UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Amendment No. 2 to
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to _________
Commission File Number 1-3523
Western Resources, Inc.
(Exact name of registrant as specified in its charter)
Kansas 48-0290150
------ ----------
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification Number)
818 South Kansas Avenue
Topeka, Kansas 66612
(785) 575-6300
(Address, including zip code and telephone number, including area code, of
registrant's principal executive offices)
-------------------------------------
Securities registered pursuant to section 12(b) of the Act:
Name of each exchange
Title of Each Class on which registered
------------------- -----------------------
Common Stock, par value $5.00 per share New York Stock Exchange
Securities registered pursuant to section 12(g) of the Act:
Preferred Stock, 4-1/2% Series, $100 par value
----------------------------------------------
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant was approximately $1,239,059,619 at March
14, 2002.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
Class Outstanding at March 14, 2002
----- -----------------------------
Common Stock, par value $5.00 per share 71,415,540 Shares
Documents Incorporated by Reference: None.
2
TABLE OF CONTENTS
Page
----
PART I
Item 1. Business.......................................................... 5
Item 2. Properties........................................................ 25
Item 3. Legal Proceedings................................................. 27
Item 4. Submission of Matters to a Vote of Security Holders............... 27
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters........................................................... 28
Item 6. Selected Financial Data........................................... 29
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................. 30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........ 60
Item 8. Financial Statements and Supplementary Data....................... 61
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................. 111
PART III
Item 10. Directors and Executive Officers of the Registrant................ 112
Item 11. Executive Compensation............................................ 114
Item 12. Security Ownership of Certain Beneficial Owners and Management.... 123
Item 13. Certain Relationships and Related Transactions.................... 125
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K... 128
Signatures................................................................. 133
3
FORWARD-LOOKING STATEMENTS
Certain matters discussed in this Annual Report on Form 10-K are
"forward-looking statements." The Private Securities Litigation Reform Act of
1995 has established that these statements qualify for safe harbors from
liability. Forward-looking statements may include words like we "believe,"
"anticipate," "expect," "plan," "will," "may," "could," "estimate," "intend" or
words of similar meaning. Forward-looking statements describe our future plans,
objectives, expectations or goals. Such statements address future events and
conditions concerning:
. capital expenditures,
. earnings,
. liquidity and capital resources,
. litigation,
. possible corporate restructurings, mergers, acquisitions and
dispositions,
. compliance with debt and other restrictive covenants,
. interest and dividends,
. Protection One, Inc.'s financial condition and its impact on our
consolidated results,
. impairment charges that will be expensed during 2002,
. environmental matters,
. nuclear operations,
. ability to enter new markets successfully and capitalize on growth
opportunities in non-regulated businesses,
. events in foreign markets in which investments have been made and
. the overall economy of our service area.
What happens in each case could vary materially from what we expect
because of such things as:
. electric utility deregulation,
. ongoing municipal, state and federal activities, such as the Wichita
municipalization effort,
. future economic conditions,
. changes in accounting requirements and other accounting matters,
. changing weather,
. rate and other regulatory matters, including the impact of the order
to reduce our rates issued on July 25, 2001 by the Kansas
Corporation Commission and the impact of the Kansas Corporation
Commission's order issued July 20, 2001 and related proceedings,
with respect to the proposed separation of Western Resources, Inc.'s
electric utility businesses from Westar Industries, Inc.,
. the impact on our service territory of the September 11, 2001
terrorist attacks,
. the impact of Enron Corp.'s bankruptcy on the market for trading
wholesale electricity,
. political, legislative and regulatory developments,
. amendments or revisions to our current business and financial plans,
. the consummation of the acquisition of the electric operations of
Western Resources, Inc. by Public Service Company of New Mexico and
related litigation,
. regulatory, legislative and judicial actions,
. regulated and competitive markets and
. other circumstances affecting anticipated operations, sales and
costs.
These lists are not all-inclusive because it is not possible to predict
all possible factors.
See "Item 1. Business -- Risk Factors" for additional information on
matters that could impact our expectations. Any forward-looking statement speaks
only as of the date such statement was made, and we do not undertake any
obligation to update any forward-looking statement to reflect events or
circumstances after the date on which such statement was made.
4
PART I
ITEM 1. BUSINESS
GENERAL
Western Resources, Inc. is a publicly traded consumer services company
incorporated in 1924 in the State of Kansas. Unless the context otherwise
indicates, all references in this Annual Report on Form 10-K to "the company,"
"Western Resources," "we," "us," "our" or similar words are to Western
Resources, Inc. and its consolidated subsidiaries. We provide electric
generation, transmission and distribution services to approximately 640,000
customers in Kansas and monitored security services to over 1.2 million
customers in North America and Europe. ONEOK, Inc. (ONEOK), in which we have an
approximate 45% ownership interest, provides natural gas transmission and
distribution services to approximately 1.4 million customers in Oklahoma and
Kansas. Our corporate headquarters are located at 818 South Kansas Avenue,
Topeka, Kansas 66612.
We and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary,
provide rate regulated electric service using the name Westar Energy. KGE owns
47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company
for Wolf Creek Generating Station (Wolf Creek).
Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary,
owns our interests in Protection One, Inc. (Protection One), Protection One
Europe, ONEOK, Inc. and other non-utility businesses. Protection One, a publicly
traded, approximately 87%-owned subsidiary, and Protection One Europe provide
monitored security services. Protection One Europe refers collectively to
Protection One International, Inc., a wholly owned subsidiary of Westar
Industries, and its subsidiaries, including a French subsidiary in which it owns
approximately a 99.8% interest.
SIGNIFICANT BUSINESS DEVELOPMENTS
PNM Transaction
---------------
On November 8, 2000, we entered into an agreement with Public Service
Company of New Mexico (PNM), pursuant to which PNM would acquire our electric
utility businesses in a tax-free stock-for-stock merger. Under the terms of the
agreement, both PNM and we are to become subsidiaries of a new holding company,
subject to customary closing conditions including regulatory and shareholder
approvals. Immediately prior to closing, all of the Westar Industries common
stock we own would be distributed to our shareholders in exchange for a portion
of their Western Resources common stock. At the same time we entered into the
agreement with PNM, we and Westar Industries entered into an Asset Allocation
and Separation Agreement which, among other things, provided for this split-off
and related matters.
On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court
of the State of New York. The lawsuit seeks, among other things, declaratory
judgment that PNM is not obligated to proceed with the proposed merger based in
part upon the Kansas Corporation Commission (KCC) orders discussed below and
other KCC orders reducing rates for our electric utility business. PNM believes
the orders constitute a material adverse effect and make the condition that the
split-off of Westar Industries occur prior to closing incapable of satisfaction.
PNM also seeks unspecified monetary damages for breach of representation.
On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court
of the State of New York. The lawsuit seeks substantial damages for PNM's breach
of the merger agreement providing for PNM's purchase of our electric utility
operations and for PNM's breach of its duty of good faith and fair dealing. In
addition, we filed a motion to dismiss or stay the declaratory judgment action
previously filed by PNM seeking a declaratory judgment that PNM has no further
obligations under the merger agreement.
On January 7, 2002, PNM sent a letter to us purporting to terminate the
merger in accordance with the terms of the merger agreement. We have notified
PNM that we believe the purported termination of the merger agreement
5
was ineffective and that PNM remains obligated to perform thereunder. We intend
to contest PNM's purported termination of the merger agreement. However, based
upon PNM's actions and the related uncertainties, we believe the closing of the
proposed merger is not likely.
KCC Rate Cases
--------------
On November 27, 2000, we and KGE filed applications with the KCC for an
increase in retail rates. On July 25 and September 5, 2001, the KCC issued
orders that reduced our combined electric rates by $15.7 million. We appealed
these orders to the Kansas Court of Appeals, but the KCC orders were upheld. We
are evaluating whether to appeal the decision to the Kansas Supreme Court. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Summary of Significant Items -- KCC Rate Cases" for further
discussion.
KCC Proceedings and Orders
--------------------------
The merger with PNM contemplated the completion of a rights offering for
shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an
investigation of the proposed separation of our electric utility businesses from
our non-utility businesses, including the rights offering, and other aspects of
our unregulated businesses. The order opening the investigation indicated that
the investigation would focus on whether the separation and other transactions
involving our unregulated businesses are consistent with our obligation to
provide efficient and sufficient electric service at just and reasonable rates
to our electric utility customers. The KCC staff was directed to investigate,
among other matters, the basis for and the effect of the Asset Allocation and
Separation Agreement we entered into with Westar Industries in connection with
the proposed separation and the intercompany payable owed by us to Westar
Industries, the separation of Westar Industries, the effect of the business
difficulties faced by our unregulated businesses and whether they should
continue to be affiliated with our electric utility business, and our present
and prospective capital structures. On May 22, 2001, the KCC issued an order
nullifying the Asset Allocation and Separation Agreement, prohibiting Westar
Industries and us from taking any action to complete the rights offering for
common stock of Westar Industries, which was to be a first step in the
separation, and scheduling a hearing to consider whether to make the order
permanent.
On July 20, 2001, the KCC issued an order that, among other things: (1)
confirmed its May 22, 2001 order prohibiting us and Westar Industries from
taking any action to complete the proposed rights offering and nullifying the
Asset Allocation and Separation Agreement; (2) directed us and Westar Industries
not to take any action or enter into any agreement not related to normal utility
operations that would directly or indirectly increase the share of debt in our
capital structure applicable to our electric utility operations, which has the
effect of prohibiting us from borrowing to make a loan or capital contribution
to Westar Industries; and (3) directed us to present a financial plan consistent
with parameters established by the KCC's order to restore financial health,
achieve a balanced capital structure and protect ratepayers from the risks of
our non-utility businesses. In its order, the KCC also acknowledged that we are
presently operating efficiently and at reasonable cost and stated that it was
not disapproving the PNM transaction or a split-off of Westar Industries. We
appealed the orders issued by the KCC to the District Court of Shawnee County,
Kansas. On February 5, 2002, the District Court issued a decision finding that
the KCC orders were not final orders and that the District Court lacked
jurisdiction to consider the appeal. Accordingly, the matter was remanded to the
KCC for review of the financial plan.
On February 11, 2002, the KCC issued an order primarily related to
procedural matters for the review of the financial plan, as discussed below. In
addition, the order required that we and the KCC staff make filings addressing
whether the filing of applications by us and KGE at the Federal Energy
Regulatory Commission (FERC), seeking renewal of existing borrowing authority,
violated the July 20, 2001 KCC order directing that we not increase the share of
debt in our capital structure applicable to our electric utility operations. The
KCC staff subsequently filed comments asserting that the refinancing of existing
indebtedness with new indebtedness secured by utility assets would in certain
circumstances violate the July 20, 2001 KCC order. The KCC filed a motion to
intervene in the proceeding at FERC asserting the same position. We are unable
to predict whether the KCC will adopt the KCC staff position, the extent to
which FERC will incorporate the KCC position in orders renewing our borrowing
authority, or the impact of the adoption of the KCC staff position, if that
occurs, on our ability to refinance
6
indebtedness maturing in the next several years. Our inability to refinance
existing indebtedness on a secured basis would likely increase our borrowing
costs and adversely affect our results of operations.
The Financial Plan
------------------
The July 20, 2001 KCC order directed us to present a financial plan to the
KCC. We presented a financial plan to the KCC on November 6, 2001, which we
amended on January 29, 2002. The principal objective of the financial plan is to
reduce our total debt as calculated by the KCC to approximately $1.8 billion, a
reduction of approximately $1.2 billion. The financial plan contemplates that we
will proceed with a rights offering and that, in the event that the PNM merger
and related split-off do not close, we will use our best efforts to sell our
share of Westar Industries common stock, or shares of our common stock, upon the
occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to
review the financial plan. We are unable to predict whether or not the KCC will
approve the financial plan or what other action with respect to the financial
plan the KCC may take.
The financial plan provides that:
. Westar Industries will use its best efforts to sell at least 4.14
million shares of its common stock, representing approximately 5.1%
of its outstanding shares, but no more than the number of shares of
its common stock (approximately 19.13 million shares) representing
19.9% of its outstanding shares. After the offering, we would
continue to own 77.0 million shares representing between 80.1% and
94.9% of Westar Industries' outstanding shares. The offering will
remain open for no less than 45 calendar days.
. In the rights offering, each of our shareholders will receive the
right to purchase one share of Westar Industries' common stock for
every three shares of our stock held on the record date of the
offering. There will be no over-subscription privilege in the
offering. However, each shareholder participating in the offering
will be issued, with respect to each right exercised in the
offering, a warrant to purchase from Westar Industries two shares of
its common stock at the subscription price in the offering, subject
to proration so that in no event will we hold less than 80.1% of
Westar Industries' outstanding shares. This right will be
exercisable at any time in the 30-day period preceding January 31,
2003.
. So long as we and Westar Industries are tax consolidated, Westar
Industries' common stock sold in the offering will have one vote per
share and Westar Industries common stock held by us will have 10
votes per share. Any shares sold by us will automatically convert to
shares with one vote per share.
. The exercise price in the offering will be a fixed price determined
on the day the offer is mailed to shareholders by calculating the
"Westar Industries Valuation" as set forth in an exhibit to the plan
and then applying a 10% initial public offering discount.
. Westar Industries will have a rescission right through December 31,
2002. This will give Westar Industries the right to repurchase the
shares sold in the rights offering at a price equal to the greater
of (i) 1.05 times the exercise price, or (ii) the market price at
the time of the repurchase offer. The warrants issued to
participating shareholders in the offering will expire if the
rescission right is exercised. We would not be able to sell any
additional shares prior to the expiration of the rescission period.
. The proceeds from the offering (or any other subsequent sale of
stock by Westar Industries) and any dividends from the ONEOK common
or convertible preferred stock not used in Westar Industries'
business or previously committed will be used to purchase in the
market our or KGE's currently outstanding debt securities. On
February 10, 2003, such debt securities and the balance, if any, of
our intercompany payable with Westar Industries will be converted
into our common stock at the average trading price for the 20 days
prior to conversion, but in no event less than $24 per share.
However, if the PNM transaction is not terminated, such funds and
the intercompany payable will be transferred by us to Westar
Industries to purchase 7.5% Western Resources convertible preferred
stock, convertible into our common stock at $30 per share, as
provided in the PNM merger agreement. Prior to tax
7
deconsolidation, Westar Industries cannot receive any cash dividends
from us, but will instead reinvest those dividends in additional
shares of our common stock. Dividends on the convertible preferred
stock will be payable in additional preferred shares rather than
cash. Westar Industries will use interest received on our and KGE
debt securities it purchases as provided above to purchase
additional debt securities.
. If the PNM transaction is not terminated, the amount of our
convertible preferred stock purchased by Westar Industries will not
exceed $291 million. Westar Industries will continue to own our
common stock it currently owns. Westar Industries will retain its
option to purchase Westar Generating, Inc., a wholly owned
subsidiary of ours, which owns an interest in the State Line
Facility (see "Item 2. Properties" for a description of this
facility and "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Other Information
-- Related Party Transactions" for a discussion of this purchase
option).
. Westar Industries will not vote any of our common stock it owns as
long as we are tax consolidated.
. Westar Industries will adopt a "poison pill" that will restrict
ownership in it to 20% of the shares not owned by us.
. The rights offering and subsequent sale of Westar Industries' shares
by us pursuant to the plan do not constitute a change in control for
our employees under the terms of existing agreements and no
agreements will be executed which include a provision under which
the offering and sale of Westar Industries' shares by us pursuant to
the plan would constitute a change in control.
. We will not sell more than 19.9% of Westar Industries unless we have
$1.8 billion or less in short- and long-term debt and all of our and
KGE's first mortgage bonds are rated investment grade.
. In the event Westar Industries' common stock trades for 45
consecutive trading days at a price that is 15% above the price
necessary to reduce our short- and long-term debt to an amount less
than $1.8 billion (as measured at the end of the immediately
preceding fiscal quarter), we will be required to use our best
efforts to sell enough shares in Westar Industries, or us, or a
combination of both (at our option), to reduce debt to $1.8 billion.
However, in no event shall this obligation be triggered prior to
February 1, 2003, unless the PNM transaction is terminated prior to
that date. Furthermore, on each annual anniversary of the closing of
the rights offering, the amount of debt used to determine whether
our obligation has been triggered will increase by $100 million.
. We agree to reduce our total debt by at least $100 million per year
each year following the completion of the offering until the
separation is consummated.
. Our board of directors will have at least a majority of independent
directors following the separation.
Impairment Charge Pursuant to New Accounting Rules
--------------------------------------------------
Effective January 1, 2002, we adopted Statement of Financial Accounting
Standard (SFAS) No. 142, "Accounting for Goodwill and Other Intangible Assets,"
and SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived
Assets," which together establish new standards for accounting for goodwill and
other long-lived assets. Pursuant to these new standards, we will record an
impairment charge to write down goodwill and customer accounts to their
estimated fair values in the first quarter of 2002. The amount of this charge,
net of tax, will be approximately $653.7 million, of which $464.2 million is
related to goodwill and $189.5 million is related to customer accounts. For
further information on the impairment charge, see "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Summary of Significant Items -- Impairment Charge Pursuant to New Accounting
Rules."
8
Ice Storm
---------
In late January 2002, a severe ice storm swept through our utility service
area causing extensive damage and loss of power to numerous customers. We
estimate storm restoration costs could run as high as $25 million. On March 13,
2002, we filed an application for an accounting authority order with the KCC
requesting that we be allowed to accumulate and defer for future recovery costs
related to storm restoration. We cannot predict whether the KCC will approve our
application.
ELECTRIC UTILITY OPERATIONS
General
-------
We supply electric energy at retail to approximately 640,000 customers in
Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina
and Hutchinson. We also supply electric energy at wholesale to the electric
distribution systems of 63 Kansas cities and 4 rural electric cooperatives. We
have contracts for the sale, purchase or exchange of wholesale electricity with
other utilities. In addition, we have power marketing operations which purchase
and sell electricity in areas outside of our historical marketing territory.
Our electric sales for the years ended December 31, 2001, 2000 and 1999
were as follows:
2001 2000 1999
---------- ---------- ----------
(In Thousands)
Residential .......................... $ 419,492 $ 452,674 $ 407,371
Commercial ........................... 380,277 367,367 356,314
Industrial ........................... 244,392 252,243 251,391
Wholesale and Interchange ............ 233,129 214,721 174,895
Power Marketing ...................... 408,242 457,178 190,101
System Marketing ..................... 32,192 35,321 3,320
Other ................................ 50,669 49,629 46,306
---------- ---------- ----------
Total ........................... $1,768,393 $1,829,133 $1,429,698
========== ========== ==========
The following table reflects electric sales volumes, as measured by
megawatt hours (MWh), for the years ended December 31, 2001, 2000 and 1999. No
amounts are included for power marketing and system marketing sales because
these sales are not based on electricity we generate.
2001 2000 1999
------ ------ ------
(Thousands of MWh)
Residential .......................... 5,755 6,222 5,551
Commercial ........................... 6,742 6,485 6,202
Industrial ........................... 5,617 5,820 5,743
Wholesale and Interchange ............ 7,547 6,892 5,617
Other ................................ 107 108 108
------ ------ ------
Total ........................... 25,768 25,527 23,221
====== ====== ======
Generation Capacity
-------------------
The aggregate net generating capacity of our system is presently 5,947
megawatts (MW). The system has interests in 21 fossil-fuel steam generating
units, one combined cycle steam generating unit, one nuclear generating unit,
ten combustion peaking turbines, two combined cycle combustion turbines, two
diesel generators and two wind generators.
Our aggregate 2001 peak system net load of 4,468 MW occurred on July 30,
2001. Our net generating capacity combined with firm capacity purchases and
sales provided a capacity margin of approximately 19% above
9
system peak responsibility at the time of the peak. Our all time peak system net
load of 4,528 MW occurred on September 11, 2000.
We have a market-based rate authority from the FERC, under which we buy
and sell energy and capacity throughout the United States.
We have agreed to provide generating capacity to other utilities for
certain periods as set forth below:
Utility Capacity (MW) Period Ending
------------------------------------------- ------------- -------------
Oklahoma Municipal Power Authority
(OMPA).................................... 60 December 2013
Midwest Energy, Inc........................ 60 May 2008
125 May 2010
Empire District Electric Company (Empire).. 80 May 2001
162 May 2010
McPherson Board of Public Utilities
(McPherson)................................ (a) May 2027
---------
(a) We provide base capacity to McPherson. McPherson provides peaking
capacity to us. During 2001, we provided approximately 74 MW to and
received approximately 182 MW from McPherson. The amount of base
capacity provided to McPherson is based on a fixed percentage of
McPherson's annual peak system load.
We forecast that we will need additional generating capacity of
approximately 150 MW by 2006 to serve our customers' expected electricity needs.
We will determine how to meet this need at a future date.
Fossil Fuel Generation
----------------------
Fuel Mix:
Coal-fired units comprise 3,349 MW of our total 5,947 MW of generating
capacity and the nuclear unit provides 550 MW of capacity. Of the remaining
2,048 MW of generating capacity, units that can burn either natural gas or oil
account for 1,964 MW, units that burn only diesel fuel account for 83 MW, and
wind turbines account for approximately 1 MW (see "Item 2. Properties").
Based on MMBtus burned, the 2001 and estimated 2002 fuel mix (percent of
electricity produced by a specific fuel type) are as follows:
Estimated
Fuel 2001 2002
---- ---- ----
Coal..................................... 77% 78%
Nuclear.................................. 17% 15%
Gas, Oil or Diesel Fuel.................. 6% 7%
Our fuel mix fluctuates with the operation of the nuclear-powered Wolf
Creek (as discussed below under "-- Nuclear Generation"), fuel costs, plant
availability and power available on the wholesale market.
Coal:
Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy Center
---------------------
(JEC) have an aggregate capacity of 1,860 MW (our 84% share). We have a
long-term coal supply contract with Amax Coal West, Inc., a subsidiary of RAG
America Coal Company, to supply coal to JEC from mines located in the Powder
River Basin in Wyoming. The contract expires December 31, 2020. The contract
contains a schedule of minimum annual MMBtu delivery quantities. The coal to be
supplied is surface mined and has an average Btu content of approximately 8,407
Btu per pound and an average sulfur content of 0.43 lbs/MMBtu (see "--
Environmental Matters"). The average cost of coal burned at JEC during 2001 was
approximately $1.10 per MMBtu, or $18.57 per ton.
10
Coal is transported from Wyoming under a long-term rail transportation
contract with Burlington Northern Santa Fe (BNSF) and Union Pacific (UP)
railroads with a term continuing through December 31, 2013.
LaCygne Generating Station: The two coal-fired units at LaCygne Station
--------------------------
have an aggregate generating capacity of 681 MW (KGE's 50% share). LaCygne 1
uses a blended fuel mix containing approximately 85% Powder River Basin coal and
15% Kansas/Missouri coal. LaCygne 2 uses Powder River Basin coal. The operator
of LaCygne Station, Kansas City Power and Light Company (KCPL), administers the
coal and coal transportation contracts. A portion of the LaCygne 1 and LaCygne 2
Powder River Basin coal is supplied through several fixed price and spot market
contracts that expire at various times through 2003 and is transported under
KCPL's Omnibus Rail Transportation Agreement with BNSF and Kansas City Southern
Railroad through December 31, 2010. Additional coal may be acquired on the spot
market. The LaCygne 1 Kansas/Missouri coal is purchased from time to time from
local Kansas and Missouri producers.
The Powder River Basin coal supplied during 2001 had an average Btu
content of approximately 8,527 Btu per pound and an average sulfur content of
0.73 lbs/MMBtu. During 2001, the average cost of all coal burned at LaCygne 1
was approximately $0.86 per MMBtu, or $14.88 per ton. The average cost of coal
burned at LaCygne 2 was approximately $0.79 per MMBtu, or $13.47 per ton.
Lawrence and Tecumseh Energy Centers: The coal-fired units located at the
------------------------------------
Tecumseh and Lawrence Energy Centers have an aggregate generating capacity of
808 MW. In 2001, we obtained coal from Wyoming and Colorado. The Wyoming coal
supplied in 2001 had an average Btu content of approximately 8,753 Btu per pound
and an average sulfur content of 0.46 lbs/MMBtu. The Colorado coal supplied in
2001 had an average Btu content of approximately 11,030 Btu per pound and an
average sulfur content of 0.44 lbs/MMBtu. During 2001, the average cost of all
coal burned in the Lawrence units was approximately $1.25 per MMBtu, or $25.19
per ton. The average cost of all coal burned in the Tecumseh units was
approximately $1.22 per MMBtu, or $23.76 per ton.
The Wyoming Powder River Basin coal is transported by BNSF railroad and
the Colorado coal is transported by BNSF and UP railroads. We have Wyoming coal
under contract to support the anticipated operation of these units through the
end of 2004. We have a portion of our Wyoming coal needs under a contract that
expires in 2004. We may also purchase coal on the spot market.
General: We have entered into all of our coal contracts in the ordinary
-------
course of business and do not believe we are substantially dependent upon these
contracts. We believe there are other suppliers with plentiful sources of coal
available at spot market prices to replace, if necessary, fuel to be supplied
pursuant to these contracts. In the event that we were required to replace our
coal agreements, we would not anticipate a substantial disruption of our
business although the cost of purchasing coal could increase.
We have entered into all of our coal transportation contracts in the
ordinary course of business. Several rail carriers are capable of serving the
coal mines from where our coal originates, but several of our generating
stations can be served by only one rail carrier. In the event the rail carrier
to one of our generating stations fails to provide reliable service, we could
experience a short-term disruption of our business. However, due to the
obligation of the rail carriers to provide service under the Interstate Commerce
Act, we do not anticipate any substantial long-term disruption of our business
although the cost of transporting coal could increase.
Natural Gas:
We use natural gas as a primary fuel in our Gordon Evans, Murray Gill,
Neosho, Abilene, and Hutchinson Energy Centers, in the gas turbine units at our
Tecumseh generating station and in the combined cycle units at the State Line
facility. Natural gas is also used as a supplemental fuel in the coal-fired
units at the Lawrence and Tecumseh generating stations. Natural gas for all
facilities is purchased in the short-term spot market, which supplies the system
with the flexible natural gas supply as necessary to meet operational needs.
For Abilene and Hutchinson Energy Centers, we maintain natural gas
transportation with Kansas Gas Service Company, a division of ONEOK, under a
contract that expires April 30, 2004. For Gordon Evans, Murray Gill, Neosho,
Lawrence and Tecumseh Energy Centers, we meet a portion of our natural gas
transportation
11
requirements through firm natural gas transportation capacity agreements with
Williams Gas Pipelines Central. All of the natural gas transportation
requirements for the State Line facility are met through a firm natural gas
transportation agreement with Williams Gas Pipelines Central. The firm
transportation agreements that serve Gordon Evans, Murray Gill, Lawrence and
Tecumseh extend through April 1, 2010. The agreement for the Neosho and State
Line facilities extends through June 1, 2016.
Oil:
We use oil as an alternate fuel when economical or when interruptions to
natural gas make it necessary. Oil is also used as a start-up fuel at some of
our generating stations and as a primary fuel in the Hutchinson No. 4 combustion
turbine and in the diesel generators. Oil is obtained by spot market purchases
and year-long contracts. We maintain quantities in inventory to meet emergency
requirements and protect against reduced availability of natural gas for limited
periods or when the primary fuel becomes uneconomical to burn.
Other Fuel Matters:
Our contracts to supply fuel for our coal-fired and natural gas-fired
generating units, with the exception of JEC, do not provide full fuel
requirements at the various stations. Supplemental fuel is procured on the spot
market to provide operational flexibility and to take advantage of economic
opportunities when the price is favorable. We use financial instruments to hedge
a portion of our anticipated fossil fuel needs in an attempt to offset the
volatility of the spot market. Due to the volatility of these markets, we are
unable to determine what the value of these financial instruments will be when
the agreements are actually settled. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Information
-- Market Risk Disclosure" for further information.
The table below provides information relating to the weighted average cost
of fuel that we have used (which includes the commodity cost, transportation
cost to our facilities and any other associated costs).
2001 2000 1999
------- ------- -------
KPL Plants
----------
Per Million Btu:
Coal .......................... $ 1.15 $ 1.13 $ 1.09
Gas ........................... 4.61 3.84 2.66
Oil ........................... 3.99 3.45 4.17
Per MWh Generation ............... $ 13.92 $ 13.61 $ 12.57
KGE Plants
----------
Per Million Btu:
Nuclear ....................... $ 0.44 $ 0.44 $ 0.45
Coal .......................... 0.95 0.91 0.87
Gas ........................... 3.75 3.34 2.31
Oil ........................... 3.84 3.12 2.11
Per MWh Generation ............... $ 11.04 $ 11.08 $ 9.83
Nuclear Generation
------------------
Fuel Supply:
The owners of Wolf Creek have on hand or under contract 100% of their
uranium and uranium conversion needs for 2002 and 77% of the uranium and uranium
conversion required for operation of Wolf Creek through October 2006. The
balance is expected to be obtained through spot market and contract purchases.
The owners have under contract 100% of Wolf Creek's uranium enrichment
needs for 2002 and 90% of the uranium enrichment required to operate Wolf Creek
through October 2006. The balance of Wolf Creek's enrichment needs are expected
to be obtained through spot market and contract purchases.
12
All uranium, uranium conversion and uranium enrichment arrangements have
been entered into in the ordinary course of business, and Wolf Creek is not
substantially dependent upon these agreements. Despite contraction and
consolidation in the supply sector for these commodities and services, Wolf
Creek's management believes there are other supplies available to replace, if
necessary, these contracts. In the event these contracts were required to be
replaced, Wolf Creek's management does not anticipate a substantial disruption
of Wolf Creek's operations.
Nuclear fuel is amortized to cost of sales based on the quantity of heat
produced (MMBtus) for the generation of electricity.
Radioactive Waste Disposal:
Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of
Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel.
Wolf Creek pays the DOE a quarterly fee of one-tenth of a cent for each
kilowatt-hour of net nuclear generation delivered for the future disposal of
spent nuclear fuel. These disposal costs are charged to cost of sales.
In 1996 and 1997, a U.S. Court of Appeals issued decisions that (1) the
NWPA unconditionally obligated the DOE to begin accepting spent fuel for
disposal in 1998 and (2) precluded the DOE from concluding that its delay in
accepting spent fuel is "unavoidable" under its contracts with utilities due to
lack of a repository or interim storage authority.
In May 1998, the Court issued an order in response to the utilities'
petitions for remedies for DOE's failure to begin accepting spent fuel for
disposal. The Court affirmed its conclusion that the sole remedy for DOE's
breach of its statutory obligation under the NWPA is a contract remedy and
indicated that the Court will not revisit the matter until the utilities have
completed their pursuit of that remedy. Wolf Creek intends to pursue its claims
against the DOE.
A permanent disposal site will not be available for the nuclear industry
until 2010 or later. Under current DOE policy, once a permanent site is
available, the DOE will accept spent nuclear fuel on a priority basis. The
owners of the oldest spent fuel will be given the highest priority. As a result,
disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek
has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek
completed replacement of spent fuel storage racks to increase its on-site
storage capacity for all spent fuel expected to be generated by Wolf Creek
through the end of its licensed life in 2025.
The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated
that the various states, individually or through interstate compacts, develop
alternative low-level radioactive waste disposal facilities. The states of
Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate
Low-Level Radioactive Waste Compact (Compact) and selected a site in Nebraska to
locate a disposal facility. WCNOC and the owners of the other five nuclear units
in the Compact have provided most of the pre-construction financing for this
project. Our net investment in the Compact through December 31, 2001 was
approximately $7.4 million.
On December 18, 1998, the Nebraska agencies responsible for considering
the developer's license application denied the application. The license
applicant has sought a hearing on the license denial, but a U.S. District Court
has indefinitely delayed proceedings related to the hearing. In December 1998,
most of the utilities that had provided the project's pre-construction financing
(including WCNOC) filed a federal court lawsuit contending Nebraska officials
acted in bad faith while handling the license application. Shortly thereafter,
the Central Interstate Low-Level Radioactive Waste Commission (Commission)
(responsible for causing a new disposal facility to be developed within the
Compact region) and US Ecology (the license applicant) filed similar claims
against Nebraska. In September 1999, the U.S. District Court partially denied
and partially granted Nebraska's motions to dismiss the utilities' and US
Ecology's cases and denied Nebraska's motion to dismiss the Commission's case.
Since that time, the utilities have dismissed their remaining claims against
Nebraska for monetary damages, but their claims for equitable relief remain. The
Commission's claims for monetary damages and equitable relief also remain, and
the parties expect the case to go to trial in the second half of 2002.
13
In May 1999, the Nebraska legislature passed a bill withdrawing Nebraska
from the Compact. In August 1999, the Nebraska governor gave official notice of
the withdrawal to the other member states. Withdrawal will not be effective for
five years and will not, of itself, nullify the site license proceeding.
