<PAGE>

                        THE STATE CORPORATION COMMISSION
                             OF THE STATE OF KANSAS


Before Commissioners:          John Wine, Chair
                               Cynthia L. Claus
                               Brian J. Moline

<TABLE>
<S>                                                                <C>
In the Matter of the Application of Western Resources, Inc.    )
for Approval To Make Certain Changes in its Charges for        )
Electric Service.                                              )
                                                               )   Docket No. 01-WSRE-436-RTS
In the Matter of the Application of Kansas Gas and Electric    )
Company for Approval To Make Certain Changes in its Charges    )
for Electric Service.                                          )
</TABLE>

                           ORDER ON RATE APPLICATIONS

            The above matter comes before the State Corporation Commission of
the State of Kansas (Commission) for consideration. Having reviewed its files
and being fully advised of all matters of record, the Commission finds:

                                  BACKGROUND


            1. On November 27, 2000, Western Resources, Inc. (WRI) filed an
Application seeking an increase in its annual revenues of $92,581,768. WRI
provides electric service in Kansas under the name KPL. Also on November 27,
2000, Kansas Gas and Electric Company (KGE), a wholly owned subsidiary of WRI,
filed an Application seeking an increase in its annual revenues of $57,924,438.
These rate filings were consolidated for consideration and hearing. The combined
requested rate increase is $150,506,206. When WRI and KGE are referred to
jointly, they will be identified as the "Applicants."

            2. WRI and KGE are electric public utilities as defined in K.S.A.
1999 Supp. 66-104. The Commission has jurisdiction of the utilities and rate
requests pursuant to K.S.A. 66-101, et seq.
<PAGE>

                                      -2-


            3. On December 21, 2000, in its Pre-Hearing Conference Order, the
Commission scheduled an evidentiary hearing on the requested rate increases.
Notice of the proposed rate increases, public hearings, and the technical
evidentiary hearing was also provided through inserts in customer bills and
publication in newspapers of general circulation in the utilities' service
territories. Public hearings on the rate applications were held in Wichita,
Kansas on April 11, 2001; in Salina, Kansas on April 17, 2001; in Topeka, Kansas
on April 19, 2001; and in Pittsburg, Kansas on April 26, 2001. No objections to
notice have been made and the Commission finds that notice was proper.

            4. The evidentiary hearing was held at the Commission's offices in
Topeka, Kansas, from May 17, 2001 through June 4, 2001. Appearances of counsel
were as follows: Martin J. Bregman, Michael Lennen, James M. Fischer and Donald
D. Barry on behalf of the Applicants; Susan B. Cunningham, W. Thomas Stratton,
Jr., and Glenda L. Cafer on behalf of Commission Staff and the public generally;
Walker Hendrix and Niki Christopher on behalf of the Citizens' Utility Ratepayer
Board (CURB); James P. Zakoura on behalf of Kansas Industrial Consumers (KIC);
Timothy E. McKee, Gregg D. Ottinger and Gary E. Rebenstorf on behalf of the City
of Wichita (Wichita); Sarah J. Loquist and Thomas R. Powell on behalf of Unified
School District No. 259 (USD 259); Kirk T. May and Matthew T. Geiger on behalf
of Goodyear Tire & Rubber Company (Goodyear); John C. Frieden and Kevin M.
Fowler on behalf of the City of Topeka (Topeka); James G. Flaherty and Daniel
Covington on behalf of the Empire District Electric Company (Empire); Brock R.
McPherson on behalf of Midwest Energy, Inc.; Larry M. Cowger on behalf of Kansas
Gas Service Company; and C. Edward Peterson, Stuart Conrad and Jeremiah Finnegan
on behalf of Kansas Municipal Energy Agency.

            5. Subsequent to the hearing, briefs on the issues were filed by the
Applicants, Staff, CURB, Wichita, KIC, Goodyear, Topeka, and USD 259. Reply
briefs were filed by the Applicants, Staff, Wichita, KIC, USD 259 and Topeka.
<PAGE>

                                      -3-


            6. At the hearing, the Commission took administrative notice of the
following records and documents pursuant to K.A.R. 82-1-230(i):

            a.          from Docket No. 99-WSRE-381-EGF [Gordon Evans siting
                        permit], the February 15, 1999 testimony of Larry
                        Holloway; the December 2, 1998 Joint Application; and
                        the March 30, 1999 Order. (Transcript, 15-19, 892-93.)

            b.          from Docket Nos. 193,306-U and 193,307-U [KGE and WRI
                        depreciation/ rate cases], the October 14, 1996
                        testimony and exhibits of Mark F. Doljac; the direct
                        testimony of Jerry D. Courington and Tom Bozeman; the
                        October 22, 1996 Motion to Approve Amended Settlement
                        Agreement; the October 29, 1996 Order; the January 15,
                        1997 Order; the Transcript, pp. 615-18; the October 17,
                        1996 testimony of James M. Proctor, pp. 4-12 and 16-20.
                        (Transcript, 1374-75; 1871-72; 1939.)

            c.          the November 15, 1991 Order in Docket Nos. 172,745-U and
                        174,155-U [approving the merger of KPL and KGE.]
                        (Transcript, 1893.)

            d.          the September 17, 1987 Order and Certificate in Docket
                        No. 156,521-U [LaCygne sale/leaseback transaction.]
                        (Transcript, 1981-83.)

            e.          the November 9, 2000 Initial Decision by the
                        Administrative Law Judge in Federal Energy Regulatory
                        Commission (FERC) Docket No. EL99-90-002 [City of
                        Wichita v. Western Resources, Inc.] (Transcript,
                        2034-35.) This is also Exhibit HEO-1 to the rebuttal
                        testimony of H. Edwin Overcast.

            f.          from Docket No. 97-KCPE-661-RTS [review of Kansas City
                        Power & Light Company's revenue requirement], the
                        January 6, 1998 Order No. 6 Adopting Amended Settlement
                        Agreement; and the November 17, 1997 Motion to Modify
                        Suggested Procedural Schedule. (Transcript, 2119-20.)

            g.          the February 11, 2000 Order Issuing Certificate in FERC
                        Docket No. CP99-576-000 [Williams Gas Pipelines Central,
                        Inc.] (Transcript, 2148-49.)

            h.          from Docket No. 97-WSRG-486-MER [WRI, ONEOK and WAI
                        merger], the March 28, 1997 Motion to Amend Joint
                        Application; and the June 3, 1997 Petition for
                        Reconsideration. (Transcript, 2589.)


                          ORGANIZATION OF THIS ORDER


            7. The issues in this Order are organized into several general
areas. The discussion of each area begins on the page listed. An alphabetical
index of issues is also attached to the Order.
<PAGE>

                                      -4-


            Preliminary Matters                          (p. 4.)
            Settled Issues                               (p. 10.)
            Depreciation                                 (p. 10.)
            Capital Structure Issues                     (p. 14.)
            New Generation Capacity                      (p. 20.)
            Rate Base Adjustments                        (p. 24.)
            Income Statement Adjustments                 (p. 34.)
            Other Issues                                 (p. 50.)
            Summary                                      (p. 50.)
            Phase II Rate Design Requirements            (p. 51.)

                              PRELIMINARY MATTERS

                             Restructuring Issues
                             --------------------


            8. As one Commissioner noted during the hearing, the plans of the
Applicants to restructure their corporate organization have been "lurking in the
background" throughout this rate case. (Transcript, 2411.) Several parties
addressed the restructuring proposals at length in testimony and at the hearing.
The Applicants have emphasized that restructuring issues should not be part of a
proceeding to determine cost of service and that the concerns of the parties
will be able to be considered by the Commission in future proceedings (such as a
merger filing). They state that the Commission should focus on regulatory
matters and not on management decisions. Conversely, Staff and Intervenors
posit, in varying degrees, that the Commission cannot ignore the evidence in the
record of the Applicants' restructuring plans and the effects on the financial
health of the utility and on ratepayers.

            9. The Commission has a statutory duty to monitor the financial
condition of electric utilities and the ability of the utilities to provide
sufficient and efficient electric service to Kansas ratepayers. K.S.A. 66-101,
et seq. Parties challenging the Applicants' restructuring plans have pointed to
the detriment to electric customers that would result from an electric utility
with an actual capital structure that is primarily composed of debt. This
situation, if it were to occur, would negatively affect regulated electric
operations and would
<PAGE>

                                      -5-

undeniably require Commission inquiry and action. However, it appears to the
Commission that this is not a direct concern for ratemaking purposes unless and
until the Applicants separate their regulated and non-regulated components and
expose the standalone electric utility to imbalanced debt/equity ratios.
(Transcript, 1987.)

            10. The Commission will not presuppose in this proceeding what will
happen with the Applicants' corporate structure and what the financial condition
of the electric utility will be in the future. The Commission will base its rate
ruling on the utility structure as it exists today. However, the Commission does
order that the rates set in this case be interim and subject to refund until it
is determined what will occur with the electric utility and the Commission is
assured that there will not be an electric utility in financial distress. The
Commission considers this to be the only prudent course of action.

            11. Because the evidence indicates that separating the regulated and
non-regulated business operations of the Applicants, together with other
announced elements of the restructuring plans, would result in an electric
utility with an actual capital structure that is heavily debt-laden (Transcript,
2976), Staff has proposed an interest synchronization adjustment. (Proctor
direct, 11-12, 47-50; Proctor cross, 2-7; Proctor surrebuttal, 4-10; Transcript,
1863-67, 1947, 1987-95.) KIC and USD 259 also support Staff's adjustment. This
interest synchronization adjustment would not be applied to the interim rates
set in this Order, but would be applied if management actions result in a
standalone electric utility with an excessive level of debt. With a hypothetical
ratemaking capital structure that contains more equity than the Applicants
actually have, the Applicants will be recovering taxes in rates that they do not
pay in reality. Staff maintains that its interest synchronization adjustment is
necessary to prevent the Applicants from receiving excessive and unintended
returns relative to an actual all-debt capital structure. The Applicants assert
that Staff's interest synchronization adjustment is improper and would prevent
the Applicants from recovering the return authorized. (Martin rebuttal, 5-6;
McKnight rebuttal, 4-14; McKnight reply, 2-4; Transcript, 3035-36.)
<PAGE>

                                      -6-


            12. The purpose of an interest synchronization adjustment is to
synchronize the portion of the rate base that is supported by debt with the
interest expense deductions that determine current income tax expense for
ratemaking purposes. When there is a hypothetical capital structure, the capital
structure used to set rates is different from the actual capital structure that
supports the rate base. (Proctor cross, 3-4.) The difference between the
positions of the parties is that the Applicants use the hypothetical capital
structure weighted-average cost of debt to calculate interest expense, and Staff
uses the actual utility capital structure weighted-average cost of debt.
(Proctor direct, 48.)

            13. The Commission has considered the Applicants' arguments and does
not find them to be persuasive. In this case, a hypothetical capital structure
is necessary due to the Applicants' debt/equity imbalance. The Commission is
adopting a hypothetical capital structure which, for ratemaking purposes, treats
some debt as if it were equity. The allowed return on equity is greater than the
allowed return on debt. These circumstances provide the opportunity for the
Applicants to benefit in two ways. First, the greater amount of equity in the
hypothetical capital structure provides the Applicants with a greater recovery
than they would receive if rates were based on the actual utility capital
structure. Secondly, at the same time that the Applicants are receiving an
increased return through the artificially high level of equity in the capital
stricture, they also receive a tax benefit because the interest deduction
related to the hypothetical capital structure is less than the actual interest
deduction that they take when income taxes are paid. (Transcript, 1863-67.)
Staff's adjustment recognizes this fact and uses the actual capital structure of
the standalone utility, with the high debt level, to determine the interest
expense that is incorporated in the Applicants' income tax calculation.
(Transcript, 1947.) Staff's adjustment recognizes that the Applicants' actual
interest expense is greater than what would be consistent with the hypothetical
capital structure. This means that, absent the adjustment, the Applicants would
collect from ratepayers current income tax expense that they would not actually
pay. (Transcript, 1995.) Without Staff's adjustment, the Applicants would
receive a greater tax benefit than is contemplated in the regulatory capital
structure, and would recover a higher return than the one authorized by the
Commission. Staff's adjustment would ensure that customers do not
<PAGE>

                                      -7-


pay rates that provide for an overall recovery in excess of what the Commission
has determined to be just and reasonable. Staff's adjustment, calculated with
the capital structure that the electric utility would have as a standalone
entity today, would result in an additional decrease of $26,065,153 to KGE's
revenue requirement and a decrease of $23,133,108 to WRI's revenue requirement.

