KCP&L Receivable Corporation. The agreement is structured as a true sale under which the creditors of KCP&L Receivable Corporation will be entitled to be satisfied out of the assets of KCP&L Receivable Corporation prior to any value being returned to KCP&L or its creditors.

Accounts receivable sold to KCP&L Receivables Corporation under the agreement totaled $95.7 million at December 31, 2001, and $108.2 million at December 31, 2000.

Administrative costs associated with the sale of customer accounts receivable of approximately $2.7 million for the year ended December 31, 2001, approximately $4.3 million for the year ended 2000 and approximately $3.5 million for the year ended 1999, were included in Other income and expenses.

Recent Accounting Pronouncements In 2001, the FASB issued SFAS No.142, "Goodwill and Other Intangible Assets", which the Company adopted January 1, 2002, and SFAS No. 143, "Accounting for Asset Retirement Obligations", which the Company will adopt January 1, 2003. Management currently does not anticipate that the adoption of these statements will have a material impact on the Company's results of operations. See notes 10 and 1 to the consolidated financial statements for additional discussion regarding SFAS No. 142 and SFAS No. 143, respectively.

30

Environmental Matters The Company's operations comply with federal, state and local environmental laws and regulations.

The generation and transmission of electricity produces and requires disposal of certain products and by-products, including PCBs, asbestos and other hazardous materials. The Superfund law imposes strict joint and several liability for those who generate, transport or deposit hazardous waste. In addition, the current owner of contaminated property, as well as prior owners since the time of contamination, may be liable for cleanup costs.

Environmental audits are conducted to detect contamination and ensure compliance with governmental regulations. However, compliance programs need to meet new and future environmental laws, as well as regulations governing water and air quality, including carbon dioxide emissions, nitrogen oxide emissions, hazardous waste handling and disposal, toxic substances and the effects of electromagnetic fields. Therefore, compliance programs could require substantial changes to operations or facilities (see Note 6 to the consolidated financial statements).

31

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Great Plains Energy and consolidated KCP&L are exposed to market risks associated with commodity price and supply, interest rates and equity prices. Market risks are handled in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, Great Plains Energy and consolidated KCP&L also face risks that are either non financial or non-quantifiable. Such risks principally include business, legal, operational and credit risks and are not represented in the following analysis.

Commodity Risk KCP&L and Strategic Energy engage in the wholesale and retail marketing of electricity, and accordingly, are exposed to risk associated with the price of electricity.

KCP&L's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity and long, intermediate and short-term capacity/energy contracts. KCP&L maintains a reserve margin of at least 12% of its peak summer demand. This net positive supply of capacity and energy is maintained through its generation assets and capacity and power purchase agreements to protect it from the potential operational failure of one of its owned or contracted power generating units. The agreements contain penalties for non-performance to protect KCP&L from energy price risk on the contracted energy. KCP&L also enters into additional power purchase agreements with the objective of obtaining the most economical energy to meet its physical delivery obligations to its customers. KCP&L continually evaluates the need for additional risk mitigation measures in order to minimize its financial exposure to, among other things, spikes in wholesale power prices during periods of high demand.

KCP&L's sales include the regulated sales of electricity to its retail customers and unregulated bulk power sales of electricity in the wholesale market. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply, the availability and cost of purchased power and the requirements of other electric systems; therefore, the impact of the hypothetical amounts that follow could be significantly reduced depending on the system and market prices at the time of the increases. Almost 60% of KCP&L's generating capacity is coal-fired. A hypothetical 10% increase in the market price of coal could have resulted in a $1.5 million decrease in pretax earnings for 2001. KCP&L currently has approximately 95% of its coal requirements for 2002 under contract. Approximately 40% of the amounts under contract are subject to the market price of coal. A hypothetical 10% increase in the cost of purchased power could have resulted in a $6.5 million decrease in pretax earnings for 2001. A hypothetical 10% increase in natural gas and oil market prices could have resulted in a $2.9 million- decrease in pretax earnings for 2001. KCP&L has implemented price risk mitigation measures to reduce its exposure to high natural gas prices. Slightly over 50% of its projected total oil and natural gas requirements for 2002 are price protected through its hedging program.

Strategic Energy aggregates retail customers into economic purchasing pools, develops predictive load models for the pools and then builds a portfolio of suppliers to provide the pools with reliable power at the lowest possible cost. Strategic Energy has entered into significant supply contracts with dispatchable and firm power agreements through the year 2005 and into 2006 that mitigate most of the commodity risk associated with its power supply coordination services. 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. Supplying electricity to retail customers under fixed rate contracts requires Strategic Energy to match customers' demand with fixed price purchases. In certain markets where Strategic Energy operates, there is limited availability of forward fixed price power contracts. By entering into swap contracts for a portion of its forecasted purchases in these markets, the future purchase price of electricity is effectively fixed under these swap contracts. The swap contracts limit the unfavorable effect that price increases will have on electricity purchases.

32

KLT Gas is exposed to commodity price risk on the natural gas it produces. Financial hedge instruments can be used to mitigate its exposure to market price fluctuations on approximately 85% of its daily gas sales in accordance with its risk management policy. Currently, KLT Gas is producing an insignificant volume of gas and the price risk is minimal. Because of a reduction in production during 2001, KLT Gas unwound all hedged positions.

Management has determined that KCP&L and Strategic Energy are not "trading organizations" under EITF 98-10 based on their business philosophy, performance measurement and other management activities. If considered "trading organizations", KCP&L and Strategic Energy would be required to record energy transactions at fair value. Commitments to purchase and sell energy and energy-related products except for derivatives that qualify as cash flow hedges are currently carried at cost. KCP&L and Strategic Energy report the revenue and expense associated with all energy contracts at the time the underlying physical transaction closes consistent with industry practice and the business philosophy of generating/purchasing and delivering physical power to customers.

Interest Rate Risk Great Plains Energy manages interest expense and short and long-term liquidity through a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly rated financial institutions may be used to achieve the desired combination. Using outstanding balances and annualized interest rates as of December 31, 2001, a hypothetical 10% increase in the interest rates associated with variable rate debt would have resulted in a $0.8 million decrease in pretax earnings for 2001. Additionally, interest rates impact the fair value of long-term debt. A change in interest rates would impact KCP&L to the extent it exercised its right to call any of its outstanding callable debt. At December 31, 2001, stated values approximate fair value.

Equity Price Risk KCP&L maintains trust funds, as required by the NRC, to fund certain costs of decommissioning its Wolf Creek nuclear power plant. KCP&L does not expect Wolf Creek decommissioning to start before 2025. As of December 31, 2001, these funds were invested primarily in domestic equity securities and fixed income securities and are reflected at fair value on the KCP&L's balance sheets. The mix of securities is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs; however the equity securities in the trusts are exposed to price fluctuations in equity markets, and the value of fixed rate fixed income securities are exposed to changes in interest rates. Investment performance and asset allocation are periodically reviewed. A hypothetical increase in interest rates resulting in a hypothetical 10% decrease in the value of the fixed income securities would have resulted in a $3.4 million reduction in the value of the decommissioning trust funds. A hypothetical 10% decrease in equity prices would have resulted in a $6.0 million reduction in the fair value of the equity securities as of December 31, 2001. KCP&L's exposure to equity price market risk associated with the decommissioning trust funds is in large part mitigated due to the fact that KCP&L is currently allowed to recover its decommissioning costs in its rates.

KLT Investments has affordable housing notes that require the greater of 15% of the outstanding note balances or the next annual installment to be held as cash, cash equivalents or marketable securities.

A hypothetical 10% decrease in market prices of the securities held as collateral would have resulted in a $1.2 million decrease in pretax earnings for 2001.

33

ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS GREAT PLAINS ENERGY Consolidated Statements of Income Year Ended December 31 2001 2000 1999 (thousands)

Operating Revenues Electric sales revenues $ 1,363,483 $ 1,063,804 $ 897,393 Gas sales revenue 15,754 48,297 20,814 Other revenues 82,681 3,767 3,275 Total 1,461,918 1,115,868 921,482 Operating Expenses Fuel 163,846 153,144 129,255 Purchased power 394,176 190,171 94,697 Gas purchased and production expenses 16,932 30,396 11,125 Other 323,663 249,926 220,534 Maintenance 77,802 74,466 62,589 Depreciation and depletion 158,771 132,378 123,269 (Gain) Loss on property 171,477 (99,118) 1,200 General taxes 98,060 92,228 93,051 Total 1,404,727 823,591 735,720 Operating income 57,191 292,277 185,762 Losses from equity investments (376) (19,441) (24,951)

Other income and expenses (29,440) (15,353) (7,382)

Interest charges 103,332 75,686 68.334 Income (loss) before income taxes, extraordinary item and cumulative effect of changes in accounting principles (75,957) 181,797 85,095 Income taxes (35,914) 53,166 3,180 Income (loss) before extraordinary item and cumulative effect (40,043) 128,631 81,915 Early extinguishment of debt, net of income taxes (Note 17) 15,872 -

Cumulative effect to January 1, 2000, of changes in accounting principles, net of income taxes (Note 3) - 30,073 Net income (loss) (24,171) 158,704 81,915 Preferred stock dividend requirements 1,647 1,649 3,733 Earnings (loss) available for common stock $ (25,818) $ 157,055 $ 78,182 Average number of common shares outstanding 61,864 61,864 61,898 Basic and diluted earnings (loss) per common share before extraordinary item and cumulative effect of changes in accounting principles $ (0.68) $ 2.05 $ 1.26 Early extinguishment of debt 0.26 -

Cumulative effect to January 1, 2000, of changes in accounting principles 0.49 Basic and diluted earnings (loss) per common share $ (0.42) $ 2.54 $ 1.26 Cash dividends per common share $ 1.66 $ 1.66 $ 1.66 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

34

GREAT PLAINS ENERGY Consolidated Balance Sheets At December 31 2001 2000 (thousands)

ASSETS Current Assets Cash and cash equivalents 29,034 $ 34,877 Receivables 152,114 115,356 Equity securities 18.597 Fuel inventories, at average cost 22,246 20,802 Materials and supplies, at average cost 50,696 46,402 Current income taxes 31,031 Deferred income taxes 5,061 737 Other 19,167 14,455 Total 309,349 251,226 Nonutility Property and Investments Affordable housing limited partnerships 81,136 98,129 Gas property and investments 43,385 47,654 Nuclear decommissioning trust fund 61,766 56,800 Other 64,519 81,624 Total 250,806 284,207 Utility Plant, at Original Cost Electric 4,332,464 3,832,655 Less-accumulated depreciation 1,793,786 1,645,450 Net utility plant in service 2,538,678 2,187,205 Construction work in progress 51,265 309,629 Nuclear fuel, net of amortization of $127,101 and $110,014 33,771 30,956 Total 2,623,714 2,527,790 Deferred Charges Regulatory assets 124,406 139,456 Prepaid pension costs 88,337 68,342 Goodwill 37,066 11,470 Other deferred charges 30,724 11,400 Total 280,533 230,668 Total $ 3,464,402 $ 3,293,891 LIABILITIES AND CAPITALIZATION Current Liabilities Notes payable $ 144,404 $

Commercial paper 62,000 55,600 Current maturities of long-term debt 238,767 93,645 EIRR bonds classified as current (Note 13) 177,500 177,500 Accounts payable 173,956 158,242 Accrued taxes 14,324 14,402 Accrued interest 13,262 12,553 Accrued payroll and vacations 26,422 28,257 Accrued refueling outage costs 12,979 1,890 Other 35,810 14,877 Total 899,424 556,966 Deferred Credits and Other Uabilities Deferred income taxes 594,704 590,220 Deferred investment tax credits 45,748 50,037 Accrued nuclear decommisioning costs 63,040 58,047 Other 114,085 63,860 Total 817,577 762,164 Capitalization (see statements) 1,747,401 1,974,761 Commitments and Contingencies (Note 6)

Total $ 3,464,402 $ 3,293,891 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

35

GREAT PLAINS ENERGY Consolidated Statements of Capitalization At December 31 2001 2000 (thousands)

Long-term Debt (excluding current maturities)

General Mortgage Bonds Medium-Term Notes due 2003-08, 7.28% and 7.18% weighted-average rate $ 179,000 $ 206,000 2.71%* and 5.59%** EIRR bonds due 2012-23 158,768 158,768 EIRR bonds classified as current liabilities (Note 13) (31,000) (31,000)

Senior Notes 7.125% due 2005 250,000 250,000 6.500% due 2011 150,000 Unamortized discount (660) (550)

Medium-Term Notes 6.69%** due 2002 200,000 EIRR bonds 3.25%* and 5.55%** Series A & B due 2015 106,500 106,500 3.25%* and 4.35%** Series D due 2017 40,000 40,000 EIRR bonds classified as current liabilities (Note 13) (146,500) (146,500) 4.50%* and 4.50%** Series C due 2017 50,000 50,000 Subsidiary Obligations R.S. Andrews Enterprises, Inc. long-term debt 8.14% weighted-average rate due 2003-07 2,832 Affordable Housing Notes 8.16% and 8.29% weighted-average rate due 2003-08 19,746 31,129 Total 778,686 864,347 Company-obligated Mandatorily Redeemable Preferred Securities of a trust holding solely KCPL Subordinated Debentures 150,000 150,000 Cumulative Preferred Stock

$100 Par Value 3.80% - 100,000 shares issued 10,000 10,000 4.50% - 100,000 shares issued 10,000 10,000 4.20% - 70,000 shares issued 7,000 7,000 4.35% - 120,000 shares issued 12,000 12,000

$100 Par Value - Redeemable 4.00% 62 Total 39,000 39,062 Common Stock Equity Common stock-150,000,000 shares authorized without par value 61,908,726 shares issued, stated value 449,697 449,697 Capital stock premium and expense (1,656) (1,666)

Retained earnings (see statements) 344,815 473,321 Accumulated other comprehensive loss Loss on derivative hedging instruments (12,110)

Minimum pension liability (1,031)

Total 779,715 921,352 Total $ 1,747,401 $ 1,974,761 Variable rate securities, weighted-average rate as of December 31, 2001 Variable rate securities, weighted-average rate as of December 31, 2000 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

36

GREAT PLAINS ENERGY Consolidated Statements of Cash Flows Year Ended December 31 2001 2000 1999 (thousands)

Cash Flows from Operating Activities Net income (loss) $ (24,171) $ 158,704 $ 81,915 Adjustments to reconcile income to net cash from operating activities:

Early extinguishment of debt, net of income taxes (15,872)

Cumulative effect of changes in accounting principles, net of income taxes (30,073)

Depreciation and depletion 158,771 132,378 123,269 Amortization of:

Nuclear fuel 17,087 15,227 15,782 Other 16,755 11,940 12,263 Deferred income taxes (net) (301) (29,542) (26,784)

Investment tax credit amortization (4,289) (4,296) (4,453)

Fuel contract settlement (13,391)

Loss from equity investments 376 19,441 24,951 (Gain) Loss on property 171,477 (99,118) 1,200 Kansas rate refund accrual (14,200)

Allowance for equity funds used during construction (3,616) (4,001) (2,657)

Other operating activities (Note 2) (37,356) 23,213 (37,786)

Net cash from operating activities 278,861 193,873 160,109 Cash Flows from Investing Activities Utility capital expenditures (262,030) (401,041) (180,687)

Allowance for borrowed funds used during construction (9,197) (12,184) (3,378)

Purchases of investments (46,105) (55,531) (35,072)

Purchases of nonutility property (66,119) (25,466) (55,792)

Proceeds from sale of assets 66,460 225,958 39,617 Hawthorn No. 5 partial insurance recovery 30,000 50,000 80,000 Loan to DTI prior to majority ownership (94,000)

Other investing activities 10,306 18,967 (10,316)

Net cash from investing activities (370,685) (199,297) (165,628)

Cash Flows from Financing Activities Issuance of long-term debt 249,597 500,445 10,889 Repayment of long-term debt (193,145) (179,858) (109,060)

Net change in short-term borrowings 140,747 (183,099) 228,699 Dividends paid (104,335) (104,335) (106,662)

Redemption of preferred stock - (50,000)

Other financing activities (6,883) (5,925) 1,513 Net cash from financing activities 85,981 27,228 (24,621)

Net Change in Cash and Cash Equivalents (5,843) 21,804 (30,140)

Cash and Cash Equivalents at Beginning of Year 34,877 13,073 43,213 Cash and Cash Equivalents at End of Year $ 29,034 $ 34,877 $ 13,073 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

37

GREAT PLAINS ENERGY Consolidated Statements of Comprehensive Income Year Ended December 31 2001 2000 1999 (thousands)

Net Income (Loss) $ (24,171) $ 158,704 $ 81,915 Other comprehensive loss:

Unrealized loss on securities available for sale - (3,778)

Income tax benefit - 1,367 Net unrealized loss on securities available for sale - (2,411)

Loss on derivative hedging instruments (43,706) -

Income tax benefit 18,136 Net loss on derivative hedging instruments (25,570)

Minimum pension liability (1,691)

Income tax benefit 660 Net minimum pension liability (1,031)

Reclassification to revenues and expenses, net of tax (3,983) 2,337 Comprehensive income before cumulative effect of a change in accounting principles, net of income taxes (54,755) 161,041 79,504 Cumulative effect to January 1, 2001, of a change in accounting principles, net of income taxes 17,443 Comprehensive Income (Loss) $ (37,312) $ 161,041 $ 79,504 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

GREAT PLAINS ENERGY Consolidated Statements of Retained Earnings Year Ended December 31 2001 2000 1999 (thousands)

