ML051450085

Transmittal of 2004 Annual Financial Reports

ML051450085
Person / Time
Site:	Wolf Creek
Issue date:	05/18/2005
From:	Moles K Wolf Creek
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RA 05-0060
Download: ML051450085 (243)

Text

'NUCLEAR OPERATING CORPORATION Kevin J. Moles Manager Regulatory Affairs May 18, 2005 RA 05-0060 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Docket No. 50-482: Transmittal of 2004 Annual Financial Reports Gentlemen: -

Wolf Creek Nuclear Operating Corporation is transmitting one copy each of the 2004 annual reports, including financial statements for its owners: Kansas Gas and Electric Company (KGE), a wholly-owned subsidiary of Westar Energy, Inc., Kansas City Power & Light Company (KCPL), a wholly-owned subsidiary of Great Plains Energy Incorporated, and Kansas Electric Power Cooperative, Inc. (KEPCo). 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) 364-4126, or Diane Hooper at (620) 364-4041.

-- -Very truly yours,

-~ ~~ - -- Kvin J. M KJM/rIg Enclosures (3) cc: J.: N. Donohew (NRC), w/e D. N. Graves (NRC), wle B. S. Mallett (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/HCANET

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TABLE OF CONTENTS Letter to Shareholders ....... . 1 Blurring the Lines Between -

Power Plants and Service Reliability .................. 3

.2.

2004 Financial Measures ...... 8 1.Doug Simrell, troubleshooter, completes a pole replacement after the January 2005 ice storm in Wichita. 2. Employees like Form 10-K .. ... 9 Simrell depend on Larry Heinrich, live line equipment tester, to ensure that rubber gloves they use when working on energized Shareholder Information equipment are without defect. 3. Patrice Poole, human resources clerk, assists Wichita employees. 4. Suzanne Coin, community and Assistance .............. 72 support representative, is a community liaison for Westar Energy.

S. Tom Homewood, cable splicer, journeyman, helps provide reli-Corporate Information ....... 72 able power to Wichita customers. 6. Dale Renner, service opera-tor, directs crews to their next assignment. 7.Kyle Hazelwood, :

Directors and Officers ........ 73 cable splicer apprentice, left, works under the watchful eye of 'I:

Terry Fleming, cable foreman.

2 004 ANN UAL REPO RT DEAR FELLOW SHAREHOLDER:

Here, in summary, are highlights of what Westar Energy accomplished in 2004.

In February we closed the sale of Protection One and thereby fulfilled our pledge to return Westar to a pure electric utility.Through early calls and timely retirements, we reduced utility debt by $533 million - on top of the $966 million by which we reduced debt in 2003. These debt reductions combined with the issue of 12.1 million shares of new equity last spring brought our balance sheet to 45% equity, from less than 30%

in 2002. Those debt reductions, combined with the refinancing of $900 million of our remaining $1.7 billion of debt, have reduced our annual interest expense by more than $110 million. Our first mortgage bonds are once again rated investment grade by the three rating services that follow us.

In December our board increased the common dividend to an indicated annual level of 92 cents from 76 cents. We expect to review the dividend again in early 2006. The year end closing price for our common shares was $22.87, a $2.62 gain over the 2003 year end close of $20.25. The total return to Westar shareholders in 2004 was 17.4%. For 2003 and 2004 together, the total return was 152%.

Although summer weather was 16% cooler than average, we achieved financial results in line with our announced earnings guidance.

It is discouraging when our equipment doesn't operate the way we wish it would, as was the case last January when the generator rotor at one of our Jeffrey Energy Center coal units failed. But it was encouraging to see our employees working brilliantly to get the unit back on-line in just 23 days, cutting the expected downtime virtually in half. Work like that enabled us to meet our targeted margins for wholesale sales.

We exceeded our goals for transmission and distribution system reliability. The average number of outages per customer was 1.47 versus our goal of 1.70. And the average length of an outage was 139 minutes versus our goal of 162 minutes. We improved customer service in other important ways as well. In our call center we achieved an answered call rate above 95%, including times when tens of thousands of our customers were without power due to severe storms.

Safety is first among our three core values. In 2004 we set new standards for industrial safety as measured by the number of injuries requiring medical attention per 100 employees (OSHA incident rate).The OSHA rate of 1.55 in our power plants was the lowest that it has ever been. That rate compares with an industry average for power plants of 4.15. In our transmission and distribution operations, our OSHA rate was 2.78.

It was 5.32 in 2003. The industry average is 5.17.

An important focus in the last two years has been compliance with the letter and spirit of the Sarbanes-Oxley Act of 2002 regarding corporate governance, financial disclosure, and internal controls. Elsewhere in this report we hope you note that Messrs. Haines and Ruelle (our CFO) have attested to the effectiveness of our internal controls.

-1 2 004 ANN UAL REPO RT Our employees and retirees continue to be leaders in their communities. Employees increased their annual contributions to the United Way by 20%. Employees and retirees volunteered over 83,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of community service in 2004, a 15% increase over 2003. Through our School Connections program, our active and retired employees volunteer in many schools throughout our service area. Our employees collected more than 83,000 pounds of food to replenish the shelves of food banks in eastern Kansas.

Our Green Team completed 57 conservation projects in 2004. Notably, the Green Team has committed to provide 5,000 volunteer hours for improvement projects at the Tallgrass Prairie National Preserve.

Looking forward, as the last step in the restructuring plan approved by the Kansas Corporation Commission in July 2003, we will go through a review of our rates in 2005. Our operating and financial results for 2004 will serve as the basis for the review, which we expect to conclude by year end. We welcome this review and see it as an opportunity to make sure our rates are fair and logical and to demonstrate that we are doing a good job for our customers. On average, our rates are the lowest in Kansas and are 18%

to 26% below the national average.

We continue to deal with investigation and litigation related to matters discussed at length in the Report of the Special Committee to the Board of Directors, released in May 2003. Those matters are discussed in our 2004 Form 10-K that is incorporated in this report.

In January 2005 eastern Kansas was hit with the most destructive ice storm in Westar's history. More than 260,000 of our customers lost power in that storm, many more than once. Our employees, with help from contractors and other utility companies from across the nation, worked safely and indefatigably for 10 days on the restoration effort. This storm was a severe test of our resolve to be focused on customer service. The Wichita Eagle had this to say about our effort:

'Westar Energy utility workers, city tree trimmers and others who worked tirelessly to restore power and street access to thousands of Wchitans after the recent ice storm deserve a hearty thanks from this community."

Finally, we are very pleased to report that in September, Dr. Jerry Farley, President of Washburn University, and Ms. Sandra Lawrence, Vice President of Midwest Research Institute, joined our board. Their skills, experience, and insight have added more depth and balance to our board and will be of substantial benefit to the company.

We appreciate your confidence.

Sincerely, Charles Q. Chandler IV . Haines, aJames Jr.

Chairman of the Board President & CEO 2

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2 004 ANN U AL REPO RT Blurring the Lines Between Power Plants and Service Reliability FuelforThought in a New Energy Era By James Haines The electric power industry nearly always has measured service A few national and Westar Energy specific facts help frame reliability not by the operation of the power plants that make discussion of this issue:

electricity, but by the performance of the towers, poles, lines,

• Based on current consumption, extraction technology, and transformers, and associated equipment and facilities that economics, U.S. domestic supplies of coal and uranium will deliver it - the wires. When the wires have succumbed to the last for centuries, while supplies of natural gas are declining precipitously.

stress of constant use, severe weather, vehicles, squirrels and birds, tree limbs, vandals, and errant construction digging

• Since 1990, about 85% of new power plants have been fueled by natural gas, 5% by coal.

power plants have continued to operate. Indeed, when we flip

• No new nuclear power plants have been ordered for a switch, if we even think about electric service reliability, we construction in the U.S. since 1978. None ordered after 1973 think of the wires - we think of bucket trucks and linemen were completed.

climbing poles.

• In 2003, fossil fueled power plants accounted for 11% of all carbon monoxide, nitrogen oxide, sulphur dioxide, volatile In coming years, however, flipping a switch may make us pause organic compounds, and particulate emissions from U.S.

to wonder if the wind is blowing, the sun is shining, there is gas sources; motor vehicles accounted for 48%.

in the pipeline, or the limit for emissions from the coal plants

• Since 1980, power plant emissions have declined by about has been exceeded. We face the prospect that electric service 35%.

reliability will become more vulnerable to power plant availability

• Air pollution emissions from U.S. nuclear power plants:

thanfailures in the wires. That would be a dire outcome - while none.

recovery from a wires failure takes hours or days, recovery

• More than 95% of the electricity that Westar generated in from problems that could affect power plant availability, e.g. 2004 came from its coal and uranium fueled plants.

fuel supply or environmental constraints or insufficient

• The MW weighted average age of those plants has increased capital, could take years. Fortunately, we can greatly reduce, if from just over eight years in 1985 to just over 27 years in 2004.

not eliminate, this danger through sound energy policies and

• Expected availability on demand from a coal plant: almost prudent management. 90%; from a wind turbine: when the wind blows.

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2 0 04 ANN UAL REPO RT A Transition Between Two Energy Eras mental concerns were greatly reduced. Accordingly, virtually all of the unregulated power plants built in the '90's were fueled I believe we are in a transition between two energy eras. The with natural gas. With subsequent sharp increases in the cost of first, which covered roughly the 20th century, was characterized gas, many of those plants are now underutilized.

by abundant and ever cheaper energy - especially electricity.

During that era, electricity became the energy form of choice. It is a subtle irony that developers of unregulated plants relied Demand doubled every 10 years until the early '70's. In the last on natural gas, a relatively scarce resource, over coal, our most 25 years of that era, several factors signaled its end. abundant energy resource. Coal fueled plants, of course, require much more capital up front, are more difficult to site and The oil embargoes of the'70's showed the vulnerability of the permit, take longer to build, and are subject to increasingly U.S. economy to dependence upon foreign energy resources.

more stringent and costly environmental controls. It appears Resulting increases in energy prices contributed to a stagnant that the success of competitive retail electricity markets economy and rampant inflation - stagflation. Annual electric depended upon a very thin reed: cheap gas.

demand growth slowed to 2% from 7%. The electric industry and its regulators were unable to cope with the financial conse- The emergence of the Chinese economy punctuated the close quences of such slower growth. Electric utility credit quality of the former era. From 1990 through 2004, China's GDP slipped from an average of AA- to BBB. There was growing averaged year over year growth above 9%. From 1900 to 1950, recognition that burning fossil fuels, e.g. to make electricity and as the U.S. economy modernized and its population doubled to power vehicles, can harm the environment.Virtually unknown 152 million, its energy use quadrupled. Imagine the growing in 1975, concerns about "global warming" and "greenhouse energy needs of over 1 billion people in an economy going gases"dominated energy policy debate by 2000.

through a similar metamorphosis. Add to that the energy needs Electricity price increases in the'70's and early'80's, as well as of other developing nations. And add to that the energy needed projected supply shortages in the'90's, led many to conclude to sustain growth in developed economies in the U.S., Japan, that regulated retail monopoly markets for electricity were and Western Europe. Finally, add the need to protect global grossly inefficient and that a shift to competition would assure environmental quality.

renewed abundance and lower prices. The last gasp of the former All the above factors point to increasingpressure not on the wires era was a series of experiments with competitive retail elec-that distribute electricity but on the plants and fuel necessary to tricity markets in the late '90's with results that ranged from produce it.

lackluster to colossal failure.

Natural gas fueled the enthusiasm for retail competition.

Significantly more efficient gas plant technology came to the Characteristics of the New Era fore in the'90's. Additionally, gas fueled plants were easy to In the new era, policy makers will finally recognize that it is permit, fast to build, and relatively cheap. They were believed better to embrace and perfect the use of virtually unlimited and to have a significantly shorter and therefore a more certain reliable energy resources under our control than to fight about payback. Gas also is substantially cleaner than coal so environ- relatively limited energy resources under the control of others. In the 4

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2 004 ANN UAL REPO RT new era, routine use of the most dear fuels - natural gas and plants will require costly upgrades to comply with more oil - to make electricity will sharply decline. Ultimately these stringent environmental regulations, those upgrades will be fuels will be used sparingly to generate electricity - only in significantly less expensive than replacement with new plants.

peak and emergency conditions. Existing nuclear plants also have attractive opportunities for life extension. Consequently, customers of utilities with substantial Developing economies will compete more vigorously for their existing coal and uranium fueled plants will be advantaged in share of the Earth's resources, seeking to reduce barriers to the new era.

their own development and perhaps erecting barriers for others. For all economies, but especially developed ones, energy Increased uranium use will require the political resolve to independence will become increasingly important. The difficulty of develop a permanent facility for disposing of highly radioactive this for the U.S. cannot be overstated. At 20 million barrels per nuclear waste. The prospects for this, however, are not good.

day, the U.S. consumes approximately four times more oil than After collecting $20 billion to develop a permanent storage it produces. facility for highly radioactive waste from nuclear power plants, the Department of Energy has failed to do so.

As harm to the environment from using fossil fuels becomes more definable, energy policy will center more and more on Certainly, as the price of electricity increases, more substitutes environmental concerns. Our most abundant domestic energy for electricity will become viable and improved efficiency in the resource, coal, presents significant environmental challenges. use of electricity will become more important. Substantial Technologies under development, however, promise to dra- research and development will be devoted to alternative and matically lower emissions from coal fueled power plants and renewable forms of electricity generation. While these forms existing coal plants can be modified to greatly reduce their will reduce some dependence on coal and uranium, they will emissions. These improvements, though, will substantially not eliminate the need for plants that provide electricity on increase the cost of coal-generated electricity. We can moderate demand. Our growing reliance on digital technology will only the increased use of coal only if, once again, we embrace increase the importance of continuous and reliable supplies of nuclear power - itself with high upfront capital costs and its electricity. It won't dofor utilities to tell customers that power is not own set of political and environmental concerns. To help available because the wind has died or the sun is behind a cloud.

overcome uncertainty and achieve energy independence, our national energy policy must rely on both fuels.

Finding Light at the End of the Transition With the rise of global terrorism, the security of our energy The most important issue for the electric power industry in the infrastructure will become as important as environmental pro-U.S. is regulatory certainty, according to a 2004 survey of tection. That will simply underscore the importance of energy industry leaders. This is not surprising. Concern for certainty is independence.

likely highest during transition periods when established Supplies of coal and uranium will remain abundant, but the practices and rules are in flux. This is especially so in the electric cost of converting them to electricity without unacceptable risk industry, which is not only capital intensive but also is required to the environment will be substantial. While existing coal to put its capital at risk in cycles of 50 years or more.

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2004 ANNUAL REPORT If the transition is mishandled, electric service outages will 5. Finally, the Kansas Legislature, through recently enacted become a way of life. To failures in the wires as causes of legislation, has created a more favorable environment in outages, we will add shortages of natural gas and oil, Kansas for constructing generation and transmission facil-environmental alerts, terrorist attacks, and insufficient capital. ities. Among other things, this legislation greatly simplifies And to the extent the U.S. remains dependent on foreign and streamlines the process for siting transmission lines.

energy resources, a U.S. presence and influence will remain Other recent legislation requires the Kansas Corporation necessary in areas that historically have been politically volatile. Commission, prior to the start of construction, to make binding determinations of the rate treatment of very long-If the transition is well handled, hallmarks of the new energy lived transmission and generation facilities and permits it to era will be further dramatic reductions in harmful emissions include in rates the value of generating facilities while under from power plants, increased reliance on coal and renewed use construction.

of uranium, sparing use of natural gas and oil, emergence of alternative electricity generation technologies as significant sources - and higher prices. Higher prices will mean greater The "Weather" Will Be Stormy emphasis on conservation and efficiency, including capital WChile the above factors show Westar well suited to successfully investment that promises to reduce fuel use. complete this transition, at times the political and regulatory "weather"will be stormy. These storms will be severe if policy makers in the new era rely on the regulatory paradigm of the How Will Westar Energy Fare?

former era.

How will Westar Energy fare in the new energy era? Well, we believe. Consider: In the new era, new facilities will need to be built. Perhaps less obvious, but of greater consequence for companies like WIestar,

1. Without distraction, we will be focused on satisfying the existing facilities will need mid or even late life"makeovers"to electric energy needs of our customers. As we committed to satisfy more rigorous environmental standards and extend their do two years ago, we have returned to being a pure utility.

useful lives. Both will require substantial amounts of capital.

We have reduced debt by nearly $2 billion and significantly Uncertainty makes investors cautious at best; at worst they improved our financial stability. Our financial obligations and invest elsewhere.

structure are now consistent with our public service obligation.

2. We have an ideal mix of generation facilities. Although we Why might investors be cautious? Consider their experience in have the capability to generate substantial electricity with the last 25 years of the former era. At the beginning of that natural gas and oil, for normal operation almost all of our period, warnings of natural gas shortages culminated in policy electricity is made with coal or uranium. makers passing the Fuel Use Act in 1978 that required utilities to phase out the use of natural gas in power plants. In response,

3. Our coal supplies are very low in sulfur content.

many utilities launched massive construction programs to

4. Kansas policy makers appropriately considered and rejected replace gas fueled plants with those using coal and uranium.

a change to retail competition. As a result, Westar remains And then, through so-called prudence reviews, when those an integrated company. Our business strategy is matched facilities began operation they were judged to be unneeded and 6 with our public service obligation, and both are well matched to have been imprudently managed. As a result, billions of with our resources. dollars of investment in those new facilities were disallowed.

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20 04 ANN U AL REPO RT Yet virtually all of those facilities are in service today and without In the new era, energy policy makers must focus not on the lowest them the U.S. economy would be in shamblesfor want of affordable possible prices in the short run (treating electricity like a mere and adequate supplies of electricity. commodity) but on the lowest possible prices consistent with sustainedhigh quality, reliable service in the long run. Prices must Then in the '90's, in response to the siren song of competitive be high enough to allow investment in the maintenance, markets (i.e. lower prices for consumers and high profits for renovation, and new construction necessary to serve growing entrepreneurs), massive amounts of capital were invested in demand for electricity, satisfy increasingly higher service quality unregulated natural gas fueled plants. Ephemeral though it standards, and comply with more rigorous regulations neces-was, natural gas prices were so low and foresight so blinded sary to assure a cleaner environment. The goal of policy makers that construction of new coal plants came to a virtual standstill should be to set prices at levels that permit companies to build and some coal and nuclear plants were sold at deeply and sustain the financial strength necessary to access capital on discounted prices. But, as gas became dear, many gas plants favorable terms for the long term. In the new era, the ability to were cancelled and of the ones that were completed few have plan ahead and raise the necessary capital for long lead time met the expectations of their initial investors.

generation projects will require robust financial health. The payoff for customers will be great and the near term cost will be There is at least one important lesson in the failed attempts by regulators, through prudence reviews and other expedients, insignificant compared with the long term benefits.

and by legislators, through "experiments" with retail competi-tion, to keep prices low in the short run. Eventually customers Back to the Future must pay the real costs of producing and distributing reliable, Reliable electric service is not established in a day, a week, a clean electricity. Avoiding such costs in the short run only month, or even a year. Once achieved it must be maintained increases them at a compound rate in the long run. When you because it cannot be readily recreated at the dire moment of pay later, you pay more not only to reflect the cost of money but need. To borrow from a popular movie of the former era, it's also to compensate for the increased risk of default. It is no time to go Back to the Future. It's time to learn from past mistakes accident that now unregulated developers of both conventional and go back to a management and regulatory model that was and alternative sources of electric energy require long term never broken but can be made better.

power sales agreements before the first spade of dirt is turned.

Finally, as electric service reliability becomes more dependent Against that backdrop it is understandable that potential upon power plant availability, integrated companies like Westar investors in regulated sources of electric energy might be with strong ties to the communities in which they do business cautious and require some level of certainty before committing are more likely to remain loyal to the letter and spirit of their billions of dollars to refurbish existing plants or build new ones.

public service obligation than unregulated generating compa-The length of the capital recovery cycle for new coal and nies without any wires business. The former provides a service, uranium generating facilities could be 50 years or more. In the latter merely trades in a commodity.

the new era, it will be the responsibility of management and regulators to work together to create a reliable energy policy environment so that such long term capital needs can be satisfied on reasonable terms. 7

2 004 ANN UAL REPO RT FINANCIAL MEASURES 2004 2004 2003 FINANCIAL DATA (Dollars in Millions)

INCOME HIGHLIGHTS Sales . ............................................................ $1,464 $1,461 Income from continuing operations ......... ......................... 100 163 Results of discontinued operations, net of tax ....... ................... 79 (78)

Earnings available for common stock ......... ........................ 178 84 BALANCE SHEET HIGHLIGHTS Total assets ....................................................... 5,086 5,743 Common stock equity . ............................................. 1,388 1,015 Capital Structure:

Common equity ................... ........................... 45% 31%

Preferred stock . .............................................. 1% 1%

Debt . ........................................................ 54% 68%

OPERATING DATA Sales (Thousands of MNBh)

Retail . ....................................................... 18,364 18,384 Wholesale .................................................... 8,688 8,666 Customers ....................................................... 653,000 644,000 COMMON STOCK DATA PER SHARE HIGHLIGHTS Earnings per share:

Basic earnings from continuing operations ....... ................. $1.19 $2.24 Discontinued operations, net of tax ........ ...................... $0.95 $(1.08)

Basic earnings available ............. ........................... $2.14 $1.16 Dividends declared per common share ......... ....................... $0.80 $0.76 Book value per share . ............................................... $16.13 $13.98 STOCK PRICE PERFORMANCE Common stock price range:

High .................. ...................................... 522.92 $20.49 Low ............... ......................................... $18.06 $9.76 Stock price at year end ................. ............................ $22.87 $20.25 Stock price appreciation ................ ............................ 12.94% 104.55%

Total return (assumes reinvested dividends) ........ ................... 17.37% 114.47%

Average equivalent common shares outstanding ....... ................ 82,941,374 72,428,728 8 Dividend yield (based on year end annualized dividend) ...... ........... 4.0% 3.8%

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2 0 04 ANN UAL REPO RT UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K FXI ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2004 OR L 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 WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

Kansas 48-0290150 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer 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:

Common Stock, par value $5.00 per share New York Stock Exchange (Title of each class) (Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act:

Preferred Stock, 4-112% Series, $100 par value (fitle 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 Fx No a 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. n Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes[ ] No Fl The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately

$1,706,425,434 at June 30, 2004.

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

Common Stock, par value $5.00 per share 86,400,384 shares (Class) (Outstanding at March 1,2005)

DOCUMENTS INCORPORATED BY

REFERENCE:

9 Description of the document Part of the Form 10-K Portions of the Westar Energy, Inc. definitive proxy Part III (Item 10 through Item 14) statement to be used in connection with the registrant's (Portions of Item 10 are not incorporated 2005 Annual Meeting of Shareholders by reference and are provided herein)

2 004 ANN UAL REPO RT TABLE OF CONTENTS FORWARD-LOOKING STATEMENTS PAGE Certain matters discussed in this Annual Report on Form 10-K are PART I "forward-looking statements."The Private Securities Litigation Reform Act of 1995 has established that these statements qualify Item 1. Business. 11 for safe harbors from liability. Forward-looking statements may Item 2. Properties. 21 include words like we "believe,""anticipate,""target,""expect,""pro forma," "estimate,"'"intend" and words of similar meaning.

Item 3. Legal Proceedings. 21 Forward-looking statements describe our future plans, objectives, Item 4. Submission of Matters to aVote expectations or goals. Such statements address future events and of Security Holders. 21 conditions concerning: capital expenditures; earnings; liquidity and capital resources; litigation; accounting matters; possible PART 11 corporate restructurings, acquisitions and dispositions; compliance with debt and other restrictive covenants; interest rates and Item 5. Market for Registrant's dividends; environmental matters; nuclear operations; and the Common Equity and Related overall economy of our service area.

Stockholder Matters. 22 Item 6. Selected Financial Data. 22 What happens in each case could vary materially from what we expect because of such things as: electric utility deregulation or Item 7. Management's Discussion and re-regulation; regulated and competitive markets; ongoing Analysis of Financial Condition municipal, state and federal activities; economic and capital market and Results of Operations. 23 conditions; changes in accounting requirements and other Item 7A. Quantitative and Qualitative accounting matters; changing weather; rates, cost recoveries and Disclosures About Market Risk. 32 other regulatory matters; the impact of changes and downturns in the energy industry and the market for trading wholesale Item 8. Financial Statements and electricity; the outcome of the notice of violation received on Supplementary Data. 34 January 22, 2004 from the Environmental Protection Agency and Item 9. Changes in and Disagreements other environmental matters; political, legislative, judicial and With Accountants on Accounting regulatory developments; the impact of the purported shareholder and Financial Disclosure. 66 and employee class action lawsuits filed against us; the impact of Item 9A. Controls and Procedures. 66 our potential liability to David C. Wittig and Douglas T. Lake for unpaid compensation and benefits and the impact of claims they Item 9B. Other Information. 66 have made against us related to the termination of their employment and the publication of the report of the special PART III committee of the board of directors; the impact of changes in Item 10. Directors and Executive Officers interest rates; changes in, and the discount rate assumptions used of the Registrant. 66 for, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed Item 11. Executive Compensation. 66 investment returns on pension plan assets; the impact of changing Item 12. Security Ownership of interest rates and other assumptions on our nuclear decom-Certain Beneficial Owners missioning liability for Wolf Creek Generating Station; Kansas and Management. 66 Corporation Commission and the North American Electric Item 13. Certain Relationships and Reliability Council's utility service reliability standards; homeland security considerations; coal, natural gas, oil and wholesale Related Transactions. 66 electricity prices; availability and timely provision of rail transpor-Item 14. Principal Accountant Fees tation for our coal supply; and other circumstances affecting and Services. 66 anticipated operations, sales and costs.

PART IV These lists are not all-inclusive because it is not possible to predict all factors.This report should be read in its entirety. No one section Item 15. Exhibits and Financial Statement of this report deals with all aspects of the subject matter. Any Schedules. 67 forward-looking statement speaks only as of the date such Signatures. 71 statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.

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2004 ANNUAL REPORT PART I customers in south-central and southeastern Kansas. We also ITEM 1. BUSINESS supply electric energy at wholesale to the electric distribution systems of 54 cities in Kansas and four electric cooperatives that GENERAL serve rural areas of Kansas. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, We are the largest electric utility in Kansas. Unless the context we engage in energy marketing and purchase and sell wholesale otherwise indicates, all references in this Annual Report on Form electricity in areas outside our historical retail service territory.

10-K to "the company," "we,"" us," "our" and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The Generation Capacity term "Westar Energy" refers to Westar Energy, Inc., a Kansas We have 5,844 megawatts (MW) of generating capacity, of which corporation incorporated in 1924, alone and not together with its 2,587 MW is owned or leased by KGE. See"Item 2. Properties"for consolidated subsidiaries. additional information on our generating units. The capacity by fuel type is summarized below.

We provide electric generation, transmission and distribution services to approximately 653,000 customers in Kansas. Westar Capacity Percent of FuelType (MW) Total Capacity Energy provides these services in central and northeastern Kansas, Coal ........................................... 3,292.0 56.3 including the cities of Topeka, Lawrence, Manhattan, Salina and Nuclear ........................................ 548.0 9.4 Hutchinson. Kansas Gas and Electric Company (KGE), Westar Natural gas or oil ................................. 1,920.0 32.9 Energy's wholly owned subsidiary, provides these services in Diesel fuel ...................................... 83.0 1.4 south-central and southeastern Kansas, including the city of Wichita, Kansas. Both Westar Energy and KGE conduct business Wind .......................................... 1.2 -

using the name Westar Energy. Our corporate headquarters is Total .................................... 5,844.2 100.0 located at 818 South Kansas Avenue, Topeka, Kansas 66612.

Our aggregate 2004 peak system net load of 4,455 MW occurred on KGE owns a 47% interest in the Wolf Creek Generating Station August 3, 2004. Our net generating capacity combined with firm (Wolf Creek), a nuclear power plant located near Burlington, capacity purchases and sales provided a capacity margin of Kansas, and a 47% interest in Wolf Creek Nuclear Operating approximately 20% above system peak responsibility at the time of Corporation (WCNOC), the operating company for Wolf Creek.

our 2004 peak system net load.

SIGNIFICANT BUSINESS DEVELOPMENTS DURING 2004 We have agreed to provide generating capacity to other utilities as set forth below.

Common Stock Issuance Westar Energy sold approximately 12.5 million shares of its com- Utility Capacity (MW) Period Ending mon stock in 2004 for net proceeds of $245.1 million. Midwest Energy, Inc............................ 20 May 2005 Midwest Energy, Inc ............................ 130 May 2008 Reduction of Debt Midwest Energy, Inc............................ 125 May 2010 During 2004, we reduced our total debt balance by $533.4 mil- Empire District Electric Company ........ .......... 162 May 2010 lion, from $2.2 billion at December 31, 2003 to $1.7 billion Oklahoma Municipal Power Authority .............. 60 December 2013 at December 31,2004. McPherson Board of Public Utilities (McPherson) (a) May 2027

(-)We provide base load capacity to McPherson. McPherson provides peaking Discontinued Operations - Sale of Protection One capacityto us. During2004,weprovided approximately 77MWto, and received On February 17, 2004, we closed the sale of our interest in approximately 178 MWfrom, McPherson. The amount of base load capacity Protection One, Inc. (Protection One) to subsidiaries of Quadrangle provided to McPherson is based on a fixed percentage of McPherson's annual Capital Partners LP and Quadrangle Master Funding Ltd. peak system load.

(together, Quadrangle). On November 12, 2004, we settled issues remaining after the sale by entering into a settlement agreement Fossil Fuel Generation with Protection One and Quadrangle that, among other things, Fuel Mix terminated a tax sharing agreement, settled Protection One's The effectiveness of a fuel to produce heat is measured in British claims with us related to the tax sharing agreement and settled thermal units (Btu). The higher the Btu content of a fuel, the lesser claims between Quadrangle and us related to the sale transaction. quantity of the fuel it takes to produce electricity. The quantity of Our net cash payment under the settlement agreement was heat consumed during the generation of electricity is measured in

$13.4 million. We recorded after tax income from discontinued millions of Btu (MMBtu).

operations of $78.8 million in 2004 and after tax loss from discontinued operations of $77.9 million in 2003. Based on MMBtus, our 2004 actual fuel mix was 79% coal, 16% nuclear and 5% natural gas, oil or diesel fuel. We expect OPERATIONS in 2005 to use a higher percentage of coal and a lower percentage of uranium because in 2005 we will refuel Wolf Creek. Our fuel mnix General fluctuates with the operation of Wolf Creek, as discussed below Westar Energy supplies electric energy at retail to approximately under "- Nuclear Generation," fluctuations in fuel costs, plant 11 352,000 customers in central and northeast Kansas and KGE availability, customer demand and the cost and availability of supplies electric energy at retail to approximately 301,000 wholesale market power.

2 004 ANN UAL REPO RT Coal entered into an agreement with Arch Coal, Inc. for coal to be Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy supplied to these energy centers beginning in 2005 and extending Center have an aggregate capacity of 2,213 MW, of which we own through 2009.This contract is expected to provide 100% of the coal an 84% share, or 1,859 MW. We have a long-term coal supply requirement for these energy centers through 2007 and 70% of the contract with Foundation Coal West to supply coal to Jeffrey coal requirements during 2008 and 2009. Approximately 30% of Energy Center from mines located in the Powder River Basin (PRB) the coal to be delivered under this contract is priced within a in Wyoming.The contract contains a schedule of minimum annual specified range of spot market prices for 2005 through 2007 and MMfBtu delivery quantities. All of the coal used at Jeffrey Energy approximately 43% of the coal to be delivered under this contract Center is purchased under this contract. The contract expires is priced within a specified range of spot market prices in 2008 December 31, 2020. The contract provides for price escalation, and 2009.

based on certain indexed costs of production. The price for In 2004, the coal supplied to Lawrence and Tecumseh Energy quantities purchased over the scheduled annual minimum is Centers had an average Btu content of approximately 8,905 Btu per subject to renegotiation every five years to provide an adjusted pound and an average sulfur content of 0.36 lbs/MMBtu. During price for the ensuing five years that reflects then current market 2004, the average delivered cost of all coal burned in the Lawrence prices.The next re-pricing is scheduled for 2008. units was approximately $1.05 per MMBtu, or $18.58 per ton. The The coal supplied to Jeffrey Energy Center during 2004 was surface average delivered cost of all coal burned in theTecumseh units was mined and had an average Btu content of approximately 8,449 Btu approximately $1.05 per MMBtu, or $18.65 per ton.

per pound and an average sulfur content of 0.47 lbs/MMBtu (see We transport coal from Wyoming using the BNSF railroad under a

"-Environmental Matters'for a discussion of sulfur content). The contract ending in December 2006. We anticipate entering into a average delivered cost of coal burned at Jeffrey Energy Center similar contract when the current contract expires. We anticipate during 2004 was approximately $1.24 per MMBtu, or $20.93 per ton.

that the cost of transporting coal may increase due to higher prices We transport coal from Wyoming under a long-term rail trans- for the items subject to contractual escalation.

portation contract with the Burlington Northern Santa Fe (BNSF) General: We have entered into all of our coal supply agreements in and Union Pacific railroads. The contract term continues through the ordinary course of business and believe we are not sub-December 31, 2013. The contract price is subject to price escalation stantially dependent on these contracts. We believe there are other based on certain costs incurred by the rail carriers. We anticipate suppliers with plentiful sources of coal available at spot market that the cost of transporting coal may increase due to higher prices prices to replace, if necessary, fuel supplied pursuant to these for the items subject to contractual escalation.

contracts and that we would be able to make transportation LaCygne Generating Station: The two coal-fired units at LaCygne arrangements for such coal. In the event that we were required to Generating Station (LaCygne) have an aggregate generating replace our coal agreements, we would not anticipate a substantial capacity of 1,362 MW, of which we own or lease a 50% share, or disruption of our business, although the cost of purchasing coal 681 MW. LaCygne 1 uses a blended fuel mix containing approxi- could increase. Because we meet the majority of our coal needs mately 85% PRB coal and 15% Kansas/Missouri coal. LaCygne 2 through long-term contracts as discussed above, we do not antici-uses PRB coal.The operator of LaCygne, Kansas City Power &Light pate being materially impacted by price changes in the spot market.

Company (KCPL), arranges coal purchases and transportation We have entered into all of our coal transportation contracts in the services for LaCygne. All of the LaCygne 1 and LaCygne 2 PRB ordinary course of business. Although several rail carriers are coal is supplied through fixed price contracts through 2005 and is capable of serving the coal mines from where our coal originates, transported under KCPL's Omnibus Rail Transportation Agree- several of our generating stations can be served by only one rail ment with the BNSF and Kansas City Southern Railroad through carrier. In the event the rail carrier to one of our generating stations December 31, 2010. As the PRB coal contracts expire, we anticipate fails to provide reliable service, we could experience a disruption of that KCPL will negotiate new supply contracts or purchase coal on our business that could have a material adverse impact on our the spot market.The LaCygne 1 Kansas/Missouri coal is purchased business, consolidated financial condition and results of operations.

from time to time from local Kansas and Missouri producers.

Natural Gas The PRB coal supplied to LaCygne 1 and LaCygne 2 during 2004 had an average Btu content of approximately 8,630 Btu per pound We use natural gas either as a primary fuel or as a start-up and/or and an average sulfur content of 0.32 lbs/MMBtu. During 2004, the secondary fuel, depending on market prices, at our Gordon Evans, average delivered cost of all coal burned at LaCygne 1 was Murray Gill, Neosho, Abilene and Hutchinson Energy Centers, in approximately $0.89 per MMBtu, or $15.51 per ton. The average the gas turbine units at ourTecumseh generating station and in the delivered cost of coal burned at LaCygne 2 was approximately combined cycle units at the State Line facility. We also use natural

$0.81 per MMBtu, or $13.74 per ton. gas as a supplemental fuel in the coal-fired units at the Lawrence and Tecumseh generating stations. We purchase natural gas in the Lawrence and Tecumseh Energy Centers: The coal-fired units spot market, which supplies our facilities with a flexible natural gas located at the Lawrence and Tecumseh Energy Centers have an supply as necessary to meet operational needs. During 2004, we aggregate generating capacity of 752 MW. During 2004, we pur- purchased 4.2 million MMBtu of natural gas on the spot market for chased coal under a contract with Kennecott Coal Sales Company a total cost of $28.1 million. Natural gas accounted for approxi-12 that expired in December 2004. During the first quarter of 2004, we mately 1% of our total fuel burned during 2004.

2004 ANNUAL REPORT If natural gas prices are higher than the amount we are able to exposure to the risk of high oil prices due to our ability to use other recover through our retail rates, we may be exposed to increased fuel types and by using other pricing techniques available to us, natural gas costs and our exposure could be material. We may be such as purchasing derivative contracts. To recover increased oil able to reduce our exposure to the risk of high natural gas prices costs in excess of the cost included in retail rates, we would have to due to our ability to use other fuel types and by using other pricing file a request for a change in rates with the KCC or request a techniques available to us, such as purchasing derivative contracts. recovery mechanism through the KCC, which could be denied in To recover increased natural gas costs in excess of the cost included whole or in part. For additional information on our exposure to in retail rates, we would have to file a request for a change in rates commodity price risks, see "Item 7A. Quantitative and Qualitative with the Kansas Corporation Commission (KCC) or request a Disclosures About Market Risk' recovery mechanism through the KCC, which could be denied in whole or in part. For additional information on our exposure to Other Fuel Matters commodity price risks, see "Item 7A. Quantitative and Qualitative The table below provides information relating to the weighted Disclosures About Market Risk." average cost of fuel that we have used, including the fuel and transportation costs and any other associated costs.

We maintain natural gas transportation arrangements for the Abilene and Hutchinson Energy Centers with Kansas Gas Service, 2004 2003 2002 a division of ONEOK, Inc. (ONEOK).This contract expires April 30, Per Million Btu:

2006. We expect to renew or renegotiate a new contract to provide Nuclear ........................... S 0.39 S 0.39 $ 0.40 this natural gas transportation prior to the current contract Coal ............................. 1.11 1.07 1.05 expiration. We meet a portion of our natural gas transportation Natural gas ........................ 6.62 4.83 3.62 requirements for the Gordon Evans, Murray Gill, Neosho, Oil ............................. 3.77 3.24 2.58 Lawrence and Tecumseh Energy Centers through firm natural gas Per MWh Generation ............ $.......

12.64 $12.08 $11.80 transportation capacity agreements with Southern Star Central Pipeline. We meet all of the natural gas transportation require- Purchased Power ments for the State Line facility through a firm natural gas At times, we purchase power to meet the energy needs of our transportation agreement with Southern Star Central Pipeline.The customers. Factors that cause us to purchase power to serve our firm transportation agreements that serve the Gordon Evans, customers include outages at our generating plants, prices for Murray Gill, Lawrence and Tecumseh Energy Centers extend wholesale energy, extreme weather conditions, growth, and other through April 1, 2010. The agreement for the Neosho and State factors. If we were unable to generate an adequate supply of Line facilities extends through June 1, 2016. electricity to serve our customers, we would typically purchase power in the wholesale market. Constraints in the transmission Oil system may keep us from purchasing power in which case we Once started with natural gas, most of the steam units at our would have to implement curtailment or interruption procedures Gordon Evans, Murray Gill, Neosho and Hutchinson Energy as permitted by our tariffs and terms and conditions of service.

Centers have the capability to bum oil or natural gas. We use oil as Purchased power for the year ended December 31,2004 comprised an alternate fuel when economical or when interruptions to approximately 6% of our total operating expenses.

natural gas supply make it necessary. During 2004 oil was more economical than natural gas, therefore, we used oil as the primary Energy Marketing Activities fuel in these generating facilities for most of 2004. During 2004, we We engage in both financial and physical trading to manage our burned 10.3 million MMBtu of oil at a total cost of $38.9 million. energy price risks. We trade electricity, coal, natural gas and oil.

Oil accounted for approximately 4% of our total MMBtu of fuel We use a variety of financial instruments, including forward burned during 2004. Because oil does not bum as cleanly as natural contracts, options and swaps and we trade energy commodity gas, our ability to use as much oil in the future could be constrained contracts daily. We also use economic hedging techniques to by new environmental rules or future settlements regarding manage fuel expenditures.

environmental matters.

Nuclear Generation Oil is also used as a start-up fuel at some of our generating General stations, as a primary fuel in the Hutchinson No. 4 combustion turbine and in our diesel generators. We purchase oil in the spot Wolf Creek is a 1,166 MW nuclear power plant located near market and under longer-term contracts. We maintain quantities Burlington, Kansas. Wolf Creek began operation in 1985. KGE in inventory that we believe will allow us to facilitate economic owns a 47% interest in Wolf Creek, or 548 MW, which represents approximately 9% of our total generating capacity. KCPL owns a dispatch of power, to satisfy emergency requirements and to protect against reduced availability of natural gas for limited 47% interest in Wolf Creek and a 6% interest is owned by Kansas periods or when the primary fuel becomes uneconomical to bum. Electric Power Cooperative, Inc. Wolf Creek is operated by WCNOC, a corporation owned by the co-owners of Wolf Creek.

If oil prices are higher than the amount we are able to recover The co-owners pay the operating costs of WCNOC equal to their through our retail rates, we may be exposed to increased oil costs percentage ownership in Wolf Creek. WCNOC has approximately and our exposure could be material. We may be able to reduce our 1,000 employees.

13

2 004 ANN UAL REPO RT Fuel Supply The Low-Level Radioactive Waste PolicyAmendments Act of 1985 We have 100% of the uranium and conversion services needed to mandated that the various states, individually or through interstate operate Wolf Creek under contract through September 2009. We compacts, develop alternative low-level radioactive waste disposal also have 100% of the enrichment services required to operateWolf facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Creek under contract through approximately March 2008. Oklahoma formed the Central Interstate Low-Level Radioactive Fabrication requirements are under contract through 2024. We Waste Compact (Compact), and the Compact Commission, which will be exposed to the price risk associated with any components is responsible for causing a new disposal facility to be developed not currently under contract if a counterparty were to fail its within one of the member states. The Compact Commission contractual obligations. selected Nebraska as the host state for the disposal facility.

WCNOC and the owners of the other five nuclear units in the All uranium, uranium conversion and uranium enrichment Compact provided most of the pre-construction financing for this arrangements, as well as the fabrication agreement, have been project. Our net investment in the Compact is approximately entered into in the ordinary course of business, and WCNOC $7.4 million.

believes Wolf Creek is not substantially dependent on these agreements. However, contraction and consolidation among In December 1998, the Nebraska agencies responsible for suppliers of these commodities and services, coupled with considering the developer's license application denied the increasing worldwide demand and past inventory draw-downs, application. Most of the utilities that had provided the project's have introduced uncertainty as to WCNOC's ability to replace, if pre-construction financing, including WCNOC as well as the necessary, some of these contracts in the event of a protracted Compact Commission itself, filed a lawsuit in federal court supply disruption. WCNOC believes this potential problem is contending Nebraska officials acted in bad faith while handling the common in the nuclear industry. Accordingly, in the event the license application. In September 2002, the court entered a affected contracts were required to be replaced, WCNOC believes judgment of $151.4 million, about one-third of which constitutes that the industry and government would arrive at a solution to prejudgment interest, in favor of the Compact Commission and minimize disruption of the nuclear industry's operations. against Nebraska, finding that Nebraska had acted in bad faith in handling the license application. Following unsuccessful appeals Nuclear fuel is amortized to fuel and purchased power based on of the decision by Nebraska, in August 2004 Nebraska and the the quantity of heat produced for the generation of electricity. Compact Commission settled the case. The settlement requires Radioactive Waste Disposal Nebraska to pay the Compact Commission a one-time amount Under the Nuclear Waste Policy Act of 1982, the Department of of $140.5 million or, alternatively, four annual installments of Energy (DOE) is responsible for the permanent disposal of spent $38.5 million beginning in August 2005. The parties agreed to nuclear fuel.Wolf Creek pays the DOE a quarterly fee for the future dismiss all pending litigation and appeals relating to this matter.

disposal of spent nuclear fuel. The fee is one-tenth of a cent for Once Nebraska makes its final payment, it will be relieved of its responsibility to host a disposal facility. Meanwhile, the Compact each kilowatt-hour of net nuclear generation produced. We include these disposal costs in operating expenses. Commission is pursuing other strategies for providing disposal capability for waste generators in the Compact region.

A permanent disposal site will not be available for the nuclear industry until 2012 or later. Under current DOE policy, once a Outages permanent site is available, the DOE will accept spent nuclear fuel Wolf Creek operates on an 18-month refueling and maintenance on a priority basis.The owners of the oldest spent fuel will be given outage schedule that permits operations during every third the highest priority. As a result, disposal services forWolf Creek will calendar year without a refueling outage. Wolf Creek was shut not be available prior to 2018. Wolf Creek has on-site temporary down for 45 days in 2003 for its thirteenth scheduled refueling and storage for spent nuclear fuel. In early 2000, Wolf Creek completed maintenance outage, which began on October 18, 2003 and ended replacement of spent fuel storage racks to increase its on-site on December 2, 2003. During outages at the plant we meet our storage capacity for all spent fuel expected to be generated by Wolf electric demand primarily with our fossil-fueled generating units Creek through the end of its licensed life in 2025. and by purchasing power depending on availability and cost. As provided by the KCC, we amortize the incremental maintenance In 2002, the Yucca Mountain site in Nevada was approved for the costs incurred for planned refueling outages evenly over the unit's development of a nuclear waste repository for the disposal of spent 18 month operating cycle. We do not defer and amortize the nuclear fuel and high level nuclear waste from the nation's defense incremental fuel or purchased power costs incurred as a result of a activities. This action allows the DOE to apply to the Nuclear refueling outage. Wolf Creek is scheduled to be taken off-line in the Regulatory Commission (NRC) to license the project. The DOE spring of 2005 for its fourteenth refueling and maintenance outage.

expects that this facility will open in 2012. However, the opening of theYucca Mountain site has been delayed many times and could be An extended or unscheduled shutdown of Wolf Creek could have a delayed further due to litigation and other issues related to the site substantial adverse effect on our business, financial condition and as a permanent repository for spent nuclear fuel. consolidated results of operations because of higher replacement power and other costs and reduced amounts of power available to Wolf Creek disposes of all classes of its low-level radioactive waste sell at wholesale. Although not expected, the NRC could impose at existing third-party repositories. Should disposal capability an unscheduled plant shutdown due to security or other concerns.

14 become unavailable, Wolf Creek is able to store its low-level radioactive waste in an on-site facility. WCNOC believes that a The NRC evaluates, monitors and rates various inspection findings temporary loss of low-level radioactive waste disposal capability and performance indicators for Wolf Creek based on their safety would not affect Wolf Creek's continued operation. significance. Wolf Creek currently meets all NRC oversight objectives

2004 ANNUAL REPORT and receives the minimum regimen of NRC inspections. However, We charge nuclear decommissioning costs to operating expense in because of Wolf Creek's recent experience with unscheduled accordance with the July 25, 2001 KCC rate order as modified by outages, one additional unscheduled outage before September 30, the KCC's approval of the funding schedule in the KCC's October 13, 2005 may result in the NRC lowering the Wolf Creek rating for one 2003 order. Electric rates charged to customers provide for recovery performance indicator. This might require additional NRC inspec- of these nuclear decommissioning costs over the life of Wolf Creek, tions to evaluate possible corrective actions that if required might which, as determined by the KCC for purposes of the funding result in additional expense or disruption in Wolf Creek's operation. schedule, will be through 2045. The NRC requires that funds to meet its nuclear decommissioning funding assurance requirement Nuclear Decommissioning be in our nuclear decommissioning fund by the time our license Nuclear decommissioning is a nuclear industry term for the expires in 2025. We believe that the KCC approved funding level permanent shutdown of a nuclear power plant and the removal of will be sufficient to meet the NRC minimum financial assurance radioactive components in accordance with NRC requirements. requirement. However, our consolidated results of operations The NRC will terminate a plant's license and release the property would be materially adversely affected if we are not allowed to for unrestricted use when a company has reduced the residual recover the full amount of the funding requirement.

radioactivity of a nuclear plant to a level mandated by the NRC.

The NRC requires companies with nuclear plants to prepare Competition and Deregulation formal financial plans to fund nuclear decommissioning. These Electric utilities have historically operated in a rate-regulated plans are designed so that funds required for nuclear decom- environment. The Federal Energy Regulatory Commission (FERC),

missioning will be accumulated prior to the termination of the the federal regulatory agency having jurisdiction over our license of the related nuclear power plant. wholesale rates and transmission services, and other utilities have initiated steps expected to result in a more competitive environ-We expense nuclear decommissioning costs over the expected life ment for utility services in the wholesale market.

of Wolf Creek. The amount we expense is based on an estimate of nuclear decommissioning costs that we will incur upon retirement The 1992 Energy Policy Act began deregulating the electricity of the plant. Nuclear decommissioning costs that are recovered in market for generation. The Energy Policy Act permitted FERC rates are deposited in an external trust fund. In 2004, we expensed to order electric utilities to allow third parties to use their approximately $3.9 million for nuclear decommissioning. We transmission systems to transport electric power to wholesale record our investment in the nuclear decommissioning fund at fair customers. In 1992, we agreed to permit third parties access to our value. Fair value approximated $91.1 million at December 31, 2004 transmission system for wholesale transactions. FERC also and $80.1 million at December 31,2003. requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, The KCC reviews nuclear decommissioning plans in two phases. FERC issued an order encouraging the formation of regional Phase one is the approval of the nuclear decommissioning study, transmission organizations (RTOs). RTOs are designed to control the current-year funding and future funding. Phase two is the filing the wholesale transmission services of the utilities in their regions, of a "funding schedule" by the owner of the nuclear facility thereby facilitating open and more competitive markets in detailing how it plans to fund the future-year dollar amount for its bulk power.

pro rata share of the plant.

Regional Transmission Organization W'Ve filed an updated nuclear decommissioning and dismantlement cost estimate with the KCC on August 30, 2002. Estimated costs We are a member of the Southwest Power Pool (SPP). On October 1, outlined by this study were developed to decommission Wolf 2004, FERC granted RTO status to the SPP. As a result, if approved Creek following a shutdown. The analyses relied on site-specific, by the KCC, we expect to turn operational control of our technical information, updated to reflect current plant conditions transmission system over to the SPP RTO under its membership and operating assumptions. Based on this study, our share of agreement and applicable tariff. The SPP RTO will operate our Wolf Creek's nuclear decommissioning costs, under the immed- transmission system as part of an interconnected transmission iate dismantlement method, is estimated to be approximately system across eight states. The SPP will collect revenues attrib-

$220.0 million in 2002 dollars. These costs include decon- utable to the use of each member's transmission system. Members tamination, dismantling and site restoration and are not inflated, and transmission customers will be able to transmit power escalated, or discounted over the period of expenditure.The actual purchased and generated for sale or bought for resale in the nuclear decommissioning costs may vary from the estimates wholesale market throughout the entire SPP system. We believe because of changes in technology and changes in costs for labor, each transmission owner generally retains the transmission capacity materials and equipment. needed to serve its retail customers. Any additional transmission capacity will be sold on a first come/first served non-discriminatory The KCC issued an order on April 16, 2003 approving the August basis. All transmission customers will be charged uniform rates for 2002 nuclear decommissioning study for Wolf Creek. On June 2, use of the transmission system, including entities that may sell 2003, we filed a funding schedule with the KCC to reflect the power inside our certificated service territory.We do not expect that KCC's April 16, 2003 order. On October 10, 2003, the KCC our participation in the SPP will have a material effect on our approved the funding schedule as filed without any change to our operations; however, we expect costs to increase due to the funding obligation. We expect to file an updated decommissioning establishment of the RTO and associated markets. At this time, we cost study with the KCC by September 1, 2005. are unable to quantify these costs because market implementation issues remain unresolved. We expect that we will recover these costs in rates we charge to our customers.

20 04 ANN U AL REPO RT Regulation and Rates electricity outside of Kansas by Westar Energy's energy marketing As a Kansas electric utility, we are subject to the jurisdiction of the operations, it is possible that the SEC could question Westar KCC, which has general regulatory authority over our rates, Energy's eligibility for an exemption from registration under the extensions and abandonments of service and facilities, valuation of 1935 Act. In that event, we would evaluate our options, including property, the classification of accounts, the issuance of some filing an application for exemption and asking the SEC to formally securities and various other matters. We are also subject to the consider that request, becoming a registered holding company, jurisdiction of FERC, which has authority over wholesale sales of restructuring our operations in a manner that would allow us electricity, the transmission of electric power and the issuance of to maintain eligibility to claim an exemption or restructuring some securities. We are subject to the jurisdiction of the NRC for our organizational structure to consolidate all utility operations nuclear plant operations and safety. into one entity so that Westar Energy is no longer a utility holding company.

As a result of an earlier KCC order, we will file a request for a rate review with the KCC by May 2, 2005, based on a test year In the event we elect to register WIestar Energy as a holding consisting of the 12 months ended December 31, 2004. company, the 1935 Act and related regulations issued by the SEC would govern its activities and the activities of its subsidiaries with Effective January 4, 2004, the "Hours of Service" regulations that respect to the acquisition, issuance and sale of securities, govern the length of time that drivers may operate vehicles and the acquisition and sale of utility assets, certain transactions among length of time they must be off-duty were revised. This legislation affiliates, engaging in business activities not directly related to the was designed to reduce accidents related to driver fatigue. Electric utility or energy business and other matters. We are unable to utilities were exempt from implementing these changes until predict whether Westar Energy will continue to be eligible for an September 2004. During restoration of electric service after a exemption for registration under the 1935 Act, however, we believe power outage, we must obtain a declaration of a state of that Westar Energy becoming a registered holding company under emergency in order to gain an exception from these rules. Such an the 1935 Act or taking steps to reorganize our corporate structure exception permits employees required to restore electric power to to avoid registration would not have a material impact on our operate equipment for extended hours without the otherwise consolidated financial position, results of operations or cash flows.

required off-duty time. The impact of this legislation could affect customer service and could result in increased operating costs if we Environmental Matters have to hire additional employees or contractors or lengthen General electric service outages.

We are subject to various federal, state and local environmental On January 16, 2004, the KCC issued an order regarding electric laws and regulations. These laws and regulations primarily relate to service reliability for retail customers. The order was intended to discharges into the air and air quality, discharges of effluents into help the KCC assess the reliability of retail electric service. water and the use of water, and the handling and disposal of Specifically, the KCC wanted to establish uniform definitions and hazardous substances and wastes. These laws and regulations requirements regarding service obligations, record keeping, require a lengthy and complex process for obtaining licenses, customer notification and methods of reporting results to the KCC. permits and approvals from governmental agencies for our new, On February 10, 2004, the North American Electric Reliability existing or modified facilities. If we fail to comply with such laws Council (NERC) issued reliability improvement initiatives and regulations, we could be fined or otherwise sanctioned by stemming from the investigation of the August 14, 2003 blackout regulators. In addition, under certain laws, we could be responsible in portions of the northeastern United States. These initiatives will for costs relating to contamination at our current and former impact our operations in a number of ways, including system relay facilities or at third-party waste disposal sites. We have incurred protection, vegetation management and operator training. The and will continue to incur capital and other expenditures to comply NERC and the ten operating regions in the United States, includ- with environmental laws and regulations.

ing the SPP, are working together to determine what operating policies and planning standards changes are necessary to achieve Environmental laws and regulations affecting power plants are the NERC's goals. We are unable to estimate potential compliance overlapping, complex, subject to changes in interpretation and costs at this time; however, it is likely that our annual capital and implementation and have tended to become more stringent over maintenance expenditure requirements will increase in the future. time. Although we believe that we can recover in rates the costs relating to compliance with such laws and regulations, there can be Public Utility Holding Company Act of 1935 no assurance that we will be able to recover all or any such Westar Energy is a holding company under the Public Utility increased costs from our customers or that our business, con-Holding Company Act of 1935 (1935 Act) as a result of Westar solidated financial condition or results of operations will not be Energy's ownership of KGE and Westar Generating, Inc., each a materially and adversely affected as a result of costs to comply with wholly-owned subsidiary. Currently, Westar Energy claims an such existing and future laws and regulations.

exemption from registration under the 1935 Act based on its operations being conducted "predominantly" within Kansas. Air Emissions Following a recent decision by the Securities and Exchange The Clean Air Act, state laws and implementing regulations Commission (SEC) with respect to its interpretation of the criteria impose, among other things, limitations on major pollutants, that must be satisfied to claim a "predominantly" intrastate including sulfur dioxide (S02), particulate matter and nitrogen 16 exemption and as a result of the amount of sales of wholesale oxides (NOx).

2 004 ANN UAL REPO RT Certain Kansas Department of Health and Environment (KDHE) We may be required to further reduce emissions of S02, NOx, regulations applicable to our generating facilities prohibit the particulate matter, mercury and carbon dioxide (C02) as a result of emission of S02 in excess of certain levels. In order to meet these various other current or pending laws, including, in particular:

standards, we use low-sulfur coal, fuel oil and natural gas and have

• the EPA's national ambient air quality standards for particulate equipped our generating facilities with pollution control equipment.

matter and ozone, In addition, we must comply with the provisions of the Clean Air

• the EPA's regional haze rules, designed to reduce S02, NOx and Act Amendments of 1990 that require a two-phase reduction in particulate matter emissions, and some emissions. We have installed continuous monitoring and

• additional legislation introduced in the past few years in reporting equipment in order to meet the acid rain requirements. Congress, such as the various"multi-pollutant"bills sponsored We have not had to make any material capital expenditures to meet by members of Congress requiring reductions of C02, NOx, Phase II S02 and NOx requirements. S02 and mercury, and the "Clear Skies" legislation proposed by the President, which would cap emissions of NOx, S02 Title IV of the Clean Air Act created an S02 allowance and trading and mercury.

program as part of the federal acid rain program. Under the allowance and trading program, the Environmental Protection Based on currently available information, we cannot estimate Agency (EPA) allocated annual S02 emissions allowances for each our costs to comply with these proposed laws, but such costs could affected emitting unit. An S02 allowance is a limited authorization be material.

to emit one ton of S02 during a calendar year. At the end of each year, each emitting unit must have enough allowances to cover its EPA New Source Review emissions for that year. Allowances are tradable so that operators The EPA is conducting investigations nationwide to determine of affected units that are anticipated to emit S02 in excess of their whether modifications at coal-fired power plants are subject to allowances may purchase allowances from operators of affected New Source Review requirements or New Source Performance units that are anticipated to emit S02 in an amount less than their Standards under Section 114(a) of the Clean AirAct (Section 114).

allowances. Because of strong demand for generation during These investigations focus on whether projects at coal-fired plants 2002 and 2003, we consumed more S02 allowances than were were routine maintenance or whether the projects were sub-allocated to us by the EPA. We made up the shortfall by buying stantial modifications that could have reasonably been expected to allowances. In 2004, we had enough emissions allowances to meet result in a significant net increase in emissions. The Clean Air Act planned generation and we expect to have enough in 2005. In requires companies to obtain permits and, if necessary, install future years, we expect to purchase S02 allowances in order to control equipment to remove emissions when making a major meet the acid rain requirements of the Clean Air Act. We cannot modification or a change in operation if either is expected to cause estimate the cost at this time, but anticipate these costs may be a significant net increase in emissions.

material. The pricing of emissions allowances is unpredictable and The EPA has requested information from us under Section 114 may change over time.

regarding projects and maintenance activities that have been On January 30, 2004, the EPA published two proposed air quality conducted since 1980 at the three coal-fired plants we operate. On rules referred to as the "Interstate Air Quality Rule" and the January 22, 2004, the EPA notified us that certain projects "Utility Mercury Reduction Rule" that, if adopted, would impact completed at Jeffrey Energy Center violated pre-construction our operations. In an attempt to address the impact of interstate permitting requirements of the Clean Air Act.

transport of air pollutants on downwind states, the proposed We are in discussions with the EPA concerning this matter in an Clean Air Interstate Rule would require reductions of S02 and NOx in certain states, including Kansas, in two separate phases. attempt to reach a settlement. We expect that any settlement with The first reductions would be required in 2010 and the second the EPA could require us to update or install emissions controls at Jeffrey Energy Center over an agreed upon number of years.

in 2015.

Additionally, we might be required to update or install emissions The proposed Utility Mercury Reduction Rule sets out two controls at our other coal-fired plants, pay fines or penalties, or approaches for requiring subject power plants to control mercury take other remedial action. Together, these costs could be material.

and nickel emissions. The first option, a traditional command and The EPA has informed us that it has referred this matter to the control approach, would require subject plants to meet Hazardous Department of Justice (DOJ) for the DOJ to consider whether to Air Pollutant emissions standards for mercury and nickel based on pursue an enforcement action in federal district court. We believe the application of maximum achievable control technology. The that costs related to updating or installing emissions controls second option would establish standards of performance limiting would qualify for recovery through rates. If we were to reach a mercury and nickel emissions, and include a "cap and trade" settlement with the EPA, we may be assessed a penalty. The program for mercury emissions. The EPA is expected to issue its penalty could be material and may not be recovered in rates.

final rule in 2005. New requirements for reductions of nickel emissions will be applicable only to our generating facilities that Manufactured Gas Sites burn a significant amount of oil. Based on currently available We have been associated with a number of former manufactured information, we cannot estimate our costs to comply with these gas sites located in Kansas and Missouri that may contain coal tar two proposed rule changes, but these costs could be material. and other potentially harmful materials.

17

2 004 ANN UAL REPO RT We and the KDHE entered into a consent agreement in 1994 RISK FACTORS governing all future work at the Kansas sites. Under the terms of Like other companies in our industry, our consolidated financial the consent agreement, we agreed to investigate and, if necessary, results will be impacted by weather, the economy of our service remediate these sites. Through December 31, 2004, the costs territory and the performance of our customers. Our common incurred for preliminary site investigation and risk assessment stock price and creditworthiness will be affected by national and have been minimal. Pursuant to an environmental indemnity international macroeconomic trends, general market conditions agreement with ONEOK, the current owner of some of the Kansas and the expectations of the investment community, all of which are sites, our liability for twelve of the Kansas sites is limited. Of those largely beyond our control. In addition, the following statements twelve sites, ONEOK assumed total liability for remediation of highlight risk factors that may affect our consolidated financial seven sites and we share liability for remediation with ONEOK for condition and results of operations. These are not intended to be five sites. Our total liability for the five shared sites is capped at an exhaustive discussion of all such risks, and the statements

$3.8 million and terminates in 2012. We have sole responsibility for below must be read together with factors discussed elsewhere in remediation with respect to three Kansas sites. With respect to two this document and in our other filings with the SEC.

of those sites, we are currently either conducting or completing remediation activities and, with respect to the third site, we will Our Revenues Depend Upon Rates Determined begin investigation activities in the near future. by the KCC The KCC regulates many aspects of our business and operations, Our liability for our former manufactured gas sites in Missouri is including the retail rates that we may charge customers for electric limited by an environmental indemnity agreement with Southern service. Retail rates are set by the KCC using a cost-of-service Union Company, which bought all of the Missouri manufactured approach that takes into account historical operating expenses, gas sites. According to the terms of the agreement, our future fixed obligations and recovery of capital investments, including liability for these sites is capped at $7.5 million and terminates potentially stranded obligations. Using this approach, the KCC in 2009.

sets rates at a level calculated to recover such costs, adjusted to Solid Waste Landfills reflect known and measurable changes, and a permitted return on We operate solid waste landfills at Jeffrey, Lawrence and Tecumseh investment. Other parties to a rate review or the KCC staff may Energy Centers for the single purpose of disposing of coal contend that our current or proposed rates are excessive. In July 2003, the KCC approved a stipulation and agreement that requires combustion waste material. Additionally, there is one retired landfill at each of the Lawrence and Neosho Energy Centers. us to file for a rate review, which may or may not include a request All landfills are permitted by the KDHE. The operating landfill for a change in rates, by May 2, 2005, and to pay customer rebates of $10.5 million on May 1, 2005 and $10.0 million on January 1, at Lawrence Energy Center is projected to be full by late 2007 or 2006. The rates permitted by the KCC in the rate review will early 2008 requiring us to permit and construct a new landfill determine our revenues for the succeeding periods and may have a at this site. We began the process of obtaining this permit in late material impact on our consolidated earnings, cash flows and 2003. We will continue to work with the appropriate regulatory financial position, as wvell as our ability to maintain our common agencies to ensure that the new landfill and expansion of the stock dividend at current levels or to increase our dividend in the existing landfill will meet the operating requirements of the future. We are unable to predict the outcome of the rate review.

Lawrence Energy Center.

Some of Our Costs May Not be Fully Recovered EMPLOYEES in Retail Rates Once established by the KCC, our rates remain fixed until changed As of February 28, 2005, we employed approximately 2,100 in a subsequent rate review. We may at any time elect to file a rate people. Our current contract with Local 304 and Local 1523 of review to request a change in our rates or intervening parties may the International Brotherhood of Electrical W\'orkers extends request that the KCC review our rates for possible adjustment, through June 30, 2005.The contract is currently under negotiation. subject to any limitations that may have been ordered by the KCC.

The contract covered approximately 1,200 employees as of Earnings could be reduced to the extent that increases in our February 28,2005. operating costs increase more than our revenues during the period between rate reviews, which may occur because of maintenance ACCESS TO COMPANY INFORMATION and repair of plants, fuel and purchased power expenses, employee or labor costs, inflation or other factors.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K are available free of charge Equipment Failures and Other External Factors either through our Internet website at www.wr.com or by Can Adversely Affect Our Results responding to requests addressed to our investor relations The generation and transmission of electricity requires the use of department. These reports are available as soon as reasonably expensive and complicated equipment. While we have a practicable after such material is electronically filed with, or maintenance program in place, generating plants are subject to furnished to, the SEC. The information contained on our Internet unplanned outages because of equipment failure. In these events, website is not part of this document. we must either produce replacement power from our less efficient 18 111I

20 04 ANN U AL REPO RT units or purchase power from others at unpredictable cost in order Competitive Pressures from Electric Industry to supply our customers and perform our contractual agreements. Deregulation Could Adversely Affect Our This can increase our costs materially and prevent or limit us from Revenues and Reported Earnings selling power at wholesale, thus reducing our profits. In addition, We currently apply the accounting principles of Statement of decisions or mistakes by other utilities may adversely affect our Financial Accounting Standards (SFAS) No. 71,"Accounting for the ability to use transmission lines to deliver or import power, thus Effects of Certain Types of Regulation," to our regulated business subjecting us to unexpected expenses or to the cost and uncer- and at December 31, 2004 had recorded $413.7 million of regula-tainty of public policy initiatives. These factors, as well as weather, tory assets, net of regulatory liabilities. In the event that we interest rates, economic conditions, fuel availability and prices, determined that we could no longer apply the principles of SFAS price volatility of fuel and other commodities and transportation No. 71, either as a result of the establishment of retail competition availability and costs are largely beyond our control, but may have in Kansas or an expectation that permitted rates would not allow a material adverse effect on our consolidated earnings, cash flows us to recover these costs, we would be required to record a charge and financial position. We engage in energy marketing transac- against income in the amount of the remaining unamortized net tions to reduce risk from market fluctuations, enhance system regulatory assets. Neither the Kansas Legislature nor the KCC has reliability and increase profits. The events mentioned above could taken action in the recent past to establish retail competition in our reduce our ability to participate in energy marketing opportunities, service territory.

which could reduce our profits.

We Face Financial Risks From Our Ownership We May Have Material Financial Exposure Under the Interest in the Wolf Creek Nuclear Facility Clean Air Act and Other Environmental Regulations Risks of substantial liability arise from the ownership and On January 22, 2004, the EPA notified us that certain projects operation of nuclear facilities, including, among others, structural completed at Jeffrey Energy Center violated pre-construction problems at a nuclear facility, the storage, handling and disposal of permitting requirements under the Clean Air Act. This notification radioactive materials, limitations on the amounts and types of was delivered as part of an investigation by the EPA regarding insurance coverage commercially available and uncertainties with maintenance activities that have been conducted since 1980 at respect to the technological aspects of nuclear decommissioning at Jeffrey Energy Center. The EPA has informed us that it has referred the end of their useful lives and anticipated increases in the cost of this matter to the DOJ for it to consider whether to pursue an nuclear decommissioning and costs or measures associated with enforcement action in federal district court. The remedy for a public safety. In the event of an extended or unscheduled outage at violation could include fines and penalties and an order to install Wolf Creek, we would be required to generate power from less new emission control systems, the cost of which could be material. efficient units, purchase power in the open market to replace the power normally produced at Wolf Creek and we would have less Our activities are subject to stringent environmental regulation by power available for sale by us in the wholesale markets. Such federal, state, and local governmental authorities. These regula- purchases would subject us to the risk of increased energy prices tions generally involve discharges of effluents into the water, and, depending on the length of the outage and the level of market emissions into the air, the use of water, and hazardous substance prices, could adversely affect our cash flow. If we were not and waste handling, remediation and disposal, among others. permitted by the KCC to recover these costs, such events could Congress also may consider legislation and the EPA may propose have an adverse impact on our consolidated financial condition.

new regulations or change existing regulations that could require us to further restrict or reduce certain emissions at our plants. We May Face Liability In Ongoing Lawsuits Legislation, proposed regulations or changes in regulations, if and Investigations adopted, could impose additional costs on the operation of our We and certain of our former and present directors and officers are power plants. Although we generally recover such costs through defendants in civil litigation alleging violations of the securities our rates, there can be no assurance that we would be able to laws. In addition, we continue to cooperate in investigations by a recover all or any increased costs relating to compliance with federal grand jury, the SEC and the DOJ into events that occurred environmental regulations from our customers or that our at our company during the years prior to 2003. Our former business, consolidated financial condition or results of operations president, chief executive officer and chairman and our former would not be materially and adversely affected. We have made and executive vice president and chief strategic officer have asserted will continue to make capital and other expenditures to comply significant claims against us in connection with the termination of with environmental laws and regulations. There can be no their employment and the publication of the report of the special assurance that such expenditures will not have a material adverse committee of our board of directors. An adverse result in any of effect on our business, consolidated financial condition or results these matters could result in damages, fines or penalties in of operations. amounts that could be material and adversely affect our con-solidated results and financial condition. Management believes that it is not currently possible to estimate the potential impact of the ultimate resolution of these matters.

19

2004 ANNUAL REPORT EXECUTIVE OFFICERS OF THE COMPANY Name Age PresentOffice Other Offices or Positions Held During the PastFiveYears James S. Haines, Jr. 58 Director, Chief Executive Officer and The University of Texas at El Paso President (since December 2002) Adjunct Professor and Skov Professor of Business Ethics January 2002 to Present)

El Paso Electric Company Director, President and Chief Executive Officer (May 1996 to November 2001)

William B. Moore 52 ExecutiveVice President and Saber Partners, LLC Chief Operating Officer Senior Managing Director and Senior Advisor (since December 2002) (October 2000 to December 2002)

Westar Energy, Inc.

ExecutiveVice President, Chief Financial Officer and Treasurer (May 1999 to August 2000)

Mark A. Ruelle 43 ExecutiveVice President and Sierra Pacific Resources, Inc.

Chief Financial Officer President, Nevada Power Company (since January 2003) (June 2001 to May 2002)

SeniorVice President, Chief Financial Officer (March 1997 to May 2001)

Douglas R. Sterbenz 41 SeniorVice President, Generation Westar Energy, Inc.

and Marketing (since October 2001) Senior Director, Bulk Power Marketing (January 1999 to October 2001)

Bruce A. Akin 40 Vice President, Administrative Services Westar Energy, Inc.

(since December 2001) Executive Director, Business Services (October 2001 to December 2001)

Executive Director, Human Resources (uly 1999 to October 2001)

Kelly B. Harrison 46 Vice President, Regulatory Westar Energy, Inc.

(since December 2001) Executive Director, Regulatory (October 2001 to December 2001)

Senior Director, Restructuring and Rates (October 1999 to October 2001)

Larry D. Irick 48 Vice President, General Counsel and Westar Energy, Inc.

Corporate Secretary Vice President and Corporate Secretary (since February 2003) (December 2001 to February 2003)

Corporate Secretary (May 2000 to December 2001)

Executive Director, Law (May 1999 to May 2000)

Peggy S. Loyd 47 Vice President, Corporate Compliance Westar Energy, Inc.

and Internal Audit Vice President, Financial Services (since March 2003) (May 2000 to March 2003)

Executive Director, Financial Services January 1999 to May 2000)

James J. Ludwig 46 Vice President, Public Affairs Westar Energy, Inc.

(since January 2003) Senior Director, Regulatory Affairs (uly 1995 to October 2001)

Lee Wages 56 Vice President, Controller Westar Energy, Inc.

(since December 2001) Controller (uly 1999 to December 2001) 20 1111

2 004 ANN UAL REPO RT ITEM 2. PROPERTIES We own approximately 6,100 miles of transmission lines, approximately 23,600 miles of overhead distribution lines and Unit Capacity (MW) ByOwner Unit Year Principal Westar Total approximately 3,300 miles of underground distribution lines.

Name/Location No. Installed Fuel Energy KGE Company Abilene Energy Center:

Substantially all of our utility properties are encumbered by first Abilene, Kansas priority mortgages pursuant to which bonds have been issued and Combustion Turbine 1 1973 Gas 72.0 - 72.0 are outstanding.

Gordon Evans Energy Center:

Colwich, Kansas SteamTurbines 1 1961 Gas-Oil - 149.0 149.0 ITEM 3. LEGAL PROCEEDINGS 2 1967 Gas-Oil - 383.0 383.0 Combustion Turbines 1 2000 Gas 74.0 - 74.0 On September 21, 2004, a grand jury in Travis County, Texas, 2 2000 Gas 74.0 - 74.0 indicted us on charges that a $25,000 contribution by us in May 3 2001 Gas 151.0 - 151.0 2002 to a Texas political action committee violated Texas election Diesel Generator 1 1969 Diesel - 3.0 3.0 laws. We believe the indictment is without merit and we intend to Hutchinson Energy Center: vigorously defend against the charges. If convicted, the court could Hutchinson, Kansas SteamTurbines 1 1950 Gas-Oil 17.0 - 17.0 impose a fine of up to $20,000 or, in certain circumstances, in an 2 1950 Gas - Oil 16.0 - 16.0 amount not to exceed twice the amount caused to be lost by the 3 1951 Gas-Oil 28.0 - 28.0 commission of the felony. As a result of the indictment, the federal 4 1965 Gas-Oil 173.0 - 173.0 government could suspend our status as a government contractor.

Combustion Turbines 1 1974 Gas 54.0 - 54.0 2 1974 Gas 55.0 - 55.0 Upon a conviction, the federal government could bar us from 3 1974 Gas 56.0 - 56.0 acting as a government contractor. We are taking action to ensure 4 1975 Diesel 77.0 - 77.0 that neither of these events occur, but we do not know whether we Diesel Generator 1 1983 Diesel 3.0 - 3.0 will be successful. We are unable to predict the ultimate impact Jeffrey Energy Center (84%): either suspension or loss of our status as a government contractor St. Marys, Kansas would have on our consolidated financial position, results of SteamTurbines 1(a) 1978 Coal 471.0 147.0 618.0 2(a) 1980 Coal 470.0 147.0 617.0 operations and cash flows.

3(a) 1983 Coal 475.0 149.0 624.0 Wind Turbines 1(a) 1999 - 0.5 0.1 0.6 Information on other legal proceedings is set forth in Notes 3, 15, 2(a) 1999 - 0.5 0.1 0.6 17,18 and 20 of the Notes to Consolidated Financial Statements, LaCygne Station (50%): "Rate Matters and Regulation,""Commitments and Contin-LaCygne, Kansas gencies - EPA New Source Review,""Legal Proceedings,"

SteamTurbines 1(a) 1973 Coal - 344.0 344.0 "Ongoing Investigations" and "Potential Liabilities to David C.

2(b) 1977 Coal - 337.0 337.0 Wittig and Douglas T. Lake," respectively, which are incorporated Lawrence Energy Center:

Lawrence, Kansas herein by reference.

Steam Turbines 3 1954 Coal 54.0 - 54.0 4 1960 Coal 122.0 - 122.0 5 1971 Coal 372.0 - 372.0 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Murray Gill Energy Center:

Wichita, Kansas No matter was submitted to a vote of our security holders through Steam Turbines 1 1952 Gas - 40.0 40.0 the solicitation of proxies or otherwise during the fourth quarter 2 1954 Gas-Oil - 71.0 71.0 3 1956 Gas-Oil - 104.0 104.0 of 2004.

4 1959 Gas-Oil - 102.0 102.0 Neosho Energy Center:

Parsons, Kansas SteamTurbine 3 1954 Gas-Oil - 63.0 63.0 State Line (40%):

Joplin, Missouri Combined Cycle 2-1 (a) 2001 Gas 65.0 - 65.0 2-2(a) 2001 Gas 64.0 - 64.0 2-3(a) 2001 Gas 71.0 - 71.0 Tecumseh Energy Center:

Tecumseh, Kansas Steam Turbines 7 1957 Coal 75.0 - 75.0 8 1962 Coal 129.0 - 129.0 Combustion Turbines 1 1972 Gas 18.0 - 18.0 2 1972 Gas 20.0 - 20.0 Wolf Creek Generating Station (47%):

Burlington, Kansas Nuclear 1(a) 1985 Uranium - 548.0 548.0 Total 3,257.0 2,587.2 5,844.2 a)Wejointly own Jeffrey Energy Center (84%), LaCygne I generatingunit (50%), 21 Wolf Creek GeneratingStation (47%) and State Line (40%). Unit capacity amounts reflect our ownershiponly.

NIn 1987, KGE entered into a sale-leasebacktransactioninvolving its 50% interest in the LaCygne2 generatingunit.

2004 ANNUAL REPORT PART 11 April, July and October to shareholders of record as of or about the ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY ninth day of the preceding month. Our board of directors reviews AND RELATED STOCKHOLDER MATTERS our common stock dividend policy from time to time. Among the factors the board of directors considers in determining our STOCK TRADING dividend policy are earnings, cash flows, capitalization ratios, regu-lation, competition and financial loan covenants. On November 23, Our common stock is listed on the NewYork Stock Exchange and 2004, our board of directors declared a quarterly dividend of $0.23 traded under the ticker symbol WR. As of March 1, 2005, there per share, payable January 3, 2005.

were 29,503 common shareholders of record. For information regarding quarterly common stock price ranges for 2004 and 2003, Our articles of incorporation restrict the payment of dividends or see Note 26 of the Notes to Consolidated Financial Statements, the making of other distributions on our common stock while any "Quarterly Results (Unaudited)." preferred shares remain outstanding unless we meet certain capitalization ratios and other conditions. We provide further DIVIDENDS information on these restrictions in Note 19 of the Notes to Consolidated Financial Statements, "Common and Preferred Holders of our common stock are entitled to dividends when and Stock."We do not expect these restrictions to have an impact on as declared by our board of directors. However, prior to the our ability to pay dividends on our common stock.

payment of common dividends, we must first pay dividends to the holders of preferred stock based on the fixed dividend rate for For additional information on dividends, see Note 19 of the Notes each series. to Consolidated Financial Statements, "Common and Preferred Stock,"included herein.