            14. The Applicants argue that this particular type of interest
synchronization is novel. However, the testimony indicates that a utility with
an actual all-debt capital structure is also novel and unique, and presents
unusual and challenging regulatory problems. The Commission finds that the
theory behind Staff's adjustment is sound, and that if a utility with an
inappropriately high debt level is created, it will be a result of the actions
and decisions of the Applicants. If such a standalone utility comes into
existence, Staff's interest synchronization adjustment, using the actual utility
capital structure, will be applied to determine permanent rates. If the
Applicants are correct in their speculation, and a perilous debt/equity ratio
does not materialize or materializes only for an insignificant period of time,
then this adjustment will not be applied and the Applicants may move to have the
interim rates made permanent.

                        Staff Wholesale/Retail Allocation
                        ---------------------------------

            15. Staff maintains that the Applicants are able to manipulate their
wholesale contracts to the detriment of retail ratepayers by having KPL enter
into the wholesale contracts instead of KGE. Staff argues that be cause the
system is only operated and dispatched, all wholesale sales are supported by the
generation resources of both KPL and KGE, and the selection of which particular
utility is a party to a contract is arbitrary. Because KPL's historic overall
costs are lower than KGE's, the wholesale customers benefit relative to retail
customers. The Applicants allocate more of the expensive KGE generation to
retail customers, who pay a higher rate based on these higher costs. Staff
argues that this manipulation is unfair to retail customers and can be reversed
by adjusting the allocations between wholesale and retail customers that have
been made by the
<PAGE>

                                      -8-


Applicants and considering the utilities on a combined basis. (Holloway direct,
7-9; Proctor direct, 71-75; Transcript, 2027-31.)

            16. The Applicants claim that this adjustment would not respect
wholesale contractual rates that have been approved by the Federal Energy
Regulatory Commission (FERC) and would deprive the Applicants of a reasonable
opportunity to recover their prudent costs. The Applicants emphasize that the
two utilities are separate entities with separate histories, generation assets
and load obligations. (Overcast rebuttal, 3-14 ; Rohlfs rebuttal, 2-8;
Transcript, 2733-37, 2748.)

            17. It appears to the Commission that the Applicants may be using
the different costs of KGE and KPL to favor wholesale customers over retail
customers and that the manner in which the contracts are designated is
questionable. The actual power for wholesale customers (other than those with
participation agreements) could come from either KGE or KPL facilities. The
Applicants raise legitimate concerns regarding the effect of Staff's adjustment
on their ability to recover legitimate costs and on the regulatory dilemma that
is created between Staff s adjustment and the contractual provisions approved by
FERC. The Commission believes that this area should be scrutinized further and
strongly encourages the Applicants to change the way that these contracts are
handled so that this inequity does not continue. At this time, the Commission is
not accepting Staff s adjustment, but the adjustment may be raised again at any
appropriate time.

                  Separate Revenue Requirements for KGE and KPL
                  ---------------------------------------------


            18. Wichita and Staff have presented evidence that combining revenue
requirements would be one way of addressing the historic differential between
KGE and KPL retail rates. The rate differential must be viewed in light of the
historical record. No party in the 1991 KGE and KPL merger proceeding, including
Staff and Wichita, advocated combining revenue requirements at the time. Mergers
should benefit the ratepayers. KGE's ratepayers benefitted measurably in the
1991 merger since scheduled rate increases were cancelled. Subsequent rate
reductions were also channeled primarily to KGE. KPL ratepayers also benefitted
from
<PAGE>

                                      -9-


the 1991 merger, but not as directly or dramatically as KGE. The Commission is
committed to reducing the rate differential, and has previously taken steps to
do so. ( January 15, 1997 Order, Docket Nos. 193,306-U and 193,307-U.) As will
become evident later in this Order, the adjustments in this case make
significant progress towards addressing the rate differential.

                                    Test Year
                                    ---------


            19. These Applications were filed with a test year ending September
30, 2000, and with the request for inclusion of certain costs outside of the
test year relating to new generation facilities. Several parties contend that
the Applicants have selectively included only expenses which occur after the
test year, and have ignored revenues and offsetting adjustments after the test
year which are known and measurable. The applicable test year for this
proceeding ends on September 30, 2000. The Commission also has the discretion to
include post-test year changes which are known and measurable. Gas Service Co.
v. Kansas Corporation Commission, 4 Kan.App.2d 623, 636-36, 609 P.2d 1157, rev.
denied 228 Kan. 806 (1980). The Commission will consider proposed adjustments
based on changes after the test year which would either increase or decrease the
revenue requirement and will rule on them individually in accordance with the
known and measurable standard.

                                 SETTLED ISSUES


            20. On the second day of the hearing, the parties informed the
Commission that they had reached settlements concerning six issues. The parties
accepted the Applicants' adjustments for Wolf Creek 18-month fuel stock,
economic development, actual billed revenues, and plant completed - not
classified. The parties also agreed to Staff's weather normalization adjustment
and that quality of service standards should be considered in a generic manner
in a docket or through the adoption of administrative regulations. In connection
with quality of service, the Applicants agreed to retain six years of actual
historic reliability data on a going forward basis. (Transcript, 242-43; Doljac
direct, 51-52.) The Commission directs Staff to initiate its review of quality
of service standards on or before November 1, 2001.
<PAGE>

                                      -10-


            21. The Commission finds that the settled positions on these matters
are reasonable. The Commission accepts the settlements and adopts the amounts
and adjustments as part of this Order.

                                  DEPRECIATION


            22. Two comprehensive depreciation studies were presented at the
hearing - Aikman on behalf of the Applicants, and Majoros on behalf of CURB,
KIC, Wichita, Goodyear and USD 259. The Applicants request an increase from
current depreciation rates. (Aikman direct, Appendix E.)

            23. Staff notes that Aikman uses the remaining life technique for
his depreciation analysis, instead of the whole life method currently used by
KPL and KGE. Staff has no objection to the remaining life approach so long as an
updated depreciation study is filed every five years. Staff questions Alkinan's
life estimates for the Jeffrey, LaCygne, Lawrence and Wolf Creek facilities.
Staff also recommends that transmission and distribution rates be combined and
that Staff's revised net salvage site values be recognized. (Holloway direct,
3-4, 9-28; Holloway cross, 5-9; Holloway surrebuttal, 10-11; Transcript,
2086-2178, 2186-2204.)

            24. The Majoros study incorporates longer remaining lives for the
LaCygne, Jeffrey, Lawrence, Gordon Evans, State Line and Wolf Creek units, but
accepts Aikman's net salvage values. (Majoros direct, 4, 10-2 1, Exhibits MJM 1-
12; Transcript, 2209-2227.) Topeka asserts that the lives for the new Gordon
Evans combustion turbines should be 35 years, instead of the 25 years used by
Aikman. (Bodmer direct, 6-7.)

            25. The Applicants acknowledge that depreciation studies require the
use of judgment and include projections for the future. The development of
depreciation accrual rates is a subjective process to a great extent.
(Transcript, 1312-1314.) Decisions about life spans are the most important
factor in depreciation analysis, and they also involve judgment. (Transcript,
1388.)

            26. The Commission finds the Majoros depreciation study and
recommendations to be the more persuasive and adopts them. The Majoros study is
supported by a detailed nationwide actuarial study of
<PAGE>

                                      -11-


steam units, by personal inspections of several of the Applicants' plants, and
by a life extension study prepared by the Applicants. (Majoros direct, 3-4,
10-24; Transcript, 2211, 2221.) The Applicants argue that the extended lives
used by Majoros are not possible without interim capital additions, and that it
would be unfair to extend the lives without recognizing the additional
expenditures. (Aikman rebuttal, 2-5; Aikman reply, 3-5.) However, it is
undisputed that new expenditures are generally not recognized or included in
depreciation calculations until they occur. (Aikman direct, 16; Transcript,
1409-10, 2086, 2130; KIC Trial Brief, 23-24.)

            27. The Applicants do not object to Staff's proposal to combine the
distribution and transmission account depreciation accrual rates (Holloway
direct, 12-14; Applicant's Initial Brief, 55.) The Commission finds that this is
appropriate.

            28. The Commission also accepts Staff's recommendation that updated
depreciation studies be prepared and filed with the Commission every five years.
The Applicants did not oppose this, and the Commission finds that it will keep
depreciation adjustments reasonably consistent with current information.

            29. In adopting the Majoros study, the Commission is assuming that
the Wolf Creek nuclear plant will request and obtain a 20-year license extension
from the Nuclear Regulatory Commission (NRC). Because Wolf Creek cannot apply
for a license extension until 2005, the Applicants argue that it is premature to
increase the useful life of Wolf Creek. (Aikman rebuttal, 9.)

            30. Staff asserts that the generating capacity from Wolf Creek will
be needed well into the future. Given this fact, and the reliability and low
operating costs of Wolf Creek, Staff suggests that it would be imprudent for the
Applicants not to apply for and receive a 20-year life extension from the NRC.
(Holloway direct, 16.) Staff originally recommended a 10-year life extension for
depreciation purposes, but after reviewing the Majoros study, stated that a
20-year life extension would be reasonable. (Holloway direct, 18-19; Holloway
cross, 8-9; Transcript, 2187-88.)
<PAGE>

                                      -12-


            31. The Commission must use its best judgment in making the
determination about the extension of the Wolf Creek operating license. It is
undisputed that Wolf Creek is one of the newest nuclear power plants in the
country, that it has modern equipment, and is operated in a good and efficient
manner. Wolf Creek is also one of the better built and designed nuclear power
plants. (Transcript, 1423, 2109, 2189.) Majoros visited the NRC to investigate
the status of operating license extensions (Majoros direct, 3), and Staff's
witness is familiar with the Wolf Creek facility. (Transcript, 2186.) However,
Aikman did not discuss a possible extension with anyone at Wolf Creek or at the
NRC. (Transcript, 1384-86.) Aikman informed the Commission that he would not
consider anything short of an actual renewal to be a sufficient basis to extend
the Wolf Creek life. (Transcript, 1385.) The Commission finds that Aikman's
standard that the license actually be renewed before the plant's depreciation
life can be extended to be unreasonable. Nuclear power plant license extensions
are widely predicted now, and the clear trend has been to grant license
extensions. (Transcript, 1369-72, 2188-90.) The information known about Wolf
Creek strongly supports the conclusion that the Wolf Creek license will be
extended for an additional 20 years by the NRC. Setting depreciation rates on
that assumption is reasonable. There is no way to know with absolute certainty
what will happen in the future with any plant. The depreciation findings are
based on the best information available today. The five-year update that the
Commission has ordered will provide additional opportunities to review the
status of Wolf Creek and to make any adjustments that appear necessary in the
future. (Transcript, 2132.)

            32. Staff has acknowledged that its net salvage site value
adjustment presents a nontraditional approach for valuing generation sites. The
Commission is intrigued by Staff's theory, but is not adopting it at this time.

            33. These findings result in changes to depreciation expenses and
related deferred income taxes. The adjustment to net operating income is an
increase of $16,170,045 for KGE, and an increase of $8,415,675 for WRI.
<PAGE>

                                      -13-


                            CAPITAL STRUCTURE ISSUES

                                Capital Structure
                                -----------------

            34. The parties agree that the apparent capital structure of the
standalone electric utility is not generally an appropriate one to use for
ratemaking purposes, and that the preferred approach would be to determine a
hypothetical capital structure. (Cicchetti rebuttal, 23, 29-30; Cicchetti reply,
2-3; Proctor direct, 17-19, 32-33, 46-47; Hill direct, 13-16; Dunn direct,
41-44, 51.) Four hypothetical capital structures have been recommended to the
Commission.

            35. The Applicants propose a capital structure of 50% long-term debt
and 50% common equity. The Applicants state that the Commission should use a
hypothetical capital structure that reflects a reasonable debt to equity
relationship and that this proposal is an acceptable target which KGE and WRI
should move towards. They suggest that this hypothetical capital structure would
encourage the Applicants to return to an appropriate capital structure.
(Cicchetti direct, 7-10; Cicchetti rebuttal, 29-30; Cicchetti reply, 2-3.) CURB
opposes the Applicants' capital structure and maintains that it contains too
much equity capital. (Hill direct, 11.) Staff argues that the Applicants'
proposal is arbitrary and is not based on facts regarding the electric utility's
financial statements or operations. (Proctor direct, 20.) KIC and Goodyear state
that Applicants' hypothetical structure is not appropriate and is not supported
by any work papers. (Dunn direct, 45.)

            36. Staff's recommended capital structure is 51.62% long-term debt;
44.14% common equity; 0.90% preferred stock; and 3.34% accumulated deferred
investment tax credits. Staff states that this capital structure represents the
funds that have been used to finance the electric utility and the effect of cash
flow generated by the profitable utility business. Staff's capital structure is
based on an extensive cash-flow analysis. (Proctor direct, 6-13, 17-20, 28-30,
Exhs. JMP-1, JMP-4.) The Applicants have acknowledged that Staff's hypothetical
capital structure is not unreasonable. (Brief, SD 259 and KIC have also
indicated that Staff's proposal would be appropriate. (USD 259 Brief, 31; USD
259 Reply Brief, 9,15; KIC Brief, 17-18.)
<PAGE>

                                      -14-


            37. CURB recommends that the Commission use the consolidated capital
structure of the parent company, WRI. This is 53.97% long-term debt, 39.07%
common equity, 0.50% preferred stock, 4.39% preferred securities, 1.85%
accumulated deferred investment tax credits, and 0.24% customer deposits. (Hill
direct, 15-17.) The Applicants are opposed to this option, and KIC does not
recommend that it be adopted. (Applicants' Brief, 15-16; KIC Brief, 17-18.) USD
259 would support CURB's hypothetical capital structure. (USD 259 Brief, 31; USD
259 Reply Brief, 9,15.)