Beginning Balance $ 473,321 $ 418,952 $ 443,699 Net Income (Loss) (24,171) 158,704 81,915 449,150 577,656 525,614 Dividends Declared Preferred stock - at required rates 1,647 1,649 3,911 Common stock 102,688 102,686 102,751 Ending Balance $ 344,815 $ 473,321 $ 418,952 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

38

KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Income Year Ended December 31 2001 2000 1999 (thousands)

Operating Revenues Electric sales revenues $ 1,256,121 $ 1,063,804 $ 897,393 Other revenues 94,773 52,064 24,089 Total 1,350,894 1,115,868 921,482 Operating Expenses Fuel 163,846 153,144 129,255 Purchased power 304,862 190,171 94,697 Gas purchased and production expenses 17,454 30,396 11,125 Other 304,704 249,926 220,534 Maintenance 77,172 74,466 62,589 Depreciation and depletion 152,893 132,378 123,269 (Gain) Loss on property (22,026) (99,118) 1,200 General taxes 97,288 92,228 93,051 Total 1,096,193 823,591 735,720 Operating income 254,701 292,277 185,762 Losses from equity investments (501) (19,441) (24,951)

Other income and expenses (22,440) (15,353) (7,382)

Interest charges 97,653 75,686 68,334 Income before income taxes, extraordinary item and cumulative effect of changes in accounting principles 134,107 181,797 85,095 Income taxes 30,288 53,166 3,180 Income before extraordinary item and cumulative effect of changes in accounting principles 103,819 128,631 81,915 Early extinguishment of debt, net of income taxes 15,872 Cumulative effect to January 1, 2000, of changes in accounting principles, net of income taxes (Note 3) - 30,073 Net income 119,691 158,704 81,915 Preferred stock dividend requirements 1,098 1,649 3,733 Earnings available for common stock $ 118,593 $ 157,055 $ 78,182 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

39

KANSAS CITY POWER & LIGHT COMPANY Consolidated Balance Sheets At December 31 2001 2000 (thousands)

ASSETS Current Assets Cash and cash equivalents $ 962 $ 34,877 Receivables 62,511 115,356 Equity securities - 18,597 Fuel inventories, at average cost 22,246 20,802 Materials and supplies, at average cost 50,696 46,402 Deferred income taxes 5,061 737 Other 11,484 14,455 Total 152,960 251,226 Nonutility Property and Investments Affordable housing limited partnerships - 98,129 Gas property and investments - 47,654 Nuclear decommissioning trust fund 61,766 56,800 Other 40,797 81,624 Total 102,563 284,207 Utility Plant, at Original Cost Electric 4,332,464 3,832,655 Less-accumulated depreciation 1,793,786 1,645,450 Net utility plant in service 2,538,678 2,187,205 Construction work in progress 51,265 309,629 Nuclear fuel, net of amortization of $127,101 and $110,014 33,771 30,956 Total 2,623,714 2,527,790 Deferred Charges Regulatory assets 124,406 139,456 Prepaid pension costs 88,337 68,342 Goodwill 22,952 11,470 Other deferred charges 30,724 11,400 Total 266,419 230,668 Total $ 3,145,656 $ 3,293,891 LIABILITIES AND CAPITALIZATION Current Liabilities Notes payable $ 20,404 $

Commercial paper 62,000 55,600 Current maturities of long-term debt 227,383 93,645 EIRR bonds classified as current (Note 13) 177,500 177,500 Accounts payable 113,029 158,242 Accrued taxes 15,895 14,402 Accrued interest 11,327 12,553 Accrued payroll and vacations 22,581 28,257 Accrued refueling outage costs 12,979 1,890 Other 14,562 14,877 Total 677,660 556,966 Deferred Credits and Other Liabilities Deferred income taxes 630,699 590,220 Deferred investment tax credits 45,748 50,037 Accrued nuclear decommisioning costs 63,040 58,047 Other 75,186 63,860 Total 814,673 762,164 Capitalization (see statements) 1,653,323 1,974,761 Commitments and Contingencies (Note 6)

Total $ 3,145,656 $ 3,293,891 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

40

KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Capitalization At December 31 2001 2000 (thousands)

Long-term Debt (excluding current maturities)

General Mortgage Bonds Medium-Term Notes due 2003-08, 7.28% and 7.18% weighted-average rate $ 179,000 $ 206,000 2.71%* and 5.59%** EIRR bonds due 2012-23 158,768 158,768 EIRR bonds classified as current liabilities (Note 13) (31,000) (31,000)

Senior Notes 7.125% due 2005 250,000 250,000 6.500% due 2011 150,000 Unamortized discount (660) (550)

Medium-Term Notes 6.69%** due 2002 - 200,000 EIRR bonds 3.25%* and 5.55%** Series A & B due 2015 106,500 106,500 3.25%* and 4.35%** Series D due 2017 40,000 40,000 EIRR bonds classified as current liabilities (Note 13) (146,500) (146,500) 4.50%* and 4.50%** Series C due 2017 50,000 50,000 Subsidiary Obligations R.S. Andrews Enterprises, Inc. long-term debt 8.14% weighted-average rate due 2003-07 2,832 Affordable Housing Notes 8.29% weighted-average rate due 2003-08 31,129 Total 758,940 864,347 Company-obligated Mandatorily Redeemable Preferred Securities of a trust holding solely KCPL Subordinated Debentures 150,000 150,000 Cumulative Preferred Stock

$100 Par Value 3.80% - 100,000 shares issued - 10,000 4.50% - 100,000 shares issued 10,000 4.20% - 70,000 shares issued 7,000 4.35% - 120,000 shares issued 12,000

$100 Par Value - Redeemable 4.00% 62 Total 39,062 Common Stock Equity Common stock-150,000,000 shares authorized without par value 61,908,726 shares issued, stated value - 449,697 Common stock-1,000 shares authorized without par value 1 share issued, stated value ** 487,041 Capital stock premium and expense 39,000 (1,666)

Retained earnings (see statements) 219,524 473,321 Accumulated other comprehensive loss Loss on derivative hedging instruments (151)

Minimum pension liability (1,031)

Total 744,383 921,352 Total $ 1,653,323 $ 1,974,761 Variable rate securities, weighted-average rate as of December 31, 2001 Variable rate securities, weighted-average rate as of December 31, 2000 "Reflects common stock value held by Great Plains Energy resulting from the exchange of KCP&L common stock to Great Plains Energy common stock and the transfer of $39 million of preferred stock and the associated stock premium and discount to Great Plains Energy due to the October 1, 2001 formation of the holding company The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

41

KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Cash Flows Year Ended December 31 2001 2000 1999 (thousands)

Cash Flows from Operating Activities Net income $ 119,691 $ 158,704 $ 81,915 Adjustments to reconcile income to net cash from operating activities:

Early extinguishment of debt, net of income taxes (15,872)

Cumulative effect of changes in accounting principles, net of income taxes (30,073)

Depreciation and depletion 152,893 132,378 123,269 Amortization of:

Nuclear fuel 17,087 15,227 15,782 Other 15,717 11,940 12,263 Deferred income taxes (net) 12,867 (29,542) (26,784)

Investment tax credit amortization (4,289) (4,296) (4,453)

Fuel contract settlement (13,391)

Loss from equity investments 501 19,441 24,951 (Gain) Loss on property (22,026) (99,118) 1,200 Kansas rate refund accrual (14,200)

Allowance for equity funds used during construction (3,616) (4,001) (2,657)

Other operating activities (Note 2) (35,322) 23,213 (37,786)

Net cash from operating activities 237.631 193.873 160.109 Cash Flows from Investing Activities Utility capital expenditures (262,030) (401,041) (180,687)

Allowance for borrowed funds used during construction (9,197) (12,184) (3,378)

Purchases of investments (41,548) (55,531) (35,072)

Purchases of nonutility property (49,254) (25,466) (55,792)

Proceeds from sale of assets 64,072 225,958 39,617 Hawthorn No. 5 partial insurance recovery 30,000 50,000 80,000 Loan to DTI prior to majority ownership (94,000)

Other investing activities 8,087 18,967 (10,316)

Net cash from investing activities (353,870) (199,297) (165,628)

Cash Flows from Financing Activities Issuance of long-term debt 249,597 500,445 10,889 Repayment of long-term debt (93,099) (179,858) (109,060)

Net change in short-term borrowings 14,524 (183,099) 228,699 Dividends paid (78,246) (104,335) (106,662)

Dividends paid to Great Plains Energy (25,677)

Cash of KLT Inc. and GPP dividended to Great Plains Energy (19,115)

Redemption of preferred stock - (50,000)

Equity contribution from Great Plains Energy 39,000 Other financing activities (4,660) (5,925) 1,513 Net cash from financing activities 82,324 27,228 (24,621)

Net Change in Cash and Cash Equivalents (33,915) 21,804 (30,140)

Cash and Cash Equivalents at Beginning of Year 34,877 13,073 43,213 Cash and Cash Equivalents at End of Year $ 962 $ 34,877 $ 13,073 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

42

KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Comprehensive Income Year Ended December 31 2001 2000 1999 (thousands)

Net income $ 119,691 $ 158,704 $ 81,915 Other comprehensive loss:

Unrealized loss on securities available for sale - - (3,778)

Income tax benefit - 1,367 Net unrealized loss on securities available for sale - (2,411)

Loss on derivative hedging instruments (39,952)

Income tax benefit 16,590 Net loss on derivative hedging instruments (23,362)

Minimum pension liability (1,691)

Income tax benefit 660 Net minimum pension liability (1,031)

Reclassification to revenues and expenses, net of tax (7,687) 2,337 Comprehensive income before cumulative effect of a change in accounting principles, net of income taxes 87,611 161,041 79,504 Cumulative effect to January 1, 2001, of a change in accounting principles, net of income taxes 17,443 Comprehensive Income $ 105,054 $ 161,041 $ 79,504 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Retained Earnings Year Ended December 31 2001 2000 1999 (thousands)

Beginning Balance $ 473,321 $ 418,952 $ 443,699 Net Income 119,691 158,704 81,915 593,012 577,656 525,614 Dividends Declared Preferred stock - at required rates 824 1,649 3,911 Common stock 77,011 102,686 102,751 Common stock held by Great Plains Energy 25,677 Equity dividend of KLT Inc. and GPP to Great Plains Energy 269,976 Ending Balance $ 219,524 $ 473,321 $ 418,952 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

43

GREAT PLAINS ENERGY INCORPORATED KANSAS CITY POWER & LIGHT COMPANY Notes to Consolidated Financial Statements The notes to consolidated financial statements that follow are a combined presentation for Great Plains Energy and consolidated KCP&L, both registrants under this filing. Effective October 1, 2001, KCP&L completed its formation of the holding company and became a wholly owned subsidiary of Great Plains Energy. Additionally, KCP&L dividended to Great Plains Energy, its ownership in KLT Inc. and GPP.

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Great Plains Energy (The Company)

Great Plains Energy is a registered holding company under the PUHCA. Effective October 1, 2001, all outstanding KCP&L shares were exchanged one for one for shares of Great Plains Energy. The Great Plains Energy trading symbol "GXP" replaced the KCP&L trading symbol "KLT" on the New York Stock Exchange.

Effective October 1, 2001, KCP&L dividended its 100% ownership of KLT Inc. and GPP to Great Plains Energy. As a result, those companies are subsidiaries of Great Plains Energy and are not included in consolidated KCP&L's results of operations and financial position since that date.

Great Plains Energy's consolidated financial statements include consolidated KCP&L, KLT Inc. and GPP. The presentation of prior years results of operations and financial position for Great Plains Energy is provided for comparative purposes and is identical to the results of operations and financial position for consolidated KCP&L, prior to formation of the holding company, presented for those years.

Intercompany balances and transactions have been eliminated in consolidation.

ConsolidatedKCP&L KCP&L's consolidated financial statements include its wholly owned subsidiary HSS. In addition, KCP&L's consolidated results of operations include KLT Inc. and GPP for all periods prior to the October 1, 2001, formation of the holding company. KCP&L is a medium-sized, integrated electric utility with more than 474,000 customers at year-end in western Missouri and eastern Kansas. About 95% of KCP&L's retail electric revenues are from the Kansas City metropolitan area, an agribusiness center and major regional center for wholesale, retail and service companies. About 60% of KCP&L's 2001 retail megawatt-hour sales were to Missouri customers, the remainder to Kansas customers.

The rates charged by KCP&L are approved by the FERC and the state utility commissions, the MPSC and the KCC. The FERC regulates wholesale electricity operations and transmission rates and the state commissions regulate retail generation and distribution rates.

HSS, a wholly owned, unregulated subsidiary, owns 72% of RSAE, a consumer services company in Atlanta, Georgia. In 2001, HSS acquired majority ownership in RSAE and changed the method of accounting for RSAE from the equity method to consolidation. In addition, HSS owns all the stock of Worry Free Service, Inc. (Worry Free). Worry Free assists residential customers in obtaining financing primarily for heating and air conditioning equipment.

KL T Inc. and GPP KLT Inc., formed in 1992, is an investment company focusing on energy-related ventures that are unregulated with high growth potential. KLT Inc.'s major holdings consist of Strategic Energy, KLT Gas, and investments in affordable housing limited partnerships. GPP, formed in 2001, will be a competitive generator that will sell to the wholesale market.

44

The preparation of Great Plains Energy and KCP&L's consolidated financial statements conforms with GAAP. Additionally, KCP&L's consolidated financial statements conform with the standards set forth by the FERC. GAAP requires in certain instances the use of estimates and assumptions that affect amounts reported in the financial statements along with the disclosure of commitments and contingencies at the date of the financial statements. Actual results could differ from those estimates.

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

Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

CurrentAssets and Current Liabilities-The stated value of financial instruments classified as current assets or liabilities approximates fair value due to the short-term nature of the instruments. At December 31, 2000, the equity securities were considered trading securities and therefore were recorded at fair value based on quoted market prices.

Investments and Nonutility Property-KCP&L's nuclear decommissioning trust fund is recorded at fair value. Fair value is based on quoted market prices of the investments held by the fund. The fair value of KLT Investments' affordable housing limited partnership total portfolio, based on the discounted cash flows generated by tax credits, tax deductions and sale of properties, approximates book value.

The fair values of other various investments are not readily determinable and the investments are therefore stated at cost.

Long-term debt-The incremental borrowing rate for similar debt was used to determine fair value if quoted market prices were not available. The stated values approximate fair market values.

Investments in Affordable Housing Limited Partnerships At December 31, 2001, KLT Investments had $81.1 million in affordable housing limited partnerships.

About 68% of these investments were recorded at cost; the equity method was used for the remainder.

Tax expense is reduced in the year tax credits are generated. The investments generate future cash flows from tax credits and tax losses of the partnerships. The investments also generate cash flows from the sales of the properties (estimated residual value). For most investments, tax credits are received over ten years. A change in accounting principle relating to investments made after May 19, 1995, requires the use of the equity method when a company owns more than 5% in a limited partnership investment. Of the investments recorded at cost, $52.9 million exceed this 5% level but were made before May 19, 1995.

On a quarterly basis, KLT Investments compares the cost of those 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 partnerships by $13.5 million in 2001 and $2.4 million in 2000. Projected annual reductions of the book cost for the years 2002 through 2006 total $9 million, $12 million, $8 million, $7 million and $6 million, respectively. Even after these reductions, earnings from affordable housing are expected to be positive for the next five years.

These projections are based on the latest information available but the ultimate amount and timing of actual reductions made could be significantly different from the above estimates.

45

Securities Available for Sale In 2000, CellNet completed a sale of its assets to a third party causing KLT's investment in CellNet to become worthless. Accordingly, in March 2000, KLT Inc. realized losses on its investment in CellNet of

$4.8 million before taxes ($0.05 per share). At December 31, 1999, $3.8 million before taxes of this loss had been reported as an unrealized loss in the Consolidated Statement of Comprehensive Income. These pre-tax amounts were reduced by taxes of $1.7 million in 2000 and $1.4 million in 1999.

Prior to realizing the losses, the investment in CellNet had been accounted for as securities available for sale and adjusted to market value, with unrealized gains or (losses) reported as a separate component of comprehensive income. The cost of these securities available for sale that KLT Investments II held as of December 31, 1999, was $4.8 million. Accumulated net unrealized losses were $2.3 million at December 31, 1999.

Utility Plant KCP&L's utility plant is stated at historical costs of construction. These costs include taxes, an allowance for funds used during construction (AFDC) and payroll-related costs, including pensions and other fringe benefits. Replacements, improvements and additions to units of property are capitalized.

Repairs of property and replacements of items not considered to be units of property are expensed as incurred (except as discussed under Wolf Creek Refueling Outage Costs). When property units are retired or otherwise disposed, the original cost, net of salvage and removal, is charged to accumulated depreciation.

Through December 31, 2001, KCP&L received $160 million in insurance recoveries related to property destroyed in the February 17, 1999, explosion at the Hawthorn No. 5 generating unit. Recoveries received have been recorded as an increase in accumulated depreciation.

AFDC represents the cost of borrowed funds and a return on equity funds used to finance construction projects. AFDC on borrowed funds reduces interest charges. AFDC on equity funds is included as a noncash item in Other income and expenses. The rates used to compute gross AFDC are compounded semi-annually and averaged 6.8% for 2001, 7.5% for 2000, and 7.7% for 1999.

Depreciation is computed using the straight-line method over the estimated lives of depreciable property based on rates approved by state regulatory authorities. Annual depreciation rates average about 3%.

Natural Gas Properties KLT Gas follows the full cost method of accounting for its natural gas properties. Under the full cost method, all costs of acquisition, exploration and development of natural gas reserves are capitalized regardless of success. Any excess of book value plus costs to develop over the present value (10%

discount rate) of estimated future net revenues (at year-end prices) from the natural gas reserves would be expensed.