Wolf Creek disposes of all classes of its low-level radioactive waste at
existing third-party repositories. Should disposal capability become
unavailable, Wolf Creek is able to store its low-level radioactive waste in an
on-site facility for up to five years under current regulations. Wolf Creek
believes that a temporary loss of low-level radioactive waste disposal
capability will not affect continued operation of the power plant.
Outages:
Wolf Creek has an 18-month refueling and maintenance schedule which
permits uninterrupted operation every third calendar year. An outage began on
March 23, 2002. During the outage, electric demand is expected to be met
primarily by our other fossil-fueled generating units and by purchased power.
An extended shut-down of Wolf Creek could have a substantial adverse
effect on our business, financial condition and results of operations because of
higher replacement power and other costs. Although not expected, reacting to
safety issues, the Nuclear Regulatory Commission (NRC) could impose an
unscheduled plant shut-down due to terrorist or other concerns.
Customer Operations
-------------------
Our Customer Operations segment transports electricity from the generating
stations to approximately 640,000 customers in Kansas. It also transports
electric energy to the electric distribution systems of 63 Kansas cities and 4
rural electric cooperatives. Customer Operations properties include substations,
poles, wire, underground cable systems, and customer meters. Customer
Operations' objective is to provide low-cost electricity transportation while
maintaining a high level of system reliability and customer service.
We are a member of the Southwest Power Pool (SPP). In February 2002, SPP
and the Midwest Independent System Operator, Inc. (MISO) executed a definitive
agreement for the consolidation of the two organizations, which is expected to
occur in 2003. We anticipate that after the consolidation of SPP and MISO, we
will participate in MISO. Among other things, these organizations were formed to
maintain transmission system reliability on a regional basis. See "--Competition
and Deregulation" below for more information on these organizations.
We are also a member of the SPP transmission tariff, along with ten other
transmission providers in the region. Revenues from this tariff are divided
among the tariff members based upon calculated impacts to their respective
systems. The tariff allows for both firm and non-firm transmission access. We
will file a new transmission tariff with MISO as it becomes operational.
Customer Operations also includes the customer service portion of our
electric utility business. Customer service includes, among other things,
operating our phone center, handling credit and collections, billing, meter
reading and field service.
Security and Insurance
----------------------
We have increased the level of security measures at our generation
facility sites and various offices, in part due to nationwide terrorist
concerns. These measures include, but are not limited to, increased security
personnel, utilization of armed guard services, patrolling of company property,
restricting access to our properties and implementing emergency training and
response procedures.
Wolf Creek's management has increased both voluntary and
federally-mandated security measures at Wolf Creek. The NRC has required nuclear
power plants to be operated at the highest level of security since September
14
11, 2001. The measures implemented at Wolf Creek include, but are not limited
to, increased guard service, no unscheduled public visits and emergency training
and response procedures.
The NRC has issued orders to all nuclear plants that make our current
voluntary security measures mandatory. The orders also impose new security
requirements at U.S. nuclear power plants. Wolf Creek's security costs will
increase as a result of these orders.
In addition, there are unfavorable trends in the availability and price of
property and casualty insurance primarily due to catastrophic events and the
world's financial markets. We anticipate material increases in insurance costs,
although the amount of the increase is unknown at this time. Information with
respect to insurance coverage applicable to the operations of our nuclear
generating facility is set forth in Note 14 of the "Notes to Consolidated
Financial Statements."
Competition and Deregulation
----------------------------
Electric utilities have historically operated in a rate-regulated
environment. Federal and state regulatory agencies having jurisdiction over our
rates and services and other utilities have initiated steps that were expected
to result in a more competitive environment for utility services. The Kansas
Legislature took no action on deregulation in 2001 or 2000.
In a deregulated environment, utility companies that are not responsive to
a competitive energy marketplace may suffer erosion in market share, revenues
and profits. Possible types of competition include cogeneration,
self-generation, retail wheeling, or municipalization. Retail wheeling is the
ability of individual customers to choose a power provider other than us and we
would provide the transmission service for this power. Kansas does not allow
retail wheeling and no such regulation is pending or being considered. However,
if retail wheeling were implemented in Kansas, increased competition for retail
electricity sales may reduce our future electric utility earnings compared to
our historical electric utility earnings. Our rates range from approximately 10%
to 20% below the national average for retail customers. Because of these rates,
we expect to retain a substantial part of our current volume of sales in a
competitive environment.
Increased competition for retail electricity sales may in the future
reduce our earnings, which could impact our ability to pay dividends and could
have a material adverse impact on our operations and our financial condition. A
material non-cash charge to earnings may be required should we discontinue
accounting under SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation."
The 1992 Energy Policy Act began deregulating the electricity market for
generation. The Energy Policy Act permitted the FERC to order electric utilities
to allow third parties to use their transmission systems to sell electric power
to wholesale customers. In 1992, we agreed to open access of our transmission
system for wholesale transactions. FERC also requires us to provide transmission
services to others under terms comparable to those we provide ourselves. In
December 1999, FERC issued an order (FERC Order No. 2000) encouraging formation
of regional transmission organizations (RTOs). RTOs are designed to control the
wholesale transmission services of the utilities in their regions thereby
facilitating open and more competitive markets in bulk power.
After the FERC rejected several attempts by the SPP to seek RTO status, the
SPP and MISO agreed in October 2001 to consolidate and form an RTO. In December
2001, the FERC approved this newly formed MISO as the first RTO. The agreement
to consolidate was executed in February 2002 and the transaction is expected to
close in 2003. This new organization will operate our transmission system as
part of an interconnected transmission system encompassing over 120,000 MW of
generation capacity located in 20 states. MISO will collect revenues
attributable to the use of each member's transmission system, and each member
will be able to transmit power purchased, generated for sale or bought for
resale in the wholesale market throughout the entire MISO system. Although each
member will have priority over the use of its own transmission facilities for
selling power to its wholesale customers or others, each member will be charged
the same uniform transmission rate as other energy suppliers who are able to
sell power to them. We intend to file with the FERC and the KCC to transfer
control over the operation of our transmission facilities to MISO. We anticipate
that FERC Order No. 2000 and our participation in the MISO will not have a
material effect on our operations.
15
For further discussion regarding competition and its potential impact on
us, see "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Other Information -- Electric Utility."
Regulation and Rates
--------------------
As a Kansas electric utility, we are subject to the jurisdiction of the
KCC, which has general regulatory authority over our rates, extensions and
abandonments of service and facilities, valuation of property, the
classification of accounts and various other matters. We are also subject to the
jurisdiction of the KCC and FERC with respect to the issuance of certain
securities. The NRC regulates our nuclear operations.
Additionally, we are subject to the jurisdiction of FERC, which has
authority over wholesale sales of electricity, the transmission of electric
power and the issuance of certain securities. We are subject to the jurisdiction
of the NRC for nuclear plant operations and safety. We are exempt as a public
utility holding company pursuant to Section 3(a)(1) of the Public Utility
Holding Company Act of 1935 from all provisions of that Act, except Section
9(a)(2).
On November 27, 2000, we and KGE filed applications with the KCC for an
increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction
in our combined electric rates of $22.7 million, consisting of a $41.2 million
reduction in KGE's rates and an $18.5 million increase in our rates.
On August 9, 2001, we and KGE filed petitions with the KCC requesting
reconsideration of the July 25, 2001 order. The petitions specifically asked for
reconsideration of changes in depreciation, reductions in rate base related to
deferred income taxes associated with the KGE acquisition premium and a deferred
gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and
several other issues. On September 5, 2001, the KCC issued an order in response
to our motions for reconsideration that increased our rate increase by an
additional $7.0 million. The $41.2 million rate reduction in KGE's rates
remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions
with the Kansas Court of Appeals in an action captioned "Western Resources, Inc.
and Kansas Gas and Electric Company vs. The State Corporation Commission of the
State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders.
We are evaluating whether to appeal this decision to the Kansas Supreme Court.
Additional information with respect to rate matters and regulation is set
forth in "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Summary of Significant Items -- KCC Rate Cases,"
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Other Information -- Electric Utility" and Notes 2 and 3 of
"Notes to Consolidated Financial Statements."
Environmental Matters
---------------------
We currently hold all federal and state environmental approvals required
for the operation of all of our generating units. We believe we are presently in
substantial compliance with all air quality regulations (including those
pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx))
promulgated by the State of Kansas and the Environmental Protection Agency
(EPA).
The JEC and LaCygne 2 units have met: (1) the federal sulfur dioxide
standards through the use of low sulfur coal; (2) the federal particulate matter
standards through the use of electrostatic precipitators; and (3) the federal
NOx standards through boiler design and operating procedures. The JEC units are
also equipped with flue gas scrubbers providing additional sulfur dioxide and
particulate matter emission reduction capability when needed to meet permit
limits.
The Kansas Department of Health and Environment (KDHE) regulations
applicable to our other generating facilities prohibit the emission of more than
3.0 pounds of sulfur dioxide per MMBtu of heat input. We meet these standards
through the use of low sulfur coal and by all coal-burning facilities being
equipped with flue gas scrubbers and/or electrostatic precipitators.
16
We must comply, and are currently in compliance, with the provisions of
The Clean Air Act Amendments of 1990 that require a two-phase reduction in
certain emissions. We have installed continuous monitoring and reporting
equipment to meet the acid rain requirements. We have not had to make any
material capital expenditures to meet Phase II sulfur dioxide and nitrogen oxide
requirements.
All of our generating facilities are in substantial compliance with the
Best Practicable Technology and Best Available Technology regulations issued by
the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are
administered in Kansas by the KDHE.
Additional information with respect to Environmental Matters is discussed
in Note 14 of the "Notes to Consolidated Financial Statements."
MONITORED SERVICES OPERATIONS
General
-------
We provide property monitoring services through Protection One and
Protection One Europe to approximately 1.2 million customers in North America
and approximately 62,000 customers in continental Europe. Revenues are generated
primarily from recurring monthly payments for monitoring and maintaining the
alarm systems that are installed in customers' homes and businesses. Services
are provided to residential (both single family and multifamily residences),
commercial and wholesale customers. Currently, North America's customers are
primarily in the residential market and Europe's customers are primarily in the
commercial market.
In prior years, the strategy for the monitored security business was
focused primarily on growing the customer account base to achieve critical mass.
Protection One and Protection One Europe grew rapidly by participating in the
growth in the alarm industry and by acquiring other alarm companies.
The strategic focus has now shifted to improving returns on invested
capital by realizing economies of scale from increasing customer density in the
largest urban markets in North America. Protection One plans to accomplish this
goal by:
. retaining customers by providing superior customer service from
monitoring facilities and branches;
. using its national presence, strategic alliances, and strong local
operations to persuade the most desirable residential and commercial
prospects to enter into long term agreements with it on terms that
permit it to achieve appropriate returns on capital; and
. on a limited basis in 2002 or 2003, acquiring alarm companies and
portfolios of alarm accounts pursuant to transactions that meet
strategic and financial requirements.
Operations
----------
Monitored services operations consist principally of alarm monitoring,
customer service functions and branch operations.
Security alarm systems include many different types of devices installed
on customers' premises designed to detect or react to various occurrences or
conditions, such as intrusion or the presence of fire or smoke. Products range
from basic intrusion and fire detection equipment to fully integrated systems
with card access, closed circuit television and voice/video monitoring.
Alarm monitoring customer contracts generally have initial terms ranging
from two to ten years in duration, and provide for automatic renewals for a
fixed period (typically one year) unless one of the parties elects to cancel the
contract at the end of its term.
17
Protection One provides monitoring services from six monitoring facilities
in North America. Protection One Europe provides monitoring services from
facilities in Paris and Vitrolles, France. See "Item 2. Properties" for further
information.
In 2001, Protection One substantially completed the installation of the
technology platform referred to as MAS(R), or Monitored Automation Systems, that
combines the customer service, monitoring, billing, and collection functions
into a single system. The conversion to MAS(R) has enabled Protection One to
consolidate monitoring facilities, resulting in operational efficiencies and
cost savings. Conversion of the Portland, Maine monitoring facility was
completed in January 2002. Currently, approximately 94% of Protection One's
North America residential and commercial customer base is served by MAS(R).
Branch Operations
-----------------
Protection One maintains approximately 60 service branches in North
America from which it provides field repair, customer care, alarm response and
sales services and seven satellite locations from which it provides field repair
services. Protection One Europe maintains approximately 35 sales branch offices
in continental Europe, primarily in France.
Customer Acquisition Strategy
-----------------------------
Protection One's current customer acquisition strategy for North America
relies primarily on internally generated sales. In June 2001, Protection One
notified most of its remaining domestic dealers that it was terminating its
dealer arrangements with them and therefore would not be extending or renewing
their contracts. The number of accounts Protection One purchased through its
dealer program decreased from 21,817 in 2000 to 7,501 in 2001. Protection One
currently has a salaried and commissioned sales force that utilizes its existing
branch infrastructure in approximately 60 markets. In late 2001, Protection One
entered into a marketing alliance with BellSouth Telecommunications, Inc. to
expand its residential, single-family market.
Protection One's multifamily business utilizes a salaried and commissioned
sales force to produce new accounts. It markets its services and products
primarily to developers, owners and managers of apartment complexes and other
multifamily dwellings. Protection One grows its multifamily business through
national and regional advertising, nationwide professional field sales efforts,
centralized inbound and outbound sales functions, prospective acquisition
marketing efforts and professional industry-related association affiliation.
Protection One continually evaluates its customer creation and marketing
strategy, including evaluating each respective channel for economic returns,
volume and other factors and may shift its strategy or focus, including the
elimination of a particular channel.
Protection One Europe's customer acquisition strategy also relies
primarily on internally generated sales. Protection One Europe uses an internal
sales force of approximately 300 employees, which operate out of 35 branch
locations in France, Germany, Belgium and the Netherlands. Protection One
Europe's salary structure for its internal sales force is heavily reliant on
commissions, but contains a portion of fixed salaries. In addition, Protection
One Europe owns a telemarketing company, known as Eurocontact, which provides
qualified leads to the sales network.
18
Competition
-----------
The security alarm industry is highly competitive. In North America, there
are only four alarm companies that offer services across the U.S. and Canada
with the remainder being either large regional or small, privately held alarm
companies. Based on total annual revenues in 2000, Protection One believes the
top four alarm companies in North America are:
. ADT Security Services, a subsidiary of Tyco International, Ltd.
(ADT)
. Protection One
. Brinks Home Security Inc., a subsidiary of The Pittston Services
Group of North America
. Honeywell Inc.
In continental Europe, there are a large number of small competitors and a
few large regional competitors who have recently been taking steps toward
establishing a continental presence. The large regional competitors include the
following companies:
. CIPE, a subsidiary of ADT Security Services and Tyco International,
Ltd., which is the largest security company in France
. Chubb, a United Kingdom based company which is also a leading
security company in France
. Securitas, based in Sweden, which has its principal operations in
the guarding industry but is expanding operations in monitored
security
. Group 4 Falck, a Danish security company that has significant
operations in Scandinavia and has recently expanded into Germany and
the Netherlands
. Rentokil Initial, based in the Netherlands which has established
operations in France and the United Kingdom
Competition in the security alarm industry is based primarily on market
visibility, price, reputation for quality of services and systems, services
offered and the ability to identify and to solicit prospective customers as they
move into homes and businesses. Protection One and Protection One Europe believe
that they compete effectively with other national, regional and local security
alarm companies due to their ability to offer integrated alarm system
installation, monitoring, repair and enhanced services, their reputation for
reliable equipment and services and their prominent presence in the areas
surrounding their branch offices.
Competitors exist in the market that have greater financial resources than
Protection One or Protection One Europe, enabling them to offer higher prices to
purchase customer accounts. The effect of such competition may be to reduce the
growth of our customer account base as purchase opportunities may be limited by
our available resources.
Regulatory Matters
------------------
A number of local governmental authorities have adopted or are considering
various measures aimed at reducing the number of false alarms. Such measures
include:
. Subjecting alarm monitoring companies to fines or penalties for
transmitting false alarms.
. Requiring permits for individual alarm systems and revoking permits
following a specified number of false alarms.
. Imposing fines on alarm customers for false alarms.
. Imposing limitations on the number of times the police will respond
to alarms at a particular location after a specified number of false
alarms.
. Requiring further verification of an alarm signal before the police
will respond.
Monitored services operations are subject to a variety of other laws,
regulations and licensing requirements of both domestic and foreign federal,
state and local authorities. In certain jurisdictions, Protection One and
Protection One Europe are required to obtain licenses or permits to comply with
standards governing employee selection and training, and to meet certain
standards in the conduct of its business.
19
The alarm industry is also subject to requirements imposed by various
insurance, approval, listing and standards organizations. Depending upon the
type of customer served, the type of security service provided, and the
requirements of the applicable local governmental jurisdiction, adherence to the
requirements and standards of such organizations is mandatory in some instances
and voluntary in others.
Protection One's monitoring services advertising and sales practices are
regulated in the United States by both the Federal Trade Commission and state
consumer protection laws. In addition, certain administrative requirements and
laws of the jurisdictions in which Protection and Protection One Europe operate
also regulate such practices. Such laws and regulations include restrictions on
the manner in which the sale of security alarm systems is promoted, the
obligation to provide purchasers of its alarm systems with certain rescission
rights and certain foreign jurisdictions' restrictions on a company's freedom to
contract.
The alarm monitoring business utilizes telephone lines and radio
frequencies to transmit alarm signals. The cost of telephone lines, and the type
of equipment, which may be used in telephone line transmission, are currently
regulated by both federal and state governments. The Federal Communications
Commission and state public utilities commissions regulate the operation and
utilization of radio frequencies. In addition, the laws of certain foreign
jurisdictions in which Protection One and Protection One Europe operate regulate
the telephone communications with the local authorities.
Risk Management
---------------
The nature of providing monitored services potentially exposes Protection
One and Protection One Europe to greater risks of liability for employee acts or
omissions, or system failure, than may be inherent in other businesses.
Substantially all alarm monitoring agreements, and other agreements, pursuant to
which products and services are sold, contain provisions limiting liability to
customers in an attempt to reduce this risk.
Protection One and Protection One Europe carry insurance of various types,
including general liability and errors and omissions insurance in amounts
considered adequate and customary for the industry and business. Loss
experience, and the loss experiences at other security services companies, may
affect the availability and cost of such insurance. Certain insurance policies,
and the laws of some states and countries, may limit or prohibit insurance
coverage for punitive or certain other types of damages, or liability arising
from gross negligence.
SEGMENT INFORMATION
Financial information with respect to business segments is set forth in
Note 24 of the "Notes to Consolidated Financial Statements."
GEOGRAPHIC INFORMATION
Geographic information is set forth in Note 24 of the "Notes to
Consolidated Financial Statements."
EMPLOYEES
As of February 28, 2002, we had approximately 5,600 employees, of which
approximately 3,700 were employees of Protection One and Protection One Europe.
In the fourth quarter of 2001 and in January 2002, we reduced our utility work
force by approximately 600 employees through involuntary and voluntary
separation programs. We may replace some of these employees. Protection One
reduced its work force by approximately 700 employees in 2001 and in January and
February 2002 due to facility consolidations and other cost cutting measures. We
did not experience any strikes or work stoppages during 2001. Our current
contract with the International Brotherhood of Electrical Workers extends
through June 30, 2002. The contract covers approximately 1,100 employees as of
February 28, 2002. We are currently negotiating an extension of the contract.
20
RISK FACTORS
You should read the following risk factors in conjunction with discussions
of factors discussed elsewhere in this and other of our filings with the
Securities and Exchange Commission (SEC). These cautionary statements are
intended to highlight certain factors that may affect our financial condition
and results of operations and are not meant to be an exhaustive discussion of
risks that apply to public companies with broad operations, such as us. Like
other businesses, we are susceptible to macroeconomic downturns in the United
States or abroad that may affect the general economic climate and our
performance or that of our customers. Similarly, the price of our securities is
subject to volatility due to fluctuations in general market conditions,
differences in our results of operations from estimates and projections
generated by the investment community and other factors beyond our control.
We Are a Public Utility Subject to Regulation Which Significantly Impacts
Our Business, Results of Operations, Financial Position and Prospects:
We are regulated by the KCC and FERC and other federal and state agencies.
See "-- Electric Utility Operations -- Regulation and Rates." This regulation
impacts most aspects of our business and operations. Throughout this Annual
Report on Form 10-K, we have described the impact of regulation and the
significant effect it has on our business, financial condition, results of
operations, liquidity and prospects. Such regulation is impacted by matters
beyond our control, such as general economic conditions, politics and
competition, and other matters described under "Forward-Looking Statements." We
refer you to "-- Significant Business Developments," and the other risk factors
below, as well as "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations," for a further discussion of some of the
more important matters which are currently the subject of, or related to,
regulatory concerns.
Municipalization Efforts by Wichita May Affect Operations and Results:
In December 1999, the City Council of Wichita, Kansas, authorized the
hiring of an outside consultant to determine the feasibility of creating a
municipal electric utility to replace KGE as the supplier of electricity in
Wichita. The feasibility study was released in February 2001 and estimates that
the City of Wichita would be required to pay us $145 million for our stranded
costs if it were to municipalize. However, we estimate the amount to be
substantially greater. In order to municipalize KGE's Wichita electric
facilities, the City of Wichita would be required to purchase KGE's facilities
or build a separate independent system and arrange for its own power supply.
These costs are in addition to the stranded costs for which the city would be
required to reimburse us. On February 2, 2001, the City of Wichita announced its
intention to proceed with its attempt to municipalize KGE's retail electric
utility business in Wichita. KGE will oppose municipalization efforts by the
City of Wichita. Should the city be successful in its municipalization efforts
without providing us adequate compensation for our assets and lost revenues, the
adverse effect on our business and financial condition could be material.
KGE's franchise with the City of Wichita to provide retail electric
service is effective through December 1, 2002. There can be no assurance that we
can successfully renegotiate the franchise with terms similar, or as favorable,
as those in the current franchise. Under Kansas law, KGE will continue to have
the right to serve the customers in Wichita following the expiration of the
franchise, assuming the system is not municipalized. Customers within the
Wichita metropolitan area account for approximately 23% of our total energy
sales.
Fuel and Purchased Power Costs are Included in Retail Rates at a Fixed
Level and Increases are not Recovered Automatically:
Fuel and purchased power costs are recovered in retail rates at a fixed
test year level. Therefore, to recover fuel and purchased power costs in excess
of the costs built into retail rates, we would have to make a rate filing with
the KCC, which could be denied in whole or in part. During 2001, we entered into
a gas hedging arrangement, designed to eliminate a portion of our risk through
July 2004. Any increase in fuel and purchased power costs over the costs
recovered through rates would reduce our earnings. Increases could be material.
21
Purchased Power Commodity Prices are Volatile:
The wholesale power market is extremely volatile in price and supply. This
volatility impacts our costs of power purchased and our participation in power
trades. If we were unable to generate an adequate supply of electricity for our
native load customers, we would purchase power in the wholesale market to the
extent it is available or economically feasible to do so and/or implement
curtailment or interruption procedures as allowed for in our tariffs and terms
and conditions of service. To the extent open positions exist in our power
marketing portfolio, we are exposed to fluctuating market prices that may
adversely impact our financial position and results of operations. The increased
expenses or loss of revenues associated with this could be material and adverse
to our consolidated results of operations and financial condition.
Hedging and Trading Activities Involve Risks:
We are involved in hedging and trading activities primarily to minimize
risk from commodity market fluctuations, capitalize on market knowledge and
enhance system reliability. In these activities, we utilize a variety of
financial instruments, including forward contracts involving cash settlements or
physical delivery of an energy commodity, futures, options and swaps providing
for payments (or receipt of payments) from counterparties based on the
differential between the contract price and a specified index price.
Our hedging and trading activities involve risks, including commodity
price risk, interest rate risk and credit risk. Commodity price risk is the risk
that changes in commodity prices may impact the price at which we are able to
buy and sell electricity and purchase fossil fuels for our generators. These
commodities have experienced price volatility in the past and can be expected to
do so in the future. This volatility may increase or decrease future earnings.
Interest rate risk is the risk of loss associated with movements in market
interest rates. Our exposure to interest rate risk is limited due to the
fixed-rate nature of most of our long-term debt. During 2001, we utilized an
interest rate swap to manage our exposure to variable interest rates. The swap
converted $500 million of variable rate debt to a fixed rate. In the future, we
may continue to utilize swaps or other financial instruments to manage interest
rate risk.
Credit risk is the risk of loss resulting from non-performance by a
counterparty of its contractual obligations. As we continue to expand our power
marketing and commodity trading activities, our exposure to credit risk and
counterparty default may increase. We maintain credit policies intended to
minimize overall credit risk and actively monitor these policies to reflect
changes and scope of operations. We employ additional credit risk control
mechanisms when appropriate, such as letters of credit, parental guarantees and
standardized master netting agreements that allow for offsetting of positive and
negative exposures. Credit exposure is monitored and, when necessary, the
activity with a specific counterparty is limited until credit enhancement is
provided. See " Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Other Information -- Market Risk
Disclosure" for further discussion.
Results actually achieved from these activities could vary materially from
intended results and could materially affect our financial results.
Current Levels of Debt Could Adversely Affect Our Business:
We have a large amount of consolidated indebtedness. As of December 31,
2001, we had outstanding total indebtedness of approximately $3.4 billion, of
which approximately $2.9 billion was the obligation of our Westar Energy
operations. A large amount of indebtedness could have a negative impact on,
among other things, our ability to obtain additional financing in the future for
working capital, capital expenditures and general corporate purposes and our
ability to withstand a downturn in our business or the economy in general.
The indentures governing our long-term indebtedness require us to satisfy
certain financial conditions in order to borrow additional funds. These
covenants require, among other things, that we maintain certain leverage and
interest coverage ratios. We are in compliance with these covenants. A breach of
any of the covenants could
22
result in an event of default, which would allow the lenders to declare all
amounts outstanding immediately due and payable.
For information regarding a financial plan that was filed with the KCC
that details our current plans for debt reduction, see "-- Significant Business
Developments -- KCC Proceedings and Orders" and "-- Significant Business
Developments -- The Financial Plan" above.
Strategic Transactions May Not Be Completed:
Our strategic plans include the acquisition of our electric utility
businesses by PNM and the split-off of Westar Industries to our shareholders.
Prior to the completion of these transactions, Westar Industries would sell a
portion of its common stock in a rights offering to our shareholders. The
completion of these transactions is subject to the satisfaction of various
conditions, including the receipt of shareholder and regulatory approvals in the
case of the PNM transaction. We believe the completion of the proposed
transaction with PNM is not likely. See "-- Significant Business Developments --
PNM Transaction" above for more information.
The Separation of Westar Industries Would Impact Results of Operations:
The financing plan we have filed with the KCC proposes a rights (and
warrants) offering of Westar Industries common stock to our shareholders. The
financing plan also contemplates (and in certain circumstances requires) a sale
of all, or some of, the Westar Industries common stock we own following the
rights (and warrants) offering. If a Westar Industries rights offering is
completed, we would record a non-cash charge against income equal to the
difference between the book value of the portion of our investment in Westar
Industries sold in the rights offering and the offering proceeds received by
Westar Industries. Similarly, if a split-off or sale of all or part of Westar
Industries were completed, we would record a non-cash charge against income
equal to the difference between the book value of our remaining investment in
Westar Industries and the fair market value of the shares of Westar Industries
common stock distributed to our shareholders or sold. We are unable to determine
the amount of the charges at this time because the subscription price in the
rights offering has not been determined and the fair market value of the common
stock of Westar Industries distributed in the split-off or sale of Westar
Industries common stock will be determined at the time it occurs. However, the
charges could be material and may have a material adverse effect on our
operating results in the period recorded. See "-- Significant Business
Developments -- The Financial Plan" above for more information.
Monitored Services Has Had a History of Losses which are Likely to
Continue:
Our monitored services segment incurred losses before interest and taxes
of $126.1 million in 2001, $91.4 million in 2000 and $20.7 million in 1999.
These losses reflect, among other factors:
. lower revenues due to a smaller customer base;
. substantial charges incurred for amortization of purchased customer
accounts and goodwill;
. interest incurred on indebtedness;
. other charges required to manage operations; and
. costs associated with the integration of acquisitions.
We anticipate that Protection One will also continue to incur substantial
interest expense because of its substantial debt. We do not expect the monitored
services segment to attain profitable operations in the foreseeable future.
Monitored Services Loses Customers Over Time:
Protection One and Protection One Europe experience the loss of accounts,
referred to as attrition, as a result of, among other factors, relocation of
customers, adverse financial and economic conditions, competition from other
alarm service companies, and customer service and operational difficulties with
the integration of acquired
23
customers. Prior to 2000, the effects of the gross number of lost customers were
offset by a combination of factors that resulted in an overall increase in the
number of customers and revenue, including acquiring alarm account portfolios,
purchasing accounts from dealers, adding new accounts from customers who moved
into premises previously occupied by prior customers in which security alarm
systems were installed, adding accounts for which Protection One obtained a
guarantee from the seller that allowed Protection One to "put" back to the
seller cancelled accounts, and revenues from price increases and the sale of
enhanced services. In 2001 and 2000, Protection One's customer acquisition
strategies did not replace accounts lost as a result of attrition. This is due
primarily to a move from reliance on a dealer program to generate customer
accounts to reliance on internally generated sales. The failure of Protection
One and Protection One Europe's customer acquisition strategies to increase the
number of new accounts, or the inability of Protection One and Protection One
Europe to reduce attrition levels, could have a material adverse effect on their
businesses, financial conditions and results of operations.
Monitored Services Will Record an Impairment Charge in the First Quarter
of 2002 and Additional Charges May be Recorded in the Future:
In the first quarter of 2002, the monitored services segment will record
an impairment charge to write down goodwill and customer accounts to their
estimated fair values. The amount of this charge net of tax will be
approximately $653.7 million, of which $464.2 million is related to goodwill and
$189.5 million is related to customer accounts. For further information on the
impairment charge, see Note 25 of the "Notes to Consolidated Financial
Statements." After this write down is recorded, we will still have material
amounts of goodwill and customer accounts recorded on our consolidated balance
sheet. The remaining amount of goodwill will be required to be tested annually
for impairment. Customer accounts will be required to be tested upon certain
triggering events, which include recurring operating losses, adverse business
conditions, declines in market values and other matters that negatively impact
value. If the monitored services segment fails future impairment tests for
either goodwill or customer accounts, we will be required to recognize
additional impairment charges on these assets in the future.
The Impact of Protection One Class Action Litigation May Be Material:
We, Westar Industries, Protection One and its subsidiary Protection One
Alarm Monitoring, Inc. (Protection One Alarm Monitoring) and certain present and
former officers and directors of Protection One, are defendants in a purported
class action litigation pending in the United States District Court for the
Central District of California brought on behalf of shareholders of Protection
One. The plaintiffs are seeking unspecified compensatory damages based on
allegations that various statements concerning Protection One's financial
results and operations for 1997, 1998, 1999 and the first three quarters of 2000
were false and misleading. Protection One and we cannot currently predict the
impact of this litigation, which could be material. See "Item 3. Legal
Proceedings" and Note 16 of the "Notes to Consolidated Financial Statements" for
more information.
24
ITEM 2. PROPERTIES
------------------
ELECTRIC UTILITY FACILITIES
--------------------------------------------------------------------------------------------------------------------------------
Year Principal Unit Capacity
Name Unit No. Installed Fuel (MW) Segment
--------------------------------------------------------------------------------------------------------------------------------
Abilene Energy Center:
Combustion Turbine 1 1973 Gas 71.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 151.0 Fossil Generation
2 1967 Gas--Oil 383.0 Fossil Generation
Combustion Turbines 1 2000 Gas--Oil 80.0 Fossil Generation
2 2000 Gas--Oil 80.0 Fossil Generation
3 2001 Gas--Oil 154.0 Fossil Generation
Diesel Generator 1 1969 Diesel 3.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 17.0 Fossil Generation
2 1950 Gas 16.0 Fossil Generation
3 1951 Gas 31.0 Fossil Generation
4 1965 Gas 175.0 Fossil Generation
Combustion Turbines 1 1974 Gas 52.0 Fossil Generation
2 1974 Gas 54.0 Fossil Generation
3 1974 Gas 54.0 Fossil Generation
4 1975 Diesel 77.0 Fossil Generation
Diesel Generator 1 1983 Diesel 3.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
Jeffrey Energy Center (84%):
Steam Turbines 1 (a) 1978 Coal 625.0 Fossil Generation
2 (a) 1980 Coal 612.0 Fossil Generation
3 (a) 1983 Coal 623.0 Fossil Generation
Wind Turbines 1 (a) 1999 -- 0.6 Fossil Generation
2 (a) 1999 -- 0.6 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
LaCygne Station (50%):
Steam Turbines 1 (a) 1973 Coal 344.0 Fossil Generation
2 (b) 1977 Coal 337.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
Lawrence Energy Center:
Steam Turbines 3 1954 Coal 57.0 Fossil Generation
4 1960 Coal 119.0 Fossil Generation
5 1971 Coal 388.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 43.0 Fossil Generation
2 1954 Gas--Oil 74.0 Fossil Generation
3 1956 Gas--Oil 112.0 Fossil Generation
4 1959 Gas--Oil 107.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
Neosho Energy Center:
Steam Turbine 3 1954 Gas--Oil 69.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
State Line (40%):
Combined Cycle 2-1 (a) 2001 Gas 60.0 Fossil Generation
2-2 (a) 2001 Gas 60.0 Fossil Generation
2-3 (a) 2001 Gas 80.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 86.0 Fossil Generation
8 1962 Coal 158.0 Fossil Generation
Combustion Turbines 1 1972 Gas 20.0 Fossil Generation
2 1972 Gas 21.0 Fossil Generation
--------------------------------------------------------------------------------------------------------------------------------
Wolf Creek Generating Station (47%):
Nuclear 1 (a) 1985 Uranium 550.0 Nuclear Generation
--------------------------------------------------------------------------------------------------------------------------------
Total 5,947.2
=======
--------------------------------------------------------------------------------------------------------------------------------
----------------
(a) We jointly own Jeffrey Energy Center (84%), LaCygne 1 generating unit
(50%), Wolf Creek Generating Station (47%) and State Line (40%). Unit
capacity amounts reflect Western Resources' ownership only.
