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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8 -K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of Earliest Event Reported) July 25, 2001 (July 25, 2001)
WESTERN RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
KANSAS 1 -3523 48 -0290150
(State or Other Jurisdiction of (Commission File (IRS Employer
Incorporation) Number) Identification No.)
818 KANSAS AVENUE, TOPEKA, KANSAS 66612
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number Including Area Code (785) 575-6300
WESTERN RESOURCES, INC.
Item 5. Other Events
On July 25, 2001, the Kansas Corporation Commission issued an order reducing
Western Resources' combined electric rates by $22.7 million. The electric rates
of Western Resources' KPL division were increased by $18.5 million and the
electric rates of Kansas Gas and Electric Company were decreased by $41.2
million.
A copy of the press release issued by the Company today is attached hereto as an
exhibit and is incorporated by reference herein. Copies of the Kansas
Corporation Commission press release and order are also attached as exhibits
hereto.
Item 7. Financial Statements and Exhibits
(c) Exhibits
Exhibit 99.1 - Press Release issued by the Company dated July 25, 2001
Exhibit 99.2 - Press Release issued by the Kansas Corporation Commission
dated July 25, 2001
Exhibit 99.3 - Order of the Kansas Corporation Commission dated July 25,
2001
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Western Resources, Inc.
Date July 25, 2001 By /s/ James A. Martin
---------------------- -------------------------------
James A. Martin, Senior Vice President
and Treasurer
[COMPANY'S LOGO]
Media contact:
Kimberly N.
Gronniger
Phone: 785.575.1927
FAX: 785.575.6399
News@wr.com
Investor contact:
Carl A. Ricketts
Phone: 785.575.8424
FAX: 785.575.1774
Carl_ricketts@wr.com
Western resources RESPONDS TO KCC ORDER
TOPEKA, Kan., July 25, 2001 -- The Kansas Corporation Commission issued an
order today reducing Western Resources' electric rates by $22.7 million,
representing less than 2 percent of total revenues in year 2000. The rates of
the company's Kansas Gas and Electric Co. subsidiary were reduced by
approximately $41.2 million and the company's KPL division's rates were
increased by approximately $18.5 million.
The company is continuing to review the order and expects to meet with
Public Service Company of New Mexico to discuss the order in the near future.
Western Resources (NYSE: WR) is a consumer services company with interests
in monitored services and energy. The company has total assets of about $8
billion, including security company holdings through ownership of Protection One
(NYSE: POI) and Protection One Europe, which have more than 1.5 million security
customers. Its utilities, KPL and KGE, provide electric service to approximately
636,000 customers in Kansas. Through its ownership in ONEOK, Inc. (NYSE: OKE), a
Tulsa-based natural gas company, Western Resources has a 45 percent interest in
one of the largest natural gas distribution companies in the nation, serving
more than 1.4 million customers.
For more information about Western Resources and its operating companies,
visit us on the Internet at http://www.wr.com.
Forward-looking statements: Certain matters discussed in this news release
are "forward-looking statements." The Private Securities Litigation Reform Act
of 1995 has established that these statements qualify for safe harbors from
liability. Forward-looking statements may include words like we "believe,"
"anticipate," "expect" or words of similar meaning. Forward-looking statements
describe our future plans, objectives, expectations or goals. Such statements
address future events and conditions concerning capital expenditures, earnings,
liquidity and capital resources, litigation, rate and other regulatory matters,
including the pending rate cases and pending investigation by the Kansas
Corporation Commission of the proposed separation of Western Resources' electric
utility businesses from Westar Industries and matters related to our unregulated
businesses, possible corporate restructurings, mergers, acquisitions,
dispositions, compliance with debt covenants, changes in accounting requirements
and other accounting matters, interest and dividends, Protection One's financial
condition and its impact on our consolidated results, environmental matters,
changing weather, nuclear operations, ability to enter new markets successfully
and capitalize on growth opportunities in non-regulated businesses, events in
foreign markets in which investments have been made, and the overall economy of
our service area. What happens in each case could vary materially from what we
expect because of such things as electric utility deregulation, ongoing
municipal, state and federal activities, such as the Wichita municipalization
effort; future economic conditions; legislative and regulatory developments; the
proposed separation of Western Resources' electric utility businesses from
Westar Industries and the consummation of the acquisition of the electric
operations of Western Resources by Public Service Company of New Mexico;
regulatory and competitive markets; and other circumstances affecting
anticipated operations, sales and costs. See Risk Factors in our Annual Report
on Form 10-K for the year ended December 31, 2000, and our quarterly reports on
Form 10-Q and current reports on Form 8-K, filed with the Securities and
Exchange Commission, for additional information on these and other matters that
may affect our business and financial results. Western Resources disclaims any
obligation to update any forward-looking statements as a result of developments
occurring after the date of this news release.