Natural gas property and equipment included in the gas property and investments totaled $39.9 million, net of accumulated depreciation of $5.0 million, in 2001 and $18.1 million, net of accumulated depreciation of $1.1 million, in 2000.

Depletion, depreciation and amortization of these assets are calculated using the units of production method. The depletion per mmBtu was $1.35 for 2001, $0.63 for 2000 and $0.42 for 1999. Unproved gas properties are not amortized but are assessed for impairment either individually or on an aggregated basis. All natural gas property interests owned by KLT Gas are located in the United States.

46

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

Nuclear Plant Decommissioning Costs The MPSC and the KCC require KCP&L and the other owners of Wolf Creek to submit an updated decommissioning cost study every three years. The following table shows the decommissioning cost estimates and the escalation rates and earnings assumptions approved by the MPSC and the KCC in 2000. The decommissioning cost estimates are based on the immediate dismantlement method and include the costs of decontamination, dismantlement and site restoration. KCP&L does not expect plant decommissioning to start before 2025.

KCC MPSC Future cost of decommissioning:

Total Station $1.2 billion $1.5 billion 47% share $554 million $694 million Current cost of decommissioning (in 1999 dollars):

Total Station $470 million $470 million 47% share $221 million $221 million Annual escalation factor 3.60% 4.50%

Annual return on trust assets 6.93% 7.66%

KCP&L contributes about $3 million annually to a tax-qualified trust fund to be used to decommission Wolf Creek. These costs are charged to other operating expenses and recovered in billings to customers. These funding levels assume a certain return on trust assets. If the actual return on trust assets is below the anticipated level, KCP&L believes a rate increase will be allowed ensuring full recovery of decommissioning costs over the remaining life of the unit.

The trust fund balance, including reinvested earnings, was $61.8 million at December 31, 2001, and

$56.8 million at December 31, 2000. The related liabilities for decommissioning are included in Deferred Credits and Other Liabilities - Other.

In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No.

143 is effective for fiscal years beginning after June 15, 2002. Under the new pronouncement, an entity must recognize as a liability the fair value of legal obligations associated with the retirement of long lived assets. Management currently believes that nuclear decommissioning cost is the only significant legal retirement obligation.

After adoption of SFAS No. 143 in 2003, the asset retirement obligation for nuclear decommissioning would be recorded as a liability, currently estimated to be less than $100 million, with offsets to net utility plant and a regulatory asset. The amount recorded to the electric plant accounts will be depreciated over the remaining life of Wolf Creek. The associated liability will be increased for the passage of time (accretion) to operating expense. Trust fund income and losses from the external decommissioning trusts would be reported as investment income or loss. KCP&L does not anticipate results of operations to be significantly affected by the adoption of SFAS No. 143 as long as KCP&L is regulated. Regulatory assets or liabilities would be recorded when SFAS No. 143 is first adopted and then yearly for the difference between decommissioning expense determined by regulation and amounts required by SFAS No. 143.

47

Nuclear Fuel KCP&L amortizes nuclear fuel to fuel expense based on the quantity of heat produced during generation of electricity. Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent disposal of spent nuclear fuel. For the future disposal of spent nuclear fuel, KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered and sold. These disposal costs are charged to fuel expense.

A permanent disposal site will not be available for the industry until 2010 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel first from the owners with the oldest spent fuel. As a result, disposal services for Wolf Creek will not be available before 2016. Wolf Creek has an on-site, temporary storage facility for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025.

Regulatory Assets SFAS No. 71, "Accounting for Certain Types of Regulation", applies to regulated entities whose rates are designed to recover the costs of providing service. Under this statement, KCP&L defers on the balance sheet items when allowed by a commission's rate order or when it is probable, based on regulatory past practices, that future rates will recover the amortization of the deferred costs. If SFAS No. 71 were not applicable, the unamortized balance of $124.4 million of KCP&L's regulatory assets, net of the related tax benefit, would be written off.

Amortization ending December 31, 2001 period Regulatory Assets (millions)

Recoverable taxes $108.0 Coal contract termination costs 6.4 2003 Decommission and decontaminate federal uranium enrichment facilities 3.9 2007 Premium on redeemed debt 5.1 2023 Other 1.0 2006 Total Regulatory Assets $ 124.4 Revenue Recognition KCP&L and Strategic Energy use cycle billing and accrue estimated unbilled revenue at the end of each month. When Strategic Energy is arranging supply for retail customers, excess supply in certain time periods may occur. To reduce the total cost of providing energy to its retail customers, Strategic Energy sells the excess retail supply. The sale of excess retail supply is recorded in the consolidated statements of income as a reduction of purchased power. The gross amount of such excess retail supply sales was approximately $95.6 million in 2001, $29.5 million in 2000 and $7.2 million in 1999.

KLT Gas records natural gas sales revenues based on the amount of gas sold to purchasers on its behalf.

Property Gains and Losses Net gains and losses from the sales of assets, businesses, and net asset impairments are recorded in operating expenses. See Note 17 for additional information regarding the net impairment of DTI assets.

Asset Impairments Long-lived assets, including intangibles, are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. To the extent that there is impairment, analysis is performed based on several criteria, including but not 48

limited to revenue trends, discounted operating cash flows and other operating factors, to determine the impairment amount.

Income Taxes The balance sheet includes deferred income taxes for all temporary differences between the tax basis of an asset or liability and that reported in the financial statements. These deferred tax assets and liabilities are determined by using the tax rates scheduled by the tax law to be in effect when the differences reverse. A tax valuation allowance is recorded when it is more likely than not that a deferred tax asset will not be realized.

Regulatory Asset - Recoverable taxes mainly reflects the future revenue requirements necessary to recover the tax benefits of existing temporary differences previously passed through to KCP&L customers. KCP&L records operating income tax expense based on ratemaking principles. However, if the method used for the balance sheet were reflected in the income statement, net income would remain the same.

Tax credits are recognized in the year generated except for certain KCP&L investment tax credits that have been deferred and amortized over the remaining service lives of the related properties.

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

Basic and Diluted Earnings per Common Share Calculation There is no dilutive effect on Great Plains Energy's earnings per share from other securities in 2001, 2000 or 1999. To determine earnings per common share, preferred stock dividend requirements are subtracted from both income before extraordinary item and cumulative effect of changes in accounting principles and net income before dividing by average number of common shares outstanding. The earnings per share impact of the extraordinary item and the cumulative effect of changes in accounting principles is determined by dividing each by the average number of common shares outstanding.

Earnings per share for KCP&L and Great Plains Energy are the same for the years 2000 and 1999, prior to the formation of the holding company.

2. SUPPLEMENTAL CASH FLOW INFORMATION Great Plains Energy Other OperatingActivities 2001 2000 1999 Cash flows affected by changes in: (thousands)

Receivables $ (32,680) $ (42,565) $ (1,417)

Fuel inventories (1,444) 1,787 (3,840)

Materials and supplies (4,294) (113) (926)

Accounts payable 9,495 66,765 6,545 Accrued taxes (31,133) 13,430 (14,653)

Accrued interest 667 (2,865) (7,962)

Wolf Creek refueling outage accrual 11,089 (5,166) (5,259)

Pension and postretirement benefit obligations (22,577) (12,653) 1,939 Other 33,521 4,593 (12,213)

Total other operating activities $ (37,356) $ 23,213 $ (37,786)

Cash paid during the period:

Interest $ 84,907 $ 76,395 $ 74,520 Income taxes $ 21,614 $ 80,445 $ 52,300 49

During the first quarter of 2001, because KLT Telecom increased its equity ownership in DTI to a majority ownership, DTI was consolidated. On December 31, 2001, DTI filed voluntary petitions in Bankruptcy Court. See Note 17 for details regarding the bankruptcy. Beginning February 8, 2001, through December 31, 2001, prior to the bankruptcy, DTI's operations were included in KLT Telecom's results of operations.

The table below reflects a reconciliation of DTI's effect on Great Plains Energy's consolidated statement of cash flows for the year ended December 31, 2001, to the cash invested in DTI during 2001.

Cash Flows from Operating Activities (thousands)

Amounts included in net income (loss) $(248,437)

Depreciation 17,907 Goodwill amortization 2,481 Loss on property (net impairment) 195,835 Other operating activities Accretion of Senior Discount Notes and amortization of the discount 16,364 Other 1,719 DTI adjustment to operating activities 234,306 Net cash from operating activities $ (14,131)

Cash Flows from Investing Activities Purchase of additional ownership in DTI (39,855)

Purchase of nonutility property (33,648)

Loans to DTI prior to consolidation (94,000)

Other investing activities 3,002 DTI effect on cash from investing activities (164,501)

Cash Flows from Financing Activities DTI effect on cash from financing activities (2,223)

Cash flows from DTI investment $(180,855)

Cash invested in DTI Loan to DTI Holdings $ (94,000)

Operating loans to Digital Teleport, Inc. (47,000)

Purchase of additional ownership in DTI (39,855)

Cash used for DTI investment $(180,855) 50

ConsolidatedKCP&L Other OperatingActivities 2001 2000 1999 Cash flows affected by changes in: (thousands)

Receivables $ (43,604) $(42,565) $ (1,417)

Fuel inventories (1,444) 1,787 (3,840)

Materials and supplies (4,294) (113) (926)

Accounts payable (14,878) 66,765 6,545 Accrued taxes (1,995) 13,430 (14,653)

Accrued interest 610 (2,865) (7,962)

Wolf Creek refueling outage accrual 11,089 (5,166) (5,259)

Pension and postretirement benefit obligations (22,577) (12,653) 1,939 Other 41,771 4,593 (12,213)

Total other operating activities $ (35,322) $ 23,213 $ (37,786)

Cash paid during the period:

Interest $ 82,867 $ 76,395 $ 74,520 Income taxes $ 21,470 $ 80,445 $ 52,300 As described in note 1, KCP&L dividended its ownership in KLT Inc. and GPP to Great Plains Energy on October 1, 2001. The effect of this transaction on KCP&L's consolidated statement of cash flows for the year ended December 31, 2001, is summarized in the table that follows.

Effect of dividend to Great Plains Energy: October 1, 2001 (thousands)

Assets Cash $ 19,115 Equity securities 283 Receivables 101,539 Nonutility property and investments 529,121 Goodwill 75,534 Other assets 8,542 Total assets $ 734,134 Liabilities and Accumulated Other Comprehensive Income Notes payable $ 3,077 Accounts payable 67,853 Accrued taxes (1,050)

Accrued interest 1,878 Deferred income taxes (23,868)

Deferred telecommunications revenue 45,595 Other liabilities and deferred credits 54,340 Long-term debt 329,788 Accumulated other comprehensive income (13,455)

Total liabilities and accumulated other comprehensive income 464.158 I

Equity dividend of KLT Inc. and GPP to Great Plains Energy $ 269,976 51

During the first quarter of 2001, KLT Telecom increased its equity ownership in DTI to a majority ownership and HSS increased its equity ownership in RSAE to a majority ownership. The effect of these transactions is summarized in the tables that follow. The initial consolidation of DTI (February 8, 2001) and RSAE (January 1, 2001) are not reflected in KCP&L's consolidated statement of cash flows for the year ended December 31, 2001.

DTI RSAE (thousands)

Cash paid to obtain majority ownership $ (39,855) $ (560)

Subsidiary cash 4,557 1,053 Purchase of DTI and RSAE, net of cash received $ (35,298) $ 493 Initial consolidation of subsidiaries:

Assets Cash $ 4,557 $ 1,053 Receivables 1,012 4,078 Other nonutility property and investments 363,825 6,267 Goodwill 62,974 24,496 Other assets 5,143 3,919 Eliminate equity investment (67,660) (7,200)

Total assets $369,851 $ 32,613 Liabilities Notes payable $ 5,300 $ 10,057 Accounts payable 31,299 6,219 Accrued taxes 2,414 24 Deferred income taxes 7,437 Other liabilities and deferred credits 46,531 13,418 Loan from KLT Telecom (a) 94,000 Long-term debt 182,870 2,895 Total liabilities $369,851 $ 32,613 Maj KLT Telecom provided a $94 million loan to DTI for the completion of the tender offer of 50.4 percent of DTI's Senior Discount Notes prior to increasing its DTI investment to a majority ownership.

Sales of KLT Gas properties KLT Gas sold producing natural gas properties to Evergreen Resources, Inc. (Evergreen) and Barrett Resources Corporation during 2000. The transactions are summarized in the table below.

2000 (thousands)

Cash proceeds $125,958 Preferred stock redeemed (a) 100,000 Total cash proceeds 225,958 Equity securities 10,000 Receivable 1,243 Total proceeds 237,201 Cost basis in property sold (87,785)

Accounts payable (b) (23,168)

Other assets and liabilities (b) (15,670)

Gain on sale before income tax 110,578 Income tax (42,606)

Gain on sale, net of income tax $ 67,972 ta) The preferred stock received in September 2000 was redeemed in December 2000.

(b) Includes $7.9 million of incentive compensation.

As part of the sales transactions, KLT Gas received additional Evergreen shares valued at $4 million in December 2000 because of the increase in natural gas futures. The Evergreen common stock was considered a trading security and recorded at fair value at December 31, 2000.

52

3. PENSION PLANS AND OTHER EMPLOYEE BENEFITS Changes in Pension Accounting Principles Effective January 1, 2000, KCP&L changed its methods of amortizing unrecognized net gains and losses and determination of expected return related to its accounting for pension expense. These changes were made to reflect more timely in pension expense the gains and losses incurred by the pension funds.

At the time KCP&L originally adopted the standards governing accounting for pensions, it chose the following accounting methods that would minimize fluctuations in pension expense:

"* Recognized gains and losses if, as of the beginning of the year, the unrecognized net gain or loss exceeded 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets. If amortization was required, amortization was the excess divided by the average remaining service period, approximately 15 years, of active employees expected to receive benefits under the plan. This method resulted in minimal gains being amortized.

"* Determined the expected return by multiplying the long-term rate of return times the market-related value. KCP&L determined market-related value by recognizing changes in fair value of plan assets over a five-year period.

KCP&L has changed the above accounting methods to the following:

"* Recognize gains and losses by amortizing over a five-year period the rolling five-year average of unamortized gains and losses.

"* Determine the expected return by multiplying the long-term rate of return times the fair value of plan assets.

Adoption of the new methods of accounting for pensions has led and will continue to lead to greater fluctuations in pension expense in the future. The following table details the effects of the adoption of the new methods of accounting for pensions.

Changes in Method of Accounting for Pensions (a)

Amortization of Gains and Expected Net Losses Return Total Reductions(b) Total (millions except per share amounts)

Cumulative effect of change in method of accounting:

Income $21.4 $13.6 $35.0 $ (4.9) $30.1 Basic and diluted earnings per common share $ 0.35 $ 0.22 $ 0.57 $ (0.08) $ 0.49 Year 2000 earnings effect of change in method of accounting:

Income $ 4.1 $ 2.0 $ 6.1 $ (1.1) $ 5.0 Basic and diluted earnings per common share $ 0.07 $ 0.03 $0.10 $(0.02) $0.08 Prior year's earnings effect of change in method of accounting if the change had been made January 1, 1999:

1999 Income $ 4.4 $ 1.1 $ 5.5 $ (1.0) $ 4.5 Basic and diluted earnings per common share $ 0.07 $ 0.02 $ 0.09 $ (0.02) $ 0.07 I

(a) All changes are increases to income or earnings per common share and are after income taxes.

(b) The Reductions column reflects the effects of capitalization and sharing with joint-owners of power plants.

53

Pension Plans and Other Employee Benefits KCP&L has defined benefit pension plans for its employees, including officers and Wolf Creek employees. Benefits under these plans reflect the employees' compensation, years of service and age at retirement. KCP&L satisfies the minimum funding requirements under the Employee Retirement Income Security Act of 1974.

During 2001, the plans, other than those at Wolf Creek, were amended resulting in an increase to the benefit obligation of $6.8 million. The increase was due primarily to an amendment to the non management plan, which improved benefits to employees with at least thirty years of service who elected lump sum distributions.

During 2000, the plans were amended, except for those at Wolf Creek, which resulted in a $42.0 million increase in the benefit obligation. The amendments changed the mortality tables used and added enhanced benefit options. The enhancements include improved early retirement benefits for employees who retire after their age plus their years of service equals at least 85. The options also include lump sum distributions. During 2001, the plans experienced lump sum distributions related to these enhancements in excess of $33.0 million.

Primarily as a result of the significant decline in the market value of plan assets, KCP&L recorded an additional minimum pension liability of $20.0 million offset by an increase of $18.3 million in intangible assets and $1.7 million in other comprehensive income.

In addition to providing pension benefits, KCP&L provides certain postretirement health care and life insurance benefits for substantially all retired employees. KCP&L accrues the cost of postretirement health care and life insurance benefits during an employee's years of service and recovers these accruals through rates. KCP&L funds the portion of net periodic postretirement benefit costs that are tax deductible. Beginning in 2001, management employees who resign with 25 years or more of service are eligible for life insurance benefits.