(b) In 1987, KGE entered into a sale-leaseback transaction involving its 50%
interest in the LaCygne 2 generating unit.
25
We own approximately 6,700 miles of transmission lines, approximately
25,000 miles of overhead distribution lines and approximately 3,000 miles of
underground distribution lines. (These properties are part of the Customer
Operations segment.)
Financing
---------
Substantially all of our utility properties are encumbered by first
priority mortgages pursuant to which bonds have been issued and are outstanding.
MONITORED SERVICES FACILITIES
-----------------------------
Protection One maintains its executive offices at 818 South Kansas Avenue,
Topeka, Kansas 66612. Protection One and Protection One Europe operate primarily
from the following facilities, although Protection One also leases office space
for approximately 60 service branch offices and seven satellite branches in
North America and Protection One Europe leases offices for approximately 35
sales branch offices in continental Europe.
------------------------------------------------------------------------------------------------------------------------------
Protection One:
Size
Location (Sq. ft.) Lease/Own Principal Purpose
------------------------------------------------------------------------------------------------------------------------------
United States:
Addison, TX (a)............ 28,512 Lease Monitoring facility/Multifamily administrative headquarters
Irving, TX (a)............. 53,750 Lease Monitoring facility/administrative headquarters
Orlando, FL................ 11,020 Lease Wholesale monitoring facility
Portland, ME............... 9,000 Lease Monitoring facility/local branch
Topeka, KS................. 17,703 Lease Financial/administrative headquarters
Wichita, KS................ 50,000 Own Monitoring facility/administrative functions
Canada:
Ottawa, ON................. 7,937 Lease Monitoring facility/administrative headquarters
Vancouver, BC.............. 5,177 Lease Monitoring facility
------------------------------------------------------------------------------------------------------------------------------
Protection One Europe:
Size
Location (Sq. ft.) Lease/Own Principal Purpose
------------------------------------------------------------------------------------------------------------------------------
Europe:
Paris, France.............. 3,498 Lease Financial/Administrative offices/Monitoring facility
Vitrolles, France.......... 27,000 Lease Administrative/Monitoring facility
Dusseldorf, Germany........ 7,800 Lease Administrative/Warehouse
Brussels, Belgium.......... 14,400 Lease Administrative/Warehouse
------------------------------------------------------------------------------------------------------------------------------
----------
(a) In 2002, the administrative headquarters and monitoring operations for
Protection One's Network Multifamily (Multifamily) segment will be
relocated to the Irving, Texas facility.
26
ITEM 3. LEGAL PROCEEDINGS
-------------------------
The SEC commenced a private investigation in 1997 relating to, among other
things, the timeliness and adequacy of disclosure filings with the SEC by us
with respect to securities of ADT Ltd. We have cooperated with the SEC staff in
this investigation.
We, Westar Industries, Protection One, Protection One Alarm Monitoring and
certain present and former officers and directors of Protection One are
defendants in a purported class action litigation pending in the United States
District Court for the Central District of California, "Alec Garbini, et al v.
Protection One, Inc., et al," No. CV 99-3755 DT (RCx). Pursuant to an Order
dated August 2, 1999, four pending purported class actions were consolidated
into a single action. On February 27, 2001, plaintiffs filed a Third
Consolidated Amended Class Action Complaint (Third Amended Complaint).
Plaintiffs purported to bring the action on behalf of a class consisting of all
purchasers of publicly traded securities of Protection One, including common
stock and bonds, during the period of February 10, 1998 through February 2,
2001. The Third Amended Complaint asserted claims under Section 11 of the
Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934
against Protection One, Protection One Alarm Monitoring, and certain present and
former officers and directors of Protection One based on allegations that
various statements concerning Protection One's financial results and operations
for 1997, 1998, 1999 and the first three quarters of 2000 were false and
misleading and not in compliance with generally accepted accounting principles.
Plaintiffs alleged, among other things, that former employees of Protection One
have reported that Protection One lacked adequate internal accounting controls
and that certain accounting information was unsupported or manipulated by
management in order to avoid disclosure of accurate information. The Third
Amended Complaint further asserted claims against us and Westar Industries as
controlling persons under Sections 11 and 15 of the Securities Act of 1933 and
Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. A claim was
also asserted under Section 11 of the Securities Act of 1933 against Protection
One's auditor, Arthur Andersen LLP. The Third Amended Complaint sought an
unspecified amount of compensatory damages and an award of fees and expenses,
including attorneys' fees. On June 4, 2001, the District Court dismissed
plaintiffs' claims under Sections 10(b) and 20(a) of the Securities Exchange
Act. The Court granted plaintiffs leave to replead such claims. The Court also
dismissed all claims brought on behalf of bondholders with prejudice. The Court
also dismissed plaintiffs' claims against Arthur Andersen and the plaintiffs
have appealed that dismissal. On February 22, 2002, plaintiffs filed a Fourth
Consolidated Amended Class Action Complaint. The new complaint realleges claims
on behalf of purchasers of common stock under Sections 11 and 15 of the
Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange
Act of 1934. The defendants have until April 5, 2002 to respond to the new
complaint. Protection One and we cannot predict the impact of this litigation,
which could be material.
We and our subsidiaries are involved in various other legal, environmental
and regulatory proceedings. We believe that adequate provision has been made and
accordingly believe that the ultimate disposition of such matters will not have
a material adverse effect upon our overall financial position or results of
operations.
See also Notes 3 and 15 of the "Notes to Consolidated Financial
Statements" for discussion of FERC proceedings and the lawsuit PNM filed against
us and the KCC regulatory proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
-----------------------------------------------------------
No matter was submitted to a vote of our security holders through the
solicitation of proxies or otherwise during the fourth quarter of 2001.
27
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
-----------------------------------------------------------------------------
STOCK TRADING
Our common stock is listed on the New York Stock Exchange and traded under
the ticker symbol WR. As of March 14, 2002, there were 35,839 common
shareholders of record. For information regarding quarterly common stock price
ranges for 2001 and 2000, see Note 27 of the "Notes to Consolidated Financial
Statements."
DIVIDENDS
Holders of our common stock are entitled to dividends when and as declared
by our board of directors. However, prior to the payment of common dividends,
dividends must be first paid to the holders of preferred stock based on the
fixed dividend rate for each series and our obligations with respect to
mandatorily redeemable preferred securities issued by subsidiary trusts must be
met.
Quarterly dividends on common stock and preferred stock normally are paid
on or about the first of January, April, July and October to shareholders of
record as of or about the ninth day of the preceding month. Our board of
directors reviews its common stock dividend policy from time to time. Among the
factors the board of directors considers in determining its dividend policy are
earnings, cash flows, capitalization ratios, regulation, competition and
financial loan covenants. In March 2000, we announced a quarterly dividend of
$0.30 per share (an indicated dividend rate of $1.20 per share on an annual
basis). We expect to maintain the dividend at this level in 2002. Our agreement
with PNM prohibits an increase in the dividend paid on our common stock without
the consent of PNM.
Our Articles of Incorporation contain restrictions on the payment of
dividends or the making of other distributions on our common stock while any
preferred shares remain outstanding unless certain capitalization ratios and
other conditions are met. We do not expect these restrictions to have an impact
on our ability to pay dividends on our common stock at the current rate.
For information regarding quarterly dividend declarations for 2001 and
2000, see "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources." See also Note 18
of the "Notes to Consolidated Financial Statements" included herein.
28
ITEM 6. SELECTED FINANCIAL DATA
-------------------------------
For the Year Ended December 31,
------------------------------------------------------------------------
2001 2000 1999(a) 1998(b) 1997(c)
---------- ---------- ---------- ---------- ----------
(In Thousands)
Income Statement Data:
Sales ............................................... $2,186,262 $2,368,476 $2,030,087 $2,034,054 $2,151,765
Net income (loss) before extraordinary gain and
accounting change ................................ (62,726) 91,050 2,554 34,058 498,652
Earnings (loss) available for common
stock ............................................ (21,771) 135,352 13,167 32,058 493,733
As of December 31,
------------------------------------------------------------------------
2001 2000 1999(a) 1998(b) 1997(c)
---------- ---------- ---------- ---------- ----------
(In Thousands)
Balance Sheet Data:
Total assets ........................................ $7,513,065 $7,801,720 $7,989,892 $7,929,776 $6,945,350
Long-term debt, net, and other mandatorily
redeemable securities ............................ 3,198,382 3,457,849 3,103,066 3,283,064 2,391,889
For the Year Ended December 31,
------------------------------------------------------------------------
2001 2000 1999(a) 1998(b) 1997(c)
---------- ---------- ---------- ---------- ----------
Common Stock Data:
Basic and diluted earnings (losses) per share
available for common stock before extraordinary
gain and accounting change ....................... $ (0.90) $ 1.30 $ 0.02 $ 0.46 $ 7.58
Basic and diluted earnings (losses) per share
available for common stock ....................... $ (0.31) $ 1.96 $ 0.20 $ 0.48 $ 7.58
Dividends per share (d) ............................. $ 1.20 $ 1.44 $ 2.14 $ 2.14 $ 2.10
Book value per share ................................ $ 25.60 $ 27.20 $ 28.03 $ 29.21 $ 30.86
Average shares outstanding (000's) .................. 70,650 68,962 67,080 65,634 65,128
----------
(a) Information reflects the impairment of marketable securities and the
change to an accelerated amortization method for the monitored services
segment's customer accounts.
(b) Information reflects exit costs associated with international power
development activities.
(c) Information reflects the gain on the sale of Tyco common shares, our
strategic alliance with ONEOK and the acquisition of Protection One.
(d) In March 2000, we announced a new dividend policy. See "Item 5. Market for
Registrant's Common Equity and Related Stockholder Matters -- Dividends."
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
-------------------------------------------------------------------------------
OF OPERATIONS
-------------
INTRODUCTION
In Management's Discussion and Analysis, we discuss the general financial
condition, significant annual changes and the operating results for us and our
subsidiaries. We explain:
. what factors impact our business,
. what our earnings and costs were in 2001, 2000 and 1999,
. why these earnings and costs differ from year to year,
. how our earnings and costs affect our overall financial condition,
. what our capital expenditures were for 2001,
. what we expect our capital expenditures to be for the years 2002
through 2004,
. how we plan to pay for these future capital expenditures,
. critical accounting policies, and
. any other items that particularly affect our financial condition or
earnings.
As you read Management's Discussion and Analysis, please refer to our
consolidated financial statements and the notes thereto, which show our
operating results.
SUMMARY OF SIGNIFICANT ITEMS
PNM Transaction
---------------
On November 8, 2000, we entered into an agreement with Public Service
Company of New Mexico (PNM), pursuant to which PNM would acquire our electric
utility businesses in a tax-free stock-for-stock merger. Under the terms of the
agreement, both PNM and we are to become subsidiaries of a new holding company,
subject to customary closing conditions including regulatory and shareholder
approvals. Immediately prior to closing, all of the Westar Industries common
stock we own would be distributed to our shareholders in exchange for a portion
of their Western Resources common stock. At the same time we entered into the
agreement with PNM, we and Westar Industries entered into an Asset Allocation
and Separation Agreement which, among other things, provided for this split-off
and related matters.
On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court
of the State of New York. The lawsuit seeks, among other things, declaratory
judgment that PNM is not obligated to proceed with the proposed merger based in
part upon the Kansas Corporation Commission (KCC) orders discussed below and
other KCC orders reducing rates for our electric utility business. PNM believes
the orders constitute a material adverse effect and make the condition that the
split-off of Westar Industries occur prior to closing incapable of satisfaction.
PNM also seeks unspecified monetary damages for breach of representation.
On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court
of the State of New York. The lawsuit seeks substantial damages for PNM's breach
of the merger agreement providing for PNM's purchase of our electric utility
operations and for PNM's breach of its duty of good faith and fair dealing. In
addition, we filed a motion to dismiss or stay the declaratory judgment action
previously filed by PNM seeking a declaratory judgment that PNM has no further
obligations under the merger agreement.
On January 7, 2002, PNM sent a letter to us purporting to terminate the
merger in accordance with the terms of the merger agreement. We have notified
PNM that we believe the purported termination of the merger agreement was
ineffective and that PNM remains obligated to perform thereunder. We intend to
contest PNM's purported termination of the merger agreement. However, based upon
PNM's actions and the related uncertainties, we believe the closing of the
proposed merger is not likely.
30
KCC Rate Cases
--------------
On November 27, 2000, we and KGE filed applications with the KCC for an
increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction
in our combined electric rates of $22.7 million, consisting of a $41.2 million
reduction in KGE's rates and an $18.5 million increase in our rates.
On August 9, 2001, we and KGE filed petitions with the KCC requesting
reconsideration of the July 25, 2001 order. The petitions specifically asked for
reconsideration of changes in depreciation, reductions in rate base related to
deferred income taxes associated with the KGE acquisition premium and a deferred
gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and
several other issues. On September 5, 2001, the KCC issued an order in response
to our motions for reconsideration that increased our rate increase by an
additional $7.0 million. The $41.2 million rate reduction in KGE's rates
remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions
with the Kansas Court of Appeals in an action captioned "Western Resources, Inc.
and Kansas Gas and Electric Company vs. The State Corporation Commission of the
State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders.
We are evaluating whether to appeal this decision to the Kansas Supreme Court.
KCC Proceedings and Orders
--------------------------
The merger with PNM contemplated the completion of a rights offering for
shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an
investigation of the proposed separation of our electric utility businesses from
our non-utility businesses, including the rights offering, and other aspects of
our unregulated businesses. The order opening the investigation indicated that
the investigation would focus on whether the separation and other transactions
involving our unregulated businesses are consistent with our obligation to
provide efficient and sufficient electric service at just and reasonable rates
to our electric utility customers. The KCC staff was directed to investigate,
among other matters, the basis for and the effect of the Asset Allocation and
Separation Agreement we entered into with Westar Industries in connection with
the proposed separation and the intercompany payable owed by us to Westar
Industries, the separation of Westar Industries, the effect of the business
difficulties faced by our unregulated businesses and whether they should
continue to be affiliated with our electric utility business, and our present
and prospective capital structures. On May 22, 2001, the KCC issued an order
nullifying the Asset Allocation and Separation Agreement, prohibiting Westar
Industries and us from taking any action to complete the rights offering for
common stock of Westar Industries, which was to be a first step in the
separation, and scheduling a hearing to consider whether to make the order
permanent.
On July 20, 2001, the KCC issued an order that, among other things: (1)
confirmed its May 22, 2001 order prohibiting us and Westar Industries from
taking any action to complete the proposed rights offering and nullifying the
Asset Allocation and Separation Agreement; (2) directed us and Westar Industries
not to take any action or enter into any agreement not related to normal utility
operations that would directly or indirectly increase the share of debt in our
capital structure applicable to our electric utility operations, which has the
effect of prohibiting us from borrowing to make a loan or capital contribution
to Westar Industries; and (3) directed us to present a financial plan consistent
with parameters established by the KCC's order to restore financial health,
achieve a balanced capital structure and protect ratepayers from the risks of
our non-utility businesses. In its order, the KCC also acknowledged that we are
presently operating efficiently and at reasonable cost and stated that it was
not disapproving the PNM transaction or a split-off of Westar Industries. We
appealed the orders issued by the KCC to the District Court of Shawnee County,
Kansas. On February 5, 2002, the District Court issued a decision finding that
the KCC orders were not final orders and that the District Court lacked
jurisdiction to consider the appeal. Accordingly, the matter was remanded to the
KCC for review of the financial plan.
On February 11, 2002, the KCC issued an order primarily related to
procedural matters for the review of the financial plan, as discussed below. In
addition, the order required that we and the KCC staff make filings addressing
whether the filing of applications by us and KGE at the Federal Energy
Regulatory Commission (FERC), seeking renewal of existing borrowing authority,
violated the July 20, 2001 KCC order directing that we not increase the share of
debt in our capital structure applicable to our electric utility operations. The
KCC staff subsequently filed comments asserting that the refinancing of existing
indebtedness with new indebtedness secured by utility assets would in certain
circumstances violate the July 20, 2001 KCC order. The KCC filed a motion to
intervene in the
31
proceeding at FERC asserting the same position. We are unable to predict whether
the KCC will adopt the KCC staff position, the extent to which FERC will
incorporate the KCC position in orders renewing our borrowing authority, or the
impact of the adoption of the KCC staff position, if that occurs, on our ability
to refinance indebtedness maturing in the next several years. Our inability to
refinance existing indebtedness on a secured basis would likely increase our
borrowing costs and adversely affect our results of operations.
The Financial Plan
------------------
The July 20, 2001 KCC order directed us to present a financial plan to the
KCC. For details of the financial plan, see Note 15 of the "Notes to
Consolidated Financial Statements."
Extraordinary Gain on Extinguishment of Debt
--------------------------------------------
During the last three years, Protection One and our bonds were repurchased
in the open market and extraordinary gains were recognized on the retirement of
these bonds of $23.2 million in 2001, $49.2 million in 2000 and $13.4 million in
1999, net of tax. From January 1, 2002 through February 2002, a gain of $3.6
million, net of tax, was recognized on the repurchase of Protection One and our
bonds.
Impairment Charge Pursuant to New Accounting Rules
--------------------------------------------------
Effective January 1, 2002, we adopted the new accounting standards
Statement of Financial Accounting Standard (SFAS) No. 142, "Accounting for
Goodwill and Other Intangible Assets," and SFAS No. 144, "Accounting for the
Impairment and Disposal of Long-Lived Assets." SFAS No. 142 establishes new
standards for accounting for goodwill. SFAS No. 142 continues to require the
recognition of goodwill as an asset, but discontinues amortization of goodwill.
In addition, annual impairment tests must be performed using a fair-value based
approach as opposed to an undiscounted cash flow approach required under prior
standards.
SFAS No. 144 establishes a new approach to determining whether our
customer account asset is impaired. The approach no longer permits us to
evaluate our customer account asset for impairment based on the net undiscounted
cash flow stream obtained over the remaining life of the goodwill associated
with the customer accounts being evaluated. Rather, the cash flow stream to be
used under SFAS No. 144 is limited to the future estimated undiscounted cash
flows of our existing customer accounts. Additionally, the new rule no longer
permits us to include estimated cash flows from forecasted customer additions.
If the undiscounted cash flow stream from existing customer accounts is less
than the combined book value of customer accounts and goodwill, an impairment
charge is required.
The new rule substantially reduces the net undiscounted cash flows used
for impairment evaluation purposes as compared to the previous accounting rules.
The undiscounted cash flow stream has been reduced from the 16-year remaining
life of the goodwill to the nine-year remaining life of customer accounts for
impairment evaluation purposes and does not include estimated cash flows from
forecasted customer additions.
32
To implement the new standards, an independent appraisal firm was engaged
to help management estimate the fair values of goodwill and customer accounts.
Based on this analysis, during the first quarter of 2002, we will record a
non-cash net charge of approximately $653.7 million, of which $464.2 million is
related to goodwill and $189.5 million is related to customer accounts. The
charge is detailed as follows:
Impairment of Impairment of
Goodwill Customer Accounts Total
------------- ----------------- ---------
(In Thousands)
Protection One .............. $ 498,921 $ 334,064 $ 832,985
Protection One Europe ....... 80,104 -- 80,104
--------- --------- ---------
Total pre-tax impairment .... $ 579,025 $ 334,064 913,089
========= =========
Income tax benefit .......... (173,650)
Minority interest ........... (85,713)
---------
Net charge .................. $ 653,726
=========
The impairment charge for goodwill will be reflected in our consolidated
statement of income as a cumulative effect of a change in accounting principle.
The impairment charge for customer accounts will be reflected in our
consolidated statement of income as an operating cost. These impairment charges
reduce the recorded value of these assets to their estimated fair values at
January 1, 2002.
In 2001, we recorded approximately $57.1 million of goodwill amortization
expense. We will no longer be permitted to amortize goodwill to income because
of adoption of the new goodwill rule. In 2001, we recorded approximately $153.0
million of customer account amortization expense. Future customer account
amortization expense will also be reduced as a result of the impairment charge.
We will be required to perform impairment tests for our monitored services
segment for long-lived assets prospectively as long as it continues to incur
recurring losses or for other matters that may negatively impact its businesses.
Goodwill will be required to be tested each year for impairment. Declines in
market values of our monitored services businesses or the value of customer
accounts that may be incurred prospectively may require additional write down of
these assets in the future.
Estimated Lives of Customer Accounts to Change Based on Customer Account Lifing
-------------------------------------------------------------------------------
Study Results
-------------
Protection One is currently evaluating the estimated life and amortization
rates for customer accounts, given the results of a lifing study performed by a
third party appraisal firm in the first quarter of 2002. Any change in its
amortization rate or estimated life will be determined in the first quarter of
2002 and accounted for prospectively as a change in estimate.
Work Force Reductions
---------------------
In late 2001, we reduced our utility work force by approximately 200
employees through involuntary separations and recorded a severance-related net
charge of approximately $14.3 million. In 2001, Protection One also reduced its
work force by approximately 500 employees in connection with facility
consolidations and recorded a severance-related net charge of approximately $3.1
million.
In the first quarter of 2002, we further reduced our utility work force by
approximately 400 employees through a voluntary separation program. We expect to
record a net charge of approximately $21.1 million in the first quarter of 2002
related to this program. We may replace some of these employees. Protection One
also reduced its work force by approximately 200 employees in connection with
facility consolidations and expects to record a net severance charge of
approximately $0.5 million in the first quarter of 2002.
33
Ice Storm
---------
In late January 2002, a severe ice storm swept through our utility service
area causing extensive damage and loss of power to numerous customers. We
estimate storm restoration costs could run as high as $25 million. On March 13,
2002, we filed an application for an accounting authority order with the KCC
requesting that we be allowed to accumulate and defer for future recovery costs
related to storm restoration. We cannot predict whether the KCC will approve our
application.
Marketable Securities
---------------------
During the fourth quarter of 1999, we decided to sell our remaining
marketable security investments in paging industry companies. These securities
were classified as available-for-sale; therefore, changes in market value were
historically reported as a component of other comprehensive income. The market
value for these securities declined during the last six to nine months of 1999.
We determined that the decline in value of these securities was other than
temporary and a charge to earnings for the decline in value was required at
December 31, 1999. Therefore, a non-cash charge of $76.2 million was recorded in
the fourth quarter of 1999 and is presented separately in the accompanying
consolidated statements of income.
During the first quarter of 2000, we sold the remainder of our portfolio
of paging company securities. We realized a gain of $24.9 million on these
sales. This gain was largely attributable to a general increase in the market
value of paging companies triggered by an announcement made by one paging
company in February 2000 that had a favorable impact on the market value of
public paging company securities.
During 2000, we sold our equity investment in a gas compression company
and realized a pre-tax gain of $91.1 million.
During 2001, we wrote down the cost basis of certain equity securities to
their fair value. The fair value of these equity securities had declined below
our cost basis, and we determined that the decline was other than temporary. The
amount of the write down totaled $11.1 million, of which $9.6 million related to
a cost method investment. The write down is included in other income (expense).
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of results of operations and financial
condition are based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States (GAAP). The preparation of these consolidated financial statements
requires us to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses, and related disclosure of contingent
assets and liabilities. We evaluate our estimates on an on-going basis,
including those related to bad debts, inventories, investments, customer
accounts, goodwill, intangible assets, income taxes, pensions and other
post-retirement benefits, and contingencies and litigation. We base our
estimates on historical experience and on various other assumptions that are
believed to be reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Actual results may differ from
these estimates under different assumptions or conditions.
Note 2 of the "Notes to Consolidated Financial Statements" includes a
summary of the significant accounting policies and methods used in the
preparation of our consolidated financial statements. The following is a brief
description of the more significant accounting policies and methods used by us.
Regulatory Accounting
---------------------
We currently apply accounting standards for our regulated utility
operations that recognize the economic effects of rate regulation in accordance
with SFAS No. 71, "Accounting for the Effects of Certain Types of
34
Regulation" and, accordingly, have recorded regulatory assets and liabilities
when required by a regulatory order or based on regulatory precedent.
Regulatory assets represent probable future revenue associated with
certain costs that will be recovered from customers through the rate-making
process. Regulatory liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers through the
rate-making process. We have recorded these regulatory assets and liabilities in
accordance with SFAS No. 71. If we were required to terminate application of
SFAS No. 71 for all of our regulated operations, we would have to record the
amounts of all regulatory assets and liabilities in our consolidated statements
of income at that time. As of December 31, 2001, this would reduce our earnings
by $352.0 million, net of applicable income taxes.
SFAS No. 71 applies to our fossil generation, nuclear generation, and
customer operations business segments. We do not anticipate the discontinuation
of SFAS No. 71 in the foreseeable future. See "-- Other Information -- Electric
Utility -- Competition and Deregulation" and "-- Other Information -- Electric
Utility -- Stranded Costs" for additional discussion of the application of SFAS
No. 71.
Revenue Recognition
-------------------
Energy Sales:
Energy sales are recognized as services are rendered and include an
estimate for energy delivered but unbilled at the end of each year, except for
power marketing. Power marketing activities are accounted for under the
mark-to-market method of accounting. Under this method, changes in the portfolio
value are recognized as gains or losses in the period of change. The net
mark-to-market change is included in energy sales in our consolidated statements
of income. The resulting unrealized gains and losses are recorded as energy
trading assets and liabilities on our consolidated balance sheets.
We primarily use quoted market prices to value our power marketing and
energy trading contracts. When market prices are not readily available or
determinable, we use alternative approaches, such as model pricing. The market
prices used to value these transactions reflect our best estimate considering
various factors, including closing exchange and over-the-counter quotations,
time value and volatility factors underlying the commitments. Results actually
achieved from these activities could vary materially from intended results and
could unfavorably affect our financial results. Financially settled trading
transactions are reported on a net basis, reflecting the financial nature of
these transactions. Physically settled trading transactions are recorded on a
gross basis in operating revenues and fuel and purchased power expense.
Monitored Services Revenues:
Monitored services revenues are recognized when security services are
provided. Installation revenue, sales revenues on equipment upgrades and direct
costs of installations and sales are deferred for residential customers with
service contracts. For commercial customers and national account customers,
revenue recognition is dependent upon each specific customer contract. In
instances when the company sells the equipment outright, revenues and costs are
recognized in the period incurred. In cases where there is no outright sale,
revenues and direct costs are deferred and amortized.
Deferred installation revenues and system sales revenues will be
recognized over the expected useful life of the customer. Deferred costs in
excess of deferred revenues will be recognized over the contract life. To the
extent deferred costs are less than deferred revenues, such costs are recognized
over the customers' estimated useful life.
Deferred revenues also result from customers who are billed for
monitoring, extended service protection and patrol and response services in
advance of the period in which such services are provided, on a monthly,
quarterly or annual basis.
35
Depreciation
------------
Utility plant is depreciated on the straight-line method at the lesser of
rates set by the KCC or rates based on the estimated remaining useful lives of
the assets, which are based on an average annual composite basis using group
rates that approximated 3.03% during 2001, 2.99% during 2000 and 2.92% during
1999. In its rate order of July 25, 2001, the KCC extended the recovery period
for our generating assets, including Wolf Creek, for regulatory rate making
purposes. The impact of this decision reduced our retail electric rates by
approximately $17.6 million on an annual basis. We intend to file an application
for an accounting authority order with the KCC to allow the creation of a
regulatory asset for the difference between our book and regulatory
depreciation. We cannot predict whether the KCC will approve our application.
Non-utility property, plant and equipment is depreciated on a
straight-line basis over the estimated useful lives of the related assets. We
periodically evaluate our depreciation rates considering the past and expected
future experience in the operation of our facilities.
Depreciable lives of property, plant and equipment are as follows:
Utility:
Fossil generating facilities............................. 10 to 48 years
Nuclear generating facilities............................ 38 years
Transmission facilities.................................. 27 to 65 years
Distribution facilities.................................. 14 to 65 years
Other.................................................... 3 to 50 years
Non-utility:
Buildings................................................ 40 years
Installed systems........................................ 10 years
Furniture, fixtures and equipment........................ 5 to 10 years
Leasehold improvements................................... 5 to 10 years
Vehicles................................................. 5 years
Data processing and telecommunications................... 1 to 7 years
Valuation of Customer Account Intangible Assets
-----------------------------------------------
Customer accounts are stated at cost. Goodwill represents the excess of
the purchase price over the fair value of net assets acquired by Protection One
and Protection One Europe. These assets are tested for impairment in accordance
with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," on a periodic basis or as circumstances
warrant. For purposes of this impairment testing, goodwill is considered to be
directly related to the acquired customer accounts. Factors we consider
important that could trigger an impairment review include the following:
. high levels of customer attrition;
. continuing recurring Monitored Services losses; and
. declines in the market value of Protection One's publicly traded
equity and debt securities.
An impairment would be recognized when the undiscounted expected future
operating cash flows by customer pool derived from customer accounts is less
than the carrying value of capitalized customer accounts and related goodwill.
Protection One and Protection One Europe have performed impairment tests on
their customer account assets and goodwill as of December 31, 2001. These tests
have indicated that future estimated undiscounted cash flows exceeded the sum of
the recorded balances for customer accounts and goodwill. See "-- Summary of
Significant Items -- Impairment Charge Pursuant to New Accounting Rules" for a
discussion of the impairment recorded on these assets in the first quarter of
2002 pursuant to the adoption of new accounting rules.
36
Income Taxes
------------
As part of the process of preparing our consolidated financial statements
we are required to estimate our income taxes in each of the jurisdictions in
which we operate. Significant management judgment is required in determining our
provision for income taxes and our deferred tax assets and liabilities. This
process involves us estimating our actual current tax exposure together with
assessing temporary differences resulting from differing treatment of items,
such as depreciation and amortization, for tax and accounting purposes. These
differences result in deferred tax assets and liabilities, which are included
within our consolidated balance sheet. We must then assess the likelihood that
our deferred tax assets will be recovered from future taxable income. To the
extent we believe that recovery is not likely, we must establish a valuation
allowance. At the current time, we believe our deferred tax assets will be
recovered from future taxable income. In the event that actual results differ
from these estimates, or we adjust these estimates in future periods, we may
need to establish a valuation allowance that could materially impact our
financial position and results of operations.
Cumulative Effect of Accounting Change
--------------------------------------
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and
138 (collectively, SFAS No. 133). We use derivative instruments (primarily
swaps, options and futures) to manage interest rate exposure and the commodity
price risk inherent in fossil fuel purchases and electricity sales. Under SFAS
No. 133, all derivative instruments, including our energy trading contracts, are
recorded on our consolidated balance sheet as either an asset or liability
measured at fair value. Changes in a derivative's fair value must be recognized
currently in earnings unless specific hedge accounting criteria are met. Cash
flows from derivative instruments are presented in net cash flows from operating
activities.
Derivative instruments used to manage commodity price risk inherent in
fuel purchases and electricity sales are classified as energy trading contracts
on our consolidated balance sheet. Energy trading contracts representing
unrealized gain positions are reported as assets; energy trading contracts
representing unrealized loss positions are reported as liabilities.
Prior to January 1, 2001, gains and losses on our derivatives used for
managing commodity price risk were deferred until settlement. These derivatives
were not designated as hedges under SFAS No. 133. Accordingly, on January 1,
2001, we recognized an unrealized gain of $18.7 million, net of $12.3 million of
tax. This gain is presented on our consolidated statement of income as a
cumulative effect of a change in accounting principle.
After January 1, 2001, changes in fair value of all derivative instruments
used for managing commodity price risk that are not designated as hedges are
recognized in revenue as discussed above under "-- Revenue Recognition -- Energy
Sales." Accounting for derivatives under SFAS No. 133 will increase volatility
of our future earnings.