            38. KIC and Goodyear recommend using the combined equity ratio that
would exist after the merger of the electric utility business with Public
Service Company of New Mexico (PNM), and state that this is 13.97% common
equity. (Dunn direct, 2-6, 51.) The Applicants contend that this proposal is
highly speculative and that it is not known what capital structure the utility
would have after a merger with PNM. (Cicchetti rebuttal, 117.) Staff also argues
that this capital structure is speculative, and emphasizes that a post-merger
utility would have additional equity related to goodwill recorded in the
transaction for the premium paid above book value. (Gatewood cross, 3;
Transcript, 2318-20.)

            39. The Commission finds that Staff's recommended capital structure
is the most reasonable and valid. Staff's capital structure is directly related
to the actual condition and operations of the utility and is based on a detailed
and thorough cash-flow analysis. The Commission adopts Staff's proposed capital
structure.

                             Cost of Long-Term Debt
                             ----------------------


            40. The Applicants originally requested an embedded cost of debt of
7.89% and stated that this was typical for other electric utilities. (Cicchetti
direct, 26.) Both Staff and CURB argued that a $600 million term loan with an
interest rate of 10.45% should not be included in the cost of debt. CURB removed
the term loan from its calculation of the embedded cost of debt, while Staff
stated that the Commission should adjust the interest rate of the term loan to
7.00% if that debt is included in the capital structure. CURB proposed an
<PAGE>

                                      -15-


embedded cost of long-term debt of 7.0589%, and Staff's proposed cost of debt
was 7.14%. (Hill direct, 16-17, revised Exh. SGH-1, Sch. 2, p.5; Gatewood
direct, 33-37.)

            41. The $600 million term loan is in the record as Applicants'
Exhibit 1. As discussed at the hearing, this loan carries a variable interest
rate. In their Brief, the Applicants note that the applicable interest rate has
fallen significantly and that their current embedded cost of debt is 7.5062%.
(Brief, 24.) Given this fact, the Commission has concluded that the Applicants'
revised embedded cost of debt is reasonable and accepts the rate of 7.5062%.

                                Return on Equity
                                ----------------


            42. The Applicants, Staff and CURB all recognize that the allowed
return on equity (ROE) should be sufficient to assure confidence in the
financial soundness of the utility, to permit the utility to attract the capital
necessary to carry out its duties of providing service and meeting customer
needs, and to provide a return comparable to returns which investors would
expect from other investments with the same degree of risk. (Cicchetti rebuttal,
49, 52; Gatewood direct, 4-6; Hill direct, 4; Applicants' Brief, 11-12.) The
Applicants' recommended ROE is 12.75%, while Staff and CURB have proposed a ROE
of 10.50%.

            43. To determine an appropriate ROE, the Applicants rely on a
discounted cash flow (DCF) analysis, and use the risk premium method as a check
on the reasonableness of the DCF analysis. (Cicchetti direct, 4, 10-23.) The
Applicants also contend that an ROE higher than what is indicated by these
analyses is justified by four additional risks faced by the Applicants. These
additional risks are increasing competition in the electric industry, having
nuclear generation, possible fuel price increases, and the threat of Wichita
municipalization. (Cicchetti direct, 28-38; Cicchetti rebuttal, 88-89; Cassidy
reply, 2-3; Transcript, 3094-95.)

            44. CURB and Staff question the Applicants' DCF analysis by pointing
out that many of the companies in the proxy group are not primarily electric
utility companies and are subject to higher risks than
<PAGE>

                                      -16-


regulated electric utilities. (Hill direct, 44-45; Gatewood direct, 22-25.) They
also raise numerous other concerns related to the Applicants' suggested ROE.
(Hill direct, 43-52; Hill surrebuttal, 15-24; Gatewood direct, 21-29.)

            45. Staff's recommended ROE is the average of two DCF analyses and
one capital asset pricing model (CAPM). Staff's DCF proxy group consists of
seven electric utility companies with at least 50% of revenues from the sale of
electricity. Other criteria include having generation, transmission and
distribution assets, no recent dividend cuts, positive earnings and growth
forecasts, and a strong financial strength rating. Staff states that it focused
on the cost of equity capital for electric utility companies that were similar
to the Applicants' utility operations, and that the Applicants' utility business
is much healthier financially than the overall WRI corporate entity which
includes riskier non-regulated activities. (Gatewood direct, 5-21, 28-29.) Staff
emphasizes that it is necessary to look at the current state of the capital
markets and that comparisons of ROEs that were authorized at different times are
not valid. (Transcript, 2326-2337, 2356-57.) The Applicants are critical of many
aspects of Staff s analysis. (Cassidy rebuttal, 2-11; Cicchetti rebuttal,
49-90.)

            46. CURB maintains that current capital costs are relatively low.
CURB used a DCF model to estimate the cost of common equity capital. CURB also
looked at results from a CAPM model, a modified earnings price-ratio analysis
(MEPR) and a market to book analysis. For its DCF analysis, CURB selected a
sample group of 11 electric companies with revenues primarily from electric
operations, bond ratings of single-A or below, and which owned generation as
well as transmission and distribution operations. (Hill direct, 5-10, 17-37,
42-43.) CURB's ROE estimate was in a range of 10.00% to 10.50%. After
considering differences in financial risk, CURB concluded that a 10.50% ROE was
reasonable. (Hill direct, 37-43.) The Applicants have numerous disagreements
with CURB's ROE recommendation. (Cicchetti rebuttal, 90-114; Cassidy rebuttal,
12-16; Cassidy reply, 1-4.)

            47. The Applicants state that no formula can compute an ROE
perfectly and that judgment is always a part of a rate of return analysis.
(Cassidy rebuttal, 11.) Staff has asserted that different ROE methods
<PAGE>

                                      -17-


capture different aspects of the capital markets. (Transcript, 2338.) One of the
Applicants' witnesses has also said that picking a proxy group is more of an art
than a science. (Cicchetti rebuttal, 87.) The Commission clearly has discretion
in its ROE findings and must evaluate the reasonableness of the various options
presented.

            48. The Commission first notes that its obligation is to determine
the cost of equity that is applicable to the electric utility operations of the
Applicants. (Hill direct, 45; Transcript, 2368.) The Applicants also indicate
that the ROE should be based upon the standalone value of the electricity
business and physical assets. (Cicchetti rebuttal, 23.) However, the DCF
approach used by the Applicants was not consistent with this principle. Both
Staff and CURB emphasize that the Applicants' proxy companies are not primarily
electric utilities. (Hill direct, 44-45; Gatewood direct, 22-25.) The Commission
finds this to be a fundamental flaw in the Applicants' ROE analysis. The
reliance on companies which are subject to greater risks than regulated electric
utilities leads to the Applicants requesting an ROE that is higher than
warranted. The Commission finds that the DCF analyses of Staff and CURB are more
reasonable and appropriate. While the Applicants have raised questions about the
ROE calculations of Staff and CURB, the Commission accepts the premise that no
ROE analysis is perfect and the criticisms do not invalidate the recommendations
of Staff and CURB.

            49. The Commission has considered the four additional risk factors
submitted by the Applicants and finds that none are unique risks which warrant
an increased ROE. The changing electric industry and volatile fuel prices are
factors that affect all electric utilities. Staff and CURB accounted for these
risks by choosing proxy companies that were primarily electric utilities. This
general risk was captured by the proxy groups and is not an additional risk to
the Applicants that requires a special adjustment. Similarly, both Staff and
CURB included companies with nuclear generation in their proxy groups, and this
is not a unique risk factor affecting the Applicants. (Gatewood direct, 7,
31-33; Hill surrebuttal, 18-19; Transcript, 2350-51.) The last suggested risk
factor is the concern that Wichita might municipalize its electric service.
Although it is reasonable to expect that Wichita will continue to pursue this
option, it is uncertain how long the process might take or what the end result
will be. The Commission agrees with Staff that this is too uncertain a factor to
serve as a basis for
<PAGE>

                                      -18-


an explicit ROE adjustment. (Gatewood direct, 33.) The Commission also finds the
argument persuasive that other electric utilities face serious litigation
matters, including potential municipalization. (Transcript, 2359.)

            50. The Commission will adopt the basic ROE analysis offered by
Staff. The DCF and CAPM models used by Staff have been accepted by this
Commission in the past. The Commission has considered the parties' objections
and qualifications to the CAPM method. The Applicants question the value of CAPM
and argue that the Commission should disregard it entirely. CURB believes that
it can be a less reliable analysis than DCF, but that it is a useful description
of the capital markets, has not been discredited, and is a fundamental finance
teaching tool. (Hill direct, 26; Hill surrebuttal, 22; Cicchetti direct, 22-23;
Cassidy rebuttal, 3-5, 12.) The Commission finds that the CAPM analysis has not
been discredited and that it may provide useful information. However, in this
case, the Commission will modify Staff's ROE by considering only the DCF models.
Giving these two analyses equal weighting provides a revised Staff ROE of
11.02%. The Commission adopts 11.02% as a fair and reasonable ROE which meets
the standards stated in Paragraph 42.

                                 Rate of Return
                                 --------------


            51. Using the capital structure, cost of long-term debt and ROE
adopted above, the approved rate of return for the Applicants is 9.0836%. The
capital structure calculations are attached to this Order.

                             NEW GENERATION CAPACITY


            52. The Applicants state that they have added approximately 514
megawatts of new generation capacity to serve KPL retail customers. This new
generating capacity consists of three combustion turbine peaking units at the
Gordon Evans site in Kansas, and a Purchase Power Agreement (PPA) under which
WRI would purchase 200 megawatts of intermediate combined cycle capacity from
Westar Generating, Inc., a wholly-owned subsidiary of WRI. The capacity is from
the State Line facility in Missouri which is owned 40% by Westar Generating and
60% by Empire. (Grennan direct, 3-9; Holloway surrebuttal, Exh. LWH-S4.) The

<PAGE>

                                      -19-


Applicants request rate base inclusion of the costs of the Gordon Evans units,
and propose that the PPA payment be an adjustment to operating expenses.

                                  Gordon Evans
                                  ------------


            53. Two of the Gordon Evans units went into commercial service in
June 2000. (Grennan direct, 4-5; Transcript, 1005.) The third Gordon Evans unit
entered commercial service on June 12, 2001. (Applicants' Brief, 3.) The first
two units, costing approximately $32 million each, are included in the test year
filing. The Applicants request an adjustment to recover the cost of the third
unit, $61,330,718. (Grennan direct, 6; Application, Vol. 1, Schedule 4-D, p. 2.)

            54. Staff maintains that the three units are needed and recommends
inclusion of the full Gordon Evans costs in rate base. (Holloway direct, 36-38;
Transcript, 2049, 2071-72.) Topeka questions the prudence and timing of these
plant investments, but states that Gordon Evans costs could be placed in rate
base if adjustments are made in areas such as additional off-system sales.
(Bodmer direct, 4-10, 20-22, 30-34, Schedule EBC-1; Pflaum direct, 3-4, 7-13;
Transcript, 2691.) CURB proposes adjustments relating to customer annualization
and additional wholesale and competitive sales. (Crane direct, 38-43, Schedule
10-KPL, Schedule 11-KPL.)

            55. Staff has recognized the importance of not discouraging utility
plant investment when there could be a generation capacity shortage in Kansas in
the near future. (Holloway direct, 37-38; Transcript, 2049.) It is clear to the
Commission that these units are needed and that the costs are not unreasonable.
The evidence also indicates that the units are needed to provide service to the
KPL service area. The Commission finds that it is appropriate to include Gordon
Evans costs in rate base. The Commission does not accept the Topeka adjustment
for dual fuel capability. (Bodmer direct, 32-35.) Other requested adjustments
will be discussed below.
<PAGE>

                                      -20-


                       State Line Purchase Power Agreement
                       -----------------------------------


            56. The State Line PPA is more controversial. The PPA has an initial
term of seven years, with an option for WRI to extend the agreement for another
five years. The PPA provides for a levelized rate for the first 7 years. The
Applicants state that this arrangement benefits ratepayers because it maintains
flexibility for the utility and the cost is less than if the plant were in rate
base. They also emphasize that the rate charged under the PPA will be set by
FERC on a cost basis. The State Line plant went into commercial service on June
22, 2001. (Harrison direct, 4-5; Harrison rebuttal, 2-10; Transcript, 795-96,
1195-97, 1206-16; Applicants' July 2, 2001 letter.)