Pension Benefits Other Benefits 2001 2000 2001 2000 (thousands)

Change in benefit obligation Benefit obligation at beginning of year $411,960 $334,939 $36,858 $31,910 Service cost 11,152 9,384 729 547 Interest cost 31,905 26,538 2,918 2,543 Contribution by participants - - 459 243 Amendments 6,790 42,025 960 Actuarial (gain) loss 22,853 26,504 3,185 4,997 Benefits paid (28,807) (27,116) (3,432) (2,980)

Benefits paid by KCP&L (1,381) (314) (454) (402)

Settlements (33,346)

Benefit obligation at end of year (a) $ 421,126 $ 411,960 $ 41,223 $ 36,858 54

Pension Benefits Other Benefits 2001 2000 2001 2n0n (thousands)

Change in plan assets Fair value of plan assets at beginning of year $564,947 $453,150 $ 8,096 $ 7,100 Actual return on plan assets (112,397) 137,684 601 225 Contributions by employer and participants 1,017 1,229 4,193 3,751 Benefits paid (28,807) (27,116) (3,432) (2,980)

Settlements (29,745) - -

Fair value of plan assets at end of year $ 395,015 $ 564,947 $ 9,458 $ 8,096 Prepaid (accrued) benefit cost Funded status $ (26,111) $152,987 $(31,765) $(28,762)

Unrecognized actuarial (gain) loss 58,686 (138,818) 4,649 1,692 Unrecognized prior service cost 47,296 44,960 1,282 400 Unrecognized transition obligation (230) (2,253) 12,919 14,093 Net prepaid (accrued) benefit cost $ 79,641 $ 56,876 $(12,915) $(12,577)

Amounts recognized in the consolidated balance sheets Prepaid benefit cost $ 88,337 $ 68,342 $ - $

Accrued benefit cost (8,696) (11,466) (12,915) (12,577)

Minimum pension liability adjustment (19,994)

Intangible asset 18,303 Accumulated other comprehensive income 1,691 Net amount recognized in statements $ 79,641 $ 56,876 $(12,915) $(12,577)

(a) Based on weighted-average discount rates of 7.25% in 2001 and 8.0% in 2000; and increases in future salary levels of 4.1% in 2001 and 2000.

Pension Benefits Other Benefits 2001 2000 1999 2001 2000 1999 Components of net periodic (thousands)

Benefit cost Service cost $ 11,152 $ 9,384 $10,983 $ 729 $ 547 $ 678 Interest cost 31,905 26,538 25,446 2,918 2,543 2,493 Expected return on plan assets (48,967) (39,571) (31,263) (403) (361) (348)

Amortization of prior service cost 3,884 488 498 78 78 77 Recognized net actuarial loss (gain) (11,333) (5,913) 896 32 2 51 Transition obligation (2,023) (2,072) (2,072) 1,174 1,174 1,175 Net settlements (1,738) - - -

Net periodic benefit cost $(17,120) $(11,146) $ 4,488 $4,528 $3,983 $4,126 Long-term rates of return on pension assets of 9.0% to 9.25% were used.

The pension benefits table above provides information relating to the funded status of all defined benefit pension plans on an aggregate basis. The projected benefit obligation, accumulated benefit 55

obligation and fair value of plan assets for pension plans with accumulated benefit obligations in excess of plan assets was $213.4 million, $176.3 million, and $234.3 million, respectively, as of December 31, 2001, and $404.1 million, $342.6 million, and$564.9 million, respectively, as of December 31, 2000. Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants.

Actuarial assumptions include an increase in the annual health care cost trend rate for the year 2001 and thereafter of 5.3%. The health care plan requires retirees to share in the cost when premiums exceed a certain amount. An increase or decrease in the assumed health care cost trend rate by 1%

per year would only increase or decrease the benefit obligation as of December 31, 2001, by about

$2,000,000 and the combined service and interest costs of the net periodic postretirement benefit cost for 2001 by about $200,000.

Employee Savings Plans KCP&L has a defined contribution savings plan that covers substantially all employees. The Company matches employee contributions, subject to limits. The annual cost of the plan was $2.9 million during both 2001 and 2000, and $2.8 million during 1999.

Stock Options The Company has a long-term incentive plan that permits the grant of restricted stock, stock options, limited stock appreciation rights and performance shares to officers and other employees of the Company and its subsidiaries. The maximum number of shares of Great Plains Energy common stock that may be issued under the plan is 3.0 million.

Stock Options Granted 1992 - 1996 The exercise price of stock options granted equaled the market price of the Company's common stock on the grant date. One-half of all options granted vested one year after the grant date, the other half vested two years after the grant date. An amount equal to the quarterly dividends paid on Great Plains Energy's common stock shares (dividend equivalents) accrues on the options for the benefit of option holders. The option holders are entitled to stock for their accumulated dividend equivalents only if the options are exercised when the market price is above the exercise price. At December 31, 2001, the market price of Great Plains Energy's common stock was $25.20, which exceeded the grant price for two of the three years that options granted were still outstanding. Unexercised options expire ten years after the grant date.

KCP&L follows Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees" and related interpretations in accounting for this plan. KCP&L recognizes annual expense equal to accumulated and reinvested dividends plus the impact of the change in stock price since the grant date. KCP&L expensed $(0.3) million in 2001, $1.1 million in 2000 and $(1.1) million in 1999.

Even though KCP&L follows APB Opinion 25, SFAS No. 123, "Accounting for Stock-Based Compensation" requires certain disclosures regarding expense and value of options granted using the fair-value method. KCP&L has expensed approximately the same amount as required by FASB 123.

For options outstanding at December 31, 2001, grant prices range from $20.6250 to $26.1875 and the weighted-average remaining contractual life is 3.6 years.

56

Stock option activity over the last three years is summarized below:

2001 2000 1999 Shares Price* Shares Price* Shares Price*

Outstanding at January 1 88,500 $23.57 89,875 $23.57 97,875 $23.41 Exercised 31,125 23.27 (1,375) 23.88 -

Canceled - - - - (8,000) 21.63 Outstanding at December 31 57,375 $23.73 88,500 $23.57 89,875 $23.57 Exercisable as of December 31 57,375 $23.73 88,500 $23.57 89,875 $23.57

• weighted-average price Stock Options Granted 2001 in 2001, 193,000 stock options were granted under the plan at the fair market value of the shares on the grant date. The options vest three years after the grant date and expire in ten years if not exercised. Exercise prices range from $25.32 to $25.98.

Great Plains Energy follows APB Opinion 25 to account for these options. No compensation cost is recognized because the option exercise price is equal to the market price of the underlying stock on the date of grant. Had compensation cost for the plan been recorded based on the fair value at the grant dates for awards as prescribed by SFAS No. 123, pro forma net income and earnings per share would not have been materially different than reported for 2001.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used to estimate the fair value of options granted in 2001:

dividend yield of 6.37%; expected stock price volatility of 25.879%; risk-free interest rate of 5.53% and expected life of option of 9.2 years.

In 2001, 144,500 performance shares were awarded. The issuance of performance shares is contingent upon achievement, over a four-year period, of company and individual performance goals.

Performance shares have an intrinsic value equal to the market price of a share on the date of grant.

Pursuant to APB 25, expense is accrued for performance shares over the period services are performed, if attainment of the performance goals appears probable. As a result of the Company's 2001 results of operations, no compensation expense was recognized in 2001 related to the performance shares.

57

4. INCOME TAXES Income tax expense consisted of the following:

Great Plains Energy 2001 2000 1999 Current income taxes: (thousands)

Federal $(32,628) $ 76,076 $ 31,439 State 1,304 10,928 2,978 Total (31,324) 87,004 34,417 Deferred income taxes:

Federal 9,785 (9,846) (23,313)

State (943) (469) (3,471)

Total 8,842 (10,315) (26,784)

Investment tax credit amortization (4,289) (4,296) (4,453)

Total income tax expense (26,771) 72,393 3,180 Less: Deferred taxes on the cumulative effect of changes in accounting principles - 19,227 Deferred taxes on early extinguishment of debt 9,143 -

Total $(35,914) $ 53,166 $ 3,180 Consolidated KCP&L 2001 2000 1999 Current income taxes: (thousands)

Federal $17,601 $76,076 $31,439 State 4,109 10,928 2,978 Total 21,710 87,004 34,417 Deferred income taxes:

Federal 18,968 (9,846) (23,313)

State 3,042 (469) (3,471)

Total 22,010 (10,315) (26,784)

Investment tax credit amortization (4,289) (4,296) (4,453)

Total income tax expense 39,431 72,393 3,180 Less: Deferred taxes on the cumulative effect of changes in accounting principles - 19,227 Deferred taxes on early extinguishment of debt 9,143 -

Total $30,288 $53,166 $ 3,180 58

The effective income tax rates differed from the statutory federal rates mainly due to the following:

Great Plains Energy 2001 2000 1999 Federal statutory income tax rate (35.0)% 35.0 % 35.0 %

Differences between book and tax depreciation not normalized 1.4 0.7 6.9 Proposed IRS Adjustment (see Note 18) - 4.6 Amortization of investment tax credits (8.4) (1.9) (5.2)

Federal income tax credits (41.6) (9.2) (26.4)

State income taxes 0.5 2.9 (0.4)

Merger expenses - (3.8)

Valuation allowance 31.0 Other (0.5) (0.8) (2.4)

Effective income tax rate (52.6)% 31.3% 3.7%

Consolidated KCP&L 2001 2000 1999 Federal statutory income tax rate 35.0 % 35.0 % 35.0 %

Differences between book and tax depreciation not normalized 0.5 0.7 6.9 Proposed IRS Adjustment (see Note 18) - 4.6 Amortization of investment tax credits (2.7) (1.9) (5.2)

Federal income tax credits (10.6) (9.2) (26.4)

State income taxes 2.9 2.9 (0.4)

Merger expenses - (3.8)

Other (0.3) (0.8) (2.4)

Effective income tax rate 24.8% 31.3% 3.7%

The tax effects of major temporary differences resulting in deferred tax assets and liabilities in the balance sheets are as follows:

Great Plains Energy Consolidated KCP&L December 31 2001 2000 2001 2000 housands)

Plant related $533,521 $530,600 $533,521 $530,600 Recoverable taxes 42,000 45,000 42,000 45,000 Pension and postretirement benefits 21,474 10,544 21,474 10,544 Tax credit carryforwards (19,183)

Gas properties related (9,535) (21,071) (21,071)

Nuclear fuel outage (5,061) (737) (5,061) (737)

AMT credit (4,258)

Other 14,906 25.147 33.704 25. 147 Net deferred tax liability before valuation allowance 573,864 589,483 625,638 589,483 Valuation allowance (see Note 17) 15,779 - -

Net deferred tax liability $589. 643 $589.483 $625.638 $589.483-

$589483

$589643 $589483 $625638 59

The net deferred income tax liability consisted of the following:

Great Plains Energy Consolidated KCP&L December 31 2001 2000 2001 2000 (thousands)

Gross deferred income tax assets $(125,413) $ (97,418) $ (73,640) $ (97,418)

Gross deferred income tax liabilities 715,056 686,901 699,278 686,901 Net deferred income tax liability $ 589,643 $589,483 $625,638 $589,483

5. RELATED PARTY TRANSACTIONS AND RELATIONSHIPS On September 30, 2000, KLT Energy Services exercised an option to purchase 1,411,765 shares of Bracknell Corporation (Bracknell) common stock owned by Reardon Capital, L.L.C. (Reardon). KLT Energy Services received 1,136,789 common shares of Bracknell at $4.25 per share and a warrant to purchase the remaining 274,976 shares at an exercise price of $4.25 per share. On that date, the closing price of Bracknell stock was $6.80 per share. Reardon had granted the option to KLT Energy Services in connection with the acquisition by Bracknell of an investment owned by KLT Energy Services and Reardon. In May 2001, KLT Energy Services exercised its warrant for 274,976 shares at

$4.25 per share and sold 278,600 shares of Bracknell common stock in June 2001 at $4.48 per share.

KLT Energy Services classified its investment in Bracknell as a trading security and reflected such investment at its market price. At December 31, 2000, the market value of KLT Energy Service's investment in Bracknell was $6.2 million or $5.56 per Bracknell share. In November 2001, Bracknell common stock ceased trading at a last sale price of $0.13 per share. As a result, during 2001, KLT Energy Services wrote off its investment in Bracknell.

Gregory Orman, President and Chief Executive Officer of KLT Energy Services owns 55% of the membership interests of Reardon in addition to 740,000 common shares (approximately 1%) of Bracknell. At December 31, 2001, Bracknell common stock is no longer traded.

In January of 1997, KLT Energy Services acquired approximately 71% of Custom Energy from Environmental Lighting Concepts. In February of 1999, Custom Energy acquired 100% of the outstanding ownership interest in Strategic Energy in exchange for 25% of the ownership interest in Custom Energy. Through a series of transactions, KLT Energy Services has increased its indirect ownership position in Strategic Energy to approximately 83% as of December 31, 2001. Environmental Lighting Concepts continues to own a 5.8% indirect ownership interest in Strategic Energy. Gregory Orman holds a 67% interest in Environmental Lighting Concepts.

6. COMMITMENTS AND CONTINGENCIES Nuclear Liability and Insurance Liability Insurance The Price-Anderson Act currently limits the combined public liability of nuclear reactor owners to $9.5 billion for claims that could arise from a single nuclear incident. The owners of Wolf Creek (the Owners) carry the maximum available commercial insurance of $0.2 billion. Secondary Financial Protection, an assessment plan mandated by the NRC, provides insurance for the $9.3 billion balance.

Under Secondary Financial Protection, if there were a catastrophic nuclear incident involving any of the nation's licensed reactors, the Owners would be subject to a maximum retrospective assessment per incident of up to $88 million ($41 million, KCP&L's share). The Owners are jointly and severally liable for these charges, payable at a rate not to exceed $10 million ($5 million, KCP&L's share) per incident 60

per year, excluding applicable premium taxes. The assessment, most recently revised in 1998, is subject to an inflation adjustment every five years based on the Consumer Price Index.

Property,Decontamination,Premature Decommissioningand Extra Expense Insurance The Owners also carry $2.8 billion ($1.3 billion, KCP&L's share) of property damage, decontamination and premature decommissioning insurance for loss resulting from damage to the Wolf Creek facilities.

NEIL provides this insurance.

In the event of an accident, insurance proceeds must first be used for reactor stabilization and NRC mandated site decontamination. KCP&L's share of any remaining proceeds can be used for further decontamination, property damage restoration and premature decommissioning costs. Premature decommissioning coverage applies only if an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses, and only after trust funds have been exhausted (see Note 1 Nuclear Plant Decommissioning Costs).

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

Under all NEIL policies, KCP&L is subject to retrospective assessments if NEIL losses, for each policy year, exceed the accumulated funds available to the insurer under that policy. The estimated maximum amount of retrospective assessments to KCP&L under the current policies could total about

$10.7 million.

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

Low-Level Waste The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact and selected a site in northern Nebraska to locate a disposal facility. WCNOC and the owners of the other five nuclear units in the compact provided most of the pre-construction financing for this project. KCP&L's net investment on its books at December 31, 2001 and 2000, was $7.4 million.

Significant opposition to the project has been raised by Nebraska officials and residents in the area of the proposed facility, and attempts have been made through litigation and proposed legislation in Nebraska to slow down or stop development of the facility. On December 18, 1998, the application for a license to construct this project was denied. This issue is being addressed in the courts. The passage of time, along with the appointment of a new state administration in Nebraska, has increased the chances for reversal of the license denial.

In May 1999, the Nebraska legislature passed a bill withdrawing Nebraska from the Compact. In August 1999, the Nebraska governor gave official notice of the withdrawal to the other member states.

Withdrawal will not be effective for five years and will not, of itself, nullify the site license proceeding.

Environmental Matters KCP&L's operations are subject to regulation by federal, state and local authorities with regard to air and other environmental matters. The generation and transmission of electricity produces and requires disposal of certain hazardous products which are subject to these laws and regulations. In addition to 61

imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. Failure to comply with these laws and regulations could have a material adverse affect on KCP&L.

KCP&L operates in an environmentally responsible manner and seeks to use current technology to avoid and treat contamination. KCP&L regularly conducts environmental audits designed to ensure compliance with governmental regulations and to detect contamination. Governmental bodies, however, may impose additional or more rigid environmental regulations that could require substantial changes to operations or facilities at a significant cost. Expenditures made in 2001 to comply with environmental laws and regulations were not material in amount and are not expected to be material in the upcoming years with the exception of the issues discussed below.

Monitoring Equipment and CertainAir Toxic Substances In July 2000, the National Research Council published its findings of a study under the Clean Air Act which stated that power plants that burn fossil fuels, particularly coal, generate the greatest amount of mercury emissions. As a result, in December 2000, the EPA announced it would propose Maximum Achievable Control Technology (MACT) requirements to reduce mercury emissions by December 2003 and issue final rules by December 2004. KCP&L cannot predict the likelihood or compliance costs of such regulations.

Air ParticulateMatter In July 1997, the EPA revised ozone and particulate matter air quality standards creating a new eight-hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns in diameter. These standards were challenged in the U. S. Court of Appeals for the District of Columbia (Appeals Court) that decided against the EPA. Upon appeal, the U. S. Supreme Court reviewed the standards and remanded the case back to the Appeals Court for further review, including a review of whether the standards were arbitrary and capricious. The Appeals Court has not rendered a decision, and the new particulate standards have not been finalized. Without implementation of the regulations, the outcome cannot be determined, but the impact on KCP&L and all other utilities that use fossil fuels could be substantial. In addition, the EPA is conducting a three-year study of fine particulate ambient air levels. Until this testing and review period has been completed, KCP&L cannot determine additional compliance costs, if any, associated with the new particulate regulations.

Nitrogen Oxide The EPA announced in 1998 regulations implementing reductions in NOx emissions. These regulations initially called for 22 states, including Missouri, to submit plans for controlling NO, emissions. The regulations require a significant reduction in NOx emissions from 1990 levels at KCP&L's Missouri coal-fired plants by the year 2003.