OPERATING RESULTS
Western Resources Consolidated
------------------------------
2001 compared to 2000:
We reported losses per share of $0.31 in 2001 compared to earnings per
share of $1.96 in 2000. This decrease resulted from decreased electricity sales
caused by milder weather, the decrease in electric rates in accordance with the
July 25, 2001 KCC rate order, higher operating losses at Protection One and
Protection One Europe, and the fourth quarter charge related to a work force
reduction. Additionally, investment earnings and the extraordinary gains on the
retirement of debt were lower in 2001 than in 2000.
37
2000 compared to 1999:
Earnings per share were $1.96 in 2000 compared to $0.20 in 1999. This
increase is primarily attributable to increased earnings from the sale of
investments and the extraordinary gain on the retirement of Protection One
bonds. This increase was partially offset by a change in the estimated life of
goodwill and operating losses from our monitored services segment.
Business Segments
-----------------
Our business is segmented based on differences in products and services,
production processes and management responsibility. Based on this approach, we
have identified five reportable segments: Fossil Generation, Nuclear Generation,
Customer Operations, Monitored Services and Other. The Fossil Generation,
Nuclear Generation and Customer Operations segments comprise our electric
utility business. Fossil Generation produces power for sale internally to the
Customer Operations segment and externally to wholesale customers. A component
of our Fossil Generation segment is power marketing, which attempts to minimize
commodity price risk associated with fuel purchases and purchased power
requirements. Power marketing also attempts to maximize utilization of
generation capacity and enhance system reliability through sales to external
customers as discussed further below. Nuclear Generation represents our 47%
ownership in the Wolf Creek Generating Station (Wolf Creek). This segment has
only internal sales because it provides all of its power to its co-owners. The
Customer Operations segment consists of the transmission and distribution of
power to our retail customers in Kansas and the customer service provided to
these customers and the transmission of wholesale energy. Monitored Services is
comprised of our security alarm monitoring business in North America and Europe.
Other includes a 45% interest in ONEOK, investments in international power
generation facilities and other investments, which in the aggregate are not
material to our business or results of operations.
We manage our business segments' performance based on their earnings
before interest and taxes (EBIT). EBIT does not represent cash flow from
operations as defined by GAAP, should not be construed as an alternative to
operating income and is indicative neither of operating performance nor cash
flows available to fund our cash needs. Items excluded from EBIT are significant
components in understanding and assessing our financial performance. We believe
presentation of EBIT enhances an understanding of financial condition, results
of operations and cash flows because EBIT is used by us to satisfy our debt
service obligations, capital expenditures and other operational needs, as well
as to provide funds for growth. Our computation of EBIT may not be comparable to
other similarly titled measures of other companies.
Electric Utility:
Our electric utility operations supply electric energy at retail to
approximately 640,000 customers in Kansas. These customers are classified as
residential, commercial and industrial as defined in our tariffs. Sales
classifications and the related descriptions for our remaining electricity sales
are as follows:
. Wholesale and Interchange: Sales consist of electric energy supplied
to the electric distribution systems of 63 Kansas cities and 4 rural
electric cooperatives. It also includes contracts for the sale,
purchase or exchange of electricity with other utilities and/or
marketers.
. Power Marketing: Sales made in areas outside of our historical
marketing territory. These sales are non-asset based, which means
that we do not use power produced by our generating facilities for
these sales.
. System Marketing: Financial transactions entered into on behalf of
system requirements.
. Other: Includes public street and highway lighting and miscellaneous
electric revenues.
Many things will affect our future electric sales. Our regulated electric
utility sales are significantly impacted by such things as the weather,
regulation (including rate regulation), customer conservation efforts, wholesale
demand, the overall economy of our service area, the City of Wichita's attempt
to create a municipal electric utility, and competitive forces. Our sales are
impacted by demand outside our service territory, the cost of fuel and purchased
power, price volatility and available generation capacity.
38
Our electric sales for the last three years ended December 31 are as
follows:
2001 2000 1999
---------- ---------- ----------
(In Thousands)
Residential .......................... $ 419,492 $ 452,674 $ 407,371
Commercial ........................... 380,277 367,367 356,314
Industrial ........................... 244,392 252,243 251,391
Other ................................ 50,669 49,629 46,306
---------- ---------- ----------
Total retail .................... $1,094,830 $1,121,913 $1,061,382
Wholesale and Interchange ............ 233,129 214,721 174,895
Power Marketing ...................... 408,242 457,178 190,101
System Marketing ..................... 32,192 35,321 3,320
---------- ---------- ----------
Total ........................... $1,768,393 $1,829,133 $1,429,698
========== ========== ==========
The following tables reflect changes in electric sales volumes, as
measured by megawatt hours (MWh), for the years ended December 31, 2001, 2000
and 1999. No amounts are included for power marketing and system marketing sales
because these sales are not based on electricity we generate.
2001 2000 % Change
------ ------ --------
(Thousands of MWh)
Residential ...................................... 5,755 6,222 (7.5)
Commercial ....................................... 6,742 6,485 4.0
Industrial ....................................... 5,617 5,820 (3.5)
Other ............................................ 107 108 (0.9)
------ ------
Total retail ................................ 18,221 18,635 (2.2)
Wholesale and Interchange ........................ 7,547 6,892 9.5
------ ------
Total ....................................... 25,768 25,527 0.9
====== ======
2000 1999 % Change
------ ------ --------
(Thousands of MWh)
Residential ...................................... 6,222 5,551 12.1
Commercial ....................................... 6,485 6,202 4.6
Industrial ....................................... 5,820 5,743 1.3
Other ............................................ 108 108 --
------ ------
Total retail ................................ 18,635 17,604 5.9
Wholesale and Interchange ........................ 6,892 5,617 22.7
------ ------
Total ....................................... 25,527 23,221 9.9
====== ======
2001 compared to 2000: Energy sales decreased $60.7 million, or 3%.
---------------------
Residential sales declined 7% and power marketing sales declined 11%.
Residential sales decreased due to weather conditions and our rate decrease,
while power marketing sales decreased because of lower prices and more power
available in the market. Cost of sales increased $5.3 million, or 1%, over 2000.
As a result gross profit decreased $66.0 million, or 7%.
This decline in gross profit is partly due to how we were required to
record a gain on certain fuel derivatives acquired in 2000 to mitigate the risk
of changing prices on our natural gas fuel requirements. Prior to the adoption
of SFAS No. 133 on January 1, 2001, gains and losses on these fuel derivatives
were deferred until settlement and reflected in gross profit at that time.
However, upon adoption of SFAS No. 133, we were required to report our $31.0
million gain on these contracts as of that date as a cumulative effect of a
change in accounting principle. This gain is reported on our consolidated
statements of income on a net-of-tax basis below income tax expense. We are not
permitted to reflect the cumulative effect of an accounting change in gross
profit. As a result, the benefit of our efforts in 2000 to mitigate the risk of
price changes on our 2001 fuel requirements is not reflected in gross profit.
39
Had we been permitted to classify this as a reduction to cost of sales,
our $66.0 million decline in gross profit would have been reduced by $31.0
million. All gains and losses after January 1, 2001 on our fuel derivatives that
are not designated as hedges are reflected in gross profit.
2000 compared to 1999: Electric operations gross profit increased $28.3
---------------------
million, or 3%. The increase is due primarily to increased power marketing
sales. Electric operations gross profit as a percentage of sales decreased to
54% from 67% primarily due to higher fuel and purchased power prices. (See "--
Other Information -- Market Risk Disclosure" for further discussion.)
Additionally, we experienced a 12% increase in residential sales volumes
and a 23% increase in wholesale and interchange sales volumes. The increase in
residential sales was primarily due to increased demand caused by warm weather.
Cooling-degree days increased by 27%. The increase in wholesale and interchange
sales volumes was primarily due to increased wholesale market opportunities.
Items included in energy cost of sales are fuel expense, purchased power
expense (electricity we purchase from others for resale) and power marketing
expense. Partially offsetting the higher sales was an increase of $371.2 million
in cost of sales primarily due to higher power marketing expense of $263.0
million and increased fuel and purchased power expenses of approximately $75.1
million. Fuel and purchased power expenses were higher primarily due to
increased commodity prices, increased demand from retail customers because of
warmer weather and higher wholesale and interchange sales volumes.
Fossil Generation:
-----------------
Fossil Generation's external sales consist of the power produced and
purchased for sale to wholesale customers and includes power marketing sales,
system marketing sales and wholesale and interchange sales. Internal sales
consist of the power produced for sale to Customer Operations. Details
concerning our earnings before interest and taxes attributable to fossil
generation are as follows.
For the years ended December 31,
--------------------------------
2001 2000 1999
-------- -------- --------
(In Thousands)
Fossil Generation:
External sales ........................ $667,953 $705,536 $365,311
Internal sales (a) .................... 560,528 572,533 546,683
Depreciation and amortization ......... 65,875 60,331 55,320
EBIT (b) .............................. 120,530 202,744 219,087
----------
(a) When sales are made between the segments, the internal transfer price is
determined by us using internally developed transfer pricing estimates
that, while not based on market rates, represent what we believe would be
market prices for capacity and energy.
(b) EBIT for 2001 does not include the unrealized gain on derivatives reported
as a cumulative effect of a change in accounting principle as explained
above. If the effect had been included, EBIT for the Fossil Generation
segment for the year ended December 31, 2001 would have been $151.6
million.
2001 compared to 2000: External sales decreased $37.6 million primarily
----------------
due to a decrease in power marketing sales of $48.9 million, or 11%, and a
decrease in system marketing sales of $3.1 million, or 9%. These decreases were
partially offset by an increase in wholesale and interchange sales of $18.4
million, or 9%. The decrease in power marketing sales was primarily due to lower
market demand and prices. EBIT decreased $82.2 million primarily due to
decreased sales, a $30.8 million non-cash mark-to-market adjustment on fuel
derivatives and increased fuel and purchased power expenses. Had SFAS No. 133
permitted us to include the cumulative gain effect in gross profit, EBIT would
have decreased $51.2 million.
2000 compared to 1999: External sales increased $340.2 million primarily
---------------------
due to power marketing sales, which increased by $267.1 million, wholesale and
interchange sales, which increased by $39.8 million, and system
40
marketing sales, which increased by $32.0 million. Since 1997, we have gradually
increased the size of our power trading operation in an effort to better utilize
our market knowledge and to mitigate the risk associated with energy prices.
While sales increased significantly, EBIT was $16.3 million lower because
of higher cost of sales. Cost of sales was $371.2 million higher primarily due
to higher power marketing expense of $263.0 million, increased fuel and
purchased power expenses of approximately $71.6 million and system marketing
transaction costs of approximately $33.1 million.
Fuel and purchased power expenses were higher primarily due to increased
commodity prices, increased demand from retail customers because of warmer
weather and higher wholesale and interchange sales volumes.
The cost of fuel in 2000 was significantly affected by increased gas costs
of $13.3 million (despite a 9% reduction in MMBtu of gas burned). Our average
natural gas price increased 45% during the year compared to 1999. Additionally,
coal costs increased by $35.1 million, primarily due to increasing the
quantities of coal burned in our efforts to minimize gas costs, and cost of oil
increased $7.2 million, primarily due to increased price and increasing the
quantities of oil burned. See "-- Other Information -- Market Risk Disclosure"
for further discussion.
Nuclear Generation:
------------------
Nuclear Generation has only internal sales because all of its power is
provided to its co-owners: KGE, Kansas City Power and Light Company (KCPL) and
Kansas Electric Power Cooperative, Inc. KGE owns 47% of Wolf Creek Nuclear
Operating Corporation (WCNOC), the operating company for Wolf Creek. Details
concerning our earnings before interest and taxes attributable to our nuclear
generation are as follows:
For the years ended December 31,
-------------------------------------
2001 2000 1999
--------- --------- ---------
(In Thousands)
Nuclear Generation:
Internal sales (a) ........................ $ 117,659 $ 107,770 $ 108,445
Depreciation and amortization ............. 41,046 40,052 39,629
Earnings (losses) before interest
and taxes ............................... (19,078) (24,323) (25,214)
----------
(a) When sales are made between the segments, the internal transfer price is
determined by us using internally developed transfer pricing estimates
that, while not based on market rates, represent what we believe would be
market prices for capacity and energy.
Wolf Creek operated the entire year of 2001 without any refueling outages.
Wolf Creek shut down for 38 days beginning on September 29, 2000 for its
eleventh scheduled refueling and maintenance outage. Internal sales and EBIT
increased during 2001 since the unit operated more during 2001 than during 2000.
During 1999, there was a 36-day refueling and maintenance outage at Wolf Creek.
Since both 2000 and 1999 had refueling outages, the change in internal sales and
EBIT between 2000 and 1999 was immaterial.
Wolf Creek has a scheduled refueling and maintenance outage approximately
every 18 months. An outage began on March 23, 2002. During an outage, Wolf Creek
produces no power for its co-owners; therefore internal sales, EBIT and nuclear
fuel expense decrease.
Customer Operations:
-------------------
Customer Operations' external sales consist of the transmission and
distribution of power to our electric retail and wholesale customers. Internal
sales consist of the intra-segment transfer price charged to Fossil Generation
and Nuclear Generation for the use of the distribution lines and transformers.
41
For the years ended December 31,
--------------------------------------
2001 2000 1999
---------- ---------- ----------
(In Thousands)
Customer Operations:
External sales .................. $1,100,443 $1,123,590 $1,064,385
Internal sales (a) .............. 317,056 291,927 293,522
Depreciation and amortization ... 78,235 75,419 71,717
EBIT ............................ 131,917 171,872 145,603
----------
(a) When sales are made between the segments, the internal transfer price is
determined by us using internally developed transfer pricing estimates
that, while not based on market rates, represent what we believe would be
market prices for capacity and energy.
2001 compared to 2000: External sales decreased $23.1 million, or 2%, and
---------------------
EBIT decreased $40.0 million, or 23%, as a result of less favorable weather
conditions and rate reductions ordered by the KCC. Weather conditions resulted
in an approximate 8% decrease in residential sales volumes. In our service
territory, the heating season of 2001 was warmer than the heating season of
2000, which caused customers to use less energy heating their homes during the
winter. Additionally, the cooling season of 2001 was cooler than in 2000, which
caused customers to use less energy to cool their homes during the summer.
2000 compared to 1999: External sales increased $59.2 million, or 6% and
---------------------
EBIT increased $26.3 million, or 18%. We experienced a 12% increase in
residential sales volumes primarily due to a 27% increase in cooling-degree days
and a 15% increase in heating-degree days, which increased the demand for power
on our system.
Monitored Services:
Protection One and Protection One Europe comprise our monitored services
business segment. The results discussed below reflect Monitored Services on a
stand-alone basis. These results do not take into consideration Protection One's
minority interest of approximately 13% at December 31, 2001 and 15% at December
31, 2000 and 1999. Details concerning our earnings before interest and taxes
attributable to our monitored services segment are as follows:
For the years ended December 31,
-------------------------------------
2001 2000 1999
--------- --------- ---------
(In Thousands)
External sales ............................... $ 416,509 $ 537,859 $ 599,105
Depreciation and amortization ................ 228,123 248,414 233,906
Earnings (losses) before interest and taxes .. (126,076) (91,370) (20,675)
2001 compared to 2000: Sales decreased $121.4 million primarily due to a
---------------------
decline in Monitored Services' average customer base and the disposition of
certain operations. Monitored Services experienced a net decline of 267,347
customers in 2001. This decrease in customers is primarily attributable to
customer attrition and a decrease of 63,875 customers due to the disposition of
operations. Additionally, the number of Protection One customers declined by
62,443 customers due to the conversion of accounts to a common billing and
monitoring system. This new system reports number of customer accounts on the
basis of one customer for every location provided service even if Protection One
has separate contracts to provide multiple services at that location. Previous
systems utilized a number of different billing and monitoring software programs,
some of which would count each separate contracted service as a separate account
regardless of the location. Protection One's customer acquisition strategies
have not been able to generate accounts in a sufficient volume at an acceptable
cost to replace accounts lost through attrition. See "-- Other Information --
Monitored Services -- Attrition" below for discussion regarding attrition.
Protection One expects this trend will continue until the efforts it is making
to acquire new accounts and reduce attrition become more successful than they
have been to date. Until it is able to reverse this trend, net losses of
customer accounts will materially and adversely affect its business, financial
condition and results of operations. In
42
2001, Protection One focused on the completion of its infrastructure projects,
cost reductions, the development of cost effective marketing programs and the
generation of positive cash flow.
Loss before interest and taxes increased $34.7 million due primarily to
the decrease in sales. Cost of sales decreased $41.6 million primarily due to
the discontinuation of Protection One's Patrol services in May 2001,
consolidation of Protection One customer monitoring facilities, a reduction of
Protection One's telecommunications expense, consolidation of monitoring and
customer service functions and the decline in customer accounts caused by
dispositions of operations and attrition. See "-- Other Information -- Monitored
Services -- Attrition" below for additional information.
2000 compared to 1999: Sales decreased $61.0 million primarily due to a
---------------------
decline in customer base and the effect of the adoption of Staff Accounting
Bulletin (SAB) No. 101, "Revenue Recognition." Adoption of SAB No. 101 reduced
revenue by $10.9 million. In North America, Protection One had a net decrease of
141,527 customers in 2000 as compared to a net increase of 8,595 customers in
1999. The decrease in customers is primarily attributable to the fact that
Protection One's present customer acquisition strategies were not able to
generate accounts in a sufficient volume at acceptable costs to replace accounts
lost through attrition. Protection One expects this trend will continue until
the efforts it is making to acquire new accounts and reduce attrition become
more successful than they have been to date. Until Protection One is able to
reverse this trend, net losses of customer accounts will materially and
adversely affect its business, financial condition and results of operations. In
2000, Protection One focused on the completion of its infrastructure projects,
the development of cost effective marketing programs, the development of its
commercial business and the generation of positive cash flow. Protection One
Europe had a net increase of 9,115 customers. The increase was primarily due to
internal marketing efforts.
Losses before interest and taxes increased $70.7 million due to lower
sales, higher cost of sales and lower other income. Cost of sales increased $5.7
million due to increased compensation costs for additional personnel hired at
Protection One's monitoring centers, an increase in the cost of parts and
materials, and increased vehicle costs. Other income decreased because
Protection One recorded a $17.2 million gain on the sale of the Mobile Services
Group in the third quarter of 1999.
Depreciation and amortization expense increased by $14.5 million primarily
due to the change in the estimated life of goodwill which was reduced from 40
years to 20 years.
Operating and maintenance expense decreased $13.6 million primarily due to
declines in third party monitoring costs, signs and decals, printing and
compensation expenses. These decreases are a direct result of the significant
decline in the number of new accounts acquired during 2000 primarily due to the
restructuring of Protection One's dealer program.
WESTERN RESOURCES CONSOLIDATED
The following discussion addresses changes in other items affecting net
income but not affecting gross profit. Where a specific distinction based on
segment cannot be determined for the items below, an allocation percent is used
to determine the amounts to be applied to the segments for the calculation of
EBIT. Since actual amounts for these items are not maintained by segment, they
are discussed below in relation to the company as a whole, rather than as they
may relate to specific reporting segments.
Operating Expenses
------------------
2001 compared to 2000:
In 2001, operating expenses increased $12.7 million primarily as a result
of approximately $8.7 million of costs associated with the PNM transaction,
approximately $28.5 million in employee-severance costs related to the work
force reductions, and approximately $13.1 million associated with the
dispositions of monitored services operations. Partially offsetting these
increased costs were decreases in Monitored Services' depreciation and
amortization expense of $20.3 million and reduced acquisition expenses of $7.8
million. The decline in depreciation
43
and amortization expense is primarily due to the accelerated depreciation of the
billing and general ledger system Protection One used in 2000 and the change in
the method of amortization utilized. The reduction in acquisition expense is
primarily due to the reduced level of account acquisitions in 2001 as compared
to 2000.
2000 compared to 1999:
Operating expenses increased $13.7 million primarily due to increased
depreciation and amortization expense of $22.7 million, of which $14.5 million
relates to Monitored Services operations. Offsetting this increase is a $17.6
million charge in 1999 for deferred KCPL merger costs related to termination of
the KCPL merger. Selling, general and administrative expenses were also higher
due to a reduction of $5.6 million in 1999 related to international power
development costs.
Other Income (Expense)
----------------------
2001 compared to 2000:
Other income was $57.6 million in 2001 compared to $201.0 million in 2000.
Other income in 2001 includes $41.8 million of ONEOK investment income, a $5.3
million pre-tax gain related to the sale of Paradigm Direct LLC (Paradigm) and
$7.6 million of interest income. These earnings were partially offset by
impairment charges of $11.1 million recorded for declines in the value of
marketable securities and other investments that were considered other than
temporary in nature. The other income in 2000 includes $45.3 million of ONEOK
investment income, a $91.1 million pre-tax gain on the sale of our investment in
a gas compression company, a $24.9 million pre-tax gain on the sale of
investments in paging companies, $7.8 million in equity earnings on investments
and $9.8 million of interest income.
2000 compared to 1999:
Other income increased $214.4 million primarily due to gains recorded in
2000 of $91.1 million on the sale of our remaining investment in a gas
compression company and $24.5 million on the sale of marketable securities.
During 1999, a special charge of $76.2 million was recorded related to our
paging securities portfolio and a gain of $17.2 million was recorded on the sale
of Protection One's Mobile Services Group.
Interest Expense
----------------
2001 compared to 2000:
Interest expense decreased $21.3 million due to lower interest rates and
lower outstanding debt at Protection One. The weighted average interest rate on
our revolving credit facility declined to 3.44% at December 31, 2001 from 8.11%
at December 31, 2000.
2000 compared to 1999:
We retired long-term debt during 2000 and 1999, causing long-term debt
interest expense to decrease by $10.0 million for the year ended December 31,
2000. The retirements included Western Resources' first mortgage bonds of $125
million in 1999 and $75 million in 2000. In the fourth quarter of 1999 and
during 2000, Protection One retired bonds with an aggregate face value of $237.9
million. For more information, see "-- Liquidity and Capital Resources" below.
Short-term debt interest expense was $5.5 million higher due to increased
short-term borrowings under our credit facilities. The majority of this
short-term debt was repaid in the third quarter of 2000 with proceeds from the
$600 million term loan.
44
Income Taxes
------------
2001 compared to 2000:
Income taxes decreased $126.9 million in 2001 compared to 2000. This was
primarily due to the decreased earnings before income taxes in 2001 resulting
from the factors discussed previously. Our overall effective tax rate changed
from a 33.6% expense in 2000 to a 56.3% benefit in 2001. The change in our
effective tax rate was primarily due to decreased earnings before income taxes
in 2001. The tax benefit from decreased earnings combined with our net tax
benefits from dividends received, low income housing tax credits, the
amortization of prior years' investment tax credits, the amortization of
non-deductible goodwill, and the tax benefits from corporate-owned life
insurance created this change in the effective tax rate.
2000 compared to 1999:
Income taxes increased $78.3 million in 2000 compared to 1999. This was
primarily due to the increased earnings before income taxes in 2000 resulting
from the factors discussed previously. Our overall effective tax rate increased
from a 108.6% benefit in 1999 to a 33.6% expense in 2000. The increase in our
effective tax rate was primarily due to increased earnings before income taxes
in 2000. This increase in earnings before income taxes reduces the impact of our
net tax benefits (as mentioned previously) on the effective tax rate.
LIQUIDITY AND CAPITAL RESOURCES
Overview
--------
Most of our cash requirements consist of capital expenditures and
maintenance costs associated with the electric utility business, cash needs of
our monitored services business, debt service and cash payments of common stock
dividends. Our ability to attract necessary financial capital on reasonable
terms is critical to our overall business plan. Historically, we have paid for
these items with cash from operations and the issuance of stock or long- or
short-term debt. Our ability to provide the cash, stock or debt to fund our
capital expenditures depends upon many things, including available resources,
our financial condition and current market conditions.
We had $96.7 million in cash and cash equivalents at December 31, 2001. We
consider cash equivalents to be highly liquid investments with a maturity of
three months or less when purchased. We also had $14.8 million of restricted
cash classified as a current asset. The current asset portion of our restricted
cash consists primarily of cash held in escrow as required by certain letters of
credit. In addition, we had $38.5 million of restricted cash classified as a
long-term asset. The long-term restricted cash consists primarily of $34.1
million cash held in escrow as required by the terms of a pre-paid capacity and
transmission agreement and $4.4 million cash used to collateralize letters of
credit and cash held in escrow.
At December 31, 2001, current maturities of long-term debt increased
$118.8 million from 2000 primarily because $100 million of our first mortgage
bonds due August 15, 2002 were moved to current maturities.
On June 28, 2000, we entered into a $600 million, multi-year term loan
that replaced two revolving credit facilities that matured on June 30, 2000. We
had $591 million outstanding on the term loan at December 31, 2001. The term
loan is secured by our and KGE's first mortgage bonds and has a maturity date of
March 17, 2003. The term loan agreement contains requirements for maintaining
certain consolidated leverage ratios, interest coverage ratios and consolidated
debt to capital ratios. At December 31, 2001, we were in compliance with all of
these requirements. In January 2002, we repaid $44 million of the term loan with
the proceeds of our sale of investments in low income housing tax credit
partnerships. The outstanding balance of the term loan after this prepayment was
$547 million. In March 2002, we entered into an amendment to the term loan that
adds to the calculation of consolidated earnings before interest, taxes,
depreciation and amortization, the severance costs incurred in the fourth
quarter of 2001 and the first quarter of 2002 related to our work force
reductions, and maintains the current maximum consolidated leverage ratio of
5.75 to 1.0 through the maturity date of the term loan in March 2003. We expect
to be in compliance with all covenants through the remaining term of this
agreement.
45
Maturities of the term loan through March 17, 2003 are as follows:
Principal
Amount
Year (In Thousands)
---- --------------
2002 $ 6,000
2003 541,000
------------
$ 547,000
============
Interest on the term loan is payable on the expiration date of each
borrowing under the facility or quarterly if the term of the borrowing is
greater than three months. For the year ended December 31, 2001, the weighted
average interest rate on the term loan, including amortization of fees and
interest swaps was 7.9%.
Effective October 4, 2001, we entered into a $500 million interest rate
swap agreement with a term of two years. The effect of the swap agreement is to
fix the annual interest rate on the term loan at 6.18%. At December 31, 2001,
the variable rate associated with this debt was 4.68%. This reduces our interest
rate exposure due to variable rates. The swap is being accounted for as a cash
flow hedge.
We also have an arrangement with certain banks to provide a revolving
credit facility on a committed basis totaling $500 million. The facility is
secured by our and KGE's first mortgage bonds and matures on March 17, 2003.
Borrowings on this facility were $222.3 million at December 31, 2001 and $366.0
million at March 21, 2002. Under the terms of the agreement, we are required,
among other restrictions, to maintain a total debt to total capitalization ratio
of not greater than 65% at all times. We are in compliance with this covenant.
At December 31, 2001, the capitalization ratio was 61.4%. Under the terms of the
facility, the impairment charge to be recorded in the first quarter of 2002 will
not affect compliance with this covenant in future periods.
We have registered securities for sale with the Securities and Exchange
Commission (SEC). As of December 31, 2001, these included $400 million of
unsecured senior notes, $500 million of our first mortgage bonds, $50 million of
KGE first mortgage bonds and approximately 11.2 million of our common shares.
Our ability to issue additional debt and equity securities is restricted
under limitations imposed by the Articles of Incorporation and the Mortgage and
Deed of Trusts of Western Resources and KGE.
Our mortgage prohibits additional first mortgage bonds from being issued
(except in connection with certain refundings) unless our unconsolidated net
earnings available for interest, depreciation and property retirement (which as
defined, does not include earnings or losses attributable to the ownership of
securities of subsidiaries), for a period of 12 consecutive months within 15
months preceding the issuance, are not less than the greater of twice the annual
interest charges on, or 10% of the principal amount of, all first mortgage bonds
outstanding after giving effect to the proposed issuance. In addition, the
issuance of bonds is subject to limitations based upon the amount of bondable
property additions. As of December 31, 2001, no additional first mortgage bonds
could be issued under the most restrictive provisions in the mortgage, except in
connection with refundings.
KGE's mortgage prohibits additional first mortgage bonds from being issued
(except in connection with certain refundings) unless KGE's net earnings before
income taxes and before provision for retirement and depreciation of property
for a period of 12 consecutive months within 15 months preceding the issuance
are not less than either two and one-half times the annual interest charges on,
or 10% of the principal amount of, all KGE first mortgage bonds outstanding
after giving effect to the proposed issuance. In addition, the issuance of bonds
is subject to limitations based upon the amount of bondable property additions.
As of December 31, 2001, approximately $279 million principal amount of
additional KGE first mortgage bonds could be issued under the most restrictive
provisions in the mortgage.
46
The table below shows the projected future cash payments for our
contractual obligations existing at December 31, 2001:
Payments Due by Period
At December 31, 2001: ---------------------------------------------------
Contractual Obligations Total 2002 2003 - 2004 2005 - 2006 Thereafter
---------- ---------- ----------- ----------- ----------
(Dollars in Thousands)
Long-term debt ........................... $3,138,958 $ 160,576 $ 1,079,542 $ 406,871 $1,491,969
Operating leases ......................... 830,771 69,897 125,264 119,292 516,318
Fossil fuel .............................. 2,099,778 229,675 323,945 213,718 1,332,440
Nuclear fuel ............................. 84,038 -- 27,449 10,389 46,200
Unconditional purchase obligations (a) ... 10,150 4,060 6,090 -- --
---------- ---------- ----------- ----------- ----------
Total contractual obligations ...... $6,163,695 $ 464,208 $ 1,562,290 $ 750,270 $3,386,927
========== ========== =========== =========== ==========
----------
(a) Represents Protection One's contract tariff for telecommunication
services.
The table below shows our total commercial commitments and the expected
expiration per period:
At December 31, 2001: Amount of Commitment Expiration Per Period
Total Amounts ---------------------------------------------------
Other Commercial Commitments Committed 2002 2003 - 2004 2005 - 2006 Thereafter
------------- ---------- ----------- ----------- ----------
(Dollars in Thousands)
Lines of credit .......................... $ 507,000 $ 7,000 $ 500,000 $ -- $ --
Standby letters of credit ................ 12,687 9,937 -- -- 2,750
----------- ---------- ----------- ----------- ----------
Total commercial commitments ....... $ 519,687 $ 16,937 $ 500,000 $ -- $ 2,750
=========== ========== =========== =========== ==========
Credit Ratings
--------------
Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and
Moody's Investors Service (Moody's) are independent credit-rating agencies that
rate our debt securities. These ratings indicate the agencies' assessment of our
ability to pay interest and principal on these securities. On June 1, 2001,
Moody's placed our ratings under review with direction uncertain. On October 19,
2001, S&P removed us from its CreditWatch listing and changed our and KGE's
ratings outlook to "negative." On November 7, 2001, S&P reaffirmed its negative
outlook for us.
As of March 14, 2002, ratings with these agencies are as follows:
Western
Resources Western KGE Protection One Protection One
Mortgage Resources Mortgage Senior Senior
Bond Unsecured Bond Unsecured Subordinated
Rating Debt Rating Debt Unsecured Debt
--------- --------- -------- -------------- --------------
S&P................ BBB- BB- BB+ B CCC+
Fitch.............. BB+ BB BB+ B CCC+
Moody's............ Ba1 Ba2 Ba1 B3 Caa2
In general, declines in our credit ratings make debt financing more costly
and more difficult to obtain on terms which are economically favorable to us.
Credit rating agencies are applying more stringent guidelines when rating
utility companies due to increasing competition and utility investment in
non-utility businesses. We do not have any credit rating conditions in any of
the agreements under which our debt has been issued.
Sale of Accounts Receivable
---------------------------
On July 28, 2000, we entered into an asset-backed securitization agreement
under which we periodically transfer an undivided percentage ownership interest
in a revolving pool of our accounts receivable arising from the sale of
electricity to a multi-seller conduit administered by an independent financial
institution through the use of a
47
special purpose entity (SPE). We account for this transfer as a sale in
accordance with SFAS No. 140, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishment of Liabilities." The agreement was renewed
on July 26, 2001, and is annually renewable upon agreement by all parties.
Under the terms of the agreement, we may transfer accounts receivable to
the bankruptcy-remote SPE and the conduit must purchase from the SPE an
undivided ownership interest of up to $125 million (and upon request, subject to
certain conditions, up to $175 million), in those receivables. The SPE has been
structured to be legally separate from us, but it is wholly owned and
consolidated. The percentage ownership interest in receivables purchased by the
conduit may increase or decrease over time, depending on the characteristics of
the SPE's receivables, including delinquency rates and debtor concentrations. We
service the receivables transferred to the SPE and receive a servicing fee.
These servicing fees are eliminated in consolidation.
Under the terms of the agreement, the conduit pays the SPE the face amount
of the undivided interest at the time of purchase. Subsequent to the initial
purchase, additional interests are sold and collections applied by the SPE to
the conduit resulting in an adjustment to the outstanding conduit interest.
We record administrative expense on the undivided interest owned by the
conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the
year ended December 31, 2000. These expenses are included in other income
(expense) in our consolidated statements of income.