Quarterly dividends on common stock and preferred stock have historically been paid on or about the first business day of January, ITEM 6. SELECTED FINANCIAL DATA For the Year Ended December 31, 2004 2003 2002(') 2001 2000 (InThousands)

Income Statement Data:

Sales .1.................................................... 1464,489 S1,461,143 $1,423,151 $1,308,536 51,361,006 Income from continuing operations before accounting change .. .............. 100,080 162,915 88,816 59,333 192,696 Earnings(loss)availableforcommonstock .................................. 177,900 84,042 (793,400) (21,771) 135,352 Asof December 31, 2004 2003 2002 2001 2000 (in Thousands)

Balance Sheet Data:

Totalassets.......................................................... $5,085,711 $5,742,975 S6,756,666 $7,718,764 $7,887,746 Long-term obligations and mandatorily redeemable preferred stockOb) .............. 1,724,967 2,259,880 3,225,556 2,915,153 2,938,832 Forthe YearEndedDecember 31, 2004 2003 2002(I 2001 2000 Common Stock Data:

Basic earnings per share available for common stock from continuingoperationsbeforeaccountingchange ........ ................... S 1.19 $ 2.24 $ 1.23 $ 0.83 $ 2.78 Basicearnings(loss)pershareavailableforcommonstock ...... ................ $ 2.14 $ 1.16 $ (11.06) $ (0.31) $ 1.96 Dividends declared per share .................... ........................ $ 0.80 $ 0.76 $ 1.20 $ 1.20 S 1.44 Bookvaluepershare ................................................. S 16.13 $ 13.98 $ 13.41 $ 25.64 S 27.28 Average equivalent common shares outstanding (inthousands) .82,941 72,429 71,732 70,650 68,962 rsee Note 4 of the Notes to Consolidated Financial Statements, "Discontinued Operations -Sale of Protection One and Protection One Europeefor discussion of impairment charges that are the primary cause of our losses.

(b)Includeslong-tern debt, capital leases, affiliate long-term debt and shares subject to mandatory redemption.

22 111

2004 ANNUAL REPORT ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS In accounting for our retirement plans and other post-retirement OF FINANCIAL CONDITION AND RESULTS OF benefits, we make assumptions regarding the valuation of benefit OPERATIONS obligations and the performance of plan assets. The reported costs of our pension benefit plans, which include our portion of INTRODUCTION WCNOCs costs, are impacted by estimates regarding earnings on We are the largest electric utility in Kansas. We produce, transmit plan assets, contributions to the plan, discount rates used to and sell electricity at retail in Kansas and at wholesale in a multi- determine our projected benefit obligation and pension costs and state region in the central United States under the regulation of the employee demographics including age, compensation levels and KCC and FERC. employment periods. A change in any of these assumptions could have a significant impact on future costs, which may be reflected as Our focus during 2004 was the continued reduction of our debt an increase or decrease in net income in the current and future and interest expense, primarily through issuing stock, the sale of periods, or on the amount of related liabilities reflected on our our interest in Protection One and by refinancing some of our consolidated balance sheets or may also require cash contributions.

debt at lower interest rates. In 2004, we reduced our debt by

$533.4 million. The following table shows the annual impact of a 0.5% decrease in our pension plan discount rate and rate of return on plan assets. If Our goals for 2005 are to improve our core utility business by the discount rate increased by 0.5%, the impact would be a similar improving our credit quality, establishing a successful clean air amount in the opposite direction.

plan, completing a successful rate review, improving our service Annual Annual quality, making our operations more efficient and continuing our Increase in Annual Increasein involvement in community affairs. Projected Increase in Projected Change in Benefit Pension Pension Assumption Obligation Liability Expense Key factors affecting our business in any given period include the (InThousands) weather, the economic well-being of our Kansas service territory, performance of our electric generating facilities, conditions in fuel Discount rate................ 0.5% decrease $35,227 $32,134 $2,850 markets and the markets for wholesale electricity and the cost of Rate of return on plan assets ... . 0.5% decrease - - 2,299 dealing with public policy initiatives.

The following table shows the annual impact of a 0.5% decrease in As you read Management's Discussion and Analysis, please refer our post-retirement plan discount rate and rate of return on plan to our consolidated financial statements and the accompanying assets. If the discount rate increased by 0.5%, the impact would be notes, which contain our operating results. a similar amount in the opposite direction.

CRITICAL ACCOUNTING ESTIMATES Annual Annual Annual Increasein We base our discussion and analysis of financial condition and Increase in Increase in Projected Projected Post- Post-results of operations on our consolidated financial statements, Change in Benefit retirement retirement which have been prepared in conformity with Generally Accepted Assumption Obligation Liability Expense Accounting Principles (GAAP). Note 2 of the Notes to (InThousands)

Consolidated Financial Statements, "Summary of Significant Discount rate .0.5% decrease

.5%decrease $6,243 $- $333 Accounting Policies," contains a summary of our significant Rate of return on plan assets ... . 0.5% decrease - - 120 accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted below Revenue Recognition - Energy Sales have an impact on our reported results that may be material due to We recognize revenues from retail energy sales upon delivery to the levels of judgment and subjectivity necessary to account for the customer and include an estimate for energy delivered but uncertain matters or susceptibility of matters to change. unbilled. Our estimate of revenue attributable to this unbilled portion is based on the total energy available for sale measured Pension Benefit Plans against billed sales. At December 31, 2004, we had estimated We calculate our pension benefit and post-retirement medical unbilled revenue of $47.6 million.

benefit obligations and related costs using actuarial concepts within the guidance provided by SFAS No. 87, "Employers' We account for energy marketing derivative contracts under the Accounting for Pensions"and SFAS No. 106,"Employers'Accounting mark-to-market method of accounting. Under this method, we for Postretirement Benefits OtherThan Pensions,'respectively. recognize changes in the portfolio value as gains or losses in the 23

2 004 ANN UAL REPO RT period of change. Unless related to fuel, we include the net mark- We record deferred tax assets for capital loss, operating loss and tax to-market change in sales on our consolidated statements of credit carryforwards. However, when there are not sufficient income (loss). We record the resulting unrealized gains and losses sources of future capital gain income or taxable income to realize as energy marketing long-term or short-term assets and liabilities the benefit of the capital loss, operating loss or tax credit on our consolidated balance sheets as appropriate. We use quoted carryforwards, we reduce the deferred tax assets by a valuation market prices to value our energy marketing derivative contracts allowance. We recognize a valuation allowance if, based on the when such data are available. When market prices are not readily weight of available evidence, it is considered more likely than not available or determinable, we use alternative approaches, such as that some portion or all of the deferred tax asset will not be model pricing. Prices used to value these transactions reflect our realized. We report the effect of a change in the valuation best estimate of fair values of our trading positions. Results actually allowance in the current period tax expense.

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

OPERATING RESULTS The tables below show fair value of energy marketing contracts We evaluate operating results based on basic earnings (loss) per outstanding for the year ended December 31, 2004, their sources share. We have various classifications of sales, defined as follows:

and maturity periods.

FairValue Retail: Sales of energy made to residential, commercial and of Contracts industrial customers.

(InThousands)

Net fair value of contracts outstanding at the Other retail: Sales of energy for lighting public streets and beginning of the period . ...................................... $10,464 highways, net of revenues reserved for rebates.

Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period ...... ........ (7,293) Tariff-based wholesale: Includes the sales of electricity to Changes in fair value of contracts outstanding at the electric cooperatives, municipalities and other electric utilities, beginning and end of the period ............ .................... (2,590) the rate for which is generally based on cost as prescribed by Fair value of new contracts entered into during the period ...... ......... 5,500 FERC tariffs, and changes in valuations of contracts that have Fair value of contracts outstanding at the end of the period ...... ........ $ 6,081 yet to settle.

Market-based wholesale: Includes sales of electricity to other The sources of the fair values of the financial instruments related to wholesale customers, the rate for which is based on prevailing these contracts are summarized in the following table. market prices as allowed by our FERC approved market-based FairValue of Contracts at Endof Period tariff, and changes in valuations of contracts that have yet Maturity to settle.

Total LessThan Maturity Maturity Sources of FairValue FairValue 1 Year 1-3Years 4-5 Years Energy marketing: Includes: (1) market-based energy Prices provided by other external sources transactions unrelated to our generation or the needs of our (swapsandforwards) .. ............

$2,255 $1,396 $(377) $1,236 regulated customers; (2) financially settled products and Prices based on the Black Option Pricing model (options and other)(a) ........ 3,826 1,328 500 1,998 physical transactions sourced outside our control area; and (3) changes in valuations for contracts that have yet to settle that Total fair value of contracts outstanding ........ .... $6,081 S2,724 $ 123 $3,234 may not be recorded either in cost of fuel or tariff- or market-based wholesale revenues.

WThe Black Option Pricingniodel is a variantof the Black-Scholes Option Pricing model. Transmission: Reflects transmission revenues received, includ-ing those based on a tariff with the SPP.

Income Taxes Other: Miscellaneous electric revenues including ancillary We use the asset and liability method of accounting for income service revenues and rent from electric property leased to others.

taxes as required by SFAS No. 109, "Accounting for Income Taxes."

Under the asset and liability method, we recognize deferred tax Regulated electric utility sales are significantly impacted by such assets and liabilities for the future tax consequences attributable to things as rate regulation, customer conservation efforts, whole-temporary differences between the financial statement carrying sale demand, the overall economy of our service area, the weather amounts and the tax basis of existing assets and liabilities. We and competitive forces. Our wholesale sales are impacted by, recognize the future tax benefits to the extent that realization of among other factors, demand, cost of fuel and purchased power, such benefits is more likely than not. We amortize deferred price volatility and available generation capacity.

investment tax credits over the lives of the related properties.

24 111I

2 004 ANN UAL REPO RT 2004 compared to 2003: Below we discuss our operating results The following table reflects changes in electric sales volumes, as for the year ended December 31, 2004 as compared to the results measured by thousands of megawatt hours (MWh) of electricity, for the year ended December 31, 2003. for the two years ended December 31, 2004 and 2003. No sales volumes are shown for energy marketing, transmission or other.

Year Ended December 31, 2004 2003 Change %Change Energy marketing activities are unrelated to electricity we generate.

(inThousands, Except PerShare Amounts)

SALES: 2004 2003 Change %Change Residential ................ S 425,150 $ 432,955 $ (7,805) (1.8) (Thousands of MWh)

Commercial ............... 386,991 382,585 4,406 1.2 Residential ......................... 5,925 6,031 (106) (1.8)

Industrial ................. 239,518 240,538 (1,020) (0.4) Commercial ........................ 6,867 6,801 66 1.0 Other retail ............... (46) 5,363 (5,409) (100.9) Industrial .......................... 5,470 5,448 22 0.4 Total Retail Sales .......... 1,051,613 1,061,441 (9,828) (0.9) Other retail ........................ 102 104 (2) (1.9)

Tariff-based wholesale ....... 143,868 140,687 3,181 2.3 Total Retail ....................... 18,364 18,384 (20) (0.1 )

Market-based wholesale ..... 140,465 125,995 14,470 11.5 Tariff-based wholesale ................ 4,573 4,747 (174) (3.7)

Energy marketing .......... 26,321 31,881 (5,560) (17.4) Market-based wholesale .............. 4,115 3,919 196 5.0 Transmission(a) ............. 77,540 76,379 1,161 1.5 Total ............................ 27,052 27,050 2 -

Other ................... 24,682 24,760 (78) (0.3)

Total Sales .............. I14I4,4Y 1,461,1 ' . 'Z4f) U.Z Our retail customers used less energy and our sales decreased OPERATING EXPENSES: because of cooler weather during the summer. When measured by Fuel used for generation ..... 353,617 342,522 11,095 3.2 cooling degree days, the weather during 2004 was 12% cooler than Purchased power ........... 66,171 47,790 18,381 38.5 during 2003 and 16% below the 20-year average. We measure Operating and maintenance 412,002 371,372 40,630 10.9 cooling degree days at weather stations we believe to be generally Depreciation and reflective of conditions in our service territory. The accrual for amortization ............

rebates to be paid to customers in 2005 and 2006 pursuant to the Selling, general and administrative ........... 173,498 160,825 12,673 7.9 July 25, 2003 KCC order also reduced revenues from retail sales.

During 2004, we accrued $8.5 million as compared to $3.5 million Total Operating Expenses 1 1,174,598 1,089,745 84,853 7.8 acre .urn'03 accrued du29ng 2003.

INCOME FROM OPERATIONS ... 289,891 371,398 (81,507) (21.9)

OTHER INCOME (EXPENSE):

Market-based wholesale sales increased due primarily to increased Investment earnings ........ 16,746 21,189 (4,443) (21.0) sales volumes and an approximate 6% increase in the average price ONEOK dividends .......... - 17,316 (17,316) (100.0) per MWh. As a result of the milder weather, we had additional Gain on sale of energy production available for sale at certain times during the year ONEOK stock ............ - 99,327 (99,327) (100.0) that was not needed to serve our retail and tariff-based wholesale Loss on extinguishment of customers. Increased sales volumes accounted for approximately debt and settlement of $6.7 million of the increased market-based wholesale sales and putable/callable notes ..... (18,840) (26,455) 7,615 28.8 higher average market prices accounted for approximately Other income ............. 2,756 2,854 (98) (3.4)

$7.8 million of the increase. Energy marketing sales declined Other expense ............. (14,879) (16,590) 1,711 10.3 because we had less favorable changes in 2004 as compared to the Total Other Income favorable changes in 2003 in the settlement and the fair value of (Expense) ............. (14,217) 97,641 (111,858) (114.6) positions receiving mark-to-market accounting treatment.

Interest expense ............. 142,151 224,356 (82,205) (36.6)

Fuel expense increased due primarily to increases in the cost of fossil INCOME FROM CONTINUING OPERATIONS BEFORE fuels, although we used approximately 2% less fuel for generation INCOME TAXES ............ 133,523 244,683 (111,160) (45.4) due to the lower demand caused by the cooler weather and due to Income tax expense .......... 33,443 81,768 (48,325) (59.1) unplanned outages or reduced operating capability experienced at INCOME FROM CONTINUING some of our generating units at various times throughout 2004.The OPERATIONS .............. 100,080 162,915 (62,835) (38.6) average equivalent availability factor for our system was 87%

Results of discontinued during 2004 compared to 90% in the prior year, due largely to the operations, net of tax ....... 78,790 (77,905) 156,695 201.1 unavailability of some of our coal-fired generating units. As a result NET INCOME ............... 178,870 85,010 93,860 110.4 of the cooler weather and the reduced availability of our coal-fired Preferred dividends ........... 970 968 2 0.2 generating units, we decreased the amount of coal burned, and EARNINGS AVAILABLE FOR consequently reduced our total expense for coal. However, the cost COMMON STOCK .......... $ 177,900 $ 84,042 S93,858 111.7 of natural gas and oil that we used at other generating facilities to BASIC EARNINGS PER SHARE ... $ 2.14 $ 1.16 $ 0.98 84.5 compensate for the unplanned outages or reduced operating capability, increased our total fuel expense.

"'Transmission:Includes an SPP network transmission tariff In 2004, our transmission costs were approximately $66.6 million. This amount, less

$4.3 million that was retained by the SPP as administrationcost, was returned to us as revenues. In 2003, our transmission costs were approximately 25

$65.3 million with an administrationcost of $5.7 million retained by the SPP

2 004 ANN UAL REPO RT Purchased power expense increased due primarily to a 34% 2003 compared to 2002: Below we discuss our operating results increase in volumes purchased during 2004 as compared to 2003. for the year ended December 31, 2003 as compared to the results At times, it was more economical to purchase power than to for the year ended December 31, 2002.

operate our available generating units. This was due to unplanned YearEndedDecember 31, 2003 2002 Change  % Change outages or reduced operating capability of our coal-fired generating (InThousands, Except PerShare Amounts) units at certain times, and the availability of economically priced SALES:

power due to cooler weather in our region.

Residential ............... S 432,955 $ 442,106 S (9,151 ) (2.1 )

During 2003, we recorded as an offset to operating and maintenance Commercial .............. 382,585 385,375 (2,790) (0.7) expense a gain of $11.9 million on the sale of utility assets. The Industrial ................ 240,538 242,847 (2,309) (1.0) absence of a similar offset in 2004 accounted for 29% of the increase Other retail .............. 5,363 8,071 (2,708) (33.6) in operating and maintenance expense in 2004. The remainder of Total Retail Sales ......... 1,061,441 1,078,399 (16,958) (1.6) the increase was caused primarily by increased expenses associated Tariff-based wholesale ...... 140,687 138,111 2,576 1.9 with maintenance at Jeffrey Energy Center, increased planned and Market-based wholesale .... 125,995 100,586 25,409 25.3 unplanned unit maintenance at various other generating units, Energy marketing ......... 31,881 7,049 24,832 352.3 increased maintenance of the distribution system, an increase in Transmission(a) ............ 76,379 76,199 180 0.2 taxes other than income tax and an increase in the transmission Other ................... 24,760 22,807 1,953 8.6 costs. During 2004, increased maintenance of our generating units Total Sales ............. 1,461,143 1,423,151 37,992 2.7 accounted for 23% of the increase in operating and maintenance OPERATING EXPENSES:

expenses. The increase in distribution expenses accounted for 17% Fuel used for generation .... 342,522 347,377 (4,855) (1.4) of the increase in operating and maintenance expenses. Distri- Purchased power .......... 47,790 32,123 15,667 48.8 bution expenses increased due to increased staffing levels and Operating and maintenance 371,372 379,220 (7,848) (2.1) higher costs associated with the termination of portions of the Depreciation and ONEOK shared services agreement as discussed in Note 24 of amortization ............ 167,236 171,807 (4,571 ) (2.7) the Notes to Consolidated Financial Statements, "Related Party Selling, general and Transactions - ONEOK Shared Services Agreement." The administrative ........... 160,825 218,345 (57,520) (26.3) change in taxes other than income tax accounted for 22% of the Total Operating Expenses ... 1,089,745 1,148,872 (59,127) (5.1) increase in operating and maintenance expenses. An increase in INCOME FROM OPERATIONS ... 371,398 274,279 97,119 35.4 transportation costs accounted for 3% of the increase in operating OTHER INCOME (EXPENSE):

and maintenance expenses.

Investment earnings ........ 21,189 30,024 (8,835) (29.4)

Selling, general and administrative expenses increased due primarily ONEOK dividends ......... 17,316 46,771 (29,455) (63.0) to an increase in legal fees, including amounts we were required to Gain on sale of ONEOK stock ........... 99,327 - 99,327 advance for fees incurred by David C. Wittig, our former president, Loss on extinguishment of chief executive officer and chairman, and Douglas T. Lake, our debt and settlement of former executive vice president, chief strategic officer and member putable/callable notes ..... (26,455) (1,541) (24,914) (1,616.7) of the board, related to the defense of criminal charges against Other income ............ 2,854 1,316 1,538 116.9 them, and fees associated with the pending shareholder class Other expense ............ (16,590) (38,380) 21,790 56.8 action and derivative lawsuits. Total Other Income ....... 97,641 38,190 59,451 155.7 The total other expense during 2004 was due primarily to the loss Interest expense ............ 224,356 235,172 (10,816) (4.6) incurred on the extinguishment of debt. The total other income INCOME FROM CONTINUING during 2003 was due primarily to the gain on the sale of our OPERATIONS BEFORE ONEOK stock and dividends received from ONEOK in 2003.This INCOME TAXES ........... 244,683 77,297 167,386 216.5 gain was partially offset by the loss recorded on the extinguish- Income tax expense (benefit) 81,768 (11,519) 93,287 809.9 ment of debt and the settlement of notes during 2003. INCOME FROM CONTINUING OPERATIONS ............. 162,915 88,816 74,099 83.4 Interest expense decreased in 2004 due to lower debt balances and Results of discontinued lower interest rates due to refinancing activities as discussed below operations, net of tax ....... (77,905) (881,817) 803,912 91.2 in "Liquidity and Capital Resources." NET INCOME ............... 85,010 (793,001) 878,011 110.7 Preferred dividends, Income from discontinued operations was $78.8 million in 2004. net of gain on reacquired The results recorded for 2004 include the settlement of previously preferred stock .......... 968 399 569 142.6 pending issues as discussed in Note 4 of the Notes to Consolidated EARNINGS AVAILABLE FOR Financial Statements, "Discontinued Operations - Sale of COMMON STOCK ......... 84,042 S (793,400) $877,442 110.6 Protection One and Protection One Europe." This compares to a EARNINGS PER SHARE ........ $ 1.16 $ (11.06) $ 12.22 110.5 loss from discontinued operations of $77.9 million in 2003.

W)Transmission: Includes an SPP network transmissiontariff In 2003, our trans-mission costs were approximately $65.3 million. This amount, less $5.7 million 26 that was retained by the SPP as administration cost, was returned to us as revenues. In 2002, our transmissioncosts were approximately $65.9 million with an administrationcost of $5.7 million retained by the SPP.

111

2 0 0 4 ANN U AL REPO RT The following table reflects changes in electric sales volumes, as Other income improved significantly in 2003 primarily because the measured by thousands of MV'h of electricity, for the two years mark to market charge to record the fair value of the call option ended December 31, 2003 and 2002. No sales volumes are shown associated with the 6.25% senior unsecured notes that were putable for energy marketing, transmission or other. Energy marketing and callable on August 15, 2003 (the putable/callable notes) was activities are unrelated to electricity we generate. $2.2 million for 2003 compared to a charge of $22.6 million for 2002.

The smaller mark to market charge in 2003 was the result of the 2003 2002 Change  % Change settlement of the call options related to the putable/callable notes (Thousands of NMWh) in August 2003.

Residential .6,031 6,170 (139) (2.3)

Commercial .6,801 6,817 (16) (0.2)

Industrial .5,448 5,451 (3) (0.1) LIQUIDITY AND CAPITAL RESOURCES Other retail....................... 104 106 (2) (1.9)

Overview Total retail .18,384 18,544 (160) (0.9)

We believe we will have sufficient cash to fund future operations, Tariff-based wholesale .4,747 4,905 (158) (3.2) debt maturities, the rebates to customers we are required to Market-based wholesale .3,919 4,210 (291) (6.9) make in 2005 and 2006, and the payment of dividends from Total .27,050 27,659 (609) (2.2) a combination of cash on hand, cash flows from operations and available borrowing capacity. Our available sources of funds Our retail customers used less energy and our sales declined include cash, Westar Energy's revolving credit facility, our accounts because of cooler weather as well as the sale of a small portion of receivable conduit facility and access to capital markets. At our rural distribution territory. Commercial and industrial sales December 31, 2004, we had cash and cash equivalents of revenues showed slight decreases while sales volumes remained $24.6 million, $284.7 million available under the revolving credit relatively flat compared to 2002. The decline in retail sales volumes facility and $45.0 million available under the accounts receivable accounted for approximately $10.2 million of the decline in retail conduit facility. Uncertainties affecting our ability to meet these sales revenues. The accrual of approximately $3.5 million to be requirements include, among others, factors affecting sales refunded to customers in 2005 and 2006 pursuant to a KCC order described in "Operating Results"above, economic conditions, regu-also contributed to the decline in retail sales revenues. latory actions, conditions in the capital markets and compliance with environmental regulations.

The increases in energy marketing and wholesale sales revenues more than offset the decline in retail sales revenues. Higher At December 31,2004, our total outstanding long-term debt, net of wholesale market prices were the primary cause of improvement current maturities, was approximately $1.6 billion compared to a in energy marketing and wholesale sales revenues. The higher balance of approximately $2.1 billion at December 31, 2003. At wholesale market prices more than offset the decline in wholesale December 31, 2004, our current maturities of long-term debt were sales volumes. $65.0 million compared to $185.9 million at December 31,2003.

Purchased power expenses increased $15.7 million during 2003. Capital Resources During periods of high energy use in 2003, we purchased more We had $24.6 million in unrestricted cash and cash equivalents at power from other sources than we did during the same periods of December 31, 2004. We consider cash equivalents to be highly 2002 because it was more economical to purchase power than to liquid investments with maturities of three months or less at the operate our peaking units. This is also the primary reason our fuel time they are purchased.

expense decreased.

At December 31,2004, we also had $12.3 million of restricted cash Operating and maintenance expense declined due primarily to the classified as a current asset and $27.4 million of restricted cash

$11.9 million gain recorded in 2003 on the sale of utility assets, classified as a long-term asset, primarily to provide credit security which was recorded as an offset to operating expenses. General for energy marketing transactions. The following table details our maintenance expenses at our generating facilities increased by restricted cash at December 31, 2004.

$8.5 million, partially offsetting the decline in operating expenses.

Restricted Cash Restricted Cash Current Portion Long-term Portion Depreciation and amortization expense decreased due to the (InThousands) adoption of new depreciation rates on April 1, 2002.

Prepaid capacity and transmission agreement ....... S 2,256 S25,982 Selling, general and administrative expenses declined in 2003, Cash held in escrow as required by certain reflecting a reduction in numerous incremental administrative letters of credit, surety bonds and expenses incurred in 2002. The 2002 administrative expenses various other deposits ................ ....... 10,023 1,426 included a $36.0 million charge related to a work force reduction, a Total .............................. $12,279 $27,408

$9.0 million charge related to an exchange of restricted share units (RSUs) for common stock and an expense of $22.9 million for The Westar Energy mortgage and the KGE mortgage each contain potential liabilities to Mr. Wittig and Mr. Lake. The decline in provisions restricting the amount of first mortgage bonds that selling general and administrative expenses for 2003 was partially could be issued by each entity. Additionally, Westar Energy's offset by $9.6 million in charges related to the special committee revolving credit facility prohibits us from increasing the amount of 27 and grand jury investigations in 2003 as compared to charges of secured indebtedness outstanding as of March 12, 2004 by more

$4.7 million in 2002 related to these investigations.

2 004 ANN UAL REPO RT than $300.0 million.Therefore, we must ensure that we will be able Cash flows from operating activities decreased $127.5 million to to comply with such restrictions prior to the issuance of additional $150.6 million in 2003 from $278.1 million in 2002. This decrease first mortgage bonds or other secured indebtedness. was mostly attributable to taxes paid in 2003 of $53.6 million compared to an income tax refund received in 2002 of $54.1 million, The Westar Energy mortgage prohibits additional first mortgage an increase in maintenance expenditures at our generating bonds from being issued, except in connection with certain facilities in 2003 as compared to 2002, and increased legal expen-refundings, unless Westar Energy's unconsolidated net earnings ditures in 2003 related to investigations and litigation.

available for interest, depreciation and property retirement (which as defined, does not include earnings or losses attributable to the Cash Flows (used in) from Investing Activities ownership of securities of subsidiaries), for a period of 12 consecu- In general, cash used for investing purposes relates to the growth tive months within 15 months preceding the issuance, are not less and improvement of our electric utility business.The utility business than the greater of twice the annual interest charges on, and 10% is capital intensive and requires significant investment in plant on of the principal amount of, all first mortgage bonds outstanding an annual basis. We spent $202.9 million in 2004, $163.5 million in after giving effect to the proposed issuance. In addition, the 2003, and $140.4 million in 2002 on net additions to utility property, issuance of bonds is subject to limitations based on the amount of plant and equipment.

bondable property additions. At December 31, 2004, based on an assumed interest rate of 6%, approximately $210.0 million principal In 2004, we received net proceeds of $108.3 million from the sale of amount of additional first mortgage bonds could be issued under Protection One and Protection One bonds. During 2003, we the most restrictive provisions in the mortgage, except in received net proceeds of $801.8 million from the sale of ONEOK connection with certain refundings. stock and net proceeds of $33.3 million from the sale of utility assets.

Proceeds from other investments includes ONEOK dividends, The KGE mortgage prohibits additional first mortgage bonds from proceeds from the sale of investments in affordable housing being issued, except in connection with certain refundings, unless tax credit limited partnerships and proceeds from the sale of KGE's net earnings before income taxes and before provision for other investments.

retirement and depreciation of property for a period of 12 consecu-tive months within 15 months preceding the issuance are not less Cash Flows (used in) Financing Activities than either two and one-half times the annual interest charges Financing activities in 2004 used $323.2 million of cash compared on, or 10% of the principal amount of, all KGE first mortgage to $881.1 million in 2003. In 2004, we received cash from issuances bonds outstanding after giving effect to the proposed issuance. of long-term debt and the issuance of common stock, and cash was In addition, the issuance of bonds is subject to limitations based used for the retirement of long-term debt and payment of dividends.

on the amount of bondable property additions. At December 31, We used $881.1 million of cash in 2003 for financing activities 2004, based on an assumed interest rate of 6%, approximately compared to $72.4 million in 2002. In 2003, cash was used in

$874.0 million principal amount of additional KGE first mortgage financing activities for the retirement of long-term debt and the bonds could be issued under the most restrictive provisions in payment of dividends. In 2003, we reduced our indicated annual the mortgage. dividend from $1.20 per share to $0.76 per share.

WIestar Energy's revolving credit facility prohibits us from increasing In 2002, an increase in long-term debt was due primarily to the the amount of secured indebtedness outstanding as of March 12, debt refinancings completed during 2002. These financings were 2004 by more than $300.0 million. In June 2004, Westar Energy the principal source of cash flows from financing activities used to issued $250.0 million of Westar Energy first mortgage bonds reduce short-term debt, retire other long-term debt, place funds in and immediately placed the funds in escrow for retirement of a trust to be used for debt repayment, pay dividends, acquire

$225.0 million of Westar Energy first mortgage bonds, which was treasury stock and retire a portion of our preferred stock.

completed in July 2004. Therefore, at December 31, 2004, we could incur a maximum of $275.0 million of additional secured debt Future Cash Requirements under this provision in the Westar Energy revolving credit facility. Our business requires significant capital investments. Through Following Westar Energy's January 18, 2005 issuance of 2007, we expect we will need cash mostly for utility construction

$250.0 million of first mortgage bonds, as discussed in"- Debt programs designed to improve facilities providing electric service Financings,"we can incur a maximum of $25.0 million of addi- and for future peaking capacity needs. In 2006 we anticipate tional secured debt under this provision in Westar Energy's additional cash expenditures necessary to purchase and build revolving credit facility. approximately 150 MW of peaking generation capacity that we anticipate will be needed in 2008. We expect to meet these cash Westar Energy sold approximately 12.5 million shares of its needs with internally generated cash flow and borrowing under common stock in 2004 for net proceeds of $245.1 million. Westar Energy's revolving credit facility.

Cash Flows from Operating Activities We are required to pay rebates to retail customers of $10.5 million Cash flows from operating activities increased $203.6 million to on May 1,2005 and $10.0 million on January 1, 2006. We believe we

$354.2 million in 2004 from $150.6 million for 2003. This increase can fund these rebates with internally generated cash flow and was primarily attributable to reduced interest of $80.2 million and available borrowing capacity under Westar Energy's revolving 28 reduced tax payments of $52.5 million. credit facility.

2 004 ANN UAL REPO RT If we are required to update emissions controls or take other Debt Financings remedial action as a result of the EPA's investigation, the costs During 2004, we made changes in our long-term debt as shown in could be material. We may also have to pay fines or penalties or the table below.

make significant capital or operational expenditures related to the Balance as of Balance as of notice of violation we received from the EPA in connection with December 31, Securities Securities December 31, certain projects completed at Jeffrey Energy Center. In addition, 2003 Redeemed Issued 2004 significant capital or operational expenditures may be required in (InThousands) order to comply with future environmental regulations or in Long-term Debt Redemptions and Issuances:

connection with future remedial obligations. The following table Westar Energy does not include any amounts related to these possible expen- First mortgage bond series:

ditures. In addition, KCPL, the operator of our jointly owned 6.00% due 2014 .......... $ - $ - S 250,000 $ 250,000 8.5% due 2022 ........... 125,000 (125,000)

LaCygne Generating Station, has informed us that it is considering 7.65% due 2023 .......... 100,000 (100,000) updating or installing additional equipment related to emissions Pollution control bond series:

controls at the LaCygne Generating Station. If KCPL decides to 6.00% due 2033 .......... 58,340 (58,340) complete this work, we will incur costs beginning in 2005 and 5.00% due 2033 .......... 58,340 58,340 continuing through the completion of installation in 2007. We 6-7/8% senior unsecured notes expect that costs related to updating or installing emissions controls due August 1,2004 ....... 184,456 (184,456) will be material. These costs are not included in the following table. 9-3/4% senior unsecured notes We believe that these costs would qualify for recovery through rates. due2007 ............... 387,000 (127,000) - 260,000 6.80% senior unsecured notes Capital expenditures for 2004 and anticipated capital expenditures due2018 ............... 26,993 (26,993) for 2005 through 2007, including costs of removal, are shown in the Senior secured term loan due 2005 ............... 114,143 (114,143) - -

following table.

$995,932 $(735,932) $ 308,340 $ 568,340 Actual 2004 2005 2006 2007 KGE (inThousands) Pollution control bond series:

7.00% due 2031 .......... $327,500 $(327,500) $ - $ -

Replacementsand other. $ 138,376 S 151,600 $152,600 $ 168,200 7,700 17,300 42,100 5.30% due 2031 .......... - - 108,600 108,600 Additional capacity .......... 5,513 5.30% due 2031 .......... - - 18,900 18,900 New customer construction ... 38,038 45,700 64,300 49,500 2.65% due 2031 and Nuclear fuel ............... 20,965 4,900 19,300 24,000 putable 2006 ........... - - 100,000 100,000 Total capital expenditures ..... . 202,892 $ 209,900 S 253,500 $ 283,800 Variable rate due 2031 ..... - - 100,000 100,000

$327,500 S(327,500) $ 327,500 S 327,500 We prepare these estimates for planning purposes and revise our l-estimates from time to time. Actual expenditures will differ from Long-term debt affiliate ........ $103,093 $(103,093) $ - $

our estimates. These amounts do not include any estimate of expenditures that may be incurred as a result of the EPA investiga-On March 12, 2004, Westar Energy entered into a revolving credit tion or other enacted or proposed environmental regulations.

facility. The credit facility matures on March 12,2007. It is used as a Environmental expenditures could be material.

source of short-term liquidity. It allows us borrowings up to an Maturities of long-term debt at December 31, 2004 are as follows. aggregate limit of $300.0 million, including letters of credit up to a maximum aggregate amount of $50.0 million. At December 31, Year Principal Amount 2004, we had no outstanding borrowings and $15.3 million of (InThousands) letters of credit outstanding under the revolving credit facility. All 2005 ..................................................... S 65,000 borrowings under the revolving credit facility are secured by KGE 2006 . .100,000 first mortgage bonds.

2007 . .625,000 2008 ..................................................... - On January 18, 2005, Westar Energy sold $250.0 million aggregate 2009 . .145,078 principal amount of Westar Energy first mortgage bonds, Thereafter ............ ........................ 769,823 consisting of $125.0 million 5.15% bonds maturing in 2017 and

$1,704,901 $125.0 million 5.95% bonds maturing in 2035. On February 17, 2005, we used the net proceeds from the offering together with 29

2004 ANNUAL REPORT cash on hand, additional funds raised through the accounts favorable to us. Westar Energy and KGE have credit rating condi-receivable conduit facility and borrowings under Westar Energy's tions under our revolving credit agreement and in the agreements revolving credit facility, to redeem the remaining $260.0 million governing the sale of our accounts receivable discussed in Note 5 aggregate principal amount of Westar Energy 9.75% senior notes of the Notes to Consolidated Financial Statements, "Accounts due 2007. Together with accrued interest and a premium equal to Receivable and Variable Interest Entities" that affect the cost of approximately 12% of the outstanding senior notes, we paid borrowing but do not trigger a default. We may enter into new

$298.5 million to redeem the W'estar Energy 9.75% senior notes credit agreements that contain credit conditions, which could due 2007 After this transaction, we had $10.0 million outstanding affect our liquidity and/or our borrowing costs.

under the revolving credit facility and $30.0 million available under the accounts receivable conduit facility. Capital Structure Our consolidated capital structure at December 31, 2004 and 2003 Debt Covenants was as follows.

Some of our debt instruments contain restrictions that require us 2004 2003 to maintain various coverage and leverage ratios as defined in the Common equity ................................... 45% 31%

agreements. We calculate these ratios in accordance with our credit Preferred stock ..................................... 1% 1%

agreements. These ratios are used solely to determine compliance Debt ....................................... 54% 68%

with our various debt covenants. We were in compliance with these covenants at December 31, 2004. Total ....................................... 100% 100%

Interest Rate Swap Effective October 4, 2001, we entered into a $500.0 million interest OFF-BALANCE SHEET ARRANGEMENTS rate swap agreement with a term of two years. At that time, the Accounts Receivable Sales Program effect of the swap agreement was to fix the annual interest rate on Under a revolving accounts receivable sales program, we currently a term loan at 6.18%. We settled the swap agreement for a nominal sell up to $125.0 million of our accounts receivable. For additional amount on September 29, 2003. For information regarding ongoing detail, see Note 5 of the Notes to Consolidated Financial State-interest rates, see "Item 7A. Quantitative and Qualitative Disclosures ments, "Accounts Receivable and Variable Interest Entities."

About Market Risk."

LaCygne 2 Sale/Leaseback Agreement Credit Ratings In 1987, KGE sold and leased back its 50% undivided interest in Standard &Poor's Ratings Group (S&P), Moody's Investors Service the LaCygne 2 generating unit. The LaCygne 2 lease has an initial (Moody's) and Fitch Investors Service (Fitch) are independent term of 29 years, with various options to renew the lease or credit-rating agencies that rate our debt securities. These ratings repurchase the 50% undivided interest. KGE remains responsible indicate the agencies' assessment of our ability to pay interest and for its share of operating and maintenance costs and other related principal when due on our securities. operating costs of LaCygne 2. The lease is an operating lease for On February 23, 2005, Moody's upgraded its ratings for our debt financial reporting purposes. We recognized a gain on the sale, and affirmed the speculative liquidity rating it assigned to us of which was deferred and is being amortized over the lease term. See SGL-2, reflecting its view that we have "good" liquidity. On Note 23 of the Notes to Consolidated Financial Statements, December 22, 2004, Fitch raised its outlook rating to positive from "Leases," for additional information.

stable and affirmed its ratings as shown in the table below. On July 22, 2004, S&P improved its ratings on KGE's first mortgage CONTRACTUAL OBLIGATIONS AND bonds to BBB from BB+. COMMERCIAL COMMITMENTS As of March 1, 2005, ratings with these agencies are as shown in In the course of our business activities, we enter into a variety of the table below. contractual obligations and commercial commitments. Some of these result in direct obligations reflected on our consolidated Westar Energy Westar Energy KGE balance sheets while others are commitments, some firm and Mortgage Unsecured Mortgage Bond Rating Debt BondRating some based on uncertainties, not reflected in our underlying S&P.............................. 88- BB- BBB consolidated financial statements. The obligations listed below do Moody's .. Baa3 Bal Baa3 not include amounts for on-going needs for which no contractual Fitch .. BBB- BB+ BBB- obligations existed at December 31, 2004, and represent only those amounts that we were contractually obligated to meet at In general, less favorable credit ratings make debt financing more December 31, 2004. We may from time to time enter into new costly and more difficult to obtain on terms that are economically contracts to replace contracts that expire.

30 III

2004 ANNUAL REPORT Contractual Cash Obligations costs related to system restoration. We can provide no assurance The following table summarizes the projected future cash pay- that the KCC will approve our application, however, in the past the ments for our contractual obligations existing at December 31,2004. KCC has approved similar requests.

Contractual Obligations Total 2005(c) 2006(1-2007 2008-2009 Thereafter New Accounting Pronouncements (InThousands) In December 2004, the Financial Accounting Standards Board Long-term debt(a) ... $1,704,901 $ 65,000 $ 725,000 $145,078 $, 769,823 (FASB) issued SFAS No. 123R, "Share-Based Payment: An Interest payments on Amendment of FASB Statements No. 123 and 95."SFAS No. 123R long-term debt>) . . 846,537 107,087 199,523 85,136 454,791 requires companies to recognize as compensation expense the Adjusted long-term grant-date fair value of stock options and other equity-based debt . 2,551,438 172,087 924,523 230,214 1,224,614 compensation issued to employees. The provisions of the state-Capital leases(d) 24,201 5,267 8,569 5,903 4,462 ment are effective for financial statements issued for periods that Operating leases(e) - - 613,898 49,422 140,041 69,145 355,290 begin after June 15,2005, which will be our third quarter beginning Fossil fuel . 1,569,155 188,304 339,237 295,529 746,085 July 1, 2005.

Nuclear fuel .g.. 162,691 4,404 39,898 12,649 105,740 Unconditional purchase We currently use RSUs for stock-based awards granted to obligations . 34,612 28,601 6,011 - - employees. In addition, we have eliminated our employee stock Miscellaneous purchase plan and all outstanding options have vested. Given the obligations 2,032 816 1,216 - -

characteristics of our stock-based compensation program, we do Total contractual not expect the adoption of SEAS No. 123R to materially impact our obligations, including adjusted long-term results of operations.

debt .......... $4,958,027 $448,901 $1,459,495 $613,440 $2,436,191 Sale of Utility Assets

(-See Note 11 of the Notes to Consolidated Financial Statements, "Long-term In August 2003, we sold a portion of our transmission and distri-Dcbt,"for individual long-term debt maturities.

bution assets and rights to provide service to approximately 10,000 lWe calculate interest payments on our variable rate debt based on the effective interest rateatDecember31, 2004.

customers in an area of central Kansas. Total sales proceeds received were $33.3 million and we realized a gain of $11.9 million.

(c We have an obligation to pay rebates to customers in 2005 and 2006.

We may enter into similar transactions in the future.

(dIncludes principal and interest on capitalleases.

'Includes the LaCygne 2 lease, office space, operatingfacilities, office equipment, Impact of Regulatory Accounting operating equipment and other miscellaneous commitments.

We currently apply accounting standards that recognize the V)Coaland naturalgas commodity and transportationcontracts.

economic effects of rate regulation and record regulatory assets I Uranium concentrates, conversion, enrichment, fabrication and spent fuel disposal.

and liabilities related to our electric utility operations. If we deter-mine that we no longer meet the criteria of SFAS No. 71, we may have a material non-cash charge to earnings.

Commercial Commitments Our commercial commitments existing at December 31, 2004 are At December 31,2004, we had recorded regulatory assets currently outstanding letters of credit that expire in 2005. The letters of credit subject to recovery in future rates of approximately $442.9 million.

are comprised of $6.6 million related to our energy marketing and Of this amount, $191.6 million is related to income tax benefits trading activities, $5.2 million related to worker's compensation previously passed on to customers. The remainder of the regulatory and $4.5 million related to other operating activities for a total assets include asset retirement obligations, system restoration, loss outstanding balance of $16.3 million. on reacquired debt, refinancing costs on the LaCygne 2 lease, deferred employee benefit costs, deferred plant costs and coal OTHER INFORMATION contract settlement costs. We periodically review SFAS No. 71 criteria and believe that our net regulatory assets are probable of Ice Storm future recovery.

On January 4 and 5, 2005, substantially all of our service territory experienced a severe ice storm. The storm interrupted electric Asset Retirement Obligations service in a large portion of our service territory and damaged a In January 2003, we adopted SEAS No. 143, "Accounting for Asset significant portion of our electric distribution system. We estimate Retirement Obligations." SFAS No. 143 requires recognition of that we will incur $38.0 million to $42.0 million of system restora- legal obligations associated with the retirement of long-lived tion costs. Of this amount, we expect $6.0 million to $8.0 million to assets that result from the acquisition, construction, development be accounted for as capital expenditures and we expect the balance or normal operation of such assets. Concurrent with the recogni-related to maintenance expenditures to be accounted for as a tion of the liability, the estimated cost of an asset retirement regulatory asset. On February 3,2005, we filed an application for an obligation is capitalized and depreciated over the remaining life of accounting authority order with the KCC requesting that we be the asset. Any income effects are offset by regulatory accounting allowed to accumulate and defer for future recovery maintenance pursuant to SEAS No. 71.

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2 0 04 ANN UAL REPO RT Legal Liability -Wolf Creek Market Price Risks On January 1, 2003, we recognized the liability for our 47% share of Our economic hedging and trading activities involve risks, the estimated cost to decommission Wolf Creek. SFAS No. 143 including commodity price risk, interest rate risk and credit risk.

requires the recognition of the present value of the asset retirement Commodity price risk is the risk that changes in commodity prices obligation we incurred at the time Wolf Creek was placed into may impact the price at which we are able to buy and sell electricity service in 1985. On January 1, 2003, we recorded an asset and purchase fuels for our generating units. We believe we will retirement obligation of $74.7 million. In addition, we increased continue to experience volatility in the prices for these com-our property and equipment balance, net of accumulated modities. This volatility may increase or decrease future earnings.

depreciation, by $10.7 million. We also established a regulatory Interest rate risk represents the risk of loss associated with asset for $64.0 million, which represents the accretion of the movements in market interest rates. In the future, we may use liability since 1985 and the increased depreciation expense swaps or other financial instruments to manage interest rate risk.

associated with the increase in plant. The asset retirement obligation is included on our consolidated balance sheets in other Credit risk represents the risk of loss resulting from non-long-term liabilities. Costs to retire Wolf Creek are currently being performance by a counterparty of its contractual obligations. We recovered through rates as provided by the KCC. have exposure to credit risk and counterparty default risk with our retail, wholesale and energy marketing activities. We maintain Non-legal Liability -Cost of Removal credit policies intended to reduce overall credit risk. We employ We have recovered amounts in rates to provide for recovery of the additional credit risk control mechanisms that we believe are probable costs of removing utility plant assets, but which do not appropriate, such as letters of credit, parental guarantees and represent legal retirement obligations. At December 31, 2004, master netting agreements with counterparties that allow for Westar Energy had $1.3 million in removal costs classified as a offsetting exposures. Results actually achieved from economic regulatory asset and KGE had $2.6 million in removal costs hedging and trading activities could vary materially from intended classified as a regulatory liability. At December 31, 2003, we had results and could materially affect our consolidated financial results

$6.6 million in removal costs classified as a regulatory asset.The net depending on the success of our credit risk management efforts.

amount related to non-legal retirement costs can fluctuate based on amounts related to removal costs recovered compared to Commodity Price Exposure removal costs incurred. We engage in both financial and physical trading to manage our commodity price risk. We trade electricity, coal, natural gas and oil.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES We use financial instruments, including forward contracts, options ABOUT MARKET RISK and swaps and we trade energy commodity contracts daily. We may also use economic hedging techniques to manage overall fuel Hedging Activity expenditures. We procure physical product under forward agree-We use financial and physical instruments to economically hedge ments and spot market transactions.

the price of a portion of our anticipated fossil fuel needs. At the time we enter into these transactions, we are unable to determine We are involved in trading activities to reduce risk from market what the value will be when the agreements are actually settled. fluctuations, enhance system reliability and increase profits. Net open positions exist, or are established, due to the origination of In an effort to mitigate market risk associated with fuel and energy new transactions and our assessment of, and response to, chang-prices, we may use economic hedging arrangements to reduce our ing market conditions. To the extent we have open positions, we exposure to price increases. Our future exposure to changes in are exposed to the risk that changing market prices could have a prices will be dependent on the market prices and the extent and material, adverse impact on our consolidated financial position or effectiveness of any economic hedging arrangements into which results of operations.

we enter.

We manage and measure the market price risk exposure of our See Note 6 of the Notes to Consolidated Financial Statements, trading portfolio using a variance/covariance value-at-risk (VaR)

"Financial Instruments, Energy Marketing and Risk Management model. The VaR model is designed to measure the predicted

- Derivative Instruments and Hedge Accounting - Hedging maximum one-day loss at a 95% confidence level. In addition to Activities," for detailed information regarding hedging relation- VaR, we employ additional risk control processes such as stress ships and an interest rate swap we entered into during the third testing, daily loss limits, credit limits and position limits. We expect quarter of 2001. to use similar control processes in 2005.

32 III

20 04 ANN U AL REPO RT The use of the VaR method requires assumptions, including the indicate, especially during adverse weather or market conditions.

selection of a confidence level for potential losses and the If we were to have a 10% increase in our purchased power price estimated holding period. This means that we are also exposed to from 2004 to 2005, given the amount of power purchased for the risk that we value and mark illiquid prices incorrectly. We utility operations during 2004, we would have exposure of approxi-expressVaR as a potential dollar loss based on a 95% confidence mately $4.7 million of operating income. Due to the volatility of the level using a one-day holding period. The calculation includes power market, we believe past prices are not a good predictor of derivative commodity instruments used for both trading and risk future prices.

management purposes. TheVaR amounts for 2004 and 2003 were as follows. We use various fossil fuel types, including coal, natural gas and oil, to operate our plants. A significant portion of our coal require-2D04 2003 ments are purchased under long-term contracts. During 2004, we (InThousands) experienced an approximate 37% increase, or $1.79 per MMIBtu, in High ....................................... $2,891 $1,393 our average cost for natural gas purchased for utility operations.

Low ....................................... 713 144 Due to the volatility of natural gas prices, we have increasingly Average ....................................... 1,321 722 operated facilities that have allowed us to use lower cost fuel types as generating unit constraints and environmental restrictions We have considered a number of risks and costs associated with allow, primarily by using oil in our facilities that also burn natural the future contractual commitments included in our energy gas. The average cost for oil purchased for utility operations portfolio. These risks include credit risks associated with the increased $0.53 per MMBtu, or approximately 16%, compared to financial condition of counterparties, product location (basis) the average cost in 2003. The average cost of oil burned was $2.85 differentials and other risks. Declines in the creditworthiness of our per MMBtu less than the average cost of the natural gas we burned.

counterparties could have a material adverse impact on our overall If we were to have a 10% increase in our price for natural gas and exposure to credit risk. We maintain credit policies with regard to oil burned from 2004 to 2005, based on MMvBtus of natural gas and our counterparties that we believe are effective in managing overall oil burned during 2004, we would have exposure of approximately credit risk.There can be no assurance that the employment ofVaR, $6.7 million of operating income. Due to the volatility of natural or other risk management tools we employ, will eliminate the risk gas prices, past prices cannot be used to predict future prices.

of loss.

We have 100% of the uranium and conversion services required to We are also exposed to commodity price changes outside of operate Wolf Creek under contract through September 2009. We trading activities. We use derivative contracts for non-trading also have 100% of the enrichment services required to operateWolf purposes and a mix of various fuel types primarily to reduce Creek under contract through March 2008. We will be exposed to exposure relative to the volatility of market and commodity prices. the price risk associated with any components not currently under The wholesale power market is extremely volatile in price and contract if a counterparty were to fail its contractual obligations.

supply. This volatility impacts our costs of power purchased and our participation in energy trades. If we were unable to generate an Additional factors that affect our commodity price exposure are the adequate supply of electricity for our customers, we would purchase quantity and availability of fuel used for generation and the power in the wholesale market to the extent it is available, subject quantity of electricity customers consume. Quantities of fossil fuel to possible transmission constraints, and/or implement curtailment used for generation vary from year to year based on the availability, or interruption procedures as permitted in our tariffs and terms price and deliverability of a given fuel type as well as planned and and conditions of service. The increased expenses or loss of scheduled outages at our facilities that use fossil fuels and the revenues associated with this could be material and adverse to our nuclear refueling schedule. Our customers' electricity usage could consolidated results of operations and financial condition. also vary from year to year based on the weather or other factors.

From 2003 to 2004, we experienced an approximate 6% increase in Interest Rate Exposure the average price per MWh of electricity purchased for utility We had approximately $286.9 million of variable rate debt and operations.Volatility in the prices for power we purchase could be current maturities of fixed rate debt at December 31, 2004. A greater than the average price increase indicates. Additionally, 100 basis point change in interest rates applicable to this debt short-term, but extreme price volatility could potentially be of would impact operating income on an annualized basis by approxi-greater significance than the change in the average price would mately $2.8 million.

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2 004 ANN UAL REPO RT ITEM 8. FINANCIAL STATEMENTS AND MANAGEMENT'S REPORT ON SUPPLEMENTARY DATA INTERNAL CONTROL OVER FINANCIAL REPORTING TABLE OF CONTENTS "le are responsible for establishing and maintaining adequate PAGE internal control over financial reporting. Internal control over Management's Report on Internal Control financial reporting is defined in Rules 13a-15(f) promulgated Over Financial Reporting ................... 34 under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company's principal executive Reports of Independent Registered Public and principal financial officers and effected by the company's Accounting Firm .......................... 35 board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting Financial Statements: and the preparation of financial statements for external purposes in Westar Energy, Inc. and Subsidiaries: accordance with generally accepted accounting principles and includes those policies and procedures that:

Consolidated Balance Sheets, as of December 31, 2004 and 2003 .......... 37 a Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of Consolidated Statements of Income (Loss) the assets of the company; for the years ended December 31, 2004,

• Provide reasonable assurance that transactions are recorded as 2003 and 2002 ...................... 38 necessary to permit preparation of financial statements in Consolidated Statements of Comprehensive accordance with generally accepted accounting principles, and Income (Loss) for the years ended that receipts and expenditures of the company are being made December 31, 2004, 2003 and 2002 ..... 39 only in accordance with authorizations of management and directors of the company; and Consolidated Statements of Cash Flows wProvide reasonable assurance regarding prevention or timely for the years ended December 31, 2004, detection of unauthorized acquisition, use or disposition of the 2003 and 2002 ...................... 40 company's assets that could have a material effect on the Consolidated Statements of Shareholders' financial statements.

Equity for the years ended December 31, Because of its inherent limitations, internal control over financial 2004, 2003 and 2002 ................. 41 reporting may not prevent or detect misstatements. Projections of Notes to Consolidated Financial Statements . . 42 any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in Financial Schedules: conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Schedule II -Valuation and Qualifying Accounts ....................... 70 We assessed the effectiveness of our internal control over financial reporting at December 31, 2004. In making this assessment, we SCHEDULES OMITTED used the criteria set forth by the Committee of Sponsoring The following schedules are omitted because of the Organizations of the Treadway Commission (COSO) in Internal absence of the conditions under which they are required Control - Integrated Framework. Based on the assessment, we or the information is included on our consolidated believe that, at December 31,2004, our internal control over financial financial statements and schedules presented: reporting is effective based on those criteria. Our independent registered public accounting firm has issued an audit report on our I, III, IV,andV. assessment of our internal control over financial reporting.

34 11I

2 0 0 4 ANN UAL REPO RT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Westar Energy, Inc.

Topeka, Kansas We have audited management's assessment, included in the preparation of financial statements in accordance with generally accompanying Management's Report on Internal Controls over accepted accounting principles, and that receipts and expenditures Financial Reporting that Westar Energy, Inc. and subsidiaries (the of the company are being made only in accordance with authoriza-

"Company") maintained effective internal control over financial tions of management and directors of the company; and (3) provide reporting as of December 31, 2004, based on criteria established in reasonable assurance regarding prevention or timely detection of Internal Control Integrated Framework issued by the Committee of unauthorized acquisition, use, or disposition of the company's Sponsoring Organizations of the Treadway Commission. The assets that could have a material effect on the financial statements.

Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of Because of the inherent limitations of internal control over financial the effectiveness of internal control over financial reporting. Our reporting, including the possibility of collusion or improper responsibility is to express an opinion on management's assess- management override of controls, material misstatements due to ment and an opinion on the effectiveness of the Company's error or fraud may not be prevented or detected on a timely basis.

internal control over financial reporting based on our audit. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the We conducted our audit in accordance with the standards of the risk that the controls may become inadequate because of changes Public Company Accounting Oversight Board (United States). in conditions, or that the degree of compliance with the policies or Those standards require that we plan and perform the audit to procedures may deteriorate.

obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material In our opinion, management's assessment that the Company respects. Our audit included obtaining an understanding of maintained effective internal control over financial reporting as internal control over financial reporting, evaluating management's of December 31, 2004, is fairly stated, in all material respects, based assessment, testing and evaluating the design and operating on the criteria established in InternalControl-IntegratedFramework effectiveness of internal control, and performing such other issued by the Committee of Sponsoring Organizations of the procedures as we considered necessary in the circumstances. We Treadway Commission. Also in our opinion, the Company main-believe that our audit provides a reasonable basis for our opinions. tained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established A company's internal control over financial reporting is a process in Internal Control - IntegratedFrameworkissued by the Committee designed by, or under the supervision of, the company's principal of Sponsoring Organizations of the Treadway Commission.

executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, We have also audited, in accordance with the standards of the management, and other personnel to provide reasonable assurance Public Company Accounting Oversight Board (United States), the regarding the reliability of financial reporting and the preparation consolidated financial statements and financial statement schedule of financial statements for external purposes in accordance with as of and for the year ended December 31, 2004 of the Company generally accepted accounting principles. A company's internal and our report dated March 11, 2005 expressed an unqualified opinion control over financial reporting includes those policies and on those financial statements and financial statement schedule.

procedures that (1) pertain to the maintenance of records that, in DELOIITE &TOUCHE LLP reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable Kansas City, Missouri assurance that transactions are recorded as necessary to permit March 11, 2005 35

2 00 4 ANN UAL REPO RT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Westar Energy, Inc.

Topeka, Kansas We have audited the accompanying consolidated balance sheets As discussed in Note 16 to the consolidated financial statements, of Westar Energy, Inc. and subsidiaries (the "Company") as of effective January 1, 2003, the Company adopted Statement of December 31, 2004 and 2003, and the related consolidated state- Financial Accounting Standard No. 143, "Accounting for Asset ments of income (loss), comprehensive income (loss), shareholders' Retirement Obligations."

equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial As discussed in Note 5 to the consolidated financial statements, statement schedule listed in the Index at Item 15. These financial effective October 1, 2003, the Company adopted FIN 46R, statements and financial statement schedule are the responsibility "Consolidation of Variable Interest Entities."

of the Company's management. Our responsibility is to express an As discussed in Note 4 to the consolidated financial statements, opinion on the financial statements and financial statement effective January 1, 2002, the Company adopted Statement of schedule based on our audits. Financial Accounting Standard No. 142, "Goodwill and Other We conducted our audits in accordance with the standards of the Intangible Assets," and Statement of Financial Accounting Public Company Accounting Oversight Board (United States). Standard No. 144,"Accounting for the Impairment or Disposal of Those standards require that we plan and perform the audit to Long-Lived Assets."

obtain reasonable assurance about whether the financial statements We have also audited, in accordance with the standards of the are free of material misstatement. An audit includes examining, on Public Company Accounting Oversight Board (United States), the a test basis, evidence supporting the amounts and disclosures in effectiveness of the Company's internal control over financial the financial statements. An audit also includes assessing the reporting as of December 31, 2004, based on the criteria established accounting principles used and significant estimates made by in Internal Control- IntegratedFramework issued by the Committee management, as well as evaluating the overall financial statement of Sponsoring Organizations of theTreadway Commission and our presentation. "le believe that our audits provide a reasonable basis report dated March 11, 2005 expressed an unqualified opinion on for our opinion. management's assessment of the effectiveness of the Company's In our opinion, such consolidated financial statements present internal control over financial reporting and an unqualified fairly, in all material respects, the financial position of the Company opinion on the effectiveness of the Company's internal control and subsidiaries as of December 31, 2004 and 2003, and the results over financial reporting.

of their operations and their cash flows for each of the three years DELOITTE &TOUCHE LLP in the period ended December 31,2004, in conformity with account-ing principles generally accepted in the United States of America. Kansas City, Missouri Also, in our opinion, such financial statement schedule, when March 11, 2005 considered in relation to the basic consolidated financial state-ments taken as a whole, presents fairly, in all material respects, the information set forth therein.

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2 004 ANN UAL REPO RT WESTAR ENERGY, INC. CONSOLIDATED BALANCE SHEETS As of December 31, 2004 2003 (Dollars in Thousands)

ASSETS CURRENT ASSETS:

Cash and cash equivalents ........................................................... S 24,611 $ 79,559 Restricted cash ..................................................................... 12,279 17,925 Accounts receivable, net ............................................................. 92,532 80,971 Inventories and supplies ............................................................. 124,563 134,931 Energy marketing contracts .......................................................... 23,155 35,385 Tax receivable ...................................................................... 90,845 5,961 Deferred tax assets .................................................................. 7,218 123,256 Prepaid expenses ................................................................... 29,179 32,430 Other ............................................................................. 11,558 10,747 Assets of discontinued operations ..................................................... 570,541 Total Current Assets .............................................................. 415,940 1,091,706 PROPERTY, PLANT AND EQUIPMENT, NET . ...................................... 3,910,987 3,909,500 OTHER ASSETS:

Restricted cash ..................................................................... 27,408 31,854 Regulatory assets ................................................................... 442,944 411,315 Nuclear decommissioning trust ....................................................... 91,095 80,075 Energy marketing contracts .......................................................... 4,904 4,190 Other ............................................................................. 192,433 214,335 Total Other Assets ............................................................... 758,784 741,769 TOTAL ASSETS ......................................................................... $ 5,085,711 $ 5,742,975 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES:

Current maturities of long-term debt .................................................. S 65,000 $ 185,941 Short-term debt .................................................................... - 1,000 Accounts payable ................................................................... 105,593 92,994 Accrued taxes ...................................................................... 97,874 108,249 Energy marketing contracts .......................................................... 20,431 28,000 Accrued interest .................................................................... 30,506 33,651 Other ............................................................................. 99,170 85,904 Liabilities of discontinued operations .................................................. - 475,597 Total Current Liabilities ........................................................... 418,574 1,011,336 LONG-TERM LIABILITIES:

Long-term debt, net ................................................................. 1,639,901 1,948,253 Long-term debt, affiliate ............................................................. - 103,093 Unamortized investment tax credits .................................................... 68,957 74,291 Deferred income taxes ............................................................... 927,087 969,544 Deferred gain from sale-leaseback ..................................................... 138,981 150,810 Accrued employee benefits ........................................................... 120,152 121,308 Asset retirement obligation ........................................................... 87,118 80,695 Nuclear decommissioning ............................................................ 91,095 80,075 Energy marketing contracts .......................................................... 1,547 1,111 Other ............................................................................. 182,977 165,699 Total Long-Term Liabilities ........................................................ 3,257,815 3,694,879 COMMITMENTS AND CONTINGENCIES (see notes 15 and 17)

SHAREHOLDERS' EQUITY:

Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares .............................................. 21,436 21,436 Common stock, par value $5 per share; authorized 150,000,000 shares; issued 86,029,721 shares and 72,840,217 shares, respectively ............................ 430,149 364,201 Paid-in capital ...................................................................... 912,932 776,754 Unearned compensation ............................................................. (10,361) (15,879)

Loans to officers .................................................................... (2)

Retained earnings (accumulated deficit) ................................................ 55,053 (102,782)

Treasury stock, at cost, 0 and 203,575 shares, respectively .................................. (2,391) 37 Accumulated other comprehensive income (loss), net ..................................... 113 (4,577)

Total Shareholders'Equity ......................................................... 1,409,322 1,036,760 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ............................................ S 5,085,711 $ 5,742,975 The accompanying notes are an integral part of these consolidatedfinancialstatements.

2 004 ANN UAL REPO RT WESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Year Ended December 31, 2004 2003 2002 (Dollars in Thousands, Except Per Share Amounts)

SALES . S 1,464,489 $ 1,461,143 $ 1,423,151 OPERATING EXPENSES:

Fuel and purchased power . 419,788 390,312 379,500 Operating and maintenance. 412,002 371,372 379,220 Depreciation and amortization. 169,310 167,236 171,807 Selling, general and administrative. 173,498 160,825 218,345 Total Operating Expenses. 1,174,598 1,089,745 1,148,872 INCOME FROM OPERATIONS. 289,891 371,398 274,279 OTHER INCOME (EXPENSE):

Investment earnings. 16,746 38,505 76,795 Gain on sale of ONEOK stock . - 99,327 -

Loss on extinguishment of debt and settlement of putable/callable notes. (18,840) (26,455) (1,541)

Other income . 2,756 2,854 1,316 Other expense . (14,879 ) (16,590) (38,380)

Total Other Income (Expense). (14,217 ) 97,641 38,190 Interest expense. 142,151 224,356 235,172 INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE . 133,523 244,683 77,297 Income tax expense (benefit). 33,443 81,768 (11,519)

INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE. 100,080 162,915 88,816 Results of discontinued operations, net of tax Discontinued operations, net of tax . 78,790 (77,905) (258,100)

Cumulative effect of accounting change, net of tax. - -(623,717)

Results of discontinued operations, net of tax . 78,790 (77,905) (881,817)

NET INCOME (LOSS) . 178,870 85,010 (793,001)

Preferred dividends, net of gain on reacquired preferred stock . 970 968 399 EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK . $ 177,900 $ 84,042 $ (793,400)

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (see note 2):

Basic earnings available from continuing operations before accounting change. S 1.19 $ 2.24 $ 1.23 Discontinued operations, net of tax . 0.95 (1.08) (3.60)

Accounting change, including discontinued operations, net of tax. - - (8.69)

Basic earnings (loss) available . $ 2.14 $ 1.16 $ (11.06)

Diluted earnings available from continuing operations before accounting change. S 1.19 $ 2.20 $ 1.22 Discontinued operations, net of tax . 0.94 (1.06) (3.57)

Accounting change, including discontinued operations, net of tax. - - (8.63)

Diluted earnings (loss) available . S 2.13 $ 1.14 $ (10.98)

Average equivalent common shares outstanding . 82,941,374 72,428,728 71,731,580 DIVIDENDS DECLARED PER COMMON SHARE . S 0.80 $ 0.76 $ 1.20 38 The accompanying notes are an integralpart of these consolidatedfinancialstatements.

2004 ANNUAL REPORT WESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Year Ended December 31, 2004 2003 2002 (Dollars in Thousands)

NET INCOME (LOSS) . $178,870 $ 85,010 $ (793,001)

OTHER COMPREHENSIVE INCOME:

Unrealized holding gain on marketable securities arising during the period . $ 11 $ 99,412 $ -

Reclassification adjustment for gain included in net income . 11 (99,310) 102 Unrealized holding gain on cash flow hedges arising during the period . 12,270 19,466 Reclassification adjustment for (gain) loss included in net income . (4,543) 7,727 1,992 21,458 Minimum pension liability adjustment . 7,769 284 (1,341)

Foreign currency translation adjustment . 1,044 Other comprehensive income, before tax . 7,780 8,113 21,161 Income tax expense related to items of other comprehensive income ..................... (3,090) (3,188) (8,032)

Other comprehensive gain, net of tax ............. 4,690 4,925 13,129 COMPREHENSIVE INCOME (LOSS) .......................... $183,560 $ 89,935 $ (779,872) 39 The accompanyingnotes are an integralpart of these consolidatedfinancialstatements.

2 004 ANN UAL REPO RT WESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2004 2003 2002 (Dollars in Thousands)

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:

Net income (loss) .................................................... S 178,870 $ 85,010 $ (793,001)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Discontinued operations, net of tax ................................... (78,790) 77,905 881,817 Depreciation and amortization ....................................... 169,310 167,236 171,807 Amortization of nuclear fuel ......................................... 14,221 12,410 13,142 Amortization of deferred gain from sale-leaseback ..................... (11,828) (11,828) (11,828)

Amortization of prepaid corporate-owned life insurance ................. 12,622 14,320 20,321 Non-cash stock compensation ....................................... 7,916 6,885 14,006 Net changes in energy marketing assets and liabilities ................... 4,383 (1,855) 20,229 Loss on extinguishment of debt and settlement of putable/callable notes 18,840 26,455 1,541 Net changes in fair value of call option ................................ 2,178 22,609 Equity in earnings from investments .................................. (9,670)

Gain on sale of ONEOK stock ....................................... (99,327)

Accrued liability to certain former officers ............................. 8,384 1,205 22,928 (Gain) loss on sale of utility plant and property ......................... (503) (11,912) 1,424 Net deferred income taxes and credits ................................ (5,215) (100,275) 35,111 Changes in working capital items, net of acquisitions and dispositions:

Restricted cash .................................................... 7,825 (4,794) (6,596)

Accounts receivable, net ............................................ (11,561) (32,031) (4,534)

Inventories and supplies ............................................ 10,368 8,607 (8,955)

Prepaid expenses and other ......................................... (40,557) 16,897 (49,079)

Accounts payable .................................................. 12,182 6,231 (21,396)

Accrued taxes ..................................................... 43,463 81,135 (7,834)

Other current liabilities ............................................. (5,046) (84,021) (13,339)

Changes in other, assets ............................................... 10,566 2,451 (30,869)

Changes in other, liabilities ............................................ 8,738 (12,245) 30,247 Cash flows from operating activities ............................... 354,188 150,637 278,081 CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:

Additions to property, plant and equipment .............................. (188,447) (150,378) (126,763)

Removal, dismantlement and salvage of property, plant and equipment ....... (14,445) (13,094) (13,621)

Investment in corporate-owned life insurance ............................. (19,658) (19,599) (19,399)

Proceeds from investment in corporate-owned life insurance ................ - - 7,859 Proceeds from sale of Protection One .................................... 81,670 --

Proceeds from sale of Protection One bonds .............................. 26,640 - -

Proceeds from sale of plant and property ................................. 8,604 33,303 1,205 Proceeds from sale of international investment ............................ 11,219 - -

Proceeds from sale of ONEOK stock .................................... - 801,841 -

Issuance of officer loans and interest, net of payments ...................... 2 438 (308)

Proceeds from other investments ....................................... 9,591 801 18,296 Cash flows (used in) from investing activities ........................ (84,824) 653,312 (132,731)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:

Short-term debt, net .................................................. (1,000) - (221,300)

Proceeds from long-term debt .......................................... 623,301 - 1,350,069 Retirements of long-term debt .......................................... (1,188,081) (963,330) (1,021,993)

Funds in trust for debt repayments ...................................... 78 145,182 (135,000)

Purchase of call option investment ...................................... - (65,785)

Repayment of capital leases ............................................ (4,977) (5,138) (5,019)

Borrowings against cash surrender value of corporate-owned life insurance .... 57,090 58,818 61,120 Repayment of borrowings against cash surrender value of corporate-owned life insurance ............................... (444) (419) (8,490)

Issuance of common stock, net ......................................... 245,130 - 2,551 Cash dividends paid .................................................. (56,189) (57,726) (73,535)

Retirement of preferred stock ........................................... - (1,547)

Acquisition of treasury stock ........................................... - - (19,544)

Reissuance of treasury stock ............................................ 1,927 7,260 255 Cash flows (used in) financing activities ............................ (323,165) (881,138) (72,433)

Net cash (used in) from discontinued operations ............................. (1,147) 43,699 (48,059)

Foreign currency translation .............................................. _ - 1,044 NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS ................... (54,948) (33,490) 25,902 CASH AND CASH EQUIVALENTS:

Beginning of period ................................................... 79,559 113,049 87,147 End of period ........................................................ $ 24,611 $ 79,559 $ 113,049 The accompanying notes are an integral partof these consolidatedfinancialstatements.

Ill

2 0 0 4 ANN UAL REPO RT WESTAR ENERGY, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY 2004 2003 2002 Year Ended December 31, Shares Amount Shares Amount Shares Amount (Dollars in Thousands)

Cumulative preferred stock:

Beginning balance ........................... 214,363 $ 21,436 214,363 $ 21,436 239,364 $ 23,936 Retirement of preferred stock ................. (25,001) (2,500)

Ending balance ............................. 214,363 21,436 214,363 21,436 214,363 21,436 Common stock:

Beginning balance ........................... 72,840,217 364,201 72,840,217 364,201 86,205,417 431,027 Issuance of common stock .................... 13,189,504 65,948 - - 6,936,289 34,681 Retirement of common stock .................. - - - - (20,301,489) (101,507)

Ending balance ............................. 86,029,721 430,149 72,840,217 364,201 72,840,217 364,201 Paid-in capital:

Beginning balance ........................... 776,754 825,744 1,196,765 Preferred dividends, net of retirements .......... 653 728 (1,035)

Issuance of common stock, net ................ 192,337 - 76,586 Dividends on common stock .................. (46,473) (53,501) (87,088)

Retirement of common stock .................. - (349,397)

Issuance of treasury stock ..................... 1,230 671 2 Grant of restricted stock ...................... 1,417 7,631 7,872 Stock compensation ......................... (12,986) (4,519) (17,961)

Ending balance ............................. 912,932 776,754 825,744 Unearned compensation:

Beginning balance ........................... (15,879) (14,742) (21,920)

Grant of restricted stock ...................... (1,417) (7,631) (7,872)

Amortization of restricted stock ............... 6,838 6,494 8,647 Forfeited restricted stock ..................... 97 - 6,403 Ending balance ............................. (10,361) (15,879) (14,742)

Loans to officers:

Beginning balance ........................... (2) (1,832) (1,973)

Issuance of officer loans and interest, net of payments .......................... 2 438 (309)

Reclass loans of former officers to other assets ... - 1,392 450 Ending balance ............................. (2) (1,832)

Retained earnings (accumulated deficit):

Beginning balance ........................... (102,782) (185,961) 606,502 Net income (loss) ........................... 178,870 85,010 (793,001)

Preferred dividends, net of retirements .......... (1,074) (1,696) 597 Dividends on common stock .................. (19,786) - -

Issuance of treasury stock ..................... (175) (135) (59)

Ending balance ............................. 55,053 (102,782) (185,961)

Treasury stock:

Beginning balance ........................... (203,575) (2,391) (1,333,264) (18,704) (15,097,987) (364,901)

Issuance of common stock .................... - - - - (5,253,502) (86,869)

Retirement of common stock .................. - - 20,301,489 450,904 Acquisition of treasury stock .................. - - - - (1,434,100) (19,508)

Issuance of treasury stock ..................... 203,575 2,391 1,129,689 16,313 150,836 1,670 Ending balance ............................. - - (203,575) (2,391) (1,333,264) (18,704)

Accumulated other comprehensive income (loss):

Beginning balance ........................... (4,577) (9,502) (22,631)

Unrealized gain on marketable securities ........ 11 102 Unrealized gain on cash flow hedges ........... 7,727 21,458 Minimum pension liability adjustment .......... 7,769 284 (1,341)

Foreign currency translation adjustment ........ 1,044 Income tax expense .......................... (3,090) (3,188) (8,032)

Ending balance ............................. 113 (4,577) (9,502)

Total Shareholders' Equity ....................... $1,409,322 $1,036,760 $ 980,640 41 The accompanying notes are an integralpart of these consolidatedfinancialstatements.

2 004 ANN UAL REPO RT WESTAR ENERGY, INC. Regulatory Accounting NOTES TO CONSOLIDATED FINANCIAL STATEMENTS We currently apply accounting standards for our regulated utility

1. DESCRIPTION OF BUSINESS operations that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards We are the largest electric utility in Kansas. Unless the context (SFAS) No. 71, "Accounting for the Effects of Certain Types of otherwise indicates, all references in this Annual Report on Form Regulation,"and, accordingly, have recorded regulatory assets and 10-K to"the company,""we,""us,""our" and similar words are to liabilities when required by a regulatory order or based on Westar Energy, Inc. and its consolidated subsidiaries. The term regulatory precedent.

"XWestar Energy"refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated Regulatory assets represent incurred costs that have been deferred subsidiaries. We provide electric generation, transmission and because they are probable of future recovery in customer rates.

distribution services to approximately 653,000 customers in Regulatory liabilities represent probable obligations to make Kansas. Westar Energy provides these services in central and refunds to customers for previous collections for costs that are not northeastern Kansas, including the cities of Topeka, Lawrence, likely to be incurred in the future. Regulatory assets and liabilities Manhattan, Salina and Hutchinson. Kansas Gas and Electric reflected on our consolidated balance sheets are as follows.

Company (KGE), Westar Energy's wholly owned subsidiary, As of December 31, 2004 2003 provides these services in south-central and southeastern Kansas, (inThousands) including the city of Wichita, Kansas. Both Westar Energy and KGE Amounts due from customers for future income taxes, net . . $191,597 $207,812 conduct business using the name Westar Energy. Our corporate Debt reacquisition costs ............................. 45,203 25,155 headquarters is located at 818 South Kansas Avenue, Topeka, Deferred employee benefit costs ...................... 39,727 18,424 Kansas 66612.

Deferred plant costs ............ 27,979 28,532 KGE owns a 47% interest in the Wolf Creek Generating Station 2002 ice storm costs ............................... 17,774 16,369 (Wolf Creek), a nuclear power plant located near Burlington, Asset retirement obligations ......................... 77,349 70,455 Kansas, and a 47% interest in VWIolf Creek Nuclear Operating KCC depreciation ........................ 22,596 14,294 Corporation (WCNOC), the operating company for Wolf Creek. Wolf Creek outage ................................ 6,467 13,645 Other regulatory assets ............................. 14,252 16,629

2.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Total regulatory assets ............................ $442,944 $411,315 Total regulatory liabilities .$ 29,292 $ 14,323 Principles of Consolidation We prepare our consolidated financial statements in accordance

• Amounts due from customers for future income taxes, net: In with Generally Accepted Accounting Principles (GAAP) for the United States of America. Our consolidated financial statements accordance with various rate orders, we have reduced rates to include all operating divisions and majority owned subsidiaries for reflect the tax benefits associated with certain accelerated tax which we maintain controlling interests. Common stock deductions. We believe it is probable that the net future increases investments that are not majority owned are accounted for using in income taxes payable will be recovered from customers when the equity method when our investment allows us the ability to these temporary tax benefits reverse. We have recorded a exert significant influence. Undivided interests in jointly-owned regulatory asset for these amounts. We also have recorded a generation facilities are consolidated on a pro rata basis. All regulatory liability for our obligation to reduce rates charged material intercompany accounts and transactions have been customers for deferred taxes recovered from customers at eliminated in consolidation. corporate tax rates higher than the current tax rates. The rate reduction will occur as the temporary differences resulting in the Use of Management's Estimates excess deferred tax liabilities reverse. The tax-related regulatory When we prepare our consolidated financial statements, we are assets and liabilities as well as unamortized investment tax required to make estimates and assumptions that affect the credits are also temporary differences for which deferred income reported amounts of assets, liabilities, revenues and expenses, and taxes have been provided. These items are measured by the related disclosure of contingent assets and liabilities at the date of expected cash flows to be received or settled through future our consolidated financial statements and the reported amounts of rates. The net regulatory asset for these tax items is classified revenues and expenses during the reporting period. We evaluate above as amounts due from customers for future income taxes.

our estimates on an on-going basis, including those related to bad

• Debt reacquisition costs: Includes loss on reacquired debt and debts, inventories, valuation of commodity contracts, depreciation, refinancing costs on the LaCygne 2 generating unit lease. Debt unbilled revenue, investments, valuation of our energy marketing reacquisition costs are amortized over the original term of the portfolio, intangible assets, income taxes, pension and other post- reacquired debt or, if refinanced, the term of the new debt.

retirement and post-employment benefits, our asset retirement

• Deferred employee benefit costs: Employee benefit costs obligations including decommissioning of WIolf Creek, net amount include pension benefit obligations and post-retirement and of tax benefits realizable from the disposition of our monitored post-employment expenses.

security businesses, environmental issues, contingencies and 42 litigation. Actual results may differ from those estimates under different assumptions or conditions.