            57. Staff, CURB, KIC, Topeka, Goodyear and USD 259 have concerns
about the PPA. They question the costs under the PPA, why this arrangement is
used instead of having the electric utility own its own generation, and what
will happen after 7 or 12 years. Parties claim that the utility should be
required to take ownership of the State Line interest and that there should be
offsetting adjustments for additional sales and customers, and for reduced fuel
costs. KIC also argues that WRI acted imprudently in 1995 when it agreed to sell
162 megawatts of Jeffrey participation power to Empire, and that the higher
costs of the State Line plant should be assigned to wholesale operations and the
lower Jeffrey costs assigned to retail customers. (Dittmer direct, 33-44.)

            58. Ths PPA was the subject of a significant amount of testimony and
was discussed extensively at the hearing by the parties and the Commissioners.
(See generally the cross-examination of Grennan and Harrison, Transcript,
Volumes 4 and 5.) The evidence is conflicting as to whether ratepayers are
disadvantaged over time by leased generation as opposed to owned generation, and
as to whether the 1995 sale to Empire of owned generation capacity artificially
created the need to participate in the State Line PPA. Intervenors and Staff
urge the Commission to direct jurisdictional utilities to own rather than lease
capacity.
<PAGE>

                                      -21-


            59. The Commission accepts the explanation of the 1995 Empire sale
provided by the Applicants (Fitzpatrick rebuttal) and finds no basis to declare
that the sale was imprudent. After much deliberation, the Commission concludes
that it cannot find with certainty that the decision to enter into the PPA or
the terms of the PPA are unreasonable. The Commission therefore adopts the
Applicants' proposed treatment of the PPA.

            60. The PPA gives the utility flexibility, which may be a benefit
with changes occurring in the industry. The Commission notes the acknowledgment
of the Applicants that the wording of the PPA is in error and that the price at
which WRI could purchase the State Line interest is based on net book value and
not on book value. (Transcript, 1219, 1251-52.) Rates under the PPA will be set
by FERC on a cost basis after a review of the terms of the contract. The PPA
rates are currently in effect subject to refund. If FERC ultimately sets rates
lower than the original rate, the Applicants have committed to ensure that any
refunds are passed through to the retail customers of KPL. (Transcript, 1237-38;
Initial Brief, 92.)

                 Adjustments Relating to New Generation Capacity
                 -----------------------------------------------


            61. The Commission agrees that adjustments related to the new
generation capacity for additional off-system sales, additional customers and
fuel savings should be made if they can be reasonably quantified. The Applicants
argue that these adjustments are speculative and that they ignore the fact that
the new capacity is to serve retail customers. (Brief, 135-38.) The Commission
is not persuaded that adjustments relating to fuel savings and additional
customers are sufficiently known and measurable. However, additional off-system
sales are another matter. Although they contend that the new Gordon Evans and
State Line capacity is intended only for retail customers, witnesses for the
Applicants acknowledge that there will be increased sales from the new capacity
if market conditions are right. (Transcript, 730-38, 765-66, 943, 1146-51,
2047-48, 2712, 2827-28.) The Commission also cannot ignore the increases in
wholesale sales by the Applicants that have occurred in recent years.
(Transcript, 766-69, 1149-57.) The Commission finds that the only credible
conclusion is that the
<PAGE>

                                      -22-


new capacity will be used by the Applicants for off-system sales. A credit for
the value of these sales should be made in favor of the retail customers who are
paying the costs of the new generation.

            62. Specific dollar adjustments have been presented by CURB, Topeka,
KIC and Wichita. The CURB witness relied on representations and projections made
by the Applicants when calculating the incremental revenue adjustment. This is a
reasonable and valid method for determining the amount of the adjustment. The
Commission adopts CURB's figure of $19,191,165 as an adjustment to operating
revenue. (Crane direct, 39-43, Schedule 11-KPL.)

                              RATE BASE ADJUSTMENTS


            63. The Applicants' proposed rate base for KGE is $1,363,609,832.
The proposed rate base for WRI is $1,099,942,723. (Application, Vols. I and II,
Section 3, Schedule 3-A, p. 1, line 6.) The following adjustments to rate base
have been requested by the parties:

            64. Accumulated Deferred Income Taxes. KPL paid an acquisition
premium (AP) when it merged with KGE. An AP is a sum above book value that an
acquiring company agrees to pay to shareholders of a company that is being
acquired. In a 1991 Order, the Commission allowed the Applicants to begin
amortizing approximately $12.9 million of the AP annually in 1995. The
Commission stated that at that time, it was not allowing the AP to be put in
rate base. The Applicants' only opportunity to earn a return of or on the AP
would be from merger-related savings. Savings above the annual amortization
amount were to be determined in the next rate case and shared 50-50 between
ratepayers and shareholders. Pursuant to the Order, 50% of the savings above the
allowed amortization would be included in cost of service. (November 15, 1991
Order in Docket Nos. 172,745-U and 174,155-U.)

            65. In 1997, in Docket Nos. 193,306-U and 193,307-U, the annual
merger savings were found to be $40 million. The amount above the $12.9 million
amortization figure was approximately $27 million.
<PAGE>

                                      -23-


Of the $27 million, 50% was to be imputed as an operating expense when
calculating the Applicants' regulated earnings. Approximately $13.5 million was
to be treated as an operating expense, and approximately $12.9 million per year
was being amortized, for a total revenue requirement recovery related to the AP
of $26.5 million. (193,306-U and 193,302-U January 15, 1997 Order.) The $26.5
million is recovered annually in rates through the operating income statement.
(Transcript, 1924.)

            66. Staff argues that the Applicants are receiving a return of and a
return on the AP through rates, and that the effect of this is equivalent to
rate base treatment. Staff asserts that its Accumulated Deferred Income Tax
(ADIT) adjustment is a standard adjustment for rate base items and that if it is
not accepted, the Applicants will receive an unfair benefit. Staff maintains
that accepting this adjustment is not inconsistent with prior Orders. Staff's
adjustment is also supported by Wichita. The Applicants rely on the 1991 Order
which said that the AP was not being put in rate base. They argue that an ADIT
adjustment was not contemplated and that no rate base offset is justified.
(Proctor direct, 12, 51-57; Proctor surrebuttal, 11-19; Martin rebuttal, 7-8;
McKnight rebuttal, 14-20; McKnight reply, 4-9; Transcript, 269-70, 1873-76,
1892-1938, 1978-81, 2011; Wichita Reply Brief, 4.)

            67. The Commission accepts Staff's adjustment. ADIT was not
mentioned at the time of the 1991 and 1997 Orders (Transcript, 270), but the
Commission finds that this was because ADIT did not become an issue until after
the $26.5 million amount was determined and the Applicants began to recover that
amount. (Transcript, 1912-13, 1979-81.) As Staff indicates, including ADIT in
rate base is standard to recognize for ratemaking purposes the cost-free capital
provided from ratepayers related to differences between when expenses are
deducted for regulatory and income tax purposes. There would be no need to
specifically refer to such an adjustment in an Order. Including ADIT in rate
base is a well-recognized regulatory accounting concept that is applied in a
variety of situations to account for deferred income tax benefits related to
rate base assets or for timing differences between when expenses are deductible
for income tax purposes and financial reporting purposes. (Proctor direct, 53.)
<PAGE>

                                      -24-


            68. There is no dispute that the Applicants are receiving both a
return of and a return on the AP. (CURB Exh. 12; Transcript, 1897.) This is
equivalent to the AP being in rate base. A rate base item would normally have a
related ADIT component. (Transcript, 1897-98, 1932, 2011.) The ADIT adjustment
addresses the benefit the Applicants derive from collecting deferred income tax
expense through the annual recovery of $26.5 million in merger savings. Through
rates, the Applicants are collecting deferred income taxes related to the AP
from ratepayers. (Proctor surrebuttal, 16.) The deferred income taxes are
collected before the Applicants are required to pay income tax expense for the
amortization of the AP. The result is an increase in expenses for purposes of
calculating rates before the utility actually has to pay the expenses. Because
the Applicants collect deferred income tax expenses related to amortization of
the AP through rates, it is necessary to recognize the unamortized ADIT in rate
base to avoid an unjust benefit accruing to the Applicants. (Proctor direct,
54-57; Proctor surrebuttal, 16; Transcript, 1896, 1916-18.)

            69. Deferred income taxes are recovered as part of the $26.5 million
annual recovery. The equivalent amount of AP in rate base is determined by
calculating the present value of the annuity represented by annual collection of
the $26.5 million through rates over a 34.83-year period. Using the rate of
return ordered in this case to discount the annuity, the Commission finds that
$208,644,237 of the AP is receiving equivalent rate base treatment. Further,
because deferred income tax is collected as part of the $26.5 million, the
Applicants are in effect receiving rate base treatment for the present value of
the deferred income tax payments. That is, the Applicants receive a return on
the present value of the deferred income tax payments. Because the Applicants
receive a return on the present value of the deferred income tax payments and
recovery of the deferred income tax essentially provides an interest-free loan
from the ratepayers to the Applicants, it is necessary to decrease rate base by
ADIT to avoid an unfair benefit to the Applicants. (Proctor 26 surrebuttal, 16;
Transcript, 1917-19.) A cost-free loan from ratepayers should not be in rate
base. The ADIT adjustment deducts the amount of taxes that correspond to the
cost-free capital that the Applicants recover every year as part of the $26.5
million. The Applicants collect deferred income taxes from the ratepayers, and
have the use of that money until the
<PAGE>

                                      -25-


time when the taxes are ultimately paid. The ADIT adjustment deducts from rate
base the amount of funds that are collected from ratepayers by the Applicants,
but are yet to be paid. Without the ADIT adjustment, the Applicants would
receive a revenue windfall from ratepayers. The ADIT adjustment, taking into
consideration the ROR ordered, results in a decrease in KGE's rate base of
$66,295,177, and a decrease in WRI's rate base of $16,698,284. (Proctor direct,
56, revised Exh. JMP-7; revised KGE and KPL Schedules A-3, Adjustment 1.)

            70. Staff's ADIT adjustment is conservative. Instead of simply using
the Applicants' records which show a return of the AP of $12,951,970 (CURB Exh.
12), and calculating the benefit to the Applicants over the remaining 35-year
amortization period, Staff determined the present value of the cash-flow from
the ratemaking treatment and based its ADIT adjustment on that number. While the
Applicants' records would have supported the argument that the $26.5 million AP
recovery is equivalent to placing $453 million of the AP in rate base, Staff
concluded that it was more appropriate to use its methodology which finds that
the recovery is equivalent to having approximately $220.6 million of the AP in
rate base. Staff's calculations result in a lower ADIT adjustment. (Proctor
direct, 53, 56; Transcript, 1873-76, 1897, 1909, 1926-29, 1933-35.) [Given the
rate of return ordered in this case, the recovery is equivalent to having in
rate base the $208 million figure stated above, instead of the $220 million
discussed at the hearing.]

            71. The Applicants assert that Staff has failed to consider that
they are paying current income taxes on the $26.5 million that they recover.
Staff did consider this, but stated that it was not relevant because the $26.5
million had been grossed up for income taxes. (Transcript, 1915-16.) The return
of the AP was approximately $7.8 million annually. In the 1997 Order, the amount
was set at $12.9 million to take into account the income taxes that would be
paid. (Transcript, 1899-1900.) That is, it was "grossed up" for income tax
expense to recognize the income tax expense related to the amortization of the
AP. Because the current income taxes were anticipated and accounted for when
setting the $12.9 million recovery amount, those current taxes are not an issue
now. The payment of current income taxes simply represents the Applicants paying
off the cost-free capital provided by ratepayers through the Applicants'
previous recovery of deferred income tax expense. The
<PAGE>

                                      -26-


Applicants also contend that Staff is trying to "create" deferred taxes. This is
incorrect. The deferral of income taxes is recorded on the books of the
Applicants. As noted above, this is not unusual and is handled through a
standard adjustment for ADIT.

            72. LaCygne Sale/Leaseback. In 1987, the Commission approved the
sale by KGE of its 50% undivided interest in LaCygne Unit 2 and addressed
treatment of KGE's sale and leaseback transaction. The Order notes the obvious
benefits of the transaction to KGE, and then states:

                        Of equal importance to the Commission is the benefit to
            the customer. KGE contends the benefits of the transaction will be
            reflected in its cost of service. KGE proposes to amortize the book
            gain on the sale of LaCygne 2 to its Kansas jurisdictional cost of
            service over the life of the lease transaction. KGE also proposes to
            reduce its rate base by the book value of LaCygne 2, reflect the
            unamortized gain as a reduction in rate base for future rate cases
            and include the benefits of the use of the proceeds from the sale in
            its cost of service. Docket No. 156,521-U, September 17, 1987 Order,
            p. 11 (emphasis added.).