The outstanding balance of SPE receivables was $43.3 million at December
31, 2001 and $85.5 million at December 31, 2000, which is net of an undivided
interest of $100.0 million and $115.0 million in receivables sold by the SPE to
the conduit. Our retained interest in the SPE's receivables is reported at fair
value and is subordinate to, and provides credit enhancement for, the conduit's
ownership interest in the SPE's receivables. Our retained interest is available
to the conduit to pay any fees or expenses due to the conduit, and to absorb all
credit losses incurred on any of the SPE's receivables. The retained interest is
included in accounts receivable, net, in our consolidated balance sheets.
Cash Flows from (used in) Operating Activities
----------------------------------------------
Our primary sources of operating cash flows are the operations of our
electric utility and monitored services businesses and dividends from our ONEOK
investment. Cash flows from operating activities decreased $187.0 million to
$224.8 million in 2001, from $411.8 million in 2000. This decrease is mostly
attributable to changes in our working capital. Operating cash flows in 2001
also decreased due to the continued decline in Protection One's and Protection
One Europe's customer base, which reduces our recurring monthly cash flow
stream. Operating cash flows also decreased in 2001 as we purchased additional
coal to restock our inventory from the levels that existed in December 2000.
Cash flows from operating activities increased $43.3 million to $411.8
million in 2000, from $368.4 million in 1999. This increase is mostly
attributable to the initial sale of accounts receivable in June 2000 offset by a
decrease in utility gross margin percentage for 2000 compared to 1999. The
decrease in gross margin percentage negatively affected operating cash flows as
our cost of sales for the utility increased at a greater rate than sales in 2000
due to increasing fuel prices and an increase in the use of purchased power.
Cash Flows from (used in) Investing Activities
----------------------------------------------
In general, cash used for investing purposes relates to the growth and
maintenance of the operations of our utility and monitored services businesses.
The utility business is capital intensive and requires significant investment in
plant on an annual basis. We spent $227.0 million in 2001 and $285.4 million in
2000 on net additions to utility property, plant and equipment, including $52.2
million in 2001 and $87.7 million in 2000 on new generation projects. This was
in addition to our normal maintenance requirements. The monitored services
business also requires significant capital investment related to the acquisition
of customer accounts. Investment in customer accounts in 2001 and 2000 amounted
to $36.5 million and $47.3 million, respectively.
Investing cash flows were also impacted significantly by the sale of
marketable security investments and the
48
dispositions of non-strategic monitored services businesses. These activities
produced cash of $50.8 million and $218.6 million in 2001 and 2000,
respectively. We do not expect these to be sources of significant cash in 2002.
Investing activities in 1999 required significantly more cash than in 2000
because Protection One invested $268.4 million in the purchase of customer
accounts and security alarm businesses.
Cash Flows from (used in) Financing Activities
----------------------------------------------
We had a net cash flows from financing activities of $24.5 million in 2001
compared to net cash flows used in financing activities of $328.0 million in
2000. In 2001, an increase in short-term debt was the principal source of cash
flows from financing activities. Cash from financing activities was used to fund
our required investment in operations, the retirement of Protection One's
long-term debt, and the payment of dividends on our common stock. In 2000, we
reduced our annual dividend from $2.14 to $1.20 per share. This reduction, and
continued reinvestment of dividends by our shareholders through the dividend
reinvestment program, resulted in a significant reduction in our net cash
dividend requirements.
Future Cash Requirements
------------------------
We believe that internally generated funds and access to capital markets
will be sufficient to meet our operating and capital expenditure requirements,
debt service and dividend payments through at least the year 2004. Uncertainties
affecting our ability to meet these requirements include the factors affecting
sales described above, the impact of inflation on operating expenses, regulatory
actions, the impact of the rate reduction, our ability to consummate the
financial plan furnished to the KCC and to refinance our outstanding debt
discussed under "-- Summary of Significant Items -- KCC Proceedings and Orders"
above, compliance with future environmental regulations, municipalization
efforts by the City of Wichita and the impact of our monitored services'
operations and financial condition.
Additionally, our ability to access capital markets will affect the new
and existing credit agreements we have available to meet our operating and
capital expenditure requirements, debt service and dividend payments. We have
$160.6 million of long-term debt that will mature in 2002 and $715.4 million of
long-term debt and a $500 million revolving credit facility that will mature in
2003. Additionally, we have $384.3 million of putable/callable bonds that may
either mature in August 2003 or be remarketed and repriced at current rates and
which will mature in 2018. We believe we will be successful in refinancing these
obligations but can give no assurance that these financings will be completed at
similar costs to maturing debt.
We forecast that we will need additional generating capacity of
approximately 150 MW by 2006 to serve our customer's expected electricity needs.
We will determine how to meet this need at a future date.
Our business requires significant capital investments. We currently expect
that through the year 2004, we will need cash mostly for:
. Ongoing utility construction and maintenance programs designed to
maintain and improve facilities providing electric service.
. Improving operations within the monitored services business and the
acquisition of customer accounts.
Capital expenditures for 2001 and anticipated capital expenditures for
2002 through 2004 are as follows:
Fossil Nuclear Customer Monitored
Generation Generation Operations Services Total
---------- ---------- ---------- -------- --------
(In Thousands)
2001 ........... $116,595 $ 27,349 $ 83,052 $ 45,944 $272,940
2002 ........... 58,000 10,000 86,800 41,100 195,900
2003 ........... 70,100 30,100 86,800 43,800 230,800
2004 ........... 69,400 30,100 86,800 47,500 233,800
49
These estimates are prepared for planning purposes and will be revised
from time to time. See Note 2 of the "Notes to Consolidated Financial
Statements." Actual expenditures will differ from our estimates.
Maturities of long-term debt as of December 31, 2001 are as follows:
Principal
Amount
Year ----------
---- (In Thousands)
2002 (a) .................. $ 160,576
2003 ...................... 715,414
2004 ...................... 364,128
2005 ...................... 306,414
2006 ...................... 100,457
Thereafter ................ 1,491,969
----------
$3,138,958
==========
----------
(a) Amount due includes $38.5 million related to the sale of investments
required to be repaid under the mandatory prepayment provisions of our
credit agreement.
Capital Structure
-----------------
Our capital structure at December 31, 2001 and 2000 was as follows:
Pro forma
2001 2000 2001 (a)
---- ---- ---------
Shareholders' equity ........................................... 36% 35% 26%
Preferred stock ................................................ 1 1 1
Western Resources obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely company
subordinated debentures ..................................... 4 4 5
Long-term debt, net ............................................ 59 60 68
--- --- ---
Total .................................................... 100% 100% 100%
=== === ===
----------
(a) Subsequent to December 31, 2001, we recorded an impairment of our goodwill
and customer accounts as more fully described in "-- Summary of
Significant Items -- Impairment Charge Pursuant to New Accounting Rules."
Had that charge occurred prior to year-end, our 2001 capital structure
would have been as shown above in the "Pro forma 2001" column.
Dividend Policy
---------------
Our board of directors reviews our dividend policy from time to time.
Among the factors the board of directors considers in determining our dividend
policy are earnings, cash flows, capitalization ratios, competition and
financial loan covenants. Provisions in our Articles of Incorporation contain
restrictions on the payment of dividends or the making of other distributions on
our common stock while any preferred shares remain outstanding unless certain
capitalization ratios and other conditions are met. We do not expect these
restrictions to have an impact on our ability to pay dividends on our common
stock at the current rate. Our agreement with PNM prohibits an increase in the
dividend paid on our common stock without the consent of PNM.
Debt and Equity Repurchase Plans
--------------------------------
Westar Industries and Protection One may, from time to time, purchase
Protection One's debt and equity securities in the open market or through
negotiated transactions. We, Westar Industries and Protection One may also
50
purchase our debt and equity. The timing and terms of purchases and the amount
of debt or equity actually purchased will be determined based on market
conditions and other factors.
OTHER INFORMATION
Electric Utility
----------------
City of Wichita Municipalization Effort:
In December 1999, the City Council of Wichita, Kansas, authorized the
hiring of an outside consultant to determine the feasibility of creating a
municipal electric utility to replace KGE as the supplier of electricity in
Wichita. The feasibility study was released in February 2001 and estimates that
the City of Wichita would be required to pay us $145 million for our stranded
costs if it were to municipalize. However, we estimate the amount to be
substantially greater. In order to municipalize KGE's Wichita electric
facilities, the City of Wichita would be required to purchase KGE's facilities
or build a separate independent system and arrange for its own power supply.
These costs are in addition to the stranded costs for which the city would be
required to reimburse us. On February 2, 2001, the City of Wichita announced its
intention to proceed with its attempt to municipalize KGE's retail electric
utility business in Wichita. KGE will oppose municipalization efforts by the
City of Wichita. Should the city be successful in its municipalization efforts
without providing us adequate compensation for our assets and lost revenues, the
adverse effect on our business and financial condition could be material.
KGE's franchise with the City of Wichita to provide retail electric
service is effective through December 1, 2002. There can be no assurance that we
can successfully renegotiate the franchise with terms similar, or as favorable,
as those in the current franchise. Under Kansas law, KGE will continue to have
the right to serve the customers in Wichita following the expiration of the
franchise, assuming the system is not municipalized. Customers within the
Wichita, metropolitan area account for approximately 23% of our total energy
sales.
FERC Proceedings:
On September 12, 2001, we filed a settlement between the FERC staff and
Westar Generating, Inc. (Westar Generating), the wholly owned subsidiary that
owns our interests in the State Line generating facility. The settlement
establishes the rate at which we will buy power from Westar Generating. FERC has
jurisdiction over the establishment of this rate because of our affiliate
relationship with Westar Generating. We continue to work toward a global
settlement with the KCC, the only other active party, but can make no assurance
on a resolution.
In September 1999, the City of Wichita filed a complaint with FERC against
us alleging improper affiliate transactions between our KPL division and KGE.
The City of Wichita asked that FERC equalize the generation costs between KPL
and KGE, in addition to other matters. After hearings on the case, a FERC
administrative law judge ruled in our favor confirming that no change in rates
was required. On December 13, 2000, the City of Wichita filed a brief with FERC
asking that the Commission overturn the judge's decision. On January 5, 2001, we
filed a brief opposing the City's position. On November 23, 2001, FERC issued an
order affirming the judge's decision. We anticipate no further activity
regarding this complaint because the City of Wichita's time to appeal FERC's
order has expired.
Competition and Deregulation:
Electric utilities have historically operated in a rate-regulated
environment. Federal and state regulatory agencies having jurisdiction over our
rates and services and other utilities have initiated steps that were expected
to result in a more competitive environment for utility services. The Kansas
Legislature took no action on deregulation in 2001 or 2000.
In a deregulated environment, utility companies that are not responsive to
a competitive energy marketplace may suffer erosion in market share, revenues
and profits. Possible types of competition include cogeneration,
self-generation, retail wheeling, or municipalization. Retail wheeling is the
ability of individual customers to choose a
51
power provider other than us and we would provide the transmission service for
this power. Kansas does not allow retail wheeling and no such regulation is
pending or being considered. However, if retail wheeling were implemented in
Kansas, increased competition for retail electricity sales may reduce our future
electric utility earnings compared to our historical electric utility earnings.
Our rates range from approximately 10% to 20% below the national average for
retail customers. Because of these rates, we expect to retain a substantial part
of our current volume of sales in a competitive environment.
Increased competition for retail electricity sales may in the future
reduce our earnings, which could impact our ability to pay dividends and could
have a material adverse impact on our operations and our financial condition. A
material non-cash charge to earnings may be required should we discontinue
accounting under SFAS No. 71. See "-- Stranded Costs" below for additional
information regarding SFAS No. 71.
The 1992 Energy Policy Act began deregulating the electricity market for
generation. The Energy Policy Act permitted the FERC to order electric utilities
to allow third parties the use of their transmission systems to sell electric
power to wholesale customers. In 1992, we agreed to open access of our
transmission system for wholesale transactions. FERC also requires us to provide
transmission services to others under terms comparable to those we provide
ourselves. In December 1999, FERC issued an order (FERC Order No. 2000)
encouraging formation of regional transmission organizations (RTOs). RTOs are
designed to control the wholesale transmission services of the utilities in
their regions thereby facilitating open and more competitive markets in bulk
power.
After the FERC rejected several attempts by the Southwest Power Pool (SPP)
to seek RTO status, the SPP and the Midwest Independent System Operator (MISO)
agreed in October 2001 to consolidate and form an RTO. In December 2001, the
FERC approved this newly formed MISO as the first RTO. The agreement to
consolidate was executed in February 2002 and the transaction is expected to
close in 2003. This new organization will operate our transmission system as
part of an interconnected transmission system encompassing over 120,000 MW of
generation capacity located in 20 states. MISO will collect revenues
attributable to the use of each member's transmission system, and each member
will be able to transmit power purchased, generated for sale or bought for
resale in the wholesale market throughout the entire MISO system. Although each
member will have priority over the use of its own transmission facilities for
selling power to its wholesale customers or others, each member will be charged
the same uniform transmission rate as other energy suppliers who are able to
sell power to them. We intend to file with the FERC and the KCC to transfer
control over the operation of our transmission facilities to MISO. We anticipate
that FERC Order No. 2000 and our participation in the MISO will not have a
material effect on our operations.
Stranded Costs:
The definition of stranded costs for a utility business is the investment
in and carrying costs on property, plant and equipment and other regulatory
assets that exceed the amount that can be recovered in a competitive market. We
currently apply accounting standards that recognize the economic effects of rate
regulation and record regulatory assets and liabilities related to our fossil
generation, nuclear generation and customer operations. If we determine that we
no longer meet the criteria of SFAS No. 71, we may have a material extraordinary
non-cash charge to earnings. Reasons for discontinuing SFAS No. 71 accounting
treatment include increasing competition that restricts our ability to charge
prices needed to recover costs already incurred, a significant change by
regulators from a cost-based rate regulation to another form of rate regulation
and the impact should the City of Wichita municipalization efforts be
successful. We periodically review SFAS No. 71 criteria and believe our net
regulatory assets, including those related to generation, are probable of future
recovery. If we discontinue SFAS No. 71 accounting treatment based upon
competitive or other events, such as the successful municipalization efforts by
areas we serve, the value of our net regulatory assets and our utility plant
investments, particularly Wolf Creek, may be significantly impacted.
Regulatory changes, including competition or successful municipalization
efforts by the City of Wichita, could adversely impact our ability to recover
our investment in these assets. As of December 31, 2001, we have recorded
regulatory assets that are currently subject to recovery in future rates of
approximately $358.0 million. Of this amount, $221.4 million is a receivable for
income tax benefits previously passed on to customers. The remainder of the
regulatory assets are items that may give rise to stranded costs, including debt
issuance costs, deferred employee benefit costs, deferred plant costs, and coal
contract settlement costs.
52
In a competitive environment or because of such successful
municipalization efforts, we may not be able to fully recover our entire
investment in Wolf Creek. KGE presently owns 47% of Wolf Creek. We may also have
stranded costs from an inability to recover our environmental remediation costs
and long-term fuel contract costs in a competitive environment. If we determine
that we have stranded costs and we cannot recover our investment in these
assets, our future net utility income will be lower than our historical net
utility income has been unless we compensate for the loss of such income with
other measures.
Nuclear Decommissioning:
Decommissioning is a nuclear industry term for the permanent shutdown of a
nuclear power plant. The Nuclear Regulatory Commission (NRC) will terminate a
plant's license and release the property for unrestricted use when a company has
reduced the residual radioactivity of a nuclear plant to a level mandated by the
NRC. The NRC requires companies with nuclear plants to prepare formal financial
plans to fund decommissioning. These plans are designed so that funds required
for decommissioning will be accumulated during the estimated remaining life of
the related nuclear power plant.
We accrue decommissioning costs over the expected life of the Wolf Creek
generating facility. The accrual is based on estimated unrecovered
decommissioning costs, which consider inflation over the remaining estimated
life of the generating facility and are net of expected earnings on amounts
recovered from customers and deposited in an external trust fund.
On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost
Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost
Study on April 26, 2000. Based on the study, our share of Wolf Creek's
decommissioning costs, under the immediate dismantlement method, is estimated to
be approximately $631 million during the period 2025 through 2034, or
approximately $221 million in 1999 dollars. These costs include decontamination,
dismantling and site restoration and were calculated using an assumed inflation
rate of 3.6% over the remaining service life from 1999 of 26 years. The actual
decommissioning costs may vary from the estimates because of changes in the
assumed dates of decommissioning, changes in regulatory requirements, changes in
technology and changes in costs for labor, materials and equipment. On May 26,
2000, we filed an application with the KCC requesting approval of the funding of
our decommissioning trust on this basis. Approval was granted by the KCC on
September 20, 2000.
Decommissioning costs are currently being charged to operating expense in
accordance with prior KCC orders. Electric rates charged to customers provide
for recovery of these decommissioning costs over the life of Wolf Creek. Amounts
expensed approximated $4.0 million in 2001 and will increase annually to $5.5
million in 2024. These amounts are deposited in an external trust fund. The
average after-tax expected return on trust assets is 5.8%.
Our investment in the decommissioning fund, including reinvested earnings,
approximated $66.6 million at December 31, 2001 and $64.2 million at December
31, 2000. Trust fund earnings accumulate in the fund balance and increase the
recorded decommissioning liability.
Asset Retirement Obligations:
In August 2001, the Financial Accounting Standards Board (FASB) issued
SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard
requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. When it is
initially recorded, we will capitalize the estimated asset retirement obligation
by increasing the carrying amount of the related long-lived asset. The liability
will be accreted to its present value each period and the capitalized cost will
be depreciated over the life of the asset. The standard is effective for fiscal
years beginning after June 15, 2002. We expect to adopt this standard January 1,
2003. This standard will impact the way we currently account for the
decommissioning of Wolf Creek. In addition to the accounting for the Wolf Creek
decommissioning, we are also reviewing what impact this pronouncement will have
on our current accounting practices and our results of operations as it relates
to other asset retirement obligations we may identify. The impact is unknown at
this time. We do not believe that such changes, if required,
53
would adversely affect our operating results due to our current ability to
recover decommissioning costs through rates.
Monitored Services
------------------
Attrition:
Customer attrition has a direct impact on the results of our monitored
security operations since it affects its revenues, amortization expense and cash
flow. In some instances, estimates are used to derive attrition data.
Adjustments are made to lost accounts primarily for the net change, either
positive or negative, in the wholesale base and for accounts which are covered
under a purchase price holdback and are "put" back to the seller. The gross
accounts lost during a period are reduced by the amount of the guarantee
provided for in the purchase agreements with sellers. In some cases, the amount
of the purchase holdback may be less than actual attrition experience. The gross
accounts lost during a period are not reduced by "move in" accounts, which are
accounts where a new customer moves into a home installed with a Protection One
security system and vacated by a prior customer, or "competitive takeover"
accounts, which are accounts where the owner of a residence monitored by a
competitor requests that we provide monitoring services. The decreases due to
the conversions to MAS(R) were excluded in the calculation of attrition for the
periods indicated below.
For the year ended December 31, 2001, gross accounts lost were further
reduced by 126,318 customers for account dispositions and for adjustments
resulting from the conversion of Protection One's Wichita, Hagerstown, Beaverton
and Irving billing and monitoring systems to a new technology platform, MAS(R).
The conversion adjustments relate to how a customer is defined and the
transition of that definition from one system to another in Protection One's new
billing and monitoring system, referred to as MAS(R), or Monitored Automation
Systems, which reports number of accounts on the basis of one for every location
Protection One provides service even if it has separate contracts to provide
multiple services at that location. Protection One anticipates further
adjustments, which could be either positive or negative, from the conversion of
its Portland, Maine monitoring station to MAS(R) in 2002. These conversions are
substantially complete at the present time.
Actual attrition experience shows that the relationship period with any
individual customer can vary significantly. Customers discontinue service for a
variety of reasons, including relocation, service issues and cost. A portion of
the acquired customer base can be expected to discontinue service every year.
Any significant change in the pattern of historical attrition experience would
have a material effect on Monitored Services' results of operations.
Attrition is monitored each quarter based on a quarterly annualized and
trailing twelve-month basis. This method utilizes the average customer account
base for the applicable period in measuring attrition. Therefore, in periods of
customer account growth, customer attrition may be understated and in periods of
customer account decline, customer attrition may be overstated.
Customer attrition for the years ended December 31, 2001 and 2000 is
summarized below.
Customer Account Attrition
-------------------------------------------
December 31, 2001 December 31, 2000
-------------------- ---------------------
Annualized Trailing Annualized Trailing
Fourth Twelve Fourth Twelve
Quarter Month Quarter Month
---------- -------- ---------- ---------
Protection One ..................... 18.1% 15.2% 15.0% 14.0%
Protection One Europe (a) .......... 10.1% 10.0% 11.6% 10.9%
----------
(a) United Kingdom operations were disposed of in June 2001.
Our monitored services segment had a net decrease of 267,347 customers
from December 31, 2000 to December 31, 2001. The number of customers decreased
primarily because Monitored Services' customer acquisition strategies were not
able to generate accounts in a sufficient volume at acceptable costs to replace
54
accounts lost through attrition. We expect that this trend will continue until
the efforts being made to acquire new accounts at acceptable costs and reduce
attrition become more successful than they have been to date. Until this trend
has been reversed, net losses of customer accounts will materially and adversely
affect monitored services' business, financial condition, results of operations
and prospects.
Related Party Transactions
--------------------------
Below we describe significant transactions between us and Westar
Industries and other subsidiaries and related parties. We have disclosed
significant transactions even if these have been eliminated in the preparation
of our consolidated results and financial position since our proposed financial
plan, as discussed in Note 15 in the "Notes to Consolidated Financial
Statements," calls for a split-off of Westar Industries from us to occur in the
future. We cannot predict whether the KCC will approve the plan and if so
whether we will be successful in executing the plan.
We and ONEOK have shared services agreements in which we provide and bill
one another for facilities, utility field work, information technology, customer
support and bill processing. Payments for these services are based on various
hourly charges, negotiated fees and out-of-pocket expenses.
2001 2000 1999
------ ------ ------
(In Thousands)
Charges to ONEOK ........................................ $8,202 $8,463 $8,876
Charges from ONEOK ...................................... 3,279 3,420 3,322
Net receivable from ONEOK, outstanding at December 31 ... 1,424 1,205 1,506
In 1999, we and Protection One entered into a service agreement pursuant
to which we provide administrative services, including accounting, human
resources, legal, facilities and technology services on a year to year basis.
Fees for these services are based upon various hourly charges, negotiated fees
and out-of-pocket expenses. Protection One incurred charges of $8.1 million in
2001, $7.3 million in 2000 and $2.0 million in 1999. These intercompany charges
have been eliminated in consolidation.
We had a payable to Westar Industries of approximately $67.7 million at
December 31, 2001 on which we paid interest at the rate of 8.5% per annum. On
February 28, 2001, Westar Industries converted $350.0 million of the then
outstanding payable balance into approximately 14.4 million shares of our common
stock, representing 16.9% of our outstanding common stock after conversion.
These shares are reflected as treasury stock in our consolidated balance sheets.
During the first quarter of 2002, we repaid the remaining balance owed to Westar
Industries. The proceeds were used by Westar Industries to purchase our
outstanding debt in the open market. At February 28, 2002, Westar Industries
owned $118.7 million of our debt. Amounts outstanding and interest earned by
Westar Industries have been eliminated in our consolidated financial statements.
See Note 2, "Summary of Significant Accounting Policies -- Principles of
Consolidation" of the "Notes to Consolidated Financial Statements."
Westar Industries is the lender under Protection One's senior credit
facility. On November 1, 2001, this facility was amended to, among other things,
extend the maturity date to January 3, 2003, and provide for a quarterly fee for
financial advisory and management services equal to 1/8% of Protection One's
consolidated total assets at the end of each quarter, beginning with the quarter
ending March 31, 2002. As of March 14, 2002, approximately $145.5 million was
drawn under the facility. On March 25, 2002, Westar Industries further amended
the facility to increase the amount of the facility to $180 million. Amounts
outstanding have been eliminated in our consolidated financial statements.
We have a tax sharing agreement with Protection One. This pro rata tax
sharing agreement allows Protection One to be reimbursed for current tax
benefits utilized in our consolidated tax return. We and Protection One are
eligible to file on a consolidated basis for tax purposes as long as we maintain
an 80% ownership interest in Protection One. We reimbursed Protection One $11.8
million for tax year 2001 and $7.4 million for tax year 2000 for the tax
benefit.
55
During 2001, Westar Industries purchased $37.9 million face value of
Protection One bonds on the open market. In October 2001, $27.6 million of these
bonds were transferred to Protection One in exchange for cash. In 2001, we
recognized an extraordinary gain from the purchase of Protection One bonds of
$22.3 million, net of tax of $12.0 million. During 2000, Westar Industries
purchased $170.0 million face value of Protection One bonds on the open market.
In exchange for cash and the settlement of certain intercompany payables and
receivables, $103.9 million of these debt securities were transferred to
Protection One. The balance of the bonds was sold to Protection One in March
2001. No gain or loss was recognized on these transactions.
In the latter part of 2001 through February 28, 2002, Protection One
purchased approximately $1.8 million of our preferred stock in open market
purchases. These purchases have been accounted for as retirements.
During 2001, we extended loans to our officers for the purpose of
purchasing shares of our common stock on the open market. The loans are
unsecured and contain a variable interest rate that is equal to our short term
borrowing rate. Interest is payable quarterly. The loans mature and become due
on December 4, 2004. The balance outstanding at December 31, 2001 was
approximately $2.0 million and is classified as a reduction to shareholders'
equity in the accompanying consolidated balance sheet. The maximum amount of
loans authorized is $7.9 million.
During the fourth quarter of 2001, KGE entered into an option agreement to
sell an office building located in downtown Wichita, Kansas, to Protection One
for approximately $0.5 million. The sales price was determined by management
based on three independent appraisers' findings.
On February 29, 2000, Westar Industries purchased the European operations
of Protection One, and certain investments held be a subsidiary of Protection
One for an aggregate purchase price of $244 million. Westar Industries paid
approximately $183 million in cash and transferred Protection One debt
securities with a market value of approximately $61 million to Protection One.
Westar Industries has agreed to pay Protection One a portion of the net gain, if
any, on a subsequent sale of the European businesses on a declining basis over
the four years following the closing. Cash proceeds from the transaction were
used to reduce the outstanding balance owed to Westar Industries on Protection
One's revolving credit facility. No gain or loss was recorded on this
intercompany transaction and the net book value of the assets was unaffected.
If the KCC approves our financial plan, at the closing of the proposed
rights offering, we would enter into an option agreement that grants Westar
Industries an option to purchase the stock of Westar Generating, Inc., a wholly
owned subsidiary that owns our interest in the State Line generating facility.
The option would be exercisable at any time during the three year period
following execution of the agreement, subject to extension for two additional
one year periods. The option price is based on net book value at the time of
exercise. The option would be exercisable only if Westar Industries is unable to
obtain a permanent exemption from registration under the Investment Company Act
of 1940.
Other New Accounting Standards
------------------------------
In July 2001, FASB issued SFAS No. 141, "Business Combinations." SFAS No.
141 establishes that all business combinations will be accounted for using the
purchase method. Use of the pooling-of-interests method is no longer allowed.
The provisions of SFAS No. 141 are effective for all business combinations
initiated after June 30, 2001 and all business combinations accounted for using
the purchase method for which the date of acquisition is July 1, 2001 or later.
Market Risk Disclosure
----------------------
Market Price Risks:
We are exposed to market risk, including market changes, changes in
commodity prices, equity instrument investment prices and interest rates.
56
Commodity Price Exposure:
We engage in both trading and non-trading activities in our commodity
price risk management activities. We trade electricity, coal, natural gas and
oil. We utilize a variety of financial instruments, including forward contracts
involving cash settlements or physical delivery of an energy commodity, options,
swaps requiring payments (or receipt of payments) from counterparties based on
the differential between specified prices for the related commodity and futures
traded on electricity, natural gas and oil.
We are involved in trading activities primarily to minimize risk from
market fluctuations, capitalize on our market knowledge and enhance system
reliability. Net open positions exist or are established due to the origination
of new transactions and our assessment of, and response to, changing market
conditions. To the extent we have open positions, we were exposed to the risk
that fluctuating market prices could adversely impact our financial position or
results from operations. In 2002, we expect to trade coal, natural gas and oil
fossil fuel types as well as electricity.
We manage and measure the exposure of our trading portfolio using a
variance/covariance value-at-risk (VAR) model. VAR measures the total risk, in
dollars, of our entire trading portfolio. VAR also measures how much capital we
are willing to put at risk to conduct trades. VAR acts as a metric to gauge
trading risk. VAR measures the worst expected loss over a given time interval
under normal market conditions at a given confidence level. The VAR computations
are based on an historical simulation, which utilizes price movements over a
specified period to simulate forward price curves in the energy markets to
estimate the size of future potential losses. The quantification of market risk
using VAR methodologies represents a consistent measure of an estimate of
reasonably possible net losses in earnings that would be recognized on its
portfolio assuming hypothetical movements in future market rates and is not
necessarily indicative of actual results that may occur. In addition to VAR, we
employ additional risk control processes such as stress testing, daily loss
limits, and commodity position limits. We expect to use the same VAR model and
control processes in 2002.
The use of the VAR method requires a number of key assumptions including
the selection of a confidence level for losses and the estimated holding period.
We express VAR as a potential dollar loss based on a 95% confidence level using
a one-day holding period. The calculation includes derivative commodity
instruments used for both trading and risk management purposes. The high, low
and average VAR amounts for 2001 were $5.3 million, $0.2 million and $2.4
million, respectively, and for 2000 were $0.7 million, $0.04 million and $0.3
million, respectively.
The VAR amounts increased from 2000 due to the inclusion of additional
trading and hedging activities in the VAR model during 2001. Prior to the
January 1, 2001 adoption of SFAS No. 133, power marketing and natural gas
contracts not designated as hedges were included in the VAR calculations. After
January 1, 2001, we included asset-based transactions that did not qualify for
hedge accounting treatment. Also in 2001, we began to trade coal in our
asset-based portfolio. Excluded from the calculation is the gas hedge, which is
discussed below in "-- Fair Value of Contracts -- Gas Hedge and Interest Rate
Swap."
We have considered a number of risks and costs associated with the future
contractual commitments included in our energy portfolio. These risks include
credit risks associated with the financial condition of counterparties, product
location (basis) differentials and other risks which management policy dictates.
The counterparties in our portfolio are primarily large energy marketers and
major utility companies. The creditworthiness of our counterparties could
positively or negatively impact our overall exposure to credit risk. We maintain
credit policies with regard to our counterparties that, in management's view,
minimize overall credit risk.
We are also exposed to commodity price changes outside of trading
activities. We use derivatives for non-trading purposes primarily to reduce
exposure relative to the volatility of market prices. From 2000 to 2001, we
experienced a 2% decrease in the average price per MW of electricity purchased
for utility operations. However, purchased power markets are volatile and if we
were to have a 10% increase from 2001 to 2002, given the amount of power
purchased for utility operations during 2001, we would have exposure of
approximately $5.3 million of operating income. Due to the volatility of the
power market, past prices cannot be used to predict future prices.
57
We use a mix of various fuel types, including coal and natural gas, to
operate our system, which helps lessen our risk associated with any one fuel
type. A significant portion of our coal requirements are under long-term
contract, which removes most of the price risk, associated with this commodity
type. However, from January 1, 2001 to December 31, 2001, we experienced a 10%
increase in our average cost for natural gas purchased for utility operations,
or an increase of $0.34 per MMBtu. The higher natural gas prices increased our
total cost of gas purchased during 2001 by approximately $3.7 million, although
we decreased the quantity burned by 5.0 million MMBtu. If we were to have a
similar increase from 2001 to 2002, we would have exposure of approximately $4.1
million of operating income. Based on MMBtus of natural gas and fuel oil burned
during 2001, we had exposure of approximately $6.5 million of operating income
for a 10% change in average price paid per MMBtu. Due to the volatility of
natural gas prices, past prices cannot be used to predict future prices.
During the first quarter of 2001, spot market prices for western coal
markets increased significantly. Although the spot market prices have fallen
back to previous levels, the increase impacted fuel prices of coal received
under contracts for the portion that was indexed to or purchased on the spot
market. This affected and will continue to affect our inventory price of coal
for our LaCygne Generating Station and Lawrence and Tecumseh Energy Centers.
Additional factors that affect our commodity price exposure are the
quantity and availability of fuel used for generation and the quantity of
electricity customers will consume. Quantities of fossil fuel used for
generation could vary dramatically year to year based on the individual fuel's
availability, price, deliverability, unit outages and nuclear refueling. Our
customers' electricity usage could also vary dramatically year to year based on
the weather or other factors.
Interest Rate Exposure:
We have approximately $1.0 billion of variable rate debt and current
maturities of fixed rate debt as of December 31, 2001. A 100 basis point change
in each debt series' benchmark rate at December 31, 2001, used to set the rate
for such series would impact net income on an annual basis by approximately $2.6
million after tax.