2 004 ANN UAL REPO RT

• Deferred plant costs: Deferred plant costs under SPAS No. 90, Property, Plant and Equipment "Regulated Enterprises - Accounting for Abandonments and Property, plant and equipment is stated at cost. For utility plant, Disallowances of Plant Costs,"related to the Wolf Creek nuclear cost includes contracted services, direct labor and materials, generating facility will be recovered over the term of the plant's indirect charges for engineering and supervision, and an allowance operating license through 2025. for funds used during construction (AFUDC). AFUDC represents

. 2002 ice storm costs: We accumulated and deferred for future the cost of borrowed funds used to finance construction projects.

recovery costs related to system restoration from an ice storm The AFUDC rate was 3.79% in 2004, 5.27% in 2003 and 5.95% in that occurred in January 2002. We were authorized to accrue 2002.The cost of additions to utility plant and replacement units of carrying costs on this item. Recovery of this asset will be property is capitalized. AFUDC capitalized was $1.8 million in considered during the 2005 rate review. 2004, $1.5 million in 2003 and $2.2 million in 2002.

. Asset retirement obligations: Asset retirement obligations represent amounts associated with our legal obligation to retire Maintenance costs and replacement of minor items of property are Wolf Creek. We recover final retirement costs through rates as charged to expense as incurred. Normally, when a unit of depre-provided by the Kansas Corporation Commission (KCC). We ciable property is retired, the original cost, less salvage value, is have placed amounts recovered through rates in a trust.The trust's charged to accumulated depreciation.

funds will be used to pay for the costs to retire and decommission Depreciation Wolf Creek. See Note 16, "Asset Retirement Obligations," for information regarding our Nuclear DecommissioningTrust Fund. Utility plant is depreciated on the straight-line method at rates

• KCC depreciation: Due to the change in our depreciation rates based on the estimated remaining useful lives of the assets, which for ratemaking purposes for Wolf Creek and LaCygne 2, we are based on an average annual composite basis using group rates record a regulatory asset for the amount that our depreciation that approximated 2.6% during 2004, 2.5% during 2003 and 2.7%

expense exceeds our depreciation costs recovered in rates. See during 2002.

"- Depreciation"for additional information. Effective April 1, 2002, we adopted new depreciation rates which

• Wolf Creek outage: Represents maintenance costs incurred in reduced our annual depreciation expense by approximately our most recent refueling outage. In accordance with regulatory $30.0 million.

treatment, this amount is amortized to expense ratably over the 18-month period after the outage. As part of the 2001 KCC rate order, the KCC extended the

. Other regulatory assets: This includes various regulatory assets estimated retirement date for Wolf Creek from 2025 to 2045, that are relatively small in relation to the total regulatory assets although our operating license for Wolf Creek expires in 2025. The balance. Other regulatory assets include property taxes, coal KCC also extended the estimated retirement date for LaCygne 2 to contract settlement costs, rate review expense, and the net 2032, although the term of our lease for LaCygne 2 expires in 2016.

removal component included in depreciation rates. The effect of extending the retirement date was to reduce our

. Other regulatory liabilities: This includes various regulatory depreciation and amortization expense recovered in customer liabilities that are relatively small and includes provisions for rate rates. For financial statement purposes, we recognize depreciation refunds, property taxes, emissions allowances, savings from the and amortization expense based on the current operating license sale of an office building and the net removal component and the lease term. We record a regulatory asset for the difference included in depreciation rates. Other regulatory liabilities are between the KCC allowed expense and the expense recorded for included in other long-term liabilities on our consolidated financial statement purposes.

balance sheets.

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

A return is allowed on the KCC depreciation and coal contract Years settlement costs. Fossil fuel generating facilities ................... ................... 6 to 68 Cash and Cash Equivalents Nuclear fuel generating facility ..................................... 38 to 45 Transmission facilities ............................................ 28 to 67 We consider highly liquid investments with maturities of three Distribution facilities ............................................. 19 to 57 months or less when purchased to be cash equivalents.

Other ......................... 5......................

to 55 Restricted Cash Restricted cash consists of cash irrevocably deposited in trust for a Nuclear Fuel prepaid capacity and transmission agreement, letters of credit, Our share of the cost of nuclear fuel used in the process of surety bonds and escrow arrangements as required by certain refinement, conversion, enrichment and fabrication is recorded as letters of credit, and various other deposits. an asset in property, plant and equipment on our consolidated balance sheets at original cost and is amortized to fuel and Inventories and Supplies purchased power based on the quantity of heat consumed during Inventories and supplies are stated at average cost. the generation of electricity, as measured in millions of British 43

2004 AN NUAL REPORT Thermal Units (MvIBtu).The accumulated amortization of nuclear Dilutive Shares fuel in the reactor was $30.9 million at December 31, 2004 and Basic earnings (loss) per share applicable to equivalent common

$16.6 million at December 31, 2003. Spent fuel charged to fuel and stock are based on the weighted average number of common purchased power was $19.3 million in 2004, $17.0 million in 2003 shares outstanding and shares issuable in connection with vested and $17.8 million in 2002. restricted share units (RSUs) during the period reported. Diluted earnings (loss) per share include the effects of potential issuances Cash Surrender Value of Life Insurance of common shares resulting from the assumed vesting of all We recorded the following amounts related to corporate-owned outstanding RSUs, the exercise of all outstanding stock options life insurance policies (COLD in other long-term assets on our issued pursuant to the terms of our stock-based compensation consolidated balance sheets at December 31. plans and the additional issuance of shares under the employee 2004 2003 stock purchase plan (ESPP). The dilutive effect of shares under the (InThousands)

ESPP, stock-based compensation and stock options is computed Cash surrender value of policies .......... ........... 1 967,485 $906,118 using the treasury stock method.

Borrowings against policies ............ ............ (891,320) (834,673) The following table reconciles the weighted average number of COLI, net ................................... $ 76,165 $ 71,445 common shares outstanding used to compute basic and diluted earnings (loss) per share.

Income is recorded for increases in cash surrender value and net YearEndedDecember 31, 2004 2003 2002 death proceeds. Interest incurred on amounts borrowed is offset DENOMINATOR FORBASIC AND against policy income. Income recognized from death proceeds DILUTED EARNINGS PERSHARE:

is highly variable from period to period. Death benefits recognized Denominator for basic earnings as income on our consolidated statements of income (loss) approx- per share - weighted average shares. 82,941,374 72,428,728 71,731,580 imated $2.0 million in 2004, $1.8 million in 2003 and $3.6 million Effect of dilutive securities:

in 2002. Employee stock purchase plan shares 17,515 113,737 11,030 Employee stock options ........... 1,943 305 -

Revenue Recognition - Energy Sales Restricted share awards ........... 680,216 924,978 527,116 We recognize revenues from retail energy sales upon delivery to Denominator for diluted the customer and include an estimate for energy delivered but earnings per share - weighted unbilled. Our estimate of revenue attributable to this unbilled average shares .................. 83,641,048 73,467,748 72,269,726 portion is based on the total energy available for sale measured Potentially dilutive shares not against billed sales. At December 31, 2004, we had estimated included in the denominator unbilled revenue of $47.6 million. because they are antidilutive ........ 217,375 217,375 232,638 We account for energy marketing derivative contracts under the Stock Based Compensation mark-to-market method of accounting. Under this method, we recognize changes in the portfolio value as gains or losses in the For purposes of the pro forma disclosures required by SFAS period of change. Unless related to fuel, we include the net mark- No. 148, "Accounting for Stock Based Compensation -Transition and Disclosure"' the estimated fair value of stock options is to-market change in sales on our consolidated statements of amortized to expense over the relevant vesting period. Information income (loss). We record the resulting unrealized gains and losses related to the pro forma impact on our consolidated earnings (loss) as energy marketing long-term or short-term assets and liabilities and earnings (loss) per share follows.

on our consolidated balance sheets as appropriate. We use quoted market prices to value our energy marketing and derivative 2004 2003 2002 contracts when such data are available. When market prices are not (DollarsInThousands, ExceptPerShareAmounts) readily available or determinable, we use alternative approaches, Earnings (loss) available for such as model pricing. Prices used to value these transactions reflect common stock, as reported ........... $177,900 S 84,042 $(793,400) our best estimate of fair values of our trading positions. Results Add: Stock-based compensation actually achieved from these activities could vary materially from included in earnings (loss) available for common stock, as reported, intended results and could affect our consolidated financial results. net of related tax effects ............. 294 46 1 Deduct: Total stock option expense Income Taxes determined under fair value method We use the asset and liability method of accounting for income for all awards, net of related tax effects 757 2,615 188 taxes as required by SFAS No. 109, "Accounting for Income Taxes." Earnings (loss) available for common stock, Under the asset and liability method, we recognize deferred tax pro forma ........................ $177,437 $ 81,473 $(793,587) assets and liabilities for the future tax consequences attributable to Weighted average shares temporary differences between the financial statement carrying used for dilution ................... 83,641,048 73,467,748 72,269,726 amounts and the tax basis of existing assets and liabilities. We Earnings (loss) per share:

recognize the future tax benefits to the extent that realization of such Basic - as reported ............... $2.14 $1.16 S111.06) benefits is more likely than not. We amortize deferred investment tax Basic - pro forma ................. $2.14 $1.12 $111.06) credits over the lives of the related properties.

Diluted - asreported ............... $2.13 $1.14 S(10.98)

Diluted - pro forma ............... $2.12 $1.11 1(10.98) 11I

2004 ANN UAL REPORT Segments of Business from the investigation of the August 14, 2003 blackout in portions Prior to 2004 we had identified two reportable segments: "Electric of the northeastern United States. These initiatives will impact our Utility"and "Other." Our "Electric Utility"segment consisted of our operations in a number of ways, including system relay protection, integrated electric utility operations. "Other" included our former vegetation management and operator training. The NERC and the ownership interests in ONEOK, Inc. (ONEOK), Protection One, ten operating regions in the United States, including the Southwest Inc. and Protection One Europe and other investments that in the Power Pool, are working together to determine what operating aggregate were immaterial to our business or consolidated results policies and planning standards changes are necessary to achieve of continuing operations. the NERC's goals. We are unable to estimate potential compliance costs at this time, it is likely that our annual capital and maintenance With the sale of our interests in ONEOK, Protection One Europe expenditure requirements will increase in the future.

and Protection One, we are now a vertically integrated electric utility with a single operating segment. Our chief operating decision maker evaluates our financial performance based 4. DISCONTINUED OPERATIONS - SALE OF PROTECTION ONE AND PROTECTION ONE EUROPE on earnings (loss) per share of the entire company. We no longer have a distinction between segments for utility operations and In 2003, we classified our monitored security businesses as other investments. discontinued operations. We also reclassified historical periods to conform with this classification.

Supplemental Cash Flow Information 2004 2003 2002 We sold our interest in Protection One Europe on June 30, 2003.

(InThousands) The sale resulted in a $58.7 million reduction in our consolidated CASH PAID FOR: debt level from the buyer's assumption of $48.2 million of Interest on financing activities, Protection One Europe debt that was included on our consolidated netofamountcapitalized .............. $127,993 $208,174 S218,066 financial statements and the use of $10.5 million of cash proceeds Incometaxes ......................... 1,162 53,625 510 to pay down debt.

NON-CASH FINANCING TRANSACTIONS:

Issuance of stock to subsidiary (SeeNote 19, On February 17, 2004, we closed the sale of our interest in

'Common and Preferred Stock') ........ - - 86,870 Protection One to subsidiaries of Quadrangle Capital Partners LP Issuance of common stock for reinvested dividends and RSUs .......... 14,674 9,505 23,146 and Quadrangle Master Funding Ltd. (together, Quadrangle). At Assets acquired through capital leases ...... 3,272 1,252 6,471 closing, we assigned to Quadrangle the senior credit facility between Westar Industries, Inc., Westar Energy's wholly owned Reclassifications subsidiary, and Protection One, which had an outstanding balance of $215.5 million. At closing, we received proceeds of $122.2 million.

We have reclassified certain prior year amounts to conform with classifications used in the current-year presentation as necessary Protection One had been part of our consolidated tax group since for a fair presentation of the financial statements. 1997. Under the terms of a tax sharing agreement, we have reimbursed Protection One for current tax benefits used in our

3. RATE MATTERS AND REGULATION consolidated tax return attributable to Protection One. On November 12, 2004, we entered into a settlement agreement with Rate Review Request Protection One and Quadrangle that, among other things, As a result of an earlier KCC order, we will file a request for a rate terminated a tax sharing agreement, settled Protection One's review with the KCC by May 2, 2005, based on a test year claims with us relating to the tax sharing agreement and settled consisting of the 12 months ended December 31,2004. claims between Quadrangle and us relating to the sale transaction.

Pursuant to the terms of the settlement agreement, Quadrangle Current Status of the Debt Reduction Plan paid us $32.5 million in cash as additional consideration, and we In 2004, we reduced, by $533.4 million, the debt shown on our settled tax sharing-related obligations to Protection One by tender-consolidated balance sheet with internally generated cash, the ing $27.1 million in Protection One 7-3/8% senior notes, including proceeds received from the sale of Protection One, Inc. (Protection accrued interest, and paying $45.9 million in cash. Our net cash One) and proceeds from an equity offering. Additionally, due to payment under the settlement agreement was $13.4 million. In the sale of Protection One in February 2004, we reduced the long- addition, the settlement agreement provided that we would jointly term debt that was included in the liabilities of discontinued agree to make an Internal Revenue Code (IRC) Section 338(h) (10) operations by $305.2 million. election. For tax purposes, an IRC Section 338(h)(10) election Electric Service Reliability allows us to treat the sale of Protection One stock as a sale of the assets of Protection One.

On January 16, 2004, the KCC issued an order regarding electric service reliability for retail customers. The order was intended to Effective January 1,2002, we adopted SFAS No.142, "Goodwill and help the KCC assess the reliability of retail electric service. Other Intangible Assets," and SFAS No. 144, "Accounting for the Specifically, the KCC wanted to establish uniform definitions and Impairment or Disposal of Long-Lived Assets." SFAS No. 142 requirements regarding service obligations, record keeping, established new standards for accounting for goodwill. SFAS customer notification and methods of reporting results to the KCC. No. 142 continued to require the recognition of goodwill as an 45 On February 10, 2004, the North American Electric Reliability asset, but discontinued the amortization of goodwill. In addition, Council (NERC) issued reliability improvement initiatives stemming annual impairment tests must be performed using a fair-value

2 004 ANN UAL REPO RT based approach as opposed to an undiscounted cash flow Results of discontinued operations are presented in the table approach required under prior standards. Upon the completion of below.

the impairment tests as of January 1, 2002, we determined that the YearEnded December 31, 2004 2003 2002 carrying values of goodwill at Protection One and Protection One (InThousands, Except PerShare Amounts)

Europe had been impaired and impairment charges were recorded as discussed below. Sales ............................... $ 22,466 S306,938 S351,499 Costs and expenses .................... 19,937 289,900 754,656 Another impairment test of Protection One's goodwill and customer Earnings (loss) from discontinued accounts was completed as of July 1, 2002 (the date selected for operations before income taxes ....... 2,529 17,038 (403,157)

Protection One's annual impairment test), with the independent Estimated gain (loss) on disposal .......... 30,980 (258,979) (1,853) appraisal firm providing the valuation of the estimated fair value of Income tax benefit ..................... (45,281) (164,036) (146,910)

Protection One's reporting units, and no impairment was indicated. Results of discontinued operations before Protection One's stock price declined after regulatory orders were accounting change, net of tax ......... 78,790 (77,905) (258,100) issued. As a result, Protection One retained the independent Cumulative effect of accounting change, appraisal firm to perform an additional valuation of Protection net of tax of $72,335 ................. - - (623,717)

One's reporting units so it could perform an impairment test as of Results of discontinued operations ....... S 78,790 S (77,905) S(881,817)

December 31, 2002, which resulted in the additional impairment Basic Earnings (Loss) Per Share:

charge discussed below.

Results of discontinued operations, SPAS No. 144 established a new approach to determining whether before accounting change ........... $ 0.95 $ (1.08) S (3.60)

Protection One's customer account asset was impaired. The Cumulative effect of accounting change, net of tax ........................ - - (8.69) approach no longer permitted the evaluation of the customer account asset for impairment based on the net undiscounted cash Results of discontinued operations, net of tax ........................ $ 0.95 S (1.08) S (12.29) flow stream obtained over the remaining life of goodwill associated with the customer accounts being evaluated. Rather, the cash flow Diluted Earnings (Loss) Per Share:

stream used under SFAS No. 144 is limited to future estimated Results of discontinued operations, undiscounted cash flows from assets in the asset group, which before accounting change ........... $ 0.94 S (1.06) S (3.57) include customer accounts, the primary asset of Protection One, Cumulative effect of accounting change, net of tax ........................ - - (8.63 )

plus an estimated amount for the sale of the remaining assets within the asset group (including goodwill). If the undiscounted Results of discontinued operations, net of tax ....................... S 0.94 $ (1.06) S (12.20) cash flow stream from the asset group is less than the combined book value of the asset group, then customer account asset carrying value must be written down to fair value, by recording The major classes of assets and liabilities of the monitored services an impairment. businesses were as follows.

December 31, 2003 The new rule substantially reduced the net undiscounted cash flows for customer account impairment evaluation purposes as (InThousands) compared to the previous accounting rules. Using these new Assets:

guidelines, it was determined that there was an indication of Current .................... .............................. S 80,850 impairment of the carrying value of the customer accounts and an Property and equipment . ...................................... 60,656 Customer accounts, net . ...................................... 268,533 impairment charge was recorded as discussed below.

Goodwill, net ............................................. 41,847 To implement the new standards, an independent appraisal firm was Other . ............................................. 118,655 engaged to help management estimate the fair values of Protection Total assets ............................................. $ 570,541 One's and Protection One Europe's goodwill and customer Liabilities:

accounts. Based on this analysis, a charge was recorded in the first Current................................................... S 68,816 quarter of 2002 of approximately $749.3 million (net of tax benefit Long-term debt ............................................. 305,234 and minority interests), of which $555.4 million was related to Other long-term liabilities ................... .................. 101,547 goodwill and $193.9 million was related to customer accounts.

Total liabilities ............................................. S475,597 Protection One completed an additional impairment test of goodwill as of December 31, 2002 and we recorded an impairment charge of $79.7 million, net of tax benefit and minority interests, in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill of Protection One's North America segment.

46

2 004 ANN NUAL REPO RT

5. ACCOUNTS RECEIVABLE AND December 2003 with the issuance of FIN 46R. The objective of this VARIABLE INTEREST ENTITIES interpretation is to provide guidance on how to identifyVariable Our accounts receivable on our consolidated balance sheets are Interest Entities (VIE) and determine when the assets, liabilities, comprised as follows. non-controlling interests and results of operations of aVIE need to be included in a company's consolidated financial statements. A As of December 31, 2004 2003 company that holds variable interests in an entity will need to (InThousands) consolidate the entity if the company's interest in the VIE is such Customeraccountsreceivable .......... ........... S 97,017 $ 85,712 that the company will absorb a majority of theVIE's expected losses Allowance for uncollectable accounts ....... ........ (5,152) (5,313) and/or receive a majority of the entity's expected residual returns, if Transferred receivables, net .......... ........... 91,865 80,399 they occur. FIN 46R also requires additional disclosures by primary Other accounts receivable ............. ........... 828 674 beneficiaries and other significant variable interest holders.

Other allowance for uncollectable accounts ...... ..... (161) (102)

On December 14, 1995, Western Resources Capital I, a wholly Accounts receivable, net ........................ S 92,532 S 80,971 owned trust, issued $100.0 million of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A. On April 16, 2004, Accounts Receivable Sales Program we redeemed our entire issuance of Western Resources Capital I WR Receivables Corporation, a wholly owned subsidiary, has an 7-7/8% Cumulative Quarterly Income Preferred Securities, agreement with a financial institution whereby WR Receivables Series A, at par. On July 31, 1996, Western Resources Capital II, a can sell an interest of up to $125.0 million in a designated pool of wholly owned trust, issued $120.0 million of 8-1/2% Cumulative our qualified accounts receivable. The agreement expires in July Quarterly Income Preferred Securities, Series B. On September 22, 2005. Under the terms of the agreement, new receivables 2003, we redeemed our entire issuance of Western Resources generated by us are continuously purchased by WR Receivables. Capital II 8-1/2% Cumulative Quarterly Income Preferred The receivables sold to the financial institution are not reflected in Securities, Series B,at par.

the accounts receivable balance in the accompanying consolidated Provisions of FIN 46R required the deconsolidation of the Western balance sheets. The amounts sold to the financial institution were Resources Capital I trust, which resulted in the amounts previously

$80.0 million at December 31,2004 and 2003. classified as shares subject to mandatory redemption being reclassi-We service, administer and collect the receivables on behalf of the fied as long-term debt, affiliate on the consolidated balance sheet.

financial institution. Administrative expenses associated with the sale of these receivables were $2.1 million in 2004, $2.4 million in 6. FINANCIAL INSTRUMENTS, ENERGY MARKETING 2003 and $2.9 million in 2002. We include these expenses in other AND RISK MANAGEMENT expense on our consolidated statements of income (loss).

Values of Financial Instruments We record receivables transferred to WR Receivables at book value, The carrying values and estimated fair values of our financial net of allowances for bad debts.This approximates fair value due to instruments are as shown in the table below.

the short-term nature of the receivable. We include the transferred Carrying Value Fair Value accounts receivables in accounts receivable, net, on our consoli-As of December 31, 2004 2003 2004 2003 dated balance sheets.The interests that we hold are included in the (In Thousands) table below.

Fixed-rate debt, net of As of December 31, 2004 2003 current maturities() ..... 1,419,406 $1,815,320 $1,530,035 $1,946,053 (in Thousands) ("'Fair value is estimated based on quoted market pricesfor the same or similar Accounts receivables retained by WR Receivables, net .... $ 81,842 $ 71,213 issues or on the current rates offered for instruments of the same remaining Accounts receivables reserved for purchaser, net ...... .. 10,023 9,186 maturitiesand redemption provisions.

Transferred receivables, net ............ S..........

91,865 $ 80,399 The recorded amounts of accounts receivable and other current financial instruments approximate fair value. Cash and cash The following table provides gross proceeds and repayments equivalents, short-term borrowings and variable-rate debt are between WR Receivables and the financial institution. We record carried at cost, which approximates fair value and are not included these items on the consolidated statements of cash flows in the in the table above.

accounts receivable, net, line of cash flows from operating activities.

The fair value estimates are based on information available at YearEndedDecember 31, 2004 2003 2002 December 31, 2004 and 2003. These fair value estimates have not (InThousands) been comprehensively revalued since that date and current estimates Proceeds from the purchaser due to the of fair value may differ significantly from the amounts above.

sale of receivables ............... $....

40,000 $ - S 30,000 Payments to the purchaser for net collection Derivative Instruments and Hedge Accounting of its receivables ..................... (40,000) (30,000) (20,000)

We are exposed to market risks from changes in commodity prices Proceeds and repayments, net .......... - (30,000) $ 10,000 and interest rates that could affect our consolidated results of operations and financial condition. We manage our exposure to 4 Consolidation of Variable Interest Entities these market risks through our regular operating and financing In January 2003, the Financial Accounting Standards Board (FASB) activities and, when deemed appropriate, economically hedge a issued Financial Interpretation Number (FIN) 46,"Consolidation portion of these risks through the use of derivative financial of Variable Interest Entities;"which was subsequently revised in instruments. We use the term economic hedge to mean a strategy

2 004 ANN UAL REPO RT designed to manage risks of volatility in prices or rate movements exposure relative to the volatility of market and commodity prices.

on some assets, liabilities or anticipated transactions by creating a The wholesale power market is extremely volatile in price and relationship in which gains or losses on derivative instruments are supply. This volatility impacts our costs of power purchased and expected to counterbalance the losses or gains on the assets, our participation in energy trades. If we were unable to generate an liabilities or anticipated transactions exposed to such market risks. adequate supply of electricity for our customers, we would purchase We use derivative instruments as risk management tools consistent power in the wholesale market to the extent it is available, subject with our business plans and prudent business practices and for to possible transmission constraints, and/or implement curtailment energy marketing purposes. or interruption procedures as permitted in our tariffs and terms and conditions of service.The increased expenses or loss of revenues We use derivative financial and physical instruments primarily to associated with this could be material and adverse to our consoli-manage risk as it relates to changes in the prices of commodities dated results of operations and financial condition.

including natural gas, oil, coal and electricity. We classify derivative instruments used to manage commodity price risk inherent in We use various fossil fuel types, including coal, natural gas and oil, fossil fuel and electricity purchases and sales as energy marketing to operate our plants. A significant portion of our coal requirements contracts on our consolidated balance sheets. We report energy are purchased under long-term contracts. Due to the volatility of marketing contracts representing unrealized gain positions as natural gas prices, we have increasingly operated facilities that assets; energy marketing contracts representing unrealized loss have allowed us to use lower cost fuel types as generating unit positions are reported as liabilities. constraints and environmental restrictions allow, primarily by using oil in our facilities that also bum natural gas.

Energy Marketing Activities We engage in both financial and physical trading to manage our Additional factors that affect our commodity price exposure are the commodity price risk. We trade electricity, coal, natural gas and oil. quantity and availability of fuel used for generation and the We use financial instruments, including forward contracts, options quantity of electricity customers consume. Quantities of fossil fuel and swaps and we trade energy commodity contracts daily. We used for generation vary from year to year based on the availability, may also use economic hedging techniques to manage overall fuel price and deliverability of a given fuel type as well as planned and expenditures. We procure physical product under forward agree- scheduled outages at our facilities that use fossil fuels and the ments and spot market transactions. nuclear refueling schedule. Our customers' electricity usage could also vary from year to year based on weather or other factors.

Within the trading portfolio, we take certain positions to economically hedge a portion of physical sale or purchase contracts Although we generally attempt to balance our physical and financial and we take certain positions to take advantage of market trends contracts in terms of quantities and contract performance, net open and conditions. We reflect changes in value on our consolidated positions typically exist. We will at times create a net open position statements of income (loss). We believe financial instruments help or allow a net open position to continue when we believe that us manage our contractual commitments, reduce our exposure to future price movements will increase the portfolio's value. To the changes in cash market prices and take advantage of selected extent we have open positions, we are exposed to the risk that market opportunities. We refer to these transactions as energy changing market prices could have a material, adverse impact on marketing activities. our consolidated financial position or results of operations.

We are involved in trading activities to reduce risk from market The prices we use to value price risk management activities reflect fluctuations, enhance system reliability and increase profits. Net our estimate of fair values considering various factors, including open positions exist, or are established, due to the origination of new closing exchange and over-the-counter quotations, time value of transactions and our assessment of, and response to, changing money and price volatility factors underlying the commitments.

market conditions. To the extent we have open positions, we are We adjust prices to reflect the potential impact of liquidating our exposed to the risk that changing market prices could have a position in an orderly manner over a reasonable period of time material, adverse impact on our consolidated financial position or under present market conditions. WVe consider a number of risks results of operations. and costs associated with the future contractual commitments We have considered a number of risks and costs associated with included in our energy portfolio, including credit risks associated the future contractual commitments included in our energy portfo- with the financial condition of counterparties and the time value of lio. These risks include credit risks associated with the financial money. We continuously monitor the portfolio and value it daily condition of counterparties, product location (basis) differentials based on present market conditions.

and other risks. Declines in the creditworthiness of our counter- Hedging Activities parties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our During the third quarter of 2001, we entered into hedging relation-counterparties that, in management's view, reduce our overall ships to manage commodity price risk associated with future credit risk. natural gas purchases. Initially, we entered into futures and swap contracts with terms extending through July 2004 to hedge price We are also exposed to commodity price changes outside of risk for a portion of our anticipated natural gas fuel requirements trading activities. We use derivative contracts for non-trading for our generation facilities. We designated these hedging relation-48 purposes and a mix of various fuel types primarily to reduce ships as cash flow hedges.

111

2 004 ANN UAL REPO RT In 2002, due to the increased availability of our coal units and interest in these facilities at December 31, 2004 is shown in the because we began burning more oil as use of oil became more table below.

economically favorable than natural gas, we did not burn our fore-Our Ownership at December 31,2004 casted amount of natural gas. In September 2002, we determined In-Service Accumulated Net Ownership that we had over-hedged approximately 12,000,000 MMBtu for the Dates Investment Depreciation MW Percent remaining period of the hedge. As a result of the discontinuance (DollarsinThousands) of this portion of the cash flow hedge, we recognized a gain of LaCygne 1(a) .June 1973 $ 191,346 $118,168 344.0 50

$4.0 million. In December 2003, we determined we could no Jeffrey 1(b).July 1978 318,211 159,469 618.0 84 longer meet the criteria to use hedge accounting for the 2004 Jeffrey2(b) .May 1980 311,333 142,225 617.0 84 forecasted natural gas purchases. As a result, we recognized in Jeffrey3) .May 1983 415,005 201,283 624.0 84 income a gain of $3.7 million, of which $2.8 million had previously Jeffrey wind 1(b) . May 1999 874 230 0.6 84 been recognized in other comprehensive income. Jeffrey wind 2'b) . May 1999 874 230 0.6 84 Wolf Creek(c) .Sept. 1985 1,409,238 590,055 548.0 47 Effective October 4,2001, we entered into a $500.0 million interest StateLine( .June 2001 108,099 15,115 200.0 40 rate swap agreement with a term of two years. At that time, the effect of the swap agreement was to fix the annual interest rate on (05Jointly owned with Kansas City Power& Light Company (KCPL) a term loan at 6.18%.We settled the swap agreement for a nominal (jointly owned with Aquila, Inc.

amount on September 29, 2003. (djointly owned with KCPL and Kansas Electric Power Cooperative,Inc.

(O'Jointlyowned with Empire District Electric Company In the second quarter of 2003, we purchased a call option at a cost of $65.8 million, which locked in a settlement cost associated with Amounts and capacity presented above represent our share. Our a call option entered into in 1998 related to our 6.25% putable! share of operating expenses of the above plants, as well as such callable notes. We settled the call option in August 2003. expenses for a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity) sold and leased back to KGE in

7. PROPERTY, PLANT AND EQUIPMENT 1987, are included in operating expenses on our consolidated statements of income (loss). Our share of other transactions The following is a summary of property, plant and equipment at associated with the plants is included in the appropriate classifica-December 31. tion on our consolidated financial statements.

2004 2003 (InThousands) 9. COMMON STOCK ISSUANCE Electric plant inservice .................. ..... S5,777,519 $5,665,479 Westar Energy sold approximately 12.5 million shares of its Electric plant acquisition adjustment ........ .... 802,318 802,318 common stock in 2004 for net proceeds of $245.1 million.

Accumulated depreciation ............. ....... (2,761,781) (2,647,214) 3,818,056 3,820,583 10. SHORT-TERM DEBT Construction work inprogress .......... ....... 56,910 59,570 Nuclearfuel, net ........................... 35,942 29,198 A syndicate of banks provides us a revolving credit facility on a Netutilityplant .......................... 3,910,908 3,909,351 committed basis totaling $300.0 million. The facility is secured by Non-utility plant in service ............. ....... 79 149 KGE's first mortgage bonds and matures on March 12, 2007. It allows us to borrow up to an aggregate limit of $300.0 million, Net property, plant and equipment ........ .... $ 3,910,987 $3,909,500 including letters of credit up to a maximum aggregate amount of

$50.0 million. At December 31, 2004, we had no outstanding Depreciation expense on property, plant and equipment for the borrowings and $15.3 million of letters of credit outstanding under years ended December 31, 2004, 2003 and 2002 was as follows. the revolving credit facility.

2004 2003 2002 Information regarding our short-term borrowings is as follows.

(InThousands)

As of December 31, 2004 2003 Utility ....................... $ 148,933 $147,015 $ 151,538 (InThousands)

Non-utility ....................... - 10 58 Borrowings outstanding at year end:

Total depreciation expense .......... S148,933

$ $147,025 S151,596 Credit agreement and an other financing arrangement .. $ - $ 1,000 Weighted average interest rate on debt outstanding at year-end, excluding fees ........ ...... - 6.00%

8. JOINT OWNERSHIP OF UTILITY PLANTS Weighted average short-term debt outstanding during the year ............ ........... S1,434 S 1,009 Under joint ownership agreements with other utilities, we have Weighted daily average interest rates undivided ownership interests in four electric generating stations. during the year, excluding fees ........... .......... 3.50% 6.12%

Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs Our interest expense on short-term debt was $1.1 million in 2004, in its statements of income. Information relative to our ownership $1.2 million in 2003 and $7.4 million in 2002.

49

2 004 ANN UAL REPO RT

11. LONG-TERM DEBT The amount ofWestar Energy's first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supple-Outstanding Debt mented, is unlimited subject to certain limitations as described Long-term debt outstanding at December 31 is as follows. below. The amount of KGE's first mortgage bonds authorized by 2004 2003 the KGE Mortgage and Deed of Trust, dated April 1, 1940, as (InThousands) supplemented, is limited to a maximum of $2 billion, unless Westar Energy amended. First mortgage bonds are secured by utility assets.

First mortgage bond series: Amounts of additional bonds that may be issued are subject to 7.875% due 2007 ........................... $ 365,000 $ 365,000 property, earnings and certain restrictive provisions, except 6.000% due 2014 ............................ 250,000 - in connection with certain refundings, of each mortgage. At 8.500% due 2022 ............................ - 125,000 December 31, 2004, based on an assumed interest rate of 6%,

7.650% due 2023 ............................ - 100,000 approximately $210.0 million principal amount of additional first 615,000 590,000 mortgage bonds could be issued under the most restrictive Pollution control bond series: provisions in Westar Energy's mortgage. At December 31, 2004, Variable due 2032, 1.95% at December 31, 2004 45,000 45,000 based on an assumed interest rate of 6%, approximately Variable due 2032, 2.00% at December 31, 2004 30,500 30,500 $874.0 million principal amount of additional KGE first mortgage 6.000% due 2033 ............................ - 58,340 bonds could be issued under the most restrictive provisions in 5.000% due 2033 ............................ 58,340 - the mortgage.

133,840 133,840 Westar Energy's revolving credit facility prohibits us from 6.875% unsecured senior notes due 2004 ............ - 184,456 increasing the amount of secured indebtedness outstanding as of 9.750% unsecured senior notes due 2007 ............ 260,000 387,000 March 12, 2004 by more than $300.0 million. In June 2004, Westar 7.125% unsecured senior notes due 2009 ............ 145,078 145,078 Energy issued $250.0 million of Westar Energy first mortgage 6.80% unsecured senior notes due 2018 ............. - 26,993 bonds and immediately placed the funds in escrow for retirement Senior secured term loan due 2005 ................. - 114,143 of $225.0 million of WMestar Energy first mortgage bonds, which was Other long-term agreements ...................... - 4,179 completed in July 2004. Therefore, at December 31, 2004, we could 405,078 861,849 incur a maximum of $275.0 million of additional secured debt KGE under this provision in Westar Energy's revolving credit facility.

First mortgage bond series: Following Westar Energy's January 18, 2005 issuance of 6.500% due 2005 ............................ 65,000 65,000 $250.0 million of first mortgage bonds, as discussed below, we can 6.200% due 2006 ............................ 100,000 100,000 incur a maximum of $25.0 million of additional secured debt under 165,000 165,000 this provision in Westar Energy's revolving credit facility.

Pollution control bond series:

During 2004, we recognized a loss of $16.1 million in connection 5.100% due 2023 ............................ 13,488 13,488 with the redemption of our senior unsecured notes and $2.7 million Variable due 2027, 1.75% at December 31, 2004 .... 21,940 21,940 7.000% due 2031 ............................

in connection with the redemption of affiliate long-term debt.

327,500 5.300% due 2031 ............................ 108,600 On January 18, 2005, Westar Energy sold $250.0 million aggregate 5.300% due 2031 ............................ 18,900 principal amount of Westar Energy first mortgage bonds, consisting 2.650% due 2031 and putable 2006 .............. 100,000 of $125.0 million 5.15% bonds maturing in 2017 and $125.0 million Variable due 2031, 1.92 % at December 31, 2004 . 100,000 5.95% bonds maturing in 2035. On February 17,2005, we used the Variable due 2032, 1.67% at December 31, 2004 ... 14,500 14,500 net proceeds from the offering, together with cash on hand, Variable due 2032, 1.85% at December 31, 2004 10,000 10,000 additional funds raised through the accounts receivable conduit 387,428 387,428 facility and borrowings under Westar Energy's revolving credit facility, to redeem the remaining $260.0 million aggregate principal Unamortized debt discount(a) ...................... (1,445) (3,923) amount of Westar Energy 9.75% senior notes due 2007. Together Long-term debt due within one year ................ (65,000) (185,941 ) with accrued interest and a premium equal to approximately 12%

Long-term debt, net ........................... S1,639,901 $1,948,253 of the outstanding senior notes, we paid $298.5 million to redeem the Westar Energy 9.75% senior notes due 2007. After this transaction, we had $10.0 million outstanding under the revolving Long-term debt, affiliate ......................... $ - $ 103,093 credit facility and $30.0 million available under the accounts

('dWe amortize debt discount over the term of the respective issue. receivable conduit facility.

The Westar Energy mortgage and the KGE mortgage each contain Debt Covenants provisions restricting the amount of first mortgage bonds that Some of our debt instruments contain restrictions that require us could be issued by each entity. Additionally, Westar Energy's to maintain various coverage and leverage ratios as defined in the revolving credit facility prohibits us from increasing the amount of agreements. We calculate these ratios in accordance with our credit 50 secured indebtedness outstanding as of March 12, 2004 by more agreements. These ratios are used solely to determine compliance than $300.0 million Therefore, we must ensure that we will be able with our various debt covenants. We were in compliance with to comply with such restrictions prior to the issuance of additional these covenants at December 31, 2004.

first mortgage bonds or other secured indebtedness.

2 004 ANN UAL REPO RT Maturities Regulatory Commission (FERC) issued guidance allowing an Maturities of long-term debt at December 31,2004 are as follows. entity to recognize the amount of the minimum pension liability otherwise chargeable to other comprehensive income as a regula-Year Principal Amount tory asset. On January 13, 2005, we received an accounting (InThousands) authority order from the KCC to recognize as a regulatory asset the 2005 ................. $ 65,000 additional minimum pension liability that otherwise would have 2006 ... .1............. l00,000 been charged to other comprehensive income (OCI).At December 2007 .............. 625,000 31,2004, our additional minimum pension liability adjustment was 2008 . , .. - $41.8 million, offset by an intangible asset of $15.9 million and a 200G9.......... .... 145,078 regulatory asset of $25.9 million. At December 31, 2003, our Thereafter . .769,823 additional minimum pension liability was $8.7 million, offset by an

$1,704,901 intangible asset of $0.9 million and OCI of $7.8 million. We accrue the cost of post-retirement benefits during the years an employee Our interest expense on long-term debt was $141.1 million in provides service. The following tables summarize the status of our 2004, $223.2 million in 2003 and $227.8 million in 2002. pension and other post-retirement benefit plans.

Affiliate Long-term Debt and Other Mandatorily Pension Benefits Post-retirement Benefits Redeemable Securities At December 31, 2004 2003 2004 2003 On December 14, 1995, Western Resources Capital 1, a wholly (InThousands) owned trust, issued $100.0 million of 7-7/8% Cumulative Quarterly Change inBenefit Obligation:

Income Preferred Securities, Series A. On April 16, 2004, we Benefit obligation, beginning of year .......... S469,651 $ 433,620 S 125,324 $ 124,113 redeemed our entire issuance of Western Resources Capital I Service cost ................ 6,110 5,381 1,487 1,186 7-7/8% Cumulative Quarterly Income Preferred Securities, Series 28,833 8,004 Interest cost ............... 28,319 6,774 A, at par. This transaction reduced our long-term liabilities by Plan participants' contributions 2,695 2,242 approximately $103.1 million. Benefits paid ............... (28,880) (29,389) (12,479) (13,076)

Assumption changes ......... 11,227 27,556 4,461 7,911 On July 31, 1996, Western Resources Capital II, a wholly owned Recognition of Medicare Part D (3,807) trust, issued $120.0 million of 8-1/2% Cumulative Quarterly Actuarial losses (gains) ........ 8,050 2,710 (989) (5,056)

Income Preferred Securities, Series B. On September 22, 2003, we Amendments .............. 138 500 redeemed our entire issuance of Western Resources Capital II Curtailments, settlements and 8-1/2% Cumulative Quarterly Income Preferred Securities, - special term benefits ....... - 440 - -

Series B, at par. This transaction reduced our long-term liabilities Benefit obligation, end of year $ 494,615 S 469,651 $ 123,466 $ 125,324 by approximately $115.7 million.

Change inPlan Assets:

Fair value of plan assets,

12. EMPLOYEE BENEFIT PLANS beginning of year .......... $ 409,932 S 360,024 $ 22,543 $ 12,629 Adjustments ............... - - - 269 Pension Actual return on plan assets ... 39,870 77,591 1,802 396 We maintain a qualified non-contributory defined benefit pension Employer contribution ........ - - 17,800 19,800 plan covering substantially all of our employees. Pension benefits Plan participants' contributions - - 2,695 2,242 are based on years of service and the employee's compensation Benefits paid ............... (27,200) (27,683) (12,228) (12,793) during the 60 highest paid consecutive months out of 120 before Fair value of plan assets, retirement. Our policy is to fund pension costs accrued, subject to end of year .............. S 422,602 $ 409,932 $ 32,612 $ 22,543 limitations set by the Employee Retirement Income SecurityAct of 1974 and the Internal Revenue Code. We also maintain a non- Funded status .............. $ (72,013) $ (59,719) S (90,854) $(102,781) qualified Executive Salary Continuation Plan for the benefit of Unrecognized net loss ........ 70,807 55,366 30,424 31,723 certain current and retired officers. Employees hired after Unrecognized transition December 31, 2001 are covered by the same defined benefit plan obligation, net ............ - - 31,768 35,699 with benefits derived from a cash balance account formula. Unrecognized prior service cost 15,906 18,530 (1,398) (1,865)

Prepaid (accrued) benefit costs $ 14,700 S 14,177 $ (30,060) $ (37,224)

As a co-owner of WCNOC, we are indirectly responsible for 47%

of the liabilities and expenses associated with the WCNOC Amounts Recognized inthe Balance Sheets Consist Of:

pension and post-retirement plans. See Note 13, "WCNOC Prepaid benefit cost .......... $ 30,597 $ 28,976 $ N/A N/A W

Employee Benefit Plans"forWCNOC benefit information. Accrued benefit liability ....... (15,897) (14,799) (30,060) (37,224)

Additional minimum liability ... (41,815) (8,692) N/A N/A Our pension plan expense and liabilities are measured using Intangible asset ............. 15,906 923 N/A N/A assumptions, which include discount rates, compensation rates Other comprehensive income (a) - 7,769 N/A N/A and past and future estimated plan asset returns. Due to a decrease Regulatory asset(a) ........... 25,909 - N/A N/A in interest rates and a corresponding decrease in the discount rates used to estimate our pension liabilities, the fair value of our Net amount recognized ....... $ 14,700 $ 14,177 $ (30,060) S (37,224) 51 pension plan assets was less than the accumulated benefit a)On March 29, 2004, FERC issued guidance allowing an entity to recognize the obligation at our measurement dates of December 31, 2004 and amount of the minimum pension liability otherwise chargeable to other December 31, 2003. On March 29, 2004, the Federal Energy comprehensive income as a regulatoryasset. OnJanuary 13, 2005, we received an accountingauthority orderfrom the KCC to record the othercomprehensive income related to pension benefit obligationcosts as a regulatoryasset.

2 004 ANN UAL REPO RT Pension Benefits Post-retirement Benefits Post-retirement Benefits At December 31, 2004 2003 2004 2003 For the Year Ended December 31, 2004 2003 2002 (DollarsinThousands) (Dollars inThousands)

Accumulated Benefit Obligation $449,717 $429,852 N/A N/A Components of Net Periodic (Benefit) Cost:

Pension Plans With a Projected Servicecost ..................... $$1,487 S 1,186 S 1,248 Benefit Obligation In Excess Interest cost ..................... 6,774 8,004 7,467 of Plan Assets: Expected return on plan assets ........... (1,999) (1,431) (52)

Projectedbenefitobligation $494,615 $469,651 N/A N/A Amortization of unrecognized Accumulated benefit transition obligation, net .............. 3,931 3,931 3,931 obligation .............. 449,717 429,852 N/A N/A Amortization of unrecognized Fair value of plan assets ..... 422,602 409,932 N/A N/A prior service costs ................... (467) (467) (467)

Pension Plans With an Amortizationofloss(gain), net ........... 1,172 1,612 919 Accumulated Benefit Obligation Curtailments, settlements and In Excess of Plan Assets: special term benefits ................. - - -

Projected benefit obligation . $494,615 S 23,613 N/A N/A Net periodic(benefit) cost .............. $10,898 $12,835 $ 13,046 Accumulated benefit obligation .............. 449,717 23,491 N/A N/A Weighted-Average Actuarial Assumptions Fair value of plan assets ..... 422,602 - N/A N/A used to Determine Net Periodic (Benefit) Cost:

Post-retirement Plans With an Discount rate ..................... 6.10% 6.75% 7.25%

Accumulated Post-retirement Expected long-term return on plan assets . . . 8.50% 9.00% 9.00%

Benefit Obligation In Excess Compensation rate increase ............. 3.10% 3.75% 4.25%

of Plan Assets:

Accumulated post-retirement benefitobligation ........ N/A N/A $123,466 $125,324 The expected long-term rate of return on plan assets is based on Fairvalueofplanassets ..... N/A N/A 32,612 22,543 historical and projected rates of return for current and planned Weighted-Average Actuarial asset classes in the plans'investment portfolio. Assumed projected Assumptions used to rates of return for each asset class were selected after analyzing Determine Net Periodic long-term historical experience and future expectations of the Benefit Obligation: volatility of the various asset classes. Based on target asset Discount rate ............. 5.90% 6.10% 5.90% 6.10% allocations for each asset class, the overall expected rate of return Compensation rate increase . . 3.00% 3.10% 3.00% 3.10% for the portfolio was developed, adjusted for historical and expected experience of active portfolio management results compared to We use a measurement date of December 31 for our pension and benchmark returns and for the effect of expenses paid from plan post-retirement benefit plans. assets. In selecting the discount rate, fixed income security yield The prior service cost (benefit) is amortized on a straight-line basis rates for corporate high-grade bond yields are considered.

over the average future service of the active employees (plan partici- In December 2003, the Medicare Prescription Drug Improvement pants) benefiting under the plan at the time of the amendment. and Modernization Act of 2003 (Medicare Act) became law. The The net actuarial gain (loss) subject to amortization is amortized Medicare Act introduced a prescription drug benefit under on a straight-line basis over the average future service of active Medicare as well as a federal subsidy beginning in 2006. This plan participants benefiting under the plan, without application of subsidy will be paid to sponsors of retiree health care benefit plans the amortization corridor described in SFAS No. 87, "Employers' that provide a benefit that is at least actuarially equivalent to Accounting for Pensions"and SPAS No. 106, "Employers'Accounting Medicare. We believe our retiree health care benefits plan is at least for Postretirement Benefits Other Than Pensions." actuarially equivalent to Medicare and is eligible for the federal Pension Benefits subsidy. We adopted the guidance in the third quarter of 2004.

Foethe YearEndedDecember 31, 2004 2003 2002 Treating the future subsidy under the Medicare Act as an actuarial (Dollars inThousands) experience gain, as required by the guidance, decreased the accumulated post-retirement benefit obligation by approximately Components of Net Periodic (Benefit) Cost:

$4.4 million. The subsidy also decreased the net periodic post-Servicecost ......................... $ 6,110 S 5,381 $ 6,942 retirement benefit cost by approximately $0.5 million for the year Interest cost ......................... 28,319 28,833 28,724 ended December 31, 2004.

Expected return on plan assets ........... (38,561) (40,513) (42,292)

Amortization of unrecognized For measurement purposes, the assumed annual health care cost transition obligation, net ....... ....... - (177) (251) growth rates were as follows.

Amortization of unrecognized prior service costs ........... ........ 2,762 3,358 3,300 At December 31, 2004 2003 Amortization of loss (gain), net ...... ..... 2,525 (2,032) (5,932) Health care cost trend rate assumed for next year 8.00% 9.00%

Curtailments, settlements and Rate to which the cost trend rate isassumed to decline special term benefits ................. - 440 12,589 (the ultimate trend rate) .5.00% 5.00%

Netperiodic(benefit)cost ............... $ 1,155 $(4,710) $ 3,080 Year that the rate reaches the ultimate trend rate ...... 2008 2008 52 Weighted-Average Actuarial Assumptions used to Determine Net Periodic (Benefit) Cost:

Discount rate ........................ 6.10% 6.75% 7.25%

Expected long-term return on plan assets ... 9.00% 9.00% 9.00%

Compensation rate increase ....... ...... 3.10% 3.75% 4.25%

) (ll

2 004 ANN UAL REPO RT The health care cost trend rate has a significant effect on the provide under the plan. Our contributions were $3.4 million for projected benefit obligation. A 1% change in assumed health care 2004, $3.0 million for 2003 and $2.9 million for 2002.

cost growth rates would have effects shown in the following table.

Under our qualified employee stock purchase plan established in One-Percentage- One-Percentage- 1999, full-time, non-union employees purchase designated shares Point Increase Point Decrease of our common stock at no more than a 15% discounted price. Our (inThousands) employees purchased 185,016 shares in 2004 at an average price of Effect on total of service and interest cost ........... . $ 113 S (111)

$17.20 per share. Employees purchased 403,705 shares in 2003 at Effect on post-retirement benefit obligation ......... .. 1,914 (1,878) an average price of $8.45 per share and employees purchased 46,432 shares at an average price of $8.45 per share in 2002. We The asset allocation for the pension plans and the post-retirement discontinued this plan effective January 1, 2005.

benefit plans at the end of 2004 and 2003, and the target allocations for 2005 and 2006, by asset category, are as shown in the following Stock Based Compensation Plans table. We have a long-term incentive and share award plan (LTISA Plan),

Target Allocations PlanAssets which is a stock-based compensation plan in which employees Asset Category 2006 2005 2004 2003 and directors are eligible for awards. The LTISA Plan was imple-Pension Plans: mented as a means to attract, retain and motivate employees and Equity securities ...............,.. 65% 65% 68% 68% directors. Under the LTISA Plan, we may grant awards in the form Debt securities ........ ,. ,,.,. 30% 30% 28% 29% of stock options, dividend equivalents, share appreciation rights, Cash and other ....... 5% 5% 4% 3% RSUs, performance shares and performance share units to plan participants. Up to five million shares of common stock may be Total ,..,,,,,... 100% 100%

granted under the LTISA Plan. At December 31, 2004, awards of Post-retirement Benefit Plans: 3,639,062 shares of common stock had been made under the Equity securities ......... ,.,,,,.,. 65% 40% 35% 32% LTISA Plan. Dividend equivalents accrue on the awarded RSUs.

Debt securities ................... 30% 55% 45% 34% Dividend equivalents are the right to receive cash equal to the Cash and other ............ ,.. 5% 5% 20% 34% value of dividends paid on our common stock.

Total 100% 100%

In December 2004, the FASB issued SFAS No. 123R,'Share-Based Payment: An Amendment of FASB Statements No. 123 and 95."

We manage pension and retiree welfare plan assets in accordance SFAS No. 123R requires companies to recognize as compensation with the"prudent investor"guidelines contained in the Employee expense the grant-date fair value of stock options and other Retirement Income Securities Act of 1974 (ERISA). The plan's equity-based compensation issued to employees. The provisions of investment strategy supports the objective of the funds, which is to the statement are effective for financial statements issued for earn the highest possible return on plan assets consistent with a periods that begin after June 15, 2005, which will be our third reasonable and prudent level of risk. Investments are diversified quarter beginning July 1, 2005. We will use the modified prospective across classes, sectors and manager style to minimize the risk of transition method. Under the modified prospective method, large losses. We delegate investment management to specialists in awards that are granted, modified or settled after the date of each asset class and where appropriate, provide the investment adoption will be measured and accounted for in accordance with manager with specific guidelines, which include allowable and/or SFAS No. 123R. Compensation cost for awards granted prior to, prohibited investment types. Investment risk is measured and but not vested as of the date SFAS No. 123R is adopted, would be monitored on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements. based on the grant date, fair value and attributes originally used to value those awards.

Pension Benefits Post-Retirement Benefits We currently use RSUs for stock-based awards granted to manage-To/(From) Tol(From)

To/(From) Company To/(From) Company ment employees. In addition, we have eliminated our employee Expected cashflows: Trust Assets Trust Assets stock purchase plan and all outstanding options have vested. Given OnThousands) the characteristics of our stock-based compensation program, we Expected contributions: do not expect the adoption of SFAS No. 123R to materially impact 2005 .... . - $ 1,900 $ 18,600 $ 300 our results of operations.

Expected benefit payments:

2005 ................... S (26,700) S(1,900) $ (8,100) $ (300) In 2004, we granted 67,051 RSUs to selected management 2006 ................... (26,200) (2,000) (8,200) (300) employees and directors. In 2003, we granted 559,095 RSUs to 2007 .... ......... (26,000) (1,900) (8,400) (300) officers, selected management employees and directors. We granted 2008 ........... (25,800) (1,800) (8,400) (300) 590,585 RSUs to a broad-based group of over 800 non-union 2009 ................... (25,600) (1,800) (8,400) (300) employees and directors in 2002. Each RSU represents a right to 2010-2014 ....... . (137,000) (9,100) (42,500) (1,500) receive one share of our common stock at the end of the restricted period assuming certain criteria are met.The unearned compensa-Savings Plans tion related to the grant of RSUs is shown as a separate component We maintain a qualified 401(k) savings plan in which most of our of shareholders'equity. Unearned compensation is being amortized 53 employees participate. We match employees'contributions in cash to expense over the vesting period. In addition, RSUs linked to up to specified maximum limits. Our contributions to the plans are 783,400 shares of Protection One common stock and 12,193 shares deposited with a trustee and are invested at the direction of plan of Guardian International, Inc. preferred stock held by us were participants into one or more of the investment alternatives we granted to certain current and former officers in 2002.

2 0 04 ANN UAL REPO RT During the second quarter of 2002, active employees awarded RSUs under the LTISA plan are as follows.

RSUs in prior years were allowed to exchange eligible RSUs for As of December 31, 2004 2003 2002 shares of common stock. As a result, approximately 145,000 RSUs Weighted- Weighted- Weighted-were exchanged for approximately 105,000 shares of our common Average Average Average stock. In addition, approximately 317,000 RSUs held by certain Exercise Exercise Exercise Shares Price Shares Price Shares Price executive officers were exchanged for approximately 12,500 shares (InThousands) (InThousands) (inThousands) of Guardian International, Inc. preferred stock held by us.

Outstanding, Compensation expense associated with this exchange totaled beginning of year .. 1,913.7 $16.25 1,619.9 $18.08 1,902.9 $22.87 approximately $9.0 million for 2002. Also, in September 2002, Granted ........... 60.1 20.57 547.3 12.90 584.2 13.28 former employees had the opportunity to convert vested RSUs into Vested ............ (668.4) 14.65 (251.8) 14.60 (291.8) 18.81 common stock. As a result, 34,433 shares of our common stock Forfeited .......... (7.0) 17.72 (1.7) 17.39 (575.4) 28.70 were issued in exchange for 68,865 RSUs. Outstanding, end of year ....... 1,298.4 17.50 1,913.7 16.25 1,619.9 18.08 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 current cash compensation. The RSUs issued and outstanding at December 31, 2004 are as follows.

Executive Stock for Compensation program was modified in 2001 Number to pay a portion of current compensation in the form of stock. Range Issued of FairValue and Although this plan was discontinued in 2001, dividends will at Grant Date Outstanding continue to be paid to plan participants on their outstanding plan Restricted share units:

balance until distribution. At the end of the deferral period, RSUs 2004 ..................................... $20.45 59,225 are paid in the form of stock. Plan participants were awarded 4,422 2003 ..................................... 11.57-13.95 464,731 shares of common stock for dividends in 2004, 10,009 shares in 2002 ..................................... 11.57-17.49 180,555 2003, and 12,121 shares in 2002. Participants received common 2001 ..................................... 17.67-19.61 196,820 stock distributions of 46,544 shares in 2004, 5,101shares in 2003 2000 ..................................... 15.3125-19.875 264,249 and 40,097 shares in 2002. 1999 ..................................... 27.8130-32.125 63,783 1998 ..................................... 38.625 69,000 Stock options under the LTISA plan are as follows. Total outstanding . .1,298,363 Asof December 31, 2004 2003 2002 Weighted- Weighted- Weighted- We also issued dividend equivalents to recipients of stock options Average Average Average and RSUs. Recipients of RSUs receive dividend equivalents when Exercise Exercise Exercise Shares Price Shares Price Shares Price dividends are paid on shares of company stock. The value of each (InThousands) (in Thousands) (InThousands) dividend equivalent related to stock options is calculated by Outstanding, accumulating dividends that would have been paid or payable on a beginning of year . . 226.7 $32.92 232.6 $32.08 552.3 $34.02 share of company common stock. The dividend equivalents, with Exercised .......... (1.5) 15.31 - (2.6) 18.71 respect to stock options, expire after nine years from date of grant.

Forfeited .......... - - (5.9) 24.99 (317.1 ) 35.57 The weighted-average fair value at the grant-date of the dividend Outstanding, equivalents on stock options was $6.40 in 2004, $6.38 in 2003 and end of year ....... 225.2 32.38 226.7 32.92 232.6 32.08 $6.35 in 2002.

Stock options issued and outstanding at December 31, 2004 are 13. WCNOC EMPLOYEE BENEFIT PLANS as follows. Pension and Post-retirement Benefits Number Weighted- Weighted- The WCNOC pension plan expense and liabilities are measured Range of Issued Average Average Exercise and Contractual Exercise using assumptions, which include discount rates, compensation Price Outstanding Life inYears Price rates and past and future estimated plan asset returns. Due to a Options - Exercisable: decrease in interest rates and a corresponding decrease in the 2000. $15.3125 7,783 6 $ 15.31 discount rates used to estimate pension liabilities, the fair value of 1999 .27.8125-32.125 22,900 5 29.52 WCNOC's pension plan assets was less than the accumulated 1998 .38.625-43.125 55,890 4 41.15 benefit obligation at the measurement dates. On March 29, 2004, 1997 .30.75 94,490 3 30.75 the FERC issued guidance allowing an entity to recognize the 1996 .29.25 44,095 2 29.25 amount of the minimum pension liability otherwise chargeable to Total outstanding .225,158 other comprehensive income as a regulatory asset. On January 13, 2005, we received an accounting authority order from the KCC to 54 III

2004 ANNUAL REPORT recognize as a regulatory asset the additional minimum pension Pension Benefits Post-retirement Benefits liability that otherwise would have been charged to other compre- At December 31, 2004 2003 2004 2003 hensive income. At December 31, 2004, our share of WCNOC's (DollarsinThousands) additional minimum pension liability adjustment was $3.1 million, Accumulated Benefit Obligation . S 46,455 S 37.037 N/A N/A offset by an intangible asset of $0.6 million and a regulatory asset of Pension Plans With aProjected

$2.5 million. At December 31, 2003, our share of WCNOC's Benefit Obligation In Excess additional minimum pension liability was immaterial. of Plan Assets:

Projected benefitobligation S 59,168 S 49,927 N/A N/A As a co-owner of WCNOC, we are indirectly responsible for 47% Accumulated benefit of the liabilities and expenses associated with the WCNOC pension obligation .............. 46,455 37,037 N/A N/A and post-retirement plans. We accrue our 47% of the WCNOC Fairvalueofplanassets ..... 32,491 26,799 N/A N/A cost of pension and post-retirement benefits during the years an Pension Plans With an Accumulated employee provides service. Our 47% share is included in the tables Benefit Obligation InExcess that follow. of Plan Assets:

Projected benefitobligation $ 59,168 $ 49,927 N/A N/A Pension Benefits Post-retirement Benefits Accumulated benefit At December 31, 2004 2003 2004 2003 obligation .............. 46,455 37,037 N/A N/A (inThousands) Fair value of plan assets ..... 32,491 26,799 N/A N/A Post-retirement Plans With an Change in Benefit Obligation:

Accumulated Post-retirement Benefit obligation, Benefit Obligation InExcess beginning of year ........ $..49,927 S 44,519 $ 5,455 S 4,857 of Plan Assets:

Service cost ................ 2,572 2,545 235 218 Accumulated post-retirement Interest cost ............... 3,295 2,928 356 289 benefit obligation ........ N/A N/A $ 6,060 5 5,455 Plan participants' contributions . - - 147 111 Fair value of plan assets ..... N/A N/A N/A N/A Benefits paid ............... (849) (729) (416) (349) Weighted-Average Actuarial Actuarial losses ............. 4,223 664 325 329 Assumptions used to Determine Net Periodic Benefit obligation, end of year. S$. 59,168 $ 49,927 $ 6,102 S 5,455 Benefit Obligation:

Change in Plan Assets: Discount rate ............. 6.00% 6.20% 6.00% 6.20%

Fair value of plan assets, Compensation rate increase . . 3.00% 3.20% N/A N/A beginning of year .......... S 26,799 $ 22,276 $ N/A S N/A Actual return on plan assets ... 2,551 2,622 N/A N/A WCNOC uses a measurement date of December 1for the majority Employer contribution .3,810 2,459 N/A NWA of its pension and post-retirement benefit plans.

Benefits paid ...... , .. (669) (558) N/A N/A The prior service cost is amortized on a straight-line basis over the Fair value of plan assets, average future service of the active plan participants benefiting end of year .............. 5 32,491 $ 26,799 $ N/A S N/A under the plan at the time of the amendment.The net actuarial loss subject to amortization is amortized on a straight-line basis over Funded status .............. S (26,677) S (23,128) $ (6,102) S (5,455) the average future service of active plan participants benefiting Unrecognized net loss ........ 15,239 11,589 2,211 2,028 under the plan, without application of the amortization corridor Unrecognized transition described in SFAS Nos. 87 and 106.

obligation, net ............ 398 455 461 519 Unrecognized prior service cost. 220 252 - - Pension Benefits Post-measurement date Forthe YearEndedDecember 31, 2004 2003 2002 adjustments .............. 740 441 - -

(DollarsinThousands)

Accrued post-retirement Components of Net Periodic Cost:

benefit costs ............. 5 (10,080) 3 (10,391) S (3,430) $ (2,908)

Service cost ......................... S 2,572 S 2,545 $ 2,207 Amounts Recognized inthe Interest cost ......................... 3,295 2,928 2,613 Balance Sheets Consist Of: Expected return on plan assets ...... ..... (2,780) (2,464) (2,469)

Accrued benefitliability ....... S (10,080) 3 (10,391) S (3,430) $ (2,908) Amortization of unrecognized:

Additional minimum liability ... (3,144) (66) N/A N/A Transition obligation, net ........ ...... 57 57 57 Intangible asset ............. 618 35 N/A N/A Priorservice costs ........... ........ 31 31 27 Other comprehensive income(a) . - 31 N/A N/A Loss, net .......................... 802 603 21 Regulatory asset(^) ........... 2,526 - N/A N/A Curtailments, settlements and Net amount recognized ....... $ (10,080) $ (10,391) S (3,430) $ (2,908) special term benefits ......... ........ - - 284 Net periodic cost ............. ........ S 3,977 3 3,700 $ 2,740

'On March 29, 2004, FERC issued guidance allowing an entity to recognize the amount of the minimum pension liability otherwise chargeable to other Weighted-Average Actuarial Assumptions comprehensive income as a regulatoryasset. On January 13, 2005, we received used to Determine Net Periodic Cost:

an accounting authority orderfrom the KCC to record the other comprehensive Discount rate ........................ 6.20% 6.75% 7.25%

income related to pension benefit obligation costs as a regulatoryasset. Expected long-term return on plan assets . .. 9.00% 9.00% 9.02%

55 Compensation rate increase .. ............ 3.20% Graded rates Graded rates

2004 ANN UAL REPORT Post-retirement Benefits WCNOC's pension plan investment strategy supports the Forthe YearEndedDecember 31, 2004 2003 2002 objective of the fund, which is to earn the highest possible return (Dollars inThousands) on plan assets consistent with a reasonable and prudent level of risk. Investments are diversified across classes, sectors and Components of Net Periodic Cost:

Servicecost ......................... $ 235 $ 218 $ 166 manager style to minimize the risk of large losses. WCNOC Interest cost . .356 289 272 delegates investment management to specialists in each asset class Expected return on plan assets . .- - -

and where appropriate, provides the investment manager with Amortization of unrecognized:

specific guidelines, which include allowable and/or prohibited Transition obligation, net . .58 58 57 investment types. Investment risk is measured and monitored on Prior service costs . .- - -

an ongoing basis through quarterly investment portfolio reviews.

toss, net . .141 99 73 Pension Benefits Post-Retirement Benefits Curtailments, settlements and To/(From) To/(From) special term benefits ................. - - - To/(From) Company To/(From) Company Expected cashflows: Trust Assets Trust Assets Net periodic cost ............. ........ 5 790 $ 664 5 568 (InThousands)

Weighted-Average Actuarial Assumptions Expected contributions:

used to Determine Net Periodic Cost:

2005 ................... $ 4,700 S 200 $ N/A 5 300 Discount rate .6.10% 6.50% 7.25%

Expected benefit payments:

Expected long-term return on plan assets . .. 8.50% N/A N/A 2005 ................... S (800) 5 (200) S N/A S (300)

Compensation rate increase.N/A N/A N/A 2006 ................... (900) (200) N/A (300) 2007 ................... (1,100) (200) N/A (300)

The expected long-term rate of return on plan assets is based on 2008 ................... (1,400) (200) NIA (400) historical and projected rates of return for current and planned 2009 ................... (1,600) (200) N/A (400) asset classes in the plans'investment portfolio. Assumed projected 2010-2014. (13,800) (900) N/A (2,600) rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the Savings Plan volatility of the various asset classes. Based on target asset alloca-tions for each asset class, the overall expected rate of return for the WCNOC maintains a qualified 401(k) savings plan in which most portfolio was developed, adjusted for historical and expected of its employees participate. They match employees'contributions experience of active portfolio management results compared to in cash up to specified maximum limits. WCNOC's contribution to benchmark returns and for the effect of expenses paid from plan the plan is deposited with a trustee and is invested at the direction assets. In selecting the discount rate, fixed income security yield of plan participants into one or more of the investment alternatives rates for corporate high-grade bond yields are considered. provided under the plan. Our portion of expense associated with WCNOC's matching contributions was $0.8 million for 2004, For measurement purposes, the assumed annual health care cost $0.9 million for 2003 and $0.8 million for 2002.

growth rates were as follows.

At December 31, 2004 2003 14. INCOME TAXES Health care cost trend rate assumed for next year .8.5% 9.0%

Income tax expense (benefit) is composed of the following compo-Rate to which the cost trend rate isassumed to decline (the ultimate trend rate) .5.0% 5.0% nents at December 31.

Year that the rate reaches the ultimate trend rate .2012 2012 2004 2003 2002 (inThousands)

The health care cost trend rate has a significant effect on the projected Current income taxes:

benefit obligation. A 1% change in assumed health care cost growth Federal .......................... 41,649 S 148,117 S (41,115) rates would have effects shown in the following table. State .......................... (2,991) 33,926 (5,515)

One-Percentage- One-Percentage- Deferred income taxes:

Point Increase Point Decrease Federal .......................... (2,285) (78,069) 31,014 (InThousands) State .......................... 1,858 (17,564) 8,890 Effect on total of service and interest cost ....... ...... S 3 $ (3) Investmenttaxcreditamortization ....... (4,788) (4,642) (4,793)

Effect on the present value of the accumulated Total income tax expense (benefit) projected benefit obligation ................ 46 (45) as reported before discontinued operations and cumulative effect The asset allocation for the pension plans at the end of 2004 and of accounting change ....... .... 33,443 81,768 (11,519) 2003, and the target allocation for 2005, by asset category are as Income tax expense (benefit) from shown in the following table. discontinued operations:

Discontinued operations ............. (45,281) (164,036) (146,910)

Target Allocation PlanAssets Cumulative effect of accounting change . - - (72,335)

Asset Category for 2005 2004 2003 Totalincometaxbenefit ....... .... 5 (11,838) $ (82268) 1(230,764)

Pension Plans:

56 Equity securities .............. ....... 50% - 70% 65% 66%

Debt securities ...................... 30% - 50% 28% 33%

Other ........................... 0% 7% 1%

Total .100% 100%

2 004 ANN UAL REPO RT Deferred tax assets and liabilities are reflected on our consolidated The effective income tax rates set forth below are for continuing balance sheets as follows. operations. The rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The December 31, 2004 2003 difference between the effective tax rates and the federal statutory (inThousands) income tax rates are as follows.

Current deferred tax assets, net ........ ......... $ 7,218 S 123,256 Non-current deferred tax liabilities, net ... ........ 927,087 969,544 For the YearEnded December 31, 2004 2003 2002 Netdeferredtaxliabilities ...................... S 919,869 $ 846,288 Statutory federal income tax rate ........ ..... 35.0% 35.0 % 35.0%

Effect of:

State income taxes ................... ... 1.0 4.3 2.8 Temporary differences related to deferred tax assets and deferred Amortization of investment tax credits ......... (3.6) (1.9) (6.2) tax liabilities are summarized in the following table.

Corporate-owned life insurance policies ...... (9.0) (5.0) (15.0)

December 31, 2004 2003 Accelerated depreciation flow (inThousands) through and amortization .......... ..... 5.3 2.2 6.4 Dividends received deduction .............. - (1.7) (12.6)

Deferred tax assets:

Income tax reserve adjustment ............. (5.3) - (27.4)

Deferred gain on sale-leaseback ....... ........ $ 61,241 S 66,448 Capital loss utilization ............. ...... (2.2) -

General business credit carryforward'a. 27,645 27,524 Other ............................ 3.8 0.5 2.1 Accrued liabilities .18,803 19,599 Disallowed plant costs .13,484 14,527 Effective income tax rate ................... 25.0 % 33.4% (14.9)%

Long-term energy contracts .11,194 12,034 Protection One impairment .- 327,665 As of December 31, 2004 and 2003, we had recorded reserves for Capital loss carryforward(b) .230,226 uncertain tax positions, including interest, of $49.7 million and Other .74,875 69,074 $55.6 million, respectively. During 2004, we reduced this reserve by Total gross deferred tax assets .437,468 536,871 $5.9 million due to a re-evaluation of estimates based on expected Less: Valuation allowance. .236,588 236,214 settlements and the finalization of the sale of Protection One. Tax Deferred tax assets ............... $.........

200,880 $ 300,657 reserves are established for tax deductions or income positions taken in prior income tax returns that we believe were treated Deferred tax liabilities: properly on the tax returns but may be challenged if such tax Accelerated depreciation ........... $..........

659,776 $ 666,315 returns are audited. The tax returns containing these tax deductions Acquisition premium . .243,165 251,163 or income positions are currently under audit or will likely be Amounts due from customers for future audited.The timing of the resolution of these audits is uncertain. If incometaxes,net . .191,597 207,812 the positions taken on the returns are ultimately sustained, we will Other . .26,211 21,655 reverse these tax provisions to income. If the positions taken on the Total deferred tax liabilities ......... $1.........

1120,749 $1,146,945 tax returns are not ultimately sustained, we may be required to make cash payments plus interest. We also have a tax reserve of Netdeferredtaxliabilities ...................... S 919,869 $ 846,288 $4.3 million (after-tax) for property and sales tax assessments by WsBalance represents unutilized tax credits generated from affordable housing various state and local taxing authorities.

partnershipsin which we sold the majorityof our interests in 2001. These credits expire beginning 2019 through2024. 15. COMMITMENTS AND CONTINGENCIES N We have a net capital loss of$839.6 million available to offset past andfuture capital gains. The capital loss can be carried back to offset 2003 capital gains Purchase Orders and Contracts (limited to the amount of 2003 taxable income). Any excess capital loss is As part of our ongoing operations and construction program, we availableforcarryforwardthrough 2009. However, as we do not expect to realize any significant capital gains in the future, a valuation allowance of $230.2 have purchase orders and contracts, excluding fuel, which is million has been established. In addition, a valuation allowance of $6.4 million discussed below under "- Fuel Commitments," that have an has been establishedfor certain deferred tax assets related to the write-down of unexpended balance of approximately $159.4 million at December investments. 31, 2004, of which $34.6 million has been committed. The

$34.6 million commitment relates to purchase obligations issued In accordance with various rate orders, we have reduced rates to and outstanding at year-end.

reflect the tax benefits associated with certain accelerated tax deductions. We believe it is probable that the net future increases in The yearly detail of the aggregate amount of required payments at income taxes payable will be recovered from customers when these December 31,2004 was as follows.

temporary tax benefits reverse. We have recorded a regulatory asset Committed for these amounts. We also have recorded a regulatory liability for Amount our obligation to reduce rates charged customers for deferred taxes (in Thousands) recovered from customers at corporate tax rates higher than the 2005 .$,..... 528,601 current tax rates. The rate reduction will occur as the temporary 2006 .3,668 differences resulting in the excess deferred tax liabilities reverse. 2007 .2,343 The tax-related regulatory assets and liabilities as well as unamor- $34,612 57 tized investment tax credits are also temporary differences for which deferred income taxes have been provided. This liability is classified above as amounts due from customers for future income taxes.

20 04 ANN U AL REPO RT Clean Air Act liability for twelve of the Kansas sites is limited. Of those twelve Generally, we must comply with the Clean Air Act, state laws and sites, ONEOK assumed total liability for remediation of seven sites implementing regulations that impose, among other things, and we share liability for remediation with ONEOK for five sites.

limitations on major pollutants, including sulfur dioxide (S02), Our total liability for the five shared sites is capped at $3.8 million particulate matter and nitrogen oxides (NOx). In addition, we must and terminates in 2012. We have sole responsibility for remediation comply with the provisions of the Clean Air Act Amendments of with respect to three Kansas sites. With respect to two of those 1990 that require a two-phase reduction in some emissions. We sites, we are currently either conducting or completing remediation have installed continuous monitoring and reporting equipment in activities and, with respect to the third site, we will begin investiga-order to meet the acid rain requirements. We have not had to make tion activities in the near future.

any material capital expenditures to meet Phase II S02 and Our liability for our former manufactured gas sites in Missouri is NOx requirements. limited by an environmental indemnity agreement with Southern EPA New Source Review Union Company, which bought all of the Missouri manufactured gas sites. According to the terms of the agreement, our future The Environmental Protection Agency (EPA) is conducting liability for these sites is capped at $7.5 million and terminates investigations nationwide to determine whether modifications at in 2009.

coal-fired power plants are subject to New Source Review require-ments or New Source Performance Standards under Section 114(a) Solid Waste Landfills of the Clean Air Act (Section 114). These investigations focus on We operate solid waste landfills at Jeffrey, Lawrence and Tecumseh whether projects at coal-fired plants were routine maintenance or Energy Centers for the single purpose of disposing of coal whether the projects were substantial modifications that could combustion waste material. Additionally, there is one retired landfill have reasonably been expected to result in a significant net at each of the Lawrence and Neosho Energy Centers. All landfills increase in emissions. The Clean Air Act requires companies to are permitted by the KDHE. The operating landfill at Lawrence obtain permits and, if necessary, install control equipment to Energy Center is projected to be full by late 2007 or early 2008 remove emissions when making a major modification or a change requiring us to permit and construct a new landfill at this site. We in operation if either is expected to cause a significant net increase began the process of obtaining this permit in late 2003. We will in emissions. continue to work with the appropriate regulatory agencies to ensure The EPA has requested information from us under Section 114 that the new landfill and expansion of the existing landfill will meet regarding projects and maintenance activities that have been the operating requirements of the Lawrence Energy Center.

conducted since 1980 at the three coal-fired plants we operate. On Nuclear Decommissioning January 22, 2004, the EPA notified us that certain projects Nuclear decommissioning is a nuclear industry term for the perma-completed at Jeffrey Energy Center violated pre-construction nent shutdown of a nuclear power plant and the removal of permitting requirements of the Clean Air Act. radioactive components in accordance with Nuclear Regulatory We are in discussions with the EPA concerning this matter in an Commission (NRC) requirements. The NRC will terminate a attempt to reach a settlement. We expect that any settlement with plant's license and release the property for unrestricted use when a the EPA could require us to update or install emissions controls at company has reduced the residual radioactivity of a nuclear plant Jeffrey Energy Center over an agreed upon number of years. to a level mandated by the NRC. The NRC requires companies Additionally, we might be required to update or install emissions with nuclear plants to prepare formal financial plans to fund nuclear controls at our other coal-fired plants, pay fines or penalties, or decommissioning.These plans are designed so that funds required take other remedial action. Together, these costs could be material. for nuclear decommissioning will be accumulated prior to the The EPA has informed us that it has referred this matter to the termination of the license of the related nuclear power plant.

Department of Justice (DOD for the DOJ to consider whether to We expense nuclear decommissioning costs over the expected life pursue an enforcement action in federal district court. Wle believe of Wolf Creek. The amount we expense is based on an estimate of that costs related to updating or installing emissions controls nuclear decommissioning costs that we will incur upon retirement would qualify for recovery through rates. If we were to reach a of the plant. Nuclear decommissioning costs that are recovered in settlement with the EPA, we may be assessed a penalty. The rates are deposited in an external trust fund. In 2004, we expensed penalty could be material and may not be recovered in rates. approximately $3.9 million for nuclear decommissioning. We Manufactured Gas Sites record our investment in the nuclear decommissioning fund at fair value. Fair value approximated $91.1 million at December 31, 2004 We have been associated with a number of former manufactured and $80.1 million at December 31, 2003.

gas sites located in Kansas and Missouri that may contain coal tar and other potentially harmful materials. The KCC reviews nuclear decommissioning plans in two phases.