In December 1998, KCP&L and several other western Missouri utilities filed suit against the EPA over the inclusion of western Missouri in the NO, reduction program based on the 1-hour NO, standard. On March 3, 2000, a three-judge panel of the District of Columbia Circuit of the U.S. Court of Appeals sent the NO, rules related to Missouri back to the EPA, stating the EPA failed to prove that fossil plants in the western part of Missouri significantly contribute to ozone formation in downwind states. On March 5, 2001, the U.S. Supreme Court denied certiorari, making the decision of the Court of Appeals final.

This decision will likely delay the implementation of new NO, regulations by the EPA in the western portion of Missouri for some time.

If required to be implemented, KCP&L would need to incur significant capital costs, purchase power or purchase NO, emission allowances. Preliminary analysis of the regulations indicates that selective catalytic reduction technology, as well as other changes, may be required for some of the KCP&L units. Currently, KCP&L estimates that additional capital expenditures to comply with these regulations could range from $40 million to $60 million. Operations and maintenance expenses could also 62

increase by more than $2.5 million per year. KCP&L continues to refine these preliminary estimates and explore alternatives. The ultimate cost of these regulations, if any, could be significantly different from the amounts estimated above.

Carbon Dioxide At a December 1997 meeting in Kyoto, Japan, delegates from 167 nations, including the United States, agreed to a treaty (Kyoto Protocol) that would require a seven percent reduction in United States C02 emissions below 1990 levels. Although the United States agreed to the Kyoto Protocol, the treaty has not been sent to Congress for ratification. The financial impact on KCP&L of future requirements in the reduction of C02 emissions cannot be determined until specific regulations are adopted.

Nuclear Fuel Commitments As of December 31, 2001, KCP&L's portion of Wolf Creek nuclear fuel commitments included $22.7 million for enrichment through 2006, $57.5 million for fabrication through 2025 and $3.8 million for uranium and conversion through 2003.

Coal Contracts KCP&L's share of coal purchased under existing contracts was $44.6 million in 2001, $31.1 million in 2000, and $33.3 million in 1999. Under these coal contracts, KCP&L's remaining share of purchase commitments totals $65.7 million. Obligations for the years 2002 and 2003 based on estimated prices for those years, total $48.5 million and $17.2 million, respectively. The remainder of KCP&L's coal requirements will be fulfilled through spot market purchases.

Natural Gas Contracts KCP&L has entered natural gas agreements for the purchase of natural gas to be used in the generation of electricity. At December 31, 2001, obligations under these agreements total $2.6 million for 2002. The remainder of KCP&L's natural gas requirements will be fulfilled through spot market purchases.

Purchased Capacity Commitments 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 capacity purchases totaled $17.7 million in 2001,

$25.4 million in 2000 and $25.9 million during 1999. As of December 31, 2001, contracts to purchase capacity totaled $109.5 million through 2016. For the years 2002 through 2006, these commitments average $14 million per year. Capacity sales contracts to supply municipalities in the years 2002 through 2006 average $12 million. For the next five years, net capacity contracts average under 3% of KCP&L's 2001 total available capacity.

Strategic Energy Purchased Power Energy Commitments Strategic Energy has entered into agreements to purchase electricity at various fixed prices to meet estimated supply requirements for 2002 through 2006. Commitments under these agreements total

$366.3 million in 2002, $242.5 million in 2003, $146.9 million in 2004, $142.2 million in 2005 and $17.1 million in 2006. See Note 15 for further discussion.

Leases Consolidated expense for leases, excluding DTI, was about $28 million during 2001, $26 million during 2000 and $22 million in 1999. The remaining rental commitments under leases total $163.6 million ending in 2028. Obligations for the years 2002 through 2006 average $16 million per year.

KCP&L Leases KCP&L has a transmission line lease with another utility through September 2025 whereby, with FERC approval, the rental payments can be increased by the lessor. If this occurs and KCP&L is able to 63

secure an alternative transmission path, KCP&L can cancel the lease. Commitments under this lease total $1.9 million per year and $44.9 million over the remaining life of the lease if it is not canceled.

KCP&L's expense for other leases, including railcars, computer equipment, buildings, transmission line and other items, was about $25 million per year for the last three years. The remaining rental commitments under these leases total $159.4 million ending in 2028. Obligations for the years 2002 through 2006 average $15 million per year. Capital leases are not material and are included in these amounts.

As the managing partner of three jointly-owned generating units, KCP&L has entered into leases for railcars to serve those units. KCP&L has reflected the entire lease commitment in the above amounts although about $1.9 million per year ($27.0 million total) will be reimbursed by the other owners.

In 2001, KCP&L entered into a synthetic lease arrangement with a Trust (Lessor) to finance the purchase, installation, assembly and construction of five combustion turbines and related property and equipment that will add 385 megawatts of peaking capacity (the "Project). The Trust is a special purpose entity and has an aggregate financing commitment from third-party equity and debt participants (Investors) of $200 million. In accordance with SFAS No. 13 "Accounting for Leases," and related EITF issues (including EITF Issue No. 90-15, "Impact of Non-substantive Lessors, Residual Value Guarantees, and Other Provisions in Leasing Transactions" and EITF Issue No. 97-10, "The Effect of Lessee Involvement in Asset Construction"), the Project and related lease obligations are not included in KCP&L's consolidated balance sheet. The Lessor has appointed KCP&L as supervisory agent responsible for completing construction of the Project by no later than June 2004. The initial lease term is approximately three and one quarter years, beginning at the date of construction completion, which is expected to be October 2003. At the end of the lease term (October 2006),

KCP&L may choose to sell the Project for the Lessor, guaranteeing to the Lessor a residual value for the Project in an amount which may be up to 83.21% of the project cost. If KCP&L does not elect the sale option, KCP&L must either extend the lease, if it can obtain the consent of the Lessor, or purchase the Project for the then outstanding project cost. KCP&L also has contingent obligations to the Lessor upon an event of a default during both the construction period and lease period. Upon a default in the construction period, KCP&L's maximum obligation to the Lessor equals (i) in the circumstances of bankruptcy, fraud, illegal acts, misapplication of funds and willful misconduct, 100% of then-incurred project costs, and (ii) in all other circumstances, an amount which may be up to 89.9% of then-incurred project costs that are capitalizable in accordance with GAAP. At December 31, 2001, project costs were approximately $62.7 million. Upon a default during the lease period, KCP&L's maximum obligation to the Lessor equals 100% of project costs. KCP&L's rental obligation, which reflects interest payments only, totals approximately $35.5 million in the aggregate.

KLT Inc. Leases KLT Inc. and its subsidiaries have entered operating leases for buildings, compressors, communications equipment and other items. KLT Inc.'s expense recorded for these leases was about

$1 million per year during both 2001 and 2000. KLT Inc. and its subsidiaries had no leases in 1999.

Obligations average about $1 million per year for the years 2002 through 2004 and $0.5 million per year for the years 2005 and 2006.

Guaranteed Savings Energy Management Agreements KCP&L is contingently liable for guaranteed energy savings under agreements with several customers.

KCP&L has entered agreements guaranteeing an aggregate value of approximately $14.7 million over the next nine years. In most cases a subcontractor would indemnify KCP&L for any payments made by KCP&L under these guarantees.

64

7. HSS PURCHASE OF AN ADDITIONAL OWNERSHIP INTEREST IN RSAE On March 12,'2001, HSS acquired control of RSAE by acquiring an additional 22.1% of the shares of RSAE for $0.6 million.

This acquisition has been accounted for by the purchase method of accounting and the operating results of RSAE have been included in the KCP&L's consolidated financial statements from January 1, 2001, with the appropriate adjustments to minority interest from January 1, 2001, through the date of the acquisition. RSAE's December 31, 2001, assets included $23.0 million of goodwill, which was being amortized over 40 years. On a pro forma basis, as if the business had been acquired at the beginning of fiscal 2000, revenue, net income and earnings per share would not differ materially from the amounts reported in the KCP&L's year ended December 31, 2000, consolidated financial statements.

8. EQUITY METHOD INVESTMENTS See Note 17 for information regarding 2001 activity in KLT Telecom's investment in DTI.

Sale of KLT Investments II Inc.'s Ownership of Downtown Hotel Group On May 31, 2001, KLT Investments II Inc. sold its 25% ownership of Kansas City Downtown Hotel Group, L.L.C. for total proceeds of $3.8 million resulting in a $2.2 million gain before income taxes. The after income tax gain on the sale was $1.4 million ($0.02 per share). The carrying value of this equity method investment at December 31, 2000, was included in Other in the table below.

Sale of KLT Gas Properties On June 28, 2001, KLT Gas sold its 50% ownership in Patrick KLT Gas, LLC for total proceeds of

$42.3 million resulting in a $20.1 million gain before income taxes. The after income tax gain on the sale was $12.0 million ($0.19 per share).

After the acquisition of majority ownership in RSAE (see Note 7) and the sales of the equity method investments discussed above, the Company has no remaining equity method investments other than affordable housing limited partnerships held by KLT Investments. Equity method investments at December 31, 2000, excluding affordable housing limited partnerships, consisted of the following:

Common Ownership Carrying Value Percentage December 31, Name of Company 2000 2000 (thousands)

DTI 47% $

Patrick KLT Gas, LLC 50% 21,744 RSAE 49% 6,750 Other Various 1,786 Total equity method investments $30,280 65

Summarized financial information supplied to us by companies in which the consolidated company had an equity investment was as follows:

December 31 2000 (thousands)

Current assets $ 36,368 Non-current assets 498,133 Total Assets $534,501 Current liabilities $ 74,616 Non-current liabilities 460,786 Equity (901)

Total Liabilities and Equity $534,501 Revenues $153,211 Costs and expenses 225,665 Net Loss $(72,454)

December 31 2000 (thousands)

Consolidated share of net loss $ (36,707)

Less: DTI losses not recorded by KLT Telecom after the investment was reduced to zero (18,768)

Consolidated net loss recorded (17,939)

Affordable housing equity losses (1,502)

Total losses from equity investments $ (19,441) 66

9. SEGMENT AND RELATED INFORMATION Great Plains Energy Great Plains Energy reportable segments are strategic business units. KCP&L is the regulated electric utility. KLT Inc. and HSS are subsidiary holding companies for various unregulated business ventures.

Other includes the operations of GPP, unallocated corporate charges and intercompany eliminations.

The summary of significant accounting policies applies to all of the segments. Segment performance is evaluated based on net income.

The tables below reflect summarized financial information concerning Great Plains Energy's reportable segments. Prior year information has been restated to conform to the current presentation.

Great Plains 2001 KCP&L HSS KLT Inc. Other Energy (millions)

Operating revenues $ 967.5 $ 66.2 $ 428.2 $ - $ 1,461.9 Fuel expense (163.8) - - - (163.8)

Purchased power expense (65.2) (329.0) - (394.2)

Other (a) (365.1) (70.8) (79.8) (0.8) (516.5)

Depreciation and depletion (136.3) (2.4) (20.1) (158.8)

Loss on property (0.2) (1.4) (169.8) (171.4)

Loss from equity investments (0.1) (0.3) (0.4)

Other income and expenses (9.2) 4.3 (24.2) (0.4) (29.5)

Interest charges (78.1) (1.7) (23.8) 0.3 (103.3)

Income taxes (51.6) 0.3 86.9 0.3 35.9 Early extinguishment of debt - - 15.9 - 15.9 Net income (loss) $ 98.0 $ (5.6) $ (116.0) $ (0.6) $ (24.2)

Favorable/(unfavorable) Great Plains variance between 2001 and 2000 KCP&L HSS KLT Inc. Other Energy (millions)

Operating revenues $ 15.5 $ 62.4 $ 268.1 $ - $ 346.0 Fuel expense (10.7) - - - (10.7)

Purchased power expense 40.5 - (244.6) - (204.1)

Other (a) 17.3 (65.3) (20.6) (0.8) (69.4)

Depreciation and depletion (12.0) (0.7) (13.7) - (26.4)

Gain (loss) on property (3.7) 12.0 (278.8) - (270.5)

Loss from equity investments - 6.5 12.5 - 19.0 Other income and expenses 7.1 2.5 (23.8) 0.1 (14.1)

Interest charges (15.3) (1.2) (10.9) (0.2) (27.6)

Income taxes 1.3 (8.3) 95.8 0.3 89.1 Early extinguishment of debt - - 15.9 - 15.9 Cumulative effect of changes in pension accounting (30.1) - - - (30.1)

Net income (loss) $ 9.9 $ 7.9 $ (200.1) $ (0.6) $ (182.9) 67

Great Plains 2000 KCP&L HSS KLT Inc. Other Energy (millions)

Operating revenues $952.0 $ 3.8 $ 160.1 $ - $ 1,115.9 Fuel expense (153.1) - - - (153.1)

Purchased power expense (105.7) (84.4) - (190.1)

Other (a) (382.4) (5.5) (59.2) - (447.1)

Depreciation and depletion (124.3) (1.7) (6.4) - (132.4)

Gain (loss) on property 3.5 (13.4) 109.0 - 99.1 Loss from equity investments - (6.6) (12.8) - (19.4)

Other income and expenses (16.3) 1.8 (0.4) (0.5) (15.4)

Interest charges (62.8) (0.5) (12.9) 0.5 (75.7)

Income taxes (52.9) 8.6 (8.9) - (53.2)

Cumulative effect of changes in pension accounting 30.1 - - 30.1 Net income (loss) $ 88.1 $ (13.5) $ 84.1 $ - $ 158.7 Favorable/(unfavorable) Great Plains variance between 2000 and 1999 KCP&L HSS KLT Inc. Other Energy (millions)

Operating revenues $ 54.6 $ 0.5 $ 139.3 $ - $ 194.4 Fuel expense (23.8) - - - (23.8)

Purchased power expense (11.0) - (84.4) - (95.4)

Other (a) (29.9) (1.7) (28.2) - (59.8)

Depreciation and depletion (5.9) (0.1) (3.1) - (9.1)

Gain (loss) on property 3.5 (13.4) 110.2 - 100.3 Loss from equity investments - (2.7) 8.2 - 5.5 Other income and expenses (7.5) 1.5 (1.5) (0.5) (8.0)

Interest charges (6.4) (0.5) (1.0) 0.5 (7.4)

Income taxes (2.5) 6.6 (54.1) - (50.0)

Cumulative effect of changes in pension accounting 30.1 - - 30.1 Net income (loss) $ 1.2 $ (9.8) $ 85.4 $ - $ 76.8 Great Plains 1999 KCP&L HSS KLT Inc. Other Energy (millions)

Operating revenues $ 897.4 $ 3.3 $ 20.8 $ - $ 921.5 Fuel expense (129.3) - - - (129.3)

Purchased power expense (94.7) - - (94.7)

Other (a) (352.5) (3.8) (31.0) - (387.3)

Depreciation and depletion (118.4) (1.6) (3.3) - (123.3)

Loss on property (1.2) - (1.2)

Loss from equity investments (3.9) (21.0) - (24.9)

Other income and expenses (8.8) 0.3 1.1 - (7.4)

Interest charges (56.4) - (11.9) - (68.3)

Income taxes (50.4) 2.0 45.2 - (3.2)

Net income (loss) $ 86.9 $ (3.7) $ (1.3) $ - $ 81.9 (a)Other includes gas purchased and production expenses, telecommunications expenses, other operating, maintenance and general tax expenses.

68

The following table provides additional detail on the operations of the KLT Inc. segment.

2001 DTI(a) SEL(a) KLT Gas Other KLT Inc.

(millions)

Operating revenues $ 15.9 $ 411.9 $ 0.3 $ 0.1 $ 428.2 Purchased power expense - (329.0) - - (329.0)

Other (23.8) (38.7) (9.4) (7.9) (79.8)

Depreciation and depletion (17.9) (0.3) (1.8) (0.1) (20.1)

Gain (loss) on property (195.8) 23.8 2.2 (169.8)

Loss from equity investments - 1.0 (1.3) (0.3)

Other income and expenses 0.9 (6.4) 0.3 (19.0) (24.2)

Interest charges (27.8) (0.5) - 4.5 (23.8)

Income taxes 74.7 (15.2) 0.1 27.3 86.9 Early extinguishment of debt 15.9 - - - 15.9 Net income (loss) $(157.9) $ 21.8 $ 14.3 $ 5.8 $(116.0) 2000 DTI(a) SEL(a) KLT Gas Other KLT Inc.

(millions)

Operating revenues $ - $ 129.6 $ 30.5 $ $ 160.1 Purchased power expense - (84.4) - (84.4)

Other - (30.9) (22.3) (6.0) (59.2)

Depreciation and depletion - (0.4) (6.0) - (6.4)

Gain on property - - 107.9 1.1 109.0 Loss from equity investments (14.4) - 3.6 (2.0) (12.8)

Other income and expenses - (4.2) 5.3 (1.5) (0.4)

Interest charges - (0.2) (3.5) (9.2) (12.9)

Income taxes 5.2 (3.6) (36.3) 25.8 (8.9)

Net income (loss) $ (9.2) $ 5.9 $ 79.2 $ 8.2 $ 84.1 1999 DTI(a) SEL(a) KLT Gas Other KLT Inc.

(millions)

Operating revenues $ - $ - $ 17.3 $ 3.5 $ 20.8 Purchased power expense - - -

Other - - (16.0) (15.0) (31.0)

Depreciation and depletion - - (3.2) (0.1) (3.3)

Gain (loss) on property - - (2.9) 1.7 (1.2)

Loss from equity investments (22.2) 3.5 (2.6) 0.3 (21.0)

Other income and expenses - 0.1 1.0 1.1 Interest charges - (1.2) (10.7) (11.9)

Income taxes 8.0 (1.3) 11.8 26.7 45.2 Net income (loss) $ (14.2) $ 2.2 $ 3.3 $ 7.4 $ (1.3)

(a) KLT Inc. acquired a majority ownership in Strategic Energy during the second quarter of 2000 and in DTI in February 2001.