            73. Staff and KIC propose a rate base adjustment to recognize
cost-free capital created from the gain on KGE's sale of LaCygne in 1987. They
state that by the terms of the 1987 Order, the gain from the LaCygne sale funds
are to be considered cost free capital in future rate cases. KIC also emphasizes
that this would be the fair and reasonable treatment regardless of any specific
language in the Order. (Proctor direct, 13, 58-61; Exh. JMP-8, Sch. 1; Dittmer
direct, 15-18; KGE Update Schedule B-1; Dittmer surrebuttal, 20-23.)

            74. The Applicants do not dispute what the Order says, but claim
that the Order is in error. (Rohlfs rebuttal, 31.) They discuss the unique
characteristics of KGE's regulatory history and state that the intended benefits
from the Order have already been recovered. (Rohlfs rebuttal, 23-25, 29-39;
Rohlfs reply, 2-9.)

            75. This adjustment was raised by Staff in the 1997 rate proceeding
involving KGE and WRI, but that case was settled and the adjustment was not
ruled upon. Docket Nos. 193,306-U and 193-307-U, January 15, 1997 Order, pp.
23-25, Paragraphs 43 and 45. The Applicants argue that making the Staff and KIC
adjustment would give all the benefits of the gain to ratepayers, contrary to
Kansas Power & Light Co. v. Kansas Corporation Commission, 5 Kan.App.2d 514, 620
P.2d 329 (1980), rev. denied 229 Kan. 670 (1981). In its Reply
<PAGE>

                                      -27-


Brief, KIC correctly states that the LaCygne transaction is not an outright sale
of utility property (as was the case in the Kansas Power & Light Co. case), but
was a refinancing transaction. (See 1987 LaCygne Order, pp. 9-11.) In addition,
what the Court found objectionable in the Kansas Power & Light Co. case was the
fact that ratepayers were receiving all of the profits from the sale. 5
Kan.App.2d at 529. That is clearly not the case here. The 1987 Order
specifically referred to the substantial monetary benefits that KGE would
receive as a result of the transaction. 1987 LaCygne Order, pp. 11-12.

            76. In arguing against this adjustment, the Applicants focus on the
wording of KGE's Application and the intent of KGE, but what is controlling is
the language in the Order and the intent of the Commission. The Applicants
should have sought reconsideration and appealed the 1987 Order if they disagreed
with its ruling on future rate base treatment. The provisions of the 1987 Order
are clear and reasonable, and will be followed by the Commission. The adjustment
of KIC and Staff is approved and results in a decrease of $86,496,813 to KGE's
rate base. (Proctor direct, 58-61, Exh. JMP-8; Staff revised KGE Schedule A-3,
Adjustment 2; Dittmer direct, KGE Update Schedule B-1.)

            77. FAS 106/112. The Applicants seek to recover unamortized costs
related to Financial Accounting Standards (FAS) opinions 106 and 112. FAS 106
and 112 deal with post-retirement benefits other than pensions and other
post-employment benefits. The Commission previously allowed the Applicants to
amortize 106 and 112 costs with an income stream from a company-owned life
insurance (COLI) program. The Applicants later received Commission approval to
use the income stream from an affordable housing tax credit (AHTC) program. The
Applicants now want to eliminate the AHTC program and to include in rate base
the net unamortized accumulated balance of deferred benefits from the prior
programs. The Applicants emphasize that even though the unamortized 106 and 112
costs represent a non-cash deferral, their shareholders took the initial steps
to fund these programs and have advanced funds to pay interest. The Applicants
also request a five-year amortization period of the net deferred balance of 106
and 112 costs, stating that that is the period of time over
<PAGE>

                                      -28-


which the costs were accumulated. (Stadler direct, 4-7; Stadler rebuttal, 2-10;
Transcript, 1512-14.) The Applicants acknowledge that there has not yet been any
cash outlay of funds. (Transcript, 1515-16.)

            78. Staff, CURB and KIC maintain that the unamortized FAS 106/112
costs which the Applicants seek to recover is the result of an accounting change
from recording the expense on an accrual basis instead of a cash basis. Because
there has been no cash or cash-equivalent investment in the deferral balance,
there is no basis for a return on the unamortized costs and rate base inclusion
is not appropriate. Staff also posits that rate base treatment is not warranted
because the unamortized costs do not have a high degree of permanency and the
value will not continue at a fairly stable level. Staff does not oppose the
five-year amortization period, but CURB recommends a 10-year period and KIC
recommends an 11-year period. KIC also argues that the Applicants should not be
allowed to end the AHTC program. (Yates direct, 5-8; Dittmer direct, 18-23,
75-85; Crane direct, 32-36, 48-50; Transcript, 2278.)

            79. Ending the AHTC program is a reasonable management decision.
(Stadler rebuttal, 7-9.) The Commission accepts the five-year amortization
period proposed by the Applicants. However, the Commission finds that Staff, KIC
and CURB are correct in their arguments that rate base treatment of the
unamortized deferred costs is not appropriate because there has not been a cash
investment. The Applicants' request for rate base inclusion of the unamortized
FAS 106/112 costs is a deviation from the standard regulatory treatment, and the
Commission will not adopt it here. The Commission adopts Staff's adjustment,
which decreases KGE's rate base by $12,848,903 and decreases WRI's rate base by
$20,107,152. (Yates direct, Exh. DDY-3; revised KGE Schedule A-3, Adjustment 5,
and revised KPL Schedule 3-A, adjustment 4.) The Commission also adopts Staff's
recommendation that there should be external third party funding of the FAS
106/112 costs. (See Yates direct, 8.) Within 90 days of the date of this Order,
the Applicants are to meet with Staff to discuss arrangements for such funding.
<PAGE>

                                      -29-


            80. Customer Deposits. The Applicants included customer deposits in
the capital structure. Although this is normally the preferred approach, Staff
and KIC recommend that an alternative treatment be followed because of the
complexity of the capital structure. Their adjustment deducts customer deposits
from rate base and includes the related interest expense in the income statement
as an operating expense. (Yates direct, 4; Dittmer direct, 30-31; Sch. B-6 KGE;
Sch. B-4 KPL.) The Applicants have not objected to this treatment, and the
Commission finds it to be reasonable. This adjustment decreases KGE's rate base
by $5,897,654, and decreases WRI's rate base by $5,957,526. (Yates direct, Exh.
DDY-2; revised KGE Schedule A-3, Adjustment 4, and revised KPL Schedule A-3,
Adjustment 3.)

            81. Environmental Compliance Projects. The Applicants have asked for
inclusion in rate base of costs associated with the Electrostatic Precipitator
(ESP) at Jeffrey Energy Center and Continuous Emission Monitoring Systems (CEMS)
at Tecumseh, Lawrence and Jeffrey Energy Centers. These are environmental
compliance projects mandated by federal and state regulations. (Irwin direct,
2-6; Irwin rebuttal, 2-4.) Staff, KIC and CURB oppose the inclusion of the
costs, arguing that the projects have not been completed and do not meet the
requirements of K.S.A. 2000 Supp. 66-128(b). (Yates direct, 2-4; Crane direct,
28-29; Dittmer direct, 26-29.)

            82. K.S.A. 2000 Supp. 66-128(b)(1) permits the Commission to include
in rates utility property which has not been completed and dedicated to
commercial service if construction of the property will be commenced and
completed in one year or less. There is no dispute that the costs for the
environmental compliance projects are known and measurable. Goodyear and Staff
question whether the construction schedules are definite enough to meet the
statute's timing requirements. (Transcript, 1808-15, 1818-24.) The Applicants
state that work on the CEMS project began in January 2001 and will be completed
in December 2001, and that the ESP construction will take place in October or
November 2001. (Irwin rebuttal, 3-4; Transcript, 1809-10, 1820-21.) The
Commission finds that the Applicants' evidence is satisfactory to meet the
standard of K.S.A. 2000 Supp. 66-128(b)(1) and that the costs should be included
in rate base.
<PAGE>

                                      -30-


            83. Tree Trimming. The Applicants used budgeted 200l amounts for
their tree trimming costs. They submitted increased tree trimming expenses
greater than those incurred during the test year. (Will direct, 8-9.) Staff,
CURB and KIC maintain that budgeted amounts are merely estimates and are not
known or determinable. (Rohrer direct, 6; Crane direct, 53-56; Suess direct,
15-16.) The Commission agrees and accepts Staff s adjustment, which uses actual
Year 2000 capitalized tree trimming costs and allocates the costs on the basis
of the Applicants' transmission allocation percentage. The effect of this
adjustment is to increase KGE's rate base by $44,128 and to increase KPL's rate
base by $69,348. (Rohrer direct, 6; revised KGE Schedule A-3, Adjustment 7, and
revised KPL Schedule A-3, Adjustment 5.)

            84. Wolf Creek and LaCygne Software. Staff made an adjustment to
allocate a portion of Wolf Creek and LaCygne software to FERC jurisdictional
wholesale customers. Staff s allocation adjustment is based on the Applicants'
plant allocations. (Rohrer direct, 5-6.) The Applicants do not contest this
adjustment (Initial Brief, 158), and it is accepted by the Commission. This
adjustment decreases KGE rate base plant by $101,267, and decreases KGE rate
base accumulated amortization of the cost of the software by $50,435. (Revised
KGE Schedule A-3, Adjustment 6.)

            85. Reserve for Depreciation. CURB and KIC recommend updating the
Applicants' reserves for depreciation through June of 200l. (Crane direct,
31-32, Schedule 6-KPL, Schedule 6 KGE; Dittmer direct, 23-26, KPL Update,
Schedules B-3 and C-8; Transcript, 2445-46.) The Commission agrees that this
adjustment is appropriate if plant additions during the same period are also
considered. CURB's proposed adjustment does not include plant additions. KIC
only considered this adjustment for KPL, using the actual data for plant and
reserve additions through December 2000 and the Applicants' budgeted numbers
from December 2000 through June 2001. The Commission finds that for the amount
of this adjustment to be sufficiently known and measurable, it would be
necessary to have the actual numbers for both KPL and KGE through June 2001.
While the proposal is conceptually correct, there is insufficient evidence to
adopt it.
<PAGE>

                                      -31-


            86. Murray Gill Repair. During the test year, the generator in
Murray Gill Unit 2 overheated and repairs were necessary. (Wages direct, 5-6.)
KIC agrees that the need for and cost of the repairs are not at issue (Reply
Brief, 30), but that the Murray Gill adjustments should be rejected because
KGE's rate base has been continuously and significantly declining. (Dittmer
direct, 99-100.) The Commission does not find KIC's argument to be persuasive.

            87. Coal Contract Buyout Costs. CURB recommends that unamortized
balances and associated deferred income taxes related to the buyout of a coal
contract be updated through June 2001. The amount being amortized each month is
known and measurable, and is adopted by the Commission. The requested adjustment
results in a net decrease to KGE's rate base of $812,639. (Crane direct, 36-37,
Schedules 10-KGE and 11-KGE.)

                         INCOME STATEMENT ADJUSTMENTS


            88. For KGE, the Applicants' proposed income statement shows
revenues of $675,192,768 , expenses of $569,201,732, and operating income of
$105,991,036. For WRI, the proposed income statement shows revenues of
$569,874,837, expenses of $513,499,001, and operating income of $56,375,836.
(Application, Vols. I and II, Section 3, Schedule 3-B, p. 1.) Numerous
adjustments to revenues and expenses have been recommended by the parties.

            89. In their Initial Brief, the Applicants state that they do not
contest certain Staff and KIC adjustments. (Initial Brief, 158-59.) The
Commission therefore accepts the following adjustments:

            a.          Staff's adjustment for the portion of Edison Electric
                        Institute dues related to lobbying activities, public
                        relations and advertising. The adjustment decreases
                        KGE's operating expenses by $60,647, and decreases WRI's
                        operating expenses by $87,789. (Rohrer direct, 11-12;
                        KGE and KPL revised Schedules B-3, Adjustment 16.)
<PAGE>

                                      -32-


            b.          Staff's pro forma salary adjustment, which increases
                        KGE's expenses by $75,889 and increases WRI's expenses
                        by $56,897. (Rohrer direct, 14-15; KGE and KPL revised
                        Schedules B-3, Adjustment 19.)

            c.          Staff's adjustment relating to expired railcar leases,
                        which decreases KGE's operating expenses by $64,565, and
                        decreases WRI's expenses by $204,235.) (Rohrer direct,
                        15-16; KGE and KPL revised Schedules B-3, Adjustment
                        20.)

            d.          Staff's adjustment to include lease payments from
                        Protection One in rent expense. This adjustment
                        decreases KGE's expenses by $98,737. (Rohrer direct, 18;
                        KGE revised Schedule B-3, Adjustment 24.)

            e.          Staff's weather normalization and customer annualization
                        adjustments, which increase KGE's revenues by $113,645,
                        and decrease WRI's revenues by $219,060. These
                        adjustments also increase KGE's fuel expenses by
                        $40,325, and decrease WRI's fuel expenses by $3,013.
                        (Rohrer direct, 18-19; KGE revised Schedule B-3,
                        Adjustment 25, and KPL revised Schedule B-3, Adjustment
                        24.)

            f.          KIC's adjustment relating to an expired capacity and
                        energy sale to Empire, and to corresponding fuel
                        savings. The overall effect of this adjustment decreases
                        KGE's revenues by $3,749,753. (Dittmer direct, 52-53;
                        KGE Update, Schedule C-7.)