Kansas Corporation Commission News Release July 25, 2001 KCC reduces Western Resources electric rates by $22.7 million KGE costs reduced $41.2 million - KPL costs increased $18.5 million TOPEKA, Kansas - The Kansas Corporation Commission (Commission) today issued an order reducing Western Resources' combined electric rates by $22.7 million. The $22.7 million rate reduction represents an overall revenue reduction of approximately 1.9 percent. Today's action will reduce KGE's revenue requirement by $41.2 million or approximately 6.6 percent, and increase KPL's revenue requirement by $18.5 million or approximately 3.3 percent. In a separate rate design proceeding the Commission will determine the actual rate impact to customers. "This decision was reached after much deliberation and study by the Commissioners and is based on the voluminous evidence presented by all parties throughout the rate case investigation," said KCC Chairman John Wine. "We are confident that it is a fair and balanced decision for consumers and the company." The rates set in this case are interim and subject to refund, until it is determined what will occur with the electric utility companies and there is a clear assurance that there will not be an electric utility in financial distress. The Commission said it will not assume in this proceeding what will happen with Western Resources' corporate structure and what the financial condition of the electric utility will be in the future. The Commission based its rate ruling on the utility structure as it exists today. In its order, the Commission reiterated its commitment to continue to work toward the elimination of the rate differential between KPL and KGE. The Commission said the rate differential between KPL and KGE must be viewed in light of the historical record dating back to the 1991 merger of the two companies. Over the course of time, customers of both companies have benefitted from the merger through rate reductions. Adjustments in this case, based on the individual company's costs to provide service, make significant progress in addressing the rate differential. The rate increase granted KPL in this case is attributable to the addition of 514 megawatts of new generation capacity necessary to provide electric service to KPL retail customers. The new generation capacity consists of three combustion turbine peaking units at the Gordon Evans facility and a purchase power agreement for capacity from the State Line facility. The-2- rate reduction to KGE is based upon several adjustments unique to the KGE service area, most notably, extension of the operating life of the Wolf Creek Generating Station. The extension provides a longer period for the recovery of Wolf Creek costs and consequently reduces rates. Customers will not see the effect of the rate changes until after the completion of the rate design phase. Today's order requires Western Resources to file its rate design for all customer classes by September 20, 2001. The Commission allowed a Retum on Equity (ROE) of 11.02 percent and a Rate of Return (ROR) of 9.08 percent. The ROE is the amount of money companies have the opportunity to earn on its common equity provided by stockholders and the ROR is the combined cost of debt and equity used to finance assets. The Commission further ordered Western Resources to submit filings and take corrective action in several areas including: within 90 days file revised guidelines and procedures for allocating executives' time and expenses between regulated and non-regulated operations, and within 30 days file procedures for classifying and tracking power marketing activities and transactions. Background On November 27, 2000, Western Resources requested a $151 million rate increase. Western Resources' KPL division and Kansas Gas and Electric Company filed applications with the Kansas Corporation Commission requesting annual increases in retail electric rates of $93 million or approximately 19 percent for KPL customers and $58 million or approximately 10 percent for KGE customers. The companies requested a ROE of 12.75 percent and an ROR of 10.27 percent. In the companies' applications, Western Resources said the increase for both KPL and KGE was necessary to recover increased operating and maintenance costs, increases in the cost of fuel for its power plants, and to attract capital and earn an adequate return on equity to protect their financial integrity. In addition, the companies said the KPL increase was necessary to recover KPL's investment in new generating facilities needed to meet growing customer demand for electricity. On April 6, 2001, Commission staff recommended a combined company rate decrease of $91.7 million. This represented a rate decrease for KGE of approximately $92 million and a rate increase of $262,072 for KPL. Staff also recommended a ROE of 10.40 percent and a ROR of 8.6 percent. -3- In April, public hearings were held in Topeka, Wichita, Salina and Pittsburgh providing an opportunity for customers to present testimony on the rate case to the Commission. A technical evidentiary hearing was held at the Commission's Topeka offices from May 17, 2001 through June 4, 2001. Western Resources, through KPL and KGE, provides retail electric service to approximately 635,000 customers. KPL serves approximately 345,000 customers in central and northeast Kansas and KGE serves approximately 290,000 customers in central and southeast Kansas. KPL and KGE also provide wholesale electric service and transmission service to numerous municipalities and electric cooperatives in Kansas. Release No. 01-13 Docket No. 01-WSRE-436-RTS
THE STATE CORPORATION COMMISSION
OF THE STATE OF KANSAS
Before Commissioners: John Wine, Chair
Cynthia L. Claus
Brian J. Moline
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. )
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.
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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.
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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.
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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
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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.)
-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
-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 Appli-
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cants 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
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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.
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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
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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.)
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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.
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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.)
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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
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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
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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
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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
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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
Ap-
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plicants 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.
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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.
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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
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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 mil-
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lion. 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.)
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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
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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
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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,P.P. 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
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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
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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.
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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.
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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.
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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.)
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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 di-
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rect, 9-10; KGE revised Schedule B-3, Adjustment 12, and KPL revised
Schedule B-3, Adjustment 14.)
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.
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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.)
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.
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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 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 adjust-
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ment 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.)
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
do-
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nations. (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.) 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,
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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 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.
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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
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.)
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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 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
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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 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.)
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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 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 sim-
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ply 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. (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
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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 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.
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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 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.
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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,
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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.
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(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
ATTACHMENTS
Attachment 1 KGE revenue requirement and capital structure
Attachment 2 KGE rate base adjustments
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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
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INDEX
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
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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