Prior to this, the investments in Strategic Energy and DTI were recorded on an equity basis. Inthe second quarter of 2000, Strategic Energy was included in the consolidated financial statements from January 1, 2000, with the appropriate adjustments to minority interest from January 1, 2000, through the date of the acquisition.

69

ConsolidatedKCP&L On October 1, 2001, consolidated KCP&L dividended its ownership interest in KLT Inc. and GPP to Great Plains Energy. As a result, those companies are direct subsidiaries of Great Plains Energy and are not included in consolidated KCP&L's results of operations and financial position since October 1, 2001. See Note 1 for additional information about the formation of the holding company.

The tables below reflect 2001 summarized financial information concerning consolidated KCP&L's reportable segments. For the years ended 2000 and 1999, consolidated KCP&L's segment information is identical to the Great Plains Energy segment information presented above.

Subsidiaries transferred to Consolidated 2001 KCP&L HSS Great Plains Energy KCP&L (millions)

Operating revenues $ 967.5 $ 66.2 $317.2 $ 1,350.9 Fuel expense (163.8) - - (163.8)

Purchased power expense (65.2) - (239.7) (304.9)

Other (a) (365.1) (70.8) (60.7) (496.6)

Depreciation and depletion (136.3) (2.4) (14.3) (153.0)

Gain (loss) on property (0.2) (1.4) 23.7 22.1 Loss from equity investments - (0.1) (0.4) (0.5)

Other income and expenses (9.2) 4.3 (17.5) (22.4)

Interest charges (78.1) (1.7) (17.8) (97.6)

Income taxes (51.6) 0.3 20.9 (30.4)

Early extinguishment of debt - - 15.9 15.9 Net income (loss) $ 98.0 $ (5.6) $ 27.3 $ 119.7 (a) Other includes gas purchased and production expenses, telecommunications expenses, other operating, maintenance and general tax expenses.

KCP&L HSS KLT Inc. Other Consolidated 2001 (millions)

Assets $ 3,089.4 $ 53.9 $ 319.1 $2.0 $ 3,464.4 Capital and investment expenditures 265.8 1.1 105.7 1.7 374.3 2000 Assets $ 2,980.9 $ 25.3 $ 287.7 - $ 3,293.9 Net equity method investments (b) - 6.8 23.5 - 30.3 Capital and investment expenditures 406.1 0.3 75.6 - 482.0 1999 Assets $ 2,672.3 $ 50.0 $ 267.8 - $ 2,990.1 Net equity method investments (b) - 25.6 25.6 - 51.2 Capital and investment expenditures 184.6 25.7 61.3 271.6 to) Excluding affordable housing limited partnerships.

10. GOODWILL AND INTANGIBLE PROPERTY SFAS No. 142, "Goodwill and Other Intangible Assets" SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. The Company will adopt SFAS No. 142 on January 1, 2002. Under the new pronouncement, goodwill will be assigned to 70

reporting units and an initial impairment test (comparison of the fair value of a reporting unit to its carrying amount) will be done on all goodwill within six months of initially applying the statement and then at least annually, thereafter. Also, goodwill will no longer be amortized. Although the Company has not completed the analysis required by SFAS No. 142, management currently does not anticipate an impairment of goodwill. Goodwill, net of amortization, reported on Great Plains Energy's Consolidated Balance Sheets totaled $23.0 million associated with HSS' ownership interest in RSAE and $14.1 million associated with KLT Energy Services ownership interest in Strategic Energy at December 31, 2001, and $11.5 million related to the ownership interest in Strategic Energy at December 31, 2000. The goodwill associated with HSS' ownership interest in RSAE is also reflected on KCP&L's consolidated balance sheet.

Intangible Property KCP&L electric utility plant on the consolidated balance sheets included intangible computer software of $48.2 million, net of accumulated depreciation of $33.0 million, in 2001 and $51.2 million, net of accumulated depreciation of $21.7 million, in 2000.

KLT Inc. gas property and investments on the consolidated balance sheets included intangible drilling costs of $17.7 million in 2001 and $7.0 million in 2000.

Other nonutility property and investments on the consolidated balance sheets included intangible computer software and other intangible property of $1.7 million, net of accumulated depreciation of

$0.2 million, in 2001 and $0.7 million, net of accumulated depreciation in 2000.

11. RECEIVABLES December 31 2001 2000 (thousands)

KCP&L Receivable Corporation $ 25,723 $ 48,208 KCP&L other receivables 36,788 67,148 Consolidated KCP&L receivables 62,511 115,356 Great Plains Energy other receivables 89,603 Great Plains Energy receivables $152,114 $115,356 In 1999, KCP&L entered into a revolving agreement to sell all of its right, title and interest in the majority of its customer accounts receivable to KCP&L Receivable Corporation, a special purpose entity established to purchase customer accounts receivable from KCP&L expiring in October 2002.

The Company expects the agreement to be renewed annually. KCP&L Receivable Corporation has sold receivable interests to outside investors. In consideration of the sale, KCP&L received $60 million in cash in 2000 increasing to $70 million in 2001 and the remaining balance in the form of a subordinated note from KCP&L Receivable Corporation. The agreement is structured as a true sale under which the creditors of KCP&L Receivable Corporation are entitled to be satisfied out of the assets of KCP&L Receivable Corporation prior to any value being returned to KCP&L or its creditors.

Accounts receivable sold under the agreement totaled $95.7 million at December 31, 2001 and $108.2 million at December 31, 2000.

Administrative costs associated with the sale of customer accounts receivable of approximately $2.7 million for the year ended December 31, 2001, approximately $4.3 million for the year ended 2000 and approximately $3.5 million for the year ended 1999, were included in Other income and expenses.

KCP&L other receivables at December 31, 2001, consist primarily of receivables from partners in jointly-owned electric utility plants, bulk power sales receivables and accounts receivable held by RSAE and Worry Free. Great Plains Energy other receivables at December 31, 2001, consist of accounts receivable held by KLT Inc. and its subsidiaries, including receivables of $85.0 million held by Strategic 71

Energy. Other receivables at December 31, 2000, consist primarily of receivables from partners in jointly-owned electric utility plants, bulk power sales receivables and accounts receivable held by subsidiaries.

12. SHORT-TERM BORROWINGS AND SHORT-TERM BANK LINES OF CREDIT In October 2001, Great Plains Energy entered into a $110 million bridge revolving credit facility with tiered pricing based on the credit rating of Great Plains Energy's unsecured long-term debt securities.

Later in 2001, this facility was increased to $129 million. At December 31, 2001, Great Plains Energy had $124 million of outstanding borrowings under this facility with a weighted-average interest rate of 3.0%. This facility terminates on February 28, 2002. Great Plains Energy is in the process of syndicating a 364-day, revolving credit facility for up to $225 million with a group of banks to replace the bridge facility. The new facility will be used for general corporate purposes.

In 2001, Strategic Energy entered into a $5 million, variable interest rate line of credit that expires in December 2002. The line is secured by the deposits, moneys, securities, and other property in the possession of the lender. There were no outstanding borrowings under this agreement as of December 31, 2001. In January 2002, Strategic Energy increased this line of credit to $15 million.

KCP&L's short-term borrowings consist of funds borrowed from banks or through the sale of commercial paper as needed. The weighted-average interest rate on the $62.0 million of commercial paper outstanding as of December 31, 2001, was 3.2%. The weighted-average interest rate on the

$55.6 million of commercial paper outstanding as of December 31, 2000, was 7.1%. Under minimal fee arrangements, KCP&L's short-term bank lines of credit totaled $196.0 million with $134.0 million unused as of December 31, 2001, and $255.0 million with $199.4 million unused as of December 31, 2000.

RSAE has a $22.0 million short-term bank credit agreement. Great Plains Energy has entered into a support agreement with RSAE and the lender that ensures adequate capital to operate RSAE. At December 31, 2001, RSAE had $20.4 million of outstanding borrowings under the agreement with a weighted-average interest rate of 6.8%.

13. LONG-TERM DEBT AND EIRR BONDS CLASSIFIED AS CURRENT LIABILITIES KCP&L General Mortgage Bonds KCP&L has issued mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented. The Indenture creates a mortgage lien on substantially all utility plant. Mortgage bonds secure $364.8 million of medium-term notes and EIRR bonds (see discussion below). KCP&L is prohibited from issuing additional mortgage bonds while its unsecured medium-term notes are outstanding and remain unsecured. KCP&L has $200.0 million of these notes outstanding which mature in March 2002.

During the third quarter 2001, KCP&L remarketed $48.3 million of its $158.8 million secured EIRR bonds due 2012-23 at a fixed rate of 3.90% through August 31, 2004. See discussion of $31.0 million, remarketed weekly, below. The rest of the secured EIRR bonds are in a 35-day, dutch auction mode.

KCP&L Unsecured Notes KCP&L has a total of $196.5 million of unsecured EIRR bonds outstanding. Series C, $50 million due 2017, has a fixed rate of 4.50% through August 31, 2003. See discussion of series A, B and D (classified as current liabilities) below. During 2001, KCP&L issued $150 million of unsecured senior notes increasing the outstanding unsecured senior notes to a total of $400 million.

72

KCP&L EIRR Bonds Classified as Current Liabilities A $31.0 million variable-rate, secured EIRR bond with a final maturity in 2017 is remarketed on a weekly basis, with full liquidity support provided by a 364-day credit facility with one bank. This facility requires KCP&L to represent, as both a condition to renewal and prior to receiving any funding under the facility, that no Material Adverse Change has occurred. KCP&L's available liquidity under this credit line is not impacted by a decline in credit ratings unless the downgrade occurs in the context of a merger, consolidation, or sale. Additionally, in 2001 KCP&L remarketed three series of unsecured EIRR bonds at a fixed rate of 3.25% through August 29, 2002; its series A and B, $106.5 million due 2015, and series D, $40.0 million due 2017. If those bonds to be remarketed in less than one-year could not be remarketed, KCP&L would be obligated to either purchase or retire the bonds. Even though such an occurrence is unlikely, the $177.5 million of bonds discussed above are classified as current liabilities on the balance sheets for the current year and the prior year has been reclassified to be consistent with the current year presentation.

KLT Inc. Long-Term Debt KLT Investments' affordable housing notes are collateralized by the affordable housing investments.

Most of the notes also require the greater of 15% of the outstanding note balances or the next annual installment to be held as cash, cash equivalents or marketable securities. The equity securities held as collateral for these notes are included in other investments and nonutility property on the consolidated balance sheets.

Scheduled Maturities Great Plains Energy's long-term debt maturities for the years 2002 through 2006 are $239 million, $31 million, $60 million, $293 million and $11 million, respectively. These amounts include consolidated KCP&L's long-term debt maturities for the years 2002 through 2006 of $227 million, $22 million, $56 million, $290 million and $9 million, respectively. EIRR bonds classified as current liabilities discussed above are considered due in 2015 and 2017 for the scheduled maturities.

14. COMMON STOCK EQUITY, PREFERRED STOCK, REDEEMABLE PREFERRED STOCK AND MANDATORILY REDEEMABLE PREFERRED SECURITIES Common Stock Equity Effective October 1, 2001, all outstanding KCP&L shares of common stock were exchanged one for one for shares of Great Plains Energy. Great Plains Energy has shares of common stock registered with the Securities and Exchange Commission for a Dividend Reinvestment and Stock Purchase Plan (the Plan). The Plan allows for the purchase of common shares by reinvesting dividends or making optional cash payments. Great Plains Energy currently purchases shares for the Plan on the open market.

As of December 31, 2001, the Company held 35,916 shares of its common stock to be used for future distribution and 60,841 shares were held as of December 31, 2000. The cost of these shares is included in other investments and nonutility property on the consolidated balance sheets.

The Restated Articles of Consolidation contain a restriction related to the payment of dividends in the event common equity falls to 25% of total capitalization. If preferred stock dividends are not declared and paid when scheduled, Great Plains Energy could not declare or pay common stock dividends or purchase any common shares. If the unpaid preferred stock dividends equal four or more full quarterly dividends, the preferred shareholders, voting as a single class, could elect the smallest number of Directors necessary to constitute a majority of the full Board of Directors.

Preferred Stock and Redeemable Preferred Stock During 2001, KCP&L redeemed its redeemable 4% Cumulative Preferred Stock. Shares outstanding totaled 6,357 as of December 31, 2000. Scheduled mandatory sinking fund requirements for the issue 73

were 1,600 per year. Shares held by KCP&L to meet future sinking fund requirements totaled 5,734 as of December 31, 2000. The cost of these shares held by KCP&L was reflected as a reduction of the capital account.

Effective October 1, 2001, all shares of KCP&L preferred stock were converted to Great Plains Energy preferred stock. As of December 31, 2001, 0.4 million shares of $100 par Cumulative Preferred Stock, 1.6 million shares of Cumulative No Par Preferred Stock and 11 million shares of no par Preference Stock were authorized. Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices approximating par or stated value.

Mandatorily Redeemable Preferred Securities In 1997, KCP&L Financing I (Trust) issued $150,000,000 of 8.3% preferred securities. The sole asset of the Trust is the $154,640,000 principal amount of 8.3% Junior Subordinated Deferrable Interest Debentures, due 2037, issued by KCP&L. The terms and interest payments on these debentures correspond to the terms and dividend payments on the preferred securities. KCP&L deducts these payments for tax purposes. KCP&L may elect to defer interest payments on the debentures for a period up to 20 consecutive quarters, causing dividend payments on the preferred securities to be deferred as well. In case of a deferral, interest and dividends will continue to accrue, along with quarterly compounding interest on the deferred amounts. KCP&L may redeem all or a portion of the debentures after March 31, 2002. If KCP&L redeems all or a portion of the debentures, the Trust must redeem an equal amount of preferred securities at face value plus accrued and unpaid distributions.

The back-up undertakings in the aggregate provide a full and unconditional guarantee of amounts due on the preferred securities.

15. DERIVATIVE FINANCIAL INSTRUMENTS On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. SFAS No. 133 requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

SFAS No. 133 requires that as of the date of initial adoption, the difference between the fair market value of derivative instruments recorded on the balance sheet and the previous carrying amount of those derivatives be reported in net income or other comprehensive income, as appropriate, as a cumulative effect of a change in accounting principle. The adoption of SFAS No. 133 on January 1, 2001, required the Company to record a $0.2 million expense, net of $0.1 million of income tax. The Company did not reflect this immaterial amount as a cumulative effect. This entry increased interest expense by $0.6 million and reduced purchased power expense by $0.3 million. The Company also recorded $17.4 million, net of $12.6 million of income tax, as a cumulative effect of a change in accounting principle applicable to comprehensive income for its cash flow hedges.

Derivative Instruments and Hedging Activities The Company's activities expose it to a variety of market risks including interest rates and commodity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on its operating results.

The Company's interest rate risk management strategy uses derivative instruments to minimize significant, unanticipated earnings fluctuations caused by interest-rate volatility on a portion of its variable rate debt. The Company maintains commodity-price risk management strategies that use derivative instruments to minimize significant, unanticipated earnings fluctuations caused by commodity price volatility.

74

The Company's risk management activities, including the use of derivatives, are subject to the management, direction and control of Risk Management Committees.

Interest Rate Risk Management KCP&L utilizes interest rate management derivatives to reduce a portion of KCP&L's interest rate risk by converting a portion of its variable interest rate payments into fixed interest rate payments.

In 2000, KCP&L issued $200 million of unsecured, floating rate medium-term notes. Simultaneously, KCP&L entered into interest rate cap agreements to hedge the interest rate risk on the notes. The cap agreements are designated as cash flow hedges. The difference between the fair market value of the cap agreements recorded on the balance sheet at initial adoption and the unamortized premium was reported in interest expense.

KCP&L entered into interest rate swap agreements to limit the interest rate on $30 million of long-term debt. These swaps do not qualify for hedge accounting. The swap agreements mature in 2003 and effectively fix the interest to a weighted-average rate of 3.88%. The fair market values of these agreements are recorded as current assets and liabilities and adjustments to interest expense on the income statement. Changes in the fair market value of these instruments are recorded in the income statement.

Commodity Risk Management KCP&L's risk management policy is to use derivative hedge instruments to mitigate its exposure to market price fluctuations on its projected gas requirements for native and firm sales. These hedging instruments are designated as cash flow hedges. The fair market value of these instruments is recorded as current assets and current liabilities. When the gas is purchased and to the extent the hedge is effective at mitigating the impact of a change in the purchase price of gas, the amounts in other comprehensive income are reclassified to the consolidated income statement. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value are recorded directly in fuel expense.

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. Supplying electricity to retail customers under fixed rate contracts requires Strategic Energy to match customers' demand with fixed price purchases. In certain markets where Strategic Energy operates, there is limited availability of forward fixed price power contracts. By entering into swap contracts for a portion of its forecasted purchases in these markets, the future purchase price of electricity is effectively fixed under these swap contracts protecting Strategic Energy from price volatility. The swap contracts limit the unfavorable effect that price increases will have on electricity purchases. Under SFAS No. 133, the majority of the swap agreements are designated as cash flow hedges resulting in the difference between the market value of energy and the hedge value being recorded as comprehensive income(loss). At December 31, 2001, the accumulated comprehensive loss, net of income taxes and minority interest, reflected in Great Plains Energy's consolidated statement of capitalization reflected a $11.7 million loss related to such cash flow hedges. However, most of the energy hedged with the swaps has been sold to customers through contracts at prices different than the fair market value used to value the swaps.

Therefore, Strategic Energy does not anticipate incurring any of the losses represented in comprehensive income.