Effective October 4, 2001, we entered into a $500 million interest rate
swap agreement with a term of two years. The effect of the swap agreement is to
fix the annual interest rate on the term loan at 6.18%. At December 31, 2001,
the variable rate associated with this debt was 4.68%. This reduces our interest
rate exposure due to variable rates. The swap is being accounted for as a cash
flow hedge.
Foreign Currency Exchange Rates:
We have foreign operations with functional currencies other than the
United States dollar. As of December 31, 2001, the unrealized loss on currency
translation, presented as a separate component of shareholders' equity and
reported within other comprehensive income, was approximately $3.8 million
pretax. A 10% change in the currency exchange rates would have an immaterial
effect on other comprehensive income.
Decline in Equity Price Risk:
During 2000, our balance in marketable securities declined approximately
$173.2 million from December 31, 1999, due to the sale of a significant portion
of our marketable security portfolio. Since we no longer have a significant
amount invested in marketable securities, we do not expect to be materially
impacted by changes in the market prices of our remaining investments.
Hedging Activity:
We also use financial instruments to hedge a portion of our anticipated
fossil fuel needs. At the time we enter into these transactions, we are unable
to determine what the value will be when the agreements are actually settled.
58
In an effort to mitigate fuel commodity price market risk, we use hedging
arrangements to minimize our exposure to increased coal, natural gas and oil
prices. Our future exposure to changes in fossil fuel prices will be dependent
upon the market prices and the extent and effectiveness of any hedging
arrangements we enter.
During the third quarter of 2001, we entered into hedging relationships to
manage commodity price risk associated with future natural gas purchases in
order to protect us and our customers from adverse price fluctuations in the
natural gas market. We are using futures and swap contracts with a total
notional volume of 39,000,000 MMBtu and terms extending through July 2004 to
hedge price risk for a portion of our anticipated natural gas fuel requirements
for our generation facilities. Based on our best estimate of generating needs,
we believe we have hedged 75% of our system requirements through this hedge. We
have designated these hedging relationships as cash flow hedges in accordance
with SFAS No. 133.
The following table summarizes the effects our natural gas hedge and our
interest rate swap had on our financial position and results of operations for
2001:
Total
Natural gas Interest Rate Cash Flow
Hedge (a) Swap Hedges
----------- ------------- ---------
(Dollars in Thousands)
Fair value of derivative instruments:
Current ............................................ $(9,988) $ -- $(9,988)
Long-term .......................................... (8,844) (2,656) (11,500)
-------- -------- --------
Total .......................................... $(18,832) $ (2,656) $(21,488)
======== ======== ========
Amounts in accumulated other comprehensive income ....... $(29,079) $ (2,656) $(31,735)
Hedge ineffectiveness ................................... 2,551 -- 2,551
Estimated income tax benefit ............................ 10,552 1,057 11,609
-------- -------- --------
Net Comprehensive Loss ......................... $(15,976) $ (1,599) $(17,575)
======== ======== ========
Anticipated reclassifications to earnings during 2002 (b) $ 9,988 $ -- $ 9,988
Duration of hedge designation as of December 31, 2001 ... 31 months 22 months --
----------
(a) Natural gas hedge liabilities are classified in the balance sheet as
energy trading contracts. Gas prices have dropped since we entered into
these hedging relationships. Due to the volatility of gas commodity
prices, it is probable that gas prices will increase and decrease over the
31 months that these relationships are in place.
(b) The actual amounts that will be reclassified to earnings could vary
materially from this estimated amount due to changes in market conditions.
Fair Value of Energy Trading Contracts
--------------------------------------
The tables below show the difference between the market value and the
notional values of energy trading contracts outstanding at December 31, 2001,
their sources and maturity periods:
Fair Value of Contracts (In Thousands)
Net fair value of contracts outstanding at the beginning of the period........ $ 39,520
Contracts realized or otherwise settled during the period..................... (24,732)
Fair value of new contracts entered into during the period.................... (12,479)
---------
Fair value of contracts outstanding at the end of the period.................. $ 2,309
=========
59
Fair Value of Contracts at End of Period
-------------------------------------------------------------
Maturity Maturity in
Total Less Than Maturity Maturity Excess of
Source of Fair Value Fair Value 1 Year 1-3 Years 4-5 Years 5 Years
---------- --------- --------- --------- -----------
(In Thousands)
Prices actively quoted (futures) ...................... $ (422) $ 160 $ (582) $ -- $ --
Prices provided by other external sources (swaps and
forwards) ........................................ (2,060) (2,028) (32) -- --
Prices based on models and other valuation models
(options and other) .............................. 4,791 5,495 (704) -- --
-------- -------- -------- -------- --------
Total fair value of contracts outstanding ............. $ 2,309 $ 3,627 $ (1,318) $ -- $ --
======== ======== ======== ======== ========
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
-------------------------------------------------------------------
Information relating to market risk disclosure is set forth in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Other Information" included herein.
60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
---------------------------------------------------
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants................................ 62
Financial Statements:
Western Resources, Inc. and Subsidiaries:
Consolidated Balance Sheets, December 31, 2001 and 2000..... 63
Consolidated Statements of Income (Loss) for the years
ended December 31, 2001, 2000 and 1999................ 64
Consolidated Statements of Comprehensive Income (Loss) for
the years ended December 31, 2001, 2000 and 1999...... 65
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999...................... 66
Consolidated Statements of Shareholders' Equity for the
years ended December 31, 2001, 2000 and 1999.......... 67
Notes to Consolidated Financial Statements........................ 68
Financial Schedules:
Schedule II - Valuation and Qualifying Accounts................... 119
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the
conditions under which they are required or the information is included in our
consolidated financial statements and schedules presented:
I, III, IV, and V.
61
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors
of Western Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Western
Resources, Inc. and subsidiaries as of December 31, 2001 and 2000, and the
related consolidated statements of income, comprehensive income, cash flows, and
shareholders' equity for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audits to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Western Resources, Inc. and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. Schedule II - Valuation and Qualifying
Accounts is presented for purposes of complying with the Securities and Exchange
Commission rules and is not part of the basic financial statements. The schedule
has been subjected to the auditing procedures applied in the audit of the basic
financial statements and in our opinion, fairly states in all material respects
the financial data required to be set forth therein in relation to the basic
financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
March 27, 2002
62
WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
December 31,
---------------------------
2001 2000
----------- -----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ................................................................. $ 96,691 $ 8,762
Restricted cash ........................................................................... 14,795 10,915
Accounts receivable, net .................................................................. 112,864 152,165
Inventories and supplies, net ............................................................. 145,099 101,303
Energy trading contracts .................................................................. 71,421 185,364
Deferred tax assets ....................................................................... 27,817 34,512
Prepaid expenses and other ................................................................ 41,331 43,049
----------- -----------
Total Current Assets ............................................................... 510,018 536,070
----------- -----------
PROPERTY, PLANT AND EQUIPMENT, NET ............................................................. 4,042,852 3,993,438
----------- -----------
OTHER ASSETS:
Restricted cash ........................................................................... 38,515 47,168
Investment in ONEOK ....................................................................... 598,929 591,173
Customer accounts, net .................................................................... 830,708 1,005,505
Goodwill, net ............................................................................. 884,786 976,102
Regulatory assets ......................................................................... 358,025 327,350
Energy trading contracts .................................................................. 15,247 15,883
Other ..................................................................................... 233,985 309,031
----------- -----------
Total Other Assets ................................................................. 2,960,195 3,272,212
----------- -----------
TOTAL ASSETS ................................................................................... $ 7,513,065 $ 7,801,720
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt ...................................................... $ 160,576 $ 41,825
Short-term debt ........................................................................... 222,300 35,000
Accounts payable .......................................................................... 125,285 154,654
Accrued liabilities ....................................................................... 181,671 206,959
Accrued income taxes ...................................................................... 39,770 53,834
Deferred security revenues ................................................................ 48,461 73,585
Energy trading contracts .................................................................. 67,859 191,673
Other ..................................................................................... 57,459 56,600
----------- -----------
Total Current Liabilities .......................................................... 903,381 814,130
----------- -----------
LONG-TERM LIABILITIES:
Long-term debt, net ....................................................................... 2,978,382 3,237,849
Western Resources obligated mandatorily redeemable preferred securities of subsidiary
trusts holding solely company subordinated debentures .................................. 220,000 220,000
Deferred income taxes and investment tax credits .......................................... 924,178 954,595
Minority interests ........................................................................ 166,850 184,591
Deferred gain from sale-leaseback ......................................................... 174,466 186,294
Energy trading contracts .................................................................. 16,500 1,096
Other ..................................................................................... 285,247 271,745
----------- -----------
Total Long-Term Liabilities ........................................................ 4,765,623 5,056,170
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTE 14)
SHAREHOLDERS' EQUITY:
Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued
248,576 shares; outstanding 239,364 shares and 248,576 shares, respectively ............ 23,936 24,858
Common stock, par value $5 per share; authorized 150,000,000 shares; issued 86,205,417
shares and 70,082,314 shares, respectively ............................................. 431,027 350,412
Paid-in capital ........................................................................... 1,196,763 868,166
Unearned compensation ..................................................................... (21,920) (18,066)
Loans to officers ......................................................................... (1,973) --
Retained earnings ......................................................................... 606,502 714,454
Treasury stock, at cost, 15,097,987 and 0 shares, respectively ............................ (364,901) --
Accumulated other comprehensive loss, net ................................................. (25,373) (8,404)
----------- -----------
Total Shareholders' Equity ......................................................... 1,844,061 1,931,420
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ..................................................... $ 7,513,065 $ 7,801,720
=========== ===========
The accompanying notes are an integral part of these
consolidated financial statements.
63
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(Dollars in Thousands, Except Per Share Amounts)
Year Ended December 31,
----------------------------------------------
2001 2000 1999
------------ ------------ ------------
SALES:
Energy ...................................................................... $ 1,768,393 $ 1,829,133 $ 1,429,698
Monitored Services .......................................................... 417,869 539,343 600,389
------------ ------------ ------------
Total Sales ...................................................... 2,186,262 2,368,476 2,030,087
------------ ------------ ------------
COST OF SALES:
Energy ...................................................................... 855,292 850,018 478,837
Monitored Services .......................................................... 144,258 185,814 180,109
------------ ------------ ------------
Total Cost of Sales .............................................. 999,550 1,035,832 658,946
------------ ------------ ------------
GROSS PROFIT ................................................................... 1,186,712 1,332,644 1,371,141
------------ ------------ ------------
OPERATING EXPENSES:
Operating and maintenance ................................................... 349,413 337,481 337,081
Depreciation and amortization ............................................... 413,642 426,369 403,669
Selling, general and administrative ......................................... 334,862 343,163 334,977
Dispositions of monitored services operations ............................... 13,056 -- --
Merger costs ................................................................ 8,693 -- 17,600
------------ ------------ ------------
Total Operating Expenses ......................................... 1,119,666 1,107,013 1,093,327
------------ ------------ ------------
INCOME FROM OPERATIONS ......................................................... 67,046 225,631 277,814
------------ ------------ ------------
OTHER INCOME (EXPENSE):
Investment earnings ......................................................... 52,634 192,423 35,979
Impairment of investments ................................................... (11,075) -- (76,166)
Minority interests .......................................................... 11,621 8,625 12,600
Other ....................................................................... 4,397 -- 14,234
------------ ------------ ------------
Total Other Income (Expense) ..................................... 57,577 201,048 (13,353)
------------ ------------ ------------
EARNINGS BEFORE INTEREST AND TAXES ............................................. 124,623 426,679 264,461
------------ ------------ ------------
INTEREST EXPENSE:
Interest expense on long-term debt .......................................... 227,601 226,419 236,417
Interest expense on short-term debt and other ............................... 40,623 63,149 57,687
------------ ------------ ------------
Total Interest Expense ........................................... 268,224 289,568 294,104
------------ ------------ ------------
EARNINGS (LOSS) BEFORE INCOME TAXES ............................................ (143,601) 137,111 (29,643)
Income tax expense (benefit) ................................................... (80,875) 46,061 (32,197)
------------ ------------ ------------
NET INCOME (LOSS) BEFORE EXTRAORDINARY GAIN AND ACCOUNTING CHANGE .............. (62,726) 91,050 2,554
Extraordinary gain, net of tax of $12,571, $26,514, and $6,322 ................. 23,156 49,241 11,742
Cumulative effect of accounting change, net of tax of $12,347 and $1,097 ....... 18,694 (3,810) --
------------ ------------ ------------
NET INCOME (LOSS) .............................................................. (20,876) 136,481 14,296
Preferred dividends ............................................................ 895 1,129 1,129
------------ ------------ ------------
EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK ..................................... $ (21,771) $ 135,352 $ 13,167
============ ============ ============
Average common shares outstanding .............................................. 70,649,969 68,962,245 67,080,281
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARES OUTSTANDING:
Basic and diluted earnings (losses) available before extraordinary gain
and accounting change .................................................... $ (0.90) $ 1.30 $ 0.02
Extraordinary gain, net of tax .............................................. 0.33 0.71 0.18
Accounting change, net of tax ............................................... 0.26 (0.05) --
------------ ------------ ------------
Basic and diluted earnings (losses) available after extraordinary gain and
accounting change ........................................................ $ (0.31) $ 1.96 $ 0.20
============ ============ ============
DIVIDENDS DECLARED PER COMMON SHARE ............................................ $ 1.20 $ 1.435 $ 2.14
The accompanying notes are an integral part of these
consolidated financial statements.
64
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
Year Ended December 31,
-----------------------------------------------------------------------
2001 2000 1999
--------------------- --------------------- ---------------------
NET INCOME (LOSS) ..................................... $ (20,876) $ 136,481 $ 14,296
--------- --------- ---------
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Unrealized holding (losses) gains on marketable
securities arising during the period .......... $ (592) $ 43,174 $ (55,420)
Adjustment for losses (gains) included in net
income ........................................ 3,336 2,744 (114,948) (71,774) 102,417 46,997
--------- --------- ---------
Unrealized holding losses on cash flow hedges
arising during the period ..................... (31,735) -- --
Adjustment for losses included in net income ...... 2,551 (29,184) -- -- -- --
--------- --------- ---------
Minimum pension liability adjustment ............. (6,712) -- --
Foreign currency translation adjustment .......... 2,568 (9,376) (115)
Income tax benefit ............................... 13,615 34,958 (18,602)
--------- --------- ---------
Total other comprehensive (loss) gain,
net of tax ............................. (16,969) (46,192) 28,280
--------- --------- ---------
COMPREHENSIVE INCOME (LOSS) ........................... $ (37,845) $ 90,289 $ 42,576
========= ========= =========
The accompanying notes are an integral part of these
consolidated financial statements.
65
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31,
-----------------------------------
2001 2000 1999
--------- --------- ---------
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income (loss) ........................................................ $ (20,876) $ 136,481 $ 14,296
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Extraordinary gain ....................................................... (23,156) (49,241) (11,742)
Cumulative effect of accounting change ................................... (18,694) 3,810 --
Depreciation and amortization ............................................ 413,642 426,369 403,669
Amortization of deferred gain from sale-leaseback ........................ (11,828) (11,828) (11,828)
Net changes in energy trading assets and liabilities ..................... 6,552 7,497 (1,188)
Equity in earnings from investments ...................................... (4,721) (11,219) (8,199)
Loss on dispositions of monitored services operations .................... 13,056 -- --
Impairment on investments ................................................ 11,075 -- 76,166
(Gain) loss on sale of marketable securities ............................. 1,861 (114,948) 26,251
Minority interests ....................................................... (11,621) (8,625) (12,600)
Gain on sale of investments .............................................. -- (9,562) (17,249)
Accretion of discount note interest ...................................... (2,247) (6,237) (6,799)
Net deferred taxes ....................................................... (35,024) (29,744) (15,825)
Deferred merger costs .................................................... 8,693 -- 17,600
Changes in working capital items, net of acquisitions and dispositions:
Restricted cash ...................................................... (3,880) (22,630) (16,154)
Accounts receivable, net ............................................. 36,213 77,873 (3,824)
Inventories and supplies, net ........................................ (45,572) 12,282 (15,024)
Prepaid expenses and other ........................................... 231 (10,314) (2,571)
Accounts payable ..................................................... (26,865) 44,172 5,000
Accrued liabilities .................................................. (19,783) (19,457) (20,152)
Accrued income taxes ................................................. (14,064) 13,506 7,386
Deferred security revenues ........................................... (8,154) (2,065) 3,479
Changes in other assets and liabilities .................................. (20,006) (14,358) (42,251)
--------- --------- ---------
Cash flows from operating activities ........................ 224,832 411,762 368,441
--------- --------- ---------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment, net .......................... (236,452) (308,073) (275,744)
Customer account acquisitions ............................................ (36,488) (35,513) (241,000)
Security alarm monitoring acquisitions, net of cash acquired ............. -- (11,748) (27,409)
Purchases of marketable securities ....................................... -- -- (12,003)
Proceeds from sale of marketable securities .............................. 2,829 218,609 73,456
Proceeds from dispositions of monitored services operations .............. 47,974 -- --
Proceeds from sale of other investments, net of purchases ................ 60,725 50,688 15,556
--------- --------- ---------
Cash flows used in investing activities ..................... (161,412) (86,037) (467,144)
--------- --------- ---------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net ..................................................... 188,907 (670,421) 392,949
Proceeds of long-term debt ............................................... 26,925 610,045 16,000
Retirements of long-term debt ............................................ (128,997) (208,952) (198,021)
Issuance of officer loans ................................................ (1,973) -- --
Issuance of common stock, net ............................................ 19,384 27,441 43,245
Cash dividends paid ...................................................... (85,547) (98,827) (145,033)
Preferred stock redemption ............................................... (547) -- --
Acquisition of treasury stock ............................................ (866) (9,187) (15,791)
Reissuance of treasury stock ............................................. 7,223 21,898 --
--------- --------- ---------
Cash flows from (used in) financing activities .............. 24,509 (328,003) 93,349
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .......................... 87,929 (2,278) (5,354)
CASH AND CASH EQUIVALENTS:
Beginning of period ...................................................... 8,762 11,040 16,394
--------- --------- ---------
End of period ............................................................ $ 96,691 $ 8,762 $ 11,040
========= ========= =========
The accompanying notes are an integral part of these
consolidated financial statements.
66
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(Dollars in Thousands)
Cumulative
Preferred and
Preference Common Paid-in Unearned Loans to Retained
Stock Stock Capital Compensation Officers Earnings
------------- -------- ---------- ------------ -------- ---------
BALANCE, December 31, 1998 ......... $ 24,858 $329,548 $ 777,401 $ (2,064) $ -- $ 810,617
Net income ......................... -- -- -- -- -- 14,296
Dividends on preferred and
preference stock ................. -- -- -- -- -- (1,129)
Issuance of common stock ........... -- 11,960 44,906 -- -- --
Dividends on common stock .......... -- -- -- -- -- (143,904)
Unrealized gain on marketable
securities ....................... -- -- -- -- -- --
Currency translation adjustment .... -- -- -- -- -- --
Tax benefit ........................ -- -- -- -- -- --
Acquisition of treasury stock ...... -- -- -- -- -- --
Grant of restricted stock .......... -- -- 4,333 (4,333) -- --
Amortization of restricted stock ... -- -- -- 702 -- --
--------------------------------------------------------------------------------
BALANCE, December 31, 1999 ......... $ 24,858 $341,508 $ 826,640 $ (5,695) $ -- $ 679,880
Net income ......................... -- -- -- -- -- 136,481
Dividends on preferred and
preference stock ................. -- -- -- -- -- (1,129)
Issuance of common stock ........... -- 8,904 18,537 -- -- --
Dividends on common stock .......... -- -- -- -- -- (97,698)
Unrealized loss on marketable
securities ....................... -- -- -- -- -- --
Currency translation adjustment .... -- -- -- -- -- --
Tax benefit ........................ -- -- -- -- -- --
Acquisition of treasury stock ...... -- -- -- -- -- --
Issuance of treasury stock ......... -- -- -- -- -- (3,080)
Grant of restricted stock .......... -- -- 22,989 (22,989) -- --
Amortization of restricted stock ... -- -- -- 10,618 -- --
--------------------------------------------------------------------------------
BALANCE, December 31, 2000 ......... $ 24,858 $350,412 $ 868,166 $(18,066) $ -- $ 714,454
Net income ......................... -- -- -- -- -- (20,876)
Dividends on preferred and
preference stock ................. -- -- -- -- -- (1,129)
Issuance of common stock ........... -- 80,615 298,236 -- -- --
Dividends on common stock .......... -- -- -- -- -- (84,474)
Retirement of preferred stock ...... (922) -- -- -- -- 375
Issuance of officer loans .......... -- -- -- -- (1,973) --
Unrealized gain on marketable
securities ....................... -- -- -- -- -- --
Unrealized loss on cash flow
hedges ............................. -- -- -- -- -- --
Minimum pension liability adjustment -- -- -- -- -- --
Currency translation adjustment .... -- -- -- -- -- --
Tax benefit ........................ -- -- -- -- -- (141)
Acquisition of treasury stock ...... -- -- -- -- -- --
Issuance of treasury stock ......... -- -- -- -- -- (1,707)
Cancellation of restricted stock ... -- -- 14,570 -- -- --
Grant of restricted stock .......... -- -- 15,791 (15,791) -- --
Amortization of restricted stock ... -- -- -- 11,937 -- --
--------------------------------------------------------------------------------
BALANCE, December 31, 2001 ......... $ 23,936 $431,027 $1,196,763 $(21,920) $(1,973) $ 606,502
================================================================================
Accumulated
Other
Treasury Comprehensive
Stock Income Total
--------- ------------- -----------
BALANCE, December 31, 1998 ......... $ -- $ 9,508 $ 1,949,868
Net income ......................... -- -- 14,296
Dividends on preferred and
preference stock ................. -- -- (1,129)
Issuance of common stock ........... -- -- 56,866
Dividends on common stock .......... -- -- (143,904)
Unrealized gain on marketable
securities ....................... -- 46,997 46,997
Currency translation adjustment .... -- (115) (115)
Tax benefit ........................ -- (18,602) (18,602)
Acquisition of treasury stock ...... (15,791) -- (15,791)
Grant of restricted stock .......... -- -- --
Amortization of restricted stock ... -- -- 702
----------------------------------------
BALANCE, December 31, 1999 ......... $ (15,791) $ 37,788 $ 1,889,188
Net income ......................... -- -- 136,481
Dividends on preferred and
preference stock ................. -- -- (1,129)
Issuance of common stock ........... -- -- 27,441
Dividends on common stock .......... -- -- (97,698)
Unrealized loss on marketable
securities ....................... -- (71,774) (71,774)
Currency translation adjustment .... -- (9,376) (9,376)
Tax benefit ........................ -- 34,958 34,958
Acquisition of treasury stock ...... (9,187) -- (9,187)
Issuance of treasury stock ......... 24,978 -- 21,898
Grant of restricted stock .......... -- -- --
Amortization of restricted stock ... -- -- 10,618
----------------------------------------
BALANCE, December 31, 2000 ......... $ -- $ (8,404) $ 1,931,420
Net income ......................... -- -- (20,876)
Dividends on preferred and
preference stock ................. -- -- (1,129)
Issuance of common stock ........... (358,805) -- 20,046
Dividends on common stock .......... -- -- (84,474)
Retirement of preferred stock ...... -- -- (547)
Issuance of officer loans .......... -- -- (1,973)
Unrealized gain on marketable
securities ....................... -- 2,744 2,744
Unrealized loss on cash flow
hedges ............................. -- (29,184) (29,184)
Minimum pension liability adjustment -- (6,712) (6,712)
Currency translation adjustment .... -- 2,568 2,568
Tax benefit ........................ -- 13,615 13,474
Acquisition of treasury stock ...... (866) -- (866)
Issuance of treasury stock ......... 9,340 -- 7,633
Cancellation of restricted stock ... (14,570) -- --
Grant of restricted stock .......... -- -- --
Amortization of restricted stock ... -- -- 11,937
----------------------------------------
BALANCE, December 31, 2001 ......... $(364,901) $(25,373) $ 1,844,061
========================================
The accompanying notes are an integral part of these
consolidated financial statements.
67
WESTERN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS
Western Resources, Inc. is a publicly traded consumer services company
incorporated in 1924 in the State of Kansas. Unless the context otherwise
indicates, all references in this Annual Report on Form 10-K to "the company,"
"Western Resources," "we," "us," "our" or similar words are to Western
Resources, Inc., and its consolidated subsidiaries. We provide electric
generation, transmission and distribution services to approximately 640,000
customers in Kansas and monitored security services to over 1.2 million
customers in North America and Europe. ONEOK, Inc. (ONEOK), in which we have an
approximate 45% ownership interest, provides natural gas transmission and
distribution services to approximately 1.4 million customers in Oklahoma and
Kansas. Our corporate headquarters are located at 818 South Kansas Avenue,
Topeka, Kansas 66612.
We and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary,
provide rate regulated electric service using the name Westar Energy. KGE owns
47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company
for Wolf Creek Generating Station (Wolf Creek).
Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary,
owns our interests in Protection One, Inc. (Protection One), Protection One
Europe, ONEOK, Inc. and other non-utility businesses. Protection One, a publicly
traded, approximately 87% -owned subsidiary, and Protection One Europe provide
monitored security services. Protection One Europe refers collectively to
Protection One International, Inc., a wholly owned subsidiary of Westar
Industries, and its subsidiaries, including a French subsidiary in which it owns
approximately a 99.8% interest.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
---------------------------
We prepare our consolidated financial statements in accordance with
accounting principles generally accepted in the United States (GAAP). Our
consolidated financial statements include all operating divisions and majority
owned subsidiaries for which we maintain controlling interests. Common stock
investments that are not majority owned are accounted for using the equity
method when our investment allows us the ability to exert significant influence.
Undivided interests in jointly-owned generation facilities are consolidated on a
pro rata basis. All material intercompany accounts and transactions have been
eliminated in consolidation.
Use of Management's Estimates
-----------------------------
The preparation of consolidated financial statements requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities at the date of our
consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
Regulatory Accounting
---------------------
We currently apply accounting standards for our regulated utility
operations that recognize the economic effects of rate regulation in accordance
with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation" and, accordingly, have recorded
regulatory assets and liabilities when required by a regulatory order or based
on regulatory precedent.
68
Cash and Cash Equivalents
-------------------------
We consider highly liquid investments with a maturity of three months or
less when purchased to be cash equivalents.
Restricted Cash
---------------
Restricted cash consists of cash used to collateralize letters of credit
and cash held in escrow, primarily related to supporting our power trading
transactions.
Inventories and Supplies
------------------------
Inventories and supplies for our utility business are stated at average
cost. Inventories for our monitored services segment, comprised of alarm systems
and parts, are stated at the lower of average cost or market.
Property, Plant and Equipment
-----------------------------
Property, plant and equipment is stated at cost. For utility plant, cost
includes contracted services, direct labor and materials, indirect charges for
engineering and supervision, and an allowance for funds used during construction
(AFUDC). AFUDC represents the cost of borrowed funds used to finance
construction projects. The AFUDC rate was 9.01% in 2001, 7.39% in 2000 and 6.00%
in 1999. The cost of additions to utility plant and replacement units of
property are capitalized. Interest capitalized into construction in progress was
$8.7 million in 2001, $9.4 million in 2000 and $4.4 million in 1999.
Maintenance costs and replacement of minor items of property are charged
to expense as incurred. Incremental costs incurred during scheduled Wolf Creek
refueling and maintenance outages are deferred and amortized monthly over the
unit's operating cycle, normally about 18 months. For utility plant, when units
of depreciable property are retired, the original cost and removal cost, less
salvage value, are charged to accumulated depreciation.
In accordance with regulatory decisions made by the Kansas Corporation
Commission (KCC), the acquisition premium of approximately $801 million
resulting from the acquisition of KGE in 1992 is being amortized over 40 years.
The acquisition premium is classified as electric plant in service. Accumulated
amortization for the KGE acquisition totaled $128.3 million as of December 31,
2001 and $108.2 million as of December 31, 2000.
Depreciation
------------
Utility plant is depreciated on the straight-line method at the lesser of
rates set by the KCC or rates based on the estimated remaining useful lives of
the assets, which are based on an average annual composite basis using group
rates that approximated 3.03% during 2001, 2.99% during 2000 and 2.92% during
1999. In its rate order of July 25, 2001, the KCC extended the recovery period
for our generating assets, including Wolf Creek, for regulatory rate making
purposes. The impact of this decision reduced our retail electric rates by
approximately $17.6 million on an annual basis. We intend to file an application
for an accounting authority order with the KCC to allow the creation of a
regulatory asset for the difference between our book and regulatory
depreciation. We cannot predict whether the KCC will approve our application.
Non-utility property, plant and equipment is depreciated on a
straight-line basis over the estimated useful lives of the related assets. We
periodically evaluate our depreciation rates considering the past and expected
future experience in the operation of our facilities.
69
Depreciable lives of property, plant and equipment are as follows:
Utility:
Fossil generating facilities.................... 10 to 48 years
Nuclear generating facilities................... 38 years
Transmission facilities......................... 27 to 65 years
Distribution facilities......................... 14 to 65 years
Other........................................... 3 to 50 years
Non-utility:
Buildings....................................... 40 years
Installed systems............................... 10 years
Furniture, fixtures and equipment............... 5 to 10 years
Leasehold improvements.......................... 5 to 10 years
Vehicles........................................ 5 years
Data processing and telecommunications.......... 1 to 7 years
Nuclear Fuel
------------
Our share of the cost of nuclear fuel in process of refinement,
conversion, enrichment and fabrication is recorded as an asset in property,
plant and equipment on our consolidated balance sheets at original cost and is
amortized to cost of sales based upon the quantity of heat produced for the
generation of electricity. The accumulated amortization of nuclear fuel in the
reactor was $35.6 million at December 31, 2001 and $18.6 million at December 31,
2000. Spent fuel charged to cost of sales was $22.1 million in 2001, $19.6
million in 2000 and $20.1 million in 1999.
Customer Accounts
-----------------
Customer accounts are stated at cost. The cost includes amounts paid to
dealers and the estimated fair value of accounts acquired in business
acquisitions. Internal costs incurred in support of acquiring customer accounts
are expensed as incurred.
Prior to the third quarter of 1999, Protection One and Protection One
Europe amortized their customer accounts by using the straight-line method over
a ten-year life, except for accounts acquired from Westinghouse for which an
eight-year 120% declining balance was applied. The choice of an amortization
life was based on estimates and judgments about the amounts and timing of
expected future revenues from these assets and average customer account life.
Selected periods were determined because, in Protection One's and Protection One
Europe's opinion, they would adequately match amortization cost with anticipated
revenue.
Protection One and Protection One Europe conducted a comprehensive review
of their amortization policy during the third quarter of 1999, prior to Westar
Industries' acquisition of Protection One Europe. As a part of this review,
Protection One and Protection One Europe hired an independent appraisal firm to
perform a lifing study on customer accounts. This review was performed
specifically to evaluate the historic amortization policy in light of the
inherent declining revenue curve over the life of a pool of customer accounts
and Protection One's historical attrition experience. After completing the
review, Protection One identified three distinct pools, each of which had
distinct attributes that effect differing attrition characteristics. The pools
corresponded to Protection One's North America, Multifamily and Europe business
segments. For the North America and Europe pools, the results of the lifing
study indicated that Protection One could expect attrition to be greatest in
years one through five of asset life and that a change from a straight-line to a
declining balance (accelerated) method would more closely match future
amortization cost with the estimated revenue stream from these assets.
Protection One and Protection One Europe elected to change to that method,
except for Protection One accounts acquired in the Westinghouse acquisition that
were utilizing an eight-year accelerated method. No change was made in the
method used for the Multifamily pool.
70
Protection One's and Protection One Europe's amortization rates consider
the average estimated remaining life and historical and projected attrition
rates. The amortization method for each customer pool is as follows:
Pool Method
--------------------------------------------- ---------------------------------
North America:
Acquired Westinghouse customers......... Eight-year 120% declining balance
Other customers......................... Ten-year 130% declining balance
Europe....................................... Ten-year 125% declining balance
Multifamily.................................. Ten-year straight-line
Adoption of the declining balance method effectively shortens the
estimated expected average customer life for these customer pools, and does so
in a way that does not make it possible to distinguish the effect of a change in
method (straight-line to declining balance) from the change in estimated lives.
In such cases, GAAP requires that the effect of such a change be recognized in
operations in the period of the change, rather than as a cumulative effect of a
change in accounting principle. Protection One changed to the declining balance
method in the third quarter of 1999 for Europe customers and the North America
customers that had been amortized on a straight-line basis. Accordingly, the
effect of the change in accounting principle increased Protection One's
amortization expense reported in the third quarter of 1999 by approximately $40
million. Accumulated amortization would have been approximately $34 million
higher through the end of the second quarter of 1999 if the declining balance
method had been used historically.