Phase one is the approval of the nuclear decommissioning study, We and the Kansas Department of Health and Environment the current-year funding and future funding. Phase two is the filing (KDHE) entered into a consent agreement in 1994 governing all of a"funding schedule"by the owner of the nuclear facility detailing future work at the Kansas sites. Under the terms of the consent how it plans to fund the future-year dollar amount for the pro rata agreement, we agreed to investigate and remediate, if necessary, share of the plant.

58 these sites. Through December 31, 2004, the costs incurred for preliminary site investigation and risk assessment have been We filed an updated nuclear decommissioning and dismantlement minimal. Pursuant to an environmental indemnity agreement with cost estimate with the KCC on August 30, 2002. Estimated costs ONEOK, the current owner of some of the Kansas sites, our outlined by this study were developed to decommission W'olf

2 004 ANN UAL REPO RT Creek following a shutdown. The analyses relied on site-specific, activities. This action allows the DOE to apply to the NRC to technical information, updated to reflect current plant conditions license the project. The DOE expects that this facility will open in and operating assumptions. Based on this study, our share of 2012. However, the opening of the Yucca Mountain site has been Wolf Creek's nuclear decommissioning costs, under the imme- delayed many times and could be delayed further due to litigation diate dismantlement method, is estimated to be approximately and other issues related to the site as a permanent repository for

$220.0 million in 2002 dollars. These costs include decontamination, spent nuclear fuel.

dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. The actual nuclear Nuclear Insurance decommissioning costs may vary from the estimates because of We maintain nuclear insurance for Wolf Creek in four areas:

changes in technology and changes in costs for labor, materials liability, worker radiation, property and accidental outage. These and equipment. policies contain certain industry standard exclusions, including but not limited to, ordinary wear and tear and war. Both the nuclear The KCC issued an order on April 16, 2003 approving the August liability and property insurance programs subscribed to by members 2002 nuclear decommissioning study for Wolf Creek. On June 2, of the nuclear power generating industry include industry aggregate 2003, we filed a funding schedule with the KCC to reflect the limits for non-certified acts, as defined by the Terrorism Risk KCC's April 16, 2003 order. On October 10, 2003, the KCC Insurance Act, of terrorism-related losses, including replacement approved the funding schedule as filed without any change to our power costs. An industry aggregate limit of $300.0 million exists for funding obligation. liability claims, regardless of the number of non-certified acts We charge nuclear decommissioning costs to operating expense affecting Wolf Creek or any other nuclear energy liability policy or in accordance with the July 25, 2001 KCC rate order as modified the number of policies in place. An industry aggregate limit of by the KCC's approval of the funding schedule in the KCC's $3.24 billion plus any reinsurance recoverable by Nuclear Electric October 13,2003 order. Electric rates charged to customers provide Insurance Limited (NEIL), our insurance provider, exists for for recovery of these nuclear decommissioning costs over the life of property claims, including accidental outage power costs for acts of Wolf Creek, which, as determined by the KCC for purposes of the terrorism affecting Wolf Creek or any other nuclear energy facility funding schedule, will be through 2045. The NRC requires that property policy within twelve months from the date of the first act.

funds to meet its nuclear decommissioning funding assurance These limits are the maximum amount to be paid to members who requirement be in our nuclear decommissioning fund by the time sustain losses or damages from these types of terrorist acts. For our license expires in 2025. We believe that the KCC approved certified acts of terrorism, the individual policy limits apply. In funding level will be sufficient to meet the NRC minimum financial addition, industry-wide retrospective assessment programs assurance requirement. However, our consolidated results of (discussed below) can apply once these insurance programs have operations would be materially adversely affected if we are not been exhausted.

allowed to recover the full amount of the funding requirement. Nuclear Liability Insurance Storage of Spent Nuclear Fuel Pursuant to the Price-Anderson Act, we are required to insure Under the Nuclear Waste Policy Act of 1982, the Department of against public liability claims resulting from nuclear incidents to Energy (DOE) is responsible for the permanent disposal of spent the full limit of public liability, which is currently approximately nuclear fuel. As required by federal law, the WCNOC co-owners $10.8 billion. This limit of liability consists of the maximum avail-entered into a standard contract with the DOE in 1984 in which the able commercial insurance of $300.0 million, and the remaining DOE promised to begin accepting from commercial nuclear power $10.5 billion is provided through mandatory participation in an plants their used nuclear fuel for disposal beginning in early 1998. industry-wide retrospective assessment program. Under this In return, Wolf Creek pays into a federal Nuclear Waste Fund retrospective assessment program, we can be assessed up to administered by the DOE a quarterly fee for the future disposal of $100.6 million per incident at any commercial reactor in the spent nuclear fuel.The fee is one-tenth of a cent for each kilowatt- country, payable at no more than $10.0 million per incident per hour of net nuclear generation produced. We include these year.This assessment is subject to an inflation adjustment based on disposal costs in operating expenses. the Consumer Price Index and applicable premium taxes. This assessment also applies in excess of our worker radiation claims A permanent disposal site will not be available for the nuclear insurance. In addition, Congress could impose additional revenue-industry until 2012 or later. Under current DOE policy, once a raising measures to pay claims. If the $10.8 billion liability permanent site is available, the DOE will accept spent nuclear fuel limitation is insufficient, Congress wili consider taking whatever on a priority basis.The owners of the oldest spent fuel will be given action is necessary to compensate the public for valid claims.

the highest priority.As a result, disposal services for~Aolf Creekwill not be available prior to 2018. Wolf Creek has on-site temporary The Price-Anderson Act expired in August 2002 but was extended storage for spent nuclear fuel. In early 2000, Wolf Creek completed until December 31, 2003 for Licensees. Licensees such as Wolf replacement of spent fuel storage racks to increase its on-site Creek continue to be grandfathered under the Act. The current storage capacity for all spent fuel expected to be generated by Wolf version of a comprehensive energy bill expected to be adopted in Creek through the end of its licensed life in 2025. 2005 by Congress contains provisions that would amend Federal Law (the "Price-Anderson Act") addressing public liability from In 2002, the Yucca Mountain site in Nevada was approved for the nuclear energy hazards in ways that would increase the annual limit development of a nuclear waste repository for the disposal of spent on retrospective assessments from $10.0 million to $15.0 million 59 nuclear fuel and high level nuclear waste from the nation's defense per reactor per incident.

2004 ANNUAL REPORT Nuclear Property Insurance approximately $9.7 million, with the estimated remainder payable The owners of Wolf Creek carry decontamination liability, over the next two years. We recover such costs from prices we premature nuclear decommissioning liability and property damage charge our customers.

insurance for Wolf Creek totaling approximately $2.8 billion (our share is $1.3 billion). This insurance is provided by NEIL. In the 16. ASSET RETIREMENT OBLIGATIONS event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a In January 2003, we adopted SFAS No. 143, "Accounting for Asset plan mandated by the NRC. Our share of any remaining proceeds Retirement Obligations." SFAS No. 143 requires recognition of can be used to pay for property damage or decontamination legal obligations associated with the retirement of long-lived expenses or, if certain requirements are met, including nuclear assets that result from the acquisition, construction, development decommissioning the plant, toward a shortfall in the nuclear or normal operation of such assets. Concurrent with the recogni-decommissioning trust fund. tion of the liability, the estimated cost of an asset retirement obligation is capitalized and depreciated over the remaining life of Accidental Nuclear Outage Insurance the asset. Any income effects are offset by regulatory accounting The owners also carry additional insurance with NEIL to cover pursuant to SFAS No. 71.

costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property Legal Liability - Wolf Creek damage at Wolf Creek. If significant losses were incurred at any of On January 1,2003, we recognized the liability for our 47% share of the nuclear plants insured under the NEIL policies, we may be the estimated cost to decommission Wolf Creek. SFAS No. 143 subject to retrospective assessments under the current policies of requires the recognition of the present value of the asset retirement approximately $26.0 million (our share is $12.2 million). obligation we incurred at the time Wolf Creek was placed into service in 1985. On January 1, 2003, we recorded an asset retire-Although we maintain various insurance policies to provide ment obligation of $74.7 million. In addition, we increased our coverage for potential losses and liabilities resulting from an property and equipment balance, net of accumulated depreciation, accident or an extended outage, our insurance coverage may not be by $10.7 million. We also established a regulatory asset for adequate to cover the costs that could result from a catastrophic $64.0 million, which represents the accretion of the liability since accident or extended outage at Wolf Creek. Any substantial losses 1985 and the increased depreciation expense associated with the not covered by insurance, to the extent not recoverable through increase in plant.The asset retirement obligation is included on our rates, would have a material adverse effect on our consolidated consolidated balance sheets in other long-term liabilities. Currently, financial condition and results of operations. we recover costs to retire Wolf Creek through rates as provided by Fuel Commitments the KCC.

To supply a portion of the fuel requirements for our generating The following table is a reconciliation of the legal asset retirement plants, we have entered into various commitments to obtain obligation related to the nuclear decommissioning of WCNOC, nuclear fuel and coal. Some of these contracts contain provisions which is included on our consolidated balance sheets in other for price escalation and minimum purchase commitments. At long-term liabilities.

December 31, 2004, our share of WCNOC's nuclear fuel commit-As of December 31, 2004 ments were approximately $13.5 million for uranium concentrates (InThousands) expiring in 2007, $1.7 million for conversion expiring in 2007, $8.6 million for enrichment expiring at various times through 2006 and Beginning asset retirement obligation ......... ........... $80,695 Accretion expense ............. ........ 6,423

$52.4 million for fabrication through 2024.

Ending asset retirement obligation .................. $.........

$87,118 At December 31, 2004, our coal and coal transportation contract commitments in 2004 dollars under the remaining terms of the Non-legal Liability - Cost of Removal contracts were approximately $1.5 billion. The largest contract We have recovered amounts in rates to provide for recovery of the expires in 2020, with the remaining contracts expiring at various probable costs of removing utility plant assets, but which do not times through 2013.

represent legal retirement obligations. At December 31, 2004, At December 31, 2004, our natural gas transportation commit- Westar Energy had $1.3 million in removal costs classified as a ments in 2004 dollars under the remaining terms of the contracts regulatory asset and KGE had $2.6 million in removal costs were approximately $43.5 million. The natural gas transportation classified as a regulatory liability. At December 31, 2003, we had contracts provide firm service to several of our natural gas burning $6.6 million in removal costs classified as a regulatory asset.The net facilities and expire at various times through 2010, except for one amount related to non-legal retirement costs can fluctuate based contract that expires in 2016. on amounts related to removal costs recovered compared to removal costs incurred.

Energy Act As part of the 1992 Energy Policy Act, a special assessment is being 17. LEGAL PROCEEDINGS collected from utilities for a uranium enrichment decontamination and nuclear decommissioning fund. Our portion of the assess- We and certain of our present and former officers are defendants in 60 ment, including carrying costs, for Wolf Creek is approximately a consolidated purported class action lawsuit in United States

$11.1 million, adjusted for inflation. To date, we have paid District Court in Topeka, Kansas, "In Re Westar Energy, Inc.

III

2004 ANNUAL REPORT Securities Litigation," Master File No. 5:03-CV-4003 and related the ultimate impact of this matter on our consolidated financial cases. Plaintiffs filed a Consolidated Amended Complaint on position, results of operations and cash flows.

July 15, 2003. The lawsuit is brought on behalf of purchasers of our Certain present and former members of our board of directors and common stock between March 29, 2000, the date we announced officers are defendants in a shareholder derivative complaint filed our intention to separate our electric utility operations from our April 18, 2003,"Mark Epstein vs David C. Wittig Douglas T. Lake, unregulated businesses, and November 8, 2002, the date the KCC Charles Q. Chandler IV,Frank J. Becker, Gene A. Budig, John C.

issued an order prohibiting the separation.The lawsuit alleges that Nettels, Jr., Roy A. Edwards, John C. Dicus, Carl M. Koupal, Jr.,

we violated federal securities laws by making material misrepresen-Larry D. Irick and Cleco Corporation, defendants, and Westar tations or omitting material facts concerning the purpose and Energy, Inc., nominal defendant, Case No. 03-4081-JAR."Plaintiffs benefits of the previously proposed separation of our electric utility filed an amended shareholder derivative complaint on July 30, operations from our unregulated businesses, the compensation of 2003. Among other things, the lawsuit claims that the defendants our senior management and the independence and functioning of (i) breached fiduciary duties owed to us because of the actions and our board of directors, and that as a result we artificially inflated the omissions described in the report of the special committee of our price of our common stock. On August 26, 2004, the court issued board of directors, (ii)caused or permitted our assets to be wasted an order granting a joint motion of all parties requesting a stay of on perquisites for certain insiders and (iii) caused or permitted our the lawsuit until December 7, 2004, pending efforts to settle the May 6, 2002 proxy statement to be issued with materially false and lawsuit through mediation.The court also denied without prejudice misleading statements. The plaintiffs seek unspecified monetary motions to dismiss the lawsuit filed by us and other defendants. damages and other equitable relief. In October 2003, our board of The court stated its intention to set aside the order upon notice by directors appointed a special litigation committee of the board to any party that mediation efforts were unsuccessful, in which case evaluate the amended shareholder derivative complaint. The the court would address the motions to dismiss the lawsuit. The members of the committee were Mollie H. Carter, Arthur B.Krause stay was subsequently extended to. March 18, 2005. We intend to and Michael F. Morrissey. On August 26, 2004, the court issued vigorously defend against this action. We are unable to predict the an order granting a joint motion of all parties requesting a stay of ultimate impact of this matter on our consolidated financial position, the lawsuit until December 7, 2004, pending efforts to settle the results of operations and cash flows. lawsuit through mediation.The stay was subsequently extended to March 18, 2005. Plaintiffs have informed us they intend to file a We and certain of our present and former officers and employees are defendants in a consolidated purported class action lawsuit motion seeking leave to amend the amended consolidated com-filed in United States District Court in Topeka, Kansas, "In Re plaint if the mediation efforts are unsuccessful. The court would Westar Energy ERISA Litigation, Master File No. 03-4032-JAR." then set a date for us, and other defendants who have not already filed a response to the complaint, to respond to the amended Plaintiffs filed a Consolidated Amended complaint on October 20, complaint. We are unable to predict the ultimate impact of this 2003. The lawsuit is brought on behalf of participants in, and matter on our consolidated financial position, results of operations beneficiaries of, our Employees'401 (k)Savings Plan between July 1, and cash flows.

1998 and January 1, 2003. The lawsuit alleges violations of the Employee Retirement Income Security Act arising from the conduct On June 13, 2003, we filed a demand for arbitration with the of certain present and former officers and employees who served American Arbitration Association asserting claims against David or are serving as fiduciaries for the plan. The conduct is related to C. Wittig, our former president, chief executive officer and chair-alleged securities law violations related to the previously proposed man, and Douglas T. Lake, our former executive vice president, separation of our electric utility operations from our unregulated chief strategic officer and member of the board, arising out of their businesses, our rate reviews filed with the KCC in 2000, the previous employment with us. Mr. Wittig and Mr. Lake have filed compensation of and benefits provided to our senior management, counterclaims against us in the arbitration alleging substantial energy marketing transactions with Cleco Corporation and the damages related to the termination of their employment and the first and second quarter 2002 restatements of our consolidated publication of the report of the special committee of our board of financial statements related to the revised goodwill impairment directors. We intend to vigorously defend against these claims.The charge and the mark-to-market charge on our putable/callable arbitration has been stayed pending the completion of a trial notes. On August 26, 2004, the court issued an order granting a scheduled to begin May 9, 2005, of Mr. Wittig and Mr. Lake on joint motion of all parties requesting a stay of the lawsuit until criminal charges in U.S. District Court in the District of Kansas. We December 7, 2004, pending efforts to settle the lawsuit through are unable to predict the ultimate impact of this matter on our mediation. The court also denied without prejudice motions to consolidated financial position, results of operations and cash flows.

dismiss the lawsuit filed by us and other defendants. The court We and our subsidiaries are involved in various other legal, environ-stated its intention to set aside the order upon notice by any party mental and regulatory proceedings. We believe that adequate that mediation efforts were unsuccessful, in which case the court provisions have been made and accordingly believe that the ultimate would address the motions to dismiss the lawsuit. The stay was disposition of such matters will not have a material adverse effect extended to February 8,2005. On February 8,2005, the court held a on our consolidated financial position or results of operations.

conference at which the parties notified the court that efforts to settle the lawsuit through mediation had not been successful. The See also Notes 3, 15, 18 and 20 for discussion of KCC regulatory court then issued an order renewing the previously filed motions to proceedings, alleged violations of the Clean Air Act, an investiga-dismiss and set a scheduling conference on March 8, 2005 to tion by the United States Attorney's Office, an inquiry by the 61 address the scope and timing of discovery in the lawsuit. We intend Securities and Exchange Commission (SEC), an investigation by to vigorously defend against this action. We are unable to predict FERC and potential liabilities to Mr. Wittig and Mr. Lake.

2 004 ANN UAL REPO RT

18. ONGOING INVESTIGATIONS 19. COMMON AND PREFERRED STOCK Grand Jury Subpoena Westar Energy's articles of incorporation, as amended, provide for On September 17, 2002, we were served with a federal grand jury 150,000,000 authorized shares of common stock. At December 31, subpoena by the United States Attorney's Office in Topeka, Kansas, 2004, we had 86,029,721 shares issued and outstanding.

requesting information concerning the use of aircraft and our Westar Energy has a direct stock purchase plan (DSPP). Shares annual shareholder meetings. Since that date, the United States sold pursuant to the DSPP may be either original issue shares or Attorney's Office has served additional subpoenas on us and shares purchased in the open market. During 2004, a total of certain of our employees requesting further information concerning 1,318,079 shares were issued by Westar Energy for the DSPP, the the use of our aircraft; executive compensation arrangements with employee stock purchase plan and other stock based plans operated Mr. Wittig, Mr. Lake and other former and present officers; the under the 1996 Long-Term Incentive and Share Award Plan. At proposed rights offering of Westar Industries stock that was December 31,2004, a total of 5,412,096 shares were available under abandoned; and the company in general. Wre are providing infor-the DSPP registration statement.

mation in response to these requests and we are cooperating fully in the investigation. We have not been informed that we are a Treasury Stock target of the investigation. On December 4, 2003, Mr. Wittig and At December 31, 2004, WIestar Energy did not have any treasury Mr. Lake were indicted by the federal grand jury on conspiracy, stock. At December 31, 2003, Westar Energy had a treasury stock fraud and other criminal charges related to their actions while balance of 203,575 shares.

serving as our officers. The trial on these charges was held in 2004 and ended with a mistrial. A new trial is scheduled to begin on May 9, Preferred Stock Not Subject to Mandatory Redemption 2005. We are unable to predict the ultimate outcome of the Westar Energy's cumulative preferred stock is redeemable in whole investigation or its impact on us. or in part on 30 to 60 days' notice at our option. The table below Securities and Exchange Commission Inquiry shows our redemption amount for all series of preferred stock not subject to mandatory redemption at December 31, 2004.

On November 1, 2002, the SEC notified us that it would be conducting an inquiry into the matters involved in the restatement Total Principal Call Amount of our first and second quarter 2002 financial statements. Our Rate Shares Outstanding Price Premium to Redeem counsel has communicated with the SEC about these and other (Dollars InThousands) matters within the scope of the grand jury investigation, including 4.500% 121,613 $12,161 108.00% $ 973 $13,134 disclosures in our proxy statements concerning personal aircraft 4.250% 54,970 5,497 101.50% 82 5,579 use by former officers and the payment of a bonus to Mr. Wittig in 5.000% 37,780 3,778 102.00% 76 3,854 2002. Wie are unable to predict the ultimate outcome of the inquiry S21,436 $1,131 S22,567 or its impact on us.

FERC Subpoena The provisions of Westar Energy's articles of incorporation, as On December 16, 2002, we received a subpoena from FERC amended, contain restrictions on the payment of dividends or the seeking details on power trades with Cleco Corporation and its making of other distributions on our common stock while any affiliates, documents concerning power transactions between our preferred shares remain outstanding unless certain capitalization system and our marketing operations and information on power ratios and other conditions are met. If the ratio of the capital trades in which we or other trading companies acted as inter- represented by our preference stock and common stock (together, mediaries. WAe have provided information to FERC in response to Subordinated Stock), including premiums on our capital stock and the original subpoena, subsequent requests submitted through our its surplus accounts, to its total capital and its surplus accounts at counsel and additional subpoenas received July 28, 2003 and the end of the second month immediately preceding the date of October 27, 2003 seeking information about compliance with the proposed payment of dividends, adjusted to reflect the FERC codes of conduct applicable to generation and transmission proposed payment (Capitalization Ratio), will be less than 20%,

activities. We believe that our participation in these transactions then the payment of the dividends on Subordinated Stock shall and the conduct of our generation and transmission operations did not exceed 50% of net income available for dividends for the 12-not violate FERC rules and regulations. However, we are unable to month period ending with and including the second month predict the ultimate outcome of the investigation. immediately preceding the date of the proposed payment. If the Capitalization Ratio is 20% or more but less than 25%, then the Department of Labor Investigation payment of dividends on the Subordinated Stock, including the On February 1,2005, we received a subpoena from the Department proposed payment, shall not exceed 75% of its net income of Labor seeking documents related to our Employees' 401(k) available for dividends for such 12-month period. Except to the Savings Plan and our defined benefit pension plan.At this time, we extent permitted above, no payment or other distribution may be do not know the specific purpose of the investigation and we are made that would reduce the Capitalization Ratio to less than 25%.

unable to predict the ultimate outcome of the investigation or its The Capitalization Ratio is determined based on the uncon-impact on us. See Note 17,"Legal Proceedings,"for discussion of a solidated balance sheet for Westar Energy. At December 31, 2004, class action lawsuit brought on behalf of participants in our the Capitalization Ratio was greater than 25%.

62 Employees'401 (k) Savings Plan.

11i

2 004 ANN UAL REPO RT So long as there are any outstanding shares of Westar Energy charges filed by the United States Attorney's Office in Topeka, preferred stock, Westar Energy shall not without the consent of a Kansas, against Mr. Wittig and Mr. Lake, and the legal proceedings majority of the shares of preferred stock or if more than one-third described in Note 17, "Legal Proceedings,"above. We are unable to of the outstanding shares of preferred stock vote negatively and estimate the amount of the additional legal fees and expenses that without the consent of a percentage of any and all classes required will be incurred by Mr. Wittig and Mr. Lake for which we may be by law and Westar Energy's articles of incorporation, declare or pay ultimately responsible. We are also currently unable to determine any dividends (other than stock dividends or dividends applied by the amount of the fees which may be recovered under any applicable the recipient to the purchase of additional shares) or make any directors and officers liability insurance policies.

other distribution upon Subordinated Stock unless, immediately In addition to these amounts, we could also be obligated to make after such distribution or payment the sum of Westar Energy's payments to Mr. Wittig and Mr. Lake pursuant to the executive capital represented by the outstanding Subordinated Stock and our salary continuation plan. Assuming an expected payout period of earned and any capital surplus shall not be less than $10.5 million 35 years, the aggregate nominal amount of these payments would plus an amount equal to twice the annual dividend requirement on be approximately $16.6 million for Mr. Wittig and $8.3 million for all the then outstanding shares of preferred stock.

Mr. Lake.

20. POTENTIAL LIABILITIES TO DAVID C.WITTIG 21. REDEMPTION OF GUARDIAN INTERNATIONAL AND DOUGLAS T. LAKE PREFERRED STOCK David C. Wittig, our former chairman of the board, president and On July 9,2004, Guardian International, Inc. (Guardian) redeemed chief executive officer, resigned from all of his positions with us and 8,397 shares of Guardian Series C preferred stock held of record by our affiliates on November 22, 2002. On May 7, 2003, our board of us. The redemption price was $8.6 million, representing the par directors determined that the employment of Mr. Wittig was value of $1,000 per share, or $8.4 million, plus $0.2 million in accrued terminated as of November 22,2002 for cause. DouglasT. Lake, our dividends through the date of redemption and the redemption former executive vice president, chief strategic officer and member premium. In 2002, we granted certain current and former officers of the board, was placed on administrative leave from all of his 540 RSUs linked to these securities. In 2002, we also transferred positions with us and our affiliates on December 6, 2002. On beneficial ownership of 4,714 shares of Guardian Series C preferred June 12,2003, our board of directors terminated the employment of stock to Mr. Wittig and Mr. Lake in exchange for other securities.

Mr. Lake for cause. The ownership of these shares and related dividends is disputed On June 13, 2003, we filed a demand for arbitration with the and is the subject of the arbitration proceeding with Mr. Wittig and American Arbitration Association asserting claims against Mr. Wittig Mr. Lake discussed above in Note 17,"Legal Proceedings."We recorded an approximate $0.6 million increase in the balance of our and Mr. Lake arising out of their previous employment with us.

potential liability to Mr. Wittig and Mr. Lake in the third quarter to Among other things, we are seeking to recover compensation and reflect the difference between the carrying value of the 4,714 shares benefits previously paid to Mr. Wittig and Mr. Lake and to avoid claimed by Mr. Wittig and Mr. Lake and the redemption amount.

compensation and other benefits Mr. Wittig and Mr. Lake claim to be owed to them as a result of their previous employment with us.

We are unable to predict the outcome of the arbitration. 22. MARKETABLE SECURITIES At December 31, 2004, we had accrued liabilities totaling approxi- On January 1, 2003, we classified our investment in ONEOK as an mately $57.8 million for compensation not yet paid to Mr. Wittig available-for-sale security. During 2003, we sold our investment in and Mr. Lake under various plans.The compensation includes RSU ONEOK and recorded a pre-tax gain of $99.3 million.The following awards, deferred vested shares, deferred RSU awards, deferred table summarizes our marketable security sales for the years ended vested stock for compensation, executive salary continuation plan December 31, 2004, 2003 and 2002.

benefits and, in the case of Mr. Wittig, benefits arising from a split 2004 2003 2002 dollar life insurance agreement. The amount of our obligation to (InThousands)

Mr. Wittig related to a split dollar life insurance agreement is Marketable Security Sales subject to adjustment at the end of each quarter based on the total Sales proceeds ..................... $ - $801,841 $ -

return to our shareholders from the date of that agreement. The Realized gains .....................- 99,327 total return considers the change in stock price and accumulated dividends. These compensation-related accruals are included in long-term liabilities on the consolidated balance sheets with a 23. LEASES portion recorded as a component of paid in capital. The amount Operating Leases accrued will increase annually as it relates to future dividends on deferred RSU awards and increases in amounts that may be due We lease office buildings, computer equipment, vehicles, railcars under the executive salary continuation plan. and other property and equipment with various terms and expiration dates ranging from I to 15 years. We have the right at the In addition, we accrued $4.2 million at December 31,2004 for legal expiration of the basic lease terms to renew several leases, fees and expenses incurred by Mr. Wittig and Mr. Lake that are including the LaCygne 2 lease, static var equipment lease, and recorded in accounts payable on our consolidated balance sheets. several railcar leases. We also have the right to purchase the 63 We will likely incur substantial additional expenses for legal fees equipment or assets at the expiration of the basic lease term or any and expenses incurred by Mr. Wittig and Mr. Lake related to the renewal term at a price equal to the fair market value of the arbitration proceeding discussed above, the defense of the criminal equipment if certain notification requirements are met.

2 004 ANN UAL REPO RT In determining lease expense, we recognize the effects of scheduled Capital lease payments are currently treated as operating leases for rent increases on a straight-line basis over the minimum lease rate making purposes. Minimum annual rental payments, excluding term. The rental expense associated with the LaCygne 2 operating administrative costs such as property taxes, insurance and mainte-lease includes an offset for the amortization of the deferred gain on nance, under capital leases at December 31, 2004 are listed below.

the sale-leaseback. The rental expense and estimated commitments Total Capital are as follows for the LaCygne 2 lease and other operating leases. YearEndedDecember 31, Leases Total (in Thousands)

LaCygne 2 Operating 2005 ......................................................

Year EndedDecember31, Lease(-) Leases S5,267 2006 ...................................................... 4,545 (inThousands) 2007 ...................................................... 4,024 Rental expense:

2008 ...................................................... 3,284 2002 ................................... $

S28,895 S 46,312 2009 ...................................................... 2,619 2003 ................................... 28,895 42,495 Thereafter ................................................... 4,462 2004 ................................... 28,895 38,793 Future commitments: 24,201 2005 ...................................... S38,013 $ 49,422 Amounts representing imputed interest ............................. (4,135) 2006 ..................................... 42,287 53,239 Present value of net minimum lease payments under capital leases ....... S20,066 2007 ...................................... 78,268 86,802 2008 ...................................... 12,609 20,343 2009 ...................................... 42,287 48,802 24. RELATED PARTY TRANSACTIONS - ONEOK Shared Thereafter .................................. 289,154 355,290 Services Agreement Total future commitments .......... ........... $502,618 S613,898 We and ONEOK had shared services agreements in which we

) The LaCygne 2 leaseamounts are included in the total operating leases column. provided and billed one another for facilities, utility field work, mobile communications, information technology, customer support, In 1987, KGE sold and leased back its 50% undivided interest in meter reading and bill processing. Payments for these services were the LaCygne 2 generating unit. The LaCygne 2 lease has an initial based on various hourly charges, negotiated fees and out-of-term of 29 years, with various options to renew the lease or pocket expenses.

repurchase the 50% undivided interest. KGE remains responsible 2004 2003 2002 for its share of operating and maintenance costs and other related (InThousands) operating costs of LaCygne 2. The lease is an operating lease for ChargestoONEOK .................... $7,213 S8,312 S8,357 financial reporting purposes. We recognized a gain on the sale, which was deferred and is being amortized over the lease term.The Charges from ONEOK ............ ...... 2,735 3,190 3,324 increase in payments in 2006 and 2007 represents a change in accordance with the terms of the lease from the lease payments ONEOK terminated portions of this shared services agreement in being made in arrears to the lease payments being made in September 2004, including electric service orders, call center advance and are included on a straight-line basis over the minimum functions, bill processing and remittance processing. In addition to lease term when determining lease expense. joint meter reading, we plan to continue to share some facilities and a mobile communications system.

Capital Leases Capital leases are identified based on the requirements set forth in 25. WORK FORCE REDUCTIONS - 2002 Voluntary Separation SFAS No. 13, "Accounting for Leases." For both vehicles and computer equipment, new leases are signed each month based on During 2002, we reduced our utility work force by approximately the terms of the master lease agreement. The lease term for 400 employees through a voluntary separation program. We have vehicles is from 5 to 14 years depending on the type of vehicle. The replaced and may continue to replace some of these employees.

computer equipment has either a 2- or 3-year term. Assets Below is a schedule of severance payments incurred related to this recorded under capital leases are listed below. workforce reduction.

December 31, 2004 2003 YearEndedDecember 31, 2002 (InThousands) (InThousands)

Vehicles...................................... $3.

S35,769 $40,018 Balance at January 1 ............. ............................. $ -

Computer equipment and software ......... ......... 2,145 1,118 Additions .19,496 Accumulated amortization ......................... (17,848) (18,543) Payments .(19,496)

$20,066 $22,593 Balance at December 31. S-Any work force reductions since the completion of the 2002 voluntary separation have been in the normal course of operations.

64 III

2 004 ANN UAL REPO RT

26. QUARTERLY RESULTS (UNAUDITED) First Second Third Fourth Our electric business is seasonal in nature and, in our opinion, (InThousands, Except PerShare Amounts) comparisons between the quarters of a year do not give a true 2003 Sales ................. $345,434 S345,885 $438,167 $331,657 indication of overall trends and changes in operations. In addition, Income from continuing our net results of discontinued operations varied between compar- operations ............. 20,102 21,807 80,584 40,422 able quarters. In the first quarter of 2003, we classified our Results of discontinued monitored security business as discontinued operations requiring operations, netof tax ..... 103,822 6,378 (161,651) (26,454) the recognition of certain tax benefits resulting in net income from Net income (loss) .......... 123,924 28,185 (81,067) 13,968 discontinued operations of $103.8 million. In the third quarter of Earnings (loss) available 2003, we wrote down our monitored security business to our forcommon stock ..... $123,697 $ 27,943 $ (81,283) $ 13,686 estimate of realizable value resulting in a net loss of $161.7 million. Per Share Data (a):

In the fourth quarter of 2004, we recognized income from discon- Basic:

tinued operations of $71.9 million, which reflects the results of the Earnings available from continuing operations .... 0.28 $ 0.30 S 1.11 $ 0.56 final settlement of all issues related to the sale of our monitored Discontinued operations, security business. net of tax .1.44 0.09 (2.23) (0.37)

First Second Third Fourth Earnings(loss)available .. . $ 1.72 $ 0.39 $ (1.12) $ 0.19 (InThousands, Except PerShare Amounts)

Diluted:

2004 Earnings available from Sales ................. $340,263 $358,430 $ 421,489 $344,307 continuing operations .... 0.27 S 0.30 $ 1.09 $ 0.54 Income from continuing Discontinued operations, operations ............. 8,791 13,979 60,369 16,941 net of tax . ....... 1.44 0.08 (2.20) (0.35)

Results of discontinued operations, net of tax ..... 6,888 - - 71,902 Earnings (loss) available ... 1.71 S 0.38 $ (1.11) S 0.19 Net income .............. 15,679 13,979 60,369 88,843 Cash dividend declared Earnings available for per common share ....... 0.19 $ 0.19 $ 0.19 $ 0.19 common stock .......... $ 15,437 S 13,737 $ 60,127 $ 88,599 Market price per Per Share Dataa': common share:

Basic: High ................ S 13.04 S 17.09 $ 18.65 $ 20.49 Earnings available from Low ................ $ 9.76 S 12.15 $ 15.45 $ 18.40 continuing operations $.... 0.12 $ 0.16 $ 0.70 S 0.19 r')Earnings (loss) per share is computed independently for each of the periods Discontinued operations, presented. The sum of the earnings (loss) per shareamountsfor the quartersmay net of tax .0.09 - - 0.84 not equal the totalfor the year.

Earnings available ....... $ 0.21 $ 0.16 $ 0.70 $ 1.03 Diluted:

Earnings available from 27. SUBSEQUENT EVENT - ICE STORM continuing operations .... S 0.12 $ 0.16 $ 0.69 $ 0.19 Discontinued operations, On January 4 and 5, 2005, substantially all of our service territory net of tax .0.09 - - 0.83 experienced a severe ice storm. The storm interrupted electric Earningsavailable ....... $ 0.21 $ 0.16 $ 0.69 $ 1.02 service in a large portion of our service territory and damaged a significant portion of our electric distribution system. We estimate Cash dividend declared that we will incur $38.0 million to $42.0 million of system restoration per common share ....... $ 0.19 S 0.19 S 0.19 $ 0.23 costs. Of this amount, we expect $6.0 million to $8.0 million to be Market price per common share:

accounted for as capital expenditures and we expect the balance High ................ S 21.00 $ 21.47 $ 21.11 $ 22.92 related to maintenance expenditures to be accounted for as a Low ................ S 18.06 $ 18.24 S 19.58 $ 20.05 regulatory asset. On February 3, 2005, we filed an application for an accounting authority order with the KCC requesting that we be (Earnings (loss) per share is computed independently for each of the periods presented. The sum of the earnings (loss) per shareamountsfor the quartersmay allowed to accumulate and defer for future recovery maintenance not equal the totalforthe year. costs related to system restoration. We can provide no assurance that the KCC will approve our application, however, in the past the KCC has approved similar requests.

65

2 004 ANN UAL REPO RT ITEM 9. CHANGES IN AND DISAGREEMENTS WITH PART III ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT None.

The information concerning directors required by Item 401 of Regulation S-K will be included under the caption"Election of ITEM 9A. CONTROLS AND PROCEDURES Directors" in our definitive Proxy Statement for our 2005 Annual Under the supervision and with the participation of our manage- Meeting of Shareholders to be filed pursuant to Regulation 14A ment, including our chief executive officer and our chief financial (the 2005 Proxy Statement), and that infonmation is incorporated officer, we have evaluated the effectiveness of the design and by reference in this Form 10-K. Information concerning executive operation of our disclosure controls and procedures as defined in officers required by Item 401 of Regulation S-K is located under Rule 13a-15(e) of the Securities Exchange Act of 1934. These Part I, Item 1 of this Form 10-K. The information required by Item controls and procedures are designed to ensure that material 405 of Regulation S-K concerning compliance with Section 16(a) information relating to the company and its subsidiaries is of the Exchange Act will be included under the caption "Section communicated to the chief executive officer and the chief financial 16(a) Beneficial Ownership Reporting Compliance" in our 2005 officer. Based on that evaluation, our chief executive officer and our Proxy Statement, and that information is incorporated by reference chief financial officer concluded that, at December 31, 2004, our in this Form 10-K. The information required by Item 406 of disclosure controls and procedures are effective to ensure that Regulation S-K will be included under the caption "Corporate information required to be disclosed by us in reports that we file or Governance Matters" in our 2005 Proxy Statement, and that submit under the Securities Exchange Act of 1934 is recorded, information is incorporated by reference in this Form 10-K.

processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. ITEM 11. EXECUTIVE COMPENSATION There were no changes in our internal control over financial The information required by Item 11 will be set forth in our 2005 reporting during the fourth quarter ended December 31, 2004, that Proxy Statement under the captions"Compensation of Directors,"

have materially affected, or are reasonably likely to materially "Compensation of Executive Officers"and"Employment Contracts,"

affect, our internal control over financial reporting. and that information is incorporated by reference in this Form 10-K.

See Item 8. Financial Statements and Supplementary Data for Management's Annual Report On Internal Control Over Financial ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Reporting and the Independent Registered Public Accounting Firm's report with respect to management's assessment of the The information required by Item 12 will be set forth in our 2005 effectiveness of internal control over financial reporting. Proxy Statement under the captions"Beneficial Ownership of Voting Securities" and "Equity Compensation Plan Information,"

ITEM 9B. OTHER INFORMATION and that information is incorporated by reference in this Form 10-K.

None.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Not applicable.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information required by Item 14 will be set forth in our 2005 Proxy Statement under the captions "Audit Fees" and "Audit Committee Pre-Approval Policies and Procedures," and that information is incorporated by reference in this Form 10-K.

66

2 004 ANN UAL REPO RT PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES FINANCIAL STATEMENTS INCLUDED HEREIN Westar Energy, Inc.

Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets, as of December 31, 2004 and 2003 Consolidated Statements of Income (Loss) for the years ended December 31, 2004, 2003 and 2002 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2004, 2003 and 2002 Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002 Consolidated Statements of Shareholders'Equity for the years ended December 31, 2004, 2003 and 2002 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: 1,III, IV,andV EXHIBIT INDEX All exhibits marked'I'are incorporated herein by reference.AIl 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. All exhibits marked"#"are filed with this Form 10-K.

Description 1(a) - Underwriting Agreement between Westar Energy, Inc., and Citigroup Global Markets Inc. and Lehman I Brothers Inc., as representatives of the several underwriters, dated January 12, 2005 (filed as Exhibit 1.1 to the January 18,2005 Form 8-K) 3(a) - By-laws of Westar Energy, Inc., as amended April 28, 2004 (filed as Exhibit 3(a) to June 30, 2004 Form 10-Q) 3(b) - Restated Articles of Incorporation of Westar Energy, Inc., as amended through May 25,1988 (filed as Exhibit 4 to Registration Statement, SEC File No. 33-23022) 3(c) - Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated March 29, 1991 3(d) - Certificate of Designations for Preference Stock, 8.5% Series, without par value, dated March 31, 1991 (filed as Exhibit 3(d) to December 1993 Form 10-K) 3(e) - Certificate of Correction to Restated Articles of Incorporation of Westar Energy, Inc. dated December 20,1991 (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, 1992, (filed as Exhibit 3(e) to December 1993 Form 10-K) 3(g) - Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated May 8, 1992 (filed as Exhibit 3(c) to December 31, 1994 Form 10-K) 3(h) - Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated May 26, 1994 (filed as Exhibit 3 to June 1994 Form 10-Q) 3(i) - Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated May 14, 1996 (filed as Exhibit 3(a) to June 1996 Form 10-Q)

30) - Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated May 12, 1998 (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 November 17,2000 Form 8-K) 3(1) - Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated July 21, 1999 (filed as Exhibit 3(1) to the December 31, 2002 Form 10-K) 67

2004 ANNUAL REPORT 3(m) - Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. dated June 19,2002 1 (filed as Exhibit 3(m) to the December 31,2002 Form 10-K) 4(a) - Mortgage and Deed of Trust dated July 1, 1939 between Westar Energy, Inc. and Harris Trust and Savings Bank, I Trustee (filed as Exhibit 4(a) to Registration Statement No.33-21739) 4(b) - First and Second Supplemental Indentures dated July 1, 1939 and April 1, 1949, respectively I (filed as Exhibit 4(b) to Registration Statement No.33-21739) 4 (c) - Sixth Supplemental Indenture dated October 4,1951 (filed as Exhibit 4(b) to Registration Statement I No.33-21739) 4(d) - Fourteenth Supplemental Indenture dated May 1, 1976 (filed as Exhibit 4(b) to Registration Statement I No.33-21739) 4(e) - Twenty-Eighth Supplemental Indenture dated July 1, 1992 (filed as Exhibit 4(o) to the December 1992 I Form 10-K) 4(f) - Twenty-Ninth Supplemental Indenture dated August 20, 1992 (filed as Exhibit 4(p) to the December 1992 Form 10-K) 4(g) - Thirtieth Supplemental Indenture dated February 1, 1993 (filed as Exhibit 4(q) to the December 1992 1 Form 10-K) 4(h) - Thirty-First Supplemental Indenture dated April 15, 1993 (filed as Exhibit 4(r) to Registration Statement I No.33-50069) 4(i) - Thirty-Second Supplemental Indenture dated April 15, 1994 (filed as Exhibit 4(s) to the December 31,1994 I Form 10-K) 4(j) - Thirty-Fourth Supplemental Indenture dated June 28, 2000 (filed as Exhibit 4(v) to the December 31, 2000 I Form 10-K) 4(k) - Thirty-Fifth Supplemental Indenture dated May 10, 2002 between Westar Energy, Inc. and BNY Midwest I Trust Company, asTrustee (filed as Exhibit 4.1 to the March 31, 2002 Form 10-Q)

40) - Thirty-Sixth Supplemental Indenture dated as of June 1, 2004, between Westar Energy, Inc. and BNY Midwest I Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.1 to the January 18, 2005 Form 8-K) 4(m) - Thirty-Seventh Supplemental Indenture, dated as of June 17, 2004, between Westar Energy, Inc. and BNY I Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.2 to the January 18, 2005 Form 8-K) 4(n) - Thirty-Eighth Supplemental Indenture, dated as of January 18, 2005, between Westar Energy, Inc. and BNY I MidwestTrust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.3 to the January 18,2005 Form 8-K) 4(o) - Forty-First Supplemental Indenture dated June 6, 2002 between Kansas Gas and Electric Company and BNY I MidwestTrust Company, as Trustee (filed as Exhibit 4.1 to the June 30,2002 Form 10-Q) 4(p) - Forty-Second Supplemental Indenture dated March 12,2004 between Kansas Gas and Electric Company and #

BNY MidwestTrust Company, as Trustee 4(q) - Debt Securities Indenture datedAugust 1, 1998 (filed as Exhibit 4.1 to theJune 30, 1998 Form 10-Q) I 4(r) - Securities Resolution No.2 dated as of May 10, 2002 under Indenture dated as of August 1, 1998 between I Western Resources, Inc. and Deutsche Bank Trust Company Americas (filed as Exhibit 4.2 to the March 31, 2002 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 EmploymentAgreements with Messers. Lake and Wittig (filed as Exhibit 10(b) to the I December 31, 2000 Form 10-K)

• 10(c) -A RailTransportation Agreement among Burlington Northern Railroad Company, the Union Pacific Railroad I 68 Company and Westar Energy, Inc. (filed as Exhibit 10 to the June 1994 Form 10-Q) 10(d) -Agreement between Westar Energy Inc. 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 Westar Energy Inc. and Williams Natural Gas Company dated October 1, 1993 I (filed as Exhibit 10(b) to the December 31, 1993 Form 10-K)

2004 ANNUAL REPORT 10(f) - Short-term Incentive Plan (filed as Exhibit 10(k) to the December 31, 1993 Form 10-K)* I 10(g) - Westar Energy, Inc. Non-Employee Director Deferred Compensation Plan, as amended and restated, I dated as of October 20,2004 (filed as Exhibit 10(1) to the October 20,2004 Form 8-K)*

10(h) - Executive Salary Continuation Plan of Western Resources, Inc., as revised, effective September 22,1995 I (filed as Exhibit 100) to the December 31,1995 Form 10-oK*

10(i) - LetterAgreement between Westar Energy, Inc. and David C. Wittig, dated April 27,1995 (filed as I Exhibit 10(m) to the December 31,1995 Form 10-K)*

10(j) - Form of Split Dollar Insurance Agreement (filed as Exhibit 10.3 to the June 30,1998 Form 10-Q)

• I 10(k) - Amendment to Letter Agreement between Westar Energy, Inc. and David C. Wittig dated April 27,1995 I (filed as Exhibit 10 to the June 30,1998 Form 10-Q/A)

• 10(1) - Letter Agreement between Westar Energy, Inc. and Douglas T. Lake, dated August 17, 1998 (filed as I Exhibit 10(n) to the December 31,1999 Form 10-K)*

10(m) - Form of Change of Control Agreement with officers of Westar Energy, Inc. (filed as Exhibit 10(o) to the I December 31, 2000 Form 10-K)*

10(n) - Form of loan agreement with officers of Westar Energy, Inc. (filed as Exhibit 10(r) to the December 31, 2001 I Form 10-K)*

10(o) - Amendment to Employment Agreement dated April 1, 2002 between Westar Energy, Inc. and David C. Wittig I (filed as Exhibit 10.1 to the June 30,2002 Form 10-Q)*

10(p) - Amendment to Employment Agreement dated April 1, 2002 between Westar Energy and Douglas T. Lake I (filed as Exhibit 10.2 to the June 30,2002 Form 10-Q)*

10(q) - Credit Agreement dated as of June 6,2002 amongWestar Energy, Inc., the lenders from time to time party I there to, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A., as Syndication Agent, and Bank of America, NA., as Documentation Agent (filed as Exhibit 10.3 to the June 30, 2002 Form 10-Q) 10(r) - Employment Agreement dated September 23,2002 between Westar Energy, Inc. and David C. Wittig I (filed as Exhibit 10.1 to the September 30,2002 Form 10-Q)*

10(s) - Employment Agreement dated September 23,2002 between Westar Energy, Inc. and Douglas T. Lake I (filed as Exhibit 10.1 to the November 25,2002 Form 8-K)*

10(t) - Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and James S. Haines, Jr. (filed as I Exhibit 10(a) to the September 30,2003 Form 10-Q)*

10(u) - LetterAgreement dated November 1,2003 between Westar Energy, Inc. and William B.Moore (filed as I Exhibit 10(b) to the September 30,2003 Form 10-Q)*

10(v) - Letter Agreement dated November 1,2003 between Westar Energy, Inc. and Mark A. Ruelle (filed as I Exhibit 10(c) to the September 30, 2003 Form 10-Q)*

10(w) - Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and Douglas R. Sterbenz (filed as I Exhibit 10(d) to the September 30,2003 Form 10-Q)*

10(x) - Letter Agreement dated November 1, 2003 between Westar Energy, Inc. and Larry D. Irick (filed as I Exhibit 10(e) to the September 30,2003 Form 10-Q)*

10(y) - Waiver and Amendment, dated as of November 6, 2003, to the Credit Agreement, dated as of June 6, 2002, I among Westar Energy, Inc., the Lenders from time to time party thereto, JPMorgan Chase Bank, as Administrative Agent for the Lenders, Citibank, N.A., as Syndication Agent, and Bank of America, N.A.,

as Documentation Agent (filed as Exhibit 10(f) to the September 30, 2003 Form 10-Q) 10(z) - CreditAgreement dated as of March 12,2004 amongWestar Energy, Inc., the several banks and other I financial institutions or entities from time to time parties to the Agreement, JPMorgan Chase Bank, as administrative agent,The Bank of NewYork, as syndication agent, and Citibank, N.A., Union Bank of California, N.A., and Wachovia Bank, National Association, as documentation agents (filed as Exhibit 10(a) to the March 31,2004 Form 10-Q) 10(aa) - Supplements and modifications to Credit Agreement dated as of March 12,2004 among Westar Energy, Inc., I as Borrower, the Several Lenders PartyThereto, JPMorgan Chase Bank, as Administrative Agent, The Bank of NewYork, as Syndication Agent, and Citibank, N.A., Union Bank of California, N.A., and Wachovia Bank, 69 national Association, as Documentation Agents (filed as Exhibit 10(a) to the June 30,2004 Form 10-Q) 10(ab) - Purchase Agreement dated as of December 23,2003 between POI Acquisition, L.L.C., Westar Industries, Inc. I and Westar Energy, Inc. (filed as Exhibit 99.2 to the December 24, 2003 Form 8-K)

2 004 ANN UAL REPO RT 10(ac) - Settlement Agreement dated November 12, 2004 by and among Westar Energy, Inc., Protection One, Inc., I POI Acquisition, L.L.C., and POI Acquisition I, Inc. (filed as Exhibit 10.1 to the November 15, 2004 Form 8-K) 10(ad) - Restricted Share Unit Award Agreement between Westar Energy, Inc. and James S. Haines, Jr. (filed as I Exhibit 10.1 to the December 7,2004 Form 8-K) 10(ae) - Deferral Election Form of James S.Haines, Jr. (filed as Exhibit 10.2 to the December 7,2004 Form 8-K) I 10(af) - Resolutions of the Westar Energy, Inc. Board of Directors regarding Non-Employee Director Compensation, I approved on September 2, 2004 (filed as Exhibit 10.2 to the December 7, 2004 Form 8-K) 10(ag) - Restricted Share Unit Award Agreement between W'estar Energy, Inc. and William B.Moore (filed as I Exhibit 10.1 to the December 29, 2004 Form 8-K) 10(ah) - Deferral Election Form of William B.Moore (filed as Exhibit 10.2 to the December 29,2004 Form 8-K) I 12 - Computations of Ratio of Consolidated Earnings to Fixed Charges 21 - Subsidiaries of the Registrant 23 - Consent of Independent Registered PublicAccounting Firm, Deloitte &Touche LLP 31 (a) - Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31(b) - Certification of PrincipalAccounting Officer pursuant to Section 302 of the Sarbanes-OxleyAct of 2002 #

32 - Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished and not to be considered #

filed as part of the Form 10-K) 99(a) - Kansas Corporation Commission Order dated November 8,2002 (filed as Exhibit 99.2 to the I September 30, 2002 Form 10-Q) 99(b) - Kansas Corporation Commission Order dated December 23, 2002 (filed as Exhibit 99.1 to the I December 27,2002 Form 8-K) 99(c) - Debt Reduction and Restructuring Plan filed with the Kansas Corporation Commission on February 6,2003 I (filed as Exhibit 99.1 to the February 6, 2003 Form 8-K) 99(d) - Kansas Corporation Commission Order dated February 10, 2003 (filed as Exhibit 99.1 to the February 11, 2003 I Form 8-K) 99(e) - Kansas Corporation Commission Order dated March 11, 2003 (filed as Exhibit 99(f to the December 31, 2002 I Form 10-K) 99(0 - Demand for Arbitration (filed as Exhibit 99.1 to the June 13, 2003 Form 8-K) I 99(g) - Stipulation and Agreement filed with the Kansas Corporation Commission on July 21,2003 (filed as I Exhibit 99.1 to the July 22,2003 Form 8-K)

WESTAR ENERGY, INC.

SCHEDULE 11- VALUATION AND QUALIFYING ACCOUNTS Balance at Charged to Balance Beginning Costs and at End Description of Period Expenses Deductions of Period (InThousands)

Year ended December 31, 2002 Allowancesdeductedfromassetsfordoubtfulaccounts(a ..................................... $6,825 $6,266 S(6,473) $6,618 Accrued exit fees, shut-down and severance costs(b) ................. ........................ 43 (43) --

Year ended December 31, 2003 Allowancesdeductedfromassetsfordoubtfulaccounts( ..................................... 6,618 3,874 (5,077) 5,415 Accrued exit fees, shut-down and severance costs... .- -

Year ended December 31, 2004 Allowances deducted from assets for doubtful accounts .............. ........................ 5,415 2,718 (2,820) 5,313 Accrued exit fees, shut-down and severance costs ......

("Deductions arc the resultoftrite-offs of accounts receivable.

an Deductions are the resultofpayment of accruedseverance costs.

70 1II

2004 ANNUAL REPORT 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.

WESTAR ENERGY, INC.

Date: March 16,2005 By: Is/ MARK A. RUELLE Mark A. Ruelle, ExecutiveVice President and Chief Financial Officer 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 Isl JAMES S. HAINES, JR. Director, Chief Executive Officer and President March 16, 2005 Games S. Haines, Jr.) (Principal Executive Officer)

/sl MARK A. RUELLE ExecutiveVice President and Chief Financial Officer March 16, 2005 (Mark A. Ruelle) (Principal Financial and Accounting Officer)

/s/ CHARLES Q. CHANDLER IV Chairman of the Board March 16, 2005 (Charles Q. Chandler IV)

/s! MOLLIE HALE CARTER Director March 16, 2005 (Mollie Hale Carter)

Is! R.A. EDWARDS III Director March 16,2005 (R.A. Edwards IIIl Is! JERRY B.FARLEY Director March 16, 2005 Gerry B.Farley)

Is/ B. ANTHONY ISAAC Director March 16, 2005 (B.Anthony Isaac)

Isl ARTHUR B. KRAUSE Director March 16,2005 (Arthur B.Krause)

Isl SANDRA A. J. LAWRENCE Director March 16,2005 (Sandra A. J. Lawrence)

Isl MICHAEL F.MORRISSEY Director March 16, 2005 (Michael F.Morrissey) is! JOHN C. NETIELS, JR. Director March 16, 2005 Gohn C. Nettels, Jr.)

71

2 004 ANN UAL REPO RT SHAREHOLDER INFORMATION & ASSISTANCE Westar Energy's Shareholder Services CONTACTING SHAREHOLDER SERVICES TRUSTEE FOR FIRST MORTGAGE BONDS department offers personalized service TELEPHONE PRINCIPAL TRUSTEE, PAYING AGENT to the company's individual shareholders. Toll-free: (800) 527-2495 AND REGISTRAR We are the transfer agent for Westar In the Topeka area: (785) 575-6394 Energy common and preferred stock. The Bank of NewYork Fax: (785) 575-1796 2 North LaSalle Street, Suite 1020 Shareholder Services provides informa-tion and assistance to shareholders ADDRESS Chicago, IL 60602-3802 regarding: Westar Energy, Inc. (800) 548-5075 Dividend payments Shareholder Services P.O. Box 750320 CORPORATE INFORMATION

> Historically paid on the first Topeka, KS 66675-0320 CORrORATE ADDRESS business day of January, April, July and October E-MAIL ADDRESS Westar Energy, Inc.

. Direct deposit of dividends sharsvcs@wr.com 818 South Kansas Avenue Topeka, KS 66612-1203

• Transfer of shares Please include a daytime telephone (785) 575-6300

• Lost stock certificates assistance number in all correspondence. wwW.wr.com

• Direct Stock Purchase Plan assistance CO-TRANSFER AGENT COMMON STOCK LISTING

> Dividend reinvestment Continental Stock Transfer Ticker Symbol (NYSE): WR

> Purchase additional shares by

&Trust Company Daily Stock Table Listing:

making optional cash payments 17 Battery Place, 8th Floor by check or monthly electronic WestarEngy NewYork, NY 10004 withdrawal from your bank account CHIEF EXECUTIVE OFFICER AND CHIEF

> Deposit your stock certificates into CONTACTING INVESTOR RELATIONS FINANCIAL OFFICER CERTIFICATIONS the plan for safekeeping TELEPHONE: (785) 575-1898 In 2004, our chief executive officer Sell shares submitted a certificate to the New ADDRESS York Stock Exchange (NYSE) affirming Please contact us in writing to request Westar Energy, Inc.

elimination of duplicate mailings because that he is not aware of any violation by Investor Relations the company of the NYSE's corporate of stock registered in more than one P.O. Box 889 way. Mailing of annual reports can be governance listing standards. Our Topeka, KS 66601-0889 chief executive officer's and chief eliminated by marking your proxy card to consent to accessing reports electroni- financial officer's certifications pursuant E-MAIL ADDRESS: investrel@wr.com cally on the Internet. to Section 302 of the Sarbanes-Oxley Copies our Annual Report on Form 10-K Act of 2002 for the year ended Please visit our Web site at www.wr.com. that was filed with the Securities and December 31, 2004 were included as Registered shareholders can easily access Exchange Commission and other pub- exhibits to Westar Energy, Inc.'s Annual their shareholder account information lished reports can be obtained without Report on Form 10-K for the year online by going to Investor Relations charge by contacting Investor Relations ended December 31 that was filed and clicking on My Shareholder at the above address, by accessing the with the Securities and Exchange Account. company's home page on the Internet Commission.

at www.wr.com or by accessing the Securities and Exchange Commission's Internet Web site at www.sec.gov.

72 T

Thisreport was printed on recycledpaper using soy-based inks.

III

2004 ANNUAL REPORT DIRECTORS OFFICERS JAMES S. HAINES, JR. (58) 18 years of service President and Chief Executive Officer WILLIAM B.MOORE (52) 24 years of service ExecutiveVice President and Chief Operating Officer MARK A. RUELLE (43) 12 years of service Executive Vice President and Chief Financial Officer DOUGLAS R. STERBENZ (41) 7 years of service SeniorVice President, Generation and Marketing BRUCE A. AKIN (40) 17 years of service Vice President, Administrative WestarEnergy Board of Directors, from left, is composed of SandraAJ. Lawrence, Jerry B. Fadey CharlesQ. Chandler IV Services B. Anthony Isaac, Mollie H. Carter John C Nettels Jr., James S. Haines Jr., R.A. Edwards, Michael E Morrissey andArthur B. Krause.

GREG A. GREENWOOD (39) 11 years of service CHARLES Q. CHANDLER IV (51) JERRY B. FARLEY (58) SANDRA A.J. LAWRENCE (47) Treasurer Chairman of the Board Directorsince 2004 Directorsince 2004 KELLY B.HARRISON (46)

Director since 1999 President SeniorVice President and 23 years of service Chairmansince 2002 Washburn University Treasurer Midwest Research Institute Vice President, Regulatory Chairman of the Board, Topeka, Kansas Chief Executive Officer Committees: Audit, Nominating Kansas City, Missouri DOUGLAS J. HENRY (52)

INTRUST Bank and CorporateGovernance Committees: Compensation, 26 years of service Wichita, Kansas Nominating and Corporate Vice President, Power Delivery JAMES S. HAINES, JR. (58) Governance MOLLIE H. CARTER (42) Director since 2002 LARRY D. IRICK (48)

Directorsince 2003 President and Chief MICHAEL F.MORRISSEY (62) 5 years ofservice President and Chief Executive Officer Directorsince 2003 Vice President, General Counsel Executive Officer Westar Energy, Inc. Managing Partner (Retired) and Corporate Secretary Sunflower Banks, Inc. Topeka, Kansas Ernst &Young LLP Salina, Kansas Naples, Florida PEGGY S. LOYD (47)

Committees: Compensation, B. ANTHONY ISAAC (51) 26 years of service Committees:Audit, Compensation Finance Director since 2003 Vice President, Corporate President JOHN C. NETTELS, JR. (48) Compliance and Internal Audit R.A. EDWARDS III (59) LodgeWorks, L.P Director since 2000 Directorsince 2001 Wichita, Kansas JAMES J. LUDWIG (46)

Partner President and Chief Committees: Compensation, Stinson Morrison Hecker LLP 14 years of service Executive Officer Finance Overland Park, Kansas Vice President, Public Affairs First National Bank ARTHUR B.KRAUSE (63) Committee: Nominating LEE WAGES (56) of Hutchinson and CorporateGovernance Hutchinson, Kansas Directorsince 2003 27 years of service ExecutiveVice President Vice President, Controller Committees: Audit, Nominating and Corporate Governance and Chief Financial Officer CAROLINE A. WILLIAMS (48)

(Retired) 29 years of service Sprint Corporation Vice President, Customer Care Naples, Florida 73 Committees: Audit, Finance Ages and years of service are as of December31, 2004.

Foflowing the January 2005 ice storm, Westar Energy invited employees to submit photos they took showing the beauty and destruction of the storm and our employees working to restore power. of the nearly 200 photos submitted, three were chosen for publication.

At left: Jim Wishart. director, work force coordination, took this photo in front of the Westar Energy System Control building on January 5. Below- Brad Kesl. electric distribution supervisor, took this photo of Bernie Braun, agent, as he works to restore power to customers southeast of Marion. Kesa also photographed Salina lncrews through icy branches as they drove to work on restoration of power to

.. -~customers near Marion.

Westar Energy braves ice, cold to restore power An ice storm covered much of Westar Energy's service territory January 4, knocking out power to more than 260,000 customers. Ice accumulation caused many of them to lose power multiple times. In the hardest hit areas, some 4 4-customers werewthout power for 10 days. Westar Energy enlisted the help of utilities and contractors from 17 states to assist with recovery efforts.

Faced with the worst ice storm in the company's history, storm managers divided Wichita and south-central Kansas into work zones. Tree trimming crews deared branches from power lines enabling restoration. Utility crews gathered at staging areas awaiting assignments as daylight appeared. With work orders and boxed -

lunches in hand, they canvassed areas going from home to home restoring service until night fell.

Truly tested, Westar Energy employees and customers showed their ability to face adversity and get the job done.

Wes-ta'r Energy.

P.O. Box 889, Topeka, Kansas 66601-0889 xwww.wr.com 1III

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I Selected Financial Data4 2004(B. 2003'B) 2002(') 2001 2000 (dollars In millions except per share amounts)

GREAT PLAINS ENERGY )

Operating revenues $ 2,464 - - $ 2,148 $ 1,802 $ 1,399 $ 1,086

$ 174 , '$ -$ 190 $ 137 $ (28) $ 53 Income (loss) from continuing operationsn Net income (loss) $ 181 $ 145 $ 126 $ (24)- $ 159 Basic and diluted earnings (loss) per common share (0.49) $ 08

.92.72 $ 2.16 $

from continuing operations p$tos $ 2.39 Basic and diluted earnings (loss) per common share $ 2.49 207 2$ 199 1$ - $ (0.42) $ 2.54 Total assets at year-end $ 3,799 $ 3,682 $ 3,517 $ 3,464 $ 3,309 Total redeemable preferred stock, mandatorily - -

redeemable securities and long-term debt (including current maturities) $ 1,296 t $ 1,347 $ 1,332 $ 1,342 $ 1,286 Cash dividends per common share $ 1.66 E - $ 1.66 . $ 1.66 $ 1.66 $ 1.66 CONSOLIDATED KCP&L(A-Operating revenues $ 1,092 $ 1 057 $ 1,013 $ 1,287 $ 1,086 Income from continuing operationsm $ 143 1 $ 126 $ 103 $ 116 $ 53 Netincome $ 143 $ 117 $ 96 $ 120 $ 159 Totalassetsatyear-end $ 3,337 $ 3,303 $ 3,139 $ 3,146 $ 3,309 Total redeemable preferred stock, mandatorily redeemable securities and long-term debt (includingcurrentmaturities) $ 1,126  ;, :$ 1,336 $ 1,313 $ 1,311 $ 1,286 financial statements include I Great Plains Energy's consolidated financial statements include consolidated KCPSL KLT Inc., GPP IEC and GPES. KCP8Ls consolidated October 1, 2001, formation prior to the its wholly owned subsidiary HSS. In addition, KCP&Ls consolidated results of operations Iiclude KLT Inc. and GPP for all periods be of the holding company, Great Plains Energy. - -:

tel See Management's Discussion and Analysis for explanations of 2004, 2003 and 2002 results.

IcJ This amount is before discontinued operations of $7.3, $(44.8), $(7.5), $4.3 and $75.6 million in 2004 through 2000.

respectively. In 2002, this amount is before the this amount is

$3.0 million cumulative effect of a change in accounting principle. For further information, see Notes to Consolidated Financial Statements. In 2000, before the $30.1 million cumulative effect of changes in pension accounting.

this amount is before the (DJThis amount is before discontinued operations of $(8.7), $(4.0), $3.6 and $75.6 million in 2003, 2002. 2001 and 2000, respectively. In 2002, effect of a change in accounting principle. For further information, see Notes to Consolidated Financial Statements. In 2000, this amount is

$3.0 million cumulative before the $30.1 million cumulative effect of changes in pension accounting.

TABLE OF CONTENTS:

Our Strategic Intent ............. 2 1 Letter to Shareholders ........... 6

- Kansas City Power & Light ...... 6

- Strategic Energy....... 9 Directors and Officers . 15 '

Shareholder Information ......

Financial Report ............

. 16 Insert 1 1:hh 2 0 0 4 A N N U A L R E PO R T 1

Iauoh thebmared cof our Strategic Intent, -afar-reaching 2004.:guide to theftuAre- This ambitious= plan embodies the aspirations as ira i .6 of off of our=X. customers, t;f R: -;g-C employees D and n0 communities-

-r IM s illuminating in In

.g a-path to reliable,

low-cost ernergy-fdr years to come. Great .Plains Energy:-

is demonstrati ng- leadership- h to make ,ithappen.

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lDependable, affordable energy is critical to everyone. So when Great Plains Energy d u- h' '6'Al asked our diverse stakeholders to brainstorm about the future, they offered lots of ideas.

This collaborative process led to the Strategic Intent shown on pages 3-5. Together, we created a substantive, achievable plan to guide the growth of Great Plains Energy, provide for future energy needs of our customers and deliver sustainable growth in earnings.

urlstatgI Intent 2 GR E A T P L A I N S E N E R G Y

GREAT PLAINS ENERGY Strateg ic InterNt:

• This intent is grounded in a solid foundation, thanks to strong operating performance and a competitive asset base, including:

- A fleet of regulated power plants, including coal plants that are top-tier in total production costs per megawatt hour

- A delivery system that provides industry-leading reliability and high customer service and satisfaction

- An industry leader in competitive supply

- Solid financial performance that includes increased shareholder value and strong dividends over the last three years

• We will position ourselves to benefit from a changing marketplace and technological innovation.

• Our strategy is to build on our core strengths across the company and add capabilities that benefit our customers, employees, investors, partners and the communities we serve.

2 0 0 4 A H N U A L R E P O R T 3

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• Executing extremelyfwell in each business r

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Achieving our strateglG:io and taking greater advantage of our strengths across the company

- Delivering operational leadership through intent - making it-2 I competitive cost structures, strong cus-tomer service, breadth of regulatory I D happen - will require. knowledge, world-class safety and practi-cal application of innovative technologies and processes a "winning culture' - Developing insights about our market-IDc places to improve our ability to serve all i, (9 - achieved by: . _'

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.i:" S of our customer segments

- Creating collaborative partnerships with customers, communities and regulators to achieve mutually beneficial results

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S. - S 4 G R E A T P L A I N S E N E R G Y

• Partnering with customers to create mutually -Enhancing our skills beneficial relationships that strengthen our bonds ' Broadening knowledge about all areas of our

- Using a consultative sales approach to meet ' -. ----4" PV5--j business - within and across regulated and customer needs non-regulated business segments

- Developing innovative electric service and I Bolstering sales and marketing capability energy solutions that help our customers maximize - Clarifying and investing in required leadership their own value and that of their own customers - skills and behaviors

- Providing responsive, superior customer service . *.Creating an engaged organization guided by strong Demonstrating environmental responsibility and > values, inspired leaders and shared accountability a commitment to community improvement  : -+ - Promoting the GPE IDEAL: Inspired leadership, Disciplined performance management, Engaged

- Making appropriate and timely investments to employees, Accountability and Loyalty.

ensure environmental compliance  :'..i-' .

e r n n--t i - Developing talented leaders who are inspired,

- Partnering with and strategically investing in -. passionate and committed communities in which we operate to improve . - Us quality of life in a meaningful way igadsilndpromnemngmn system to foster shared accountability, collaboration and increased personal growth and contribution "Now we are building on a shared vision to create the vibrant, innovative energy provider that our customers and other stakeholders need for the future."

- Mike Chesser Chairman and Chief Executive Officer 2 0 0 4 A N N U A L R E P O R T 5

Dear Fellow Shareholder 2004 was a landmark year for Great Plains Energy. We delivered on our promise of demonstrating operational excellence, while charting a comprehensive and compelling course for the future.

I'm proud of what we accomplished this year, and Kansas City Power & Light proud of how people at all levels of the company KCP&L delivered outstanding performance in2004, worked together and collaborated with our cus- producing higher earnings and cash flow while tomers and communities. providing top-tier service to our customers. This While our financial performance was strong, accomplishment ismore impressive in light of the I believe that 2004 will be remembered more for challenging weather conditions inour service area in our efforts to step back and develop a longer-term 2004, which included one of the coolest summers strategic intent. Our future success will be based on record and a higher-than-normal number of on implementation of this intent, which includes damaging storms.

building a cultural environment where our people Our generation feet achieved a record-breaking are inspired, accountable and engaged. year. Performance improvements led to record equivalent availability and capacity factors for the A Year of Strong Operating Performance total baseload generation Despite challenging conditions, 2004 was a record-setting year in both the utility and competitive supply businesses. Our success was driven fleet. Our latan, LaCygne 1, LaCygne 2 and Montrose "Our eyes are Generating Stations set by a variety of initiatives to improve operating effectiveness, as well as by our efforts to shape all-time megawatt gener- on the future ...

ation records, thanks to a Winning Culture within the organization.

employees' continued and we intend focus on operational excellence and proactive maintenance strategies.

to build value." ii With this level of increased output, reduced sum-mer retail demand and higher wholesale market prices, our Power Marketing group was able to produce record wholesale revenues of more than

$200 million, up 27% from 2003.

We also provided some of the most reliable service in the nation. In September, KCP&L earned I

the prestigious Reliability One award for the highest reliability performance in our region. The award committee noted that our excellent record is the result of years of wise decisions and consistent hard work and dedication on the part of our employees in Distribution and Transmission. 1 Bill Downey Mike Chesser President and Chief Chairman and Operating Officer Chief Executive Officer 6 GR E A T P L A I N S E N E RG Y 11'11

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Creating a winning culture: Engaged people, talented leaders commit to executing a shared vision Great Plains Energy is values, inspired leaders communities, developing our committed to creating and shared accountability. leaders' skills at all levels a winning culture - an We are charting new kinds and encouraging inclusive-engaged organization of partnerships, forging ness in our workforce.

empowered by strong collaborative ties in our 2 0 0 4 A N N U A L R E PO RT 7

Community commitment: business as usual in building our future at Great Plains Energy Getting involved, solving a and money where we do the environment and human problem, lending a helping business. We understand development. Our culture hand: The employees of that to earn recognition values personal commitment, Great Plains Energy demon- as a leader, our company above and beyond our 'day strate great enthusiasm for must be a catalyst for jobs." For us, investing in community commitment. positive change in issues the community is business We believe in investing time like energy affordability, as usual.

M .0i-M "i

_ WvM" 8 G R E A T P L A I N S E N E R G Y

GPE Operating Revenues KCP&L faced an unusually large number of storm-related outages in 2004, but through the "Generating goodwill efforts of our people and improved processes, we continued to decrease the time it takes to restore power to customers after major storm reinforces our role outages. Our Delivery group continues to innovate - completing more than 100 perform-as a trusted leader ance improvement initiatives in 2004 alone.

Technological innovations have also improved in energy delivery."

performance. We launched a program to install automated network protectors, for example, that 00 01 02 03 04 across all divisions. This emphasis helped lead to Year remotely notify us about malfunctions, saving our entire Generation Division achieving the lowest time and money by helping us detect problems total case incident rate in its history and the Delivery faster with less manpower.

Division reducing the severity of incidents by 50%.

Along with internal initiatives, we also helped form a consortium of mid-sized utilities during 2004 to Strategic Energy GPE Income (Loss) collaboratively seek additional performance improve- Strategic Energy, our competitive electricity supply from Continuing Operations ment and cost savings opportunities for the industry. business, continued to grow, and posted strong We are proud of our continued improvements revenues and earnings in 2004. This was 200 in Customer Service. In less than three years, achieved despite market conditions that were very service levels have improved dramatically, while III challenging for competitive supply firms in the 150 costs have decreased. The top-tier performance second half of 2004. Wholesale electricity prices delivered to our customers in 2004 earned KCP&L moved steadily h gher during most of the year 100 national recognition with the ServiceOneTm award. and, in several markets, were higher than the The award is based on an electric utility's perform- standard offer rates of the host utilities that provide ance in the Call Center, Billing, Meter Reading, the main alternative to competitive supp iers like 011J11 14 Field Service and Credit functions. Strategic Energy. While host utility rates will adjust 00 YLm 02 03 04 Safety is a cornerstone of operational excel- to wholesale prices over t me, the regulatory lag

• Year lence, and I'm pleased to report that our empha- in the process continues to provide a headwind sis on moving to world-class safety performance for competitive supply sales as we enter 2005.

produced solid results in 2004. We established a Consistent with our position as one of the new Corporate Safety Council during the year to leading national electricity retailers, Strategic Energy create greater levels of safety awareness by pro- is responding to these challenges by increasing our GPE Basic and Diluted moting widespread participation and consistently focus on satisfying customer needs and revamp-Earnings (Loss) per applying best practices to sustain cultural change ing key internal business processes. 11; Common Share from Continuing Operations 3.00 2.50 2.00 1.50 1.00

.50

.00I 00 02 03 I Year 2 0 0 4 A N N U A L R E PO R T 9

(,0

For example, Strategic Energy has introduced several contract options to satisfy different cus-tomers' desires such as: higher or lower exposure to wholesale commodity risk; a balanced approach to power needs with a combination of short, medium and longer term contracts; and streamlined, less complex products for convenience while ensuring protection from energy price volatility.

At Strategic Energy we are also transforming our internal capabilities and business processes to maintain our leadership in this rapidly changing market. We are adopting best-in-class marketing The heartof KCP&L,ourefficient fleet of generatingstations, performedwell in2004 - deliveringreliable,low-cost electricity and sales processes to identify the rght customer at for customersandreturnsfor shareholders.

the right time wth the right product. We are also upgrading our supply and portfolio management management tocus. Early in the year, we made KCP&L Average Retail capabilities in order to reduce supply costs, which the decision to exit our gas exploration and pro- Price Comparison represent more than 90% of Strategic Energy's duction business, KLT Gas. Through careful man- Cents per KWh Source: EEI Typical Bills for total costs, whi e remaining true to the prudent risk agement of the sales process over the course 12 months ending 6/30/04 management philosophy that has been one of the of the year, we achieved favorable results from hallmarks of the company. the sale of the KLT Gas properties. In December In April, Great Plains Energy increased its own- we entered into a letter of intent to sell Worry Free ership in Strategic Energy to just under 100%. We Services, Inc., a small business that provided resi-also added talent to the executive team by hiring dential services in several metropolitan areas and Shahid Malik as our new CEO. Shah d's depth closed the sa e in February 2005.

and breadth of experience in the energy industry, InJune, we completed successful $150 million combined with his inspirational leadership style, common stock and $163 million equity-linked make him the right leader to help drive this fast- securities offerings. This improved our cap tal evolving, entrepreneurial business forward. structure and was well received by investors.

Throughout the year, teams across the Great Plains Energy UKCP&L URegirn [0USA Nerage Company evaluated and assessed our interna In addition to the results within our major busi-controls over financial reporting required by the nesses, we also improved the focus of the Sarbanes-Oxley Act. Management concluded, portfolio at Great Plains Energy.

and our external auditors agreed, that our internal We sold two companies that were not strongly controls over financial reporting are effective as of aligned with our core businesses, enabling greater December 31, 2004. iIE 10 G R E A T P L A I N S E N ER G Y Cow

i KCP&L delivers reliable, low-cost power - and builds new partnerships with customers.

Customer focus drives excellence In a dramatically changing trying new ways of tracking two co-workers converse or energy market, leadership and improving performance, a team comes together to comes from empowering and reaching into the future tackle a challenge. But our our organization to serve to offer new energy solutions efforts pay off when energy customers in innovative for the market. Operational makes a difference in a ways. So we are building excellence takes shape customer's life.

new skills in our workforce, behind the scenes, when 2 0 0 4 A N N U A I R E PO R 11

Strategic Energy is delivering smart solutions for the challenges of a competitive world.

Our value proposition saves money for energy customers with a choice Strategic Energy provides of electricity at predictable marketplace and offer solu-energy management services costs from Strategic Energy. tions tailored to the cus-incompetitive markets Our skilled team can assess a tomer. Our value proposition nationwide. Nearly 8,500 customer's needs, buy energy makes sense - we deliver commercial, institutional and to match those requirements sustainable savings to cus-industrial customers nation- and provide competitive tomers with a choice.

wide get a reliable supply prices. We sort out a confusing 12 G R E AT P L A I N S E N E R G Y

Building the Foundation for the Future InJanuary of 2004 we launched a comprehensive "Our team is well-positioned strategic planning process. Our approach to strat-egy development set the tone for how we will do to thrive in a market that has business in the future.

• We engaged employees at all levels of the com-pany, including our bargaining units, to ensure a tremendous untapped potential."

common understanding and level of awareness.

• We reached out to our customers, community We selected a diverse team to lead the develop-leaders and regulators. This unprecedented ment of a Winning Culture, one in which employee level of collaboration enabled us to better under- development, growth and empowerment are stand their perspectives, and they developed encouraged and supported. Our employee team a better understanding of the issues facing our company. captured the spirit of Winning Culture through the concept of the GPE IDEAL. Each letter inthe word

• We took an outside-in viewpoint, recruiting industry experts to bring leading thinking from "I-D-E-A-L" represents a desirable quality in a a variety of perspectives, often representing Winning Culture environment - Inspired leader-opposing views on key topics. ship, Disciplined performance management,

• We considered multiple aspects of strategy Engaged employees, Accountability and Loyalty.

development with an explicit focus on the And as part of this IDEAL, we are finalizing a cultural aspects necessary for success.

formal, disciplined performance management pro-

• We developed and evaluated alternative cess that features balanced scorecards, initiatives, scenarios to ensure that while we have a timetables and accountabilities, as well as broad-clear strategy, we will stay flexible enough to respond to potential changes in our markets. based employee rewards and recognition. Hi -

This process succeeded on many fronts.