The remaining swap agreements do not qualify for hedge accounting. The fair market value of these swaps at January 1, 2001, was recorded as an asset or liability on the consolidated balance sheet and an adjustment to the cost of purchased power. The change in the fair market value and future changes in the fair market values of these swaps will also be recorded in purchased power.

75

An option that was designated as a cash flow hedge expired on December 31, 2001. The option allowed Strategic Energy to purchase up to 270 megawatts of power at a fixed rate of $21 per mwh.

The fair market value of this option and the swap agreements designated as cash flow hedges at January 1, 2001, was recorded as a current asset and a cumulative effect of a change in accounting principle in comprehensive income. When the power is purchased and to the extent the hedge is effective at mitigating the cost of purchased power, the amounts accumulated in other comprehensive income are reclassified to the consolidated income statement. However, most of the energy hedged with the swaps has been sold to customers through contracts at prices different than the fair market value used to value the swaps. Therefore, Strategic Energy will not receive income or losses to the extent represented in comprehensive income in the current or future periods. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value will be recorded directly in purchased power.

KLT Gas' risk management policy is to use firm sales agreements or financial hedge instruments to mitigate its exposure to market price fluctuations on up to 85% of its daily natural gas production.

These hedging instruments are designated as cash flow hedges. The fair market value of these instruments at January 1, 2001, was recorded as current assets and current liabilities, as applicable, and the cumulative effect of a change in an accounting principle in comprehensive income. When the gas is sold and to the extent the hedge is effective at mitigating the impact of a change in the sales price of gas, the amounts in other comprehensive income are reclassified to the consolidated income statement. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value are recorded directly in gas revenues.

KLT Gas unwound the majority of its gas hedge derivatives with an offsetting swap transaction during the second quarter of 2001 primarily due to declining production at its gas properties. This transaction does not qualify for hedge accounting. The fair market value of the swap has been recorded in gas revenues. Future changes in the fair market value of this swap will also be recorded in gas revenues.

KCP&L has eight capacity contracts it considers to be normal purchases and sales and not derivatives in accordance with GAAP. During the fourth quarter of 2001, FASB cleared new implementation guidelines that will be applied in the second quarter of 2002. KCP&L is still evaluating its capacity contracts under the new guidelines, but does not expect the contracts to be considered derivatives under the new guidelines.

The amounts recorded related to the cash flow hedges are summarized below.

Great Plains Energy activity for 2001 Cumulative Increase Effect to (Decrease) in January 1, Comprehensive December 31 Balance Sheet Classification 2001 Income Reclassified 2001 Assets (millions)

Other current assets $ 44.5 $ (20.6) $ (24.1) $(0.2)

Liabilities and capitalization Other current liabilities (6.8) (20.8) 14.9 (12.7)

Other comprehensive Income (17.4) 25.6 3.9 12.1 Deferred income taxes (12.7) 18.1 3.1 8.5 Other deferred credits (7.6) (2.3) 2.2 (7.7) 76

KCP&L activity for 2001 Cumulative Increase Transferred Effect to (Decrease) in to Great January 1, Comprehensive Plains December 31 Balance Sheet Classification 2001 Income Reclassified Energy 2001 Assets (millions)

Other current assets $ 44.5 $ (20.6) $ (24.1) $ - $(0.2)

Liabilities and capitalization Other current liabilities (6.8) (15.7) 7.4 15.0 (0.1)

Other comprehensive income (17.4) 23.4 7.6 (13.4) 0.2 Deferred income taxes (12.7) 16.6 5.6 (9.4) 0.1 Other deferred credits (7.6) (3.7) 3.5 7.8

16. JOINTLY-OWNED ELECTRIC UTILITY PLANTS KCP&L's share of jointly-owned electric utility plants as of December 31, 2001, is as follows (in millions of dollars):

Wolf Creek LaCygne latan Unit Units Unit KCP&L's share 47% 50% 70%

Utility plant in service $1,360 $ 327 $ 253 Estimated accumulated depreciation (production plant only) $ 540 $ 217 $ 163 Nuclear fuel, net $ 34 -

KCP&L's accredited capacity-megawatts 550 681 469 Each owner must fund its own portion of the plant's operating expenses and capital expenditures.

KCP&L's share of direct expenses is included in the appropriate operating expense classifications in the income statement.

17. DTI HOLDINGS, INC. AND SUBSIDIARIES On December 31, 2001, a subsidiary of KLT Telecom, DTI Holdings, Inc. (Holdings) and its subsidiary Digital Teleport Inc. (collectively called DTI), filed voluntary petitions in Bankruptcy Court for the Eastern District of Missouri for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The filings enable DTI to continue to conduct its business operations while restructuring its financial obligations. DTI is a telecommunications company headquartered in St. Louis that focuses on providing access and connectivity to secondary and tertiary markets. KLT Telecom has agreed to provide up to $5 million in DIP financing to Digital Teleport Inc. during the bankruptcy process if it achieves certain financial goals. If KLT Telecom provides loans under this DIP financing agreement, it will have priority repayment over most other DTI obligations.

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 the majority shareholder, Richard D. Weinstein (Weinstein) increasing its ownership to 83.6%. In connection with the February 8, 2001 purchase agreement, KLT Telecom granted Weinstein a put option. The put option allows Weinstein to sell his remaining shares to KLT Telecom during a period beginning September 1, 2003, and ending August 31, 2005. The shares shall have an aggregate exercise price equal to the fair market of the shares with an aggregate floor amount of $15 million. The put option has negligible value at December 31, 77

2001, because of the bankruptcy of DTI and prior to December 31, 2001, because of the contract provisions.

Prior to items discussed below, KLT Telecom's remaining $175.2 million investment in DTI included a February 1, 2001, $94 million loan to Holdings, the proceeds of which were used to repurchase a portion of its Senior Discount Notes, and $47 million in loans to Digital Teleport Inc. under various arrangements. The $47 million of loans are secured, to the extent permitted by law or agreement, by Digital Teleport Inc.'s assets. In December 2001, KLT Telecom converted $84 million of the $94 million loan, plus accrued interest of $8.5 million, to an equity contribution.

The Company obtained from legal counsel, an opinion which stated that based upon and subject to the analysis, limitations and qualifications set forth in the opinion, that they are of the opinion that a court applying Missouri law and acting reasonably in a properly presented and argued case would hold that the corporate veil of DTI would not be pierced with respect to Great Plains Energy and its subsidiaries and therefore neither Great Plains Energy nor the subsidiaries would be required to fund, beyond KLT Telecom's current equity investment in or loans to DTI, directly, indirectly or through guarantees, any of the present, past or future liabilities, commitments or obligations of DTI except for the DIP loan and certain performance bonds.

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.

During the fourth quarter of 2001, the following have been recognized in the financial statements of Great Plains Energy related to the activities of DTI:

"* Wrote off $60.8 million of goodwill related to the purchase of DTI in February 2001.

"* Recorded a $342.5 million impairment of DTI's assets resulting in a negative KLT Telecom investment of $228.1 million.

" Because of DTI's filing for bankruptcy protection under the U.S. Bankruptcy code, KLT Telecom no longer has control over nor can they exert significant control over DTI. As a consequence, as of December 31, 2001, DTI has been de-consolidated and is presented on the cost basis.

Consequently KLT Telecom will not include the ongoing results of operations, earnings or losses incurred by DTI during bankruptcy.

" Because of the legal opinion from counsel discussed above, the Company was able to record a reduction in the negative investment of $207.5 million. This reduction resulted in a net impairment charge of $195.8 million ($342.5 million impairment of DTI's assets plus the $60.8 million write-off of goodwill less the $207.5 million adjustment of KLT Telecom's investment) and a remaining negative investment of $20.6 million. This remaining negative investment represents the possible commitments and guarantees relating to DTI including the $5 million for DIP financing and the $15 million aggregate floor of the Weinstein put option. The $20.6 million is included in Deferred Credits and Other Liabilities - Other on Great Plains Energy's consolidated balance sheet.

The results of the above include a $140.0 million ($2.27 per share) reduction to net income ($195.8 included in (Gain) Loss on Property in Operating Expenses and $55.8 million of income tax benefits included in Income Taxes on Great Plains Energy's Consolidated Statements of Income).

The $55.8 million income tax benefits applicable to this net write-off is net of a $15.8 million tax valuation allowance due to the uncertainty of recognizing future tax deductions while in the bankruptcy process. The $55.8 million income tax benefit reflects the impact of DTI's 2001 abandonment of its

$104 million of long-haul assets in addition to other expected tax deductions. If additional assets of DTI are sold or abandoned during the bankruptcy process., or additional tax losses not already 78

reflected are incurred by DTI, KLT Telecom will record tax benefits associated with these additional tax deductions at that time. The amount of additional tax deductions will be limited by KLT Telecom's tax basis in DTI. DTI's tax losses will continue to be included in Great Plains Energy's consolidated tax return. In accordance with the tax allocation agreement with DTI, cash tax savings are shared with DTI only to the extent DTI generates taxable income to utilize such losses.

Following are condensed DTI consolidated financial statements for the year ended December 31, 2001.

Net Assets De-consolidated DTI Consolidated Balance Sheet December 31, 2001 by KLT Telecom (millions)

Assets Property and equipment, net $ 46.9 Other 6.1 Total assets $ 53.0 $ (53.0)

Liabilities Current liabilities not subject to compromise $ 0.2 0.2 Liabilities subject to compromise Loans from KLT Telecom 57.0 Deferred revenue 45.8 45.8 Interest payable to KLT Telecom 3.0 Other 31.9 31.9 Senior discount notes Held by KLT Telecom 8.5 Held by others 203.2 203.2 Total liabilities subject to compromise 349.4 Stockholders' equity(deficit) (296.6)

Total liabilities and stockholders' equity(deficit) $ 53.0 $ 228.1 DTI Consolidated Statement of Income for the Year Ended December 31, 2001 (millions)

Telecommunications service revenues $ 17.4 Operating expenses Provision for impairment of long-lived assets (a) (342.5)

Other (44.2)

Interest expense net of interest income (31.9)

Loss before income tax benefit and extraordinary item (401.2)

Income tax benefit 37.9 Gain on early extinguishment of debt 57.2 Net loss $(306.1)

(a) The write-down of assets was determined by DTI in accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of'. The write down reflects the abandonment of $104 million of long-haul assets and the impairment of the rest of the telecommunication network and equipment. The impairment is primarily a result of the downward trends in certain segments of the economy, particularly with respect to previously expected growth of demand in technology and telecommunications, the accompanying deterioration in value of DTI's operating assets and its Chapter 11 filing. The fair value used in the impairment analysis was derived primarily from the discounted cash flows from continued future operations.

79

DTI Consolidated Statement of Cash Flows for the Year Ended December 31, 2001 (millions)

Net cash used in operating activities $ (10.8)

Net cash used in investing activities (41.2)

Cash provided by financing activities 42.9 Net decrease in cash and cash equivalents $ (9.1)

Reconciliation of DTI consolidated financial statements to DTI financial results included in Great Plains Energy consolidated financial statements (millions)

Loss before income tax benefit and extraordinary item $ (401.2)

Loss before consolidation on February 8, 2001 7.1 Goodwill write-off (60.8)

Reduction to KLT Telecom's negative investment in DTI 207.5 Total

$(247.4)

Net DTI write-off $ (195.8)

DTI operational loss, excluding net write-off (51.6)

Total equal to the above (247.4)

Other (1.0)

Total included in loss before income taxes (248.4)

Income tax benefits recorded by KLT Telecom 74.6 Loss before extraordinary item (173.8)

Early extinguishment of debt 15.9 DTI loss included in Great Plains Energy consolidated loss $ (157.9)

Extraordinary Item - Early Extinguishment of Debt The KLT Telecom gain on early extinguishment of debt resulted from DTI's completion of a successful tender offer for 50.4 percent of its outstanding Senior Discount Notes prior to KLT Telecom acquiring a majority ownership in DTI. The $15.9 million early extinguishment of debt has been reduced by the losses previously recorded by DTI but not reflected by KLT Telecom, and is net of $9.1 million of income taxes.

18. PROPOSED INTERNAL REVENUE SERVICE ADJUSTMENT - CORPORATE OWNED LIFE INSURANCE During 2000, KCP&L recorded a $12.7 million charge for the Federal and states income tax impact of the proposed disallowance of interest deductions on corporate owned life insurance loans and assessed interest on the disallowance for tax years 1994 to 1998. KCP&L believes it has complied with all applicable tax laws and regulations. As a result, KCP&L plans to vigorously contest the IRS's disallowance up to, and including, all appeals available.

80

19. QUARTERLY OPERATING RESULTS (UNAUDITED)

Quarterly operating results for Great Plains Energy and consolidated KCP&L are identical prior to the October 1, 2001, formation of a holding company. Thus, Great Plains Energy and consolidated KCP&L are presented separately below for the year 2001 to reflect the differences for the registrants in the fourth quarter. The 2000 quarterly operating results presented below represent both Great Plains Energy and consolidated KCP&L.

Great Plains Energy Quarter 1st 2nd 3rd 4th (millions) 2001 Operating revenues $280.2 $346.5 $480.9 $354.3 Operating income (loss) 7.4 75.8 131.7 (157.7)

Income (loss) before extraordinary item (3.0) 36.2 55.6 (128.8)

Net income (loss) 12.9 36.2 55.6 (128.9)

Basic and diluted earnings (loss) per common share before extraordinary item $(0.06) $ 0.58 $ 0.89 $ (2.09)

Basic and diluted earnings (loss) per common share $ 0.20 $ 0.58 $ 0.89 $ (2.09)

Basic and diluted earnings per common share in the fourth quarter of 2001 include a loss of $2.27 due to the net write-off of the investment in DTI.

Consolidated KCP&L Quarter 1st 2nd 3rd 4th (millions) 2001 Operating revenues $280.2 $346.5 $480.9 $243.3 Operating income 7.4 75.8 131.7 39.8 Income (loss) before extraordinary item (3.0) 36.2 55.6 15.0 Net income 12.9 36.2 55.6 15.0 Certain reclassifications have been made to previously reported amounts in the 2001 Form 10 Q's, reflecting audit adjustments to revenues and purchased power recorded by Strategic Energy.

There is no impact to net income as a result of these adjustments. Revenues previously reported were $281.9 million, $354.3 million, and $492.6 million for the first, second and third quarters of 2001, respectively.

81

Great Plains Energy and Consolidated KCP&L Quarter 1st 2nd 3rd 4th (millions) 2000 Operating revenues $199.3 $290.9 $378.4 $247.3 Operating income 22.0 63.3 142.2 64.8 Income before cumulative effect of changes in accounting principles 0.6 26.7 81.6 19.7 Net income 30.7 26.7 81.6 19.7 Basic and diluted earnings per common share before cumulative effect of changes in accounting principles - $0.43 $1.31 $0.31 Basic and diluted earnings per common share $ 0.49 $ 0.43 $1.31 $ 0.31 Basic and diluted earnings per common share in the third and fourth quarter of 2000, include

$0.62 and $0.48, respectively, from the sales of gas properties.

The quarterly data is subject to seasonal fluctuations with peak periods occurring during the summer months.

82

Report of Independent Accountants To the Shareholders and the Board of Directors of Great Plains Energy Incorporated:

We have audited the consolidated financial statements of Great Plains Energy Incorporated and Subsidiaries listed in the index appearing under Item 14 on page 87. These financial statements are the responsibility of the Company's management.

Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the consolidated financial statements of DTI Holdings, Inc.

and Subsidiaries (Debtors-in Possession) (an 83.6 percent owned entity), as of and for the year ended December 31, 2001, which statements reflect total assets of $53.0 million as of December 31, 2001 and total revenues of $17.4 million and a net loss of $306.1 million for the year ended December 31, 2001. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for DTI Holdings, Inc. and Subsidiaries is based solely on the report of the other auditors.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Great Plains Energy Incorporated and Subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 15 to the consolidated financial statements, the Company adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities", as amended on January 1, 2001. As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for pensions in 2000.

/s/PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP Kansas City, Missouri February 5, 2002 83

Report of Independent Accountants To the Shareholder and the Board of Directors of Kansas City Power & Light Company:

We have audited the consolidated financial statements of Kansas City Power & Light Company (a wholly-owned subsidiary of Great Plains Energy Incorporated) and Subsidiaries listed in the index appearing under Item 14 on page 87. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the consolidated financial statements of DTI Holdings, Inc. and Subsidiaries (Debtors-in-Possession)

(an 83.6 percent owned entity through September 30, 2001), as of and for the year ended December 31, 2001, which statements reflect total assets of $53.0 million as of December 31, 2001 and total revenues of $17.4 million and a net loss of $306.1 million for the year ended December 31, 2001. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for DTI Holdings, Inc. and Subsidiaries is based solely on the report of the other auditors.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Kansas City Power & Light Company and Subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 15 to the consolidated financial statements, the Company adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities",

as amended on January 1, 2001. As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for pensions in 2000.

As discussed in Note 1 to the consolidated financial statements, on October 1, 2001 the Company completed its corporate reorganization creating a holding company structure.

/s/PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP Kansas City, Missouri February 5, 2002 84

INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholders of DTI Holdings, Inc.