In accordance with SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," long-lived
assets held and used by Protection One and Protection One Europe are evaluated
for recoverability on a periodic basis or as circumstances warrant. An
impairment would be recognized when the undiscounted expected future operating
cash flows by customer pool derived from customer accounts is less than the
carrying value of capitalized customer accounts and related goodwill. See Note
25 below for information regarding SFAS No. 144, "Accounting for the Impairment
and Disposal of Long-Lived Assets," which replaces SFAS No. 121 as of January 1,
2002.
Goodwill has been recorded in business acquisitions where the principal
asset acquired was the recurring revenues from the acquired customer base. For
purposes of the impairment analysis, goodwill has been considered directly
related to the acquired customers.
Due to the customer attrition experienced in 2001, 2000 and 1999, the
decline in market value of Protection One's publicly traded equity and debt
securities and because of recurring losses, Protection One and Protection One
Europe performed impairment tests on their customer account assets and goodwill
in 2001, 2000 and 1999. These tests indicated that future estimated undiscounted
cash flows exceeded the sum of the recorded balances for customer accounts and
goodwill.
See Note 25 below for information regarding an impairment recorded in 2002
pursuant to new accounting rules.
Goodwill
--------
Goodwill represents the excess of the purchase price over the fair value
of net assets acquired by Protection One and Protection One Europe. Protection
One and Protection One Europe changed their estimated goodwill life from 40
years to 20 years as of January 1, 2000. After that date, remaining goodwill,
net of accumulated amortization, is being amortized over its remaining useful
life based on a 20-year life. As a result of this change in estimate, goodwill
amortization expense for the year ended December 31, 2000 increased by
approximately $33.0 million. The resulting reduction to net income for 2000 was
$26.1 million or a decrease in earnings per share of $0.38.
71
The carrying value of goodwill was included in the evaluations of
recoverability of customer accounts. No reduction in the carrying value was
necessary at December 31, 2001 or 2000.
Goodwill accumulated amortization was $170.0 million at December 31, 2001
and $118.6 million at December 31, 2000. Goodwill amortization expense was $57.1
million for the year ended 2001, $61.4 million for 2000 and $31.6 million for
1999. Beginning January 1, 2002, goodwill will no longer be amortized. New
accounting rules to be adopted on January 1, 2002 do not permit goodwill
amortization and require an annual impairment test.
See Note 25 below for information regarding an impairment recorded in 2002
pursuant to new accounting rules.
Regulatory Assets and Liabilities
---------------------------------
Regulatory assets represent probable future revenue associated with
certain costs that will be recovered from customers through the rate-making
process. Regulatory liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers through the
rate-making process. We have recorded these regulatory assets and liabilities in
accordance with SFAS No. 71. If we were required to terminate application of
SFAS No. 71 for all of our regulated operations, we would have to record the
amounts of all regulatory assets and liabilities in our consolidated statements
of income at that time. Our earnings would be reduced by the total amount in the
table below, net of applicable income taxes. Regulatory assets and liabilities
reflected in our consolidated financial statements are as follows:
As of December 31,
------------------------
2001 2000
-------- --------
(In Thousands)
Recoverable income taxes ....................... $221,373 $187,308
Debt issuance costs ............................ 58,054 63,263
Deferred employee benefit costs ................ 32,687 36,251
Deferred plant costs ........................... 29,499 29,921
Other regulatory assets ........................ 16,412 10,607
-------- --------
Total regulatory assets ................... $358,025 $327,350
======== ========
Total regulatory liabilities .............. $ 6,037 $ 1,978
======== ========
. Recoverable income taxes: Recoverable income taxes represent amounts
due from customers for accelerated tax benefits which have been
previously flowed through to customers and are expected to be
recovered in the future as the accelerated tax benefits reverse.
. Debt issuance costs: Debt reacquisition expenses are amortized over
the remaining term of the reacquired debt or, if refinanced, the
term of the new debt. Debt issuance costs are amortized over the
term of the associated debt.
. Deferred employee benefit costs: Deferred employee benefit costs
represent post-retirement and post-employment expenses in excess of
amounts paid that are to be recovered over a period of five years as
authorized by the KCC.
. Deferred plant costs: Costs related to the Wolf Creek nuclear
generating facility.
We expect to recover all of the above regulatory assets in rates charged
to customers. A return is allowed on deferred plant costs and coal contract
settlement costs (included in "Other regulatory assets" in the table above).
72
Cash Surrender Value of Life Insurance
--------------------------------------
The following amounts related to corporate-owned life insurance policies
(COLI) are recorded in other long-term assets on our consolidated balance sheets
at December 31:
2001 2000
------ ------
(In Millions)
Cash surrender value of policies (a) ................... $772.8 $705.4
Borrowings against policies ............................ (723.6) (665.9)
------ ------
COLI, net ........................................ $ 49.2 $ 39.5
====== ======
----------
(a) Cash surrender value of policies as presented represents the value of the
policies as of the end of the respective policy years and not as of
December 31, 2001 and 2000.
Income is recorded for increases in cash surrender value and net death
proceeds. Interest incurred on amounts borrowed is offset against policy income.
Income recognized from death proceeds is highly variable from period to period.
Death benefits recognized as other income approximated $2.7 million in 2001,
$0.9 million in 2000 and $1.4 million in 1999.
Minority Interests
------------------
Minority interests represent the minority shareholders' proportionate
share of the shareholders' equity and net loss of Protection One and Protection
One Europe.
Revenue Recognition
-------------------
Energy Sales:
Energy sales are recognized as services are rendered and include an
estimate for energy delivered but unbilled at the end of each year, except for
power marketing. Power marketing activities are accounted for under the
mark-to-market method of accounting. Under this method, changes in the portfolio
value are recognized as gains or losses in the period of change. The net
mark-to-market change is included in energy sales in our consolidated statements
of income. The resulting unrealized gains and losses are recorded as energy
trading assets and liabilities on our consolidated balance sheet.
We primarily use quoted market prices to value our power marketing and
energy trading contracts. When market prices are not readily available or
determinable, we use alternative approaches, such as model pricing. The market
prices used to value these transactions reflect our best estimate considering
various factors, including closing exchange and over-the-counter quotations,
time value and volatility factors underlying the commitments. Results actually
achieved from these activities could vary materially from intended results and
could unfavorably affect our financial results. Financially settled trading
transactions are reported on a net basis, reflecting the financial nature of
these transactions. Physically settled trading transactions are recorded on a
gross basis in operating revenues and fuel and purchased power expense.
Monitored Services Revenues:
Monitored services revenues are recognized when security services are
provided. Installation revenue, sales revenues on equipment upgrades and direct
costs of installations and sales are deferred for residential customers with
service contracts. For commercial customers and national account customers,
revenue recognition is dependent upon each specific customer contract. In
instances when the company sells the equipment outright, revenues and costs are
recognized in the period incurred. In cases where there is no outright sale,
revenues and direct costs are deferred and amortized.
73
Deferred installation revenues and system sales revenues will be
recognized over the expected useful life of the customer. Deferred costs in
excess of deferred revenues will be recognized over the contract life. To the
extent deferred costs are less than deferred revenues, such costs are recognized
over the customers' estimated useful life.
Deferred revenues also result from customers who are billed for
monitoring, extended service protection and patrol and response services in
advance of the period in which such services are provided, on a monthly,
quarterly or annual basis.
Income Taxes
------------
Our consolidated financial statements use the liability method to reflect
income taxes. Deferred tax assets and liabilities are recognized for temporary
differences in amounts recorded for financial reporting purposes and their
respective tax bases. We amortize deferred investment tax credits over the lives
of the related properties.
Foreign Currency Translation
----------------------------
The assets and liabilities of our foreign operations are translated into
United States dollars at current exchange rates and revenues and expenses are
translated at average exchange rates for the year.
Cumulative Effects of Accounting Changes
----------------------------------------
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and
138 (collectively, SFAS No. 133). We use derivative instruments (primarily
swaps, options and futures) to manage interest rate exposure and the commodity
price risk inherent in fossil fuel purchases and electricity sales. Under SFAS
No. 133, all derivative instruments, including our energy trading contracts, are
recorded on our consolidated balance sheet as either an asset or liability
measured at fair value. Changes in a derivative's fair value must be recognized
currently in earnings unless specific hedge accounting criteria are met. Cash
flows from derivative instruments are presented in net cash flows from operating
activities.
Derivative instruments used to manage commodity price risk inherent in
fuel purchases and electricity sales are classified as energy trading contracts
on our consolidated balance sheet. Energy trading contracts representing
unrealized gain positions are reported as assets; energy trading contracts
representing unrealized loss positions are reported as liabilities.
Prior to January 1, 2001, gains and losses on our derivatives used for
managing commodity price risk were deferred until settlement. These derivatives
were not designated as hedges under SFAS No. 133. Accordingly, on January 1,
2001, we recognized an unrealized gain of $18.7 million, net of $12.3 million of
tax. This gain is presented on our consolidated statement of income as a
cumulative effect of a change in accounting principle.
After January 1, 2001, changes in fair value of all derivative instruments
used for managing commodity price risk that are not designated as hedges are
recognized in revenue as discussed above under "-- Revenue Recognition -- Energy
Sales." Accounting for derivatives under SFAS No. 133 will increase volatility
of our future earnings.
In the fourth quarter of 2000, we adopted Staff Accounting Bulletin (SAB)
No. 101, "Revenue Recognition," which had a retroactive effective date of
January 1, 2000. The impact of this accounting change generally required
deferral of certain monitored security services sales for installation revenues
and direct sales-related expenses. Deferral of these revenues and costs is
generally necessary when installation revenues have been received and a
monitoring contract to provide future service is obtained.
The cumulative effect of the change in accounting principle was
approximately $3.8 million, net of tax benefits of $1.1 million and is related
to changes in revenue recognition at Protection One Europe. Prior to the
adoption of SAB No. 101, Protection One Europe recognized installation revenues
and related expenses upon completion of the installation.
74
Supplemental Cash Flow Information
----------------------------------
Cash paid for interest and income taxes for each of the years ended
December 31, are as follows:
2001 2000 1999
-------- -------- --------
(In Thousands)
Interest on financing activities, net of amount capitalized .... $306,865 $310,345 $298,802
Income taxes ................................................... 5,811 28,751 784
Reclassifications
-----------------
Certain amounts in prior years have been reclassified to conform with
classifications used in the current year presentation.
3. RATE MATTERS AND REGULATION
KCC Rate Proceedings
--------------------
On November 27, 2000, we and KGE filed applications with the KCC for an
increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction
in our combined electric rates of $22.7 million, consisting of a $41.2 million
reduction in KGE's rates and an $18.5 million increase in our rates.
On August 9, 2001, we and KGE filed petitions with the KCC requesting
reconsideration of the July 25, 2001 order. The petitions specifically asked for
reconsideration of changes in depreciation, reductions in rate base related to
deferred income taxes associated with the KGE acquisition premium and a deferred
gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and
several other issues. On September 5, 2001, the KCC issued an order in response
to our motions for reconsideration that increased our rate increase by an
additional $7.0 million. The $41.2 million rate reduction in KGE's rates
remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions
with the Kansas Court of Appeals in an action captioned "Western Resources, Inc.
and Kansas Gas and Electric Company vs. The State Corporation Commission of the
State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders.
We are evaluating whether to appeal this decision to the Kansas Supreme Court.
KCC Investigation and Order
---------------------------
See Note 15 for a discussion of the order issued by the KCC on July 20,
2001 in the KCC's docket investigating the proposed separation of our electric
utility businesses from our non-utility businesses and other aspects of our
unregulated businesses.
FERC Proceedings
----------------
On September 12, 2001, we filed a settlement between the Federal Energy
Regulatory Commission (FERC) staff and Westar Generating, Inc. (Westar
Generating), the wholly owned subsidiary that owns our interests in the State
Line generating facility. The settlement establishes the rate at which we will
buy power from Westar Generating. FERC has jurisdiction over the establishment
of this rate because of our affiliate relationship with Westar Generating. We
continue to work toward a global settlement with the KCC, the only other active
party, but can make no assurance on a resolution.
In September 1999, the City of Wichita filed a complaint with FERC against
us alleging improper affiliate transactions between our KPL division and KGE.
The City of Wichita asked that FERC equalize the generation costs between KPL
and KGE, in addition to other matters. After hearings on the case, a FERC
administrative law judge ruled in our favor confirming that no change in rates
was required. On December 13, 2000, the City of Wichita filed a brief with FERC
asking that the Commission overturn the judge's decision. On January 5, 2001, we
75
filed a brief opposing the City's position. On November 23, 2001, FERC issued an
order affirming the judge's decision. The City of Wichita's time to appeal
FERC's order has expired.
4. ACCOUNTS RECEIVABLE
Our accounts receivable on our consolidated balance sheets are comprised
as follows:
December 31,
-------------------------
2001 2000
--------- ---------
(In Thousands)
Gross accounts receivable ...................... $ 189,254 $ 254,743
Allowance for uncollectable accounts (a) ....... (19,121) (45,816)
Unbilled energy receivables .................... 42,731 58,238
Accounts receivable sale program ............... (100,000) (115,000)
--------- ---------
Accounts receivable, net ....................... $ 112,864 $ 152,165
========= =========
----------
(a) The decrease in allowance for uncollectable accounts is primarily due to
the write off of Protection One customer accounts in 2001.
On July 28, 2000, we entered into an asset-backed securitization agreement
under which we periodically transfer an undivided percentage ownership interest
in a revolving pool of our accounts receivable arising from the sale of
electricity to a multi-seller conduit administered by an independent financial
institution through the use of a special purpose entity (SPE). We account for
this transfer as a sale in accordance with SFAS No. 140, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities."
The agreement was renewed on July 26, 2001, and is annually renewable upon
agreement by all parties.
Under the terms of the agreement, we may transfer accounts receivable to
the bankruptcy-remote SPE and the conduit must purchase from the SPE an
undivided ownership interest of up to $125 million (and upon request, subject to
certain conditions, up to $175 million), in those receivables. The SPE has been
structured to be legally separate from us, but it is wholly owned and
consolidated. The percentage ownership interest in receivables purchased by the
conduit may increase or decrease over time, depending on the characteristics of
the SPE's receivables, including delinquency rates and debtor concentrations. We
service the receivables transferred to the SPE and receive a servicing fee.
These servicing fees are eliminated in consolidation.
Under the terms of the agreement, the conduit pays the SPE the face amount
of the undivided interest at the time of purchase. Subsequent to the initial
purchase, additional interests are sold and collections applied by the SPE to
the conduit resulting in an adjustment to the outstanding conduit interest.
We record administrative expense on the undivided interest owned by the
conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the
year ended December 31, 2000. These expenses are included in other income
(expense) in our consolidated statements of income.
The outstanding balance of SPE receivables was $43.3 million at December
31, 2001 and $85.5 million at December 31, 2000, which is net of an undivided
interest of $100 million and $115.0 million in receivables sold by the SPE to
the conduit. Our retained interest in the SPE's receivables is reported at fair
value and is subordinate to, and provides credit enhancement for, the conduit's
ownership interest in the SPE's receivables. Our retained interest is available
to the conduit to pay any fees or expenses due to the conduit, and to absorb all
credit losses incurred on any of the SPE's receivables. The retained interest is
included in accounts receivable, net, in our consolidated balance sheets.
76
5. FINANCIAL INSTRUMENTS
The carrying values and estimated fair values of our financial instruments
are as follows:
Carrying Value Fair Value
------------------------ ------------------------
As of December 31,
----------------------------------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
(In Thousands)
Fixed-rate debt, net of current maturities (a) ... $2,418,838 $2,518,415 $2,229,998 $2,218,711
Other mandatorily redeemable securities (a) ...... 220,000 220,000 190,960 182,232
----------
(a) Fair value is estimated based on quoted market prices for the same or
similar issues or on the current rates offered for instruments of the same
remaining maturities and redemption provisions.
The recorded amounts of accounts receivable and other current financial
instruments approximate fair value. Cash and cash equivalents, short-term
borrowings and variable-rate debt are carried at cost, which approximates fair
value and are not included in the table above.
The fair value estimates presented herein are based on information
available at December 31, 2001 and 2000. These fair value estimates have not
been comprehensively revalued for the purpose of these consolidated financial
statements since that date and current estimates of fair value may differ
significantly from the amounts presented herein.
Derivative Instruments and Hedge Accounting
-------------------------------------------
We use derivative financial instruments primarily to manage risk as it
relates to changes in the prices of commodities including natural gas, coal and
electricity and changes in interest rates. We also use certain derivative
instruments for trading purposes in order to take advantage of favorable price
movements and market timing activities in the wholesale power and fossil fuel
markets. Derivative instruments used to manage commodity price risk inherent in
fuel purchases and electricity sales are classified as energy trading contracts
on our consolidated balance sheet. Energy trading contracts representing
unrealized gain positions are reported as assets; energy trading contracts
representing unrealized loss positions are reported as liabilities.
Energy Trading Activities:
We trade energy commodity contracts daily. Within the trading portfolio,
we take certain positions to hedge physical sale or purchase contracts and we
take certain positions to take advantage of market trends and conditions. We
record most energy contracts, both physical and financial, at fair value.
Changes in value are reflected in our consolidated statement of income. We use
all forms of financial instruments, including futures, forwards, swaps and
options. Each type of financial instrument involves different risks. We believe
financial instruments help us manage our contractual commitments, reduce our
exposure to changes in cash market prices and take advantage of selected market
opportunities. We refer to these transactions as energy trading activities.
Although we generally attempt to balance our physical and financial
contracts in terms of quantities and contract performance, net open positions
typically exist. We will at times create a net open position or allow a net open
position to continue when we believe that future price movements will increase
the portfolio's value. To the extent we have an open position, we are exposed to
fluctuating market prices that may adversely impact our financial position or
results from operations.
The prices we use to value price risk management activities reflect our
best estimate of fair values considering various factors, including closing
exchange and over-the-counter quotations, time value of money and price
volatility factors underlying the commitments. We adjust prices to reflect the
potential impact of liquidating
77
our position in an orderly manner over a reasonable period of time under present
market conditions. We consider a number of risks and costs associated with the
future contractual commitments included in our energy portfolio, including
credit risks associated with the financial condition of counterparties and the
time value of money. We continuously monitor the portfolio and value it daily
based on present market conditions.
Future changes in our creditworthiness and the creditworthiness of our
counterparties may change the value of our portfolio. We adjust the value of
contracts and set dollar limits with counterparties based on our assessment of
their credit quality.
Non-Trading Activities - Derivative Instruments and Hedging Activities:
We use derivative financial instruments to reduce our exposure to adverse
fluctuations in commodity prices, interest rates, and other market risks. When
we enter into a financial instrument, we formally designate and document the
instrument as a hedge of a specific underlying exposure, as well as the risk
management objectives and strategies for undertaking the hedge transaction.
Because of the high degree of correlation between the hedging instrument and the
underlying exposure being hedged, fluctuations in the value of the derivative
instruments are generally offset by changes in the value or cash flows of the
underlying exposures being hedged.
We record derivatives used for hedging commodity price risk in our
consolidated balance sheets at fair value as energy trading contracts. The
effective portion of the gain or loss on a derivative instrument designated as a
cash flow hedge is reported as a component of accumulated other comprehensive
income (loss). This amount is reclassified into earnings in the period during
which the hedged transaction affects earnings. Effectiveness is the degree to
which gains and losses on the hedging instruments offset the gains and losses on
the hedged item. The ineffective portion of the hedging relationship is
recognized currently in earnings.
The fair values of derivatives used to hedge or modify our risks fluctuate
over time. These fair value amounts should not be viewed in isolation, but
rather in relation to the fair values or cash flows of the underlying hedged
transactions and the overall reduction in our risk relating to adverse
fluctuations in interest rates, commodity prices and other market factors. In
addition, the net income effect resulting from our derivative instruments is
recorded in the same line item within our consolidated statements of income as
the underlying exposure being hedged. We also formally assess, both at the
inception and at least quarterly thereafter, whether the financial instruments
that are used in hedging transactions are effective at offsetting changes in
either the fair value or cash flows of the related underlying exposures. Any
ineffective portion of a financial instrument's change in fair value is
immediately recognized in net income.
The notional volumes and terms of commodity contracts used for trading and
non-trading purposes are as follows at December 31, 2001 and 2000:
December 31, 2001
-----------------------------------------
Fixed Price Fixed Price Maximum
Payor Receiver Term in Years
----------- ----------- -------------
Electricity (MWh's) ............... 3,942,352 2,976,504 4
Natural gas and oil (MMBtus) ...... 124,632,157 81,702,324 3
Coal (MMBtus) ...................... 245,667,419 237,819,001 3
December 31, 2000
-----------------------------------------
Fixed Price Fixed Price Maximum
Payor Receiver Term in Years
----------- ----------- -------------
Electricity (MWh's) ............... 4,229,100 4,100,448 4
Natural gas and oil (MMBtus) ...... 113,030,679 80,754,417 3
Coal (MMBtus) ..................... -- -- --
78
The following table presents the fair values of energy transactions by
commodity at December 31, 2001 and 2000:
Energy Trading Contract Energy Trading Contract
Assets Liabilities
----------------------- -----------------------
2001 2000 2001 2000
-------- -------- -------- --------
(In Thousands)
Electricity $ 26,087 $108,726 $ 17,721 $104,337
Natural gas and oil 37,884 92,521 42,068 88,432
Coal 22,697 -- 24,570 --
-------- -------- -------- --------
Total $ 86,668 $201,247 $ 84,359 $192,769
======== ======== ======== ========
During the third quarter of 2001, we entered into hedging relationships to
manage commodity price risk associated with future natural gas purchases in
order to protect us and our customers from adverse price fluctuations in the
natural gas market. We are using futures and swap contracts with a total
notional volume of 39,000,000 MMBtu and terms extending through July 2004 to
hedge price risk for a portion of our anticipated natural gas fuel requirements
for our generation facilities. Based on our best estimate of generating needs,
we believe we have hedged 75% of our system requirements through this hedge. We
have designated these hedging relationships as cash flow hedges in accordance
with SFAS No. 133.
Effective October 4, 2001, we entered into a $500 million interest rate
swap agreement with a term of two years. The effect of the swap agreement is to
fix the annual interest rate on the term loan at 6.18%. At December 31, 2001,
the variable rate associated with this debt was 4.68%. This reduces our interest
rate exposure due to variable rates. The swap is being accounted for as a cash
flow hedge.
The following table summarizes the effects our natural gas hedge and our
interest rate swap had on our financial position and results of operations for
2001:
Total
Natural gas Interest Rate Cash Flow
Hedge (a) Swap Hedges
----------- ------------- ----------
(Dollars in Thousands)
Fair value of derivative instruments:
Current ............................................... $ (9,988) $ -- $ (9,988)
Long-term ............................................. (8,844) (2,656) (11,500)
---------- ---------- ----------
Total ............................................. $ (18,832) $ (2,656) $ (21,488)
========== ========== ==========
Amounts in accumulated other comprehensive income .......... $ (29,079) $ (2,656) $ (31,735)
Hedge ineffectiveness ...................................... 2,551 -- 2,551
Estimated income tax benefit ............................... 10,552 1,057 11,609
---------- ---------- ----------
Net Comprehensive Loss ............................ $ (15,976) $ (1,599) $ (17,575)
========== ========== ==========
Anticipated reclassifications to earnings during 2002 (b) .. $ 9,988 $ -- $ 9,988
Duration of hedge designation as of December 31, 2001 ...... 31 months 22 months --
----------
(a) Natural gas hedge liabilities are classified in the balance sheet as
energy trading contracts. Gas prices have dropped since we entered into
these hedging relationships. Due to the volatility of gas commodity
prices, it is probable that gas prices will increase and decrease over the
31 months that these relationships are in place.
(b) The actual amounts that will be reclassified to earnings could vary
materially from this estimated amount due to changes in market conditions.
79
6. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December
31:
2001 2000
---------- ----------
(In Thousands)
Electric plant in service ........................ $6,289,316 $5,987,920
Less - Accumulated depreciation .................. 2,404,478 2,274,940
---------- ----------
3,884,838 3,712,980
Construction work in progress .................... 63,927 189,853
Nuclear fuel, net ................................ 33,883 30,791
---------- ----------
Net utility plant ............................. 3,982,648 3,933,624
Non-utility plant in service ..................... 115,682 113,040
Less accumulated depreciation .................... 55,478 53,226
---------- ----------
Net property, plant and equipment ............. $4,042,852 $3,993,438
========== ==========
Our depreciation expense on property, plant and equipment was $203.5
million in 2001, $201.7 million in 2000 and $186.1 million in 1999.
7. JOINT OWNERSHIP OF UTILITY PLANTS
Our Ownership at December 31, 2001
--------------------------------------------------------------------------------
In-Service Accumulated Net Ownership
Dates Investment Depreciation MW Percent
------------- ---------- ------------ ----- ---------
(Dollars in Thousands)
LaCygne 1.................... (a) June 1973 $ 188,277 $120,300 344.0 50
Jeffrey 1.................... (b) July 1978 306,136 148,000 625.0 84
Jeffrey 2.................... (b) May 1980 312,803 134,322 612.0 84
Jeffrey 3.................... (b) May 1983 411,582 179,867 623.0 84
Jeffrey wind 1............... (b) May 1999 874 98 0.6 84
Jeffrey wind 2............... (b) May 1999 873 97 0.6 84
Wolf Creek................... (c) Sept. 1985 1,387,391 528,268 550.0 47
State Line................... (d) June 2001 105,391 2,108 200.0 40
----------
(a) Jointly owned with Kansas City Power and Light Company (KCPL)
(b) Jointly owned with Aquila, Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
(d) Jointly owned with Empire District Electric Company (EDE)
Amounts and capacity presented above represent our share. Our share of
operating expenses of the plants in service above, as well as such expenses for
a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity)
sold and leased back to KGE in 1987, are included in operating expenses on our
consolidated statements of income. Our share of other transactions associated
with the plants is included in the appropriate classification in our
consolidated financial statements.
80
8. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD
Our investments that are accounted for by the equity method are as
follows:
Ownership at Equity Earnings,
December 31, Investment at December 31, Year Ended December 31,
------------ -------------------------- -----------------------
2001 2001 2000 2001 2000
------------ -------- -------- ------ ------
(Dollars in Thousands)
ONEOK (a) ................................ 45% $598,929 $591,173 $4,721 $8,213
International companies and joint
ventures(b) .......................... 9% to 50% 1,976 13,514 2,334 3,394
----------
(a) We also received approximately $40 million of preferred and common
dividends in both 2001 and 2000. ONEOK equity earnings for 2001 decreased
due to charges recorded for Enron Corp. exposure and for certain
regulatory issues ONEOK has in Oklahoma.
(b) Investment is aggregated. Individual investments are not material.
During 2001, we disposed of our portfolio of affordable housing tax credit
limited partnerships. We recorded earnings on these partnerships, including
equity in earnings and loss on disposal, of $4.4 million.
The following is summarized unaudited ONEOK financial information related
to our investment in ONEOK:
As of December 31,
-------------------------------
2001 2000
---------- ----------
(In Thousands)
Balance Sheet:
Current assets ................................... $1,561,969 $3,324,959
Non-current assets ............................... 4,317,190 4,035,386
Current liabilities .............................. 1,818,417 3,526,561
Long-term debt, net .............................. 1,498,012 1,336,082
Other deferred credits and other liabilities ..... 1,297,440 1,272,745
Equity ........................................... 1,265,290 1,224,957
For the Year Ended December 31,
-------------------------------
2001 2000
---------- ----------
(In Thousands)
Income Statement:
Revenues ......................................... $6,803,146 $6,642,858
Gross profit ..................................... 908,785 797,132
Income before cumulative effect of a change in
accounting principle .......................... 103,716 143,492
Net income ....................................... 101,565 145,607
At December 31, 2001, our ownership interest in ONEOK was comprised of
approximately 4.7 million common shares and approximately 19.9 million
convertible preferred shares, each share of which is convertible into two shares
of ONEOK common stock. If all the preferred shares were converted, we would then
own approximately 45% of ONEOK's common shares outstanding.
ONEOK earnings for 2001 include a pretax charge of $34.6 million for
unrecovered gas costs from the winter of 2000/2001 and a $37.4 million pretax
charge related to the Enron Corp. bankruptcy. The charge for the outstanding gas
costs is a result of the Oklahoma Corporation Commission order denying ONEOK the
right to collect a portion of gas costs incurred during the winter of 2000/2001.
Gas prices increased significantly in this period due to high demand and a
perceived supply shortage. The charges related to Enron Corp.'s bankruptcy are
due to Enron Corp.'s non-payment of both financial and physical natural gas
positions for November and December of 2001. These charges also include the
value of forward natural gas positions on ONEOK's termination of natural
81
gas contracts in early January 2002. These contracts were related to physical
commodity sales and storage management activities.
9. MONITORED SERVICES' CUSTOMER ACCOUNTS
The following is a rollforward of the investment in customer accounts (at
cost) of the monitored services segment for the following years:
December 31,
------------------------------
2001 2000
----------- -----------
(In Thousands)
Beginning customer accounts, net ......... $ 1,005,505 $ 1,122,585
Acquisition of customer accounts ......... 17,482 54,993
Amortization of customer accounts ........ (153,019) (163,297)
Sale of accounts ......................... (42,246) --
Purchase holdbacks and other ............. 2,986 (8,776)
----------- -----------
Ending customer accounts, net ....... $ 830,708 $ 1,005,505
=========== ===========
Accumulated amortization of the investment in customer accounts at
December 31, 2001 was $630.5 million and $493.4 million at December 31, 2000.
Customer account amortization expense was $153.0 million for 2001, $163.3
million for 2000, and $186.0 million for 1999.
During 2001, the monitored services segment's attrition, along with its
change in focus from growth to strengthening operations, dispositions of certain
accounts and Protection One's conversion to MAS(R), resulted in a net loss of
267,347 customers or a 17.8% decrease in its customer base from January 1, 2001.
This was the primary cause of Protection One's $59.9 million decline in
monitoring and related service revenues in its North America segment from
January 1, 2001. Protection One expects this trend will continue until the
efforts it is making to acquire new accounts and reduce its rate of attrition
become more successful than they have been to date. Until Protection One is able
to reverse this trend, net losses of customer accounts will materially and
adversely affect our business, financial position and results of operations.
10. SHORT-TERM DEBT
We have an arrangement with certain banks to provide a revolving credit
facility on a committed basis totaling $500 million. The facility is secured by
our and KGE's first mortgage bonds and matures on March 17, 2003. We also have
arrangements with certain banks to provide unsecured short-term lines of credit
on a committed basis totaling approximately $7.0 million. As of December 31,
2001, borrowings on these facilities were $222.3 million.
The agreements provide us with the ability to borrow at different
market-based interest rates. We pay commitment or facility fees in support of
these lines of credit. Under the terms of the agreements, we are required, among
other restrictions, to maintain a total debt to total capitalization ratio of
not greater than 65% at all times. We are in compliance with this covenant. At
December 31, 2001, the capitalization ratio was 61.4%. Under the terms of the
facility, the impairment charge to be recorded in the first quarter of 2002 will
not affect compliance with this covenant in future periods.
82
Information regarding our short-term borrowings is as follows:
As of December 31,
----------------------
2001 2000
-------- --------
(Dollars in Thousands)
Borrowings outstanding at year end:
Credit agreement ..................................................... $222,300 $ 35,000
Weighted average interest rate on debt outstanding at year end ............ 3.44% 8.11%
Weighted average short-term debt outstanding during the year .............. $123,131 $402,845
Weighted daily average interest rates during the year, including fees ..... 6.58% 7.92%
Our interest expense on short-term debt and other was $40.6 million in
2001, $63.1 million in 2000 and $57.7 million in 1999.