It engaged our employees and constituents, increased our mutual understanding of the key issues and resulted in a Strategic Intent that will guide our actions well into the future.

Our Strategic Intent is the roadmap for our company to become an industry leader at supply-ing and delivering electricity and innovative energy solutions to our customers. It's truly a milestone in the Company's history. Pease refer to pages 4 and 5 for more detail about our Strategic Intent We Have Already Started to Implement Our Strategic Intent An important priority in our plan is a Winning Culture.

By building a place where people can grow and thrive, we're building a company that will also thrive - and produce the kind of results that make shareholders eager to invest. Our business will succeed based on the talent and engagement of our workforce. For us, Winning Culture has a very specific definition - one developed by employees for employees.

2 0 0 4 A N N U A L R E P 0 R T 13

Inan effort to make the development of KCP&Lis "Inthe long run, our comprehensive plan as open, collaborative and transparent as possible, we met with more than greatest competitive 80 civic and community groups and hosted six public forums in many parts of our service area.

advantage will come We also participated in a series of regulatory workshops in Kansas and Missouri open to all from a winning interested parties. We also invited the public to provide comments on the proposal through infor-mational mailings and advertisements. At every culture at Great stage of the process, we've welcomed input.

Our lengthy and personal grassroots effort Plains Energy." helped us incorporate suggestions from all sides of the various issues. This created an even stronger KCP&L's Comprehensive Energy Plan and more viable proposal. The resulting compre-Another area where the Strategic Intent has already hensive plan represents a proactive and sensible produced results is KCP&Ls comprehensive energy approach to meeting the energy, economic and plan. This plan was developed to meet the long- environmental needs of our community throughout term energy needs of the communities we serve the next decade.

- in a way that balances the perspectives of our We are currently in discussions with partici-multiple constituents and is consistent with our pants in both Missouri and Kansas to develop a Strategic Intent. The key elements of the plan are: regulatory structure to make these investments

• Majority ownership of a regulated possible. We are working toward an agreement 800-900 MW coal-fired plant to be submitted to the state commissions that

• Environmental investments of enables us to balance the needs of shareholders, approximately $300 million customers, regulators and our community to meet

• Up to 200 megawatts of wind generation the growing demand for electricity in our region.

• Demand, efficiency and affordability response programs, including distributed generation to Summary help customers use energy more effectively The course we have set for the next decade will

• Infrastructure improvements to maintain address the needs of our customers, community and improve reliability and employees, and will reward shareholders with excellent long-term earnings potential. We have A key driver for this investment is the growth within our service territory and the demand for clear direction and a clear commitment to building electricity, which we estimate will continue to a Winning Culture. I believe that all of our constituents will look back proudly on 2004 as expand at approximately 2% - 2.5% per year.

A prime example of this growth is downtown a year in which we not only demonstrated the power of our businesses to deliver outstanding Kansas City, which is beginning a major revitaliza-results, but also established a strong foundation tion. KCP&L is an integral part of this effort.

for our longer-term success.

As I look out my office window, I can see our employees replacing an aging underground electricity infrastructure to deliver power to projects such as H&R Block's new world XCc/2SC/0~

headquarters and the proposed Sprint Arena.

/) Michael I Chesser It is estimated that the downtown revival, when Chairman and Chief Executive Officer completed, will require an additional 20 to 30 March 7, 2005 megawatts of electricity.

14 G R E AT PL A I N S E N E RG Y 111

Directors and Officers AS OFDECEMBER 31, 2004 BOARD -OF - DIRECTORS G E. -LAN S. EE G IGREAT PLAINS- ENERGY Michael J. Chesser Mark A.Ernst Dr. WilliamK.- Hall James A. Mitchell Dr. Linda Hood Talbott Chairrnan of the Board and Chairman, President and Chairman of Procyon Executive Fellow- President, Talbott &

Chief Executive Officer Chief Executive Officer, Technologies, Inc. ; Leadership, Center Associates H&R Block, Inc. a holding company for Ethical Business consultants instrategic Dr. David L. Bodde a global provider of tax Mwth irivestrnents in Cultures planning, philanthropic Senior Fellow and preparation, investment, the aerospace anud a not-for-profit organization management and devel-Professor, Arthur M. Spiro mortgage and accounting defense industries assisting business leaders opment to foundations, Center for Entrepreneurial services in creating ethical and corporations and non-Leadership at Clemson Luis A.4Jimenez' profitable cultures profit organizations University Randall C.Ferguson, Jr. Senior Vice President and Senior Partner for Business Chief Strategy Officer of William C.Nelson Robert H.West William H. Downey Development, Tshibanda & Pitney Bowes Inc. - Chairman, George K. Retired Chairman of President and Chief Associates, LLC a global frovider of inte- Baum Asset Management the Board, Butler Operating Officer a consulting and project grated mail and document a provider of investment Manufacturing Company management services management solutions management services to a supplier of non-residential firm committed to assisting individuals, foundations building systems, specialty dents to improve opera- and institutions components and con-tions and achieve long-last- struction services ing, measurable results

- IOFFICERS GREAT PLAINS ENERGY I - KANSAS CITY POWER & LIGHT COMPANY I STRATEGIC ENERGY Michael J. Chesser Jeanie S. Latz Michael J. Chesser William P.Herdegen Ill Shahid Malik Chairman of the Board and Executive Vice President - Chairm an of the Board Vice President -  : President and Chief Chief Executive Officer Corporate and Shared Distribution Operations Executive Officer Services and Secretary ,William H.Downey William H.Downey President and Chief - Nancy J. Moore President and Chief Brenda Nolte Executive Officer Vice President -

Operating Officer Vice President - Customer Services Public Affairs Andrea F.Bielsker Andrea F.Bielsker Senior Vice President - Richard A.Spring Senior Vice President - William G.Riggins Finance, Chief Financial Vice President -

Finance, Chief Financial General Counsel -Officerand Treasurer Transmission Services Officer and Treasurer Lori A. Wright Stephen T. Easley Jeanie S. Latz Controller Vice President - Secretary Generation Seriices Lori A.Wright Contrailer 2 0 0 4 A N U AL R EPO RT 15

Shareholder Information GREAT PLAINS ENERGY FORM 10-K ANNUAL MEETING OF SHAREHOLDERS Great Plains Energy's 2004 annual report filed with Great Plains Energy's annual meeting of shareholders the Securities and Exchange Commission on Form will be held at 10:00 a.m. on May 3, 2005, at The Discovery Center, 4750 Troost inKansas City, Missouri.

10-K can be found at: wwwgreatplainsenergy.com and is available at no charge upon written request to: DIVIDEND REINVESTMENT AND Corporate Secretary DIRECT STOCK PURCHASE PLAN Great Plains Energy Incorporated Great Plains Energy offers the opportunity to purchase P.O. Box 418679 common shares directly from the Company with an Kansas City, MO 64141-9679 initial minimum investment of $500 through our Dividend Reinvestment and Direct Stock Purchase Plan. The Plan offers shareholders several choices, MARKET INFORMATION including reinvestment of all or some of their common Great Plains Energy common stock is traded on the stock dMdends and the option of investing additional New York Stock Exchange under the ticker symbol GXP. cash monthly. Shareholders may choose to deposit Shareholders of record as of December31,2004: 15,188 their certificates with the transfer agent for safekeep-ing in their Plan account. For more information or an INTERNET SITE enrollment form, contact Investor Relations or UMB Bank, n.a. or visit Great Plains Energy's Web site at The company has a site on the Internet at wwwgreatplainsenergy com www.greatplainsenergy.com. Information available includes company news releases, stock quotes, DIRECT DEPOSIT OF DIVIDENDS AND 4 AUTOMATIC MONTHLY INVESTMENT customer account information, community and environmental efforts, and information of general Shareholders may elect the convenience of having dividends deposited directly to their checking, savings interest to investors and customers. or other accounts. Shareholders can also choose to Also located on our Web site are the company's Code authorize automatic monthly deductions from checking of Ethics, Corporate Govemance Guidelines and or savings accounts to purchase additional shares.

the charters for the Audit Committee, Govemance Electing direct deposit or automatic deduction changes only the manner of dividend payment.

Committee, and Compensation and Development Annual report and proxy materials, year-end tax Committee of the Board of Directors, which are information and other correspondence will be mailed also available at no charge upon written request to the shareholder's address of record. For more to the Corporate Secretary. information, please contact Investor Relations or UMB Bank, n.a., or visit Great Plains Energy's COMMON STOCK DIVIDENDS PAID Web site at www.greatplainsenergy com QUARTER 2004 2003 REGISTERED SHAREHOLDER INQUIRIES First $0.415 $0.415 For account information or assistance, including change Second $0.415 $0.415 of address, stock transfers, dividend payments, Third $0.415 $0.415 duplicate accounts or to report a lost certificate, Fourth $0.415 $0.415 please contact Investor Relations at 800-245-5275.

CUMULATIVE PREFERRED STOCK DIVIDENDS FINANCIAL COMMUNITY INQUIRIES Quarterly dividends on preferred stock were declared Securities analysts and investment professionals in each quarter of 2004 and 2003 as follows: seeking information about Great Plains Energy may contact Investor Relations at 816-556-2312.

SERIES AMOUNT 3.80% $0.95 TRANSFER AGENT AND STOCK REGISTRAR 4.20% 1.05 UMB Bank, n.a.

4.35% 1.0875 Securities Transfer Division 4.50% 1.125 P.O. Box 410064 Kansas City, Missouri 64141-0064 800-884-4225 (toll free)

TWO-YEAR COMMON STOCK HISTORY Great Plains Energy's common stock price range was: CORPORATE GOVERNANCE LISTING STANDARDS CERTIFICATION 2004 2003 On May 18, 2004, the company submitted its Annual QUARTER HIGH LOW HIGH LOW CEO Certification to the New York Stock Exchange.

First $35.29 $31.66 $25.00 $21.36 (NYSE). Mr. Chesser, Chairman of the Board and Chief' Second 34.36 29.23 30.31 23.75 Executive Officer of the company, certified that as of Third 31.71 28.62 30.84 27.32 May 17, 2004, he was not aware of any violation by Fourth 30.71 28.17 32.78 30.10 the company of NYSE Corporate Governance listing standards.

16 G R E AT P L A IN S E N E RG Y 1111

Financial Report Page Number Cautionary Statements Regarding Forward-Looking Information 18 Glossary of Terms 19 Management's Discussion and Analysis of Financial Conditions and Results of Operations 21 Quantitative and Qualitative Disclosures About Market Risks 56 Financial Statements Great Plains Energy Consolidated Statements of Income 59 Consolidated Balance Sheets 60 Consolidated Statements of Cash Flows 62 Consolidated Statements of Common Stock Equity 63 Consolidated Statements of Comprehensive Income 64 Kansas City Power & Light Company Consolidated Statements of Income 65 Consolidated Balance Sheets 66 Consolidated Statements of Cash Flows 68 Consolidated Statements of Common Stock Equity 69 Consolidated Statements of Comprehensive Income 70 Great Plains Energy Kansas City Power & Light Company Notes to Consolidated Financial Statements 71 Independent Auditors' Report to the Board of Directors and Shareholders of Great Plains Energy 121 Independent Auditors' Report to the Board of Directors of KCP&L 122 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 123 Management's Report on Internal Control Over Financial Reporting - Great Plains Energy 123 Independent Auditors' Report to the Board of Directors and Shareholders of Great Plains Energy 123 Management's Report on Internal Control Over Financial Reporting - KCP&L 124 Independent Auditors' Report to the Board of Directors of KCP&L 125 Certifications of the Chief Executive Officer and Chief Financial Officer of Great Plains Energy to the 2004 Annual Report on Form 10-K Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 127 17

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

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

• market perception of the energy industry and the Company

• changes in business strategy, operations or development plans

• effects of current or proposed state and federal legislative and regulatory actions or developments, including, but not limited to, deregulation, re-regulation and restructuring of the electric utility industry and constraints placed on the Company's actions by the Public Utility Holding Company Act of 1935

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

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

• credit ratings

• inflation rates

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

• impact of terrorist acts

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

• ability to carry out marketing and sales plans

• weather conditions including weather-related damage

• cost, availability and deliverability of fuel

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

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

• nuclear operations

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

• performance of projects undertaken by the Company's non-regulated businesses and the success of efforts to invest in and develop new opportunities, and

• other risks and uncertainties.

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

18 III

GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.

Abbreviation or Acronym Definition 35 Act Public Utility Holding Company Act of 1935, as amended ARO Asset Retirement Obligations CAIR Clean Air Interstate Rule Clean Air Act Clean Air Act Amendments of 1990 CO 2 Carbon Dioxide Compact Central Interstate Low-Level Radioactive Waste Compact Company Great Plains Energy Incorporated and its subsidiaries Consolidated KCP&L KCP&L and its subsidiary, HSS COSO Committee of Sponsoring Organizations Digital Teleport Digital Teleport, Inc.

DOE Department of Energy DTI DTI Holdings, Inc. and its subsidiaries, Digital Teleport, Inc.

and Digital Teleport of Virginia, Inc.

EBITDA Earnings before interest, income taxes, depreciation and amortization EEI Edison Electric Institute EIRR Environmental Improvement Revenue Refunding EPA Environmental Protection Agency EPS Earnings per common share ERISA Employee Retirement Income Security Act of 1974 FASB Financial Accounting Standards Board FELINE PRIDESsM Flexible Equity Linked Preferred Increased Dividend Equity Securities, a service mark of Merrill Lynch & Co., Inc.

FERC Federal Energy Regulatory Commission FIN Financial Accounting Standards Board Interpretation GAAP Generally Accepted Accounting Principles GPP Great Plains Power Incorporated, a wholly owned subsidiary of Great Plains Energy Great Plains Energy Great Plains Energy Incorporated and its subsidiaries Holdings DTI Holdings, Inc.

HSS Home Service Solutions Inc., a wholly owned subsidiary of KCP&L IEC Innovative Energy Consultants Inc., a wholly owned subsidiary of Great Plains Energy IRS Internal Revenue Service ISO Independent System Operator KCC The State Corporation Commission of the State of Kansas KCP&L Kansas City Power & Light Company, a wholly owned subsidiary of Great Plains Energy KLT Energy Services KLT Energy Services Inc., a wholly owned subsidiary of KLT Inc.

KLT Gas KLT Gas Inc., a wholly owned subsidiary of KLT Inc.

KLT Gas portfolio KLT Gas natural gas properties KLT Inc. KLT Inc., a wholly owned subsidiary of Great Plains Energy KLT Investments KLT Investments Inc., a wholly owned subsidiary of KLT Inc.

KLT Telecom KLT Telecom Inc., a wholly owned subsidiary of KLT Inc.

KW Kilowatt 19

Abbreviation or Acronym Definition kWh Kilowatt hour Lease Trust Lessor for KCP&L's synthetic lease arrangement for five combustion turbines MAC Material Adverse Change MACT Maximum Achievable Control Technology MODOR Missouri Department of Revenue MPSC Missouri Public Service Commission MW Megawatt MWh Megawatt hour NEIL Nuclear Electric Insurance Limited NO, Nitrogen Oxide NPNS Normal purchases and normal sales exception under SFAS No. 133, as amended NRC Nuclear Regulatory Commission OCI Other Comprehensive Income Receivables Company Kansas City Power & Light Receivables Company, a wholly owned subsidiary of KCP&L RSAE R.S. Andrews Enterprises, Inc., a subsidiary of HSS RTO Regional Transmission Organization SEC Securities and Exchange Commission SE Holdings SE Holdings, L.L.C.

Services Great Plains Energy Services Incorporated SFAS Statement of Financial Accounting Standards SO 2 Sulfur Dioxide Sox Sulfur Oxide SPP Southwest Power Pool, Inc.

Strategic Energy Strategic Energy, L.L.C., a subsidiary of KLT Energy Services WCNOC Wolf Creek Nuclear Operating Corporation Wolf Creek Wolf Creek Generating Station Worry Free Worry Free Service, Inc., a wholly owned subsidiary of HSS 20 III

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Management's Discussion and Analysis of Financial Condition and Results of Operations that follow are a combined presentation for Great Plains Energy and consolidated KCP&L, both registrants under this filing. The discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of the registrants during the periods presented. It should be read in conjunction with the accompanying consolidated financial statements and related notes.

SIGNIFICANT EVENTS IN 2004

• Exited the KLT Gas business

• Developed a comprehensive strategic intent

• Initiated discussions with interested participants on a comprehensive energy plan at KCP&L

• Completed an equity offering to strengthen the balance sheet

• Purchased an additional indirect interest in Strategic Energy OVERVIEW Great Plains Energy is a public utility holding company registered with and subject to the regulation of the SEC under the 35 Act. Great Plains Energy does not own or operate any significant assets other than the stock of its subsidiaries. Great Plains Energy's direct subsidiaries are KCP&L, KLT Inc., GPP, lEC and Services. As a diversified energy company, Great Plains Energy's reportable business segments include KCP&L and Strategic Energy.

KCP&L KCP&L is an integrated, regulated electric utility that engages in the generation, transmission, distribution and sale of electricity. KCP&L has over 4,000 MWs of generating capacity and has transmission and distribution facilities that provide reliable affordable electricity to almost 495,000 customers in the states of Missouri and Kansas. KCP&L has continued to experience modest load growth annually through increased customer usage and additional customers. Rates charged for electricity are below the national average.

KCP&L has a wholly owned subsidiary, HSS, which held a residential services investment, Worry Free.

HSS entered into a letter of intent to sell Worry Free in December 2004 and closed the sale in February 2005.

Strategic Energy Strategic Energy provides competitive electricity supply services by entering into contracts with its customers to supply electricity. Strategic Energy does not own any generation, transmission or distribution facilities. Of the states that offer retail choice, Strategic Energy operates in California, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas. Strategic Energy also provides strategic planning and consulting services in the natural gas and electricity markets.

Great Plains Energy owns just under 100% of the indirect interest in Strategic Energy after IEC's May 2004 purchase of an additional 11.45% indirect interest. See Note 8 to the consolidated financial statements for additional information about the acquisition.

Strategic Energy serves approximately 8,500 customers including numerous Fortune 500 companies, smaller companies and governmental entities. Strategic Energy provides competitive electricity supply to over 54,000 commercial, institutional and small manufacturing accounts. Strategic Energy had a 21

79% customer retention rate for 2004 and expects continued growth in 2005, with MWhs delivered projected to range from 21 to 23 million. The increase in MWhs delivered is expected to be more than offset by a decline in average gross margin per MWh. Strategic Energy currently expects the gross margin per MWh on new customer contracts to average from $3.00 to $4.00 and gross margin per MWh on total customer contracts to average $4.60 to $5.00 in 2005.

Based solely on expected usage under current signed contracts, Strategic Energy has forecasted future MWh commitments (backlog) of 15.4 million, 4.4 million and 1.2 million for the years 2005 through 2007, respectively. Strategic Energy expects to deliver additional MWhs in these years through growth in existing markets, retention of existing customers and expansion into new markets. Higher wholesale energy prices have reduced savings available to customers in some markets compared to prevailing utility rates, which have created more customer price sensitivity and reduced average contract lengths and the rate of backlog growth.

STRATEGIC INTENT Over the first six months of 2004, the Company engaged in a comprehensive strategic planning process to map its view of the future of the electric industry, and ultimately the Company, over the next five to ten years. This inclusive process drew on the creativity and skills of employees, outside experts and community leaders. The strategic planning process sought to enhance the disciplined growth of the Company and build upon the strong foundation of KCP&L and Strategic Energy. This platform for growth provides a balanced mix of regulated earnings from the utility operations of KCP&L and the potential continued growth of Strategic Energy as it expands its presence in competitive retail markets.

KCP&L held a series of public forums during June and July 2004 in Missouri and Kansas to discuss how to meet the area's growing need for electricity and cleaner air. In July 2004, Great Plains Energy unveiled six key elements to its long-range strategic intent.

• KCP&L will expand and diversify its regulated supply portfolio to include new coal and wind generation.

• KCP&L will accelerate its investments in improving the environmental performance of its fleet, helping to protect its community's quality of life and preparing for an uncertain future of potentially more stringent regulations.

• KCP&L will adopt new delivery technology to enhance the reliability and efficiency of its delivery system. This technology will allow KCP&L to transform the delivery grid from a one-way to a two-way system. Customers will serve as both consumers and virtual suppliers of electricity through distributed generation and various demand response programs.

• Great Plains Energy, through Strategic Energy, will continue to profitably grow its competitive supply business, expanding into new markets, and creating new offerings when economical, and further cementing its reputation as the premium energy retailer from the standpoint of customer focus and value added.

• Great Plains Energy will collaborate even more closely with customers, communities and regulators to take a broader view in anticipating and meeting their energy needs.

• Great Plains Energy will continue to manage its business to achieve disciplined growth, and strong operating performance and deliver strong returns to its shareholders.

Since the July 2004 announcement, Strategic Energy has initiated several product innovations and process improvements to adapt to market conditions and changing customer needs. Strategic Energy has developed new product offerings including contract options to satisfy the desire of some customers to accept more commodity risk themselves in the near term, contracts that trigger automatically if prices 22

fall to predefined levels and contracts to aid customers who desire to take a balanced approach to their power needs with a combination of short, medium and longer term contracts. Strategic Energy is also implementing processes to sharpen its customer targeting approach to insure that the right products and services are being offered to various customer segments to meet customers' needs. Additionally, electricity supply costs represent over 90% of Strategic Energy's total costs. Strategic Energy is currently exploring innovative ways to manage these supply costs to enhance its competitiveness.

Since the July 2004 announcement, KCP&L, through a MPSC established workshop docket, began discussions with interested participants, including the MPSC staff and the KCC staff, among others, to collaborate on and develop a regulatory plan to implement KCP&L's proposed comprehensive energy plan, which includes:

• accelerated environmental investments of $300 million to $350 million for selected existing plants,

• investment in up to 200 megawatts of wind generation,

• building and owning up to 500 megawatts of an 800 to 900 megawatt coal fired plant at the latan site in Missouri and

• development of technologies and pilot programs to help customers conserve energy.

The proposal has the potential to add approximately $1.1 billion in capital investment for KCP&L over the next five years and is dependent upon approvals from the MPSC and KCC. In February 2005, the MPSC issued an order closing a workshop docket established specifically for the discussions. KCP&L continues in discussions with the interested participants with the goal of developing an agreement on implementation of the comprehensive energy plan to be formally submitted by KCP&L to the MPSC and KCC for approval. KCP&L anticipates that the next step in the process would include hearings scheduled by the MPSC and KCC to take testimony regarding the implementation of the comprehensive energy plan.

RELATED PARTY TRANSACTIONS See Note 12 to the consolidated financial statements for information regarding related party transactions.

CRITICAL ACCOUNTING POLICIES The preparation of financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect reported amounts and related disclosures. Management considers an accounting estimate to be critical if it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate or different estimates that could have been used could have a material impact on the results of operations and financial position.

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

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

23

These assumptions are updated annually in accordance with Statement of Financial Accounting Standards (SFAS) No. 87, "Employers' Accounting for Pensions". In selecting an assumed discount rate, the prevailing market rate of fixed income debt instruments with maturities matching the expected timing of the benefit obligation was considered. The assumed rate of return on plan assets was developed based on the weighted average of long-term returns forecast for the expected portfolio mix of investments held by the plan. These assumptions are based on the Company's best estimates and judgment; however, material changes may occur if these assumptions differ from actual events. See Note 9 to the consolidated financial statements for information regarding the assumptions used to determine benefit obligations and net costs.

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

Impact on Impact on Projected Impact on 2004 Change in Benefit Pension Pension Actuarial assumption Assumption Obligation Liability Expense (millions)

Discount rate 0.5% increase $ (28.3) $ (16.1) $ (1.7)

Rate of return on plan assets 0.5% increase - - (1.8)

Discount rate 0.5% decrease 30.3 18.6 1.8 Rate of return on plan assets 0.5% decrease - - 1.8 For the year ended December 31, 2004, the Company recorded pension expense of approximately

$21.8 million, a $4.3 million increase from the prior year. Pension expense for 2005 is expected to approximate $27.0 million, a $5.2 million increase over 2004. The increase is primarily due to the amortization of investment losses from prior years that are recognized on a rolling five-year average basis and lower discount rates.

The Company's pension plan assets are primarily made up of equity and fixed income investments.

The market value of the plan assets increased $29.5 million in 2004 reflecting continued improvement in the equity markets since the decline in 2002 and 2001. At plan year-end 2004, the fair value of pension plan assets was $370.5 million, not including a $20.7 million contribution made in 2004 after the plan year-end.

The total accumulated benefit obligation (ABO) of the plans exceeded the fair value of plan assets requiring the Company to record an additional minimum pension liability of $84.2 million including $79.8 million recorded at KCP&L. See Note 9 to the consolidated financial statements for additional information.

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

Regulatory Matters As a regulated utility, KCP&L is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, KCP&L has recorded assets and liabilities on its balance sheet resulting from the effects of the ratemaking process, which would not be recorded under GAAP if KCP&L were not regulated. Regulatory assets represent costs incurred that have been deferred because future recovery in customer rates is probable. Regulatory liabilities generally represent probable future reductions in revenue or refunds to customers. KCP&L's continued ability to meet the 24 III1

criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric industry. In the event that SFAS No. 71 no longer applied to all, or a separable portion, of KCP&L's operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment on utility plant assets as determined pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets." See Note 4 to the consolidated financial statements for a discussion of regulatory assets and liabilities.

Asset Retirement Obligations Effective January 1, 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets.

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

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

depending on the anticipated settlement date.

Revisions to the estimated liabilities of KCP&L could occur due to changes in the decommissioning or other cost estimates, extension of the nuclear operating license or changes in federal or state regulatory requirements. KCP&L has legal Asset Retirement Obligations (ARO) for certain other assets where it is not possible to estimate the time period when the obligations will be settled. Consequently, the retirement obligations cannot be measured at this time. See Note 16 to the consolidated financial statements for a discussion of ARO.

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

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

During 2003, KLT Gas management determined that two gas properties were impaired as development activities indicated a decline in the estimates of future gas production. As a result of the lower 25

estimated production, the carrying amount of each property exceeded its estimated fair value based upon discounted estimated future cash flows, which resulted in impairments on the two properties.

Internal and third party models were used in the Company's estimate of future production volumes, natural gas pricing, capital expenditures and operating costs. Cash flow models were based on management's understanding of prospect geology, well costs and projected operating expenses.

Natural gas pricing assumptions were based on the New York Mercantile Exchange Henry Hub Natural Gas forward curve, adjusted for basis differentials and other transportation charges.

Additionally in 2003, Great Plains Energy management performed a strategic review of the KLT Gas portfolio and operations. Management determined it would recommend a sale of the KLT Gas portfolio and a plan to exit the gas business at the February 2004 Board of Directors' meeting. As a result of its decision to recommend a sale of the KLT Gas portfolio and exit the gas business, Great Plains Energy management engaged a second third party firm to complete a market reference valuation analysis for the Company's use in determination of the fair value of the KLT Gas portfolio. As a result of the KLT Gas strategic review and market reference valuation analysis having been conducted, an impairment test of the entire KLT Gas portfolio was performed at December 31, 2003, in accordance with SFAS No. 144, using a probability weighting of the likelihood of potential outcomes at the February 2004 meeting. The impairment test considered 1) the scenario of sale of the entire KLT Gas portfolio with fair value based on estimated market prices and 2) the scenario of hold and use with fair value determined by risk adjusted discounted cash flows.

In February 2004, the Great Plains Energy Board of Directors approved management's recommendation to sell the KLT Gas portfolio and exit the gas business. As a result, the carrying amount of the KLT Gas portfolio was written down to its estimated realizable value. See Note 6 to the consolidated financial statements for a discussion of KLT Gas discontinued operations and SFAS 144 impairments.

SFAS No. 142 Great Plains Energy, through IEC, completed its purchase of an additional indirect interest in Strategic Energy during 2004. The Company recorded indefinite and finite lived intangible assets at fair value in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets." Finite lived intangible assets are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS No. 144. Indefinite lived intangibles are tested for impairment at least annually and more frequently when indicators of impairment exist as prescribed under SFAS No. 142. See Note 8 to the consolidated financial statements for additional information.

Goodwill is tested for impairment at least annually and more frequently when indicators of impairment exist as prescribed under SFAS No. 142. SFAS No. 142 requires that if the fair value of a reporting unit is less than its carrying value including goodwill, the implied fair value of the reporting unit goodwill must be compared with its carrying value to determine the amount of impairment. Strategic Energy's 2004 annual impairment test was completed as of September 1, the annual review date, and there was no impairment of the Strategic Energy goodwill. See Note 5 to the consolidated financial statements for information regarding the impact of adopting SFAS No. 142 on goodwill and goodwill amortization.

The accounting estimates related to impairment analyses are subject to change from period to period because management is required to make assumptions about future sales, operating costs and discount rates over an indefinite life. Actual margins and volumes have fluctuated and, to a great extent, fluctuations are expected to continue. The estimates of future margins are based upon internal budgets, which incorporate estimates of customer growth, business expansion and weather trends, among other items.

26 III

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

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

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

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

Derivative assets and liabilities consist of a combination of energy and energy-related contracts. While some of these contracts represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using modeling techniques to determine expected future market prices. The market prices used to determine fair value reflect management's best estimate considering time, volatility and historical trends.

However, future market prices will vary from those used in recording energy assets and liabilities at fair value, and it is possible that such variations could be significant.

Market prices for energy and energy-related commodities vary based upon a number of factors.

Changes in market prices will affect the recorded fair value of energy contracts. Changes in the fair value of energy contracts will affect operating income in the period of the change for contracts under fair value accounting and OCI in the period of change for contracts under cash flow hedge accounting, while changes in forward market prices related to contracts under accrual accounting will affect operating income in future periods to the extent those prices are realized. Strategic Energy cannot predict whether, or to what extent, the factors affecting market prices may change, but those changes could be material and could be either favorable or unfavorable.

27

GREAT PLAINS ENERGY RESULTS OF OPERATIONS The following table summarizes Great Plains Energy's comparative results of operations.

2004 2003 2002 (millions)

Operating revenues $2,464.0 $ 2,148.0 $1,802.3 Fuel (179.4) (160.3) (159.7)

Purchased power- KCP&L (52.5) (53.2) (46.2)

Purchased power - Strategic Energy (1,247.5) (968.9) (685.4)

Other operating expenses (510.6) (479.2) (465.1)

Depreciation and amortization (150.1) (142.8) (146.8)

Gain (loss) on property (5.1) 23.7 1.4 Operating income 318.8 367.3 300.5 Non-operating income (expenses) (8.4) (13.0) (13.1)

Interest charges (83.0) (76.2) (87.4)

Income taxes (54.5) (78.6) (51.3)

Minority interest in subsidiaries 2.1 (7.8) (10.8)

Loss from equity investments -

(1.5) (2.0) (1.2)

Income from continuing operations 173.5 189.7 136.7 Discontinued operations 7.3 (44.8) (7.5)

Cumulative effect of a change in accounting principle (3.0)

Net income 180.8 144.9 126.2 Preferred dividends (1.6) (1.6) (1.7)

Earnings available for common stock $ 179.2 $ 143.3 $ 124.5 Great Plains Energy's 2004 earnings, as detailed in the following table, increased to $179.2 million, or

$2.49 per share, from $143.3 million, or $2.07 per share in 2003. The issuance of 5.0 million shares in June 2004 diluted 2004 EPS by $0.10.

Earnings Per Great Earnings Plains Energy Share 2004 2003 2002 2004 2003 2002 (millions)

KCP&L $ 150.0 $ 127.2 $ 102.9 $ 2.08 $ 1.84 $ 1.64 Subsidiary operations (6.7) (1.3) (0.2) (0.09) (0.02) -

Discontinued operations (RSAE) - (8.7) (4.0) - (0.13) (0.06)

Cumulative effect of a change in accounting principle - - (3.0) - - (0.05)

Consolidated KCP&L 143.3 117.2 95.7 1.99 1.69 1.53 Strategic Energy 42.5 39.6 29.7 0.59 0.57 0.48 Other non-regulated operations (12.3) 24.2 4.3 (0.17) 0.35 0.07 Discontinued operations (KLT Gas) 7.3 (36.1) (3.5) 0.10 (0.52) (0.06)

Preferred dividends (1.6) (1.6) (1.7) (0.02) (0.02) (0.03)

Great Plains Energy $ 179.2 $ 143.3 $ 124.5 $ 2.49 $ 2.07 $ 1.99 The earnings per share of any segment does not represent a direct legal interest in the asset and liabilities allocated to any one segment but rather represents a direct equity interest in Great Plains Energy's assets and liabilities as a whole.

28 III

The increase in Great Plains Energy's 2004 earnings is primarily due to an increase in KCP&L's wholesale MWhs sold at higher wholesale prices, the May 2004 purchase of an additional 11.45%

indirect interest in Strategic Energy and a $10.8 million favorable impact of state tax planning on the composite tax rate for the Company. The increase in KCP&L's wholesale MWh sales was primarily due to increased generation, bundling transmission with energy and lower retail loads during the summer months. The Great Plains Energy earnings increase was offset by an increase in operating expenses at KCP&L and Strategic Energy, a $5.3 million impairment related to the first quarter 2005 sale of Worry Free, the net effect on 2003 earnings of the Hawthorn No. 5 litigation settlements and the $28.1 million net gain in 2003 related to the DTI bankruptcy. Additionally, a continuing environment of higher and less volatile energy prices and flat to higher forward electricity prices continue to negatively impact Strategic Energy's average gross margins. Discontinued operations (KLT Gas) primarily reflect the gain on sales of assets in 2004 and the loss due to the impairment related to the exit of the business in 2003. Discontinued operations (RSAE) primarily reflect the loss on the sale of RSAE in 2003.

Great Plains Energy's 2003 earnings increased to $143.3 million, or $2.07 per share, from $124.5 million, or $1.99 per share in 2002. The issuance of 6.9 million shares in November 2002 diluted 2003 EPS by $0.23. The increase in Great Plains Energy's 2003 earnings is primarily due to an increase in wholesale MWh sales, partial settlements of the Hawthorn No. 5 litigation, the fourth quarter 2002 purchase of an additional 6.0% indirect interest in Strategic Energy and the $28.1 million net gain related to the DTI bankruptcy. The increase in wholesale revenues was partially offset by the effect on retail revenues of the January 2003 Kansas rate reduction. In 2003, discontinued operations (KLT Gas) reflect an operating loss, property impairments and impairments related to the exit of the business. Discontinued operations (RSAE) primarily reflect the loss on the sale of RSAE in 2003.

Great Plains Energy's projected net income is expected to decrease in 2005. The decrease in projected net income for 2005 is due to a significant increase in fuel costs at KCP&L, lower anticipated 2005 average gross margins at Strategic Energy, expiration of a portion of the Company's investment tax credits in 2005 and the absence of the 2004 impact of the lower composite tax rate on deferred tax balances. These factors are projected to more than offset projected retail load growth and operational expense savings at KCP&L as well as lower holding company losses in 2005.

29

CONSOLIDATED KCP&L RESULTS OF OPERATIONS The following discussion of consolidated KCP&L results of operations includes KCP&L, an integrated electric utility and HSS, an unregulated subsidiary of KCP&L. References to KCP&L, in the discussion that follows, reflect only the operations of the integrated electric utility. The following table summarizes consolidated KCP&L's comparative results of operations.

2004 2003 2002 (millions)

Operating revenues $ 1,091.6 $ 1,057.0 $ 1,012.8 Fuel (179.4) (160.3) (159.7)

Purchased power (52.5) (53.2) (46.2)

Other operating expenses (442.3) (422.6) (411.6)

Depreciation and amortization (145.2) (141.0) (145.5)

Gain (loss) on property -

(5.1) 1.6 0.2 Operating income 267.1 281.5 250.0 Non-operating income (expenses) (1.9) (3.1) (4.1)

Interest charges (74.2) (70.3) (80.3)

Income taxes (52.8) (83.5) (62.9)

Minority interest in subsidiary -

5.1 1.3 Income from continuing operations 143.3 125.9 102.7 Discontinued operations (8.7) (4.0)

Cumulative effect of a change in accounting principle (3.0)

Net income $ 143.3 $ 117.2 $ 95.7 Consolidated KCP&L's income from continuing operations increased $17.4 million in 2004 compared to 2003. Consolidated KCP&L's operating revenues increased $34.6 million in 2004 compared to 2003, primarily due to a 14% increase in KCP&L's wholesale MWhs sold and a 13% increase in the average wholesale market price. The increase in wholesale MWhs sold was primarily due to increased generation, bundling transmission with energy and lower than expected retail loads during the summer months. An increase in operating expenses more than offset these factors primarily due to the increase in MWhs generated, including higher coal and coal transportation costs, higher administrative expenses, a $7.3 million impairment charge related to the first quarter 2005 sale of Worry Free and the significant positive impact on 2003 of the Hawthorn No. 5 litigation settlements. Income taxes decreased due to the $10.1 million favorable impact of state tax planning on the composite tax rate and a $5.9 million allocation of tax benefits from holding company losses pursuant to the Company's intercompany tax allocation agreement.

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As described in Item 3. Legal Proceedings, KCP&L filed suit against multiple defendants who are alleged to have responsibility for the 1999 Hawthorn No. 5 boiler explosion. KCP&L and its primary insurance company have entered into a subrogation allocation agreement under which recoveries in this suit are generally allocated 55% to the primary insurance company and 45% to KCP&L. Various defendants have settled with KCP&L in this litigation, resulting in KCP&L recording $2.4 million and

$35.8 million in 2004 and 2003, respectively, under the terms of the subrogation allocation agreement.

A portion of the settlements, $1.2 million and $17.3 million, for 2004 and 2003, respectively, was recorded as a recovery of capital expenditures. The following table summarizes the income statement impact related to the remainder of the settlements for loss of use of Hawthorn No. 5.

2004 2003 (millions)

Wholesale revenues $ 0.2 $ 2.7 Fuel 0.2 4.0 Purchased power 0.8 11.8 Operating income 1.2 18.5 Income taxes (0.5) (7.2)

Net income $ 0.7 $ 11.3 Consolidated KCP&L's income from continuing operations increased $23.2 million in 2003 compared to 2002. Consolidated KCP&L's operating revenues increased $44.2 million primarily due to a significant increase in wholesale MWhs sold at higher wholesale prices partially offset by the effect on retail revenues of the January 2003 Kansas rate reduction. Wholesale MWhs sold increased 16% in 2003 primarily due to increased generation and a more focused sales effort. Additionally, the average market price increased 33% primarily due to higher natural gas prices. Revenues also increased due to the partial settlements of Hawthorn No. 5 litigation. This increase in revenues combined with decreases in interest expense and depreciation expense more than offset increases in purchased power, pension, power plant maintenance and transmission expenses. The amortization of the Missouri jurisdictional portion of the January 2002 storm costs increased $3.1 million in 2003. In 2002, KCP&L expensed $16.5 million for the Kansas jurisdictional portion of the January 2002 storm costs.

Discontinued operations in 2003 includes a $7.1 million loss on the June 2003 disposition of HSS' interest in RSAE and continuing losses through the date of disposition of $1.6 million. Additionally, 2002 net income reflects the $3.0 million cumulative effect to January 1, 2002, of a change in accounting principle for the adoption of SFAS No. 142 and the associated write-down of RSAE goodwill.

Consolidated KCP&L's net income is projected to decrease in 2005 primarily due to a significant increase in fuel costs and the absence of the 2004 impact of the lower composite tax rate on deferred tax balances. These factors are projected to more than offset projected retail load growth and operational expense savings at KCP&L.

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Consolidated KCP&L Sales Revenues and MWh Sales 2004 Change 2003 Change 2002 Retail revenues (millions)

Residential $ 347.1 (4) $ 361.5 (2) $ 367.4 Commercial 421.1 1 417.6 - 418.6 Industrial 96.2 1 95.0 1 93.7 Other retail revenues 8.7 1 8.7 - 8.6 Total retail 873.1 (1) 882.8 (1) 888.3 Wholesale revenues 200.2 27 157.5 46 108.0 Other revenues 16.8 15 14.6 8 13.6 KCP&L electric revenues 1,090.1 3 1,054.9 4 1,009.9 Subsidiary revenues 1.5 (25) 2.1 (28) 2.9 Consolidated KCP&L revenues $ 1,091.6 3 $ 1,057.0 4 $ 1,012.8 2004 Change 2003 Change 2002 Retail MWh sales (thousands)

Residential 4,903 (3) 5,047 1 5,004 Commercial 6,998 1 6,933 - 6,902 Industrial 2,058 1 2,035 3 1,968 Other retail MWh sales 85 - 85 2 83 Total retail 14,044 - 14,100 1 13,957 Wholesale MWh sales 6,603 14 5,777 16 4,969 KCP&L electric MWh sales 20,647 4 19,877 5 18,926 Retail revenues decreased $9.7 million in 2004 compared to 2003 primarily due to a $14.4 million reduction in residential revenues. Residential usage per customer decreased 4% in 2004 compared to 2003 as a result of significantly cooler summer weather in 2004. The Kansas City area experienced one of the coolest summers in the past 30 years, which resulted in cooling degree days 18% below normal. Weather most significantly affects residential customers' usage patterns. The impact of the cooler summer weather was partially offset by continued load growth in 2004. Load growth consists of higher usage per customer and the addition of new customers. The average number of residential and commercial customers continues to grow; both increased 1%to 2% in 2004 and 2003 compared to the respective prior years. Retail revenues decreased $5.5 million in 2003 compared to 2002. The Kansas rate reduction effective January 1, 2003, decreased 2003 retail revenues approximately $12.5 million and was partially offset by load growth in 2003.

Bulk power sales, the major component of wholesale sales, vary with system requirements, generating unit and purchased power availability, fuel costs and requirements of other electric systems. Wholesale revenues increased $42.7 million in 2004. Wholesale MWhs sold increased 14% in 2004 compared to 2003, primarily due to increased generation, bundling transmission with energy and lower than expected retail loads during the summer months, combined with successful marketing efforts. KCP&L's coal fleet equivalent availability factor increased to 84% in 2004 compared to 82% for 2003, which contributed to an increased volume of wholesale MWhs available to sell. Average market prices per MWh increased 13% to $30.72 in 2004 compared to 2003, primarily due to more sales made during periods of higher natural gas prices and bundling transmission with energy to provide a delivered product. Additionally, wholesale revenues were affected by the partial settlements of the Hawthorn No.

5 litigation. Wholesale revenues increased $49.5 million in 2003 compared to 2002, which in 2003 included $2.7 million related to the partial settlements of Hawthorn No. 5 litigation. Wholesale MWhs 32 111

sold increased 16% in 2003 compared to 2002, primarily due to increased generation and a more focused sales effort. The revenue variance in 2003 compared to 2002 was primarily due to a 33%

increase in average market price per MWh of power sold in 2003 to $27.27. The increase was driven by higher natural gas prices. Less than 1% of revenues reflect rates that include an automatic fuel adjustment provision.

Consolidated KCP&L Fuel and Purchased Power The fuel cost per MWh generated and the purchased power cost per MWh has a significant impact on the results of operations for KCP&L. Generation fuel mix can change the fuel cost per MWh generated substantially. In 2004, KCP&L experienced a record coal base load capacity factor of 80%. The coal fleet achieved a record level of generation of approximately 16 million MWhs, a 5% increase compared to 2003. Nuclear fuel costs per MWh generated remain substantially less than the cost of coal per MWh generated. Coal has a significantly lower cost per MWh generated than natural gas and oil.

Fossil plants averaged over 75% of total generation and the nuclear plant the remainder over the last three years. Replacement power costs for planned Wolf Creek outages are accrued evenly over the unit's operating cycle. KCP&L expects its cost of nuclear fuel to remain relatively stable through the year 2009. The cost per MWh for purchased power is still significantly higher than the fuel cost per MWh of coal and nuclear generation. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply, availability and cost of purchased power and the requirements of other electric systems to provide reliable power economically.

Fuel expense increased $19.1 million in 2004 compared to 2003 primarily due to a 6% increase in MWhs generated, higher coal and coal transportation costs, higher natural gas costs and the net effect of $3.8 million from the Hawthorn No. 5 partial litigation settlements. The increase was partially offset by a lower average fuel cost per MWh generated due to increased coal and nuclear fuel and less natural gas in the fuel mix. The change in fuel mix was primarily due to the 2003 refueling outage at Wolf Creek and the cooler 2004 summer weather, which allowed coal and nuclear capacity to supply a greater percentage of the reduced retail load. Fuel expense increased $0.6 million in 2003 compared to 2002 primarily due to a 3% increase in MWhs generated. This increase was partially offset by a lower average fuel cost per MWh generated due to increased coal and less natural gas in the fuel mix and a $4.0 million decrease related to the partial settlements of Hawthorn No. 5 litigation.

Purchased power expense decreased $0.7 million in 2004 compared to 2003. MWhs purchased decreased 31% in 2004 compared to 2003 primarily due to lower retail customer demand and a 2%

increase in the coal fleet equivalent availability factor in 2004 compared to 2003. The decrease in MWhs purchased was partially offset by an 11% increase in the average purchased power price per MWh in 2004 compared to 2003 primarily due to higher natural gas market prices and increased demand in the market area earlier in 2004. Another offset includes the net effect of the Hawthorn No. 5 partial litigation settlements, which impacted purchased power expense by $11.0 million in 2004 compared to 2003. Purchased power expense increased $7.0 million in 2003 compared to 2002 primarily due to a 31% increase in the price per MWh driven primarily by increased natural gas prices.

MWhs purchased increased 27% in 2003 compared to 2002 due to increased customer needs. These increases were partially offset by the $11.8 million related to the Hawthorn No. 5 litigation settlements in 2003.

KCP&L expects its fuel expense to increase significantly in 2005 due to projected increases in the cost of coal and coal transportation and in the volume and price of natural gas generation in the fuel mix.

KCP&L expects to utilize its natural gas-fired peaking generating capacity more often to serve expected growth in retail customer demand, which will increase natural gas consumption. High natural gas and fuel oil costs are also influencing the price of coal and coal transportation costs, which are also expected to increase. The anticipated increase in delivered coal prices is expected to affect most 33

utilities; therefore, the increase is not expected to materially erode KCP&L's position as a low cost regional electricity generator.

Consolidated KCP&L Other Operating Expenses (includingother operating, maintenance and general taxes)

Consolidated KCP&L's other operating expenses increased $19.7 million in 2004 compared to 2003 primarily due to the following:

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

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

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

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

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

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

Partial offsets to the increase in other operating expenses included:

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

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

Consolidated KCP&L's other operating expenses increased $11.0 million in 2003 compared to 2002 primarily due to the following:

• amortizing an additional $3.1 million of the Missouri jurisdictional portion of the January 2002 ice storm in 2003,

• increased pension expense of $11.3 million primarily due to a significant decline in the market value of plan assets,

• increased plant maintenance expense of $6.7 million for plant outages,

• increased transmission expenses of $3.3 million primarily due to increased usage charges as a result of the increased wholesale MWh sales and increased MWh of purchased power,

• partially offsetting the increases were lower maintenance expense in 2003 due to expensing in 2002 the $16.5 million of the Kansas jurisdictional portion of the January 2002 ice storm.

Consolidated KCP&L Depreciation and Amortization Consolidated KCP&L's depreciation and amortization expense increased $4.2 million in 2004 compared to 2003. The increases are primarily due to an increase of $2.6 million related to capital additions and

$3.8 million as a result of the consolidation of the Lease Trust. The increase was partially offset by

$1.9 million as a result of certain software becoming fully amortized in 2003.

34 111

Consolidated KCP&L's depreciation expense decreased $4.5 million in 2003 compared to 2002.

Depreciation expense decreased approximately $7.7 million due to the change to a 60-year life for Wolf Creek pursuant to the 2002 KCC stipulation and agreement. See Note 4 to the consolidated financial statements for additional information. This decrease was partially offset by increased depreciation expense of $2.2 million related to capital additions and $1.3 million as a result of the consolidation of the Lease Trust.

Consolidated KCP&L Interest Charges Consolidated KCP&L's interest charges increased $3.9 million in 2004 compared to 2003. The increase was primarily due to a $10.1 million interest component related to the IRS 1995-1999 audit settlement. Partially offsetting this increase was a $6.3 million decrease primarily due to the 2004 redemption of KCP&L's $154.6 million 8.3% Junior Subordinated Deferred Interest Bonds. See Notes 11 and 19 to the consolidated financial statements for further information.

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

Consolidated KCP&L Income Taxes Consolidated KCP&L's income taxes decreased $30.7 million in 2004 compared to 2003. Several factors contributed to the decreased taxes including lower income in 2004 compared to 2003. The favorable impact of state tax planning on the composite tax rate decreased income taxes $10.1 million, including $8.6 million reflecting the composite tax rate change on deferred tax balances resulting from book to tax temporary differences. An additional $10.1 million decrease is attributable to the reserves for the interest component of the IRS 1995-1999 audit settlement, which offset interest expense and had no impact on income from continuing operations. Income taxes also decreased by $5.9 million due to the allocation of tax benefits from holding company losses pursuant to the Company's intercompany tax allocation agreement. Income taxes increased $20.6 million in 2003 compared to 2002, primarily due to higher income.

On October 22, 2004, the American Jobs Creation Act of 2004 (AJCA) became law. Most significantly, the AJCA contains a provision that allows for a tax deduction of 9% (3% for 2005-2006; 6% for 2007-2009; 9% thereafter) of qualified production activities income. Income from electric generation activities is included in the definition of qualified production activities. Because of its electric generation activities, KCP&L expects to be favorably impacted by the AJCA. The IRS has recently issued interim guidance on which KCP&L may rely on until regulations are issued. KCP&L is reviewing the recent guidance and has made preliminary estimates of the deduction. For 2005, the deduction is estimated to be approximately $6 million. The regulatory treatment regarding the qualified production deduction is unknown at this time.

35

STRATEGIC ENERGY RESULTS OF OPERATIONS The following table summarizes Strategic Energy's comparative results of operations.

2004 2003 2002 (millions)

Operating revenues $ 1,372.4 $ 1,091.0 $ 789.5 Purchased power (1,247.5) (968.9) (685.4)

Other operating expenses (51.3) (42.1) (37.6)

Depreciation and amortization (4.8) (1.7) (0.9)

Operating income 68.8 78.3 65.6 Non-operating income (expenses) 1.7 1.0 0.4 Interest charges (0.7) (0.4) (0.3)

Income taxes (24.3) (30.2) (25.2)

Minority interest (3.0) (9.1) (10.8)

Net income $ 42.5 $ 39.6 $ 29.7 Strategic Energy's net income increased $2.9 million in 2004 compared to 2003. Retail MWhs delivered increased 22% in 2004 compared to 2003. Great Plains Energy, through IEC, completed the purchase of an additional 11.45% indirect interest in Strategic Energy resulting in a $1.8 million increase in net income. Income taxes decreased in 2004 primarily due to a $3.1 million allocation of tax benefits from holding company losses pursuant to the Company's intercompany tax allocation agreement and the Company's income tax accounting policies for segment reporting. The increase to net income was partially offset by a 16% decline in the average gross margin per MWh (revenues less purchased power divided by MWhs delivered) to $6.15 in 2004. The decline in gross margin is primarily due to the roll-off of older, higher margin contracts, price discounts driven by a more competitive market and persistently higher commodity prices, and a $4.2 million increase in tax reserves. A continuing environment of higher and less volatile energy prices and flat to higher forward electricity prices continue to negatively impact the average gross margins. The negative impacts on average gross margin per MWh were partially offset by a $1.7 million change in fair value related to energy contracts that do not qualify for hedge accounting and from hedge ineffectiveness.

Strategic Energy's net income increased $9.9 million in 2003 compared to 2002. The increased net income was primarily due to growth in retail electric revenues from the expansion into new markets and continued sales efforts in existing markets. In addition, Great Plains Energy increased its indirect interest in Strategic Energy by 6% in the fourth quarter of 2002. These increases were partially offset by increased general and administrative expenses including employee related expenses. Also, the average gross margin per MWh decreased to $7.34 in 2003 compared to $8.70 in 2002. The decrease in average gross margin per MWh in 2003 compared to 2002 was primarily due to the roll-off of higher margin contracts that were obtained during periods of high market price volatility in late 2000 and early 2001 and to a lesser extent market conditions, including increased competition.

Strategic Energy's net income is projected to decrease in 2005. The projected decrease in average gross margins per MWh to a range of $4.60 to $5.00 in 2005 from $6.15 in 2004 is anticipated to more than offset the expected increase in MWhs delivered from 20.3 million in 2004 to a range of 21 to 23 million in 2005.

36 ill

Strategic Energy Operating Revenues Operating revenues from Strategic Energy increased $281.4 million in 2004 compared to 2003 and

$301.5 million in 2003 compared to 2002 as shown in the following table.

2004 Change 2003 Change 2002 (millions)

Electric - Retail $ 1,355.3 27 $ 1,063.2 40 $ 759.5 Electric - Wholesale 15.5 (41) 26.5 (8) 28.8 Professional services 1.6 18 1.3 14 1.2 Total operating revenues $ 1,372.4 26 $ 1,091.0 38 $ 789.5 Retail electric revenues increased $292.1 million in 2004 compared to 2003 primarily due to increased retail MWhs delivered. Retail MWhs delivered increased 22% to 20.3 million in 2004 compared to 2003. The increased MWhs delivered resulted primarily from strong sales efforts in customer retention as well as enrolling new customers primarily in Michigan and Texas where Strategic Energy continued to experience favorable conditions for growth. Strategic Energy's customer accounts totaled over 54,000 accounts at the end of 2004, a 14% increase from approximately 48,000 accounts at the end of 2003. Several factors contribute to changes in the average retail price per MWh, including the underlying electricity price, the nature and type of products offered and the mix of sales by geographic market. Average retail revenues per MWh increased 4% in 2004 compared to 2003 primarily due to a higher underlying electricity price that was driven by higher natural gas prices partially offset by price discounts driven by a more competitive market and persistently higher commodity prices.

Retail electric revenues increased $303.7 million in 2003 compared to 2002 primarily due to increased retail MWhs delivered. Retail MWhs delivered increased 41% to 16.6 million in 2003 from 11.8 million in 2002. The increased MWhs delivered resulted primarily from effective sales efforts in re-signing approximately 80% of existing customers as well as enrolling new customers in markets in which Strategic Energy continued to experience favorable conditions for growth. Customer accounts at the end of 2003 increased 44% from approximately 33,000 accounts at the end of 2002. MWhs delivered in California increased 70% to 5.5 million in 2003 and MWhs delivered in Texas increased 58% to 4.5 million in 2003 compared to 2002.

Strategic Energy Purchased Power Strategic Energy primarily purchases power under forward physical delivery contracts to supply electricity to its retail energy customers based on projected usage. Strategic Energy sells any excess retail supply of electricity back into the wholesale market. The proceeds from the sale of excess supply of electricity are recorded as a reduction of purchased power. The amount of excess retail supply sales that reduced purchased power was $265.2 million, $160.4 million and $126.4 million in 2004, 2003 and 2002, respectively.

Strategic Energy utilizes derivatives including forward physical delivery contracts in the procurement of electricity. Changes in the fair value of derivative instruments that do not qualify for hedge accounting and cash flow hedge ineffectiveness reduced purchased power expense by $1.7 million in 2004 and were insignificant for 2003 and 2002.

As previously discussed, Strategic Energy operates in several retail choice electricity markets. The cost of supplying electricity to retail customers can vary widely by geographic market. This variability can be affected by many factors including, among other items, geographic differences in the cost per MWh of purchased power and capacity charges due to regional purchased power availability and requirements of other electricity providers and differences in transmission charges.

37

Purchased power expense increased $278.6 million in 2004 compared to 2003 primarily due to increased MWhs delivered as discussed above. Additionally, average prices per retail MWh purchased increased 7% in 2004 primarily due to the effect of the persistent environment of relatively high natural gas prices, increased competition, increased supply costs on certain contracts caused by customers selecting variable pricing mechanisms and increased tax reserves partially offset by the change in fair value of derivative instruments. Purchased power increased $283.5 million in 2003 compared to 2002 primarily due to increased MWhs delivered.

Strategic Energy Other Operating Expenses Strategic Energy's other operating expenses as a percentage of operating revenues decreased to 3.7%

in 2004 from 3.9% and 4.8% in 2003 and 2002, respectively, due to Strategic Energy's efforts in leveraging its infrastructure and the effects of achieving economies of scale. Strategic Energy's other operating expenses increased $9.2 million in 2004 compared to 2003; a 22% increase driven mainly by higher staffing levels associated with the continued growth of Strategic Energy. Additionally, higher consulting expenses associated with new software development initiatives and higher general tax expenses primarily due to higher capital stock and franchise tax rates increased other operating expenses.

Other operating expenses increased $4.5 million in 2003 compared to 2002 primarily due to higher staffing levels and higher other general and administrative expenses associated with higher sales volumes, geographic market expansion, and regulatory and market development initiatives.

Strategic Energy Income Taxes Strategic Energy's income taxes decreased $5.9 million in 2004 compared to 2003 reflecting lower income and additional tax benefits. The additional benefits included $3.1 million due to the allocation of tax benefits from holding company losses pursuant to the Company's intercompany tax allocation agreement and a slight decrease due to the favorable impact of state tax planning on the composite tax rate. Strategic Energy's income taxes increased $5.0 million in 2003 compared to 2002 primarily reflecting higher income.

Strategic Energy Minority Interest Minority interest represents the share of Strategic Energy's net income not attributable to Great Plains Energy's indirect ownership interest in Strategic Energy. Minority interest decreased $6.1 million in 2004 compared to 2003 primarily due to IEC's acquisition of an additional 11.45% indirect interest in Strategic Energy in May 2004. Minority interest decreased $1.7 million in 2003 compared to 2002 primarily due to IEC's acquisition of a 6% indirect ownership interest in Strategic Energy during the fourth quarter of 2002.

OTHER NON REGULATED ACTIVITIES Investment in Affordable Housing Limited Partnerships - KLT Investments KLT Investments Inc.'s (KLT Investments) net income in 2004 totaled $11.2 million (including an after tax reduction of $4.6 million in its affordable housing investment) compared to net income of $8.1 million in 2003 (including an after tax reduction of $6.7 million in its affordable housing investment) and net income of $10.4 million in 2002 (including an after tax reduction of $5.7 million in its affordable housing investment).

On a quarterly basis, KLT Investments compares the cost of properties accounted for by the cost method to the total of projected residual value of the properties and remaining tax credits to be received. Based on the latest comparison, KLT Investments reduced its investments in affordable housing limited partnerships by $7.5 million, $11.0 million and $9.0 million in 2004, 2003 and 2002, respectively. Pre-tax reductions in affordable housing investments are estimated to be $10 million, $1 million and $2 million in 2005 through and 2007, respectively. These projections are based on the 38

latest information available but the ultimate amount and timing of actual reductions could be significantly different from the above estimates. The properties underlying the partnership investment are subject to certain risks inherent in real estate ownership and management. Even after these estimated reductions, net income from the investments in affordable housing is expected to be positive for 2005 through 2007.

KLT Investments accrued tax credits related to its investments in affordable housing limited partnerships of $18.3 million, $19.1 million and $19.3 million in 2004, 2003 and 2002, respectively. KLT Investments' estimates tax credits will be $16 million, $10 million and $6 million for 2005 through 2007, respectively, and continue to decline through 2009.

DTI Bankruptcy On December 31, 2001, a subsidiary of KLT Telecom, DTI Holdings, Inc. and its subsidiaries, Digital Teleport, Inc. and Digital Teleport of Virginia, Inc., filed separate voluntary petitions in the Bankruptcy Court for the Eastern District of Missouri for reorganization under Chapter 11 of the U.S. Bankruptcy Code, which cases were procedurally consolidated. DTI Holdings and its two subsidiaries are collectively called "DTI". In December 2002, Digital Teleport entered into an agreement to sell substantially all of its assets to CenturyTel Fiber Company II, LLC, a nominee of CenturyTel, Inc, which was approved by the Bankruptcy Court, and closed in 2003.

The Company recorded a net gain of $28.1 million or $0.41 per share in 2003 related to the DTI bankruptcy. The impact on 2003 net income was primarily due to the net effect of the Chapter 11 plan confirmation and the resulting distribution, the reversal of a $15.8 million tax valuation allowance and the reversal of $5 million debtor in possession financing previously reserved.

Holding Company Income Taxes The Company maintains an intercompany tax allocation agreement among the companies that file a consolidated or combined income tax return. Tax benefits from holding company losses are allocated to the subsidiaries based on income and these allocations are reflected in each segment's provision for income taxes. Holding company income taxes increased $6.5 million in 2004 compared to 2003 primarily to reflect the allocation of tax benefits pursuant to the Company's intercompany tax allocation agreement.

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

In 2004, KLT Gas completed sales of substantially all of the KLT Gas portfolio for $23.5 million cash, net of $1.4 million of transaction costs. The gain on the KLT Gas portfolio asset sales totaled $10.3 million, or $0.14 per share. The impact of the gain was partially offset by the loss from the wind down operations of $1.8 million in 2004. Additionally, the 2004 write down of the KLT Gas portfolio to its estimated net realizable value reduced net income by $1.2 million. Loss from discontinued operations in 2003 was $36.1 million including after tax impairments of $33.5 million and after tax operating losses of $2.6 million. See Note 6 to the consolidated financial statements for additional information and see Note 15 to the consolidated financial statements for information regarding a pending arbitration proceeding.

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GREAT PLAINS ENERGY AND CONSOLIDATED KCP&L SIGNIFICANT BALANCE SHEET CHANGES (December 31, 2004 compared to December 31, 2003)

• Great Plains Energy's restricted cash and supplier collateral decreased $13.2 million due to a reduction in the collateral provided from suppliers to cover portions of credit exposure as a result of lower market exposure with counterparties posting cash and one counterparty posting a letter of credit rather than cash.

• Great Plains Energy's receivables increased $6.8 million primarily due to a $35.0 million increase in Strategic Energy's receivables, which was primarily the result of increased sales in late 2004 compared to late 2003. This increase was mostly offset by a $32.3 million decrease in consolidated KCP&L's receivables. Consolidated KCP&L's receivables decreased primarily due to KCP&L's receipt of $30.8 million for the Hawthorn No. 5 insurance recovery.

• Great Plains Energy's and consolidated KCP&L's deferred income taxes (current assets) increased $12.4 million and $12.1 million, respectively, to reflect previously non-current deferred income taxes expected to reverse in 2005 and $4.4 million related to the timing of the Wolf Creek refueling outage.

• Great Plains Energy's assets of discontinued operations decreased $27.1 million due to the sale of KLT Gas' assets in 2004.

• Great Plains Energy's goodwill increased $60.7 million due to the purchase of the additional indirect interest in Strategic Energy in May 2004.

• Great Plains Energy's other deferred charges increased $31.5 million primarily due to $36.1 million in intangible assets, net of amortization, recorded as a result of the purchase of the additional indirect interest in Strategic Energy in May 2004.

• Great Plains Energy's notes payable decreased $67.0 million due to the net repayments of short-term borrowings. Consolidated KCP&L's notes payable to Great Plains Energy decreased

$22.0 million primarily due to HSS' repayment of an intercompany loan mostly related to the disposition of RSAE.

• Great Plains Energy's and consolidated KCP&L's current maturities of long-term debt increased

$193.9 million and $195.5 million, respectively, to reflect KCP&L's $250 million of senior notes scheduled to mature in 2005, partially offset by the retirement of KCP&L's $54.5 million of medium-term notes in 2004.

• Great Plains Energy's and consolidated KCP&L's Environmental Improvement Revenue Refunding (EIRR) bonds classified as current decreased $43.4 million due to scheduled remarketings of EIRR bonds. The new terms changed the classification of certain EIRR bonds to long-term debt.

• Great Plains Energy's other deferred credits and liabilities increased $9.4 million primarily due to an $18.8 million liability for the fair value of acquired retail contracts, net of amortization, partially offset by a $9.0 million reduction in minority interest recorded as a result of the purchase of an additional indirect interest in Strategic Energy in May 2004. An additional increase of $6.7 million was due to recording the FELINE PRIDESSM long-term forward contract fee, partially offset by a $5.3 million decrease in consolidated KCP&L's other deferred credits and liabilities.

Consolidated KCP&L's decrease was primarily due to a $4.6 million decrease in minority interest, which was the result of losses at KCP&L's Lease Trust.

• Great Plains Energy's common stock increased $154.1 million due to the issuance of five million shares of common stock in June 2004 and the issuance of shares for purchases under the Dividend Reinvestment and Direct Stock Purchase Plan plans. Consolidated KCP&L's common stock increased $225.0 million due to equity contributions from Great Plains Energy.

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• Great Plains Energy's capital stock premium and expense increased $24.9 million primarily due to recording $19.6 million of FELINE PRIDES purchase contract adjustment, allocated fees and expenses. Additionally, the June 2004 common stock issuance costs totaled $5.4 million.

• Great Plains Energy's and consolidated KCP&L's long-term debt decreased $201.9 million and

$362.3 million, respectively, to reflect KCP&L's $250 million of senior notes scheduled to mature in 2005 as current and the 2004 redemption of KCP&L's $154.6 million 8.3% Junior Subordinated Deferred Interest Bonds partially offset by KCP&L's EIRR bonds totaling $43.4 million now classified as long-term following the scheduled remarketing during 2004. Great Plains Energy's decrease was further offset by the issuance of $163.6 million of FELINE PRIDES senior notes in 2004.

CAPITAL REQUIREMENTS AND LIQUIDITY Great Plains Energy operates through its subsidiaries and has no material assets other than the stock of its subsidiaries. Great Plains Energy's ability to make payments on its debt securities and its ability to pay dividends is dependent on its receipt of dividends or other distributions from its subsidiaries and proceeds from the issuance of its securities.

Great Plains Energy's capital requirements are principally comprised of KCP&L's utility construction and other capital expenditures, debt maturities, pension benefit plan funding requirements discussed below and credit support provided to Strategic Energy. Additional cash and capital requirements for the companies are discussed below.

Great Plains Energy's liquid resources at December 31, 2004, consisted of $127.1 million of cash and cash equivalents on hand, including $51.6 million at KCP&L, and $795.8 million of unused bank lines of credit. The unused lines consisted of $250.0 million from KCP&L's revolving credit facility, $55.8 million from Strategic Energy's revolving credit facility, and $490.0 million from Great Plains Energy's revolving credit facility. See the Debt Agreements section below for more information on these agreements.

Cash Flows From Operations Great Plains Energy and consolidated KCP&L generated positive cash flows from operating activities for the periods presented. The increase in cash flows from operating activities for Great Plains Energy in 2004 compared to 2003 was primarily due to the changes in working capital detailed in Significant Balance Sheet Changes and in Note 2 to the consolidated financial statements. The individual components of working capital vary with normal business cycles and operations. In addition, the timing of the Wolf Creek outage affects the refueling outage accrual, deferred income taxes and amortization of nuclear fuel. Consolidated KCP&L's cash flow from operations increased in 2004 compared to 2003 partially due to a $17.4 million increase in income from continuing operations and the changes in working capital detailed in Significant Balance Sheet Changes and in Note 2 to the consolidated financial statements.

The increase in cash flows from operating activities for Great Plains Energy in 2003 compared to 2002 is primarily due to a $56.0 million increase in income from continuing operations and the changes in working capital detailed in Significant Balance Sheet Changes and in Note 2 to the consolidated financial statements. Consolidated KCP&L's cash flow from operations increased slightly in 2003 compared to 2002 due to a $26.2 million increase in income from continuing operations and an increase in deferred taxes mostly offset by the changes in working capital detailed in Significant Balance Sheet Changes and in Note 2 to the consolidated financial statements.

Investing Activities Great Plains Energy's and consolidated KCP&L's cash used for investing activities varies with the timing of utility capital expenditures and purchases of investments and nonutility property. Investing 41

activities are offset by the proceeds from the sale of properties and insurance recoveries. Great Plains Energy's and consolidated KCP&L's utility capital expenditures increased $41.9 million in 2004 compared to 2003 primarily due to the $28.5 million buyout of KCP&L's operating lease for vehicles and heavy equipment in 2004. Insurance recoveries and litigation settlements related to Hawthorn No. 5 in 2004 of $31.9 million, a $10.7 million increase over 2003 recoveries, offset cash used in investing activities. Additionally, Great Plains Energy paid $90.0 million to acquire an additional indirect interest in Strategic Energy during 2004.

Utility capital expenditures and the allowance for borrowed funds used during construction increased

$17.9 million in 2003 compared to 2002 primarily due to transmission plant and nuclear fuel additions partially offset by 2002 capital expenditures of $14.7 million related to the January 2002 ice storm and insurance proceeds and partial litigation settlements from Hawthorn No. 5 received in 2003. In 2003, Great Plains Energy received proceeds of $19.2 million as a result of the DTI bankruptcy.

Financing Activities The change in Great Plains Energy's cash flows from financing activities in 2004 compared to 2003 reflects Great Plains Energy's June 2004 gross proceeds of $150.0 million from the issuance of five million shares of common stock at $30 per share and $163.6 million from the issuance of 6.5 million FELINE PRIDES. Fees related to these issuances were $10.2 million. Great Plains Energy used the proceeds to repay short-term borrowings and to make $225.0 million of equity contributions to KCP&L.

In 2004, KCP&L redeemed $154.6 million of 8.3% Junior Subordinated Deferred Interest Bonds from KCPL Financing I. KCPL Financing I used those proceeds to redeem the $4.6 million common securities held by KCP&L and the $150.0 million of 8.3% Trust Preferred Securities. See Note 19 to the consolidated financial statements for additional information. KCP&L also redeemed $54.5 million of its medium-term notes at maturity during 2004.

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

In November 2002, Great Plains Energy entered into an Agreement and Plan of Merger (Agreement) with Environmental Lighting Concepts, Inc. (ELC), the ELC shareholders and IEC, a wholly owned subsidiary of Great Plains Energy, to acquire ELC's 6% indirect interest in Strategic Energy. The ELC Shareholders received $15.1 million in merger consideration. As part of the merger consideration, on November 7, 2002, Great Plains Energy issued 387,596 additional shares of its common stock to the ELC Shareholders. The Agreement valued such shares at approximately $8 million. The remainder of the merger consideration was in short-term notes, which were paid in January 2003.

KCP&L expects to meet day-to-day operating requirements including interest payments, construction requirements (excluding new generating capacity and environmental compliance on existing generating units) and dividends to Great Plains Energy with internally generated funds. However, it might not be able to meet these requirements with internally generated funds because of the effect of inflation on operating expenses, the level of MWh sales, regulatory actions, compliance with future environmental regulations and the availability of generating units. The funds Great Plains Energy and consolidated KCP&L need to retire maturing debt will be provided from operations, the issuance of long and short-term debt and/or the issuance of equity or equity-linked instruments. In addition, the Company may 42 1ll1

issue debt, equity and/or equity-linked instruments to finance growth or take advantage of new opportunities.

Strategic Energy expects to meet day-to-day operating requirements including interest payments, credit support fees, capital expenditures and dividends to its indirect interest holders with internally generated funds. However, it might not be able to meet these requirements with internally generated funds because of the effect of inflation on operating expenses, the level of MWh sales, commodity-price volatility and the effects of counterparty non-performance.

Great Plains Energy filed a registration statement, which became effective in April 2004, for the issuance of an aggregate amount up to $500.0 million of any combination of senior debt securities, subordinated debt securities, trust preferred securities and related guarantees, common stock, warrants, stock purchase contracts or stock purchase units. The prospectus filed with this registration statement also included $148.2 million of securities remaining available to be offered under a prior registration statement providing for an aggregate amount of availability of $648.2 million. In June 2004, Great Plains Energy issued $150.0 million of common stock and $163.6 million of FELINE PRIDES.

After these issuances, $171.0 million remains available under this registration statement, which reflects the effect of the $163.6 million stock purchase contract component of FELINE PRIDES.

As a registered public utility holding company, Great Plains Energy must receive authorization from the SEC under the 35 Act to issue securities. Great Plains Energy is currently authorized to issue up to

$1.2 billion of debt and equity through December 31, 2005. The following table reflects Great Plains Energy's utilization of this amount.

December 31 2004 Preferred stock issued in connection with the (millions)

October 2001 reorganization $ 39.0 Five-year credit facility (a) 28.0 November 2002 common equity offer 151.8 Common equity issued in connection with IEC's 2002 acquisition of an indirect ownership interest in Strategic Energy 8.0 June 2004 common equity offer 150.0 June 2004 FELINE PRIDES 163.6 June 2004 FELINE PRIDES purchase contracts 163.6 Issuance of common stock under the Dividend Reinvestment and Direct Stock Purchase Plan 3.7 Issuance of restricted stock to executives 2.3 Total utilized $ 710.0 (a)This is a $550 million facility; however, at December 31, 2004, the Company could borrow a maximum of $518 million under the 35 Act authorization of which $28 million was outstanding at December 31, 2004.

Under its current SEC authorization, Great Plains Energy cannot issue securities other than common stock unless (i) the security to be issued, if rated, is rated investment grade by one nationally recognized statistical rating organization, (ii) all of its outstanding securities that are rated (except for its preferred stock) are rated investment grade by one nationally recognized statistical rating organization, and (iii) it has maintained common equity as a percentage of consolidated capitalization (as reflected on its consolidated balance sheets as of the end of each quarter) of at least 30%. Great Plains Energy was in compliance with these conditions as of December 31, 2004.

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

KCP&L may issue equity and long-term debt only with the authorization of the MPSC. In June 2004, the MPSC authorized KCP&L to issue up to $600 million of long-term debt through March 31, 2006.

The authorization contains the following conditions, among others: (i) no more than $150.0 million of the authorized debt can be used for purposes other than refinancing existing securities and (ii) the proceeds of the authorized debt must be used exclusively for the benefit of KCP&L's regulated operations.

Issuances of short-term debt by KCP&L are subject to SEC authorization under the 35 Act. Under the current authorization, KCP&L may issue and have outstanding at any given time up to $500 million of short-term debt. Under this authorization, KCP&L cannot issue short-term debt (other than commercial paper or short-term bank facilities) unless (i) the short-term debt to be issued, if rated, is rated investment grade by one nationally recognized statistical rating organization, (ii) all of its outstanding securities that are rated are rated investment grade by one nationally recognized statistical rating organization, (iii) all of the outstanding rated securities of Great Plains Energy (except preferred stock) are rated investment grade and (iv) Great Plains Energy and KCP&L have maintained common equity as a percentage of consolidated capitalization (as reflected on their consolidated balance sheets as of the end of each quarter) of at least 30%. KCP&L was in compliance with these conditions as of December 31, 2004.

In 2004, KCP&L remarketed its secured 1994 series EIRR bonds totaling $35.9 million and its unsecured 1998 Series C EIRR bonds totaling $50.0 million. The bonds are classified as current liabilities in the December 31, 2004, balance sheet. The 1994 series bonds were remarketed with a one-year maturity at a fixed interest rate of 2.25%. The 1998 Series C bonds were remarketed with a one-year maturity at a fixed interest rate of 2.38%. KCP&L also remarketed its secured 1993 series EIRR bonds totaling $12.4 million at a fixed rate of 4.0% until maturity at January 2, 2012.

In 2004, KCP&L secured a municipal bond insurance policy as a credit enhancement to its secured 1992 series EIRR bonds totaling $31.0 million. This municipal bond insurance policy replaced a 364-day credit facility with a bank, which expired in August 2004 that previously supported full liquidity of these bonds. These variable-rate secured EIRR bonds with a final maturity in 2017 are remarketed on a weekly basis through a Dutch auction process.

KCP&L had entered into a revolving agreement to sell all of its right, title and interest in the majority of its customer accounts receivable to Kansas City Power & Light Receivables Company, which in turn sold most of the receivables to outside investors. The agreement expired in January 2005 and was not renewed by KCP&L. KCP&L is currently evaluating alternatives to replace this agreement and intends to enter into a new agreement in 2005. See Note 3 to the consolidated financial statements.

Debt Agreements In December 2004, Great Plains Energy syndicated a $550 million, five-year revolving credit facility with a group of banks replacing a $150.0 million 364-day revolving credit facility and a $150.0 million three-year revolving credit facility with a group of banks that were syndicated earlier in 2004. Those latter two facilities had replaced a prior $225.0 million revolving credit facility with a group of banks. The new facility contains a Material Adverse Change (MAC) clause that requires Great Plains Energy to represent, prior to receiving funding, that no MAC has occurred. The clause does, however, permit the Company to access the facility even in the event of a MAC in order to repay maturing commercial paper. Available liquidity under this facility is not impacted by a decline in credit ratings unless the downgrade results in a MAC or occurs in the context of a merger, consolidation or sale. A default by 44 III

Great Plains Energy or any of its significant subsidiaries of other indebtedness totaling more than $25.0 million is a default under the current facility. Under the terms of this agreement, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At December 31, 2004, the Company was in compliance with this covenant. At December 31, 2004, Great Plains Energy had $20.0 million of outstanding borrowings with an interest rate of 3.04% and had issued letters of credit totaling $8.0 million under the credit facility as credit support for Strategic Energy. At December 31, 2004, Great Plains Energy had $490 million available under this facility due to limitations under its 35 Act authorization.

In December 2004, KCP&L syndicated a $250 million five-year revolving credit facility. This facility replaced $155 million in 364-day bilateral credit lines KCP&L had in place with a group of banks.

KCP&L uses this facility to provide support for its issuance of commercial paper and other general purposes. The new facility contains a MAC clause that requires KCP&L to represent, prior to receiving funding, that no MAC has occurred. The clause does, however, permit KCP&L to access the facility even in the event of a MAC in order to repay maturing commercial paper. Available liquidity under this facility is not impacted by a decline in credit ratings unless the downgrade results in a MAC or occurs in the context of a merger, consolidation or sale. A default by KCP&L on other indebtedness totaling more than $25.0 million is a default under the current facility. Under the terms of the agreement, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At December 31, 2004, KCP&L was in compliance with this covenant. At December 31, 2004, KCP&L had no short-term borrowings outstanding.