            90. The Commission adopts the following adjustments, finding that
they also do not appear to be contested by the Applicants:

            a.          Staff's adjustment to remove expenses for outside legal
                        services, which decreases KGE's expenses by $271,545,
                        and decreases WRI's expenses by $494,577. (Rohrer
                        direct, 8; KGE revised Schedule B-3, Adjustment 10, and
                        KPL revised Schedule B-3, Adjustment 12.)

            b.          Staff s adjustment concerning outside accounting
                        services on restructuring options, which decreases WRI's
                        expenses by $235,100. (Rohrer direct, 7-8; KPL revised
                        Schedule B-3, Adjustment 11.)

            c.          Staff's adjustment to remove an extra payment for
                        outside services made during the test year, which
                        decreases KGE's expenses by $68,472, and decreases WRI's
                        expenses by $86,712. (Rohrer direct, 8-9; KGE revised
                        Schedule B-3, Adjustment 11, and KPL revised Schedule
                        B-3, Adjustment 13.)

            d.          Staff's adjustment to remove expenses that were prior to
                        the test year or related to the Applicants'
                        non-regulated affiliate, which decreases KGE's expenses
                        by $183,955, and decreases WRI's expenses by $249,071.
                        (Rohrer direct, 9-10; KGE revised Schedule B-3,
                        Adjustment 12, and KPL revised Schedule B-3, Adjustment
                        14.)
<PAGE>

                                      -33-


            e.          KIC's income tax adjustments concerning a nuclear fuel
                        expense tax deduction and a Wolf Creek net operating
                        loss carry forward deferred tax expense. These
                        adjustments decrease KGE's income tax expenses by
                        $536,562 and $133,174, respectively. (Dittmer direct
                        102-03, KGE Update Schedule C- 12.)

            f.          Wichita's labor allocator adjustment, which decreases
                        KGE's revenue requirement by $73,769. (Suess direct,
                        22-23, Exhibit NDS-7.)

            g.          Wichita's reverse dividend equivalent accrual
                        adjustment, which decreases KGE's revenue requirement by
                        $105,347, and decreases WRI's revenue requirement by
                        $162,839. (Suess direct, 23-24, Exhibit NDS-8.)

            h.          CURB's adjustment to normalize the PeopleSoft software
                        for an entire year, which results in a decrease in WRI's
                        expenses of $194,499 after a percentage is allocated to
                        FERC customers. (Ostrander direct, 50; Transcript,
                        2461.)

            91. The Commission finds that Staff's adjustment relating to
advertising, as revised, is not in dispute. Staff originally sought to eliminate
advertising expenses related to promotion of utility services, goodwill,
improvement of utility image, and economic development. (Rohrer direct, 16.) The
Applicants did not contest the elimination of image and goodwill advertising,
but maintained that advertising concerning economic development benefits
customers and should not be eliminated. (Wages rebuttal, 2.) At the hearing,
Staff rescinded its objection to economic development advertising. (Transcript,
2229.) The Commission will allow the expenses for economic development
advertising, as given by Staff, and also accepts the remainder of Staff's
adjustment. The effect is to decrease KGE's expenses by $125,233, and to
decrease WRI's expenses by $156,799. (Rohrer direct, 16; Transcript, 2229; KGE
and KPL Schedules B-3, Adjustment 21.)

            92. There are several income statement adjustments that correspond
to depreciation, new generation capacity, and rate base rulings. These
adjustments are adopted by the Commission:

            a.          the depreciation rulings increase the Applicants' net
                        operating income. For KGE, the increase is $16,170,045;
                        and for WRI, the increase of $8,415,675 for WRI. There
                        is also an amortization expense adjustment for
                        intangible plant that increases KGE's operating income
                        by $20,253.

            b.          the Commission accepted CURB's adjustment relating to
                        additional sales from new generation facilities. This
                        adjustment increases WRI's revenues by $19,191,165.
                        (Crane direct, 39-43, Schedule 11-KPL.)
<PAGE>

                                      -34-


            c.          Staff's ADIT rate base adjustment requires a decrease in
                        deferred income tax expenses of $1,903,393 for KGE, and
                        a decrease of $479,422 for WRI. (Proctor direct, 557,
                        revised Exh. JMP-7; KPL revised Schedule B-3, Adjustment
                        1.)

            d.          consistent with the rate base customer deposit
                        adjustment, KGE's expenses are increased by $353,859,
                        and WRI's expenses are increased by $ 357,452. (Yates
                        direct, 4, Exh. DDY-2; KGE and KPL revised Schedules
                        B-3, Adjustment 5.)

            e.          consistent with its adoption of Staff's rate base tree
                        trimming adjustment, the Commission accepts Staff's
                        income statement tree trimming adjustments. These
                        adjustments decrease KGE's expenses by $900,219, and
                        increase KPL's expenses by $107,156. (Rohrer direct, 11;
                        KGE and KPL revised Schedules B-3, Adjustment 15.)

            f.          Staff's rate base adjustment to allocate a portion of
                        software expenses to FERC customers was not contested.
                        The income statement adjustment for related amortization
                        of the cost of the software decreases KGE's expenses by
                        $20,253. (Rohrer direct, 5-6; KGE revised Schedule B-3,
                        Adjustment 14.)

            93. The Commission finds that the expense for union retroactive pay
claimed by the Applicants was for a time period outside of the test year and
should not be allowed. The Commission adopts Staff's adjustment to remove this
portion of the union retroactive pay, which decreases KGE's expenses by $112,058
and decreases WRI's expenses by $106,750. (Rohrer direct, 19-21.)

            94. The Applicants included costs for Y2K retention incentive pay.
The Commission agrees with Staff that this is a one-time, non-recurring expense
which should not be included. This adjustment decreases KGE's expenses by
$35,761, and decreases WRI's expenses by $45,288. (Rohrer direct, 21.)

            95. The argument was also made that costs relating to Wichita's
municipalization plans should be disallowed as one-time, non-recurring expenses.
The Commission agrees with the Applicants that these costs relate to regulated
activities and will likely continue for an unspecified period of time. (Wages
rebuttal, 11.) The Commission will allow these expenses.

            96. KIC and Wichita claim that supplemental distributions related to
premiums paid for Nuclear Electric Insurance Limited (NEIL) insurance should be
considered as recurring and included in cost of
<PAGE>

                                      -35-


service. (Dittmer direct, 96-98; Suess direct, 16-18.) The Applicants received
NEIL distribution payments in March 2000 and March 2001, but argue that these
are the only years in which distributions have been made in the past 18 years,
that the distributions were attributable to record investment income and
extremely good loss experiences, and that these factors no longer exist and
supplemental distributions are not expected to continue. (Wages rebuttal, 6-7.)
The Commission does not find the evidence to be sufficient to conclude that
these payments are recurring and accepts the Applicants' proposal to exclude the
NEIL distribution from the rate filing.

            97. The Commission previously expressed its willingness to consider
adjustments outside of the test year that are known and measurable.

            a.          SPP Tariff. Staff supports the Applicants' proposal to
                        place their retail load under the Southwest Power Pool
                        (SPP) network tariff, but KIC, Wichita, Topeka and CURB
                        have all raised objections to including the SPP expenses
                        in the cost of service. (Holloway direct, 44; Dittmer
                        direct, 68-74; Corrigan direct, 10- 12; Bodmer direct,
                        40-41; Crane direct, 19.) The Commission has concluded
                        that the costs are known and measurable, and that
                        placing retail loads under the SPP tariff is reasonable
                        and will improve reliability of electric service. (Dixon
                        direct, 3-9; Dixon rebuttal, 2-13; Transcript, 1102-05.)
                        The SPP expenses are allowed, and Wichita's requested
                        adjustment for point-to-point transmission service is
                        not necessary. (Suess direct, 2022; Dixon rebuttal,
                        5-6.) At the hearing, the Applicants stated their
                        agreement that the cost to ratepayers should be adjusted
                        as the SPP fee paid by the Applicants changes, and that
                        an automatic adjustment clause might be reasonable.
                        (Transcript, 1096-97, 1100.) The Commission directs
                        Staff and the Applicants to discuss possible methods for
                        adjusting the expense paid by ratepayers.

            b.          Company Owned Life Insurance. Both KIC and CURB state
                        that the income from company owned life insurance (COLI)
                        through June 2001 is actuarially determined and should
                        be included. (Dittmer direct, 92-93; Crane direct 53.)
                        The Commission finds that this additional revenue is
                        known with certainty and will adopt CURB's adjustment of
                        an increase in KGE's revenues of $1,410,909. (Crane
                        direct, Schedule 16-KGE.)

            c.          Pension Expense. KIC argues that pension expense should
                        be adjusted, based on actuary projections for 2001. This
                        adjustment is based on records of the Applicants and is
                        sufficiently definite to justify inclusion. The
                        adjustment decreases KGE's expenses by $2,047,032, and
                        decreases WRI's expenses by $3,938,700. (Dittmer direct,
                        93-96, KGE Update Schedule C-1, KPL Update Schedule C-
                        14.)
<PAGE>

                                      -36-


            d.          Postage. KIC acknowledges that the postage increase
                        outside of the test year is unavoidable and will be
                        incurred by the Applicants. (Dittmer direct, 102;
                        Transcript, 2454-55.) The Commission finds this expense
                        to be known and measurable. (Wages rebuttal, 15.)

            e.          Property Taxes. Staff proposed two property tax
                        adjustments. The first adjustment, which is not
                        contested by the Applicants, reflects the difference
                        between current actual property taxes billed to the
                        Applicants and property taxes included in the test year
                        cost of service. This adjustment decreases KGE's
                        property taxes by $2,044,541, and increases WRI's
                        property taxes by $1,552,658. The second adjustment
                        relates only to WRI and reverses the estimated property
                        taxes related to the new Gordon Evans units. Staff
                        states that this amount is not known and measurable at
                        this time and that WRI can request a surcharge under K.
                        S.A. 2000 Supp. 66-117(f) if there is an additional
                        increase. This adjustment decreases WRI's taxes by
                        $1,888,889. The Applicants argue that seeking a
                        surcharge under K.S.A. 2000 Supp. 66-117(f) would be
                        confusing to customers and that the full property tax
                        amount sought should be included. (Rohrer direct, 12-13,
                        revised KGE and KPL Schedules B-3, Adjustment 17; Wages
                        rebuttal, 7-11; Transcript, 2237-38.) The Commission
                        finds Staff's position to be reasonable. The estimated
                        tax amount is uncertain because the applicable mill levy
                        has not yet been determined. The parties agree that
                        there is a statutory remedy for the Applicants if an
                        increase in WRI's property taxes makes a surcharge
                        necessary. The Commission adopts both of Staff's
                        property tax adjustments.

            98. The Commission finds that the following requested adjustments
have not been sufficiently supported by the evidence and rules in favor of the
Applicants:

            a.          KIC's adjustment to reject the increase in liability
                        insurance for directors and officers. (Dittmer direct,
                        96-97.)

            b.          Adjustments by CURB and KIC to disallow costs relating
                        to new administrative positions. (Crane direct, 47-48;
                        Dittmer direct, 86-88.) [The Commission has previously
                        accepted Staff's pro forma salary adjustment.]

            c.          CURB's adjustment concerning the cubicle size of leased
                        office space. (Ostrander direct, 46-49.)

            99. Several parties suggest that the Commission exclude all of the
charitable donations made by the Applicants. The controlling statute, K.S.A.
2000 Supp. 66-101(f), permits the Commission to disallow up to 50% of donations.
Consistent with this, the Applicants only requested recovery of 50% of their
donations. (Wages rebuttal, 5.) It appears that the Applicants are requesting
recovery of half of their total donations, with none of the donations assigned
to wholesale customers or non-regulated operations. (See Crane direct, 57.)
<PAGE>

                                      -37-


The Commission finds that it is necessary to make these allocations and then
appropriate to disallow 50% of the amount that is properly assigned to retail
electric customers. To accomplish this, the Commission will begin with the total
contribution amounts of $792,810 for KGE and $889,806 for WRI. (KGE Application,
Section 9, Schedule 9-C, Adjustment 9; WRI Application, Section 9, Schedule 9-C,
Adjustment 8.) To these amounts, the Commission will apply Staff's residual
allocation factor of 62.5% for regulated activities (see Proctor direct, 63),
and the retail percentage based on FERC Account 930.2 [98.0005% for KGE;
93.3583% for WRI.] The resulting numbers are the amount of total donations that
should be attributed to retail customers. The Commission disallows 50% of these
amounts, and will permit a donations expense of $242,799 for KGE, and a
donations expense of $259,596 for WRI. The Applicants included donations of
$396,405 for KGE and $444,903 for WRI. The Commission's adjustment to the filed
amounts results in a decrease of $153,606 for KGE, and a decrease of $185,307
for WRI. The Commission does not accept KIC's request that the Applicants be
required to give recognition to ratepayers when making contributions. The
Commission also does not accept the argument that it is improper for donations
to be made through a charitable foundation.