We have audited the accompanying balance sheets of DTI Holdings, Inc. and subsidiaries (Debtors-in Possession) (the "Company") as of December 3 1, 2000 and 200 1, and the related statements of operations and stockholder's equity (deficit) and of cash flows for the years ended June 30, 1999 and 2000, the six month period ended December 3 1, 2000 and the year ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of DTI Holdings, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years ended June 30, 1999 and 2000, the six-month period ended December 3 1, 2000 and the year ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1, the Company has filed for reorganization under Chapter It of the Federal Bankruptcy Code. The accompanying financial statements do not purport to reflect or provide for the consequences of the bankruptcy proceedings. In particular, such financial statements do not purport to show (a) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (b) as to prepetition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (c) as to stockholder accounts, the effect of any changes that may be made in the capitalization of the Company; or (d) as to operations, the effect of any changes that may be made in its business.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1, the Company's recurring losses from operations, negative working capital, and stockholders' capital deficiency raise substantial doubt about its ability to continue as a going concern. Management's plans concerning these matters are also discussed in Note 1. The financial statements do not include adjustments that might result from the outcome of this uncertainty.

As discussed in Note 3, the Company determined that the carrying value of its long-lived assets had been impaired during the year. In accordance with Financial Accounting Standards No. 121, Accountingfor the Impairment ofLong-Lived Assets andfor Long-lived Assets to be Disposedof, the Company recorded an impairment charge of approximately $342 million at December 31, 2001.

Is! DELOITTE & TOUCHE, LLP St. Louis, Missouri January 30, 2002 85

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE The Board of Directors, upon recommendation of the Board's Audit Committee, approved the engagement of the accounting firm of Deloitte & Touche LLP as the independent public accountants to audit and certify the financial statements in 2002, subject to ratification and approval by the shareholders. The services of the accounting firm of PricewaterhouseCoopers LLP, who previously served as Great Plains Energy Incorporated's and Kansas City Power & Light Company's independent public accountants, were notified on February 8, 2002, that their services would be discontinued effective with the completion of the audit of the December 31, 2001 financial statements. For further information, see the Company's Form 8-K/A dated February 8, 2002.

PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS Directors KCP&L directors are the same as those listed for Great Plains Energy. See General Note to Part II1.

Executive Officers See Part I, page 6, entitled "Executive Officers of the Registrants."

ITEM 11. EXECUTIVE COMPENSATION See General Note to Part III.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT KCP&L is solely owned by Great Plains Energy. See General Note to Part Ill.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS See General Note to Part III.

General Note To Part III Pursuant to General Instruction G to Form 10-K, the other information required by Part III (Items 10, 11, 12 and 13) of Form 10-K not disclosed above will either be (i) incorporated by reference from the Definitive Proxy Statement for Great Plains Energy's 2002 Annual Meeting of Shareholders, to be filed with the SEC not later than March 31, 2002, or (ii) included in an amendment to this report filed with the SEC on Form 10-K/A.

86

PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K Financial Statements Page No.

Great Plains Energy

a. Consolidated Statements of Income for the years ended December 31, 2001, 34 2000 and 1999

b. Consolidated Balance Sheets - December 31, 2001 and 2000 35 c Consolidated Statements of Capitalization - December 31, 2001 and 2000 36

d. Consolidated Statements of Cash Flows for the years ended December 31, 37 2001, 2000 and 1999

e. Consolidated Statements of Comprehensive Income and Consolidated 38 Statements of Retained Earnings for the years ended December 31, 2001, 2000 and 1999 KCP&L

f. Consolidated Statements of Income for the years ended December 31, 2001, 39 2000 and 1999

g. Consolidated Balance Sheets - December 31, 2001 and 2000 40 h Consolidated Statements of Capitalization - December 31, 2001 and 2000 41

i. Consolidated Statements of Cash Flows for the years ended December 31, 42 2001, 2000 and 1999

j. Consolidated Statements of Comprehensive Income and Consolidated 43 Statements of Retained Earnings for the years ended December 31, 2001, 2000 and 1999

k. Notes to Consolidated Financial Statements 44 I. Report of Independent Accountants - Great Plains Energy 83

m. Report of Independent Accountants - KCP&L 84

n. Report of Independent Accountants - DTI 85 87

Exhibits Great Plains Energy Documents Exhibit Number Description of Document 2.1

• Agreement and Plan of Merger among Kansas City Power & Light Company, Great Plains Energy Incorporated and KCP&L Merger Sub Incorporated dated as of October 1, 2001 (Exhibit 2 to Form 8-K dated October 1, 2001).

3.1.a

• Articles of Incorporation of Great Plains Energy Incorporated dated as of February 26, 2001 (Exhibit 3.i to Form 8-K filed October 1, 2001).

3.1.b

• By-laws of Great Plains Energy Incorporated dated March 13, 2001 (Exhibit 3.ii to Form 8-K filed October 1, 2001).

4.1.a

• Resolution of Board of Directors Establishing 3.80% Cumulative Preferred Stock (Exhibit 2-R to Registration Statement, Registration No. 2-40239).

4.1.b

• Resolution of Board of Directors Establishing 4.50% Cumulative Preferred Stock (Exhibit 2-T to Registration Statement, Registration No. 2-40239).

4.1.c

• Resolution of Board of Directors Establishing 4.20% Cumulative Preferred Stock (Exhibit 2-U to Registration Statement, Registration No. 2-40239).

4.1.d

• Resolution of Board of Directors Establishing 4.35% Cumulative Preferred Stock (Exhibit 2-V to Registration Statement, Registration No. 2-40239).

10.1.a

• Long-Term Incentive Plan (Exhibit 28 to Registration Statement, Registration 33-42187).

10.1.b

• Annual Incentive Compensation Plan, dated February 2001 (Exhibit 10-c to Form 10-K for the year ended December 31, 2000).

10.1 .c

• Indemnification Agreement with each officer and director (Exhibit 10-f to Form 10-K for year ended December 31, 1995).

10.1.d

• Restated Severance Agreement dated January 2000 with certain executive officers (Exhibit 1 0-e to Form 10-K for the year ended December 31, 2000).

10.1.e

• Supplemental Executive Retirement Plan Amended and Restated November 1, 2000 (Exhibit 10-f to Form 10-K for the year ended December 31, 2000).

10.1.f

• Nonqualified Deferred Compensation Plan (Exhibit 10-b to Form 10-Q for period ended March 31, 2000).

10.1.g

• Employment Agreement between KLT Inc. and Gregory J. Orman (Exhibit 10-c to Form 10-Q for period ended March 31, 2000).

10.1.h

• KLT Inc. Incentive Compensation Plan for Employees and Directors (Exhibit 10-d to Form 1 0-Q for period ended March 31, 2000).

88

10.1.i

• Amendment No. 1 to KLT Inc. Incentive Compensation Plan dated as of November 16, 2000 (Exhibit 10-j to Form 10-K for the year ended December 31, 2000).

10.1.j

• Amendment No. 2 to KLT Inc. Incentive Compensation Plan dated as of January 25, 2001 (Exhibit 10-k to Form 10-K for the year ended December 31, 2000).

10.1.k Amendment No. 3 to KLT Inc. Incentive Compensation Plan dated as of December 26, 2001.

10.1.1

• KLT Gas Inc. Incentive Compensation Plan effective January 1, 2001(Exhibit 10-1 to Form 10-K for the year ended December 31, 2000).

10.1.m Amendment No. 1 to KLT Gas Inc. Compensation Program dated as of October 31, 2001.

10.1.n

• Demand Promissory Note and Pledge Agreement between DTI Holdings, Inc. and KLT Telecom Inc. dated February 1, 2001 (Exhibit 10-t to Form 10-K for the year ended December 31, 2000).

10.1.o

• Credit Agreement between KLT Telecom Inc. and Digital Teleport Inc. dated February 21, 2001 (Exhibit 10-u to Form 10-K for the year ended December 31, 2000).

10.1.p

• Amendment Number 1 dated April 30, 2001, to Credit Agreement among KLT Telecom Inc. and Digital Teleport, Inc. (Exhibit 10-c to Form 10-Q for the period ended June 30, 2001).

10.1.q

• Amendment No. 2 dated June 4, 2001 to Credit Agreement between KLT Telecom Inc. and Digital Teleport Inc. (Exhibit 10-c to 10-Q for quarter ended June 30, 2001).

10.1.r

• Credit Agreement between KLT Telecom Inc. and Digital Teleport Inc. dated as of September 25, 2001 (Exhibit 10 to Form 10-Q for period ended September 30, 2001).

10.1.s First Amendment dated as of October 23, 2001 to Credit Agreement between KLT Telecom Inc. and Digital Teleport Inc.

10.1.t Guaranty and Suretyship Agreement, dated as of March 30, 2001, by KLT Inc. in favor of PNC Bank, National Association.

10.1.u Promissory Note between Strategic Energy, L.L.C. and Custom Energy Holdings, L.L.C. dated September 14, 2001.

10.1.v Credit Agreement dated as of October 3, 2001 among Great Plains Energy Incorporated and Bank One, NA.

16.1 Letter of PricewaterhouseCoopers LLP (Exhibit 16 to Form 8-K/A dated February 8, 2002).

89

21.1 List of Wholly-Owned Subsidiaries of Great Plains Energy Inc.

23.1 .a Consent of Counsel.

23.1 .b Consent of Independent Accountants-PricewaterhouseCoopers LLP.

23.1.c Consent of Independent Accountants-Deloitte & Touche LLP.

24.1 Powers of Attorney.

• Filed with the SEC as exhibits to prior registrationstatements (except as otherwise noted) and are incorporatedherein by reference and made a part hereof The exhibit number and file number of the documents so filed, and incorporatedherein by reference, are stated in parenthesisin the description of such exhibit.

Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from Great PlainsEnergy upon written request KCP&L Documents Exhibit Number Description of Document 2.2

• Agreement and Plan of Merger among Kansas City Power & Light Company, Great Plains Energy Incorporated and KCP&L Merger Sub Incorporated dated as of October 1, 2001 (Exhibit 2 to Form 8-K dated October 1, 2001).

3.2.a

• Restated Articles of Consolidation of KCP&L, as amended October 1, 2001 (Exhibit 3-(i) to Form 10-Q for quarter ended September 30, 2001).

3.2.b

• By-laws of KCP&L, as amended and in effect on November 7, 2000 (Exhibit 3-b to Form IO-K for the year ended December 31, 2000).

4.2.a

• General Mortgage and Deed of Trust dated as of December 1, 1986, between KCP&L and UMB Bank, n.a. (formerly United Missouri Bank) of Kansas City, N.A., Trustee (Exhibit 4-bb to Form 10-K for the year ended December 31, 1986).

4.2.b

• Fourth Supplemental Indenture dated as of February 15, 1992, to Indenture dated as of December 1, 1986 (Exhibit 4-y to Form 10-K for year ended December 31, 1991).

4.2.c

• Fifth Supplemental Indenture dated as of September 15, 1992, to Indenture dated as of December 1, 1986 (Exhibit 4-a to Form 10-Q for the quarter ended September 30, 1992).

4.2.d

• Sixth Supplemental Indenture dated as of November 1, 1992, to Indenture dated as of December 1, 1986 (Exhibit 4-z to Registration Statement, Registration No. 33-54196).

4.2.e

• Seventh Supplemental Indenture dated as of October 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4-a to Form 10-Q for the quarter ended September 30, 1993).

90

4.2.f Eighth Supplemental Indenture dated as of December 1, 1993, to Indenture dated as of December 1, 1986 (Exhibit 4 to Registration Statement, Registration No. 33-51799).

4.2.g Ninth Supplemental Indenture dated as of February 1, 1994, to Indenture dated as of December 1, 1986 (Exhibit 4-h to Form 10-K for year ended December 31, 1993).

4.2.h

• Tenth Supplemental Indenture dated as of November 1, 1994, to Indenture dated as of December 1, 1986 (Exhibit 4-1 to Form 10-K for year ended December 31, 1994).

- 4.2.i

• Indenture for Medium-Term Note Program dated as of February 15, 1992, between KCP&L and The Bank of New York (Exhibit 4-bb to Registration Statement, Registration No. 33-45736).

4.2.j

• Indenture for Medium-Term Note Program dated as of November 15, 1992, between KCP&L and The Bank of New York (Exhibit 4-aa to Registration Statement, Registration No. 33-54196).

4.2.k

• Indenture for Medium-Term Note Program dated as of November 17, 1994, between KCP&L and The Bank of New York (Exhibit 4-s to Form 10-K for year ended December 31, 1994).

4.2.1

• Indenture for Medium-Term Note Program dated as of December 1, 1996, between KCP&L and The Bank of New York (Exhibit 4 to Registration Statement, Registration No. 333-17285).

4.2.m

• Amended and Restated Declaration of Trust of KCP&L Financing I dated April 15, 1997 (Exhibit 4-a to Form 10-Q for quarter ended March 31, 1997).

4.2.n Indenture dated as of April 1, 1997 between the Company and The First National Bank of Chicago, Trustee (Exhibit 4-b to Form 1O-Q for quarter ended March 31, 1997).

4.2.o First Supplemental Indenture dated as of April 1, 1997 to the Indenture dated as of April 1, 1997 between the Company and The First National Bank of Chicago, Trustee (Exhibit 4-c to Form 1 0-Q for quarter ended March 31, 1997).

4.2.p Preferred Securities Guarantee Agreement dated April 15, 1997 (Exhibit 4-d to Form 10-Q for quarter ended March 31, 1997).

4.2.q Indenture dated as of December 1, 2000, between Kansas City Power & Light Company and The Bank of New York (Exhibit 4-a to Report on Form 8-K dated December 18, 2000).

10.2.a

• Railcar Lease dated as of April 15, 1994, between Shawmut Bank Connecticut, National Association, and KCP&L (Exhibit 10 to Form 10-Q for period ended June 30, 1994).

10.2.b

• Railcar Lease dated as of January 31, 1995, between First Security Bank of Utah, National Association, and KCP&L (Exhibit 1O-o to Form 1O-K for year ended December 31, 1994).

- 10.2.c

• Railcar Lease dated as of September 8, 1998, with CCG Trust Corporation (Exhibit 10(b) to Form 10-Q for period ended September 30, 1998).

91

10.2.d Amended and Restated Lease dated as of October 12, 2001 between Kansas City Power & Light Company and Wells Fargo Bank Northwest, National Association.

10.2.e

• Purchase and Sale Agreement dated October 29, 1999 between KCP&L and Kansas City Power & Light Receivables Company (Exhibit 10-m to Form 10-K for year ended December 31, 1999).

16.2

• Letter of PricewaterhouseCoopers LLP (Exhibit 16 to Form 8-K/A dated February 8, 2002).

23.2.a Consent of Counsel.

23.2.b Consent of Independent Accountants - PricewaterhouseCoopers LLP.

24.2 Powers of Attorney.

• Filed with the SEC as exhibits to prior registrationstatements (except as otherwise noted) and are incorporatedherein by reference and made a part hereof. The exhibit number and file number of the documents so filed, and incorporatedherein by reference, are stated in parenthesisin the description of such exhibit.

Copies of any of the exhibits filed with the SEC in connection with this document may be obtained from KCP&L upon written request.

Reports on Form 8-K Great Plains Energy Great Plains Energy filed a report on Form 8-K with the SEC dated October 1, 2001 with attached documents in connection with the completion of a corporate restructuring.

Great Plains Energy filed a report on Form 8-K with the SEC dated October 9, 2001, providing an update on the financial condition of DTI Holdings, Inc. and Digital Teleport, Inc.

Great Plains Energy filed a report on Form 8-K with the SEC dated December 31, 2001 regarding the filing of voluntary petition for reorganization under Chapter 11 of the U.S. bankruptcy code by DTI Holdings, Inc. and Digital Teleport, Inc.

Great Plains Energy filed a report on Form 8-K/A with the SEC dated February 8, 2002 regarding a change in the certifying accountants for 2002.

KCP&L KCP&L filed a report on Form 8-K with the SEC dated October 10, 2001 with attached documents in connection with the completion of a corporate restructuring.

KCP&L filed a report on Form 8-K with the SEC dated November 19, 2001 with attached documents in connection with the issuance of $150,000,000 aggregate principal amount of 6.50% Senior Notes.

KCP&L filed a report on Form 8-K/A with the SEC dated February 8, 2002 regarding a change in the certifying accountants for 2002.

92

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Kansas City, and State of Missouri on the 26th day of February, 2002.

GREAT PLAINS ENERGY INCORPORATED By /s/Bernard J. Beaudoin Chairman of the Board Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title Date

/s/Bernard J. Beaudoin Chairman of the Board, President )

(Bernard J. Beaudoin) and Chief Executive Officer )

(Principal Executive Officer) )

)

/s/Andrea F. Bielsker Vice President - Finance, )

(Andrea F. Bielsker) Chief Financial Officer and )

Treasurer )

(Principal Financial Officer) )

/s/Neil Roadman Controller )

(Neil Roadman) (Principal Accounting Officer) )

David L. Bodde* Director ) February 26, 2002

)

Mark A. Ernst* Director

)

William K. Hall* Director )

)

Luis A. Jimenez* Director )

)

William C. Nelson* Director )

)

Linda Hood Talbott* Director )

Robert H. West* Director

• By Is/Bernard J. Beaudoin (Bernard J. Beaudoin)

Attorney-in-Fact*

93

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Kansas City, and State of Missouri on the 26th day of February, 2002.

KANSAS CITY POWER & LIGHT COMPANY By /s/Bernard J. Beaudoin Chairman of the Board Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title Date

/s/Bernard J. Beaudoin Chairman of the Board, President (Bernard J. Beaudoin) and Chief Executive Officer (Principal Executive Officer)

/s/Andrea F. Bielsker Vice President - Finance, (Andrea F. Bielsker) Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/Neil Roadman Controller (Neil Roadman) (Principal Accounting Officer)

David L. Bodde* Director February 26, 2002 Mark A. Ernst* Director William K. Hall* Director Luis A. Jimenez* Director William C. Nelson* Director Linda Hood Talbott* Director Robert H. West* Director

• By /s/Bernard J. Beaudoin (Bernard J. Beaudoin)

Attorney-in-Fact*

94