During 2004, Strategic Energy syndicated a $125.0 million three-year revolving credit facility with a group of banks. Great Plains Energy has guaranteed $25.0 million of this facility. This facility replaced a $95.0 million revolving credit facility with a group of banks. The existing facility contains a MAC clause that requires Strategic Energy to represent, prior to receiving funding, that no MAC has occurred. A default by Strategic Energy of other indebtedness, as defined in the facility, totaling more than $7.5 million is a default under the facility. Under the terms of this agreement, Strategic Energy is required to maintain a minimum net worth of $62.5 million, a maximum funded indebtedness to EBITDA ratio of 2.25 to 1.00, a minimum fixed charge coverage ratio of at least 1.05 to 1.00 and a minimum debt service coverage ratio of at least 4.00 to 1.00, as those terms are defined in the agreement. In the event of a breach of one or more of these four covenants, so long as no other default has occurred, Great Plains Energy may cure the breach through a cash infusion, a guarantee increase or a combination of the two. At December 31, 2004, Strategic Energy was in compliance with these covenants. At December 31, 2004, $69.2 million in letters of credit had been issued and there were no borrowings under the agreement, leaving $55.8 million of capacity available for loans and additional letters of credit.

Great Plains Energy has agreements with KLT Investments associated with notes KLT Investments issued to acquire its affordable housing investments. Great Plains Energy has agreed not to take certain actions including, but not limited to, merging, dissolving or causing the dissolution of KLT Investments, or withdrawing amounts from KLT Investments if the withdrawals would result in KLT Investments not being in compliance with minimum net worth and cash balance requirements. The agreements also give KLT Investments' lenders the right to have KLT Investments repurchase the notes if Great Plains Energy's senior debt rating falls below investment grade or if Great Plains Energy ceases to own at least 80% of KCP&L's stock. At December 31, 2004, KLT Investments had $5.8 million in outstanding notes, including current maturities.

Under stipulations with the MPSC and the KCC, Great Plains Energy and KCP&L maintain common equity at not less than 30% and 35%, respectively, of total capitalization. Pursuant to an SEC order, 45

Great Plains Energy's and KCP&L's authorization to issue securities is conditioned on maintaining a consolidated common equity capitalization of at least 30% and complying with other conditions described above.

KCP&L Projected Utility Capital Expenditures Total utility capital expenditures, excluding allowance for funds used to finance construction, were

$190.5 million, $148.7 million and $132.0 million in 2004, 2003 and 2002, respectively. Utility capital expenditures projected for the next three years are in the following table.

2005 2006 2007 (millions)

Generating facilities $ 43.4 $ 61.3 $ 47.7 Nuclear fuel 4.6 18.6 23.7 Distribution and transmission facilities 69.1 76.5 90.4 General facilities 18.2 17.7 13.6 Total $135.3 $174.1 $175.4 This utility capital expenditure plan is subject to continual review and change and does not reflect utility capital expenditures for new capacity. These projections could be significantly impacted by KCP&L's comprehensive energy plan for environmental investments and new generation, which has the potential to add approximately $1.1 billion in capital investment for KCP&L over the next five years. See Strategic Intent for additional information.

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

The Company contributed $39.1 million to the plans in 2004, which included $35.0 million of additional funding above the minimum ERISA funding requirements. In 2003, the Company contributed $41.2 million to the plans, which included $26.8 million to cover the 2003 and a portion of the 2004 minimum funding requirements. KCP&L contributed $32.7 million and $39.3 million of the contributions in 2004 and 2003, respectively.

The ERISA funding requirement for 2005 is projected to be $4.7 million, all of which will be paid by KCP&L. Management believes the Company has adequate access to capital resources through cash flows from operations or through existing lines of credit to support the funding requirement. Participants in the plans may request a lump-sum cash payment upon termination of their employment. A change in payment assumptions could result in increased cash requirements from pension plan assets with the Company being required to accelerate future funding.

Under the terms of the pension plans, the Company reserves the right to amend or terminate the plans, and from time to time benefits have changed. See Note 9 to the consolidated financial statements for additional information.

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Credit Ratings At December 31, 2004, the major credit rating agencies rated the companies' securities as detailed in the following table.

Moody's Standard Investors Service and Poor's Great Plains Energy Outlook Negative Stable Corporate Credit Rating BBB Preferred Stock Bal BB+

Senior Unsecured Debt Baa2 BBB-KCP&L Outlook Stable Stable Senior Secured Debt A2 BBB Senior Unsecured Debt A3 BBB Commercial Paper P-2 A-2 The ratings presented reflect the current views of these rating agencies and are subject to change. The companies view maintenance of strong credit ratings as being extremely important and to that end an active and ongoing dialogue is maintained with the agencies with respect to the companies' results of operations, financial position, and future prospects.

None of the companies' outstanding debt, except for the notes associated with affordable housing investments, requires the acceleration of interest and/or principal payments in the event of a ratings downgrade, unless the downgrade occurs in the context of a merger, consolidation, or sale. In the event of a downgrade the companies and/or their subsidiaries may be subject to increased interest costs on their credit facilities. Additionally, in KCP&L's bond insurance policies on its secured 1992 series EIRR bonds totaling $31.0 million and its Series 1993A and 1993B EIRR bonds totaling $79.5 million, KCP&L has agreed to limits on its ability to issue additional mortgage bonds based on the mortgage bond's credit ratings. See Note 19 to the consolidated financial statements.

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

Great Plains Energy Contractual Obligations Payment due by period 2005 2006 2007 2008 2009 After 2009 Total Long-term debt (millions)

Principal $ 253.2 $147.0 $389.6 $ 0.3 $ - $ 505.3 $ 1,295.4 Interest 70.5 53.9 25.9 21.3 21.2 101.9 294.7 Lease obligations 21.4 21.7 13.4 11.1 8.7 85.2 161.5 Pension plans 4.7 - - - - - 4.7 Purchase obligations Fuel 74.2 80.7 63.7 30.9 7.3 43.2 300.0 Purchased capacity 10.9 5.4 5.5 5.6 4.4 24.8 56.6 Purchased power 697.2 201.5 65.6 10.3 3.7 3.7 982.0 Other 32.9 5.2 4.0 4.7 - - 46.8 Total contractual obligations $1,165.0 $515.4 $567.7 $ 84.2 $45.3 $ 764.1 $3,141.7 47

Consolidated KCP&L Contractual Obligations Payment due by period 2005 2006 2007 2008 2009 After 2009 Total Long-term debt (millions)

Principal $ 250.0 $145.2 $225.5 $ - $ - $ 505.3 $1,126.0 Interest 57.1 40.6 24.0 21.2 21.2 101.9 266.0 Lease obligations 20.1 20.5 12.4 10.3 8.7 85.2 157.2 Pension plans 4.7 - - - - - 4.7 Purchase obligations Fuel 74.2 80.7 63.7 30.9 7.3 43.2 300.0 Purchased capacity 10.9 5.4 5.5 5.6 4.4 24.8 56.6 Other 32.9 5.2 4.0 4.7 - - 46.8 Total contractual obligations $ 449.9 $297.6 $335.1 $ 72.7 $41.6 $ 760.4 $ 1,957.3 Long-term debt includes current maturities. Long-term debt principal excludes $0.5 million discount on senior notes and the $0.7 million fair value adjustment to the EIRR bonds related to SFAS No. 133.

EIRR bonds classified as current liabilities of $85.9 million due at various dates during the years 2015 through 2018 are included here on their final maturity date. Variable rate interest obligations are based on rates as of January 1, 2005. See Note 19 to the consolidated financial statements for additional information.

Lease obligations include capital and operating lease obligations; capital lease obligations are $0.2 million per year for the years 2005 through 2009 and total $4.1 million after 2009. Lease obligations also include leases for railcars to serve jointly-owned generating units where KCP&L is the managing partner. KCP&L will be reimbursed by the other owners for about $2.0 million per year ($21.9 million total) of the amounts included in the table above. See Note 13, contractual commitments, to the consolidated financial statements for additional information regarding leases.

Pension plans represent only the minimum funding requirements under ERISA. Minimum funding requirements for future periods are not yet known. The Company's funding policy is to contribute amounts sufficient to meet the minimum funding requirements plus additional amounts as deemed fiscally appropriate; therefore, actual contributions may differ from expected contributions. See Note 9 to the consolidated financial statements for additional information regarding pensions.

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

KCP&L purchases capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable. This can be a cost-effective alternative to new construction. KCP&L has capacity sales agreements not included above that total $11.7 million for 2005, $11.4 million for 2006, $11.2 million per year for 2007 through 2009 and $23.5 million after 2009.

Purchased power represents Strategic Energy's agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Strategic Energy has energy sales contracts not included above for 2005 through 2007 totaling $69.1 million, $8.7 million and $0.6 million, respectively.

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

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Great Plains Energy and consolidated KCP&L have long-term liabilities recorded on their consolidated balance sheets at December 31, 2004, under GAAP that do not have a definitive cash payout date and are not included in the table above.

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

As a registered public utility holding company system, Great Plains Energy must receive authorization from the SEC, under the 35 Act, to issue guarantees on behalf of its subsidiaries. Under its current SEC authorization, guarantees cannot be issued unless (i) all of its outstanding securities that are rated (except for its preferred stock) are rated investment grade and (ii) it has maintained common equity as a percentage of consolidated capitalization (as reflected on its consolidated balance sheets as of the end of each quarter) of at least 30%. Great Plains Energy was in compliance with these conditions as of December 31, 2004. Great Plains Energy is currently authorized to issue up to $600 million of guarantees on behalf of its subsidiaries and the nonutility subsidiaries have $300 million of authorization for guarantees they can issue on behalf of other nonutility subsidiaries. The nonutility subsidiaries cannot issue guarantees unless Great Plains Energy is in compliance with its conditions to issue guarantees.

Other Commercial Commitments Outstanding Amount of commitment expiration per period 2005 2006 2007 2008 2009 After 2009 Total (millions)

Consolidated KCP&L Guarantees $ 1.4 $ 1.0 $ 1.0 $ 1.0 $ 1.0 $ 1.0 $ 6.4 Great Plains Energy Guarantees, including consolidated KCP&L $117.6 $ 1.0 $ 1.0 $ 1.0 $ 1.0 $ 1.1 $122.7 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 $6.4 million over the next six years. In most cases, a subcontractor would indemnify KCP&L for any payments made by KCP&L under these guarantees.

Great Plains Energy and KLT Inc. have provided $116.3 million of guarantees to support certain Strategic Energy power purchases and regulatory requirements. At December 31, 2004, guarantees related to Strategic Energy are as follows:

• Great Plains Energy direct guarantees to counterparties totaling $53.3 million and KLT Inc.

direct guarantees to counterparties totaling $0.1 million, with varying expiration dates,

• Great Plains Energy provides indemnifications to the issuers of surety bonds totaling $29.9 million which expire in 2005,

• Great Plains Energy guarantees related to letters of credit totaling $25.0 million, which expire in 2005 and 2006 and

• Great Plains Energy letters of credit totaling $8.0 million.

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The table above does not include guarantees related to bond insurance policies that KCP&L has as a credit enhancement to its secured 1992 series EIRR bonds totaling $31.0 million and its Series 1993A and 1993B EIRR bonds totaling $79.5 million. The insurance agreement between KCP&L and the issuer of the bond insurance policies provides for reimbursement by KCP&L for any amounts the insurer pays under the bond insurance policies.

RISK FACTORS Actual results in future periods for Great Plains Energy and consolidated KCP&L could differ materially from historical results and the forward-looking statements contained in this report. Factors that might cause or contribute to such differences include, but are not limited to, those discussed below. These and many other factors described in this report, including the factors listed in the "Cautionary Statements Regarding Certain Forward-Looking Information" and "Quantitative and Qualitative Disclosures About Market Risks" sections of this report, could adversely affect the results of operations and financial position of Great Plains Energy and consolidated KCP&L. Risk factors of consolidated KCP&L are also risk factors for Great Plains Energy.

KCP&L Has Operations Risks The operation of KCP&L's electric generation, transmission and distribution systems involves many risks, including breakdown or failure of equipment or processes; operating limitations that may be imposed by equipment conditions, environmental or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; and catastrophic events such as fires, explosions, severe weather or other similar occurrences. These events may reduce revenues or increase costs, or both, at KCP&L, and may materially affect KCP&L's results of operations and financial position.

KCP&L And Strategic Energy Are Affected By Demand, Seasonality And Weather The results of operations of KCP&L and Strategic Energy can be materially affected by changes in weather and customer demand. KCP&L and Strategic Energy estimate customer demand based on historical trends, to procure fuel and purchased power. Differences in customer usage from these estimates due to weather or other factors could materially affect KCP&L's and Strategic Energy's results of operations.

Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. KCP&L is significantly impacted by seasonality with approximately one-third of its retail revenues recorded in the third quarter. Strategic Energy is impacted by seasonality, but to a much lesser extent. In addition, severe weather, including but not limited to tornados, snow, rain and ice storms can be destructive causing outages and property damage that can potentially result in additional expenses and lower revenues. KCP&L's latan and Hawthorn power plants use water from the Missouri River for cooling purposes. A continuing drought in the north central United States has led to record low river levels in the Missouri River reservoir system, resulting in lower water and flow levels in the Missouri River. Low water and flow levels can increase KCP&L's maintenance costs and, if these levels are low enough, could cause KCP&L to modify plant operations.

KCP&L Has Nuclear Exposure KCP&L owns 47% (548 MW) of Wolf Creek. The NRC has broad authority under Federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including Wolf Creek. In the event of non-compliance, the NRC has the authority to impose fines, shutdown the facilities, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Any revised safety requirements promulgated by the NRC could result in substantial capital expenditures at Wolf Creek.

Wolf Creek has the lowest fuel cost per MWh of any of KCP&L's generating units. Although not expected, an extended shut-down of Wolf Creek, whether resulting from NRC action, an incident at the 50 111

plant or otherwise, could have a substantial adverse effect on KCP&L's results of operations and financial position in the event KCP&L incurs higher replacement power and other costs that are not recovered through rates. If a long-term shut down occurred, the state regulatory commissions could reduce rates by excluding the Wolf Creek investment from rate base.

Ownership and operation of a nuclear generating unit exposes KCP&L to risks regarding decommissioning costs at the end of the unit's life. KCP&L contributes annually to a tax-qualified trust fund to be used to decommission Wolf Creek. The funding level assumes a projected level of return on trust assets. If the actual return on trust assets is below the anticipated level, KCP&L could be responsible for the balance of funds required. If returns are lower than the expected level, KCP&L believes a rate increase would be allowed ensuring full recovery of decommissioning costs over the remaining life of the unit.

KCP&L is also exposed to other risks associated with the ownership and operation of a nuclear generating unit, including but not limited to potential liability associated with the potential harmful effects on the environment and human health resulting from the operation of a nuclear generating unit and the storage, handling and disposal of radioactive materials, and to potential retrospective assessments and losses in excess of insurance coverage.

The Company Is Subject to Environmental Laws and the Incurrence of Environmental Liabilities The Company is subject to regulation by federal, state and local authorities with regard to air and other environmental matters primarily through KCP&L's operations. The generation, transmission and distribution of electricity produces and requires disposal of certain hazardous products, 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 effect on Great Plains Energy and consolidated KCP&L results of operations and financial position. KCP&L regularly conducts environmental audits designed to ensure compliance with governmental regulations and to detect contamination.

New environmental laws and regulations affecting KCP&L's operations may be adopted, and new interpretations of existing laws and regulations could be adopted or become applicable to KCP&L or its facilities, which may substantially increase its environmental expenditures in the future. New facilities, or modifications of existing facilities, may require new environmental permits or amendments to existing permits. Delays in the environmental permitting process, denials of permit applications or conditions imposed in permits may materially affect KCP&L's results of operations and financial position. In addition, KCP&L may not be able to recover all of its costs for environmental expenditures through rates at current levels in the future. Under current law, KCP&L is also generally responsible for any on-site liabilities associated with the environmental condition of its facilities that it has previously owned or operated, regardless of whether the liabilities arose before, during or after the time it owned or operated the facilities. The incurrence of material environmental costs or liabilities, without related rate recovery, could have a material adverse effect on KCP&L's results of operations and financial position. See Note 13 to the consolidated financial statements for additional information regarding environmental matters.

KCP&L and Strategic Energy Have Commodity Price Risks KCP&L and Strategic Energy engage in the wholesale and retail marketing of electricity and, accordingly, are exposed to risks associated with the price of electricity. Strategic Energy routinely enters into contracts to purchase and sell electricity in the normal course of business. KCP&L generates, purchases and sells electricity in the retail and wholesale markets.

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Fossil Fuel and Transportation Prices Impact KCP&L's Costs The majority of KCP&L's rates do not contain an automatic fuel adjustment provision, exposing KCP&L to risk from changes in the market prices of coal and natural gas used to generate power and in the cost of coal and natural gas transportation. Changes in KCP&L's fuel mix due to electricity demand, plant availability, transportation issues, fuel prices and other factors can also adversely affect KCP&L's fuel costs. KCP&L's net income may be adversely affected until increased costs are recovered in rates.

KCP&L manages its exposure to coal and coal rail transportation prices through the structure of commercial contracts. KCP&L enters into coal purchase contracts with various suppliers in Wyoming's Powder River Basin to hedge significant portions of its projected coal requirements for upcoming years consistent with KCP&L risk management policies. The remainder of KCP&L's coal requirements are generally insignificant and are fulfilled through additional contracts or spot market purchases. About half of KCP&L's delivered cost of coal is for rail transportation. KCP&L enters into rail transportation contracts to reduce the degree of variability in the delivered cost of coal. Coal rail transportation prices are generally trending upwards, primarily due to rail transportation companies moving away from contract rates to tariff rates, which could impact KCP&L as it renegotiates rail contracts expiring at the end of 2005. KCP&L also hedges its expected natural gas usage for retail load and firm MWh sales consistent with its risk management policies.

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

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

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

As described below, Strategic Energy operates in competitive retail electricity markets, competing against the host utilities and other retail suppliers. Wholesale electricity costs, which account for a significant portion of its operating expenses, can materially affect Strategic Energy's ability to attract and retain retail electricity customers at profitable prices. There is also a regulatory lag that slows the adjustment of host public utility rates in response to changes in wholesale prices. This lag can negatively affect Strategic Energy's ability to compete in a rising wholesale price environment, which is the current environment. Strategic Energy manages wholesale electricity risk by establishing risk limits and entering into contracts to offset some of its positions to balance energy supply and demand; however, Strategic Energy does not hedge its entire exposure to electricity price volatility. As a consequence, its results of operations and financial position may be materially impacted by changes in the wholesale price of electricity.

Strategic Energy Operates in Competitive Retail Electricity Markets Strategic Energy has several competitors that operate in most or all of the same states in which Strategic Energy serves customers. Some of these competitors also operate in states other than where Strategic Energy has operations. It also faces competition in certain markets from regional suppliers 52 11ll

and deregulated utility affiliates formed by holding companies affiliated with regulated utilities to provide retail load in their home market territories. Strategic Energy's competitors vary in size from small companies to large corporations, some of which have significantly greater financial, marketing and procurement resources than Strategic Energy. Additionally, Strategic Energy, as well as its other competitors, must compete with the host utility in order to convince customers to switch from the host utility. Strategic Energy's results of operations and financial position are impacted by the success Strategic Energy has in attracting and retaining customers in these markets.

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

Based on guidelines set by Strategic Energy's Exposure Management Committee, counterparty credit risk is monitored by routinely evaluating the credit quality and performance of its suppliers. Among other things, Strategic Energy monitors counterparty credit ratings, liquidity and results of operations.

As a result of these evaluations, Strategic Energy establishes counterparty credit limits and adjusts the amount of collateral required from its suppliers, among other measures.

Strategic Energy enters into forward contracts with multiple suppliers. At December 31, 2004, Strategic Energy's five largest suppliers under forward supply contracts represented 70% of the total future committed purchases. Four of Strategic Energy's five largest suppliers, or their guarantors, are rated investment grade and the non-investment grade rated supplier collateralizes its position with Strategic Energy. In the event of supplier non-delivery or default, Strategic Energy's results of operations could be affected to the extent the cost of replacement power exceeded the combination of the contracted price with the supplier and the amount of collateral held by Strategic Energy to mitigate its credit risk with the supplier. In addition to the collateral, if any, that the supplier provides, Strategic Energy's risk is further mitigated by the obligation of the supplier to make a default payment equal to the shortfall and to pay liquidated damages in the event of a failure to deliver power. Strategic Energy's results of operations could also be affected, in a given period, if it was required to make a payment upon termination of a supplier contract to the extent that the contracted price with the supplier exceeded the market value of the contract at the time of termination.

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The following table provides information on Strategic Energy's credit exposure to suppliers, net of collateral, as of December 31, 2004. It further delineates the exposure by the credit rating of counterparties and provides guidance on the concentration of credit risk and an indication of the maturity of the credit risk by credit rating of the counterparties.

Number Of Net Exposure Of Counterparties Counterparties Exposure Greater Than Greater Than Before Credit Credit Net 10% Of Net 10% of Net Rating Collateral Collateral Exposure Exposure Exposure External rating (millions) (millions)

Investment Grade $ 49.4 $ - $ 49.4 2 $ 43.9 Non-investment Grade 18.0 14.0 4.0 -

Internal rating Investment Grade 3.9 - 3.9 Non-investment Grade 5.6 5.5 0.1 -

Total $ 76.9 $ 19.5 $ 57.4 2 $ 43.9 Maturity Of Credit Risk Exposure Before Credit Collateral Exposure Less Than Greater Than Total Rating 2 Years 2 - 5 Years 5 Years Exposure External rating (millions)

Investment Grade $ 46.1 $ 3.3 $ - $ 49.4 Non-Investment Grade 13.5 3.8 0.7 18.0 Internal rating Investment Grade 3.8 0.1 - 3.9 Non-Investment Grade 4.2 1.1 0.3 5.6 Total $ 67.6 $ 8.3 $ 1.0 $ 76.9 External ratings are determined by using publicly available credit ratings of the counterparty. If a counterparty has provided a guarantee by a higher rated entity, the determination has been based on the rating of its guarantor. Internal ratings are determined by, among other things, an analysis of the counterparty's financial statements and consideration of publicly available credit ratings of the counterparty's parent. Investment grade counterparties are those with a minimum senior unsecured debt rating of BBB- from Standard & Poor's or Baa3 from Moody's. Exposure before credit collateral has been calculated considering all netting agreements in place, netting accounts payable and receivable exposure with net mark-to-market exposure. Exposure before credit collateral, after consideration of all netting agreements, is impacted significantly by the power supply volume under contract with a given counterparty and the relationship between current market prices and contracted power supply prices. Credit collateral includes the amount of cash deposits and letters of credit received from counterparties. Net exposure has only been calculated for those counterparties to which Strategic Energy is exposed and excludes counterparties exposed to Strategic Energy.

At December 31, 2004, Strategic Energy had exposure before collateral to non-investment grade counterparties totaling $23.6 million, of which 75% is scheduled to mature in less than two years. In addition, Strategic Energy held collateral totaling $19.5 million limiting its exposure to these non-investment grade counterparties to $4.1 million.

Strategic Energy is continuing to pursue a strategy of contracting with national and regional counterparties that have direct supplies and assets in the region of demand. Strategic Energy is also 54 1111

continuing to manage its counterparty portfolio through strict margining, collateral requirements and contract based netting of credit exposures against payable balances.

Great Plains Energy's Ability to Pay Dividends and Meet Financial Obligations Depends on its Subsidiaries Great Plains Energy is a holding company with no significant operations of its own. The primary source of funds for payment of dividends to its shareholders and its financial obligations is dividends paid to it by its subsidiaries. The ability of Great Plains Energy's subsidiaries to pay dividends or make other distributions, and, accordingly, Great Plains Energy's ability to pay dividends on its common stock and meet its financial obligations, will depend on the actual and projected earnings and cash flow, capital requirements and general financial position of its subsidiaries, as well as on regulatory factors, financial covenants, general business conditions and other matters.

The Company has Regulatory Risks The Company is subject to extensive regulation under the 35 Act and Federal and state utility regulation, as described below. Failure to obtain in a timely manner adequate rates or regulatory approvals, adoption of new regulations by Federal or State agencies, or changes to current regulations and interpretations of such regulations may materially affect the Company's business and its results of operations and financial position.

The Company is a Registered Holding Company Under the 35 Act Great Plains Energy and its subsidiaries comprise a registered holding company system under the 35 Act, and are subject to certain limitations and approval requirements with respect to matters such as the structure of the holding company system, payment of dividends out of capital, transactions among affiliates, acquisitions, business combinations, the issuance, sale and acquisition of securities and engaging in business activities not directly related to the utility or energy business.

KCP&L and Strategic Energy are Impacted by Federal and State UtilityRegulation KCP&L is also regulated by the MPSC and KCC with respect to retail rates, accounting matters, standards of service and, in certain cases, the issuance of securities and certification of facilities and service territories. Pursuant to a stipulation entered into in 2002, KCP&L has agreed to file a rate case with the KCC by May 15, 2006. KCP&L currently is engaged in discussions with interested participants, seeking an agreement on a proposed comprehensive energy plan relating to generation additions, environmental and infrastructure improvements, rate recovery and other matters. KCP&L is also subject to regulation by the FERC with respect to wholesale electricity sales and transmission matters and the NRC as to nuclear operations.

Strategic Energy is a participant in the wholesale electricity and transmission markets, and is subject to FERC regulation with respect to wholesale electricity sales. Additionally, Strategic Energy is subject to regulation by state regulatory agencies in states where it has retail customers. Each state has a public utility commission and rules related to retail choice. Each state's rules are distinct and may conflict.

These rules do not restrict the amount Strategic Energy can charge for its services, but can have an impact on Strategic Energy's ability to provide retail electricity services in each state. Additionally, each state regulates the rates of the host public utility, and the timing and amount of changes in host public utility rates can materially affect Strategic Energy's results of operations and financial position.

The Company has Financial Market and Ratings Risks The Company relies on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations.

KCP&L's capital requirements are expected to increase substantially over the next several years if its regulatory plan, which includes environmental and generation investments, is approved. The Company believes that it will maintain sufficient access to these financial markets based upon current credit 55

ratings and market conditions. However, changes in market conditions or credit ratings could adversely affect the companies' ability to access financial markets and could materially affect their results of operations and financial position.

Great Plains Energy, KCP&L and certain of their securities are rated by Moody's and Standard &

Poor's. These ratings impact the Company's cost of funds and Great Plains Energy's ability to provide credit support for its subsidiaries. Additionally, Great Plains Energy and KCP&L must maintain investment-grade ratings from at least one nationally recognized rating agency as a condition of their 35 Act authorization to issue securities.

The Company's Financial Statements Reflect the Application of Critical Accounting Policies The application of the Company's critical accounting policies reflects complex judgments and estimates. These policies include industry-specific accounting applicable to regulated public utilities, accounting for pensions, long-lived assets, derivative instruments and goodwill. The adoption of new GAAP or changes to current accounting policies or interpretations of such policies may materially affect the Company's results of operations and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK In the normal course of business, Great Plains Energy and consolidated KCP&L face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operations and credit risks and are not represented in the following analysis. See Item 7. Management's Discussion and Analysis for further discussion of the companies' risk factors.

Great Plains Energy and consolidated KCP&L are exposed to market risks associated with commodity price and supply, interest rates and equity prices. Management has established risk management policies and strategies to reduce the potentially adverse effects that the volatility of the markets may have on its operating results. During the normal course of business, under the direction and control of internal risk management committees, the companies' hedging strategies are reviewed to determine the hedging approach deemed appropriate based upon the circumstances of each situation. Derivative instruments are frequently utilized to execute risk management and hedging strategies. Derivative instruments are instruments, such as futures, forward contracts, swaps or options that derive their value from underlying assets, indices, reference rates or a combination of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives and instruments that are listed and traded on an exchange. The companies maintain commodity-price risk management strategies that use derivative instruments to minimize significant, unanticipated net income fluctuations caused by commodity price volatility.

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, 2004, a hypothetical 10% increase in the interest rates associated with variable rate debt would result in an increase of less than $1.0 million in interest expense for 2005. Additionally, interest rates impact the fair value of long-term debt. A change in interest rates would impact the Company to the extent it redeemed any of its outstanding long-term debt. Great Plains Energy's and consolidated KCP&L's book values of long-term debt were between 3% and 4% below fair values at December 31, 2004.

Commodity Risk KCP&L and Strategic Energy engage in the wholesale and retail marketing of electricity and are exposed to risk associated with the price of electricity.

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KCP&L's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity and long, intermediate and short-term capacity or power purchase agreements.

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

KCP&L's sales include the sales of electricity to its retail customers and bulk power sales of electricity in the wholesale market. KCP&L continually evaluates its system requirements, the availability of generating units, availability and cost of fuel supply, the availability and cost of purchased power and the requirements of other electric systems; therefore, the impact of the hypothetical amounts that follow could be significantly reduced depending on the system requirements and market prices at the time of the increases. A hypothetical 10% decrease in the market price of power could result in a $3.5 million decrease in operating income for 2005 related to wholesale sales of electricity and purchased power.

In 2005, approximately 77% of KCP&L's net MWhs generated are expected to be coal fired. KCP&L currently has almost all of its coal requirements for 2005 under contract. A hypothetical 10% increase in the market price of coal could result in less than a $1.0 million increase in fuel expense for 2005.

KCP&L has also implemented price risk mitigation measures to reduce its exposure to high natural gas prices. A hypothetical 10% increase in natural gas and oil market prices could result in an increase of less than $1.0 million in fuel expense for 2005. As of December 31, 2004, KCP&L had slightly under half of its 2005 projected natural gas usage for retail load and firm MWh sales hedged, which is less than the percentages for 2004 hedged as of December 31, 2003.

Strategic Energy maintains a commodity-price risk management strategy that uses forward physical energy purchases and derivative instruments to minimize significant, unanticipated net income fluctuations caused by commodity-price volatility. In certain markets where Strategic Energy operates, entering into forward fixed price contracts is cost prohibitive. Derivative instruments, primarily swaps, are used to limit the unfavorable effect that price increases will have on electricity purchases, effectively fixing the future purchase price of electricity for the applicable forecasted usage and protecting Strategic Energy from significant price volatility. A hypothetical 10% increase in the cost of purchased power could result in less than $1.0 million increase in purchased power expense for 2005.

The effectiveness of the companies' policies and procedures for managing risk exposure can never be completely estimated or fully assured. The Company could experience losses, which could have a material adverse effect on its results of operations or financial position, from unexpectedly large or rapid movements or disruptions in the energy markets, from regulatory-driven market rule changes and/or bankruptcy of customers or counterparties.

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, 2004, these funds were invested primarily in domestic equity securities and fixed income securities and are reflected at fair value on KCP&L's balance sheets. The mix of securities is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs; however, the equity securities in the trusts are exposed to price fluctuations in equity markets and the value of fixed rate fixed income securities are exposed to changes in interest rates. Investment performance and asset allocation are periodically 57

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 $4.2 million reduction in the value of the decommissioning trust funds at December 31, 2004. A hypothetical 10% decrease in equity prices would have resulted in a $3.9 million reduction in the fair value of the equity securities at December 31, 2004. 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 could result in a decrease of less than $1.0 million in pre-tax net income for 2005.

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GREAT PLAINS ENERGY Consolidated Statements of Income Year Ended December 31 2004 2003 2002 Operating Revenues (thousands, except per share amounts)

Electric revenues - KCP&L $ 1,090,067 $ 1,054,900 $ 1,009,868 Electric revenues - Strategic Energy 1,370,760 1,089,663 788,278 Other revenues 3,191 3,482 4,147 Total 2,464,018 2,148,045 1,802,293 Operating Expenses Fuel 179,362 160,327 159,666 Purchased power - KCP&L 52,533 53,163 46,214 Purchased power - Strategic Energy 1,247,522 968,967 685,370 Other 324,237 295,383 276,632 Maintenance 83,603 85,416 91,419 Depreciation and amortization 150,071 142,763 146,757 General taxes 102,756 98,461 97,146 (Gain) loss on property 5,133 (23,703) (1,376)

Total 2,145,217 1,780,777 1,501,828 Operating income 318,801 367,268 300,465 Non-operating income 6,799 7,414 5,839 Non-operating expenses (15,184) (20,462) (18,948)

Interest charges (83,030) (76,171) (87,380)

Income from continuing operations before income taxes, minority interest in subsidiaries and loss from equity investments 227,386 278,049 199,976 Income taxes (54,451) (78,565) (51,348)

Minority interest in subsidiaries 2,131 (7,764) (10,753)

Loss from equity investments (1,531) (2,018) (1,173)

Income from continuing operations 173,535 189,702 136,702 Discontinued operations, net of income taxes (Notes 6 and 7) 7,276 (44,779) (7,514)

Cumulative effect of a change in accounting principle (Note 5) (3,000)

Net income 180,811 144,923 126,188 Preferred stock dividend requirements 1,646 1,646 1,646 Earnings available for common stock $ 179,165 $ 143,277 $ 124,542 Average number of common shares outstanding 72,028 69,206 62,623 Basic and diluted earnings (loss) per common share Continuing operations $ 2.39 $ 2.72 $ 2.16 Discontinued operations 0.10 (0.65) (0.12)

Cumulative effect - - (0.05)

Basic and diluted earnings per common share $ 2.49 $ 2.07 $ 1.99 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.

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GREAT PLAINS ENERGY Consolidated Balance Sheets December 31 2004 2003 ASSETS (thousands)

Current Assets Cash and cash equivalents $ 127,129 $ 114,227 Restricted cash 7,700 20,850 Receivables, net 247,184 240,344 Fuel inventories, at average cost 21,121 22,543 Materials and supplies, at average cost 54,432 56,599 Deferred income taxes 13,065 686 Assets of discontinued operations 749 27,830 Other 20,857 14,293 Total 492,237 497,372 Nonutility Property and Investments Affordable housing limited partnerships 41,317 52,644 Nuclear decommissioning trust fund 84,148 74,965 Other 32,739 44,428 Total 158,204 172,037 Utility Plant, at Original Cost Electric 4,841,355 4,700,983 Less-accumulated depreciation 2,196,835 2,082,419 Net utility plant in service 2,644,520 2,618,564 Construction work in progress 53,821 53,250 Nuclearfuel, netof amortization of $127,631 and $113,472 36,109 29,120 Total 2,734,450 2,700,934 Deferred Charges Regulatory assets 144,345 145,627 Prepaid pension costs 119,811 108,247 Goodwill 86,767 26,105 Other deferred charges 63,087 31,628 Total 414,010 311,607 Total $ 3,798,901 $ 3,681,950 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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GREAT PLAINS ENERGY Consolidated Balance Sheets December 31 2004 2003 LIABILITIES AND CAPITALIZATION (thousands)

Current Liabilities Notes payable $ 20,000 $ 87,000 Current maturities of long-term debt 253,230 59,303 EIRR bonds classified as current 85,922 129,288 Accounts payable 199,952 186,747 Accrued taxes 46,993 39,886 Accrued interest 11,598 11,937 Accrued payroll and vacations 32,462 34,762 Accrued refueling outage costs 13,180 1,760 Supplier collateral 7,700 20,850 Liabilities of discontinued operations 2,129 4,607 Other -

24,931 28,944 Total 698,097 605,084 Deferred Credits and Other Liabilities Deferred income taxes 632,160 609,333 Deferred investment tax credits 33,587 37,571 Asset retirement obligations 113,674 106,694 Pension liability 95,805 89,488 Other 88,524 79,141 Total 963,750 922,227 Capitalization Common stock equity Common stock-1 50,000,000 shares authorized without par value 74,394,423 and 69,259,203 shares issued, stated value 765,482 611,424 Unearned compensation (1,393) (1,633)

Capital stock premium and expense (32,112) (7,240)

Retained earnings 451,491 391,750 Treasury stock-28,488 and 3,265 shares, at cost (856) (121)

Accumulated other comprehensive loss (41,018) (36,886)

Total 1,141,594 957,294 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 Total 39,000 39,000 Long-term debt (Note 19) 956,460 1,158,345 Total 2,137,054 2,154,639 Commitments and Contingencies (Note 13)

Total $ 3,798,901 $ 3,681,950 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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GREAT PLAINS ENERGY Consolidated Statements of Cash Flows Year Ended December 31 2004 2003 2002 Cash Flows from Operating Activities (thousands)

Net income $ 180,811 $ 144,923 $ 126,188 Less: Discontinued operations, net of income taxes 7,276 (44,779) (7,514)

Income from continuing operations 173,535 189,702 133,702 Adjustments to reconcile income to net cash from operating activities:

Cumulative effect of a change in accounting principles 3,000 Depreciation and amortization 150,071 142,763 146,757 Amortization of:

Nuclear fuel 14,159 12,334 13,109 Other 11,827 11,626 12,461 Deferred income taxes, net 20,286 30,471 12,009 Investment tax credit amortization (3,984) (3,994) (4,183)

Loss from equity investments 1,531 2,018 1,173 (Gain) loss on property 5,133 (23,703) (1,376)

Deferred storm costs (20,149)

Minority interest in subsidiaries (2,131) 7,764 10,753 Other operating activities (Note 2) 6,693 (2,254) 25,067 Net cash from operatina activities 377.120 366.727 332.323 Cash Flows from Investing Activities Utility capital expenditures (190,548) (148,675) (131,158)

Allowance for borrowed funds used during construction (1,498) (1,368) (979)

Purchases of investments (38,556) (3,520) (7,134)

Purchases of nonutility property (6,108) (3,256) (2,788)

Proceeds from sale of assets and investments 43,949 32,556 7,821 Purchase of additional indirect interest in Strategic Energy (90,033) - -

Hawthorn No. 5 partial insurance recovery 30,810 3,940 Hawthorn No. 5 partial litigation settlements 1,139 17,263 Other investing activities (7,081) (1,220) (3,748)

Net cash from investing activities (257,926) (104,280) (137,986)

Cash Flows from Financing Activities Issuance of common stock 153,662 - 151,800 Issuance of long-term debt 163,600 - 224,539 Issuance costs (14,496) (266) (9,962)

Repayment of long-term debt (213,943) (133,181) (238,384)

Net change in short-term borrowings (67,000) 43,846 (172,001)

Dividends paid (120,806) (116,527) (107,424)

Other financing activities (7,309) (7,598) (5,517)

Net cash from financing activities (106,292) (213,726) (156,949)

Net Change in Cash and Cash Equivalents 12,902 48,721 37,388 Cash and Cash Equivalents from Continuing Operations at Beginning of Year 114,227 65,506 28,118 Cash and Cash Equivalents from Continuing Operations at End of Year $ 127,129 $ 114,227 $ 65,506 Net Change in Cash and Cash Equivalents from Discontinued Operations $ 458 $ 73 $ (821)

Cash and Cash Equivalents from Discontinued Operations at Beginning of Year 168 95 916 Cash and Cash Equivalents from Discontinued Operations at End of Year $ 626 $ 168 $ 95 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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GREAT PLAINS ENERGY Consolidated Statements of Common Stock Equity 2004 2003 2002 Shares Amount Shares Amount Shares Amount Common Stock (thousands, except share amounts)

Beginning balance 69,259,203 $ 611,424 69,196,322 $ 609,497 61,908,726 $ 449,697 Issuance of common stock 5,121,887 153,662 - - 7,287,596 159,800 Issuance of restricted common stock 13,333 396 62,881 1,927 - -

Ending balance 74,394,423 765,482 69,259,203 611,424 69,196,322 609,497 Unearned Compensation Beginning balance (1,633)

Issuance of restricted common stock (396) (1,927)

Compensation expense recognized 636 294 Ending balance (1,393) (1,633)

Capital Stock Premium and Expense Beginning balance (7,240) (7,744) (1,656)

Issuance of common stock (5,434) (6,096)

FELINE PRIDESsM purchase contract adjustment, allocated fees and expenses (19,603)

Other 165 504 8 Ending balance (32,112) (7,240) (7,744)

Retained Earnings Beginning balance 391,750 363,579 344,815 Net income 180,811 144,923 126,188 Loss on reissuance of treasury stock (193)

Dividends:

Common stock (119,160) (114,881) (105,778)

Preferred stock - at required rates (1,646) (1,646) (1,646)

Options (71) (225)

Ending balance 451,491 391,750 363,579 Treasury Stock Beginning balance (3,265) (121) (152) (4) (35,916) (903)

Treasury shares acquired (54,683) (1,645) (85,000) (2,332) (17,000) (435)

Treasury shares reissued 29,460 910 81,887 2,215 52,764 1,334 Ending balance (28,488) (856) (3,265) (121) (152) (4)

Accumulated Other Comprehensive Loss Beginning balance (36,886) (25,858) (13,141)

Derivative hedging activity, net of tax 931 (598) 13,037 Minimum pension obligation, net of tax (5,063) (10,430) (25,754)

Ending balance (41,018) (36,886) (25,858)

Total Common Stock Equity $ 1,141,594 $ 957,294 $ 939,470 The accompanying Notes to Consolidated Financial Statements are an Integral part of these statements.

63

GREAT PLAINS ENERGY Consolidated Statements of Comprehensive Income Year Ended December 31 2004 2003 2002 (thousands)

Net income $ 180,811 $ 144.923 $ 126,188 Other comprehensive income Gain on derivative hedging instruments 2,649 7,712 17,584 Income taxes (1,126) (3,359) (7,138)

Net gain on derivative hedging instruments 1,523 4,353 10,446 Reclassification to revenues and expenses, net of tax (592) (4,951) 2,591 Derivative hedging activity, net of tax 931 (598) 13,037 Change in minimum pension obligation (7,624) (17,100) (42,218)

Income taxes 2,561 6,670 16,464 Net change in minimum pension obligation (5,063) (10,430) (25,754)

Comprehensive income $ 176,679 $ 133,895 $ 113,471 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

64 111

KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Income Year Ended December 31 2004 2003 2002 Operating Revenues (thousands)

Electric revenues $ 1,090,067 $ 1,054,900 $ 1,009,868 Other revenues 1,568 2,101 2,918 Total 1,091,635 1,057,001 1,012,786 Operating Expenses Fuel 179,362 160,327 159,666 Purchased power 52,533 53,163 46,214 Other 259,699 241,701 224,618 Maintenance 83,535 85,391 91,333 Depreciation and amortization 145,246 140,955 145,569 General taxes 98,984 95,590 95,546 (Gain) loss on property 5,133 (1,603) (178)

Total 824,492 775,524 762,768 Operating income 267,143 281,477 250,018 Non-operating income 5,402 5,251 4,641 Non-operating expenses (7,407) (8,280) (8,830)

Interest charges (74,170) (70,294) (80,306)

Income from continuing operations before income taxes and minority interest in subsidiaries 190,968 208,154 165,523 Income taxes (52,763) (83,572) (62,857)

Minority interest in subsidiaries 5,087 1,263 -

Income from continuing operations 143,292 125,845 102,666 Discontinued operations, net of income taxes (Note 7) (8,690) (3,967)

Cumulative effect of a change in accounting principle (Note 5) - - (3,000)

Net income $ 143,292 $ 117,155 $ 95,699 The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

65

KANSAS CITY POWER & LIGHT COMPANY Consolidated Balance Sheets December 31 2004 2003 ASSETS (thousands)

Current Assets Cash and cash equivalents $ 51,619 $ 26,520 Receivables, net 63,366 95,635 Fuel inventories, at average cost 21,121 22,543 Materials and supplies, at average cost 54,432 56,599 Deferred income taxes 12,818 686 Other 12,874 8,611 Total 216,230 210,594 Nonutility Property and Investments Nuclear decommissioning trust fund 84,148 74,965 Other 20,576 34,255 Total 104,724 109,220 Utility Plant, at Original Cost Electric 4,841,355 4,700,983 Less-accumulated depreciation 2,196,835 2,082,419 Net utility plant in service 2,644,520 2,618,564 Construction work in progress 53,821 53,046 Nuclear fuel, net of amortization of $127,631 and $113,472 36,109 29,120 Total 2,734,450 2,700,730 Deferred Charges Regulatory assets 144,345 145,627 Prepaid pension costs 116,024 106,888 Other deferred charges 21,621 29,517 Total 281,990 282,032 Total $ 3,337,394 $ 3,302,576 The disclosures regarding KCP&L included inthe accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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KANSAS CITY POWER & LIGHT COMPANY Consolidated Balance Sheets December 31 2004 2003 LIABILITIES AND CAPITALIZATION (thousands)

Current Liabilities Notes payable to Great Plains Energy $ 24 $ 21,983 Current maturities of long-term debt 250,000 54,500 EIRR bonds classified as current 85,922 129,288 Accounts payable 84,105 82,353 Accrued taxes 34,497 41,114 Accrued interest 9,800 11,763 Accrued payroll and vacations 22,870 20,486 Accrued refueling outage costs 13,180 1,760 Other 8,327 8,619 Total 508,725 371,866 Deferred Credits and Other Liabilities Deferred income taxes 654,055 641,673 Deferred investment tax credits 33,587 37,571 Asset retirement obligations 113,674 106,694 Pension liability 90,491 84,434 Other 46,933 52,196 Total 938,740 922,568 Capitalization Common stock equity Common stock-1,000 shares authorized without par value I share issued, stated value 887,041 662,041 Retained earnings 252,893 228,761 Accumulated other comprehensive loss (40,334) (35,244)

Total 1,099,600 855,558 Long-term debt (Note 19) 790,329 1,152,584 Total 1,889,929 2,008,142 Commitments and Contingencies (Note 13)

Total $ 3,337,394 $ 3,302,576 The disclosures regarding KCP&L included inthe accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Cash Flows Year Ended December 31 2004 2003 2002 Cash Flows from Operating Activities (thousands)

Net income $ 143,292 $ 117,155 $ 95,699 Less: Discontinued operations, net of income taxes (8,690) (3,967)

Income from continuing operations 143,292 125,845 99,666 Adjustments to reconcile income to net cash from operating activities:

Cumulative effect of a change in accounting principles 3,000 Depreciation and amortization 145,246 140,955 145,569 Amortization of:

Nuclear fuel 14,159 12,334 13,109 Other 7,719 9,350 9,546 Deferred income taxes, net 10,861 34,285 11,355 Investment tax credit amortization (3,984) (3,994) (4,183)

(Gain) loss on property 5,133 (1,603) (178)

Deferred storm costs (20,149)

Minority interest in subsidiaries (5,087) (1,263)

Other operating activities (Note 2) (1,080) (34,536) 21,178 Net cash from operating activities 316,259 281,373 278,913 Cash Flows from Investing Activities Utility capital expenditures (190,548) (148,675) (132,039)

Allowance for borrowed funds used during construction (1,498) (1,368) (979)

Purchases of investments (3,553) (3,520) (3,421)

Purchases of nonutility property (254) (147) (225)

Proceeds from sale of assets 7,465 4,135 Hawthorn No. 5 partial insurance recovery 30,810 3,940 Hawthorn No. 5 partial litigation settlements 1,139 17,263 Other investing activities (7,100) (4,045) (4,084)

Net cash from investing activities (163,539) (132,417) (140,748)

Cash Flows from Financing Activities Issuance of long-term debt - - 224,539 Repayment of long-term debt (209,140) (124,000) (227,000)

Net change in short-term borrowings (21,959) (341) (61,750)

Dividends paid to Great Plains Energy (119,160) (98,000) (105,617)

Equity contribution from Great Plains Energy 225,000 100,000 36,000 Issuance costs (2,362) (266) (4,269)

Net cash from financing activities (127,621) (122,607) (138,097)

Net Change in Cash and Cash Equivalents 25,099 26,349 68 Cash and Cash Equivalents from Continuing Operations at Beginning of Year 26,520 171 103 Cash and Cash Equivalents from Continuing Operations at End of Year $ 51,619 $ 26,520 $ 171 Net Change in Cash and Cash Equivalents from Discontinued Operations $ - $ (307) $ (552)

Cash and Cash Equivalents from Discontinued Operations at Beginning of Year - 307 859 Cash and Cash Equivalents from Discontinued Operations at End of Year $ - $ - $ 307 The disclosures regarding KCP&L included in the accompanying Notes to Consolidated Financial Statements are an integral par of these statements.

68

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KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Common Stock Equity 2004 2003 2002 Shares Amount Shares Amount Shares Amount Common Stock (thousands, except share amounts)

Beginning balance 1 $ 662,041 1 $ 562,041 1 $ 526,041 Equity contribution from Great Plains Energy - 225,000 - 100,000 - 36,000 Ending balance 1 887,041 1 662,041 1 562,041 Retained Earnings Beginning balance 228,761 209,606 219,524 Net income 143,292 117,155 95,699 Dividends:

Common stock held by Great Plains Energy (119,160) (98,000) (105,617)

Ending balance 252,893 228,761 209,606 Accumulated Other Comprehensive Loss Beginning balance (35,244) (26,614) (1,182)

Derivative hedging activity, net of tax (233) (83) 322 Minimum pension obligation, net of tax (4,857) (8,547) (25,754)

Ending balance (40,334) (35,244) (26,614)

Total Common Stock Equity $ 1,099,600 $ 855,558 $ 745,033 The disclosures regarding KCP&L included inthe accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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KANSAS CITY POWER & LIGHT COMPANY Consolidated Statements of Comprehensive Income Year Ended December 31 2004 2003 2002 (thousands)

Net income $ 143,292 S 117,155 $ 95,699 Other comprehensive income Gain on derivative hedging instruments 280 657 702 Income taxes (111) (256) (274)

Net gain on derivative hedging instruments 169 401 428 Reclassification to revenues and expenses, net of tax (402) (484) (106)

Derivative hedging activity, net of tax (233) (83) 322 Change in minimum pension obligation (7,321) (14,012) (42,218)

Income taxes 2,464 5,465 16,464 Net change in minimum pension obligation (4,857) (8,547) (25,754)

Comprehensive income $ 138,202 $ 108,525 $ 70,267 The disclosures regarding KCP&L included inthe accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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GREAT PLAINS ENERGY INCORPORATED KANSAS CITY POWER & LIGHT COMPANY Notes to Consolidated Financial Statements The notes to consolidated financial statements that follow are a combined presentation for Great Plains Energy Incorporated and Kansas City Power & Light Company, both registrants under this filing. The terms "Great Plains Energy," "Company," "KCP&L" and "consolidated KCP&L" are used throughout this report. "Great Plains Energy" and the "Company" refer to Great Plains Energy Incorporated and its consolidated subsidiaries, unless otherwise indicated. "KCP&L" refers to Kansas City Power & Light Company, and "consolidated KCP&L" refers to KCP&L and its consolidated subsidiaries.

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Organization Great Plains Energy, a Missouri corporation incorporated in 2001, is a public utility holding company registered with and subject to the regulation of the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935, as amended (35 Act). Great Plains Energy does not own or operate any significant assets other than the stock of its subsidiaries.

Great Plains Energy has five direct subsidiaries:

• KCP&L is an integrated, regulated electric utility, which provides electricity to customers primarily in the states of Missouri and Kansas. KCP&L's wholly owned subsidiary, Home Service Solutions Inc. (HSS) has invested in Worry Free Service, Inc. (Worry Free). HSS entered into a letter of intent to sell Worry Free in December 2004 and closed the sale in February 2005. Prior to the June 2003 disposition of R.S. Andrews Enterprises, Inc. (RSAE),

HSS held an investment in RSAE. See Note 7 for additional information concerning the June 2003 disposition of RSAE.

• KLT Inc. is an intermediate holding company that primarily holds, directly or indirectly, interests in Strategic Energy, L.L.C. (Strategic Energy) and affordable housing limited partnerships.

Strategic Energy provides competitive electricity supply services in several electricity markets offering retail choice. KLT Inc. wholly owns KLT Gas Inc. (KLT Gas). In February 2004, the Board of Directors approved the sale of the KLT Gas natural gas properties (KLT Gas portfolio) and discontinuation of the gas business. KLT Gas completed sales of substantially all of the KLT Gas portfolio in 2004. See Note 6 for additional information.

• Great Plains Power Incorporated (GPP) focuses on the development of wholesale generation.

Management decided during 2002 to limit the operations of GPP to the siting and permitting process that began in 2001 for potential new generation. GPP has made no significant investments to date.

• Innovative Energy Consultants Inc. (IEC) is an intermediate holding company that holds an indirect interest in Strategic Energy. IEC does not own or operate any assets other than its indirect interest in Strategic Energy. When combined with KLT Inc.'s indirect interest in Strategic Energy, the Company owns just under 100% of the indirect interest in Strategic Energy.

• Great Plains Energy Services Incorporated (Services) was formed to provide services at cost to Great Plains Energy and its subsidiaries, including consolidated KCP&L, as a service company under the 35 Act.

The operations of Great Plains Energy and its subsidiaries are divided into two reportable segments, KCP&L and Strategic Energy. Great Plains Energy's legal structure differs from the functional management and financial reporting of its reportable segments. Other activities not considered a 71

reportable segment include the operations of HSS, GPP, Services, all KLT Inc. operations other than Strategic Energy, and holding company operations.

Financial Statement Presentation Certain prior year amounts have been reclassified to conform to current year presentation.

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

For Great Plains Energy this includes Strategic Energy's cash held in trust of $21.0 million and

$16.1 million at December 31, 2004 and 2003, respectively.

Strategic Energy has entered into collateral arrangements with selected electricity power suppliers that require selected customers to remit payment to lockboxes that are held in trust and managed by a Trustee. As part of the trust administration, the Trustee remits payment to the supplier of electricity purchased by Strategic Energy. On a monthly basis, any remittances into the lockboxes in excess of disbursements to the supplier are remitted back to Strategic Energy.

Restricted Cash Strategic Energy has entered into Master Power Purchase and Sale Agreements with its power suppliers. Certain of these agreements contain provisions whereby, to the extent Strategic Energy has a net exposure to the purchased power supplier, collateral requirements are to be maintained.

Collateral posted in the form of cash to Strategic Energy is restricted by agreement, but would become unrestricted in the event of a default by the purchased power supplier. Restricted cash collateral at December 31, 2004 and 2003, was $7.7 million and $20.9 million, respectively.

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

Nonutility Property and Investments - Consolidated KCP&L's investments and nonutility property includes the nuclear decommissioning trust fund recorded at fair value. Fair value is based on quoted market prices of the investments held by the fund. In addition to consolidated KCP&L's investments, Great Plains Energy's investments and nonutility property include KLT Investments Inc.'s (KLT Investments) affordable housing limited partnerships. 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. Great Plains Energy's and consolidated KCP&L's book values of long-term debt were between 3% and 4% below fair values at December 31, 2004.

Derivative Instruments The Company accounts for derivative instruments in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities,"

as amended. This statement generally requires derivative instruments to be recorded on the balance sheet at fair value and establishes criteria for designation and effectiveness of hedging relationships.

The Company enters into derivative contracts to manage its exposure to commodity price fluctuations and interest rate risk. All derivative instruments are used solely for hedging purposes and are not issued or held for speculative reasons.

72 IlIll

The Company's policy is to elect normal purchases and normal sales exception (NPNS), in accordance with SFAS No. 133, for derivative contracts that qualify for this accounting treatment. The appropriate accounting treatment for NPNS designation for derivative contracts is accrual accounting, which requires the effects of the derivative to be recorded when the derivative contract settles.

The Company records derivative instruments that are not accounted for as NPNS as assets or liabilities on the consolidated balance sheets at fair value. The fair value of derivative instruments is estimated using market quotes, over-the-counter forward price and volatility curves and correlation among power and fuel prices, net of estimated credit risk. Changes in the fair value of derivatives are recorded each period in net income unless specific hedge accounting criteria are met. Changes in the fair value of derivative instruments recorded to other comprehensive income (OCI) are reclassified to revenues and expenses in the period when the forecasted transaction occurs. The portion of the change in fair value of a derivative instrument determined to be ineffective is immediately recognized in net income. See Note 21 for additional information regarding derivative financial instruments and hedging activities.

Investments in Affordable Housing Limited Partnerships At December 31, 2004, KLT Investments had $41.3 million in affordable housing limited partnerships.

Approximately 65% 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. 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, $26.0 million exceed this 5% level but were made before May 19, 1995. Management does not anticipate making additional investments in affordable housing limited partnerships at this time.

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. Based on the latest comparison, KLT Investments reduced its investments in affordable housing limited partnerships by $7.5 million, $11.0 million and $9.0 million in 2004, 2003 and 2002, respectively. These amounts are included in Non-operating expenses on Great Plains Energy's consolidated statements of income. The properties underlying the partnership investments are subject to certain risks inherent in real estate ownership and management.

Natural Gas Properties Included in Assets of Discontinued Operations During 2004, KLT Gas completed sales of substantially all of the KLT Gas portfolio, and natural gas properties had a zero-balance at December 31, 2004. At December 31, 2003, natural gas property and equipment included in Assets of Discontinued Operations on Great Plains Energy's consolidated balance sheets totaled $9.8 million, net of $63.8 million of accumulated depreciation and impairments.

See Note 6 for information regarding the impairment and sale of KLT Gas assets and discontinued operations.

Other Nonutility Property Great Plains Energy's and consolidated KCP&L's other nonutility property includes land, buildings, vehicles, general office equipment and software and is recorded at historical cost, net of accumulated depreciation, and has a range of estimated useful lives of 3 to 50 years.

Utility Plant KCP&L's utility plant is stated at historical costs of construction. These costs include taxes, an allowance for the cost of borrowed and equity funds used to finance construction and payroll-related costs, including pensions and other fringe benefits. Replacements, improvements and additions to 73

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, is charged to accumulated depreciation. Substantially all utility plant is pledged as collateral for KCP&L's mortgage bonds under the General Mortgage Indenture and Deed of Trust dated December 1, 1986, as supplemented.

The balances of utility plant in service with a range of estimated useful lives are listed in the following table.

December 31 2004 2003 Utility Plant In Service (millions)

Production (23 - 42 years) $ 2,938.5 $ 2,913.9 Transmission (27 -76 years) 315.5 308.3 Distribution (8 - 75 years) 1,320.0 1,261.6 General (5 - 50 years) 267.4 217.2 Total "I $ 4,841.4 $ 4,701.0 (a)Includes $89.1 million and $66.7 million of land and other assets for which depreciation was not recorded in 2004 and 2003, respectively.

Through December 31, 2004, KCP&L had received $194.8 million in insurance recoveries related to property destroyed in the 1999 explosion at the Hawthorn No. 5 generating unit. An additional $10.0 million in insurance recoveries was received in early 2005. Additionally, KCP&L filed suit against multiple defendants who are alleged to have responsibility for the explosion. Various defendants have settled with KCP&L for a total of $38.2 million through December 31, 2004, of which $18.5 million was recorded as a recovery of capital expenditures. Recoveries received related to property destroyed and subrogation settlements recorded as a recovery of capital expenditures have been recorded as an increase in accumulated depreciation.

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

in 2003 and 4.4% in 2002.

In 2001, the American Institute of Certified Public Accountants issued an exposure draft on a proposed Statement of Position (SOP) "Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment." In 2004, the Financial Accounting Standards Board (FASB) objected to final clearance of the proposed SOP and removed the project from its agenda. No further discussion or action related to this SOP is expected.

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

Depreciation of nonutility property is computed using the straight-line method. Consolidated KCP&L's nonutility property annual depreciation rates for 2004, 2003 and 2002 were 12.3%, 11.5% and 10.7%,

respectively. Other Great Plains Energy nonutility property annual depreciation rates for 2004, 2003 and 2002 were 24.2%, 21.2% and 15.7%, respectively. Other Great Plains Energy's nonutility property 74 1III

includes Strategic Energy's depreciable assets, which are primarily software costs and are amortized over a shorter time period, three years, resulting in a higher annual depreciation rate.

As part of the acquisition of additional interest in Strategic Energy, IEC recorded intangible assets that have finite lives and are subject to amortization. These intangible assets include the fair value of acquired supply contracts, customer relationships and asset information systems, which are being amortized over 28, 72 and 44 months, respectively. See Note 8 for additional discussion of the May 2004 acquisition of an additional indirect interest in Strategic Energy.

Natural gas properties sold in 2004 were included in Assets of Discontinued Operations in 2003.

Depletion, depreciation and amortization of natural gas properties were calculated using the units of production method. After deciding to exit the gas business, the Company ceased recording depletion and as such, there was no significant depletion recorded in 2004. The depletion per mmBtu was $2.78 in 2003 and $4.61 in 2002. The depletion per mmBtu in 2002 reflected downward revisions in reserve estimates. Unproved gas properties were not amortized but were assessed for impairment either individually or on an aggregated basis.

Spent Nuclear Fuel and Radioactive Waste Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. KCP&L pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to fuel expense. In 2002, the U.S. Senate approved Yucca Mountain, Nevada as a long-term geologic repository. The DOE is currently in the process of preparing an application to obtain the Nuclear Regulatory Commission (NRC) license to proceed with construction of the repository. Management cannot predict when this site may be available. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel first from the owners with the oldest spent fuel. Wolf Creek Generating Station (Wolf Creek) has completed an on-site storage facility that is designed to hold all spent fuel generated at the plant through the end of its 40-year licensed life in 2025.

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

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 are probable.

Nuclear Plant Decommissioning Costs The Missouri Public Service Commission (MPSC) and The State Corporation Commission of the State of Kansas (KCC) require KCP&L and the other owners of Wolf Creek to submit an updated decommissioning cost study every three years. The most recent study was submitted to the MPSC and the KCC on August 30, 2002, and is the basis for the decommissioning cost estimates in the following 75

table. Both the MPSC and the KCC have accepted the 2002 cost estimate as filed and have approved funding schedules for this cost estimate. The MPSC-approved schedule assumes funding through the expiration of Wolf Creek's current NRC operating license (2025). The KCC-approved schedule assumes that Wolf Creek will be granted a 20-year license extension and, thus, assumes funding through 2045. At this time, the owners of Wolf Creek have neither sought nor received a license extension from the NRC. The escalation rates and return on assets assumptions shown in the following table are those that were last explicitly approved by the MPSC and the KCC. 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 Current cost of decommissioning (in2002 dollars): (millions)

Total Station $ 468 $ 468 47% share 220 220 Future cost of decommissioning (in 2025 dollars):

Total Station $ 1,288 47% share 606 Future cost of decommissioning (in 2045 dollars):

Total Station $ 2,527 47% share 1,188 Annual escalation factor 4.00% 4.50%

Annual return on trust assets (a) 6.02% 7.66%

(a)The 6.02% rate of return inKansas is thru 2025. The rate systematically decreases to 3.99% from 2025 to decommissioning at the end of the extended 60-year life of 2045.

KCP&L currently contributes about $3.6 million annually to a tax-qualified trust fund to be used to decommission Wolf Creek. These costs are charged to other operating expense and recovered in billings to customers. If the actual return on trust assets is below the anticipated level, KCP&L believes a rate increase would be allowed ensuring full recovery of decommissioning costs over the remaining life of the station.

The trust fund balance, including reinvested earnings, was $84.1 million and $75.0 million at December 31, 2004 and 2003, respectively. The related liabilities for decommissioning are included in Asset Retirement Obligations (ARO).

The Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. See Note 16 for discussion of ARO including those associated with nuclear plant decommissioning costs.

Regulatory Matters KCP&L is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Pursuant to SFAS No. 71, KCP&L defers items on the balance sheet resulting from the effects of the ratemaking process, which would not be recorded in accordance with Generally Accepted Accounting Principles (GAAP) if KCP&L were not regulated. See Note 4 for additional information concerning regulatory matters.

Revenue Recognition KCP&L and Strategic Energy recognize revenues on sales of electricity when the service is provided.

Receivables recorded at December 31, 2004 and 2003, include $31.2 million and $28.4 million, 76 I1

V respectively, for electric services provided but not yet billed by KCP&L, and $103.0 million and

$81.2 million, respectively, for electric services provided, but not yet billed by Strategic Energy. See Note 3 for additional information on receivables.

Strategic Energy primarily purchases power under forward physical delivery contracts to supply electricity to its retail energy customers. Strategic Energy sells any excess retail supply of electricity back into the wholesale market. The proceeds from the sale of excess supply of electricity are recorded as a reduction of purchased power. The amount of excess retail supply sales that reduced purchased power was $265.2 million, $160.4 million and $126.4 million in 2004, 2003 and 2002, respectively.

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

Property Gains and Losses Net gains and losses from the sales of assets, businesses and asset impairments are recorded in operating expenses. See Note 2 for information regarding the sale of RSAE.

Asset Impairments Long-lived assets and finite lived intangible assets subject to amortization are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS No. 144 "Accounting for the Impairment or Disposal of Long-lived Assets." SFAS No. 144 requires that if the sum of the undiscounted expected future cash flows from an asset to be held and used is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. The amount of impairment recognized is the excess of the carrying value of the asset over its fair value. In December 2004, HSS entered into a letter of intent to sell Worry Free and recorded an asset impairment based on the valuation performed in connection with the sale.

Goodwill and indefinite lived intangible assets are tested for impairment at least annually and more frequently when indicators of impairment exist as prescribed under SFAS No. 142. SFAS No. 142 requires that if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment charge for goodwill must be recognized in the financial statements. To measure the amount of the impairment loss to recognize, the implied fair value of the reporting unit goodwill would be compared with its carrying value. See Note 5 for additional information.

Income Taxes In accordance with SFAS No. 109, "Accounting for Income Taxes," Great Plains Energy has recognized deferred taxes for all temporary book to tax differences using the liability method. The liability method requires that deferred tax balances be adjusted to reflect enacted tax rates that are anticipated to be in effect when the temporary differences reverse. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized.

Great Plains Energy and its subsidiaries file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of income or loss. In accordance with 35 Act requirements and the Company's intercompany tax allocation agreement, the holding company also 77

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

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

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

Stock Options The Company has an equity compensation plan, which is described more fully in Note 10. The Company adopted the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," for its stock options as of January 1, 2003. The Company has elected to use the modified prospective method of adoption as prescribed under SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." Under the modified prospective method of adoption, stock option compensation cost recognized beginning January 1, 2003, is the same as if the fair value recognition provisions of SFAS No. 123 had been applied to all stock options granted after October 1, 1995.

In December 2004, FASB issued SFAS No. 123 (revised 2004) "Share-Based Payment," effective for reporting periods beginning after June 15, 2005. Management has determined that this statement will not have a significant impact on the Company's results of operations and financial position.

The following table illustrates the effect on net income and earnings per common share (EPS) for Great Plains Energy as if the fair value method had been applied in preparing the 2002 financial statements.

2002 (thousands, except per share amounts)

Net income, as reported $ 126,188 Add: Stock-based employee compensation expense included in net income as reported, net of income taxes 57 Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of income taxes 255 Pro forma net income as if fair value method were applied $ 125,990 Basic and diluted EPS, as reported $ 1.99 Basic and diluted EPS, pro forma $ 1.99 Basic and Diluted Earnings per Common Share Calculation There was no significant dilutive effect on Great Plains Energy's EPS from other securities in 2004, 2003 and 2002. To determine basic EPS, preferred stock dividend requirements are deducted from income from continuing operations and net income before dividing by average number of common shares outstanding. The earnings (loss) per share impact of discontinued operations, net of income taxes, is determined by dividing discontinued operations, net of income taxes, by the average number of common shares outstanding. Diluted EPS assumes the issuance of common shares applicable to 78

stock options, performance shares, restricted stock and FELINE PRIDES calculated using the treasury stock method.

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

2004 2003 2002 Income (thousands, except per share amounts)

Income from continuing operations $173,535 $ 189,702 $136,702 Less: preferred stock dividend requirements 1,646 1,646 1,646 Income available to common stockholders $171,889 $ 188,056 $ 135,056 Common Shares Outstanding Average number of common shares outstanding 72,028 69,206 62,623 Add: effect of dilutive securities 64 42 1 Diluted average number of common shares outstanding 72,092 69,248 62,624 Basic EPS from continuing operations $ 2.39 $ 2.72 $ 2.16 Diluted EPS from continuing operations $ 2.39 $ 2.72 $ 2.16 As of December 31, 2004 and 2003, there were no anti-dilutive shares applicable to stock options, performance shares or restricted stock. As of December 31, 2004, 6.5 million FELINE PRIDES had no dilutive effect because the number of common shares to be issued in accordance with the settlement rate described in Note 19, assuming applicable market value equal to the average price during the period, would be equal to the number of shares Great Plains Energy could re-purchase in the market at the average price during the period. Options to purchase 394,723 shares of common stock as of December 31, 2002, were excluded from the computation of diluted EPS because they were anti-dilutive due to the option exercise prices being greater than the average market price of the common shares during the period.

In February 2005, the Board of Directors declared a quarterly dividend of $0.415 per share on Great Plains Energy's common stock. The common dividend is payable March 21, 2005, to shareholders of record as of February 28, 2005. The Board of Directors also declared regular dividends on the preferred stock, payable June 1, 2005, to shareholders of record on May 10, 2005.

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2. SUPPLEMENTAL CASH FLOW INFORMATION Great Plains Energy Other Operating Activities 2004 2003 2002 Cash flows affected by changes in: (thousands)

Receivables $ (36,517) $ (13,077) $ (50,200)

Fuel inventories 1,840 (821) 1,339 Materials and supplies 2,167 (5,799) (104)

Accounts payable 43,261 6,331 (2,982)

Accrued taxes 7,107 21,777 48,756 Accrued interest (1,006) (4,184) 3,117 Wolf Creek refueling outage accrual 11,420 (6,532) (4,687)

Pension and postretirement benefit assets and obligations (10,387) (20,545) 3,774 Allowance for equity funds used during construction (2,087) (1,424) (299)

Other (9,105) 22,020 26,353 Total other operating activities $ 6,693 $ (2,254) $ 25,067 Cash paid during the period:

Interest $ 84,082 $ 78,049 $ 82,132 Income taxes $ 38,611 $ 42,440 $ 17,709 Consolidated KCP&L Other Operating Activities 2004 2003 2002 Cash flows affected by changes in: (thousands)

Receivables $ 1,649 $ (1,444) $ (8,565)

Fuel inventories 1,840 (821) 1,339 Materials and supplies 2,167 (5,799) (104)

Accounts payable 1,752 7,735 (35,963)

Accrued taxes (6,617) (2,792) 49,584 Accrued interest (1,963) (3,413) 4,107 Wolf Creek refueling outage accrual 11,420 (6,532) (4,687)

Pension and postretirement benefit assets and obligations (8,059) (20,272) 3,774 Allowance for equity funds used during construction (2,087) (1,424) (299)

Other (1,182) 226 11,992 Total other operating activities $ (1,080) $ (34,536) $ 21,178 Cash paid during the period:

Interest $ 73,840 $ 71,399 $ 74,068 Income taxes $ 64,878 $ 68,112 S 11,897 Significant Non-Cash Items Asset Retirement Obligations KCP&L adopted SFAS No. 143 on January 1, 2003, and recorded a liability for ARO of $99.2 million and increased property and equipment, net of accumulated depreciation, by $18.3 million. KCP&L is a regulated utility subject to the provisions of SFAS No. 71, and management believes it is probable that any differences between expenses under SFAS No. 143 and expenses recovered currently in rates will be recoverable in future rates. As a result, the $16.3 million net cumulative effect of the adoption of SFAS No. 143 was recorded as a regulatory asset; therefore, it had no impact on net income. The adoption of SFAS No. 143 had no effect on Great Plains Energy and consolidated KCP&L's cash flows.

FIN 46 KCP&L consolidated the Lease Trust and de-consolidated KCPL Financing I in 2003, as required by FASB Interpretation (FIN) No. 46, "Consolidation of Variable Interest Entities," as amended. As a result of the consolidation of the Lease Trust, Great Plains Energy's and consolidated KCP&L's long-term 80 111

debt increased $143.8 million. The consolidation of the Lease Trust had no effect on Great Plains Energy's and consolidated KCP&L's cash flows. See Note 13 for additional information concerning the consolidation of the Lease Trust.

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

Minimum Pension Liability Primarily as a result of lower discount rates and historical losses in the market value of plan assets, the Company recorded a minimum pension liability of $84.2 million offset by an intangible asset of $15.6 million and OCI of $68.6 million ($42.3 million net of tax) in 2004. In 2003, the Company's minimum pension liability was $78.4 million offset by an intangible asset of $17.4 million and OCI of $61.0 million

($37.2 million net of tax). Recording the minimum pension liabilities had no effect on Great Plains Energy's and consolidated KCP&L's cash flows.

RSAE Disposition In 2003, HSS completed the disposition of its interest in RSAE. See Note 7 for additional information concerning the disposition of RSAE. The following table summarizes Great Plains Energy's and consolidated KCP&L's loss from discontinued operations as a result of this transaction.

Year to Date June 30 2003 (thousands)

Cash repayment of supported bank line $ (22,074)

Write-off of intercompany balance and investment 4,760 Accrued transaction costs (1,550)

Income tax benefit 11,793 Loss on disposition (7,071)

Pre-disposition operating losses (1,619)

Discontinued operations $ (8,690)

DTI Bankruptcy On December 31, 2001, a subsidiary of KLT Telecom Inc. (KLT Telecom), DTI Holdings, Inc. and its subsidiaries, Digital Teleport, Inc. and Digital Teleport of Virginia, Inc., filed separate voluntary petitions in the Bankruptcy Court for the Eastern District of Missouri for reorganization under Chapter 11 of the U.S. Bankruptcy Code, which cases were procedurally consolidated. DTI Holdings and its two subsidiaries are collectively called "DTI." In December 2002, Digital Teleport entered into an agreement to sell substantially all of its assets to CenturyTel Fiber Company II, LLC, a nominee of CenturyTel, Inc., which was approved by the Bankruptcy Court and closed in 2003.

KLT Telecom received $19.2 million in 2003 related to the confirmation of the DTI bankruptcy. Pending final resolution of the MODOR Claim and the litigation regarding the put option of a minority shareholder, the effect of the DTI bankruptcy on the Company has been resolved. See Note 15 for information regarding the MODOR Claim and the put option.

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The following table summarizes Great Plains Energy's gain on the sale of DTI assets.

DTI 2003 (thousands)

Cash proceeds from bankruptcy estates $ 19,234 Cash proceeds from sale of office building 1,186 Receivables 1,300 Total proceeds 21,720 Book basis of office building sold (2,720)

DIP financing accrual reversal 5,000 Accounts payable (1,900)

Income tax (9,810)

Reversal of tax valuation allowance 15,779 Gain on sale of assets $ 28,069 Strategic Energy Acquisition During November 2002, Great Plains Energy indirectly acquired an additional 6% ownership in Strategic Energy through its subsidiary IEC. The $15.1 million consideration paid for the 6% ownership consisted of $8.0 million in Great Plains Energy common stock and promissory notes of $4.7 million (issued by Great Plains Energy) and $2.4 million (issued by IEC). The promissory notes were paid in January 2003. This transaction had no effect on Great Plains Energy's cash flows for the year ended December 31, 2002. See Note 8 for information regarding the purchase of an additional indirect interest in Strategic Energy in 2004.

3. RECEIVABLES The Company's receivables are detailed in the following table.

December 31 2004 2003 Customer accounts receivable sold to (thousands)

Receivables Company $ 19,866 $ 17,902 Consolidated KCP&L other receivables 43,500 77,733 Consolidated KCP&L receivables 63,366 95,635 Great Plains Energy other receivables 183,818 144,709 Great Plains Energy receivables $ 247,184 $ 240,344 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 Kansas City Power & Light Receivables Company (Receivables Company), which in turn sold most of the receivables to outside investors. Accounts receivable sold under this revolving agreement totaled $84.9 million and $87.9 million at December 31, 2004 and 2003, respectively. These sales included unbilled receivables of $31.2 million and $28.4 million at December 31, 2004 and 2003, respectively. As a result of the sale to outside investors, Receivables Company received up to $70 million in cash, which was forwarded to KCP&L as consideration for its sale. At December 31, 2004 and 2003, Receivables Company had received $65.0 million and

$70.0 million in cash, respectively. The agreement was structured as a true sale under which the creditors of Receivables Company were entitled to be satisfied out of the assets of Receivables Company prior to any value being returned to KCP&L or its creditors. The agreement expired in January 2005 and was not renewed by KCP&L. KCP&L is currently evaluating alternatives to replace this agreement and intends to enter into a new agreement in 2005.

Under the agreement, KCP&L sold its receivables at a fixed price based upon the expected cost of funds and charge-offs. These costs comprised KCP&L's loss on the sale of accounts receivable.

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KCP&L serviced the receivables and received an annual servicing fee of 0.25% of the outstanding principal amount of the receivables sold and retained any late fees charged to customers.

Information regarding KCP&L's sale of accounts receivable is reflected in the following table.

2004 2003 2002 Gross proceeds on sale of (thousands) accounts receivable $ 929,122 $ 939,498 $ 957,222 Collections 927,986 949,484 974,669 Loss on sale of accounts receivable 2,529 3,714 4,558 Late fees 2,210 2,256 2,572 Consolidated KCP&L's other receivables at December 31, 2004 and 2003, consist primarily of receivables from partners in jointly owned electric utility plants, wholesale sales receivables and accounts receivable held by Worry Free. The December 31, 2003, amounts also included insurance recoveries. Great Plains Energy's other receivables at December 31, 2004 and 2003, are primarily the accounts receivable held by Strategic Energy including unbilled receivables of $103.0 million and

$81.2 million, respectively.

4. REGULATORY MATTERS Regulatory Assets and Liabilities KCP&L is subject to the provisions of SFAS No. 71. Accordingly, KCP&L has recorded assets and liabilities on its balance sheet resulting from the effects of the ratemaking process, which would not be recorded under GAAP for non-regulated entities. Regulatory assets represent costs incurred that have been deferred because future recovery in customer rates is probable. Regulatory liabilities generally represent probable future reductions in revenue or refunds to customers. KCP&L's continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric industry. In the event that SFAS No. 71 no longer applied to all, or a separable portion, of KCP&L's operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of utility plant assets if the cost of the assets could not be expected to be recovered in customer rates. Whether an asset has been impaired is determined pursuant to SFAS No. 144.

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Amortization December 31 ending period 2004 2003 Regulatory Assets (millions)

Taxes recoverable through future rates $ 81.0 $ 89.0 Decommission and decontaminate federal uranium enrichment facilities 2007 2.0 2.6 Loss on reacquired debt 2023 7.7 4.3 January 2002 incremental ice storm costs (Missouri) 2007 9.5 14.1 Change in depreciable life of Wolf Creek (Kansas) 2045 15.5 7.7 Cost of removal 13.9 14.5 Asset retirement obligations 11.4 12.9 Other (a) Various 3.3 0.5 Total Regulatory Assets $ 144.3 $ 145.6 Regulatory Liabilities Emission allowances (b) $ (4.1) $ (3.8)

Total Regulatory Liabilities $ (4.1) $ (3.8)

(a) An insignificant amount at December 31, 2004 and 2003, respectively, earns a return on investment in the rate making process.

(b) Consistent with the MPSC order establishing regulatory treatment, no amortization is being recorded.