            100. Wichita requests an adjustment related to an apparently large
expense entry made in FERC Account 557. The Applicants' response is that this
involves hedging activities and that the entries in Account 557 for expenses are
offset by entries in Account 451 for revenues. (Suess direct, 18-20; Wages
rebuttal, 16; Transcript, 1466-75, 2580-86, 2928-32; Applicants' Exhibit 22.)
The Commission finds the explanation of the Applicants to be reasonable and
denies the adjustment.

            101. The Applicants' power marketing activities were discussed
extensively during the proceeding. The Applicants maintain that there are no
power marketing expenses in the rate case and that profits from asset-based
transactions are credited to retail customers. The Applicants state that
ratepayers should not be subjected to the risks and potential losses from
non-asset based transactions. In their Briefs, Topeka, KIC, Wichita and CURB
raise questions about the practices of the power marketing group and the manner
in which transactions are classified. They argue that the power marketing group
benefits from its association with the regulated
<PAGE>

                                      -38-


utility and that there should be some recognition of the trading profits from
non-asset based transactions in rates. The Commission has determined that a
sharing of profits without a sharing of losses is not fair, and that ratepayers
should not be at risk for potential losses. Accordingly, no adjustment will be
made. However, the Commission also finds that information about the operations
of the power marketing group was not sufficiently clear and that further review
is warranted. This is a difficult area in which there is interaction between
regulated and non-regulated activities. The Commission agrees with the witness
for KIC that the lack of an audit trail and the complexity of these transactions
are causes for concern. (Transcript 2450-51.) The Commission therefore orders
that the Applicants file, within 30 days of the date of this Order, their
written procedures for differentiating, classifying and tracking asset and non-
asset based transactions. The Commission further orders that there be a thorough
review of the Applicants' power trading activities and procedures by Staff or by
an independent third-party approved by Staff. Definite plans for the timing and
details of this review are to be formalized on or before December 17, 2001.

            102. The Applicant used a three-year average ratio when calculating
their bad debt expense. They state that the test year amount was unusually low
and has increased tremendously, in part due to joint billing of electricity and
natural gas services. The Applicants maintain that the benefits to customers
from joint billing far outweigh the bad debt expense that would be incurred in
this case. Staff and KIC recommend that the expense be based on the Applicants'
actual test year bad debt expense. (Williams rebuttal, 2-8; Rohrer direct,
13-14; Dittmer direct, 88-90; Transcript, 1495, 1508.) Although the Commission
does have some concern about electricity customers paying an expense related to
high natural gas prices (Transcript, 2239-40), the Commission has concluded that
bad debts for the electric utilities will, in fact, be higher than those shown
in the test year, and that the Applicants' three-year average ratio is
reasonable.

            103. Reserve normalization concerns accounts for injuries and
damages to third parties, environmental costs, and property insurance associated
with storm damages. For their reserve normalization adjustment, the Applicants
used a three-year average. They argue that the three-year average is the method
<PAGE>

                                      -39-


generally used. (Wages rebuttal, 14.) Staff argues that a five-year average
should be used because it will provide a more level and accurate historical
picture. (Kuzelka direct, 17-18.) Staff's five-year data shows large variance in
the charges to this area over the years. The Commission concurs with Staff's
recommendation and finds that using five years provides a better view of
normalized expenses. The effect of this adjustment is to decrease KGE's expenses
by $1,281,016, and to increase WRI's expenses by $147,313. (Kuzelka direct,
Exhibit RLK-7.)

            104. A number of adjustments relating to employee compensation and
benefits have been proposed. (Rohrer direct, 17-24; Ostrander direct, 51-57.)
The Commission does not accept Staff's adjustments relating to legal, tax, and
financial services, severance pay, real estate bonuses, or short term incentives
and bonuses. The Commission believes that the structure of the total
compensation package is largely a matter for the Applicants' management to
decide. However, as discussed below, the Commission does find that adjustments
to the long-term benefits of stock options and restricted share units (RSUs)
should be made.

            105. The Applicants included expenses relating to benefits changes
of $3,035,784 for KGE and $5,558,264 for WRI. These expenses were to terminate a
stock options program and to replace it with a RSU program. (KGE and WRI
Applications, Section 9, Schedule 9-C, Adjustment 3.) CURB contends that some of
these expenses are not known and measurable, that other expenses are for
one-time, non-recurring payments, that some of the expenses were based on
estimated instead of actual data, that the change to amortization over 3-4 years
instead of 9 years is inappropriate, and that a greater percentage of these
expenses (50%) should be allocated to non-regulated operations. The total CURB
adjustment is a decrease in expenses of $5,518,979. (Ostrander direct, 51-57,
Attachments BCO-2 and BCO-12.) The witness for the Applicants on these
adjustments did not address CURB's issues in rebuttal testimony (see Wages
rebuttal), and the CURB witness was not cross-examined in this area.
(Transcript, 2466-91.)

            106. The Commission finds that the Applicants have made no serious
effort to oppose CURB's stock option and RSU adjustments. The adjustments are
supported by data request responses from the
<PAGE>

                                      -40-


Applicants. The Commission accepts CURB's adjustments. When allocated between
KGE and WRI the result is a decrease in expenses of $1,910,558 for KGE, and a
decrease in expenses of $3,332,369 for WRI.

            107. There was no Wolf Creek refueling outage during the test year.
The Applicants, Staff, CURB, KIC and Wichita all provided recommendations as to
what the length of the outage should be, what units would replace the lost
generation, whether natural gas fired generation would need to be used, whether
an adjustment for higher coal costs should be made, and whether there should be
an adjustment for natural gas prices. (Harrison direct, 6-10; Hodson rebuttal,
2-10; Hodson reply, 1-4; Holloway direct, 28-36; Holloway cross, 1-5; Crane
direct, 50-53; Dittmer direct, 54-58; Suess direct, 5-15.) This fuel
normalization adjustment is designed to reflect what would happen during a
standard outage. The Commission has considered the arguments of the parties and
concludes that this is best accomplished by Staff's adjustment. Staff relied
upon the actual past performance and historical availability of plants during a
Wolf Creek outage when formulating its adjustment. Staff did not assume optimal
operating conditions, as the Applicants suggest, but based its recommendation
directly on empirical facts. The Commission adopts Staff's adjustment, which
results in a decrease in KGE's expenses of $8,679,018, and a decrease in WRI's
expenses of $2,116,120. (revised KGE and KPL Schedules B-3, Adjustment 7.)

            108. The Applicants did not oppose Staff's proposal to use the Henry
Hub 36-month natural gas futures price strip to set natural gas costs (Cita
direct, 8-12; Transcript, 2269-70; Mathis rebuttal, 22), and the Commission
accepts this method. Wichita's suggestion that a fuel cost recovery mechanism be
reinstated is rejected. (Corrigan direct, 31-32.)

            109. In 1997, in Docket No. 97-WSRG-486-MER, the Commission approved
the joint application of WRI, ONEOK, Inc., and WAI, Inc. to approve various
transactions and transfers related to the merger of their natural gas
operations. The Order in Docket No. 97-WSRG-486-MER found that evidence in the
case supported the potential for administrative costs resulting from the
alliance of WRI and ONEOK to flow back
<PAGE>

                                      -41-


to WRI's electric customers. The potential amount of costs shown by the evidence
was in a range of $4.6 million to $5.2 million. To ensure that there was no
detriment to WRI's electric customers from the ONEOK relationship, the
Commission ruled that WRI would have the burden of showing in its next rate case
that these potential costs have been offset, in whole or in part, by benefits
attributable to the WRI / ONEOK alliance. (Kuzelka Direct Testimony, Exhs. RLK-2
and RLK-2.)

            110. The Applicants presented testimony that there had been over
$5.4 million in savings resulting from the alliance. These savings were in 11
categories, with the largest amount ($4.2 million) attributable to the WRI/ONEOK
shared services agreement. (Harrison Direct Testimony, 12-19; Exh. KBH-2.) The
Applicants explained that the type of savings were generally caused by being
able to avoid the duplication of costs, achieving volume discounts, or having
one vendor for both entities. (Transcript, 1142-43.)

            111. Staff conducted discovery to attempt to verify the claimed
savings. Ultimately, Staff disputed the savings, arguing that the Applicants had
not met the burden of furnishing adequate supporting documentation to prove any
savings or to meet standard auditing guidelines. Staff stated that it would be
important to have historical baseline information in order to determine what
changed after the alliance. Staff also concluded that some of the amounts
submitted were simply not supported. Staff acknowledged that it was likely that
there were savings of some amount from the WRI/ONEOK alliance, but emphasized
that the burden was on the Applicants and they had not met it. (Kuzelka Direct
Testimony, 3-17; Transcript, 2282-2304.)

            112. Staff submitted an alternative position in case the Commission
determined that some savings should be recognized. Under the alternative, Staff
concluded that there was evidence of savings in 4 of the categories, totaling
$4,035,987. Staff recommended that only 50% of the savings be attributed to the
Applicants, and that savings of $2,017,090 be recognized. (Kuzelka Direct
Testimony, 9-17.)

            113. The Commission finds that the Applicants have not met the
burden of establishing the level of savings, but that it is undisputed that some
savings did result from the ONEOK relationship. In order to
<PAGE>

                                      -42-


properly establish savings, the Applicants would have needed to demonstrate
baseline costs and provide credible documentation to show savings from sources
outside of the utility. While this was not done, the Commission does not want to
ignore the acknowledged fact that there has been some level of savings, and will
adopt Staff's alternative savings estimate of $4,035,987. However, the
Commission does not accept Staff's recommendation to only consider 50% of the
savings because it is not supported by the Stipulation and Agreement or the
Order in Docket No. 97-WSRG-486-MER. The amount of necessary savings was
identified as $4,600,000 to $5,222,000. The difference between $4,600,000 and
the accepted level of savings ($4,035,987) is $564,013, and this amount is
imputed to the cost of service as an income statement adjustment. This
adjustment decreases KGE's expenses by $284,247, and decreases WRI's expenses by
$279,766.

            114. The primary allocation adjustment proposed concerns executive
compensation. The Applicants allocated 34% of the compensation for seven
executives to non-regulated activities, based on an average of the fixed time
allocations for the executives. (Transcript, 1688-91.) CURB initially adjusted
this to 50%, and then later increased the percentage to 60%. The 50% number was
based on CURB's review of corporate activities and was a weighted average of the
seven executive officers. The 60% number is based largely on a review of
aircraft logs. (Ostrander direct, 19-20; Attachment BCO-2; Ostrander
supplemental direct, 15.) Staff allocates the salaries and benefits for nine
corporate officers between regulated and unregulated operations. For eight of
the officers, Staff allocates 37.5% of their compensation to unregulated
operations. For the ninth officer (Douglas Lake), Staff allocates 100% to
unregulated operations. The 37.5% is Staff's residual allocation factor, and is
based on the percentage of WRI's investment and common equity in unregulated
operations. (Proctor direct, 13-15, 62-75; Exh. JMP-10, Sch. 1; Exh. JMP-9, Sch.
1.)

            115. The Commission must first comment on the deficiencies in the
Applicants' allocation evidence. There was a fundamental problem with the manner
in which Flaherty's review was designed. He simply looked at the allocation
process being used, asked whether it was consistent with the process designed to
be used originally, and evaluated whether the employees understood the process
and were properly implementing it.
<PAGE>

                                      -43-


(Flaherty direct, 4-6; Flaherty rebuttal, 5-8; Transcript, 1682-83, 1705, 1708.)
This does not answer the basic question before the Commission, which is whether
the allocations themselves are fair and reasonable. The Applicants focused on
whether the procedures were being understood and followed, not on whether the
procedures were the correct ones. The Commission finds that the Applicants'
testimony should be given only minimal weight because of this failure to address
the relevant issue.

            116. The Commission further notes several alarming aspects of the
allocation procedures. The allocation system was designed in 1992, prior to the
time when the Applicants expanded their operations out of the public utility
arena. The Applicants concede that their operations have changed significantly
since 1992. (Flaherty rebuttal, 5; Transcript, 1678-79, 1683-84, 1698.) The
Applicants' witness looked at broad cost categories and did not consider any
particular individual employees. (Transcript, 1686-90, 1695, 1705, 1802.) The
executive officers make an annual estimate of the proportion of time that will
be spent on regulated and non-regulated matters. No time sheets are kept.
(Transcript, 248.) Instead, the estimated fixed percentage is used. At the end
of the year, the executives can revisit the time allocations and make changes if
they desire. For rate case allocations , an average of the executives' fixed
time percentages was calculated, and this resulted in 34 % of the expenses being
allocated to non-regulated activities. (Transcript, 1691,1701-02, 1719.)
However, very few records or documentation of the process used to review and
evaluate the allocation procedures were retained. (Transcript, 1756-66.)