The Company adopted SFAS No. 143 on January 1, 2003, and recorded liabilities for legal obligations to retire assets. In conjunction with the adoption of SFAS No. 143, non-legal costs of removal were reclassified for all periods presented from accumulated depreciation to a regulatory asset. See Note 16 for discussion of ARO. The change in the depreciable life of Wolf Creek in 2003 was the result of the KCC stipulation and agreement discussed below.

Retail Rate Matters At the end of January 2002, a severe ice storm occurred throughout large portions of the Midwest, including the greater Kansas City metropolitan area. In 2002, the KCC approved a stipulation and agreement regarding the treatment of the $16.5 million Kansas jurisdictional portion of the ice storm costs. Pursuant to the stipulation and agreement, KCP&L implemented a retail rate reduction January 1, 2003, and began calculating depreciation expense on Wolf Creek using a 60-year life instead of a 40-year life. As a result of the stipulation and agreement, KCP&L's retail revenues decreased approximately $12.5 million and depreciation expense decreased approximately $7.7 million annually beginning in 2003. The reduction in depreciation expense has been recorded as a regulatory asset, as discussed above. KCP&L also agreed to file a rate case by May 15, 2006.

In 2002, the MPSC approved KCP&L's application for an accounting authority order related to the Missouri jurisdictional portion of the storm costs. The order allows KCP&L to defer and amortize

$20.1 million, representing the Missouri portion of the storm costs, through January 2007. The amortization, which began in September 2002, is approximately $4.6 million annually for the remainder of the amortization period. The amortization totaled $1.5 million in 2002.

5. GOODWILL AND INTANGIBLE PROPERTY In accordance with SFAS No. 142, goodwill is tested for impairment upon adoption and at least annually thereafter. The annual test must be performed at the same time each year.

Strategic Energy's annual impairment tests, conducted September 1, have been completed and there were no impairments of the Strategic Energy goodwill in 2004, 2003 or 2002. Goodwill reported on Great Plains Energy's consolidated balance sheets associated with the Company's ownership in Strategic Energy was $86.8 million and $26.1 million at December 31, 2004 and 2003, respectively.

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See Note 8 for additional information concerning the acquisition of an additional indirect interest in Strategic Energy in 2004.

As a result of the transition impairment test of RSAE goodwill related to the adoption of SFAS No. 142 in 2002, the Company recorded a $3.0 million write-down of goodwill as a cumulative effect of a change in accounting principle. See Note 7 for additional information concerning the June 2003 disposition of RSAE.

Other Intangible Assets and Liabilities KCP&L's electric utility plant on the consolidated balance sheets included intangible computer software of $27.4 million, net of accumulated amortization of $61.3 million, in 2004 and $33.6 million, net of accumulated amortization of $52.5 million, in 2003.

Other intangible assets on Great Plains Energy's consolidated balance sheets include other intangible computer software of $2.0 million, net of accumulated amortization of $3.4 million, in 2004 and

$2.7 million, net of accumulated amortization of $1.8 million, in 2003. See Note 8 for information concerning the intangible assets and liabilities recorded as a result of the acquisition of an additional indirect interest in Strategic Energy.

Assets of Discontinued Operations on Great Plains Energy's consolidated balance sheets included no intangible assets at December 31, 2004, and included gross intangible drilling costs, before impairments, of $32.0 million at December 31, 2003. Assets of Discontinued Operations, including intangible drilling costs, were significantly written down at the end of 2003 in aggregate at the property level. See Note 6 for additional information.

6. KLT GAS DISCONTINUED OPERATIONS In February 2004, the Board of Directors approved the sale of the KLT Gas portfolio and discontinuation of the gas business. Consequently, in 2004, the KLT Gas portfolio was reported as discontinued operations and KLT Gas' historical activities were reclassified in accordance with SFAS No. 144 for all periods presented.

In 2004, KLT Gas completed sales of substantially all of the KLT Gas portfolio for $23.5 million cash, net of $1.4 million of transaction costs. During 2003, the Company recorded a loss of $33.5 million in Discontinued Operations, net of income taxes, as a result of impairments recognized in accordance with SFAS No. 144. The following table summarizes the discontinued operations.

2004 2003 2002 (millions)

Revenues $ 1.6 $ 1.5 $ 1.1 Loss from operations, including impairments, before income taxes (4.5) (59.1) (6.6)

Gain on sales of assets 16.8 - -

Discontinued operations before income taxes 12.3 (59.1) (6.6)

Income taxes (5.0) 23.0 3.1 Discontinued operations, net of income taxes $ 7.3 $ (36.1) $ (3.5) 85

Assets and liabilities of the discontinued operations are summarized in the following table.

December 31 2004 2003 (millions)

Current assets $ 0.7 $ 1.0 Gas property and investments - 9.8 Other nonutility property and investments - 0.3 Accrued taxes - 6.7 Deferred income taxes - 10.0 Total assets of discontinued operations $ 0.7 $ 27.8 Current liabilities $ 2.1 $ 2.8 Asset retirement obligations - 1.8 Total liabilities of discontinued operations $ 2.1 $ 4.6

7. DISPOSITION OF OWNERSHIP INTEREST IN R.S. ANDREWS ENTERPRISES, INC.

On June 13, 2003, HSS' board of directors approved a plan to dispose of its interest in residential services provider RSAE. On June 30, 2003, HSS completed the disposition of its interest in RSAE.

The financial statements reflect RSAE as discontinued operations for all periods presented as prescribed under SFAS No. 144. The following table summarizes the discontinued operations.

2003 2002 (millions)

Revenues $ 31.8 $ 58.5 Loss from operations before income taxes (1.6) (4.0)

Loss on disposal before income taxes (18.9)

Total loss on discontinued operations before income taxes (20.5) (4.0)

Income tax benefit (a) 11.8 Discontinued operations, net of income taxes $ (8.7) $ (4.0)

(a) Since RSAE was not included in Great Plains Energy's consolidated income tax returns, an income tax benefit was not recognized on RSAE's 2002 losses. RSAE had continual losses and therefore did not recognize tax benefits. The 2003 tax benefit reflects the tax effect of Great Plains Energy's disposition of its interest in RSAE. See Note 11 on income taxes.

8. ACQUISITION OF ADDITIONAL INDIRECT INTEREST IN STRATEGIC ENERGY Effective May 6, 2004, Great Plains Energy, through IEC, completed its purchase of an additional 11.45% indirect interest in Strategic Energy bringing Great Plains Energy's indirect ownership interest in Strategic Energy to just under 100%. The Company paid cash of $90.0 million, including $1.2 million of transaction costs. In accordance with the purchase terms, the Company also recorded a $0.9 million liability for 2004 fractional dividends to the previous owner for its share of 2004 budgeted Strategic Energy dividends. See Notes 12 and 15 for additional discussion of the acquisition.

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The purchase price allocation for the net assets acquired is detailed in the following table.

2004 (millions)

Other non-utility property and investments $ 10.6 Goodwill 60.7 Other deferred charges 46.1 Total assets 117.4 Accounts payable 0.9 Other deferred credits and liabilities 26.5 Net assets acquired $ 90.0 A third party valuation was prepared to assist in the Company's determination of the purchase price allocation. The acquired share of identifiable intangible assets and liabilities were recorded by IEC at fair value as part of the purchase price allocation. The acquired share of the fair value of the identifiable intangibles was a net asset of $19.6 million. The fair value of acquired supply (intangible asset) and retail (liability) contracts is being amortized over approximately 28 months. Other intangible assets recorded that have finite lives and are subject to amortization include customer relationships and asset information systems, which are being amortized over 72 and 44 months, respectively. Net amortization for 2004 was $2.2 million. A $0.7 million intangible asset for the Strategic Energy trade name was also recorded and deemed to have an indefinite life, and as such, is not being amortized.

9. PENSION PLANS AND OTHER EMPLOYEE BENEFITS Pension Plans and Other Employee Benefits The Company maintains defined benefit pension plans for substantially all employees, including officers, of KCP&L, Services and Wolf Creek Nuclear Operating Corporation (WCNOC). Pension benefits under these plans reflect the employees' compensation, years of service and age at retirement. The funding policy for the pension plans is to contribute amounts sufficient to meet the minimum funding requirements under the Employee Retirement Security Act of 1974 (ERISA) plus additional amounts as considered appropriate.

For defined benefit pension plans sponsored by Great Plains Energy, contributions and expense are allocated to KCP&L and Services based on labor costs of plan participants. Any additional minimum pension liability is allocated based on each companies' funded status per plan. The Company recognizes gains and losses incurred by the pension plans by amortizing over a five-year period the rolling five-year average of unamortized actuarial gains and losses.

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

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law. The Medicare Act, among other things, provides a federal subsidy to sponsors of retiree health care benefit plans. In 2004, the Company adopted FASB Staff Position No. FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The 2004 actuarial measurements include the effects of 87

the Medicare Act. The Medicare Act did not materially impact plan obligations and it is not expected to materially impact future health care costs and participation rates.

The following pension benefits tables provide information relating to the funded status of all defined benefit pension plans on an aggregate basis. The plan measurement date for the majority of plans is September 30. In 2004, contributions of $20.7 million were made to the pension plans after the measurement date and in 2003, contributions of $32.0 million and $4.8 million were made to the pension and postretirement benefit plans, respectively, after the measurement date. Net periodic benefit costs reflect total plan benefit costs prior to the effects of capitalization and sharing with joint-owners of power plants.

Pension Benefits Other Benefits 2004 2003 2004 2003 Change in projected benefit obligation (PBO) (thousands)

PBO at beginning of year $ 501,497 $ 450,800 $ 52,119 $ 48,936 Service cost 16,695 14,969 948 851 Interest cost 30,137 29,892 3,094 3,210 Contribution by participants - - 1,082 858 Amendments - 34 - 230 Actuarial loss (gain) 25,117 42,496 (3,193) 2,176 Benefits paid (54,702) (36,122) (4,331) (3,655)

Benefits paid by Company (348) (572) (585) (487)

Settlements (2,660) - - -

PBOatendofplanyear $ 515,736 $ 501,497 $ 49,134 $ 52,119 Change in plan assets Fair value of plan assets at beginning of year $ 340,986 $ 324,169 $ 8,353 $ 11,054 Actual return on plan assets 33,893 43,663 287 122 Contributions by employer and participants 50,345 9,276 10,424 970 Benefits paid (54,702) (36,122) (4,331) (3,793)

Fair value of plan assets at end of plan year $ 370,522 $ 340,986 $ 14,733 $ 8,353 Prepaid (accrued) benefit cost Funded status $ (145,214) $ (160,511) $ (34,401) $ (43,766)

Unrecognized actuarial loss 195,978 182,555 10,467 13,984 Unrecognized prior service cost 36,271 40,556 1,045 1,282 Unrecognized transition obligation 398 455 9,395 10,570 Net prepaid (accrued) benefit cost $ 87,433 $ 63,055 $(13,494) $(17,930)

Amounts recognized in the consolidated balance sheets Prepaid benefit cost $ 89,229 $ 80,881 $ - $

Accrued benefit cost (1,796) (17,826) (13,494) (17,930)

Minimum pension liability adjustment (84,245) (78,435)

Intangible asset 15,613 17,426 Accumulated other comprehensive income 68,632 61,009 Net amount recognized in balance sheets 87,433 63,055 (13,494) (17,930)

Contributions and changes after measurement date 20,740 34,139 - 4,790 Netamount recognized at December31 $ 108,173 $ 97,194 $(13,494) $(13,140) 88 111I

Pension Benefits Other Benefits 2004 2003 2002 2004 2003 2002 Components of net periodic benefit cost (thousands)

Service cost $16,695 $14,969 $ 13,360 $ 948 $ 851 $ 757 Interest cost 30,137 29,892 30,272 3,094 3,210 2,951 Expected return on plan assets (31,701) (27,702) (34,144) (669) (572) (503)

Amortization of prior service cost 4,285 4,286 4,313 237 216 194 Recognized net actuarial loss (gain) 7,746 1,377 (7,237) 737 574 100 Transition obligation 57 57 (742) 1,175 1,175 1,174 Amendment - - - - 110 Net settlements 1,798 - 284 - -

Net periodic benefit cost $29,017 $22,879 $ 6,106 $5,522 $5,564 $4,673 The accumulated benefit obligation (ABO) for all defined benefit pension plans was $445.4 million and

$429.9 million at December 31, 2004 and 2003, respectively. The projected benefit obligation, accumulated benefit obligation and the fair value of plan assets at plan year-end are aggregated by funded and underfunded plans in the following table.

2004 2003 Pension plans with the ABO in excess of plan assets (thousands)

Projected benefit obligation $ 309,799 $ 297,392 Accumulated benefit obligation 266,081 252,209 Fair value of plan assets 179,980 156,389 Pension plans with plan assets in excess of the ABO Projected benefit obligation $ 205,937 $ 204,105 Accumulated benefit obligation 179,327 177,725 Fair value of Dlan assets 190,542 184,597 Pension plan assets are managed in accordance with "prudent investor" guidelines contained in the ERISA requirements. The investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets within a reasonable and prudent level of risk. Investments are diversified across classes and within each class to minimize risks. At December 31, 2004 and 2003, the fair value of plan assets was $370.5 million, not including a $20.7 million contribution made after the plan year-end, and $341.0 million, not including a $32.0 million subsequent contribution, respectively.

The asset allocation for the Company's pension plans at the end of 2004 and 2003, and the target allocation for 2005 are reported in the following table. The portfolio is rebalanced when the targets are exceeded.

Plan Assets at Target December 31 Asset Category Allocation 2004 2003 Equity securities 59% 59% 62%

Debt securities 30% 31% 34%

Real estate 6% 8% 4%

Other 5% 2% 0%

Total 100% 100% 100%

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plan's investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns of various asset classes. Based on the target asset allocation for each asset class, the 89

overall expected rate of return for the portfolio was developed and adjusted for the effect of projected benefits paid from plan assets and future plan contributions.

The following tables provide the weighted-average assumptions used to determine benefit obligations and net costs.

_ . _ , .. A.. . _

Weighted average assumptions used to determine Pension Benefits Other Benefits the benefit obligation at plan year-end 2004 2003 2004 2003 Discount rate 5.82% 6.00% 5.82% 6.00%

Rate of compensation increase 3.06% 3.30% 3.05% 3.25%

Weighted average assumptions used to determine Pension Benefits Other Benefits net costs for years ended at December 31 2004 2003 2004 2003 Discount rate 6.00% 6.75% 6.00% 6.75%

Expected long-term return on plan assets 9.00% 9.00% 9.00% 9.00%

Rate of compensation increase 3.30% 4.10% 3.25% 4.00%

Primarily as a result of lower discount rates and historical losses in the market value of plan assets, the Company recorded a minimum pension liability offset by an intangible asset and OCI. The amounts recognized in Great Plains Energy's and consolidated KCP&L's balance sheets related to the minimum pension liability are detailed in the following table.

Great Plains Energy Consolidated KCP&L December 31 December 31 2004 2003 2004 2003 (millions)

Additional minimum pension liability $ 84.2 $ 78.4 $ 79.8 $ 74.4 Intangible asset 15.6 17.4 14.6 16.5 Deferred taxes 26.3 23.8 25.0 22.6 OCI, net of tax 42.3 37.2 40.2 35.3 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The health care plan requires retirees to share in the cost when premiums exceed a certain amount. The following table provides information on the assumed health care rate trends.

Assumed Health Care Cost Trends at December 31 2004 2003 Health care cost trend rate assumed for next year 10% 9%

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) 5% 5%

Year that the rate reaches the ultimate trend rate 2010 2008 90 111

The effects of a one-percentage point change in the medical cost trend rates, holding all other assumptions constant, as of December 31, 2004, are detailed in the following table.

Increase Decrease (thousands)

Effect on total service and interest component $ 73 $ (62)

Effect on postretirement benefit obligation $ 732 $ (647)

The Company expects to contribute $4.7 million to its pension plans and $4.3 million to its other postretirement benefit plans in 2005. The Company's funding policy is to contribute amounts sufficient to meet the minimum funding requirements of employee benefit and tax regulations plus additional amounts as deemed fiscally appropriate, therefore actual contributions may differ from expected contributions.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid through fiscal 2014.

Pension Other Benefits Benefits (thousands) 2005 $ 32,934 $ 5,479 2006 35,827 5,984 2007 36,532 6,739 2008 37,262 7,497 2009 39,358 8,205 2010-2014 238,915 51,370 Employee Savings Plans Great Plains Energy has defined contribution savings plans that cover substantially all employees. The Company matches employee contributions, subject to limits. The annual cost of the plans was

$4.3 million in 2004 and $4.1 million in 2003 and 2002.

Strategic Energy Phantom Stock Plan Strategic Energy had a phantom stock plan that provided incentive in the form of deferred compensation based upon the award of performance units, the value of which was related to the increase in profitability of Strategic Energy. The plan was terminated and an insignificant amount of costs were recorded in 2004. Strategic Energy's annual cost for the plan was $4.6 million and

$5.9 million in 2003 and 2002, respectively.

10. EQUITY COMPENSATION The Company's Long-Term Incentive Plan is an equity compensation plan approved by its shareholders. The Long-Term Incentive Plan permits the grant of restricted stock, stock options, limited stock appreciation rights and performance shares to officers and other employees of the Company and its subsidiaries. The maximum number of shares of Great Plains Energy common stock that can be issued under the plan is 3.0 million. At December 31, 2004, 2.2 million shares remained available for future issuance.

Stock Options Granted 1995 The exercise price of stock options granted equaled the market price of the Company's common stock on the grant date. An amount equal to the quarterly dividends paid on Great Plains Energy common 91

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, 2004, the market price of Great Plains Energy common stock was $30.28, which exceeded the grant price for all such options still outstanding. Unexercised options expire ten years after the grant date. For options outstanding at December 31, 2004, the grant price was $23.0625 and the remaining contractual life was 0.4 years.

Prior to the adoption of SFAS No. 123 on January 1, 2003, Great Plains Energy followed Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees" and related interpretations in accounting for these options. Great Plains Energy recognized annual compensation expense equal to accumulated and reinvested dividends plus the impact of the change in stock price since the grant date. Great Plains Energy recognized compensation expense of $0.1 million in 2002.

These options were fully vested prior to the adoption of SFAS No. 123; therefore, no compensation expense was recognized in 2003 or 2004.

Stock Options Granted 2001 - 2003 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 $24.90 to $27.73 and the weighted-average remaining contractual life at December 31, 2004 was 6.9 years.

In accordance with the provisions of SFAS No. 123, the Company recognized an insignificant amount of compensation expense in 2004 and 2003. Under the provisions of APB Opinion 25, no compensation expense was recognized in 2002 because the option exercise price was equal to the market price of the underlying stock on the date of grant.

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

2003 2002 2001 Risk-free interest rate 4.77 % 4.57 % 5.53 %

Dividend yield 6.88 % 7.68 % 6.37 %

Stock volatility 22.650 % 27.503 % 25.879 %

Expected option life (inyears) 10 10 10 All stock option activity for the last three years is summarized in the following table.

2004 2003 2002 Shares Price* Shares Price* Shares Price*

Outstanding at January 1 241,898 $ 25.41 397,000 $ 25.21 250,375 $ 25.14 Granted - - 27,898 27.73 181,000 24.90 Exercised (26,000) 24.79 (16,000) 26.19 (34,375) 23.00 Forfeited (19,925) 25.50 (167,000) 25.26 - -

Outstanding at December 31 195,973 $ 25.48 241,898 $ 25.41 397,000 $ 25.21 Exercisable as of December 31 75,000 $ 25.43 7,000 $ 21.67 23,000 $ 24.81

. weighted-average price 92 111I

Performance Shares The number of performance shares granted may increase or decrease depending on company performance goals as compared to a peer group of utilities, over a three-year vesting period. The issuance of performance shares is contingent upon achievement of these goals. Performance shares have a value equal to the fair market value of the shares on the grant date with accruing dividends.

During 2004, 1,431 of the 20,744 performance shares granted in 2003 were forfeited, and at December 31, 2004,19,313 shares were outstanding. No additional shares were granted in 2004. In accordance with the provisions of SFAS No. 123, compensation expense and accrued dividends are recognized over the vesting period based on the Company's estimate of the number of shares to be issued. The Company recognized an insignificant amount of compensation expense in 2004 and $0.4 million in 2003.

During 2003, all 144,500 performance shares granted in 2001 were canceled. No compensation expense had been recorded related to these performance shares.

Restricted Stock Restricted stock cannot be sold or otherwise transferred by the recipient prior to vesting and has a value equal to the fair market value of the shares on the grant date. Restricted stock granted in 2004 and 2003 totaled 13,333 and 120,196, respectively. Restricted stock shares issued in 2003 totaling 57,315 vested in 2003 and were issued out of treasury stock; however, 54,436 of these shares were restricted as to transfer until December 31, 2004, but were considered vested under SFAS No. 123 because the employee's right to retain the shares of stock was not contingent upon remaining in the service of the Company and was not contingent upon achievement of performance conditions. The remaining restricted stock shares issued in 2004 and 2003, totaling 76,214, vest on a graded schedule over a three-year period with accruing reinvested dividends. The Company recognized compensation expense of $0.6 million and $1.8 million in 2004 and 2003, respectively.

11. INCOME TAXES Components of income tax expense (benefit) are detailed in the following tables.

Great Plains Energy 2004 2003 2002 Current income taxes (thousands)

Federal $ 19,898 $ 12,024 $ 27,505 State 13,255 8,896 9,369 Total 33,153 20,920 36,874 Deferred income taxes Federal 45,811 23,299 13,915 State (15,492) 3,497 1,679 Total 30,319 26,796 15,594 Investment tax credit amortization (3,984) (3,994) (4,183)

Total income tax expense 59,488 43,722 48,285 Less: taxes on discontinued operations (Notes 6 and 7)

Current tax benefit (4,996) (31,167) (6,648)

Deferred tax (benefit) expense 10,033 (3,676) 3,585 Income taxes on continuing operations $ 54,451 $ 78,565 $ 51,348 93

Consolidated KCP&L 2004 2003 2002 Current income taxes (thousands)

Federal $ 39,232 $ 26,063 $ 47,027 State 6,654 5,688 8,668 Total 45,886 31,751 55,695 Deferred income taxes Federal 22,226 37,140 9,391 State (11,365) 6,883 1,964 Total 10,861 44,023 11,355 Investment tax credit amortization (3,984) (3,994) (4,183)

Total income tax expense 52,763 71,780 62,867 Less: taxes on discontinued operations (Notes 6 and 7)

Current tax (benefit) expense - (21,530) 10 Deferred tax expense - 9,738 Income taxes on continuing operations $ 52,763 $ 83,572 $ 62,857 Effective Income Tax Rates The effective income tax rates reflected in the financial statements and the reasons for their differences from the statutory federal rates are in the following tables.

Great Plains Energy 2004 2003 2002 Federal statutory income tax rate 35.0 % 35.0 % 35.0 %

Differences between book and tax depreciation not normalized 0.6 2.1 1.9 Amortization of investment tax credits (1.7) (2.1) (2.4)

Federal income tax credits (5.3) (7.7) (11.3)

State income taxes 3.3 4.8 4.1 State effective rate change on deferred taxes (3.6) -

Valuation allowance 0.2 (8.4)

RSAE (a) - (1.9) 1.4 Other (3.5) 1.5 (1.0)

Effective income tax rate 25.0 % 23.3 % 27.7 %

Consolidated KCP&L 2004 2003 2002 Federal statutory income tax rate 35.0 % 35.0 % 35.0 %

Differences between book and tax depreciation not normalized 0.7 2.1 2.1 Amortization of investment tax credits (2.0) (2.1) (2.6)

State income taxes 3.4 4.3 4.4 State effective rate change on deferred taxes (4.4) -

Allocation of parent company tax benefits (3.0) -

RSAE(a) - (1.9) 1.5 Other (2.7) 0.6 (0.8)

Effective income tax rate 27.0 % 38.0 % 39.6 %

(a) Amounts reflect the tax effect of operations in 2002 and the effect of the disposition in 2003.

Great Plains Energy and consolidated KCP&L's income tax expense decreased by $10.8 million and

$10.1 million, respectively, due to the favorable impact of state tax planning on the companies' composite tax rates. SFAS No. 109, "Accounting for Income Taxes" requires the companies to adjust 94 111

deferred tax balances to reflect tax rates that are anticipated to be in effect when the differences reverse. The largest component of the companies' decreases in income taxes was the result of adjusting KCP&L's deferred tax balance to its lower composite tax rate. The impact of the composite tax rate reductions on KCP&L's deferred tax balances resulted in an $8.6 million tax benefit for both the Company and consolidated KCP&L. The change in the deferred tax balances reduced the Company's and consolidated KCP&L's 2004 effective tax rates by 3.6% and 4.4%, respectively.

Deferred Income Taxes The tax effects of major temporary differences resulting in deferred tax assets and liabilities in the balance sheets are in the following table.

Great Plains Energy Consolidated KCP&L December 31 2004 2003 2004 2003 (thousands)

Plant related $ 556,543 $ 543,840 $ 556,543 $ 543,840 Future income taxes 81,000 89,000 81,000 89,000 Pension and postretirement benefits 9,047 6,838 9,239 7,768 Tax credit carryforwards (23,661) (22,393) - -

Gas properties related 3,356 (6,640) -

Nuclear fuel outage (5,061) (686) (5,061) (686)

Alternative minimum tax credit carryforward (4,093) (4,093) -

State net operating loss carryforward (476) - -

Other 1,964 (7,252) (484) 1,065 Net deferred tax liability before valuation allowance 618,619 598,614 641,237 640,987 Valuation allowance 476 - - -

Less deferred taxes in discontinued operations (Notes 6 and 7) - 10,033 - -

Net deferred tax liability $ 619,095 $ 608,647 $ 641,237 $ 640,987 The net deferred income tax liability is detailed in the following table.

Great Plains Energy Consolidated KCP&L December 31 2004 2003 2004 2003 (thousands)

Gross deferred income tax assets $ (144,324) $ (131,968) $ (120,739) $ (99,936)

Gross deferred income tax liabilities 763,419 740,615 761,976 740,923 Net deferred income tax liability $ 619,095 $ 608,647 $ 641,237 $ 640,987 Tax Credit Carryforwards At December 31, 2004, the Company had $7.3 million and $16.4 million of federal and Missouri state income tax credit carryforwards, respectively. These credits relate primarily to the Company's low-income housing investment portfolio, and the carryforwards expire in years 2006 to 2024. Management believes the credits will be fully utilized within the carryforward period.

Net Operating Loss Carryforwards At December 31, 2004, KLT Inc. and subsidiaries had Kansas state net operating loss carryforwards of

$10.0 million primarily resulting from losses associated with DTI. KLT Inc. and subsidiaries moved its corporate headquarters to Missouri in 2003, and as a result, will not have sufficient presence in Kansas to utilize the losses. The Kansas state net operating loss carryforwards expire in years 2011 to 2012.

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In 2004, management determined that the loss carryforwards will more likely than not expire unutilized and has provided a valuation allowance against the entire deferred tax benefit.

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

At December 31, 2004 and 2003, the Company had $13.4 million and $16.8 million, respectively, of liabilities for contingencies related to tax deductions or income positions taken on the Company's tax returns. Consolidated KCP&L had liabilities of $3.7 million and $6.4 million at December 31, 2004 and 2003, respectively. Management believes the tax deductions or income positions are properly treated on such tax returns, but has recorded reserves based upon its assessment of the probabilities that certain deductions or income positions may not be sustained when the returns are audited. The tax returns containing these tax deductions or income positions are currently under audit or will likely be audited. The timing of the resolution of these audits is uncertain. If the positions are ultimately sustained, the Company will reverse these tax provisions to income. If the positions are not ultimately sustained, the Company may be required to make cash payments plus interest and/or utilize the Company's federal and state credit carryforwards.

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

KCP&L accrued for these payments in 2000.

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

12. RELATED PARTY TRANSACTIONS AND RELATIONSHIPS In May 2004, Great Plains Energy, through IEC, completed its purchase from SE Holdings, L.L.C. (SE Holdings) of an additional 11.45% indirect interest in Strategic Energy. The purchase increased Great Plains Energy's indirect ownership of Strategic Energy to just under 100%. See Note 8 for additional information regarding the purchase transaction. Richard Zomnir, who resigned as Chief Executive Officer of Strategic Energy in November 2004, and certain other current and former employees of Strategic Energy held direct or indirect interests in SE Holdings. Mr. Zomnir has disclosed that he held an approximate 25% interest in SE Holdings. In connection with the transaction, Mr. Zomnir and other direct and indirect owners of SE Holdings entered into an agreement with IEC and Strategic Energy, providing for certain indemnification rights related to the litigation described in Note 15.

SE Holdings remains a member of Custom Energy Holdings, L.L.C. (Custom Energy Holdings) and is represented on the Management Committees of Custom Energy Holdings and Strategic Energy.

Custom Energy Holdings' business and affairs are controlled and managed by a three member Management Committee composed of one representative designated by KLT Energy Services Inc.

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(KLT Energy Services), one representative designated by IEC, and one representative designated by SE Holdings. Certain actions (including amendment of Custom Energy Holdings' operating agreement, approval of actions in contravention of the operating agreement, approval of a dissolution of Custom Energy Holdings, additional capital contributions and assumption of recourse indebtedness) require the unanimous consent of all the members of Custom Energy Holdings.

Strategic Energy's business and affairs are controlled and managed by a four member Management Committee composed of two representatives designated by KLT Energy Services, one representative designated by IEC and one representative designated by SE Holdings. Certain actions (including amendment of Strategic Energy's operating agreement, approval of actions in contravention of the operating agreement, approval of transactions between Strategic Energy and affiliates of its members, approval of a dissolution of Strategic Energy, and assumption of recourse indebtedness) require the unanimous consent of all the Management Committee members.

Pursuant to a service agreement approved by the SEC under the 35 Act, consolidated KCP&L began receiving various support and administrative services from Services. These services are billed to consolidated KCP&L at cost based on payroll and other expenses incurred by Services for the benefit of consolidated KCP&L. These costs totaled $62.7 million and $45.2 million for 2004 and 2003, respectively, and consisted primarily of employee compensation, benefits and fees associated with various professional services. At December 31, 2004 and 2003, consolidated KCP&L had a net intercompany payable to Services of $9.2 million and $10.9 million, respectively.

13. COMMITMENTS AND CONTINGENCIES Nuclear Liability and Insurance The owners of Wolf Creek, a nuclear generating station, (Owners) maintain nuclear insurance for Wolf Creek in four areas: liability, worker radiation, property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear, and war.

Both the nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts of, as defined by the Terrorism Risk Insurance Act, of terrorism-related losses, including replacement power costs. An industry aggregate limit of $0.3 billion exists for liability claims, regardless of the number of non-certified acts affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place.

An industry aggregate limit of $3.2 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), the Owners insurance provider, exists for property claims, including accidental outage power costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. For certified acts of terrorism, the individual policy limits apply. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

Liability Insurance Pursuant to the Price-Anderson Act, the Owners are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently $10.8 billion. This limit of liability consists of the maximum available commercial insurance of $0.3 billion, and the remaining $10.5 billion is provided through an industry-wide retrospective assessment program mandated by the NRC. Under this retrospective assessment program, the Owners can be assessed up to $100.6 million ($47.3 million, KCP&L's 47% share) per incident at any commercial reactor in the country, payable at no more than $10 million ($4.7 million, KCP&L's 47% share) per incident per year.

This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. This assessment also applies in excess of our worker radiation claims 97

insurance. In addition, the U.S. Congress could impose additional revenue-raising measures to pay claims. If the $10.8 billion liability limitation is insufficient, management believes the U.S. Congress will consider taking whatever action is necessary to compensate the public for valid claims.

The Price-Anderson Act expired in August 2002 and was extended until December 31, 2003 for Licensees. Licensees such as Wolf Creek continue to be grandfathered under the Act. A current version of a comprehensive energy bill pending before Congress contains provisions that would amend the Price-Anderson Act addressing public liability from nuclear energy hazards in ways that would increase the annual limit on retrospective assessments from $10 million to $15 million per reactor per incident.

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

In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. KCP&L's share of any remaining proceeds can be used for further decontamination, property damage restoration and premature decommissioning costs. Premature decommissioning coverage applies only if an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses, and only after trust funds have been exhausted.

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

Under all NEIL policies, the Owners are subject to retrospective assessments if NEIL losses, for each policy year, exceed the accumulated funds available to the insurer under that policy. The estimated maximum amount of retrospective assessments under the current policies could total about

$26.0 million ($12.2 million, KCP&L's 47% share) per policy year.

In the event of a catastrophic loss at Wolf Creek, the insurance coverage may not be adequate to cover property damage and extra expenses incurred. Uninsured losses, to the extent not recovered through rates, would be assumed by KCP&L and 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 (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 in the Compact was $7.4 million at December 31, 2004, and December 31, 2003.

On December 18, 1998, the application for a license to construct this project was denied. After the license denial, WCNOC, the Compact Commission (Commission) and others filed a lawsuit in federal court contending Nebraska officials acted in bad faith while handling the license application. In September 2002, the U.S. District Court Judge presiding over the lawsuit issued his decision in the case finding that the State of Nebraska acted in bad faith in processing the license application for a low-98

level radioactive waste disposal site in Nebraska and rendered a judgment on behalf of the Commission in the amount of $151.4 million against the state. After the U.S. Court of Appeals affirmed the decision, Nebraska and the Commission settled the case by Nebraska agreeing to pay the Commission either a one-time amount of $140.5 million or four annual installments of $38.5 million each beginning on August 1, 2005. All related litigation and appeals have been dismissed. Upon final payment, Nebraska will be relieved of its responsibility to host a disposal facility. The Commission has begun seeking alternative long-term waste disposal capability elsewhere. WCNOC intends to pursue with the Commission the possibility of recovering from the settlement proceeds some of WCNOC's contributions to the Nebraska facility's pre-licensing effort. Based on the contribution of the respective utilities in relation to the total settlement amount, management believes the settlement proceeds would be sufficient to recover KCP&L's $7.4 million net investment in the Compact.

Wolf Creek continues to dispose of its low-level radioactive waste at the reopened disposal facility at Barnwell, South Carolina. South Carolina intends to gradually decrease the amount of waste it allows from outside its compact until around 2008 when it intends to no longer accept waste from generators outside its compact. Wolf Creek remains able to dispose of some of its radioactive waste at a facility in Utah. Although management is unable to predict when a permanent disposal facility for Wolf Creek low-level radioactive waste might become available, this issue is not expected to affect continued operation of Wolf Creek.

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

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 restrictive environmental regulations that could require substantial changes to operations or facilities at a significant cost. At December 31, 2004 and 2003, KCP&L had $0.3 million and $1.8 million, respectively, accrued for environmental remediation expenses. The remaining accrual covers water monitoring at one site. The amounts accrued were established on an undiscounted basis and KCP&L does not currently have an estimated time frame over which the accrued amounts may be paid out.

On April 15, 2004, the EPA issued to KCP&L a notice of violation of Hawthorn No. 5 permit limits on sulfur dioxide (SO 2 ) emissions. SO2 emissions from Hawthorn No. 5 exceeded the applicable thirty-day rolling average emission limit on certain days in the third and fourth quarters of 2003 and also exceeded the applicable 24-hour emission limit on one day in the fourth quarter of 2003. These exceedances occurred while the unit was operating in compliance with an exception protocol that had been accepted by the issuer of the air permit. The equipment issues that caused these violations have been addressed by KCP&L. In September 2004, KCP&L finalized a consent order with the EPA, agreeing to pay a civil penalty and fund certain Kansas City metro environmental projects at an aggregate cost of $0.4 million.

Discussed below are issues that may require material expenditures to comply with environmental laws and regulations. KCP&L's expectation is that any such expenditures will be recovered through rates.

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Clean Air Legislation Congress is currently debating numerous bills that could make significant changes to the Clean Air Act Amendments of 1990 (Clean Air Act) including potential establishment of nationwide limits on power plant emissions for several specific pollutants. Some of these bills address oxides of sulfur and nitrogen (SO, and NOX), mercury and carbon dioxide (CO2), while other bills address SO,, NO, and mercury, and some legislative bills address CO2 by itself. There are various compliance dates and compliance limits stipulated in the numerous legislative bills being debated. These bills have the potential for a significant financial impact on KCP&L through the installation of new pollution control equipment to achieve compliance if new nationwide limits are enacted. The financial consequences to KCP&L cannot be accurately determined until the final legislation is passed. However, KCP&L would seek recovery of capital costs and expenses for such compliance through rates. KCP&L will continue to monitor the progress of these bills.

EPA Phase II NOQ SIP Call On April 1, 2004, the Environmental Protection Agency (EPA) issued final Phase II NO, State Implementation Plan (SIP) Call regulation, which specifically excludes coal-fired power plants in the western part of Missouri, including all of KCP&L's Missouri coal-fired plants, from the NO, SIP Call.

The final Phase II NO, SIP Call was contained in the April 21, 2004, Federal Register with an effective date of June 7, 2004. This action completes the EPA's response to several decisions from the U.S.

Court of Appeals for the District of Columbia.

NO, and S02 Regulations-Proposed Clean Air Interstate Rule The EPA published a proposed regulation in the January 30, 2004, Federal Register titled the Interstate Air Quality Rule, which addresses SO2 and NO, emissions. This title was subsequently changed to the Clean Air Interstate Rule (CAIR). A supplemental proposal forthe CAIR was published in the June 10, 2004, Federal Register. The proposed CAIR is designed to reduce NO, and SO2 emissions 65% and 70%, respectively, below current levels in a two-phased program between 2010 and 2015.

If coal-fired plants in Missouri and Kansas are required to implement reductions under the proposed CAIR, KCP&L would need to incur significant capital costs, purchase power or purchase emission allowances. Preliminary analysis of the proposed regulation indicates that selective catalytic reduction technology for NO, control and scrubbers for SO2 control may be required for some of the KCP&L units.

Currently, KCP&L estimates that additional capital expenditures could range from $385 million to

$555 million. The timing of the installation of such control equipment is uncertain pending the final regulation being issued. The final regulation is expected to contain specific compliance dates and compliance levels, final determination of whether Kansas and/or Missouri are included (as they are in the proposed rules), as well as the applicability of accumulated SO2 allowances for future compliance.

KCP&L is currently allocated approximately 50,000 tons of SO2 allowances per year to support its emissions of approximately 50,000 tons per year. KCP&L has accumulated over 190,000 tons of allocated S02 allowances; however, the disposition of such credits is subject to regulatory approvals from both Kansas and Missouri. 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. The CAIR is scheduled to be finalized in March 2005. As discussed below, certain of the control technology for SO2 and NO. will also aid in the control of mercury. If mercury controls, as discussed below, are required to be implemented prior to the CAIR, the above estimates could be reduced by $100 million to $144 million.

In the May 5, 2004, Federal Register, the EPA published proposed regulations on best available retrofit technology (BART) that would amend its July 1999 regional haze regulations regarding emission controls for industrial facilities emitting air pollutants that reduce visibility. The BART requirement would direct state air quality agencies to identify whether emissions from sources subject to BART are below limits set by the state, or whether retrofit measures are needed to reduce the emissions below those 100 1ill

limits. If the proposed BART regulations are adopted, they will apply to KCP&L units Montrose No. 3, LaCygne No. 1, LaCygne No. 2 and latan. Based on the results of the state air quality studies, KCP&L could be required to achieve compliance by making capital expenditures that would be similar to those required for the proposed CAIR. The EPA is scheduled to adopt final regulations by April 15, 2005; however, if the proposed CAIR is adopted, management believes the EPA will reevaluate the need for the proposed BART regulation.

Mercury Emissions 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 from man-made sources. As a result, in the January 30, 2004, and March 16, 2004, Federal Registers, the EPA published proposed regulations for controlling mercury emissions from coal-fired power plants that contained three options. Two of the options, the EPA's preferred approaches, call for regulating mercury via emission trading regimes under section 111 or section 112 of the Clean Air Act (cap and trade options), and the third option would require utilities to install controls known as maximum achievable control technology (MACT). The EPA is scheduled to issue final rules by March 2005.

Under either of the cap and trade options, both of which would become applicable in 2010, the EPA would establish a mechanism by which mercury emissions from new and existing coal-fired plants would be capped at specified, nationwide levels. A first phase cap of 34 tons would become effective on January 1, 2010, and a second phase cap of 15 tons would become effective on January 1, 2018.

Facilities would demonstrate compliance with the standard by holding one allowance for each ounce of mercury emitted in any given year and allowances would be readily transferable among all regulated facilities nationwide. Under the cap and trade options, KCP&L would be able to purchase mercury allowances that would be available nationwide or elect to install pollution control equipment to achieve compliance. While it is expected that mercury allowances would be available in sufficient quantities for purchase in the 2010-2018 timeframe, the significant reduction in the nationwide cap in 2018 may hamper KCP&L's ability to obtain reasonably priced allowances beyond 2018. Therefore, capital expenditures may be required in the 2016-2018 timeframe to install mercury pollution control equipment.

Under the MACT option, KCP&L could incur capital expenses prior to the 2007-2008 timeframe when the regulation would be applicable. This option would require compliance on a facility basis and therefore the option of trading nationwide mercury allowances would not be available. The EPA stated in the preamble that there are no adequately demonstrated control technologies specifically designed to reduce mercury emissions from coal-fired plants. However, the EPA also stated it is confident such technologies will be commercially available by 2007. There is currently considerable debate at the EPA and within the utility industry whether the installation of pollution control equipment for the control of NO, and SO2 under the CAIR might simultaneously remove mercury to the specified MACT regulatory levels, which is referred to as the co-benefit approach. If this approach is correct, and if the CAIR became final and all of KCP&L's units were subject to the final regulation, KCP&L would not be required to install additional mercury control equipment to achieve compliance with this regulation.

However, if the co-benefit approach is not correct, or if KCP&L units located in Missouri and/or Kansas were not included in the final CAIR regulation, KCP&L would be required to install mercury control equipment prior to 2007. If KCP&L were required to install mercury control equipment on all of its coal-fired plants, it is anticipated that activated carbon injection or comparable technology in conjunction with a baghouse would need to be installed at a projected cost to KCP&L ranging from $170 million to $245 million.

KCP&L is a participant in the DOE project at the Sunflower Electric Holcomb plant to investigate control technology options for mercury removal from coal-fired plants burning sub bituminous coal.

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Carbon Dioxide At a December 1997 meeting in Kyoto, Japan, delegates from 167 nations, including the U.S., agreed to a treaty (Kyoto Protocol) that would require a 7% reduction in U.S. C02 emissions below 1990 levels, a nearly 30% cut from current levels. On March 28, 2001, the Bush administration announced it will not negotiate implementation of the Kyoto Protocol and it will not send the Kyoto Protocol to the U.S.

Senate for ratification.

There are several bills being debated in the U.S. Congress that address the C02 issue, including establishing a nationwide cap on C02 levels. There are various compliance dates and nationwide caps stipulated in the numerous legislative bills being debated. These bills have the potential for a significant financial impact on KCP&L in conjunction with achieving compliance with the proposed new nationwide limits. However, the financial consequences to KCP&L cannot be determined until final legislation is passed. KCP&L will continue to monitor the progress of these bills.

On February 14, 2002, President Bush unveiled his Clear Skies Initiative, which included a climate change policy. The climate change policy is a voluntary program that relies heavily on incentives to encourage industry to voluntarily limit emissions. The strategy includes tax credits, energy conservation programs, funding for research into new technologies, and a plan to encourage companies to track and report their emissions so that companies could gain credits for use in any future emissions trading program. The greenhouse strategy links growth in emissions of greenhouse gases to economic output. The administration's strategy is intended to reduce the greenhouse gas intensity of the U.S. economy by 18% over the next 10 years. Greenhouse gas intensity measures the ratio of greenhouse gas emissions to economic output as measured by Gross Domestic Product (GDP). Under this plan, as the economy grows, greenhouse gases also would continue to grow, although at a slower rate than they would have without these policies in place. When viewed per unit of economic output, the rate of emissions would drop. The plan projects that the U.S. will lower its rate of greenhouse gas emissions from an estimated 183 metric tons per $1 million of GDP in 2002 to 151 metric tons per

$1 million of GDP by 2012.

On December 19, 2002, Great Plains Energy joined the Power Partners through Edison Electric Institute (EEI). Power Partners is a voluntary program with the DOE under which utilities commit to undertake measures to reduce, avoid or sequester CO2 emissions. Eventually, industry sectors and individual companies are expected to enter into an umbrella memorandum of understanding (MOU) that will set forth programs for industries and individual companies to reduce greenhouse gas emissions.

On January 17, 2003, the EEI sent a letter to numerous Administration officials, in which the EEI committed to work with the government over the next decade to reduce the power sector's C02 emissions per kWh generated (carbon intensity) by the equivalent of 3% to 5% of the current level.

On December 13, 2004, Power Partners entered into a cooperative umbrella MOU with the DOE. This MOU contains supply and demand-side actions as well as offset projects that will be undertaken to reduce the power sector's C02 emissions per kWh generated over the next decade consistent with the EEI commitment of 3% to 5%. Individual companies, including KCP&L, will now begin entering into agreements with the DOE that set forth quantitative, concrete and specific activities to reduce, avoid or sequester greenhouse gases.

EPA New Source Review The EPA is conducting an enforcement initiative under Section 114(a) of the Clean Air Act to determine whether modifications at selected coal-fired plants across the U.S. may have been subject to New Source Performance Standards (NSPS) or New Source Review (NSR) requirements. After an operator has received a Section 114 letter, the EPA requests data and reviews all expenditures at the plants to determine if they were routine maintenance or whether the expenditures were for substantial 102 II

modifications or resulted in improved operations. If a plant, subject to a Section 114 letter, is determined to have been subject to NSPS or NSR, the plant could be required to install best available control technology or lowest achievable emission rate technology. KCP&L has not received a Section 114 letter to date.

Air Particulate Mlatter and Ozone 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 (PM-2.5) in diameter. These standards were challenged in Federal court. However, the courts ultimately denied all state, industry and environmental groups petitions for review and thus upheld as valid the EPA's new eight-hour ozone and PM-2.5 National Ambient Air Quality Standards (NAAQS). In so doing, the court held that the EPA acted consistently with the Clean Air Act in setting the standards at the levels it chose and the EPA's actions were reasonable and not arbitrary and capricious, and cited the deference given the EPA's decision-making authority. The court stated that the extensive records established for each rule supported the EPA's actions in both rulemakings. This removed the last major hurdle to the EPA's implementation of stricter ambient air quality standards for ozone and fine particles. On December 17, 2004, the EPA designated the Kansas City area as attainment with respect to the PM-2.5 NAAQS.

On April 15, 2004, the EPA designated the Kansas City area as unclassifiable with respect to the eight-hour ozone NAAQS based on 2003 ozone season data. In the February 10, 2005, Federal Register, the EPA issued a proposed rule to redesignate Johnson, Linn, Miami and Wyandotte Counties in Kansas and Cass, Clay, Jackson and Platte Counties in Missouri to attainment for the eight-hour ozone standard. The EPA is scheduled to designate attainment areas for the eight-hour ozone NAAQS by April 15, 2005.

Water Use Regulations On February 16, 2004, the EPA finalized the Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures at existing facilities. The final rule was published in the July 9, 2004, Federal Register with an effective date of September 7, 2004. This final regulation is applicable to certain existing power producing facilities that employ cooling water intake structures that withdraw 50 million gallons or more per day and use 25% or more of that water for cooling purposes. KCP&L is required to complete a Section 316(b) comprehensive demonstration study on each of its generating facilities' intake structures by the end of 2007. KCP&L plans to complete the comprehensive demonstration studies by the end of 2006 at an expected cost of $0.3 million to $0.5 million per facility. Depending on the outcome of the comprehensive demonstration studies, facilities may be required to implement technological, operational or restoration measures to achieve compliance. Compliance with the final rule is expected to be achieved between 2011 and 2014. Until the Section 316(b) comprehensive demonstration studies are completed, the impact of this final rule cannot be quantified.

Southwest Power Pool Regional Transmission Organization Under the FERC Order 2000, KCP&L, as an investor-owned utility, is strongly encouraged to join a FERC approved Regional Transmission Organization (RTO). RTOs combine transmission operations of utility businesses into regional organizations that schedule transmission services and monitor the energy market to ensure regional transmission reliability and non-discriminatory access. The Southwest Power Pool (SPP), of which KCP&L is a member, obtained approval from FERC as an RTO in a January 24, 2005, order. KCP&L intends on participating in the SPP RTO; however, state regulatory approvals are required. KCP&L anticipates making the necessary applications to the MPSC and the KCC, during the second quarter of 2005 upon completion of the regional cost/benefit analysis currently being conducted for the SPP RTO. This cost/benefit analysis is being conducted under the 103

direction of the SPP Regional State Committee (composed of state commissions from the states where the SPP RTO operates) and is expected to be completed in the first quarter of 2005.

Pennsylvania Gross Receipts Tax Contingency In January 2005, Strategic Energy was advised by the Pennsylvania Department of Revenue of a potential tax deficiency relating to state gross receipts tax on Strategic Energy's Provider of Last Resort (POLR) revenues from 2000 to 2002. After consulting with external legal counsel, management believes the Pennsylvania Department of Revenue does not have an appropriate basis for a tax deficiency claim. Management believes, but cannot assure, that Strategic Energy will prevail if a claim is formally asserted. Strategic Energy has not accrued for any portion of this contingency at December 31, 2004. If this claim is formally asserted and the Pennsylvania Department of Revenue is successful, Strategic Energy's total anticipated loss for the period 2000 through 2004 is a maximum of

$16.4 million.

Income Tax Contingencies See Note 11 for information regarding income tax contingences.

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

2004 2003 2002 (millions)

Consolidated KCP&L $18.4 $23.1 $25.7 Other Great Plains Energy (a) 1.9 1.0 1.7 Total Great Plains Energy $20.3 $24.1 $27.4 (a) Includes insignificant amounts related to discontinued operations.

Great Plains Energy's and consolidated KCP&L's contractual commitments excluding pensions and long-term debt are detailed in the following tables.

Great Plains Energy Contractual Commitments 2005 2006 2007 2008 2009 After 2009 Total (millions)

Lease commitments $ 21.4 $ 21.7 $ 13.4 $ 11.1 $ 8.7 $ 85.2 $ 161.5 Purchase commitments Fuel (a) 74.2 80.7 63.7 30.9 7.3 43.2 300.0 Purchased capacity 10.9 5.4 5.5 5.6 4.4 24.8 56.6 Purchased power 697.2 201.5 65.6 10.3 3.7 3.7 982.0 Other 32.9 5.2 4.0 4.7 - - 46.8 Total contractual commitments $836.6 $314.5 $152.2 $ 62.6 $ 24.1 $156.9 $1,546.9 (a) Fuel commitments consists of commitments for nuclear fuel, coal and coal transportation costs.

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Consolidated KCP&L Contractual Commitments 2005 2006 2007 2008 2009 After 2009 Total (millions)

Lease commitments $ 20.1 $ 20.5 $ 12.4 $ 10.3 $ 8.7 $ 85.2 $ 157.2 Purchase commitments Fuel (a) 74.2 80.7 63.7 30.9 7.3 43.2 300.0 Purchased capacity 10.9 5.4 5.5 5.6 4.4 24.8 56.6 Other 32.9 5.2 4.0 4.7 - - 46.8 Total contractual commitments $138.1 $111.8 $ 85.6 $ 51.5 $ 20.4 $153.2 $ 560.6 (a) Fuel commitments consists of commitments for nuclear fuel, coal and coal transportation costs.

Lease commitments end in 2028 and include insignificant amounts for capital leases. These amounts exclude possible termination payments under the synthetic lease arrangement with the Lease Trust.

As the managing partner of three jointly owned generating units, KCP&L has entered into leases for railcars to serve those units. Consolidated KCP&L has reflected the entire lease commitment in the above amounts, although the other owners will reimburse about $2.0 million per year ($21.9 million total).

KCP&L purchases capacity from other utilities and nonutility suppliers. Purchasing capacity provides the option to purchase energy if needed or when market prices are favorable. KCP&L has capacity sales agreements not included above that total $11.7 million for 2005, $11.4 million for 2006, $11.2 million per year for 2007 through 2009 and $23.5 million after 2009.

Purchased power represents Strategic Energy's agreements to purchase electricity at various fixed prices to meet estimated supply requirements. Strategic Energy has energy sales contracts not included above for 2005 through 2007 totaling $69.1 million, $8.7 million and $0.6 million, respectively.

Synthetic Lease In 2001, KCP&L entered into a synthetic lease arrangement with a Lease Trust (Lessor) to finance the purchase, installation, assembly and construction of five combustion turbines and related property and equipment that added 385 MWs of peaking capacity (Project). Rental payments under the lease, which reflects interest payments only, began in 2004 and end in October 2006. KCP&L's expense for the synthetic lease was $1.9 million in 2004. Upon a default during the lease period, KCP&L's maximum obligation to the Lessor equals 100% of project costs, approximately $154.0 million. KCP&L's rental obligation for the years 2005 and 2006 are $5.3 million and $5.9 million, respectively. At the end of the lease term, KCP&L may choose to sell the project for the Lessor, guaranteeing that the Lessor receives a residual value for the Project in an amount, which may be up to 83.21 % of the project cost.

Alternatively, KCP&L may purchase the facility at an amount equal to the project cost.

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

14. GUARANTEES In the normal course of business, Great Plains Energy and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees and indemnification of letters of credit 105

and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended business purposes. The majority of these agreements guarantee the Company's own future performance, so a liability for the fair value of the obligation is not recorded.

As of December 31, 2004, KCP&L had guarantees, with a maximum potential of $6.4 million, for energy savings under agreements with several customers that expire over the next six years. In most cases, a subcontractor would indemnify KCP&L for any payments made by KCP&L under these guarantees.

These guarantees were entered into before December 31, 2002; therefore, a liability was not recorded in accordance with FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Guarantees of Indebtedness of Others."

15. LEGAL PROCEEDINGS Strategic Energy On March 23, 2004, Robert C. Haberstroh filed suit for breach of employment contract and violation of the Pennsylvania Wage Payment Collection Act against Strategic Energy Partners, Ltd. (Partners), SE Holdings and Strategic Energy in the Court of Common Pleas of Allegheny County, Pennsylvania. Mr.

Haberstroh claims that he acquired an equity interest in Partners under the terms of his employment agreement and that through a series of transactions, Mr. Haberstroh's equity interest became an equity interest in SE Holdings. In 2001, Mr. Haberstroh's employment was terminated and SE Holdings redeemed his equity interest. Mr. Haberstroh is seeking the loss of his non-equity compensation (including salary, bonus and benefits) and equity compensation and associated distributions (his equity interest in SE Holdings).

Strategic Energy has filed a counterclaim against Mr. Haberstroh for breach of contract. SE Holdings, and its direct and indirect owners, have agreed to indemnify Strategic Energy and Innovative Energy Consultants Inc. against any judgment or settlement of Mr. Haberstroh's claim that relates to his equity interest in SE Holdings, up to a maximum amount of approximately $8 million.

See Note 12 for further information regarding related party transactions.

KLT Gas On July 28, 2004, KLT Gas received a Notice and Demand for Arbitration Pursuant to Joint Operating Agreement from SWEPI LP doing business as Shell Western E&P and formerly known as Shell Western E&P Inc. (Shell). Prior to the October 2004 sale (with a July 1, 2004, effective date) of KLT Gas' working interests in certain oil and gas leases in Duval County, Texas to Shell, KLT Gas had a 50% working interest in the leases. Shell held the other 50% working interest and was the operator of the properties under a joint operating agreement, as amended (JOA). Three groups of current or past lessors filed suit against Shell in Duval County, Texas, alleging various claims against Shell.

Additionally, Shell has been party to ongoing proceedings before the Texas Railroad Commission relating to a well drilled on acreage adjacent to the properties of Shell and KLT Gas mentioned above.

Through arbitration, Shell is seeking recovery from KLT Gas of 50% of the fees and costs incurred in the three lawsuits and the Texas Railroad Commission proceedings and settlement proceeds paid with respect to the three lawsuits, which Shell asserts is a total amount of not less than $5.4 million for KLT Gas' share. Shell is also seeking a declaration that the fees and costs incurred and settlement proceeds paid, including any fees and costs incurred in the future, are reimbursable expenses under the JOA. Shell is seeking a ruling compelling KLT Gas to pay Shell immediately all sums deemed to be due pursuant to the arbitration. On August 17, 2004, KLT Gas submitted its notice of defense generally asserting that there is no contractual basis or implied duty for reimbursement or contribution regarding the settlements and there is no contractual basis for reimbursement or contribution regarding the Texas 106 Iil

Railroad Commission proceedings. KLT Gas also asserted counterclaims based upon misrepresentations and promissory estoppel, gross negligence in imprudent operations, full accounting under the JOA and offset. The arbitration is currently scheduled to begin in May 2005. KLT Gas and its counsel continue to evaluate KLT Gas' rights and obligations under the JOA as well as other possible counterclaims that KLT Gas may have against Shell; however, management is unable to predict the ultimate outcome of this demand for arbitration.

Hawthorn No. 5 Subrogation Litigation KCP&L filed suit against National Union Fire Insurance Company of Pittsburgh, Pennsylvania (National Union) and Travelers Indemnity Company of Illinois (Travelers) in Missouri state court on June 14, 2002, which was removed to the U.S. District Court for the Western District of Missouri. In 1999, there was a boiler explosion at KCP&L's Hawthorn No. 5 generating unit, which was subsequently reconstructed and returned to service. National Union and Reliance National Insurance had issued a $200 million primary insurance policy and Travelers had issued a $100 million secondary insurance policy covering Hawthorn No. 5. A dispute arose among KCP&L, National Union and Travelers regarding the amount payable under these insurance policies for the reconstruction of Hawthorn No. 5 and replacement power expenses, and KCP&L filed suit against the two carriers. In that suit, KCP&L sought recovery, subject to the limits of the insurance policies, of Hawthorn No. 5 reconstruction costs and replacement power expenses, plus damages and attorneys' fees from National Union for failing to pay the full amount of its insurance policy. In 2004, KCP&L settled with National Union for the amount remaining under the primary insurance policy limit, less the applicable deductible. In January 2005, KCP&L settled with Travelers for $10 million. This settlement does not encompass any alleged subrogation claims Travelers may have against National Union or any alleged subrogation claims with regard to possible future recoveries by National Union and KCP&L in the litigation described in the next paragraph.

KCP&L also filed suit on April 3, 2001, in Jackson County, Missouri Circuit Court against multiple defendants who are alleged to have responsibility for the Hawthorn No. 5 boiler explosion. KCP&L and National Union have entered into a subrogation allocation agreement under which recoveries in this suit are generally allocated 55% to National Union and 45% to KCP&L. Certain defendants have been dismissed from the suit and various other defendants have settled with KCP&L. KCP&L received

$38.2 million under the terms of the subrogation allocation agreement. Trial of this case with the one remaining defendant resulted in a March 2004 jury verdict finding KCP&L's damages as a result of the explosion were $452 million. After deduction of amounts received from pre-trial settlements with other defendants and an amount for KCP&L's comparative fault (as determined by the jury), the verdict would have resulted in an award against the defendant of approximately $97.6 million (of which KCP&L would have received $33 million pursuant to the subrogation allocation agreement after payment of attorney's fees). In response to post-trial pleadings filed by the defendant, in May 2004 the trial judge reduced the award against the defendant to $0.2 million. Both KCP&L and the defendant have appealed this case to the Court of Appeals for the Western District of Missouri.

KLT Telecom On December 31, 2001, a subsidiary of KLT Telecom, DTI Holdings, Inc. (Holdings) and its subsidiaries Digital Teleport Inc. (Digital Teleport) and Digital Teleport of Virginia, Inc., filed separate voluntary petitions in the Bankruptcy Court for the Eastern District of Missouri for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In 2003, the Bankruptcy Court confirmed the plan of reorganization for these three companies. The Bankruptcy Court conducted an evidentiary hearing regarding three priority proofs of claim by the Missouri Department of Revenue (MODOR) in the aggregate amount of

$2.8 million (collectively, the MODOR Claim), and ruled substantially in favor of Digital Teleport.

MODOR has appealed this ruling. KLT Telecom may receive an additional distribution from the bankruptcy estate; however, the amount and timing of any additional distribution is dependent upon the outcome of the MODOR appeal.

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

The put option provides for an aggregate exercise price for these remaining shares equal to their fair market value with an aggregate floor amount of $15 million. The floor amount of the put option was fully reserved during 2001. On September 2, 2003, Weinstein delivered to KLT Telecom notice of the exercise of his put option. KLT Telecom declined to pay Weinstein any amount under the put option because, among other things, the stock of Holdings has been cancelled and extinguished pursuant to the joint Chapter 11 plan confirmed by the Bankruptcy Court. Weinstein has sued KLT Telecom for allegedly breaching the put option. Trial of this suit is scheduled to begin in May 2005.

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

The adoption of SFAS No. 143 changed the accounting for and the method used to report KCP&L's obligation to decommission its 47% share of Wolf Creek. The legal obligation to decommission Wolf Creek was incurred when the plant was placed in service in 1985. The estimated liability, recognized on KCP&L's balance sheet at January 1, 2003, was based on a third party nuclear decommissioning study conducted in 2002. KCP&L used a credit-adjusted risk free discount rate of 6.42% to calculate the retirement obligation. This estimated rate was based on the rate KCP&L could issue 30-year bonds, adjusted downward to reflect the portion of the anticipated costs in current year dollars that had been funded at date of adoption through a tax-qualified trust fund. The cumulative impact of prior decommissioning accruals recorded consistent with rate orders issued by the MPSC and KCC has been reversed with an offsetting reduction of the regulatory asset established upon adoption of SFAS No. 143, as described below. Amounts collected through these rate orders have been deposited in a legally restricted external trust fund. The fair market value of the trust fund was $84.1 million and

$75.0 million at December 31, 2004 and 2003, respectively.

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

depending on the anticipated settlement date.

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

On January 1, 2003, KCP&L recorded an ARO of $99.2 million, reversed the decommissioning liability of $64.6 million previously accrued and increased property and equipment, net of accumulated depreciation, by $18.3 million. KCP&L is a regulated utility subject to the provisions of SFAS No. 71 108 Il

and management believes it is probable that any differences between expenses under SFAS No. 143 and expenses recovered currently in rates will be recoverable in future rates. As a result, the

$16.3 million net cumulative effect ($80.9 million gross cumulative effect net of $64.6 million decommissioning liability previously accrued) of the adoption of SFAS No. 143 was recorded as a regulatory asset and therefore, had no impact on net income.

In addition, KCP&L recognizes removal costs for utility assets that do not have an associated legal retirement obligation. Historically, these removal costs have been reflected as a component of depreciation in accordance with regulatory treatment. In conjunction with the adoption of SFAS No.

143, non-legal costs of removal were reclassified for all periods presented from accumulated depreciation to a regulatory asset.

KCP&L has legal ARO for certain other assets where it is not possible to estimate the time period when the obligations will be settled. Consequently, the retirement obligations cannot be measured at this time. For transmission easements obtained by condemnation, KCP&L must remove its transmission lines if the line is de-energized. It is extremely difficult to obtain siting for new transmission lines.

Consequently, KCP&L does not anticipate de-energizing any of its existing lines. KCP&L also operates, under state permits, ash landfills at several of its power plants. While the life of the ash landfill at one plant can be estimated and is included in the estimated liabilities above, the future life of ash landfills at other permitted landfills cannot be estimated. KCP&L can continue to maintain permits for these landfills after the adjacent plant is closed.

KLT Gas had estimated liabilities for gas well plugging and abandonment, facility removal and surface restoration. As a result of the sale of the KLT Gas portfolio discussed in Note 6, the new owners have assumed the ARO related to the KLT Gas portfolio estimated to be $1.8 million as December 31, 2003.

The following table summarizes the change in Great Plains Energy's and consolidated KCP&L's ARO, excluding prior year amounts included in Liabilities of Discontinued Operations. Pro forma amounts for 2002 illustrate the effect on ARO if the provisions of SFAS No. 143 had been applied prior to the January 1, 2003, adoption and were measured using assumptions consistent with the period of adoption.

December 31 2004 2003 2002 (millions)

ARO beginning of period $ 106.7 $ 99.2 $ 93.1 Additions - 1.0 Accretion 7.0 6.5 6.1 ARO end of period $ 113.7 $ 106.7 $ 99.2

17. SEGMENT AND RELATED INFORMATION Great Plains Energy Great Plains Energy has two reportable segments based on its method of internal reporting, which generally segregates the reportable segments based on products and services, management responsibility and regulation. The two reportable business segments are KCP&L, an integrated, regulated electric utility, which provides reliable, affordable electricity to customers; and Strategic Energy, a competitive electricity supplier, which operates in several electricity markets offering retail choice. Other includes the operations of HSS, GPP, Services, all KLT Inc. operations other than Strategic Energy, unallocated corporate charges and intercompany eliminations. Intercompany eliminations include insignificant amounts of intercompany financing related activities. The summary of significant accounting policies applies to all of the reportable segments. For segment reporting, each 109

segment's income taxes include the effects of allocating holding company tax benefits. Segment performance is evaluated based on net income.

The tables below reflect summarized financial information concerning Great Plains Energy's reportable segments.

Strategic Great Plains 2004 KCP&L Energy Other Energy (millions)

Operating revenues $ 1,090.1 $ 1,372.4 $ 1.5 $ 2,464.0 Depreciation (144.3) (4.8) (1.0) (150.1)

Interest charges (73.7) (0.7) (8.6) (83.0)

Income taxes (55.7) (24.3) 25.5 (54.5)

Loss from equity investments - - (1.5) (1.5)

Discontinued operations - - 7.3 7.3 Net income (loss) 150.0 42.5 (11.7) 180.8 Strategic Great Plains 2003 KCP&L Energy Other Energy (millions)

Operating revenues $ 1,054.9 $ 1,091.0 $ 2.1 $ 2,148.0 Depreciation (139.9) (1.7) (1.2) (142.8)

Interest charges (69.9) (0.4) (5.9) (76.2)

Income taxes (84.4) (30.2) 36.0 (78.6)

Loss from equity investments - - (2.0) (2.0)

Discontinued operations - - (44.8) (44.8)

Net income (loss) 127.2 39.6 (21.9) 144.9 Strategic Great Plains 2002 KCP&L Energy Other Energy (millions)

Operating revenues $ 1,009.9 $ 789.5 $ 2.9 $ 1,802.3 Depreciation (144.3) (0.9) (1.6) (146.8)

Interest charges (80.3) (0.3) (6.8) (87.4)

Income taxes (63.4) (25.2) 37.3 (51.3)

Loss from equity investments - - (1.2) (1.2)

Discontinued operations - - (7.5) (7.5)

Cumulative effect of a change in accounting principle - - (3.0) (3.0)

Net income (loss) 102.9 29.7 (6.4) 126.2 110 III

Strategic Great Plains KCP&L Energy Other Energy 2004 (millions)

Assets $ 3,330.2 $ 407.7 $ 61.0 $ 3,798.9 Capital expenditures (a) 190.8 2.6 3.3 196.7 2003 Assets $ 3,293.5 $ 283.0 $ 105.5 $ 3,682.0 Capital expenditures (a) 148.8 3.1 - 151.9 2002 Assets $ 3,084.5 $ 226.0 $ 206.6 $ 3,517.1 Capital expenditures (a) 132.1 2.1 (0.3) 133.9 (a) Capital expenditures reflect annual amounts for the periods presented.

Consolidated KCP&L The following tables reflect summarized financial information concerning consolidated KCP&L's reportable segment. Other includes the operations of HSS and intercompany eliminations.

Intercompany eliminations include insignificant amounts of intercompany financing related activities.

Consolidated 2004 KCP&L Other KCP&L (millions)

Operating revenues $ 1,090.1 $ 1.5 $ 1,091.6 Depreciation (144.3) (0.9) (145.2)

Interest charges (73.7) (0.5) (74.2)

Income taxes (55.7) 2.9 (52.8)

Net income (loss) 150.0 (6.7) 143.3 Consolidated 2003 KCP&L Other KCP&L (millions)

Operating revenues $ 1,054.9 $ 2.1 $ 1,057.0 Depreciation (139.9) (1.1) (141.0)

Interest charges (69.9) (0.4) (70.3)

Income taxes (84.4) 0.9 (83.5)

Discontinued operations - (8.7) (8.7)

Net income (loss) 127.2 (10.0) 117.2 Consolidated 2002 KCP&L Other KCP&L (millions)

Operating revenues $ 1,009.9 $ 2.9 $ 1,012.8 Depreciation (144.3) (1.2) (145.5)

Interest charges (80.3) - (80.3)

Income taxes (63.4) 0.5 (62.9)

Discontinued operations - (4.0) (4.0)

Cumulative effect of a change in accounting principle - (3.0) (3.0)

Net income (loss) 102.9 (7.2) 95.7 i11

Consolidated KCP&L Other KCP&L 2004 (millions)

Assets $ 3,330.2 $ 7.2 $ 3,337.4 Capital expenditures (a) 190.8 - 190.8 2003 Assets $ 3,293.5 $ 9.1 $ 3,302.6 Capital expenditures (a) 148.8 - 148.8 2002 Assets $ 3,084.5 $ 54.7 $ 3,139.2 Capital expenditures (a) 132.1 0.1 132.2 (a) Capital expenditures reflect annual amounts for the periods presented.

18. SHORT-TERM BORROWINGS AND SHORT-TERM BANK LINES OF CREDIT In December 2004, Great Plains Energy syndicated a $550 million, five-year revolving credit facility with a group of banks replacing a $150.0 million 364-day revolving credit facility and a $150.0 million three-year revolving credit facility with a group of banks that were syndicated earlier in 2004. Those latter two facilities had replaced a $225.0 million revolving credit facility with a group of banks. A default by Great Plains Energy or any of its significant subsidiaries of other indebtedness totaling more than

$25.0 million is a default under the current facility. Under the terms of the agreement, Great Plains Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At December 31, 2004, the Company was in compliance with this covenant. At December 31, 2004, Great Plains Energy had

$20.0 million of outstanding borrowings with an interest rate of 3.04% and had issued letters of credit totaling $8.0 million under the credit facility as credit support for Strategic Energy. At December 31, 2003, Great Plains Energy had $87.0 million of outstanding borrowings under the $225.0 million revolving credit facility with a weighted-average interest rate of 2.12% and had issued a letter of credit for $15.8 million as credit support for Strategic Energy.

KCP&L's short-term borrowings consist of funds borrowed from banks or through the sale of commercial paper as needed. In December 2004, KCP&L syndicated a $250 million five-year revolving credit facility. This facility replaced $155 million in 364-day bilateral credit lines KCP&L had in place with a group of banks. A default by KCP&L on other indebtedness totaling more than $25.0 million is a default under the current facility. Under the terms of the agreement, KCP&L is required to maintain a consolidated indebtedness to consolidated capitalization ratio, as defined in the agreement, not greater than 0.65 to 1.00 at all times. At December 31, 2004, KCP&L was in compliance with this covenant. At December 31, 2004 and 2003, KCP&L had no short-term borrowings outstanding.

During 2004, Strategic Energy syndicated a $125.0 million three-year revolving credit facility with a group of banks. Great Plains Energy has guaranteed $25.0 million of this facility. This facility replaced a $95.0 million revolving credit facility with a group of banks. A default by Strategic Energy of other indebtedness, as defined in the new facility, totaling more than $7.5 million is a default under the facility. Under the terms of this agreement, Strategic Energy is required to maintain a minimum net worth of $62.5 million, a maximum funded indebtedness to EBITDA ratio of 2.25 to 1.00, a minimum fixed charge coverage ratio of at least 1.05 to 1.00 and a minimum debt service coverage ratio of at least 4.00 to 1.00 as those are defined in the agreement. In the event of a breach of one or more of these four covenants, so long as no other default has occurred, Great Plains Energy may cure the breach through a cash infusion, a guarantee increase or a combination of the two. At December 31, 2004, Strategic Energy was in compliance with these covenants. At December 31, 2004, $69.2 million in letters of credit had been issued and there were no borrowings under the agreement. At December 31, 2003, $58.5 million in letters of credit had been issued under the previous agreement.

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On June 30, 2003, HSS completed the disposition of its interest in RSAE. RSAE's line of credit totaling

$27 million was cancelled. With proceeds from a note to Great Plains Energy, HSS repaid $22.1 million on the supported bank line. HSS repaid all but an immaterial amount of the notes payable to Great Plains Energy during 2004. At December 31, 2003, the notes payable to Great Plains Energy totaled

$22.0 million. See Note 7 for additional information concerning the disposition of RSAE.

19. LONG-TERM DEBT AND EIRR BONDS CLASSIFIED AS CURRENT LIABILITIES Great Plains Energy and consolidated KCP&L's long-term debt is detailed in the following table.

December 31 Year Due 2004 2003 Consolidated KCP&L (thousands)

General Mortgage Bonds 7.95%* and 7.55%** Medium-Term Notes 2007 $ 500 $ 55,000 2.26%* and 2.36%** EIRR bonds 2012-2023 158,768 158,768 Senior Notes 7.125% 2005 250,000 250,000 6.500% 2011 150,000 150,000 6.000% 2007 225,000 225,000 Unamortized discount (465) (689)

EIRR bonds 2.29%* and 2.16%** Series A & B 2015 106,991 108,919 2.38%* and 2.25%** Series C 2017 50,000 50,000 2.29%* and 2.16%** Series D 2017 40,183 40,923 8.3% Junior Subordinated Deferred Interest Bonds - 154,640 2.10%* and 1.25%** Combustion Turbine Synthetic Lease 2006 145,274 143,811 Current liabilities EIRR bonds classified as current (85,922) (129,288)

Current maturities (250,000) (54,500)

Total consolidated KCP&L excluding current liabilities 790,329 1,152,584 Other Great Plains Energy 4.25% FELINE PRIDES Senior Notes 2009 163,600 7.64%* and 7.84%** Affordable Housing Notes 2005-2008 5,761 10,564 Current maturities (3,230) (4,803)

Total consolidated Great Plains Energy excluding current maturities $ 956,460 $ 1,158,345 Weighted-average rate as of December 31, 2004 Weighted-average rate as of December 31, 2003 Amortization of Debt Expense Great Plains Energy's and consolidated KCP&L's amortization of debt expense is detailed in the following table.

2004 2003 2002 (millions)

Consolidated KCP&L $ 2.1 $ 2.1 $ 2.1 Other Great Plains Energy 1.8 1.4 0.8 Total Great Plains Energy $ 3.9 $ 3.5 $ 2.9 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 113

plant. Mortgage bonds secure $159.3 million and $213.8 million of medium-term notes and Environmental Improvement Revenue Refunding (EIRR) bonds at December 31, 2004 and 2003, respectively. In 2004, KCP&L redeemed $54.5 million of its medium-term notes at maturity.

In August 2004, KCP&L secured a municipal bond insurance policy as a credit enhancement to its secured 1992 series EIRR bonds totaling $31.0 million. This municipal bond insurance policy replaced a 364-day credit facility with a bank, which expired in August 2004 that previously supported full liquidity of these bonds. These variable-rate secured EIRR bonds with a final maturity in 2017 are remarketed on a weekly basis through a Dutch auction process. The insurance agreement between KCP&L and XL Capital Assurance Inc. (XLCA), the issuer of the municipal bond insurance policy, provides for reimbursement by KCP&L for any amounts that XLCA pays under the municipal bond insurance policy.

The insurance policy is in effect for the term of the bonds. The insurance agreement contains a covenant that the indebtedness to total capitalization ratio of KCP&L and its consolidated subsidiaries will not be greater than 0.68 to 1.00. At December 31, 2004, KCP&L was in compliance with this covenant. KCP&L is also restricted from issuing additional bonds under its General Mortgage Indenture if, after giving effect to such additional bonds, the proportion of secured debt to total indebtedness would be more than 75%, or more than 50% if the long term rating for such bonds by Standard & Poor's or Moody's Investors Service would be at or below A- or A3, respectively. In the event of a default under the insurance agreement, XLCA may take any available legal or equitable action against KCP&L, including seeking specific performance of the covenants.

During 2004, KCP&L remarketed its secured 1994 series EIRR bonds totaling $35.9 million at a fixed rate of 2.25% ending August 31, 2005. If the bonds could not be remarketed, KCP&L would be obligated to either purchase or retire the bonds. KCP&L also remarketed its secured 1993 series EIRR bonds totaling $12.4 million at a fixed rate of 4.0% until maturity at January 2, 2012. The previous interest rate periods on these two series, with interest rates of 3.9%, expired on August 31, 2004. The

$35.9 million of secured 1994 series EIRR bonds were classified as current liabilities at December 31, 2004. Both of these series were classified as current liabilities at December 31, 2003.

KCP&L Unsecured Notes KCP&L had $196.5 million of unsecured EIRR bonds outstanding excluding the fair value of interest rate swaps of $0.7 million and $3.3 million at December 31, 2004 and 2003, respectively. During 2004, KCP&L remarketed its 1998 Series C EIRR bonds, totaling $50.0 million due 2017, at a fixed rate of 2.38% ending August 31, 2005. If the bonds could not be remarketed, KCP&L would be obligated to either purchase or retire the bonds. The previous interest rate period on this series, with an interest rate of 2.25%, expired on August 31, 2004. The Series C EIRR bonds were classified as current liabilities at December 31, 2004 and 2003.

In 1997, KCPL Financing I issued $150.0 million of 8.3% preferred securities and KCP&L invested

$4.6 million in common securities of KCPL Financing I. The sole asset of KCPL Financing I was the

$154.6 million principal amount of 8.3% Junior Subordinated Deferrable Interest Debentures, due 2037, issued by KCP&L. In July 2004, KCP&L redeemed the $154.6 million 8.3% Junior Subordinated Deferred Interest Debentures. KCPL Financing I used the proceeds from the repayment of the 8.3%

Junior Subordinated Deferrable Interest Debentures to redeem the $4.6 million of common securities held by KCP&L and the $150.0 million of 8.3% preferred securities.

Other Great Plains Energy Long-Term Debt Great Plains Energy filed a registration statement, which became effective in April 2004, for the issuance of an aggregate amount up to $500.0 million of any combination of senior debt securities, subordinated debt securities, trust preferred securities and related guarantees, common stock, warrants, stock purchase contracts or stock purchase units. The prospectus filed with this registration 114

statement also included $148.2 million of securities remaining available to be offered under a prior registration statement providing for an aggregate amount of availability of $648.2 million.