            117. A system that relies on an estimate made once a year, with no
formal attempt to verify the accuracy of that estimate, is woefully insufficient
to be used as a means of determining what expenses should be paid by ratepayers.
The Commission finds that the criticisms of the Applicants' allocation
methodology are valid. The Commission cannot stress too strongly the importance
of properly allocating costs. The Applicants have the obligation to provide
credible evidence to prove how time is spent before asking that ratepayers bear
the expenses. Ratepayers should not be at risk for paying expenses for
non-regulated activities. While the Applicants agree with this fundamental
premise in principle (Transcript, 287), their allocation procedures are clearly
<PAGE>

                                      -44-


inadequate to serve as a means of fairly allocating costs between regulated and
non-regulated operations. The current haphazard procedures for executive
allocations provide no assurance that electric customers are not paying costs
related to non-regulated businesses.

            118. The Commission finds that the existing allocation guidelines
and procedures for executives are so deficient as to require immediate remedial
action. Within 90 days of the date of this Order, the Applicants are to file
with the Commission a revised methodology for allocating costs relating to
executive compensation between regulated and non-regulated operations. The
methodology must include a reasonable process for allocating time and expenses
that is subject to verification by contemporaneous records and documents. The
Commission finds that this is essential to protect ratepayers from unjustified
charges and to ensure that expenses collected through rates are just and
reasonable.

            119. The Commission finds no rational basis for accepting the
Applicants' proposed 34% allocation percentage; however, the allocation between
regulated and non-regulated operations still must be determined as part of this
case. Evidence from Staff and CURB presents the Commission with two other
alternatives for allocating executive time and expenses. The Commission adopts
Staff's recommendation that 0% of Lake's time be allocated to regulated
activities. For the other executives, the Commission adopts Staff s 37.5%
allocation factor, finding that this was derived in a reasonable manner and
provides a basis for fairly allocating expenses. The Commission rejects the
Applicants' claim that Staff s allocation is in error because Staff began with a
number which had already taken allocations of 30% into account. Staff used the
pre-allocation figures, based on information received from the Applicants during
discovery. (Proctor direct, Exhibits JMP-9, 10 and 11.) The effect of these
adjustments is to decrease KGE's expenses by $292,488, and to decrease WRI's
expenses by $447,091.

            120. Several other allocation issues have been raised. The
Commission accepts CURB's adjustment to allocate 50% of Board of Directors' fees
to non-regulated activities. This adjustment decreases
<PAGE>

                                      -45-


total expenses by $303,394, and is allocated between KGE ($136,464) and WRI
($166,930). (Ostrander direct, 43-44; Attachment BCO-2.) The Commission finds
that CURB's requested adjustment relating to insurance costs was not
established, and does not accept it. (Ostrander direct, 44-45.) Similarly, the
Commission does not find a sufficient basis to extend CURB's executive
allocation to other corporate officers, or to change the reimbursement relating
to tax services, and denies those adjustments. (Ostrander direct, 39-42.) Both
Staff and CURB propose adjustments to outside services. (Proctor direct, 15,
62-75; Ostrander direct, 58-64.) The Commission accepts Staff's adjustment,
which is based on a review of invoices from vendors which provided consulting
and legal services to the Applicants. This adjustment decreases KGE's expenses
by $171,168, and decreases WRI's expenses by $1,589,304. (Exh. JMP-11, Sch. 1;
revised KGE and KPL Schedules B-3, Adjustment 3.)

            121. Staff and the Applicants have requested that the Commission
find that the ground lease payment by KPL to KGE is appropriate. (Harrison
direct, 3-4.; Holloway direct, 38-39; Staff Post-Hearing Brief, 36; Applicants'
Reply Brief, 42.) The Commission finds the lease payment to be reasonable. The
contract is currently pending in Docket No. 00-KG&E-1122-CON, and the Commission
will enter a separate order relating to the contract in that docket.

            122. Rate case expenses are generally amortized over a three-year
period, and the Commission will follow that practice in this case. (See Rohrer
direct, 24; Transcript, 2245-46.) An adjustment for rate case expense will be
made as soon as expenses have been determined.

            123. A final adjustment for current income taxes is necessary to
reflect the effect of the Commission's rulings. (Rohrer direct, 24.) This
adjustment decreases KGE's operating expenses by $7,788,533; and decreases WRI's
operating expenses by $13,085,528.
<PAGE>

                                      -46-


                                  OTHER ISSUES


            124. CURB suggests that the Commission review and upgrade its
process for monitoring affiliate transactions in light of the fact that many
utilities are becoming part of holding companies and affiliate transactions are
increasing. CURB requests annual reporting of affiliate transactions and that
utilities be required to demonstrate that the products or services could not
have been obtained from non-affiliated sources or performed by the utility
itself at a lower cost. CURB also asks the Commission to adopt policies related
to cost shifting, to require competitive bidding, and to adopt asymmetric
pricing standards. (Crane direct, 65-80; Brief, 53-61.)

            125. The Applicants argue that it would be inappropriate to consider
affiliate transaction standards and requirements in this rate proceeding, and
that any such standards should not be applied only to the Applicants. The
Applicants question whether such rules are necessary, but state that if the
Commission decides to consider this matter, it should be through a rulemaking
process in which all interested parties could participate.

            126. The Commission will not adopt CURB's request in this
proceeding. A review of affiliate transactions and related issues should be
conducted, but will be on a generic basis.

            127. Any adjustments or findings requested by the parties that are
not addressed above have not been adequately explained or supported and are not
adopted by the Commission.

                                     SUMMARY


            128. Pursuant to this Order, the capital structure for the
Applicants is 51.62% debt, 44.14% common equity, 0.90% preferred stock, and
3.34% accumulated deferred investment tax credits. The cost of long-term debt is
7.5062%; the return on equity is 11.02%; and the rate of return is 9.0836%. For
KGE, the rate base is $1,191,251,942, the required operating income is
$108,208,538, and the revenue requirement is a decrease of $41,222,163. For WRI,
the rate base is $1,057,249,109, the required operating income is $96,036,259,
<PAGE>

                                      -47-


and the revenue requirement is an increase of $18,470,583. The overall effect on
the Applicants is a revenue requirement decrease of $22,751,580. Attachments
summarizing these findings are attached. As determined in Docket No.
00-WSRE-855-COM, Orders No. 6 and 7, these rate changes are effective as of the
date of this Order, and will begin accruing with interest at a rate of 9.0836%
(the rate of return) as of the date of this Order.

                       PHASE II RATE DESIGN REQUIREMENTS

            129. The Commission established a bifurcated process for reviewing
the rates of the Applicants in Docket No. 00-WSRE-855-COM. This first proceeding
determines revenue requirements. There will then be a second filing by the
Applicants, in a new docket, for rate design purposes. This rate design filing
is to be made on or before September 20, 2001. The filing of any petitions for
reconsideration of this Order, or any appeal of this Order, will not delay the
deadline for the rate design filing. The Commission intends to commence its
consideration of the appropriate rate design for the Applicants in September of
2001, regardless of the status of this Order.

                  IT IS, THEREFORE, BY THE COMMISSION ORDERED THAT:

                  (A) These findings, conclusions and Attachments are the order
of the Commission.

                  (B) Revenue requirements are set on an interim basis, subject
to refund, as discussed in Paragraphs 8-14. The rates ordered above are
effective as of the date of this Order, and will begin accruing with interest as
of the date of this Order.

                  (C) On or before November 1, 2001, Staff is to initiate a
generic review of quality of service standards, through either a formal docket
or an administrative regulation process.

                  (D) Within 90 days of the date of this Order, the Applicants
are to meet with Staff to discuss arrangements for funding of FAS 106/112
through an external third party.
<PAGE>

                                      -48-


                  (D) The Applicants are to file, within 30 days of the date of
this Order, their written procedures for differentiating, classifying and
tracking asset and non-asset based transactions. A power marketing review by
Staff or by an independent third party approved by Staff is to be planned and
scheduled on or before December 17, 2001.

                  (E) The Applicants are to file revised allocation procedures
for Commission approval within 90 days of the date of this Order.

                  (F) The Applicants are to make a rate design filing, in a
separate docket, on or before September 20, 2001.

                  (G) A party may file a petition for reconsideration of this
Order within fifteen (15) days of the date of this Order. If service is by mail,
three (3) additional days may be added to the fifteen (15) day time limit to
petition for reconsideration.

                  (H) The Commission retains over the subject matter and parties
for the purpose of entering such further orders as it may deem necessary.

                  BY THE COMMISSION IT IS SO ORDERED.

                  Wine, Chr.; Claus, Com.; Moline, Com.

                  Dated:      7-25-2001
                              ---------

                                                          ORDER MAILED 7-25-2001
                                                          ----------------------
                                                          Jeffrey S. Wagaman
                                                          Executive Director

<TABLE>
<CAPTION>
                                                   ATTACHMENTS
                                                   -----------
<S>                                                <C>
Attachment 1                                       KGE revenue requirement and capital structure
Attachment 2                                       KGE rate base adjustments
Attachment 3                                       KGE income statement adjustments
Attachment 4                                       WRI revenue requirement and capital structure
Attachment 5                                       WRI rate base adjustments
Attachment 6                                       WRI income statement adjustments
Alphabetical Index
</TABLE>
<PAGE>

                                     -49-

<TABLE>
<CAPTION>
                                      INDEX
<S>                                                <C>
account 557                                        Paragraph 100
accumulated deferred income tax adjustment         Paragraphs 64-71, 92(c)
advertising                                        Paragraph 91
affiliate transactions                             Paragraphs 124-26
allocations                                        Paragraphs 15-17, 114-20
bad debt expense                                   Paragraph 102
benefits                                           Paragraphs 104-06
capital structure                                  Paragraphs 34-39
charitable donations                               Paragraph 99
company owned life insurance (COLI)                Paragraph 97(b)
corporate restructuring                            Paragraphs 8-14
cost of long-term debt                             Paragraphs 40-41
customer deposits                                  Paragraphs 80, 92(d)
depreciation                                       Paragraphs 22-33, 85
donations                                          Paragraph 99
employee compensation and benefits                 Paragraphs 104-06
environmental compliance projects                  Paragraphs 81-82
executive compensation                             Paragraphs 114-19
FAS 106/112 (post-retirement benefits)             Paragraphs 77-79
FERC Account 557                                   Paragraph 100
fuel normalization                                 Paragraphs 107-08
Gordon Evans units                                 Paragraphs 53-55, 61-62
income statement adjustments                       Paragraphs 88-123
interest synchronization                           Paragraphs 11-14
interim rates                                      Paragraph 14
KPL / KGE ground lease                             Paragraph 121
LaCygne sale/leaseback                             Paragraphs 72-76
long-term debt                                     Paragraphs 40-41
Murray Gill repair                                 Paragraph 86
natural gas prices                                 Paragraph 108
NEIL insurance distributions                       Paragraph 96
</TABLE>
<PAGE>

                                     -50-


<TABLE>
<S>                                                <C>
new generation units                               Paragraphs 52-62
off-system sales                                   Paragraphs 61-62, 92(b)
ONEOK savings                                      Paragraphs 109-13
outside services                                   Paragraphs 90(a) and (b), 120
pension expense                                    Paragraph 97(c)
postage                                            Paragraph 97(d)
power marketing                                    Paragraph 101
property taxes                                     Paragraph 97(e)
quality of service standards                       Paragraph 20
rate base adjustments                              Paragraphs 63-87
rate design filing                                 Paragraph 129
rate of return                                     Paragraphs 51
real estate bonuses                                Paragraph 104
required filings and actions                       Paragraphs 20, 60, 79, 97(a), 101, 118, 129
reserve normalization                              Paragraph 103
restricted share units / stock options             Paragraphs 105-06
restructuring                                      Paragraphs 8-14
return on equity                                   Paragraphs 42-50
revenue requirements                               Paragraph 18
settled issues                                     Paragraph 20
severance pay                                      Paragraph 104
Southwest Power Pool tariff                        Paragraph 97(a)
State Line purchased power agreement               Paragraphs 56-60
test year                                          Paragraph 19
tree trimming                                      Paragraphs 83, 92(e)
wholesale/retail allocations                       Paragraphs 15-17
Wichita municipalization                           Paragraph 95
Wolf Creek license renewal                         Paragraphs 29-31
Wolf Creek refueling outage                        Paragraphs 107-08
Y2K incentives                                     Paragraph 94
</TABLE>