In June 2004, Great Plains Energy issued $163.6 million of FELINE PRIDES under this registration statement. After this transaction and the stock issuance discussed in Note 20, $171.0 million remains available under the registration statement. FELINE PRIDES, each with a stated amount of $25, initially consist of an interest in a senior note due February 16, 2009, and a contract requiring the holder to purchase the Company's common stock on February 16, 2007. Each purchase contract obligates the holder of the purchase contract to purchase, and Great Plains Energy to sell, on February 16, 2007, for

$25 in cash, newly issued shares of the Company's common stock equal to the settlement rate. The settlement rate will vary according to the applicable market value of the Company's common stock at the settlement date. Applicable market value will be measured by the average of the closing price per share of the Company's common stock on each of the 20 consecutive trading days ending on the third trading day immediately preceding February 16, 2007. The settlement rate will be applied to the 6.5 million FELINE PRIDES at the settlement date to issue a number of common shares determined as described in the following table.

Applicable Settlement rate Market value market value (in common shares) per common share (a)

$35.40 or greater 0.7062 to 1 Greater than $25 per common share

$35.40 to $30.00 $25 divided by the applicable Equal to $25 per common share market value to 1

$30.00 or less 0.8333 to 1 Less than $25 per common share (a) Assumes that the market price of the Company's common stock on February 16, 2007, is the same as the applicable market value.

Great Plains Energy will make quarterly contract adjustment payments at the rate of 3.75% per year and interest payments at the rate of 4.25% per year both payable in February, May, August and November of each year, which commenced August 16, 2004. Great Plains Energy must attempt to remarket the senior notes, in whole but not in part. If the senior notes are not successfully remarketed by February 16, 2007, Great Plains Energy will exercise its rights as a secured party to dispose of the senior notes in accordance with applicable law and satisfy in full each holder's obligation to purchase the Company's common stock under the purchase contracts.

The June 2004 fair value of the contract adjustment payments of $15.4 million was recorded as a liability in other deferred credits and other liabilities with a corresponding amount recorded as capital stock premium and expense on Great Plains Energy's consolidated balance sheet. Expenses incurred with the offering were allocated between the senior notes and the purchase contracts. Expenses allocated to the senior notes of $1.2 million have been deferred and are being recognized as interest expense over the term of the notes. Expenses allocated to the purchase contracts of $4.2 million were recorded as capital stock premium and expense. Great Plains Energy has the right to defer the contract adjustment payment on the purchase contracts, but not the interest payments on the senior notes. In the event Great Plains Energy exercises its option to defer the payment of contract adjustment payments, Great Plains Energy and its subsidiaries are not permitted to, with certain exceptions, declare or pay dividends on, make distributions with respect to, or redeem, purchase or acquire, or make a liquidation payment with respect to, any capital stock of Great Plans Energy until the deferred contract adjustment payments have been paid.

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 115

installment to be held as cash, cash equivalents or marketable securities. At December 31, 2004, the collateral was held entirely as cash and totaled $3.7 million. At December 31, 2003, collateral of

$4.7 million was held as cash and $1.5 million was held in equity securities for these notes. The equity securities were included in other investments and nonutility property on Great Plains Energy's consolidated balance sheets.

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

2005 2006 2007 2008 2009 (millions)

Consolidated KCP&L $ 250.0 $ 145.2 $ 225.5 $ - $ -

Other Great Plains Energy 3.2 1.8 164.1 0.3 -

Total Great Plains Energy $ 253.2 $ 147.0 $ 389.6 $ 0.3 $ -

20. COMMON STOCK EQUITY AND PREFERRED STOCK Common Stock Equity In 2004, Great Plains Energy issued 5.0 million shares of common stock at $30 per share under the registration statement discussed in Note 19 with $150.0 million in gross proceeds. Issuance costs of

$5.4 million are reflected in capital stock premium and expense on Great Plains Energy's consolidated balance sheet and statement of common stock equity at December 31, 2004.

Treasury shares are held for future distribution upon exercise of options issued in conjunction with the Company's equity compensation plan.

Great Plains Energy has 3.0 million shares of common stock registered with the SEC for a Dividend Reinvestment and Direct Stock Purchase Plan (Plan). The Plan allows for the purchase of common shares by reinvesting dividends or making optional cash payments. Great Plains Energy can issue new shares or purchase shares on the open market for the Plan. At December 31, 2004, 2.2 million shares remained available for future issuances.

Great Plains Energy has 9.3 million shares of common stock registered with the SEC for a defined contribution savings plan. The Company matches employee contributions, subject to limits. At December 31, 2004, 1.1 million shares remained available for future issuances.

Under the 35 Act, Great Plains Energy and KCP&L can pay dividends only out of retained or current earnings, unless authorized to do otherwise by the SEC. Under stipulations with the MPSC and KCC, Great Plains Energy and KCP&L have committed to maintain consolidated common equity of not less than 30% and 35%, respectively. Pursuant to SEC order, Great Plains Energy's and KCP&L's authorization to issue securities is conditioned on maintaining a consolidated common equity capitalization of at least 30%.

Great Plains Energy's Articles of Incorporation 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.

116 II I

Great Plains Energy made capital contributions to KCP&L of $225 million and $100 million in 2004 and 2003, respectively. These contributions were used to pay down long-term debt. At December 31, 2004, KCP&L's capital contributions from Great Plains Energy totaled $400 million which is reflected in common stock in the consolidated KCP&L balance sheet.

Preferred Stock As of December 31, 2004, 1.6 million shares of Cumulative No Par Preferred Stock and 11.0 million shares of no par Preference Stock were authorized under Great Plains Energy's Articles of Incorporation. Great Plains Energy has the option to redeem the $39.0 million of issued Cumulative Preferred Stock at prices approximating par or stated value.

21. DERIVATIVE FINANCIAL INSTRUMENTS 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 risk management activities, including the use of derivatives, are subject to the management, direction and control of internal risk management committees. The Company's interest rate risk management strategy uses derivative instruments to adjust the Company's liability portfolio to optimize the mix of fixed and floating rate debt within an established range. The Company maintains commodity-price risk management strategies that use derivative instruments to reduce the effects of fluctuations on purchased power expense caused by commodity price volatility. Counterparties on commodity derivatives and interest rate swap agreements expose the Company to credit loss in the event of nonperformance. This credit loss is limited to the cost of replacing these contracts at current market rates. Derivative instruments measured at fair value are recorded on the balance sheet as an asset or liability. Changes in the fair value are recognized currently in net income unless specific hedge accounting criteria are met.

Fair Value Hedges - Interest Rate Risk Management In 2002, KCP&L remarketed its 1998 Series A, B, and D EIRR bonds totaling $146.5 million to a 5-year fixed interest rate of 4.75% ending October 1, 2007. Simultaneously with the remarketing, KCP&L entered into an interest rate swap for the $146.5 million based on the London Interbank Offered Rate (LIBOR) to effectively create a floating interest rate obligation. The transaction is a fair value hedge with no ineffectiveness. Changes in the fair market value of the swap are recorded on the balance sheet as an asset or liability with an offsetting entry to the respective debt balances with no net impact on net income. The fair value of the swap was an asset of $0.7 million and $3.3 million at December 31, 2004 and 2003, respectively.

Cash Flow Hedges - Commodity Risk Management KCP&L's risk management policy is to use derivative hedge instruments to mitigate its exposure to market price fluctuations on a portion of its projected natural gas purchases to meet generation requirements for retail and firm wholesale sales. As of December 31, 2004, KCP&L had slightly under half of its 2005 projected natural gas usage for retail load and firm MWh sales hedged. These hedging instruments are designated as cash flow hedges. The fair values of these instruments are recorded as current assets or current liabilities with an offsetting entry to OCI for the effective portion of the hedge.

To the extent the hedges are not effective, the ineffective portion of the change in fair market value is recorded currently in fuel expense. KCP&L did not record any gains or losses due to ineffectiveness for the years ended December 31, 2004, 2003 or 2002. When the natural gas is purchased, the amounts in OCI are reclassified to fuel expense in the consolidated income statement.

Strategic Energy maintains a commodity-price risk management strategy that uses forward physical energy purchases and other derivative instruments to reduce the effects of fluctuations on purchased 117

power expense caused by commodity-price volatility. Derivative instruments are used to limit the unfavorable effect that price increases will have on electricity purchases, effectively fixing the future purchase price of electricity for the applicable forecasted usage and protecting Strategic Energy from significant price volatility. The maximum term over which Strategic Energy is hedging its exposure and variability of future cash flows is 3.1 years and 3.0 years at December 31, 2004 and 2003, respectively.

Certain forward fixed price purchases and swap agreements are designated as cash flow hedges. The fair values of these instruments are recorded as assets or liabilities with an offsetting entry to OCI for the effective portion of the hedge. To the extent the hedges are not effective, the ineffective portion of the change in fair market value is recorded currently in purchased power. When the forecasted purchase is completed, the amounts in OCI are reclassified to purchased power. Purchased power for the year ended December 31, 2004, includes a $3.2 million gain due to ineffectiveness of the cash flow hedges. Strategic Energy did not record any gains or losses due to ineffectiveness for the years ended December 31, 2003 or 2002.

In 2003, Strategic Energy terminated an agreement with a swap counterparty due to credit and performance concerns. Strategic Energy received a $4.8 million fair value settlement. The swap was designated as a cash flow hedge of a forecasted transaction and Strategic Energy management believed the forecasted transaction would occur. Accordingly, the $4.8 million settlement was reclassified to purchased power expense over the remaining term of the underlying transaction, which was completed in 2003.

Strategic Energy also enters into economic hedges (non-hedging derivatives) that do not qualify for hedge accounting. The changes in the fair value of these derivative instruments recorded into net income as a component of purchased power were a $1.5 million loss and an insignificant gain for the years ended December 31, 2004 and 2003, respectively.

The notional and estimated fair values of the Company's derivative instruments are summarized in the following table as of December 31. The fair values of these derivatives are recorded on the consolidated balance sheets as of December 31, 2004 and 2003, respectively.

2004 2003 Notional Notional Contract Fair Contract Fair Amount Value Amount Value Great Plains Energy (millions)

Swap contracts Cash flow hedges $ 92.4 $ 4.5 $ 67.3 $ (0.8)

Non-hedging derivatives 2.3 0.7 - -

Forward contracts Cash flow hedges 23.0 1.6 25.8 1.0 Non-hedging derivatives 5.5 (2.2) 1.3 -

Consolidated KCP&L Swap contracts Cash flow hedges 6.3 (0.3) 2.9 0.1 118 111

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

Great Plains Energy Consolidated KCP&L December 31 December 31 2004 2003 2004 2003 (millions)

Current assets $ 2.5 $ 2.7 $ (0.3) $ 0.1 Other deferred charges 0.9 0.8 - -

Other current liabilities (0.5) (2.6) -

Deferred income taxes (0.8) (0.2) 0.2 Other deferred credits (0.9) (0.4) - -

Total $ 1.2 $ 0.3 $ (0.1) $ 0.1 The amounts recorded in current assets and liabilities reflected in accumulated OCI in the table above as of December 31, 2004, are expected to be reclassified to expenses during the next twelve months for Great Plains Energy and consolidated KCP&L.

The amounts reclassified to revenues and expenses in 2004, 2003 and 2002 are summarized in the following table.

Great Plains Energy Consolidated KCP&L 2004 2003 2002 2004 2003 2002 (millions)

Gas revenues $ - $ - $ 0.2 $ - $ - $ -

Fuel expense (0.7) (0.8) (0.1) (0.7) (0.8) (0.1)

Purchased power expense (0.6) (9.0) 5.4 Minority interest 0.2 1.0 (0.9) - - -

Income taxes 0.5 3.8 (2.0) 0.3 0.3 0.1 CCI $ (0.6) $ (5.0) $ 2.6 $ (0.4) $ (0.5) $ -

22. JOINTLY OWNED ELECTRIC UTILITY PLANTS KCP&L's share of jointly owned electric utility plants as of December 31, 2004, is detailed in the following table.

Wolf Creek LaCygne latan Unit Units Unit (millions, except MW amounts)

KCP&L's share 47% 50% 70%

Utility plant in service $ 1,366 $ 322 $ 260 Accumulated depreciation 671 236 183 Nuclear fuel, net 36 KCP&L's accredited capacity--MWs 548 681 469 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 Great Plains Energy and consolidated KCP&L Statements of Income.

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23. QUARTERLY OPERATING RESULTS (UNAUDITED)

Quarter Great Plains Energy 1st 2nd 3rd 4th 2004 (millions, except per share amounts)

Operating revenue $ 541.5 $ 613.5 $ 714.8 $ 594.2 Operating income 62.6 82.3 125.5 48.4 Income from continuing operations 29.5 41.4 67.9 34.7 Net income 27.3 41.6 75.9 36.0 Basic and diluted earning per common share from continuing operations 0.42 0.59 0.91 0.46 Basic and diluted earning per common share 0.39 0.59 1.02 0.48 2003 Operating revenue $ 464.2 $ 503.0 $ 660.8 $ 520.0 Operating income 58.7 90.9 166.9 50.8 Income from continuing operations 22.0 59.0 84.2 24.5 Net income (loss) 14.5 50.9 83.8 (4.3)

Basic and diluted earning per common share from continuing operations 0.31 0.85 1.21 0.34 Basic and diluted earning (loss) per common share 0.20 0.73 1.20 (0.07)

Quarter Consolidated KCP&L 1st 2nd 3rd 4th 2004 (millions)

Operating revenue $ 247.0 $ 275.0 $ 323.7 $ 245.9 Operating income 49.7 68.3 111.3 37.8 Net income 21.2 32.3 63.9 25.9 2003 Operating revenue $ 234.9 $ 247.9 $ 350.7 $ 223.5 Operating income 42.8 53.9 148.5 36.3 Income from continuing operations 13.1 22.0 78.5 12.3 Net income 11.9 14.5 78.5 12.3 Quarterly data is subject to seasonal fluctuations with peak periods occurring in the summer months.

120 III

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Great Plains Energy Incorporated We have audited the accompanying consolidated balance sheets of Great Plains Energy Incorporated and subsidiaries (the "Company") as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, common stock equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Great Plains Energy Incorporated and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 5 to the consolidated financial statements, effective January 1, 2002, the Company changed its method of accounting for intangible assets to adopt Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets". As discussed in Notes 1 and 16, respectively, to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for stock-based compensation to adopt SFAS No. 123, "Accounting for Stock-Based Compensation" and changed its method of accounting for asset retirement obligations to adopt SFAS No. 143, "Accounting for Asset Retirement Obligations".

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 4, 2005, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP Kansas City, Missouri March 4, 2005 121

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Kansas City Power & Light Company We have audited the accompanying consolidated balance sheets of Kansas City Power & Light Company and subsidiaries (the "Company") as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, common stock equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Kansas City Power & Light and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 5 to the consolidated financial statements, effective January 1, 2002, the Company changed its method of accounting for intangible assets to adopt Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets". As discussed in Note 16 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations to adopt SFAS No. 143, "Accounting for Asset Retirement Obligations".

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 4, 2005, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP Kansas City, Missouri March 4, 2005 122 III

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Great Plains Energy Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended) for Great Plains Energy. Under the supervision and with the participation of Great Plains Energy's chief executive officer and chief financial officer, management evaluated the effectiveness of Great Plains Energy's internal control over financial reporting as of December 31, 2004. Management used for this evaluation the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Management has concluded that, as of December 31, 2004, Great Plains Energy's internal control over financial reporting is effective based on the criteria set forth in the COSO framework. Deloitte & Touche, LLP, the independent registered public accounting firm that audited the financial statements included in this Annual Report, has issued its audit report on this assessment, which is included below.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Great Plains Energy Incorporated We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Great Plains Energy Incorporated and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to 123

provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2004, of the Company and our report dated March 4, 2005, expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/DELOITTE & TOUCHE LLP Kansas City, Missouri March 4, 2005 KCP&L Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 15d-1 5(f) under the Securities Exchange Act of 1934, as amended) for KCP&L. Under the supervision and with the participation of KCP&L's chief executive officer and chief financial officer, management evaluated the effectiveness of KCP&L's internal control over financial reporting as of December 31, 2004. Management used for this evaluation the framework in Internal Control - Integrated Frameworkissued by the COSO of the Treadway Commission. Management has concluded that, as of December 31, 2004, KCP&L's internal control over financial reporting is effective based on the criteria set forth in the COSO framework. Deloitte & Touche, LLP, the independent registered public accounting firm that audited the financial statements included in this Annual Report, has issued its audit report on this assessment, which is included below.

124

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of Kansas City Power & Light Company We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Kansas City Power & Light Company and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

125

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2004, of the Company and our report dated March 4, 2005, expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/DELOITTE & TOUCHE LLP Kansas City, Missouri March 4, 2005 126 II

CERTIFICATIONS I, Michael J. Chesser, certify that:

1. I have reviewed this annual report on Form 10-K of Great Plains Energy Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report:

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-1 5(e) and 15d-1 5(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-1 5(f) and 15d-1 5(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 7, 2005 /s/Michael J. Chesser Michael J. Chesser Chairman of the Board and Chief Executive Officer 127

CERTIFICATIONS I, Andrea F. Bielsker, certify that:

1. I have reviewed this annual report on Form 10-K of Great Plains Energy Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report:

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-1 5(f) and 15d-1 5(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 7, 2005 /s/Andrea F. Bielsker Andrea F. Bielsker Senior Vice President - Finance, Chief Financial Officer and Treasurer 128

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Kansas Electric Power Cooperative, Inc. (KEPCo), headquaftered at Topeka, Kansas, was incorporated in 1975 as a not-for-profit generation and transmission coo'perative (G&T). it '

is KEPCo's reisjonsbility to procure an adequate and reliable' power supply for its nineteen distribution Rural Electric Cooperative Members at a reasonable cost.

Through their combined resources, KEPCo Members support a wide range of other services such as rural economic development, marketing and diversification opportunities, power requirement and engineeringi studies,- rate design, etc.

KEPCo'is go'overnmed y'a Board of TruStees representig-Each of its nineteen Members which collectively serve more than 100,000 electric meters in -itwo-thirds of rural Kansas.

The KEPCo Board of Trustees meets-regularly to establish policies and act on issues that often include recommendations from working committees of the Board and KEPCo Staff.

The Board also elects a seven;person Executive Committee which includes the President, Vice President, Secretary, Treasurer, and three additional Executive Committee members.

KEPCo is under the jurisdiction of the Kansas Corporation Commission (KCG) and was granted a limited certificate of cbn'venieice and authority in' 1980 to act as a G&T public utility. KEPCo's power supply resources consist of: 70 MW of owned generation from the Wolf Creek Generating Station"; te 20 MW Sharpe Generating Station lo&ated in Coffey County; hydropower purchases of an equivalent 100 MW from the Southwestern Power Administration, and 14 MW fto'm the Westerm Area Power Administi plus partial requirement power purchases frtom egiciial utilities.

KEPCo is a Touchstone Energy Cooperative. Touchstone Energy is a nationwide alliance of more than"600 cooperatives committed to promoting the core strengths of electric cooperatives integrity, accountability, innovation, personal service and a legacy of community commitment. The'national program is anchored by the motto "The Power of Human Connections."

Kansas Electric Power Cooperative, Inc. C 11 P.O. Box 4877-; Topeka, KS '66604 600 SW Corporate View' Topeka, KS 66615' (785) 273-7010 www.kepco.org 2

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fl II i Sometimes a single year weathered nuclear, hydropower and can't be- neatly packaged into other generation and transmission a series of highlights or words challenges, and confronted financial of wisdom and inspiration. impediments such as record high Sometimes the work of an interest rates. History shows that Mr. Maginley and Mr. Parr organization is focused on larger efforts there were many times when Members that are not defined within 12 neat did not agree on an issue but recog-monthly periods. 2004 was such a year.

While the year precedes the anniver-nized the importance of cooperation and that KEPCo would work best- iii from when it worked together.

sary of KEPCo's charter 30 years ago, KennethJ. Maginley, KEPCo continues to have such most days, and many evenings, were KEPCo President leaders on the Board of Trustees -

more appropriately focused on the future rather than reflection. Neverthe- leaders who combine a respect for that Stephen E. Parr, Executive Vice President less, a brief salute to our history would be in order and perhaps inspirational.

history with a commitment to meet the challenges facing KEPCo in the future.

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& Chief Executive Officer Working to meet those challenges best On February 13, 1975, six rural Kansas leaders filed papers to incorporate the Kansas Electric Power Cooperative, Inc.

defines the year 2004.

The cornerstone of KEPCo's II (KEPCo). Their mission was to gain continuing ability to fashion a stable control of power supply and transmis-sion issues by owning and economical power supply for its Members is a new Member Wholesale 11 and operating a G&T Power Agreement that better fits the "These challenges are nothing new and history proves that they will be met most effectively through our cooperative Cooperative. 21st Century. New contracts will permit some power supply flexibility for il efforts. Member unity was necessary to provide the clout to Those visionary individuals were our Members, as well as provide organize KEPCo. That common bond has been equally followed by a series of KEPCo with the lending security important in order to develop and provide a reliable electric Cooperative leaders necessary for existing debt and to supply through three decades. Unity and cooperation will be who demonstrated consider future resource acquisitions.

even more importantas we preparefor changes ahead."

determination and a With resolve, the KEPCo Board will to succeed that was nothing short of heroic. KEPCo's reviewed contract provisions and language during the year and a series of U

development overcame regulatory and workshops continue towvard develop-legislative obstacles, endured litigation, ment of suitable language. Member fl support for a new contract will guide the

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development of KEPCo's power supply generationfacilities have been an-5 to meet demand over the next 30 years. nounced by several uitilities in the-Numerous other major efforts went region and KEPCob' 5 tinues to mee-t on simultaneously to contract develop- with principal developers to review ment. The KEPCo Board approved a opportunities for participation. The Long Range Resource Plan, indepen- last coal generation facility in Kansas; dently developed by consultants Burns was built more than 20 years ago and

-'Melroy Kopsad and McDonnell, which states clear plans for new generation in the region Completes FourYears objectives for meeting our power supply are quicklyj dexvelopirg." i of.Service as President needs in a cost effective and limited risk In orde~'for KEPCo to participate in One of the most signifcant manner. The study calls for KEPCo to generation opportunities we must be in a' events in 2004 was Meiroy Kopsa's seek an extension of the Wolf Creek position to initially finance and main-conclusion of service as Presidentfof Generating Station operating license in tain status as apstrong partner through the KEPCo Board of Trustees. His order to maximize this significant the life of a new plant. That strength leadershipas Presidentbegan in generating resource. It also calls for lies in the assurance of Member support November 2000 and he stood for -

KEPCo to secure approximately 100 for KEPCo through commitment to a'-'-

' successful re-election three'subse-,'

MW of coal-fired generation and new wholesale power contract.

quent years. iPartof Mr. Kopsa's-extend existing power purchase con- Preparation of that contract will remarks to'the KEPCo Annual,.-

tracts with regional utilities. continue into 2005, as will related work Meeting on November 2004 are Steps to implement that plan were on accompanying bylaw and policy reprintedbelow. - -

taken immediately. Work isunderway, changes, financing options, contract '-"When I decided not to seek re-in cooperation with the other owners of - negotiations and other steps to prepare electionsI began to reflect on the' Wolf Creek, to seek a license extension for the future., pastfour years and believe we have from the Nuclear Regulatory Commis- Meanwhile, we want toiecognize reasonsto be proud and thankful.

sion. KEPCo isalso meeting with and applaud the day-to-day efforts of We've seen energy prces skyrocket regional utilities to evaluate power our staff to provid power supply and to more than $7for naturalgas and supply contract opportunities. These other professional services to our over $50 a barrelforboil and the efforts continue to proceed with promise. Member Cooperatives'. Many of those effect of energy prices and other Developing its Long Range Re- accomplishments are detailed in this - factors on our economy.

source Plan served to reinforce Annual Report. They include the "In our industry, we've KEPCo's long-standing' belief that tsuccessful 'refinancing of eligible; witnessed the collapse of Enron and future power supply needs may best be -KEPCo debijongoing emphasis on; misdeeds at utilities closer to home.

served by pursuing ownership and power quality, reliability, engineering We've seen a colossal energy control of our own generation. New (continued on paje 15) - .

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Highlights In January, the KEPCo Finance Department established a Cushion of Credit account in the Rural Electric and Telephone (RET) loan system. This program enables KEPCo to deposit funds that are then made available to meet scheduled payments to the Federal Financing Bank (FFB). KEPCo receives 5% interest on these advance payments. This program allowed KEPCo to recognize an additional JJ

$200,000 in interest income in 2004. L KEPCo's Engineeringand OperationsDepartmentcontinues to concentrateon the maintenance of metering, SCADA and communications to over 300 delivery points and individualsites across the state of Kansas. Accurate and dependable metering and communicationsare vital to KEPCo operations. j KEPCo owns six percent of the Wolf Creek Generating Station.

Wolf Creek, an 1170 MW nuclear plant, islocated near Burlington, in 'f II 0ilI~'I{ Coffey County, KS. The plant has an outstanding record of operating iMnd safety excellence dating back to the start of commercial operation 111 lron September 3, 1985. In 2004, Wolf Creek implemented a number of L security enhancements as a result of Homeland Security mandates, completed the year with no serious accidents and received a positive safety assessment by the Nuclear Regulatory Commission.

j KEPCo Operationsand MaintenanceStaff worked on maintenance of instrument transformers, meters, andcommunications at 80 meter locations duringthe year. Staff also maintained 290 RTUs alongwith communications consistingof 2.4 GHz radios, 900 MHz .1 radios, 220 MHz radios, and frame-relay lease circuits. In addition to other normalmainte-nance functions, Staff participatedin significant projects such as the installation of a new 34.5 kV delivery point for Victory Electric Cooperative to support a new industrialload and a joint project with Ninnescah Electric Cooperative to install voltage regulatorsat an industrialfacility. Departmentemployees traveled over 120,000 miles during the year to meet Member needs.

i An Inter Control-center Communication Protocol (ICCP) connection was added between KEPCo and Empire via the Southwest Power Pool (SPP). The ICCP allows an exchange of information to support KEPCo's energy contracts with Il Westar Energy and the Southwestern Power Administration.

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Below: An official ribbon cutting was held on September 20 to mark the successful expansion of Nutri-Shield, Several KEPCo Staff members are serving in leadership roles in state and federal Inc.2 mhCourtland, KS. Rolling Hills industry related associations and groups. Harold Haun serves as President of the REC assistedwith the project by securinga $136,000 zero-interest National G&T Lawyers Association. Loren Medley is Past President of the Na- REDLG loan.

tional Rural Economic Developers Association and is President of the Kansas Rural Development Council. Bruce Graham is President of NRECA's Council of Rural Electric Communicators (CREG). Bill Goshom is active in hydropower customer groups for both WAPA and SWPA and currently serves as Chairman of the SPRA Federal Power Marketing Committee.

KEPCo continued to fund and assist Members in promotion of an electric water heater and heatingsystem rebate program. Since the startof the rebate program! KEPCohas issued more than 11,000 water heater rebates and nearly 4,000 heatingsystem rebates.

Electricity is a safe, clean and competitively priced option and this program helps commu-nicate that message. REDLG Loans Yield Success Stories The Legal Department has been engaged in discussions and drafting of new KEPCo and its Members are wholesale power contracts, new policies and changes in the KEPCo Bylaws in successful participantsin USDA's response to the effort to meet Member power supply needs to the year 2045. In Rural Economic Development addition, Harold Haun supported numerous projects including KEPCo's filings and Loan and Grant (REDLG) responses to KCC Dockets as well as draft and approval of various KEPCo program. In 2004, five Members contracts, Board resolutions, policies, some Board committee minutes, and other Igarnered$806,000 in zero legal documents. The Legal Department also leads administrative action on certain interest loans for a variety of internal KEPCo policies and benefits.

economic development projects.

Over the years, the REDLG KEPCocontinued participationin Touchstone Energy andassisted in the organizationof program has loaned orgranted state events such as the ElectricCooperative Day at the State Fairand Kansas participationin KEPCo Member projects $14.3 the new economic development web site called SitesAcrossAmerica.com. Nationally, million and, when combined with Touchstone Energy now includes more than 600 Cooperativesthat benefit from service the $38.3 million in project enhancements such as new employee trainingmodules, the Co-op Connections loyalty card, the Get Chargededucation kit, Touchstone Energy Home, and otherprogramadditions. private investment, results in a ruraldevelopment impact of

$52.6 million. In addition, the projects increaseproperty valha-

-tion and the 780 new jobs and associated wages improve regional TouchstoneEniergy The Jior of hurnion connections prosperity.

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II I The 20 MW Sharpe GeneratingStation, located in Coffey County, KS, is owned by KEPCo and was declaredoperationalin 2002. KEPCo and Martin TractorCompany work KEPCo Services Inc. together to test and maintain generation capability in order to be able to operate the plant (KSI) marked its seventh year within a few minutes of being notified by Westar Energy.

of operation in 2004. KSI Enginieering, the principal KEPCo supports Member marketing efforts in a variety of ways. KEPCo serves as a operatingactivity of KEPCo key contact for Touchstone Energy programs in Kansas. In addition, KEPCo marketing Services, is now listed as the Staff developed a series of advertisements for use in Kansas Country Living, displayed at official engineering consultant ten Member annual meetings, and supported numerous individual Member projects.

for nine electric cooperatives. KEPCo Staff also worked with Members to utilize the Customer Information System for KSI has completed at least one creation of more than 20,000 direct mail pieces promoting surge protection, security project for each of KEPCo's lights, load management, auto bank draft, levelized billing, DirecTV, annual meeting Members and surpassed 100 notices, electrical contracting services, electric water heaters, and heat pumps.

completed projects to date.

Through the last six years, KSI KEPCo Engineers have prioritizeddelivery point reliabilityby conductingfield inspections, Engineering has earned more compiling reliability reports, and organizing multiple meetings with transmission providers in II than $825,000 in revenues, has contributed$150,000 to order to improve power quality.

li KEPCo overheads, and KSI is your cooperative engineering and planning partner specializing in construc-developed a net margin of more tion work plans, mapping, sectionalizing studies, financial forecasts, substation design, than $15,000. transmission design, work order inspections, power quality, demand side management, and substation spill prevention/control plans. This last year, KSI added the following to

'AI its list of services: line staking, GIS development and the preparation of transformer specifications. KSI Engineering provided design engineering and technical support for Ai the construction of the 5 MVA Kaw Valley WK" Substation. KSI Engineering continues to help Member Cooperatives take advantage of the KEPCo SCADA communication infrastructure to monitor and control equipment at their substations. KSI Engineering now has both AutoCAD Map and ESRI GIS capabilities to meet any mapping or drawing need.

KEPCo hosted several VIPs during the year including a February breakfast with RUS Administrator Hilda Legg and a presentationto the KEPCo Board by SWPA Administrator Mike Deihl. KEPCo also makes its Board Room available to groups and organizations that have a business association. Many times, legislators and important l state and federal officials are present at these events, raising awarenessof KEPCo as a HildaLegg visits the KEPCo office. partner in important planning and development activities in Kansas.

Jll 7

1

KEPCo's SCADA system anchored another successful load management season and Staff continues to improve-the capabilities of the system-wide communication network. Enhancements include offering 3-line displays 'ofeach delivery point,.i better alarm handling by providing separate alarms for Members and KEPCo, and a-greatly improved load estimating algorithm. Using the SCADA system, Staff can remotely start, operate and monitor the Sharpe Generating Station. Bluestem, Butler, Flint Hills, Heartland,-Rolling Hills, and Sumner-Cowley Electric Coopera-tives have Automated Meter Reading (AMR) using the SCADA Wide Area Network (WAN) to communicate to their Master Radio sites. DS&O has started its AMR project and quotes have been issued for AMR communication projects for,,

CMS and Twin Valley.

KEPCo continues to work with Kansas Electric Cooperativ (KEC) 'and Sunflower Electric Power Cororation on legislative issues m Kansasand in ,.

Washington, D.C. KEPCo testified on six different bills in 2004 and tracked approximately 50 different pieces of legislation. In Congress, KEPCoparticipated4 in the NRECA Legislative Conference and a series of actions in response to.

NRECA cals on the federal energy bill, the Rural Economic Development Loan --

& GrantProgram regulations, and other issues. -

Safety training continues to be essential for all employees at KEPCo.

An Employee Safety Committee organized six mandatory meetings and one volun tary CPR/First Aid course during the year. Dating back to 1984, KEPCo employees have logged more than 850,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> without a lost-time accident.

KEPCo has been involved in a cross-section of community and associated activities in support of ruraldevelopment. Staff participatedin high profile events such as the;Kansas Prosperity Summit and Congressional Listening Tours.

KEPCo's SCADA system scored another home run when it enabled KEPCo to begin scheduling SWPA hydropower into the Efpirv conitrol area. Staff manages.this procedure which allows KEPCo to take advantage of a contract that reduced purchases from a higher priced supplier. In addition, this creative solution was accomplished -

without investing approximately $30 million in transmission that the Southwest Power Pool determined was necessary to complete the power supply transaction.

il I1 Ark Valley Electric Cooperative Assn., Inc.

PO Box 1246, South Hutchinson, KS 67504 620-662-6661 J

',' Trustee Rep.-- Dwight Engelland

-AlternateTrustee Rep.-- Bob Hall Manager -- Bob Hall uwight Engeuana Bob flaU Ill Blu'estem Electric Cooperative, Inc.

PO Box5, Wamego, KS 66547 785-456-2212 P 1Box 513, Clay Center, KS 67432 785-632-3111 Trustee Rep. -- Kenneth J. Maginley Alternate Trustee Rep. -- Robert OhIde Manager -- Kenneth J. Maginley Keii Mag~nley Bob Ohlde I

Brown-Atchison Electric Cooperative Assn., Inc.

PO Box 230, Horton, KS 66439 785-486-2117 ..

11 Trustee Rep.'-"- Dale Bodenhausen Alternate Trustee Rep. -- Kevin Compton Manager - Rodney V. Gerdes fli

'Dale Bodenhausen Kevin Compton Rod Gerdes dl Butler Rural Electric Cooperative Assn., Inc.

POBox 1242, ElDorado,KS 67042 316-321-9600

Trustee Rep. -- Bob Nichols

,A Alternate Trustee Rep. -- Dale Short Manager -- Dale Short I

.0 Bob Nichols Dale Short Caney Valley Electric CooperativeAssn., Inc.

PO Box 308, CedarVale, KS 67024 620-758-2262

'Trustee Rep.-- Floyd Montgomery itl Alternate Trustee Rep. -- Allen A. Zadorozny Manager - Allen A. Zadorozny ID Floyd Montgomery Allen Zadorozny 9

II Ill

CMS Electric Cooperative, Inc.'-

P0 Box 790, Meade, KS 67864 620-873-2184 Trustee Rep.-- Kirk A. Thompson Alternate Trustee Rep. - Clifford Friesen

'Manager -- Kirk A. Thompson DS&O Rural Electric CooperativeAssn., Inc.

-P0Box 286, Solomon, KS 67480 '785-655-2011 i iTrustee Rep. -- Harlow Haney' -

'Alternate Trustee Rep. -- Don Hellwig  !:- ,

- Manager:--Don Hellwig Harlow Haney Von Hellwig Flint Hills Rural Electric Cooperative Assn., Inc.

PO Box B, Council Grove, KS 66846 620-767-5144

-Trust'ee Rep.-- Robert E. Reece . L, -

' Alteiate Trustee Rep. -- Gus Hamm -  : j .

Manager -- Robert E. Reece bob Reece (UusHamm

" HeartlandRural Electric Cop'erative,'Inc.

PO Box 40,'Girard,KS 66743 620-724-8251 DisirictOffices, lola 620-365-5151

-Mound City, 913-795-2221 Trustee Rep.-- Dennis Peck'man-: - I 1/4 t'

`Alternate Trustee Rep. -- Dale Coomes

Manager -- Dale Coomes Dennis Peckman Lale Uoomes Leavenworth-Jefferson - --

i Electric Cooperative, Inc.

j . PO Box 70, McLouth, KS 66054 913-796-61 11 J,_

i - Trustee Rep. -- Robert Smith, Jr. - .

2 1

Alternate Trustee Rep. -- H.B. Canida

'Manager H.B. Canida Robert Smith, Jr. H.B Canida I

2004 05 KEPCo Eiecutive Committee LI Ir 1-  ;'-ficers -Executive President:.,Kenneth Maginley Vice President: -Larry Scott Secretary: Gordon Coulter Treasurer: Bryan Coover Committee Me7nbers

)DwightEngelland.

Melroy Kopsa

. ,David Reichenberge

iI Lyon-Coffey Electric Cooperative, Inc.

PO Box 229, Burlington, KS 66839 620-364-2116 Trustee Rep. -- Larry Scott Altern"ate Trustee Rep. -- Donna Williams Manager -- Larry Scott Iii Lar Sct ii Ninnescah Electric Cooperative Assn., Inc.

PO Box 967, Pratt, KS 67124 620-672-5538 Trustee Rep. -- Gordon Coulter Alternate Trustee Rep. -- Carla Bickel Manager - Carla Bickel JI GordonCoulter CarlaBickel PrairieLand Electric Cooperative, Inc.

PO Box 360, Norton, KS 67654 785-877-3323 DistrictOffice, Bird City 785-734-2311 Trustee Rep. -- Gilbert Berland III Alternate Trustee Rep. -- Allan J. Miller Manager -- Allan J. Miller Gilbert Berland Alan Miller 11 Radiant Electric Cooperative, Inc.

PO Box 390, Fredonia, KS 66736 620-378-2161 Trustee Rep. -- Dennis Duft Alternate Trustee Rep. - Tom Ayers Administrative Manager -- Leah Tindle Dennis DXX Operations Manager -- Dennis Duft Tom Ayers 'Leah Tindle Il ill Rolling Hills Electric Cooperative, Inc.

PO Box 307, Mankato, KS 66956 785-378-3151 DistrictOffices, Belleville 785-527-2251 EUlsworth 785-472-4021 Trustee Rep. - Melroy Kopsa Alternate Trustee Rep. -- Leon Eck II Melro Kopsa Manager -- Douglas J. Jackson Leon tck Lougjackson, a

ii

Sedgvick County Electric CooperativeAssn., Inc.

PO Box 220, Cheney, KS 67025 316-542-3131 Trustee Rep. -- David Reichenberger Alternate Trustee Rep. -- Alan L. Henning Manager -- Alan L. Henning David Reichenberger Alan Henning Swwner-Coidey Electric Cooperative, Inc.

PO Box 220, Wellington, KS 67152 620-326-3356 Trustee Rep. -- Charles Riggs Alternate Trustee Rep. -- Cletas Rains Manager -- Cletas Rains lharles Kiggs zletas Ramns Twin Valley Electric Cooperative, Inc.

PO Box 385, Akamont, KS 67330 620-784-5500 Trustee Rep. -- Bryan Coover Alternate Trustee Rep. -- Ron Holsteen Manager -- Ron Holsteen non nolsteen Victory Electric Cooperative Assn., Inc.

PO Box 1335, Dodge City, KS 67801 620-227-2139 Trustee Rep. -- Marvin Hampton Alternate Trustee Rep. -- Terry Janson Manager -- Terry Janson Marvin Hampton

Nuclear Fuel 28% I Wolf Creek O&M and A&G 13.3%Y \ _ 3 l _ l l ~KEPCo O&M _

andA&G 5.6%

Depreciation

& Amortizati I

8.8%

Interest 11.4%

Purchased Power 58.1%

lI lI 150 ISO

.1 .1 clo-', -

co V-market disasterin Californiaand a-transmissionsystem breakdown that caused ai a.d operational services, effective black-o`u-t in the NortheastUnited States. Power supply markets and transmission- governiment'affairs, marketing and rural issues are unsettled across the nation and will take years to resolve. - 'development, and a growing KEPCo "Through it all, KEPCo stayed steady". We protected Members from the Services, Inc. 1 volatility of the energy market for several years, saving them nearly 40 million To succeed in life, a person must i dollars," he said. Mr. Kopsa acknowledged that fuel costs, weather and other often readjust to their surroundings.

factors eventually combined to requirea rate increase in February 2002. That is also true for KEPCo and its However, because of that market volatility, Mr. Kopsa may best be remembered Member Cooperatives. Poweivsupply, for his leadership in the Board's strategicdecision to work toward increasingcontrol contract evaluation and negotiations, and management of generationresources. - maintenance and operations, along As a result, on July 18, 2002, the KEPCo Board of Trustees proudly dedi- with other Member services, equire our cated the 20 megawatt Sharpe GeneratingStation. In addition, KEPCo installed primary attention. New generation.j[

an EMS/SCADA system to provide load control, power supply scheduling, opportunities, iransmlissif onages, communication and other services. potential asset acquisitions, and'other 7.-. ii Efforts continue toward a more cost-based rate rather than market-based risk challenges require more effort and under the new leadership of Mr. Kenneth Maginley, who was elected KEPCo adjustment.

Presidenton November 18, 2004. Mr. Maginley is Managerof Bluestem Electric These challenges are nothing newi11 Cooperative, headquarteredin Wamego. and history proves that they 'willbe met "Since I joined the Electric Cooperativefamily in 1977, 1 have witnessed and most effectively through ou coopera-a '

been Partof the evolu- tive efforts. Member unity was neces-tion of KEPCo. I sar to "provide the clout to oranz appreciatethe Board's KEPCo. That common bond has been  !]

confideMrce in electing oequally important in order to develop poveistry and tha thy wil b me me Presidentand with and provide a reliable electric supplyjJ that I accept the respon- through three decades. Unity and sibility of working with cooperation will be even more impor-the Board to prepare tant as we prepare for changes ahead.

KEP.Co for the fut ure" said Mr., Maginley. ~ ~

Kenneth J. Maginley The KEPCo Boardof Trustees elected its Executive Committee during the President November 18, 2004 Aleeting. Executive Committee Mlembers front row II left to right): Mfelroy Kopsa, David Relchenberger, and Dwight Engelland, Back row (left to right).Kenneth Mdginley, President, Larry Scott, Vice President;Bryan Coover, Treasurer;Gordon Coulter, Secretary; and In Stephen E. Parr Stephen E. Parr, Executive Vice President and CEO. Executive Vice President and CEO ra i wwg I 77--7,77 VN-in

PW SC-- LLP BA ID *M Sbee KwmC4Y,1R0 41W82162

'5The Board ofTrustees

- Kansas Electric Power Cooperative, Inc.:

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

and subsidiaries (KEPCo) as ofDecember 31, 2004 and 2003, and the related consolidated statements of revenues

• and expenses, cash flows, and changes in patronage capital for the years then ended. These &onsolidated financial statements are the responsibility of KEPCo's management. Our responsibility is to express an opinion on these:

consolidated financial statements based on our audits. - - .

We conducted our audits in accordance with auditing standards generally accepted in the United States of America and the stanidards applicable to financial audits contained in GovernmentAuditingStandards,issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain _

reasonable assurance about whether the consolidated financial statements are free of material misstatement. An

- audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated

- financial statements. An audit also includes assessing the accounting principles used and.significant estimates

• madeby management as well as evaluating the overall consolidated financial statement jresentiti6n. We believe that our audits provide a reasonable basis for our opinion.

As more fully described in note 4 to the consolidated financial statements, certain depreciation and aniortization methods have been used in the preparation of the consolidated financial statements that do not,'in our opinionri>'-

conform to accounting principles generally'accepted in the United States of America.

opinion, for the effects on the ourconsolidatedexcept financial aIn statementsofthe matters referred to in the paragraph, the consolidated financial opreceding statements referred to above present fairly, in all material respects,

- -the financialposition of KEPCo as of December 31,2004 and 2003, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 2 to the consolidated financial statemiients, onJanuary 1,2003, KEPCo adopted Statement

• ofAccounting Standards No. 143, AccountingforAsset Retirement Obligations.' -- i In accordance with GovernmentAuditing Standard we have also issued a report dated March 1I, 2005, on our consideration of KEPCo's internal control over financial reporting and our tests of its compliance with certain

',-' provisions of laws, regulations, contacts, and grant agreements and other matters.The purpose of that report is to"

'.' descnbe the scope of our testing of internal control over finiancial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part ofan audit performed in accordance with GovernmentAuditingStandardsand should be considered in assessing the results of our audit. -.

> -X t o £P--

• S .

Kansas City, Missouri March 11, 2005 i: ,. Xa- .1

ii xl~KEPco~i] Cosldte aac SetY7 iIP dlI Assets 2004 2003.

iii Utility plant:

In-service $ 223,290,771 223,111,948 dl Less allowances for depreciation (114,279,455) (111,796,459)

Net in-service Construction work in progress 109,011,316 1,801,777 111,315,489 1,172,065 ii Nuclear fuel, net of amortization 4,558,431 3,693,512 Total utility plant Restricted assets:

115,371,524 116,181,066 ii Investments in the National Rural Utilities Cooperative Finance Corporation Bond fund reserve 3,323,052 4,230,261 3,318,093 4,193,570 1i Decommissioning fund 7,165,662 6,089,845 Investments in other associated organizations Total restricted assets 84,040 14,803,015 59,129 13,660,637

'IT Current assets:

Cash and cash equivalents Member accounts receivable 5,229,724 7,332,176 8,226,833 7,220,772 i~

Materials and supplies 2,785,126 2,658,146 Other assets and prepaid expenses Total current assets 608,221 15,955,247 532,203 18,637,954 I

Other long-term assets:

Deferred charges:

Wolf Creek disallowed costs (less accumulated amortization of

-L

$9,606,405 and $8,849,243 for 2004 and 2003, respectively) 16,376,515 17,133,678 Wolf Creek deferred plant costs (less accumulated amortization of $9,389,759 and $6,259,839 for 1I 2004 and 2003, respectively)-- 37,559,034 40,688,954 Wolf Creek decommissioning regulatory asset Deferred Department of Energy decommissioning costs

Deferred incremental outage costs: -

3,088,274 254,597 831,829 3,349,999 338,199 2,793,858 A~

Other deferred charges (less accumulated amortization of

$1,252,185 and $1,087,234 for 2004 and 2003, respectively)

Unamortized debt issuance costs 1,245,506 4,749,145 1,410,457 5,417,944 Il Other investments 178,447 173,976 Total long-term assets Total assets $

64,283,347 210,413,133 71,307,065 219,786,722 I.l IL 17 M

IM

N ,M

'Consohdated Balance Sheets I I

Deceiiiber3l 2004 and2003 Patronage Capital and Liabilities 2004 2003 Patronage capital:

Memberships $ 3,200 3,200 Patronage capital (payment restricted as indicated) 14,998,948 11,812,345 Total patronage capital 15,002,148 11,815,545 Long-term debt:

National Rural Utilities Cooperative Finance Corporation 4,832,764 *5,267,017 Federal Financing Bank 86,909,257 ;96,295,154 Grantor Trust Series 1997 47,740,000 49,640,000 Pollution control revenue bonds 30,100,000 31,700,000 Total long-term debt 169,582,021 182,902,171 Less current maturities of long-term debt (9,953,205) (9,112,155)

Long-term debt, nettof current maturities 159,628,816 _--i 73,790,016 Other long-term liabilities:

Deferred Department of Energy decommissioning costs 185,161 270,559 Wolf Creek decommissioning liability 13,128,504 12,385,380 Wolf Creek nuclear operating liabilities 2,298,001 2,225,422 Arbitrage rebate long-term liability 801,948 585,092 Other deferred credits 2,262 925 Total other long-term liabilities 16,415,876 15,467,378 Current liabilities:

Current maturities of long-term debt 9,953,205 u 9,112,155 Accounts payable 7,466,081 6,438,669 Payroll and payroll-related liabilities 266,134 245,540 Accrued property taxes 1,310,783 1,290,654 Accrued interest payable 370,090 *1,626,765 Total current liabilities - 19,366,293 -- 18,713,783 Total patronage capital and liabilities . $ 210,413,133 219,786,722 See accompanying notes to consolidated financial statements.

18

1I II Ti SvenueW R s an pense2

{: 'I cm'b'r l, 2004X and 200 2004 2003 Ib Operating revenues:

Sales of electric energy $ 89,827,520 89,424,340 Other 634,802 411,162 Total operating revenues 90,462,322 89,835,502 Operating expenses:

Power purchased 51,029,353 50,371,152 Nuclear fuel 2,442,098 2,149,674 Plant operations 8,698,938 8,559,578 Plant maintenance 2,867,437 2,839,025 Administrative and general Amortization of deferred charges Depreciation and decommissioning 4,574,684 4,052,034 4,261,130 4,374,015 4,057,683 4,353,980 it Total operating expenses 77,925,674 76,705,107 Net operating revenues 12,536,648 13,130,395 Interest and other deductions:

Interest on long-term debt Amortization of debt issuance costs Other deductions

. 9,239,290 668,799 47,306 10,904,171 454,861 44,997 11 Total interest and other deductions 9,955,395 11,404,029 Operating income Other income (expense):

2,581,253 1,726,366 jin Interest income 621,143 423,963 Other expense (15,793) (22,226)

Total other income Net margin $

605,350 3,186,603 401,737 2,128,103 iI' See accompanying notes to consolidated financial statements.

iii JUI Decemb en3 Changes inPatro g Capi December 31, 2004 and 2003 iarng nloae Balance, December 31, 2002 $

Memberships 3,200 pratronage capital 11,801,741 Unallocated margin (loss)

(2,117,499)

Total 9,687,442 Il Net margin Balance, December 31, 2003 3,200 10,604 11,812,345 2,117,499 2,128,103 11,815,545 JI Net margin Balance, December 31, 2004 $ 3,200 3,186,603 14,998,948 3,186,603 15,002,148 li 19 See accompanying notes to consolidated financial statements.

ii II

at I Decmb-r3, 200.4and2 2004 2003 Cash flows from operating activities:

Net margin II 3,186,603 2,128,103 Adjustments to reconcile net margin to net cash provided by operating activities: -

Depreciation and amortization 3,817,830 3,977,830 Decommissioning 443,300 -376,150 Amortization of nuclear fuel 1,795,148 '1,559,637 Amortizationof deferred charges 4,052,034 4,057,683 Amortization of deferred incremental 6utage costs 2,221,663 1,640,259 Amortization of debt issuance costs 668,799, 454,861 Changes in assets and liabilities:

Member accounts receivable (111,404) (450,097)

Materials and supplies (126,980) (101,506)

Other assets and prepaid expenses (76,018) (43,078)

Accounts payable 1,027,412 1,114,148 Payroll and payroll-related liabilities 20,594 ' (1,732)

Accrued property taxes 20,129 202,596 Accrued interest payable: (1,256,675) 1,231,844

'R estricted assets - ' -' ' (71,032) (91,623) 01ther long-term liabilities 205,374 306,634 Net cash provided by operating activities 15,816,777 16,361,709 Cash flows from investing activities: -;

Additions to electric plant, net . (2,130,735) (1,631,880)

Additions to nuclear fuel (2,660,067) (2,533,135)

Additions to deferred incremental outage costs (259,634) (3,352,629)

Investments in decommissioning fund assets (443,300) (376,150)

Net cash used in investing activities (5,493,736) (7,893,794)

Cash flows from financing activities:

Repayment of long-term debt (13,320, 150) . (8,220,390)

Issuance of debt -- - ' ' 2,270,262 Increase in debt issuance costs '-- _-;(2,327,018)

Net'cash used in financing activities * (13,320,]150) ' (8,277,146)

Net increase (decrease) in cash and cash equivalents A2,997,]

(., 109) 190,769 Cash and cash equivalents at: ' - {

Beginning of year - 5 t - --.. 8,226, 833 8,036,064 I 11 . I End of year ' I $ 5,229,'724 8,226,833 Supplemental disclosures of cash flow information:

Cash piaid duing the"year for interest " ~' I 2 ,- I $ 10,543,:271 , - 9,717,324 See accompanying notes to consolidated financial statements.

': '! tofi_':~--

i-S Z- A,'

I 20

(1) Nature of Operations Kansas Electric Power Cooperative, Inc. and subsidiaries (KEPCo), headquartered in Topeka, Kansas, was incorporated in 1975 as a not-for-profit generation and transmission cooperative (G&T). KEPCo is under the jurisdiction of the Kansas Corporation Commission (KCC) and4 was granted a limited certificate of 'III convenience and authority in 1980 to act as a G&T public utility. It is KEPCo's responsibility to procure an j adequate and reliable power supply for its 19 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 19 members, which collectively serve more than 100,000 electric customers in rural Kansas. il (2) Summary of Significant Accounting Policies (a) System ofAccounts KEPCo maintains its accounting records substantially in accordance with the Rural Utilities Service ll (RUS) Uniform System of Accounts and in accordance with accounting practices prescribed by the KCC.

(b) Rates The KCC has the authority to establish KEPCo's electric rates under, state law in Kansas. Rates are l]

established to meet the times-interest-earned ratio and debt-service coverage set forth by the RUS. On

- 4 _ January 17, 2002, the KCC ordered a rate increase of approximately $6.5 million, including an energy, t cost adjustment (ECA) mechanism, which allows KEPCo to pass along increases in certain energy costs j to its cooperative members. These rates became effective February 1, 2002.

(c) Principlesof Consolidation KEPCo's consolidated financial statements include all majority-owned subsidiaries for which it '

maintains controlling interests. 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.

(d) Utility PlantandDepreciation 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. -lI The composite depreciation rate for electric generation plant for the years ended December 31, 2004 and 2003 was 2.81% and 2.74%, respectively.

The provision for depreciation computed on a straight-line basis for electric and other components of LV utility plant is as follows:

Transportation and equipment 25 to 33%

Office furniture and fixtures 10 to 20% Ll Leasehold improvements Transmission equipment 20%

10% I Depreciation expense was $3.8 million for each of the years ended December 31, 2004 and 2003, respectively.

(e) NuclearFuel The cost of nuclear fuel in process of refinement, conversion, enrichment, and fabrication is recorded as iU 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 i,]

generation to the DOE for the future disposal service. These disposal costs are charged to nuclear fuel expense.

21 - continued ii

(9 F

Investments Notso Cos 4.>Decmber31, Dided Financia 004 nd 003 tate ns 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. In the consolidated balance sheets, investments in debt securities aK~iigial maturity' greater Tan lth three months'and a remaining maturity' less than one year are presented as current assets, 'and inventments 'witb a remaining maturity greater than one year are presented as lofig-te'm investments.' Invesitmient returns realized in excess of contractual limits for unexpended loaii pfroceds are recorded as arbitrage rebate long-term liability in the consolidated balance sheets.

(g) DecommissioningFundAssetsfDeconmissroningLiability As -ofDeicemberf 31,2004 and 2003,1$7.2 iiiilli6n and $6;1 millio-i, respectively, have been collected and are being retained in an interest-bearing trust find 'to be used for the physical deomimissioning of Wolf Creek. The trustee invests the decommissioning funds primarily in mutual funds, which are carried at estimated fir value. During 2003, the KCC extended the estimated useful life of Wolf Creek to 60 years from the' original estimates of 40 years only for the determination of 'decomrmissioning costs to be recognized for ratemaking purposes. In 2003, the KCC approved a 2002 Wolf Creek decommissioning cost study, which decreased the estimate of total decommissioning costs to $468.4 million in 2002 dollars ($28.1 million is KEPCo's share). The study assumes a 4% rate of inflation and 2% rate of return. KEPCo adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003. SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities' associated with the retire'me'ft-> of tangible long-lived assets." Under 'the standard, these liabilities will be recognized at'fairvaue 'as 'incurred and-capitalized 'and depreciated over the appropriate period as part of the cost of the related tangible long-lived assets.

SFAS No.' 143 required KEPCo to recognize and estimate the liability for its6% share of the estimated cost to decommission Wolf Crek, based cmth6 pesent value'of the asset retirement 'obligation KEPCo incurred at the time it was placed into service in 1985. On January 1, 2003, KEPCo recognized an asset retirement obligation of $11.7 million. Inn addition, utility plant in-service, .net of accumulated depreciation, was increased by $2.9 million. These amounts were estimated based on the calculation guidelines of SEAS No. 143. KEPCo also established a regulatory asset for $3.9, million, which represents the amount of the Wolf Creek asset retirement obligation and accumulated depreciation not yet funded. A reconciliation of the asset retirement obligation for the years ended December 31, 2004 and 2003 is as follows:

200C

______2003 Balance at January 1 -'- $ 12,385,380 11,684 Accretion ' ' "a 743,124 ' 701 Balance at December 31 $ 13,128,504 12,385 The adoption of SEAS No. 143 did not impact ne'tmargin. Anj' net margin -effects' aie deferred in the Wolf Creek decommissioning regulatory asset created pursuant to SFAS No. 71, Accountingfor the Effects of Certain types ofRegulation. .. ..

(h) Long-livedAssets  !*.~ .' do a. ':'--f-2'?. *t. A Managemenet reviews' iong-lived asssets for impairment whenever events or /changes iri circuimstances indicate the carrymgamount of an asset riay not be recoverable: Iii the event a log-lived asset was determined to be' ipaired, such asset iould be required to be written down to its fair value, with the loss recognized in the consolidated satements of revenu and expensie-s.

(1) Cash andCashEquivalents -  :,.. .--

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 fair value.

a) Materials andSupplies Inventory Materials and supplies inventory are valued at average cost.

- continued 22

Notes to Cons1id&ie Financial S~tatiem'ent Decmbe312'60041 anid 200 A:.:n 4 (k) UnamortizedDebt Issue Costs Unamortized debt issue costs relate to the issuance of the floating/fixed rate pollution control revenue I 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 and notes.

(1) 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 other investments on the consolidated balance sheets.

2004 2003 Cash surrender value of contracts $ 4,206,023 3,910 Borrowings against contracts (4,206,022) (3,885 Net $ 1 25 Borrowings against contracts include a prepaid interest charge. KEPCo pays interest on these borrowings at a rate of 5.84% and 6.53% for the years ended December 31, 2004 and 2003, respectively.

(m) Revenues - Il 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.

(n) Income Taxes -l 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 consolidated financial statements.

(o) Estimates The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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 consolidated financial statements and the reported amounts of revenues and expenses i

during the reporting period. Actual results could differ from those estimates.

(p) Reclassiflcations Certain prior year amounts in the consolidated financial statements have been reclassified where j

necessary to conform to the 2004 presentation.

(3) Factors that Could Affect Future Operating 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 and transmission 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. M 23 -- continued flu

Nots CnsoidaedFinncil t tatement The 1992 Energy Policy Act began the process of restructuring the United Statesuelectric'utiity industry by permitting the Federal Energy Regulatory Coifimission to order electric 'utilities i6 allow third parties to sell electric power to wholesale customers overtheir'transnission systeems. Many states are' cuirrently 'moving toward 'opening the retail segnment to competition.'Thle Kansas Legislature has'not taken any significant action

'on industry restructuring'that would have adire'ct impact on KEPCo. Management will 6continue' to monitor

' deregulation initiatives, but does not presently e-pect any actions, which would be 'unfavorable to KEPCo, to be adopted within the next 12 months.

(4) Departures from Generally Accepted Accounting Principles o - wot Effective February 1, 1987, the KCC isiiued an Order to KEPCo requiring the use of present worth (sinking fund) depreciation and amortization. As 6moeA'ully described in note 8, such depreciation and amortization methods constituted phase-in pla that did 'riot meiet the requirements of SFAS No. 92, Accounting for Phase-In Plans.

Effective February 1, 2002, the KCC issued an order that extended the depreciable life of Wolf Creek from 40 years to 60 years. This order also permitted recoveryin rates of the $53.5 inillion cumulative difference between historical present worth (sinking fund)'deFpreciation and amortization'and straight-iline depireciation and amortization of Wolf Creek generation plant and disallowed costs over a 15-year period. As more fully described in note 8, such depreciation and amortization methods constitute phase-in plans that do not meet the requirements of SEAS No. 92. Recovery of these costs in rates is included in operating revenues and the related amortization expense is included in deferred charges in the consolidated statements of revenue and expenses.

The effect of these departures from generally accepted accounting principles is to overstate (understate) the following items in the consolidated financial statements by the following amounts:

2004 2003

'Deferred charges - $ 42,763,609 46,32; Patronage capital 42,763,609 46,321 Net margin  ;- (3,563,634) (3,563 (5) Wolf Creek Nuclear Generating Station KEPCo owns 6% of Wolf Creek, which is located near Burlington, Kansas. The remainder is owned by the Kansas City Power & Light Company (KCPL-47%) and Kansas Gas & Electric'Company' (KGE-470/%):

KGE is a wholly owned subsidiary of Westar Energy, Inc. KCPL is a wholly owned subsidiary of Great Plains Energy Inc. KEPCo's undivided interest in Wolf Creek is consolidated -ona 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 'fromn Wolf Creek, .which'ismused to supply a portion. of KEPCo's members' requirements. KEPCo is billed on a dailybasis for 6% of the operations,*maintenance, administrative and general costs, and cost of plant additions related to Wolf Creek. -

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

The' Lo-Level Radioactive Waste Policy Amendments Act of 1985' mniidated that the`'various states, individually or through interstate compacts, develop alternative low-level radioactive 'waste disposal facilities.

7The states of Kansas, Nebraska, Arkansas, Louisiana, and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Compact), aind the Compact Commission, which is responsible for causing a new disposal facility' to be developed within one'of the member states. The Compact Commission selected Nebraska as the host state for the 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.

-continued 24

Not& Con~soli-date IFinnil--tmet Co aDecer.ir3l,2 a.

In December 1998, the Nebraska agencies responsible for considering the developer's license application m "denied the application 'Most of the utilities tht' had provided the project's pre-construction financing, including WCNOC, as well as the Compact Commission itself, 'filed a lawsuit in federal court contending Nebraska officials acted in bad faith while handlin'g the license application. In September 2002, the court entered a judgment of$151.4 million; about one-third of which constitutes prejudgment interest, in favor ofthe Compact Commnission and against'Nebraska, finding that Nebraska had acted' in bad faith in handling the license application. Following unsuccessful appeals of the decision by Nebraska, in August 2004 Nebraska and the Compact Commission settled the case. The settlement requires Nelraska to pay the Compact Commission ,

a one-time amount of $140.5 million or, alternatively, four annual installments of $38.5 million beginning in August 2005. The parties agreed to dismiss all pending litigation and appeals relating to this matter. Once Nebraska makes its final payment, it will be relieved of its responsibility to host a disposal facility. Meanwhile, the Compact Commission is pursuing other strategies for providing disposal capability for waste generators in the Compact region.'

L]

(6) Investments in Associated Organizations Investments in associated organizations are carried at cost. At December 31, 2004 and 2003, investments in associated organizations, including CFC, consisted of the following:

2004 2003 CFC: ill Membership $ 1,000 1,000 Capital term certificates Subordianated term certificates Patronage capital certificates 395,970 2,205,000 11,441 395,970 2,205,000 6,482 i

Equity term certificates 709,641 709,641 Other 84,040 59,129 j

$ 3,407,092 3,377,222 (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 $4.2 million. This stipulated amount is sufficient to satisfy certain future interest and ii principal obligations. The amount held in the bond fund reserve is invested by the trustee in tax-exempt municipal securities, pursuant to the restrictions of the indenture agreement, which are carried at amortized cost. I (8) Deferred Charges (a) Disallowed Costs :

Effective October 1, 1985; the KCC issued a rate order relating to KEPCo's investment in Wolf Creek, which disallowed $26.0 million of KEPCo's investment in Wolf Creek ($16.4 net of accumulated amortization as of December 31, 2004). 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 i

period starting February 1, 1987. Pursuant to a KCC rate order dated December 30, 1998, the disallowed portion's recovery period was extended to a 30-year period. Through December 31, 2001, KEPCo used the present worth' (sinking fund) method to recover the disallowed costs, which' enables it to meet the M times-interest-earned ratio and debt service requirements in the KCC rate order dated January 30, 1987.

The method used by KEPCo through 2001 constituted a phase-in plan that did not meet the requirements of SFAS No. 92. - l Effective February 1, 2002, the KCC issued an order permitting recovery in rates of the $6.5 million cumulative difference between historical present worth (sinking fund) and straight-line amortization of Wolf Creek disallowed costs over a 15-year period. Such depreciation practice does not constitute a phase-in plan that meets the requirements of SFAS No. 92.

If the disallowed costs were recovered using a method in accordance with accounting principles 25 generally accepted in the United States, the costs would have been expensed in their entirety upon implementation of the KCC order, with a corresponding decrease in patronage capital.

-- continued i

ilM

(b) Woy Creek Deferred Plant Costs Effective February 1, 2002, the KCC issued an order permitting recovery in rates of the $46.9 million cumulative difference between historical present worth (sinking funid) depreciation and straight-line depreciation 'of Wolf Creek' generation plant over a 15-year period. Such depreciation practice does not constitute a phase-in plan that meets the requirements of SFAS No. 92. In 2002, this cumulative difference was reclassified from utility plant allowance for depreciation to deferred charges on the consolidated balance sheets to reflect the amount as a regulatory asset. Amortization of the Wolf Creek deferred plant costs is included in amortization' of deferred chaires on the '6onsolidated statements of revenue and expenses and amounted to $3.1 'million for each of the years ended December 31, 2004 and 2003, respectively.

If the deferred plant costs were recovered using a method in accordance with accounting principles generallyaccepted in the United Staiks,'the costs would have been expensed in' theirrentirety upon implementation of the KCC order, with a corresponding decrease in patronage capital.

(c) Decommissioning and Decontamination Assessments,.

The Energy Policy Act of 1992 established a fund to pay for the decommissioning and decontamination of nuclear enrichment facilities 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 $150.0 million each y 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 i related deferred asset, 'which is being amortized to nuclear fuel expense over the 15-year assessment period.

(d) Deferred Incremental Outage Costs In 1991, the KCC issued an order that allowed KEPCo to defer its 6% 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.

(e) Other Deferred Charges KEPCo includes in other deferred charges the early call premium resulting from refinancing the 1988 CFC Grantor Trust Certificates piriorJto maturity. This early call preriaium is amortized using the effective interest method over the remaining life ofthe new Grantor Trust Series 1997 certificates.

(9) Short-term Borrowings As of December 31, 2004, KEPCo had a $15.0 million line of credit outstanding with the CFC. This line of credit has a term of 12 months. There were no outstanding borrowings at -eitlher December31, 2004, or December 31, 2003.

-- continued

- -. -I 26

in ecme31,2004'aiid2 (10), Long-term Debt 1I1 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:

2004 2003 'II Mortgage notes payable to the FFB at fixed rates varying from 3.616% to 9.206%, payable in quarterly installments through 201 18* $ 86,909,257 96,295

~i 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 47,740,000 49,64(

II Floating/fixed rate pollution control revenue bonds, City of Burlington, Kansas, Pooled Series 1985C, variable interest rate (ranging from 1.87% to 1.88% at December 31, 2004) payable annually through 2015 30,100,000 31,70(

In Mortgage note payable and equity certificate loan to the National Rural Utilities Cooperative Finance Corporation at ,i fixed rates of 3.05% and 5.6%, payable quarterly through 2007 and 2017 4,832,764 5,261 169,582,021 182,902 11 Less current portion 9,953,205 9,112

$ 159,628,816 173,79C I,

• Mortgage notes payable to the FFB is presented net of $4,225,112 and $1,501,644 of cash deposited with the FFB for the future repayment of debt as of December 31, 2004 and 2003, respectively. These deposits are restricted for the future repayment of FFB debt and earn interest at a rate of 5 percent.

It Aggregate maturities of long-term debt for the next five years and thereafter are as follows: Ii Year 2005 2006 2007

$ 9,953,205 10,638,964 11,252,021 in 2008 11,946,939 2009 12,763,417 Thereafter 113,027,475

$ 169,582,021 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% of total assets unless such

'i distribution is approved by RUS. KEPCo was in compliance with all restrictive covenants as of December 31, 2004 and 2003, respectively.

Il

-- continued 27

Me ~~~~~- i;

• r -'ws-:';_,.ef.....................

. ..... 1-,,;1~~~"',-"l-tS~";"7

! jIn 1997, KEPCo refinanced its mortgage notes payable to the 1988 CFC Grantor Trust through the establishment of a newCFC 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% through the use of an interest rate swap that was assigned by KEPCo to the Series 1997 Trust. The mortgage notes payable are prepayable at any time with no prepayment penalties. However, any termination costs relating to the termination of the assigned interest rate swaps is'KEPCo's responsibility. -At December31, 2004, the termination obligation associated with the assigned swap agreement to early retire the mortgage notes payable is approximately $15.9 million. This fair value'estimate is based on information available at December 31, 2004 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 the counterparty to the swap L agreement. However, KEPCo does not anticipate nonperformance by the counterparty.

(11) Benefit Plans j (

(a) National Rural Electric Cooperative Association (NRECA) Redirement and Security Program L KEPCo participates in the NRECA Retirement and Security Program for its'employees. All employees are eligible to participate in this program after one'year of service; In the master multi-employer plan, which is available to all members of NRECA, the -accumulated benefits and plan assets are not l determined or allocated by individual employees. KEPCo's pension expense under this program was

$0.2 million for each of the years ended December 31 2004 iand 2003, respectively.

(b) NRECA Savings 401(k) Plan i All employees of KEPCo are eligible participate in the NRECA Savings 401(k) Plan. Under the plan, KEPCo contributes an amount not to exceed 5%, dependent upon each employee's level of participation and completion of one year of service, of the 'respective employee's base pay to provide additional retirement benefits. KEPCo contributed $0.1 million to the plan for each of the years ended December 31, 2004 and 2003, respectively.

(c) Wol CreekNuclear Oaerating (WCNO) Retirement Plhns KEPCo has an obligation to the WCNOC retirement and supplemental retirement plans for its 6%

ownership interest in Wolf Creek. The plans provide for benefits upon retirement, normally at age 65. In Li l

accordance with the Employee Retirement Income Security Act of 1974, KEPCo has satisfied its minimum fundingrequirements. Benifits under the plans reflect the employee's compensation, years of service, and age at retirement.

Wolf Creek uses a measurement date of-December I for its retirement plan!and January I for its supplemental retirement plan.

The following sets forth KEPCo's share of the plans' changes in benefit obligation, plan assets, and funded status as of December 31:

2004 2003 L Changes in benefit obligation:

Benefit obligation at beginning of year - . $ 6,373,620 5,683 Service cost - 328,320, 324 Interest cost - 420,660 373 Actuarial loss -- - 539,100 84

--.Benefitspaid . - (108,360) (93 i i - -- . L L -

Benefit obligation at end of year d  ; X *s' - , yL;~r

$ .7,553,340 6,373 Accumulated benefit obligation $ 5,930,460 4,728

- continued 28

6tesoo Consolidated Financial Statements d1 1

+:December31", 2004an2O

,i Plan assets are invested in insurance contracts, corporate bonds, equity securities, United States I government securities, and short-term investments.

Changes in plan assets:

2004 - 2003 I A

Fair value of plan assets at beginning of year $ 3,421,140 2,843 Actual return on plan assets Contributions during the year Benefits paid 325,680 486,360 (85,380) 334 313 (71 IT Fair value of plan assets at end of year $ 4,147,800 3,421 Funded status $ (3,405,540) (2,952 Unrecognized net actuarial loss Unrecognized prior service cost 1,945,380 28,080 1,475 32 iI Unrecognized net transition obligation Postmeasurement date adjustments 50,820 94,500 58 TL Accrued benefit cost $ (1,286,760) (1,326 Actuarial assumptions used to determine benefit obligations:

Discount rate Annual salary increase rate 6.00%

3.00%

6.

3.

"A The asset allocation for the plans at the end of 2004 and 2003, and the target allocation for 2005, by

.i asset category are as follows:

Target allocation for 2005 2004 Plan assets 2003 itk Asset category.

Equity securities 50% - 70% 65% 66%

A Debt securities 30%-50% 28% 33%

Other 0% 7%

100%

1%

100%

jJ WCNOC's pension plan investment strategy supports the objective of the fund, which is to earn the In highest possible return on plan assets consistent with a reasonable and prudent level of risk. Investments are diversified across classes, sectors, and manager style to minimize the risk of large losses. WCNOC delegates investment management to specialists in each asset class and, where appropriate, provides the 1li investment manager with specific guidelines, which include allowable and/or prohibited investment types. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews. lII IU

-- continued 29 Il

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

,.= 2004 2003 Service cost $ 328,320 324 Interest cost on projected benefit obligation 420,660 373 Expected return on plan assets (354,900) (314.

Amortization of actuarial loss -  ;  : , .123076 Other -  ;. 11,280- 11 Total net periodic pensioncost ' $ 507,720 472 Actuarial assumptions used to deteimife net periodic pension cost:

Discountrate -- 6.'

Expected return on plan assets' ' '9.00% 9.1 Annual salary increase rate ' ' . 3.20% 3.:

The expected return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans' investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing': long-term historical 'experience ' arid future expectations of the volatility of the various asset classes-Based on the target asset allocations for each asset class, the

- overall expected rate of retun f the portfolio 'was developed; adjusted- for historical and expected mexperience of active portfolio mnanage_ nt resuls compared to benchmark returns and for the effect of

- xesspaid from plan'assets. In'selecting the discount rate,' fixed incom tsecurity yiel rates o corporate high-grade bond yields were considered. r KEPCo estimates cash contributions of $0.6 million will be made to the plans in 2005.

Estimated future benefit payments f6%tth plans xpected future are as follows:

2005  ;- $ :126,000 2006 144,000 '

- 207 in - -- - -168,000 2008 - ' -; .- 198,000 (WhcNh Poteirfleette B erevit e 2 009 v r; i;-2 34,00 0

- 2010 through 2014 - '  :;' 1,884,000i (d) WotfCreek Nuclear Operating Corporation (WCNOQ)Postretirement Benefits KEPCo has an obligation to the WCNOC postretirement plan fori its 6%o onrhi interest in Wolf Creek. This pIlan provides certain 'm"edifcal'bnefts"'tot paiticipants"uipon'retirement'KPos6

- 'obligat'ion is'pisentd Min Wolf Creek miclear 'operating liabilities in the'accompanying consolidated prcaestoKEPCo's 6%

-alace w $0i .4and million-as mil-l-",: of NW_

Dec2emberr~,31,2004 ft'-*-I:-i..and 2003, respectively.

(12) ;"Cominitments and Conting'encies ii-' -';

(a) Ltgation> ; .. :.- >I; d., ..  :- .- - .i 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 borne 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. - ' 7--1t +3

- s is the case with other~eleciiic utilitiesKEPCo, from time-to-time is subject to various actions, A

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, 2004, it is the opinioni of the gen'eral counsel of

- KEPCo i- that there is not a significant probability th,' as a result ofpending 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. - T-'- cniud3

D~

ii i, 200 Lii (b) NuclearLiability and Insurance Pursuant to the Price-Anderson Act, KEPCo is required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, approximately $10.8 billion currently. This limit of liability consists of the maximum available commercial insurance of $300.0 million and the remaining $10.5 billion is provided through mandatory participation in an industry-wide retrospective assessment program. Under this plan, owners are jointly and severally subject to a retrospective i

assessment of up to $100.6 million ($6.0 million-KEPCo's share) in the event there is a major nuclear incident involving any of the nation's commercial reactors. There is a limitation of $10.0 million ($0.6 million-KEPCo's share) in retrospective assessments per incident per year. This assessment is subject to an inflation adjustment based on the consumer price index and applicable premium taxes. If the n

$10.8 billion liability limitation is insufficient, the United States Congress will consider taking whatever action is necessary to compensate the public for valid claims. j The Price-Anderson Act (the Act) expired in August 2002, but was extended until December 31, 2003 for licensees. Licensees such as Wolf Creek continue to be grandfathered under the Act. The current version of a comprehensive energy bill expected to be adopted in 2005 by Congress contains provisions that would amend federal law addressing public liability froni nuclear energy hazards in ways that '

would increase the annual limit on retrospective assessments from $10.0 million to $15.0 million per reactor per incident.

The owners carry decontamination liability, premature decommissioning liability, and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($168.0 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 11 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 properly damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, KEPCo may be subject to retrospective assessments under the current policies of approximately

$1.6 million.

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 of 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 KEPCo's financial condition and result of operations.

(c) DecommissioningInsurances KEPCo carries premature decommissioning insurance, which has several restrictions, one of which can IL only be used if Wolf Creek incurs an accident exceeding $500.0 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor statio i- 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 $500.0 million in covered damages and causes Wolf Creek to be prematurely decommissioned.

i (a) NuclearFuel Commitments At December 31, 2004, KEPCo's share of WCNOC's nuclear fuel commitments were approximately

$1.7 million for uranium concentrates expiring in 2007, $0.2 million for conversion expiring in 2007, I

$1.1 million for enrichment expiring at various times through 2006, and $6.7 million for fabrication through 2024. jj (e) PurchasePower Commitments KEPCo has supply contracts with various utility companies to purchase power to supplement generation in the given service areas. KEPCo has recently executed a new five-year contract with Westar Energy through May 2008 with minimum purchase commitments of 85 megawatts per year.

31 -- continued ill

(13) Faiir.Value of inancial Instruments

- The following ~methods and assumptions were used to estimt h ~rvleo ahcaso iaca instruments for which it is praicticable to esti jtre; that value as stfrhi ESN.17 icoue bu

'FairValueiofFiniancialIn'strumnents.

Cash and Cas~h Equivalents-'The carrying amount approximates the fa~ir value because of the short-term maturity of theselinve'stments.:

Decommissioning-Trust, Inv'estments in AscaeOrganizatos an o udRsreTe fi aue of

• theseassets is primarily based oqutdraktpceasfDcember 31, 2004.

Variable-RateDebt-LThe carrying amount approximates' the fair value because of the short-term variable rates of those debt instruments.

Fixed-Rte eb-Th~fair valu'e of the f -ixedrtFEB debt and thefxdrtSris19Tut debt is based, on the sm fthesiaevluof eahise, tkigntcnsdrioth u rrniates offered to KEPCo 0fordebt of siniilar reinaining mtries.~

The estixiated fair vaues of kEPCo's financial inilstr~urents are as follows:

December 31,'2004 Carrying Fair valu value.

-Cash ad czashequivaleInts $ 5,229,724 5,229.

Invstentsin associated organizatins (icuigivstments in CFQ)., 3,407,092 3,407.

-Bond fuind reserve 4,230,261 4,557.

'Decommissioninig tut 7,165,662

• 7,165.,

Fie-ae et.139,482,021 143,571, Vral-aedebt - 30,100,000~_~e 30,100

-(14) .Patironage Capital

-in accordnewthKPosIylw kEP6o's 'current margins -are to be alocated to members. KEPCo's,:

curn :oiyis to allocate margins to the memfbers based on reeus collecte from the~members as a,-

pretge~f total revenu-es. If KEPCo s consolidated financial statemients were adjusted to rfetacutn

,principles generally accepted in' teUtdSaeso erca,,total patronage caia ol enegative As noted 'in"the'conislidated 'state'ments bf c ~ie arnage capitalno patronagecptldsrbtoswr made'to m-ember inm2004 an~d 2003.~~~'.~

- - end 32

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