83
11. LONG-TERM DEBT
Long-term debt outstanding is as follows at December 31:
2001 2000
---------- ----------
(In Thousands)
Western Resources
-----------------
First mortgage bond series:
7 1/4% due 2002 ........................................................ $ 100,000 $ 100,000
8 1/2% due 2022 ........................................................ 125,000 125,000
7.65% due 2023 ......................................................... 100,000 100,000
---------- ----------
325,000 325,000
---------- ----------
Pollution control bond series:
Variable due 2032, 1.43% at December 31, 2001 .......................... 45,000 45,000
Variable due 2032, 1.70% at December 31, 2001 .......................... 30,500 30,500
6% due 2033 ............................................................ 58,340 58,410
---------- ----------
133,840 133,910
---------- ----------
6 7/8% unsecured senior notes due 2004 ...................................... 355,560 370,000
7 1/8% unsecured senior notes due 2009 ...................................... 150,000 150,000
6.80% unsecured senior notes due 2018 ....................................... 28,104 28,977
6.25% unsecured senior notes due 2018, putable/callable 2003 ................ 384,300 400,000
Senior secured term loan due 2003, variable rate of 7.9% at December 31,
2001 .................................................................... 591,000 600,000
Other long-term agreements .................................................. 5,830 16,889
---------- ----------
1,514,794 1,565,866
---------- ----------
KGE
---
First mortgage bond series:
7.60% due 2003 ......................................................... 135,000 135,000
6 1/2% due 2005 ........................................................ 65,000 65,000
6.20% due 2006 ......................................................... 100,000 100,000
---------- ----------
300,000 300,000
---------- ----------
Pollution control bond series:
5.10% due 2023 ......................................................... 13,493 13,623
Variable due 2027, 1.35% at December 31, 2001 .......................... 21,940 21,940
7.0% due 2031 .......................................................... 327,500 327,500
Variable due 2032, 1.5% at December 31, 2001 ........................... 14,500 14,500
Variable due 2032, 1.53% at December 31, 2001 .......................... 10,000 10,000
---------- ----------
387,433 387,563
---------- ----------
Protection One
--------------
Convertible senior subordinated notes due 2003, fixed rate 6.75% ............ 23,770 23,785
Senior subordinated discount notes due 2005, effective rate 11.8% ........... 33,520 42,887
Senior unsecured notes due 2005, fixed rate 7.375% .......................... 203,650 204,650
Senior subordinated notes due 2009, fixed rate 8.125% ....................... 174,840 255,740
Other ....................................................................... 898 267
---------- ----------
436,678 527,329
---------- ----------
Protection One Europe
---------------------
CET recourse financing agreements, average effective rate 13.17%(a) .......... 34,931 33,512
---------- ----------
Unamortized debt premium (b) ................................................... 12,837 13,541
Less:
Unamortized debt discount (b) ............................................... 6,555 7,047
Long-term debt due within one year .......................................... 160,576 41,825
---------- ----------
Long-term debt, net .................................................... $2,978,382 $3,237,849
========== ==========
----------
(a) Agreements mature on various dates not exceeding four years.
(b) Debt premiums, discounts and expenses are being amortized over the
remaining lives of each issue.
The amount of our first mortgage bonds authorized by our Mortgage and Deed
of Trust, dated July 1, 1939, as supplemented, is unlimited. The amount of KGE's
first mortgage bonds authorized by the KGE Mortgage and
84
Deed of Trust, dated April 1, 1940, as supplemented, is limited to a maximum of
$2 billion, unless amended. First mortgage bonds are secured by utility assets.
Amounts of additional bonds that may be issued are subject to property, earnings
and certain restrictive provisions of each mortgage.
Our unsecured debt represents general obligations that are not secured by
any of our properties or assets. Any unsecured debt will be subordinated to all
of our secured debt, including the first mortgage bonds. The notes are
structurally subordinated to all secured and unsecured debt of our subsidiaries.
We have material amounts of debt maturing over the next one to two years
(see also Note 10 above). This debt will need to be refinanced. We are
evaluating strategies for refinancing this debt.
On June 28, 2000, we entered into a $600 million, multi-year term loan
that replaced two revolving credit facilities that matured on June 30, 2000. We
had $591 million outstanding on the term loan at December 31, 2001. The term
loan is secured by our and KGE's first mortgage bonds and has a maturity date of
March 17, 2003. The term loan agreement contains requirements for maintaining
certain consolidated leverage ratios, interest coverage ratios and consolidated
debt to capital ratios. At December 31, 2001, we were in compliance with all of
these requirements. In January 2002, we repaid $44 million of the term loan with
the proceeds of our sale of investments in low income housing tax credit
partnerships. The outstanding balance of the term loan after this prepayment was
$547 million. In March 2002, we entered into an amendment to the term loan that
adds to the calculation of consolidated earnings before interest, taxes,
depreciation and amortization, the severance costs incurred in the fourth
quarter of 2001 and the first quarter of 2002 related to our work force
reductions, and maintains the current maximum consolidated leverage ratio of
5.75 to 1.0 through the maturity date of the term loan in March 2003. We expect
to be in compliance with all covenants through the remaining term of this
agreement.
Maturities of the term loan through March 17, 2003, are as follows:
Principal Amount
----------------
Year (In Thousands)
----
2002 ....................... $ 6,000
2003 ....................... 541,000
--------
$547,000
========
Interest on the term loan is payable on the expiration date of each
borrowing under the facility or quarterly if the term of the borrowing is
greater than three months. The weighted average interest rate, including
amortization of fees, on the term loan for the year ending December 31, 2001,
was 7.9%.
Maturities of long-term debt as of December 31, 2001 are as follows:
Principal Amount
----------------
As of December 31, (In Thousands)
------------------
2002 (a).................... $ 160,576
2003........................ 715,414
2004........................ 364,128
2005........................ 306,414
2006........................ 100,457
Thereafter.................. 1,491,969
----------
$3,138,958
==========
----------
(a) Amount due includes $38.5 million related to the sale of investments
required to be repaid under the mandatory prepayment provisions of our
credit agreement.
Our interest expense on long-term debt was $227.6 million in 2001, $226.4
million in 2000 and $236.4 million in 1999.
85
In 1998, Protection One issued $350 million of unsecured Senior
Subordinated Notes due 2009. As a result of the completion of a registered offer
to exchange a new series of 8.125% Series B Senior Subordinated Notes for a like
amount of Protection One's outstanding 8.125% Senior Subordinated Notes,
effective June 1, 2001 the annual interest rate on all of such outstanding notes
decreased from 8.625% to 8.125%. Because the exchange offer was not completed
within six months of the issuance date, Protection One had been paying an
additional 0.5% interest penalty since June 1999. At the time of the exchange,
the resulting annual interest savings were $1.2 million. The notes are
redeemable at Protection One's option, in whole or in part, at a predefined
price. Interest on these notes is payable semi-annually on January 15 and July
15.
In 1998, Protection One issued $250 million of Senior Unsecured Notes.
Interest is payable semi-annually on February 15 and August 15. The notes are
redeemable at Protection One's option, in whole or in part, at a predefined
price.
In 1995, Protection One issued $166 million of Unsecured Senior
Subordinated Discount Notes with a fixed interest rate of 13.625%. Interest
payments began in 1999 and are payable semi-annually on June 30 and December 31.
In connection with the acquisition of Protection One in 1997, these notes were
restated to fair value. As of June 30, 2000, the notes became redeemable at
Protection One's option, at a specified redemption price.
In 1996, Protection One issued $103.5 million of Convertible Senior
Subordinated Notes. Interest is payable semi-annually on March 15 and September
15. The notes are convertible at any time at a conversion price of $11.19 per
share. As of September 19, 1999, the notes became redeemable, at Protection
One's option, at a specified redemption price.
During the last three years, Protection One and our bonds were repurchased
in the open market and extraordinary gains were recognized on the retirement of
these bonds of $23.2 million in 2001, $49.2 million in 2000 and $13.4 million in
1999, net of tax. From January 1, 2002 through February 2002, a gain of $3.6
million, net of tax, was recognized on the repurchase of Protection One and our
bonds.
Protection One Europe has recognized as a financing transaction cash
received through the sale of security equipment and future cash flows to be
received under security equipment operating lease agreements with customers to a
third-party financing company.
Protection One's debt instruments contain financial and operating
covenants which may restrict its ability to incur additional debt, pay
dividends, make loans or advances and sell assets. At December 31, 2001,
Protection One was in compliance with its debt covenants.
The indentures governing all of Protection One's debt securities require
that Protection One offer to repurchase the securities in certain circumstances
following a change of control.
12. EMPLOYEE BENEFIT PLANS
Pension
-------
We maintain qualified noncontributory defined benefit pension plans
covering substantially all utility employees. Pension benefits are based on
years of service and the employee's compensation during the five highest paid
consecutive years out of ten before retirement. Our policy is to fund pension
costs accrued, subject to limitations set by the Employee Retirement Income
Security Act of 1974 and the Internal Revenue Code. We also maintain a
non-qualified Executive Salary Continuation Program for the benefit of certain
management employees, including executive officers.
86
Post-retirement Benefits
------------------------
We accrue the cost of post-retirement benefits, primarily medical benefit
costs, during the years an employee provides service.
The following tables summarize the status of our pension and other
postretirement benefit plans:
Pension Benefits Post-retirement Benefits
----------------------- ------------------------
December 31, 2001 2000 2001 2000
----------------------------------------------------------------------------------------------------------------------
(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year ....................... $ 383,403 $ 350,749 $ 102,530 $ 79,287
Service cost ................................................ 9,042 7,964 1,477 1,344
Interest cost ............................................... 28,783 26,901 7,344 7,158
Plan participants' contributions ............................ -- -- 1,189 1,130
Benefits paid ............................................... (23,982) (20,337) (7,741) (6,476)
Assumption changes .......................................... 39 19,350 587 5,038
Actuarial losses (gains) .................................... 21,662 (2,491) 2,697 15,049
Curtailments, settlements and special term benefits ......... 4,867 1,267 547 --
--------- --------- --------- ---------
Benefit obligation, end of year ............................. $ 423,814 $ 383,403 $ 108,630 $ 102,530
========= ========= ========= =========
Change in Plan Assets:
Fair value of plan assets, beginning of year ................ $ 490,173 $ 506,995 $ 394 $ 261
Actual return on plan assets ................................ (2,144) 1,448 19 17
Employer contribution ....................................... 3,015 2,067 6,716 5,462
Plan participants' contributions ............................ -- -- 1,189 1,130
Benefits paid ............................................... (23,982) (20,337) (7,741) (6,476)
--------- --------- --------- ---------
Fair value of plan assets, end of year ...................... $ 467,062 $ 490,173 $ 577 $ 394
========= ========= ========= =========
Funded status ............................................... $ 43,248 $ 106,770 $(108,053) $(102,136)
Unrecognized net (gain)/loss ................................ (65,477) (141,443) 14,447 11,904
Unrecognized transition obligation, net ..................... 141 174 44,195 48,183
Unrecognized prior service cost ............................. 24,071 29,538 (2,797) (3,264)
--------- --------- --------- ---------
Prepaid (accrued) postretirement benefit costs .............. $ 1,983 $ (4,961) $ (52,208) $ (45,313)
========= ========= ========= =========
Amounts recognized in the statement of financial
position consist of:
Prepaid benefit cost ........................................ $ 19,687 $ 9,712 $ N/A $ N/A
Accrued benefit liability ................................... (17,704) (14,673) (52,208) (45,313)
Additional minimum liability ................................ (7,370) -- N/A N/A
Intangible asset ............................................ 658 -- N/A N/A
Accumulated other comprehensive income ...................... 6,712 -- N/A N/A
--------- --------- --------- ---------
Net amount recognized ....................................... $ 1,983 $ (4,961) $ (52,208) $ (45,313)
========= ========= ========= =========
Actuarial Assumptions:
Discount rate ............................................... 7.25% 7.25-7.75% 7.25% 7.25-7.75%
Expected rate of return ..................................... 9.0-9.25% 9.00-9.25% 9.0-9.25% 9.00-9.25%
Compensation increase rate .................................. 4.0-5.0% 4.25-5.00% 4.0-5.0% 4.50-5.00%
Components of net periodic (benefit) cost:
Service cost ................................................ $ 9,042 $ 7,972 $ 1,477 $ 1,344
Interest cost ............................................... 28,783 26,977 7,344 7,157
Expected return on plan assets .............................. (43,001) (39,143) (36) (24)
Amortization of unrecognized transition obligation, net ..... 34 35 3,987 3,988
Amortization of unrecognized prior service costs ............ 3,317 3,316 (466) (466)
Amortization of (gain)/loss, net ............................ (8,327) (9,427) 794 457
Other ....................................................... -- 9 -- --
Curtailments, settlements and special term benefits ......... 6,133 -- -- --
--------- --------- --------- ---------
Net periodic (benefit) cost ................................. $ (4,019) $ (10,261) $ 13,100 $ 12,456
========= ========= ========= =========
For measurement purposes, an annual health care cost growth rate of
5.25%-6.0% was assumed for 2001. The health care cost trend rate has a
significant effect on the projected benefit obligation. Increasing the trend
rate
87
by 1% each year would increase the present value of the accumulated projected
benefit obligation by $2.5 million and the aggregate of the service and interest
cost components by $0.2 million. A 1% decrease in the trend rate would decrease
the present value of the accumulated projected benefit obligation by $2.4
million and the aggregate of the service and interest cost components by $0.2
million.
Savings Plans
-------------
We maintain savings plans in which substantially all employees
participate, with the exception of Protection One and Protection One Europe
employees. We match employees' contributions with Western Resources' stock up to
specified maximum limits. Our contributions to the plans are deposited with a
trustee and are invested in one or more funds, including the company stock fund.
Our contributions were $4.4 million for 2001, $3.9 million for 2000 and $3.7
million for 1999.
In 1999, we established a qualified employee stock purchase plan, the
terms of which allow full-time non-union employees to participate in the
purchase of designated shares of our common stock at no more than a 15%
discounted price. Our employees purchased 67,519 shares in 2001, pursuant to
this plan, at an average price per share of $14.55625. In 2000, employees
purchased 249,050 shares at an average price per share of $13.9984. A total of
1,250,000 shares of common stock have been reserved for issuance under this
program.
Protection One also maintains a savings plan. Contributions, made at
Protection One's election, are allocated among participants based upon the
respective contributions made by the participants through salary reductions
during the year. Protection One's matching contributions may be made in
Protection One common stock, in cash or in a combination of both stock and cash.
Protection One's matching cash contribution to the plan was approximately $1.1
million for 2001, $0.7 million for 2000 and $0.9 million for 1999.
Protection One maintains a qualified employee stock purchase plan that
allows eligible employees to acquire shares of Protection One common stock at
periodic intervals through their accumulated payroll deductions. A total of
1,650,000 shares of common stock have been reserved for issuance in this program
and a total of 912,186 shares have been issued including the issuance of 489,791
shares in January 2002.
Stock Based Compensation Plans
------------------------------
We have a long-term incentive and share award plan (LTISA Plan), which is
a stock-based compensation plan in which utility employees are eligible for
awards. The LTISA Plan was implemented as a means to attract, retain and
motivate employees and board members (Plan Participants). Under the LTISA Plan,
we may grant awards in the form of stock options, dividend equivalents, share
appreciation rights, restricted shares, restricted share units (RSUs),
performance shares and performance share units to Plan Participants. Up to five
million shares of common stock may be granted under the LTISA Plan.
During 2001, 579,915 RSUs were granted to a broad-based group of over
1,000 non-union employees. Each RSU represents a right to receive one share of
our common stock at the end of the restricted period assuming performance
criteria are met. During 2000, 710,352 RSUs were granted. Also in 2000,
non-union employees were offered the opportunity to exchange their stock options
for RSUs of approximately equal economic value. As a result, 2,246,865 stock
options were canceled in 2000 in exchange for 614,741 RSUs. We granted a total
of 152,000 restricted shares in 1999. The grant of restricted stock is shown as
a separate component of shareholders' equity. Unearned compensation is being
amortized to expense over the vesting period. This compensation expense is shown
as a separate component of shareholders' equity.
Another component of the LTISA Plan is the Executive Stock for
Compensation program where in the past eligible employees were entitled to
receive RSUs in lieu of cash compensation at the end of a deferral period. The
Executive Stock for Compensation program was modified in 2001 to pay a portion
of current compensation in the form of stock. In 2001, eligible employees were
issued 31,881 shares of common stock representing $0.7 million of compensation.
In 2000, 95,000 RSUs were awarded in lieu of $1.3 million in cash compensation.
In 1999, 35,000
88
RSUs were awarded in lieu of $0.7 million of cash compensation. Dividend
equivalents accrue on the awarded RSUs. Dividend equivalents are the right to
receive cash equal to the value of dividends paid on our common stock.
Stock options and RSUs under the LTISA plan are as follows:
As of December 31,
2001 2000 1999
------------------------ ------------------------ ------------------------
Weighted- Weighted- Weighted-
Average Average Average
Shares Exercise Shares Exercise Shares Exercise
(Thousands) Price (Thousands) Price (Thousands) Price
---------- ---------- ---------- ---------- ---------- ----------
Outstanding, beginning of year ...... 2,105.6 $ 22.583 2,418.6 $ 34.139 1,590.7 $ 36.106
Granted ............................. 649.4 24.75 1,953.1 15.513 981.6 30.613
Exercised ........................... (278.2) 19.05 (0.5) 15.625 -- --
Forfeited ........................... (21.7) 17.86 (2,265.6) 28.827 (153.7) 31.985
---------- ---------- ----------
Outstanding, end of year ............ 2,455.1 $ 24.56 2,105.6 $ 22.583 2,418.6 $ 34.139
========== ========== ==========
Weighted-average fair value of awards
granted during the year .......... $ 24.08 $ 11.28 $ 8.22
Stock options and RSUs issued and outstanding at December 31, 2001 are as
follows:
Number Weighted- Weighted-
Range of Issued Average Average
Exercise and Contractual Exercise
Price Outstanding Life in Years Price
--------------- ----------- ------------- ---------
Options - Exercisable:
2000............................ $ 15.3125 3,494 9 $ 15.31
1999............................ 27.8125-32.125 28,546 8 29.44
1998............................ 38.625-43.125 218,380 7 40.97
1997............................ 30.750 185,630 6 30.75
1996............................ 29.250 90,290 5 29.25
-----------
526,340
-----------
Options - Not Exercisable:
2000............................ $ 15.3125 14,273 9 $ 15.31
1999............................ 27.8125-32.125 11,660 8 29.44
-----------
25,933
-----------
Range of
Fair Value at
Grant Date
---------------
Restricted share units:
2001............................ $21.600-$24.200 576,470
2000............................ 15.3125-19.875 1,037,893
1999............................ 27.8125-32.125 152,000
1998............................ 38.625 136,500
-----------
1,902,863
-----------
Total issued................. 2,455,136
===========
An equal number of dividend equivalents were issued to recipients of stock
options and RSUs. Recipients of RSUs receive dividend equivalents when dividends
are paid on shares of company stock. The value of each dividend equivalent
related to stock options is calculated by accumulating dividends that would have
been paid or payable on a share of company common stock. The dividend
equivalents, with respect to stock options, expire after nine years from date of
grant. The weighted-average grant-date fair value of the dividend equivalents on
stock options was $6.28 in 2001 and $6.27 in 2000.
89
The fair value of stock options and dividend equivalents were estimated on
the date of grant using the Black-Scholes option-pricing model. The model
assumed the following at December 31, 2000. There were no options granted in
2001.
2000
----
Dividend yield................................. 6.32%
Expected stock price volatility................ 16.42%
Risk-free interest rate........................ 5.79%
Remaining expected option life................. 5 years
Protection One Stock Warrants and Options
-----------------------------------------
Protection One has outstanding stock warrants and options that were
considered reissued and exercisable upon our acquisition of Protection One on
November 24, 1997. The 1997 Long-Term Incentive Plan (the LTIP), approved by the
Protection One stockholders on November 24, 1997, provides for the award of
incentive stock options to directors, officers and key employees. Under the
LTIP, 4.2 million shares of Protection One are reserved for issuance, subject to
such adjustment as may be necessary to reflect changes in the number or kinds of
shares of common stock or other securities of Protection One. The LTIP provides
for the granting of options that qualify as incentive stock options under the
Internal Revenue Code and options that do not so qualify.
Options issued since 1997 have a term of 10 years and vest ratably over 3
years. The purchase price of the shares issuable pursuant to the options is
equal to (or greater than) the fair market value of the common stock at the date
of the option grant.
A summary of warrant and option activity for Protection One common stock
from December 31, 1999 through December 31, 2001 is as follows:
December 31,
-------------------------------------------------------------------
2001 2000 1999
--------------------- --------------------- ---------------------
Weighted- Weighted- Weighted-
Average Average Average
Shares Exercise Shares Exercise Shares Exercise
(Thousands) Price (Thousands) Price (Thousands) Price
----------- -------- ----------- -------- ----------- --------
Outstanding, beginning of year .... 4,404.6 $ 6.058 3,788.1 $ 7.232 3,422.7 $ 7.494
Granted ........................... 1,880.5 1.327 922.5 1.436 1,092.9 7.905
Exercised ......................... (59.7) 2.490 (5.4) 3.890 -- --
Forfeited ......................... (555.3) 4.941 (300.6) 6.698 (727.5) 10.125
-------- -------- --------
Outstanding, end of year .......... 5,670.1 4.281 4,404.6 6.058 3,788.1 7.232
======== ======== ========
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Stock options and warrants of Protection One issued and outstanding at
December 31, 2001 are as follows:
Number Weighted- Weighted-
Range of Issued Average Average
Exercise and Contractual Exercise
Price Outstanding Life in Years Price
--------------- ----------- ------------- --------
Exercisable:
Fiscal 1995................ $6.375 - $6.500 130,800 3 $6.4954
Fiscal 1996................ 8.000 - 15.000 438,400 4 10.0478
Fiscal 1997................ 9.500 - 15.000 209,000 5 11.9565
Fiscal 1998................ 11.000 812,500 6 11.0000
Fiscal 1999................ 5.250 - 8.9275 355,606 7 8.4857
Fiscal 2000................ 1.4375 153,372 8 1.4375
1993 Warrants.............. 0.167 428,400 2 0.1670
1995 Note Warrants......... 3.890 780,837 3 3.8900
-----------
Total................ 3,308,915
-----------
Not Exercisable:
1999 options............... $5.2500 - $8.9275 165,008 7 $8.4857
2000 options............... 1.4375 315,648 8 1.4375
2001 options............... 0.8750 - 1.480 1,880,541 9 1.3273
-----------
Total................ 2,361,197
-----------
Total outstanding............. 5,670,112
===========
The weighted average fair value of options for Protection One stock
granted by Protection One during 2001, 2000 and 1999 estimated on the date of
grant were $1.88, $1.13 and $5.41. The fair value was calculated using the
following assumptions:
Year Ended December 31,
--------------------------------
2001 2000 1999
------- ------- -------
Expected stock price volatility............. 83.92% 92.97% 64.06%
Risk free interest rate..................... 4.95% 4.87% 6.76%
Expected option life........................ 7 years 6 years 6 years
Effect of Stock-Based Compensation on Earnings Per Share
We account for both our and Protection One's plans under Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and
the related interpretations. Had compensation expense been determined pursuant
to SFAS No. 123, "Accounting for Stock-Based Compensation," we would have
recognized additional compensation costs during 2001, 2000 and 1999 as shown in
the table below.
Year Ended December 31, 2001 2000 1999
-------------------------------------------------------------------------------------------------------
(In Thousands, Except Per Share Amounts)
Earnings (loss) available for common stock (a):
As reported ............................................. $ (21,771) $ 135,352 $ 13,167
Pro forma ............................................... (21,259) 134,274 10,699
Basic and diluted earnings (losses) per common share (a):
As reported ............................................. $ (0.31) $ 1.96 $ 0.20
Pro forma ............................................... $ (0.30) 1.95 0.16
----------
(a) Represents consolidated Western Resources.
91
Split Dollar Life Insurance Program
-----------------------------------
We have established a split dollar life insurance program for our benefit
and the benefit of certain of our executives. Under the program, we have
purchased life insurance policies on which the executive's beneficiary is
entitled to a death benefit in an amount equal to the face amount of the policy
reduced by the greater of (i) all premiums paid by the company or (ii) the cash
surrender value of the policy, which amount, at the death of the executive, will
be returned to us. We retain an equity interest in the death benefit and cash
surrender value of the policy to secure this repayment obligation.
Subject to certain conditions, each executive may transfer to us their
interest in the death benefit based on a predetermined formula, beginning no
earlier than the first day of the calendar year following retirement or three
years from the date of the policy. The liability associated with this program
was $18.6 million as of December 31, 2001 and $19.1 million as of December 31,
2000. The obligations under this program can increase and decrease based on our
total return to shareholders and payments to plan participants. This liability
decreased approximately $0.5 million in 2001 primarily due to balance
adjustments and $12.8 million in 2000 due primarily to payments to plan
participants. In 1999, the liability decreased approximately $10.5 million based
on our total return to shareholders. Under current tax rules, payments to active
employees in exchange for their interest in the death benefits may not be fully
deductible by us for income tax purposes. Subsequent to December 31, 2001, this
liability was reduced by a payment of $4.6 million pursuant to the plan.
13. INCOME TAXES
Income tax expense (benefit) is composed of the following components at
December 31:
2001 2000 1999
-------- -------- --------
(In Thousands)
Current income taxes:
Federal ............................... $(21,942) $ 39,747 $ 12,996
State ................................. (186) 10,131 9,622
Deferred income taxes:
Federal ............................... (28,363) 18,060 (35,857)
State ................................. 1,180 9,585 (6,582)
Investment tax credit amortization ...... (6,646) (6,045) (6,054)
-------- -------- --------
Total ............................ (55,957) 71,478 (25,875)
Less taxes classified in:
Extraordinary gain .................... 12,571 26,514 6,322
Cumulative effect of accounting change 12,347 (1,097) --
-------- -------- --------
Total income tax (benefit) expense .... $(80,875) $ 46,061 $(32,197)
======== ======== ========
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Under SFAS No. 109, "Accounting for Income Taxes," temporary differences
gave rise to deferred tax assets and deferred tax liabilities summarized in the
following table.
December 31,
--------------------------
2001 2000
---------- ----------
(In Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback ............. $ 76,806 $ 82,013
Customer accounts ........................... 60,023 49,853
General business credit carryforward (a) .... 28,494 11,012
Accrued liabilities ......................... 23,511 21,108
Disallowed plant costs ...................... 16,650 17,758
Long-term energy contracts .................. 13,538 14,209
Other ....................................... 115,874 110,261
---------- ----------
Total deferred tax assets ................ $ 334,896 $ 306,214
========== ==========
Deferred tax liabilities
Accelerated depreciation .................... $ 617,682 $ 627,024
Acquisition premium ......................... 267,161 275,159
Deferred future income taxes ................ 222,071 188,006
Investment tax credits ...................... 84,900 91,546
Other ....................................... 39,443 44,562
---------- ----------
Total deferred tax liabilities ........... $1,231,257 $1,226,297
========== ==========
----------
(a) Balance represents unutilized tax credits generated from affordable
housing partnerships in which we sold the majority of our interests in
2001. These credits expire beginning 2019 through 2021.
Deferred tax assets and liabilities are reflected on our consolidated
balance sheets as follows:
December 31,
-----------------------
2001 2000
-------- --------
(In Thousands)
Current deferred tax assets, net ................. $ 27,817 $ 34,512
Non-current deferred tax liabilities, net ........ 924,178 954,595
-------- --------
Net deferred tax liabilities ..................... $896,361 $920,083
======== ========
In accordance with various rate orders, we have not yet collected through
rates certain accelerated tax deductions, which have been passed on to
customers. We believe it is probable that the net future increases in income
taxes payable will be recovered from customers. We have recorded a regulatory
asset for these amounts. These assets are also a temporary difference for which
deferred income tax liabilities have been provided. This liability is classified
above as deferred future income taxes.
93
The effective income tax rates set forth below are computed by dividing
total federal and state income taxes by the sum of such taxes and net income.
The difference between the effective tax rates and the federal statutory income
tax rates are as follows:
For the Year Ended December 31,
------------------------------
2001 2000 1999
------ ------ ------
Effective income tax rate .................................. (56.3)% 33.6% (108.6)%
Effect of:
State income taxes ...................................... 0.6 (9.4) (7.1)
Amortization of investment tax credits .................. 4.6 4.4 20.4
Corporate-owned life insurance policies ................. 9.5 8.4 28.0
Affordable housing tax credits .......................... 6.8 7.8 31.3
Accelerated depreciation flow through and amortization .. (0.1) (4.9) (12.2)
Dividends received deduction ............................ 7.1 7.1 34.3
Amortization of goodwill ................................ (10.6) (13.0) (19.3)
Other ................................................... 3.4 1.0 (1.8)
------ ------ ------
Statutory federal income tax rate .......................... (35.0)% 35.0% (35.0)%
====== ====== ======
14. COMMITMENTS AND CONTINGENCIES
Municipalization Efforts by Wichita
-----------------------------------
In December 1999, the City Council of Wichita, Kansas, authorized the
hiring of an outside consultant to determine the feasibility of creating a
municipal electric utility to replace KGE as the supplier of electricity in
Wichita. The feasibility study was released in February 2001 and estimates that
the City of Wichita would be required to pay us $145 million for our stranded
costs if it were to municipalize. However, we estimate the amount to be
substantially greater. In order to municipalize KGE's Wichita electric
facilities, the City of Wichita would be required to purchase KGE's facilities
or build a separate independent system and arrange for its own power supply.
These costs are in addition to the stranded costs for which the city would be
required to reimburse us. On February 2, 2001, the City of Wichita announced its
intention to proceed with its attempt to municipalize KGE's retail electric
utility business in Wichita. KGE will oppose municipalization efforts by the
City of Wichita. Should the city be successful in its municipalization efforts
without providing us adequate compensation for our assets and lost revenues, the
adverse effect on our business and financial condition could be material.
KGE's franchise with the City of Wichita to provide retail electric
service is effective through December 1, 2002. There can be no assurance that we
can successfully renegotiate the franchise with terms similar, or as favorable,
as those in the current franchise. Under Kansas law, KGE will continue to have
the right to serve the customers in Wichita following the expiration of the
franchise, assuming the system is not municipalized. Customers within the
Wichita metropolitan area account for approximately 23% of our total energy
sales.
Purchase Orders and Contracts
-----------------------------
As part of our ongoing operations and construction program, we have
commitments under purchase orders and contracts, excluding fuel (which is
discussed below under "-- Fuel Commitments,") that have an unexpended balance of
approximately $98.4 million at December 31, 2001.
Manufactured Gas Sites
----------------------
We have been associated with 15 former manufactured gas sites located in
Kansas that may contain coal tar and other potentially harmful materials. We and
the Kansas Department of Health and Environment (KDHE) entered into a consent
agreement governing all future work at these sites. The terms of the consent
agreement will allow us to investigate these sites and set remediation
priorities based on the results of the investigations and risk analysis. At
December 31, 2001, the costs incurred for preliminary site investigation and
risk assessment have been
94
minimal. In accordance with the terms of the strategic alliance with ONEOK,
ownership of twelve of these sites and the responsibility for clean-up of these
sites were transferred to ONEOK. The ONEOK agreement limits our future liability
associated with these sites to an immaterial amount. Our investment earnings
from ONEOK could be impacted by these costs.
Superfund Sites
---------------
In December 1999, we were identified as one of more than 1,000 potentially
responsible parties at an EPA Superfund site in Kansas City, Kansas (Kansas City
site). We have previously been associated with other Superfund sites for which
our liability has been classified as de minimis, or insignificant, and any
potential obligations have been settled at minimal cost. Since 1993, we have
settled Superfund obligations at three sites for a total of $141,300. We were
notified in 2001 that one site was issued an EPA "Notice of Completion of Work"
and final oversight costs have been paid out of the existing joint responsible
party account, which has an adequate balance to cover this expense. This
effectively closes this site and we can expect a refund in 2002 of our share of
the remaining funds in this account. Our obligation, if any, at the Kansas City
site is expected to be limited based upon previous experience and the limited
nature of our business transactions with the previous owners of the site. In the
opinion of our management, the resolution of this matter is not expected to have
a material impact on our financial position or results of operations.
Clean Air Act
-------------
We must comply with the provisions of The Clean Air Act Amendments of 1990
that require a two-phase reduction in certain emissions. We have installed
continuous monitoring and reporting equipment to meet the acid rain
requirements. Material capital expenditures have not been required to meet Phase
II sulfur dioxide and nitrogen oxide requirements.
Nuclear Decommissioning
-----------------------
We accrue decommissioning costs over the expected life of the Wolf Creek
generating facility. The accrual is based on estimated unrecovered
decommissioning costs, which consider inflation over the remaining estimated
life of the generating facility and are net of expected earnings on amounts
recovered from customers and deposited in an external trust fund.
On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost
Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost
Study on April 26, 2000. Based on the study, our share of Wolf Creek's
decommissioning costs, under the immediate dismantlement method, is estimated to
be approximately $631 million during the period 2025 through 2034, or
approximately $221 million in 1999 dollars. These costs include decontamination,
dismantling and site restoration and were calculated using an assumed inflation
rate of 3.6% over the remaining service life from 1999 of 26 years. The actual
decommissioning costs may vary from the estimates because of changes in the
assumed dates of decommissioning, changes in regulatory requirements, changes in
technology and changes in costs of labor, materials and equipment. On May 26,
2000, we filed an application with the KCC requesting approval of the funding of
our decommissioning trust on this basis. Approval was granted by the KCC on
September 20, 2000.
Decommissioning costs are currently being charged to operating expense in
accordance with prior KCC orders. Electric rates charged to customers provide
for recovery of these decommissioning costs over the life of Wolf Creek. Amounts
expensed approximated $4.0 million in 2001 and will increase annually to $5.5
million in 2024. These amounts are deposited in an external trust fund. The
average after-tax expected return on trust assets is 5.8%.
Our investment in the decommissioning fund is recorded at fair value,
including reinvested earnings. It approximated $66.6 million at December 31,
2001 and $64.2 million at December 31, 2000. Trust fund earnings accumulate in
the fund balance and increase the recorded decommissioning liability.
95
Storage of Spent Nuclear Fuel
-----------------------------
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE)
is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays
the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net
nuclear generation produced for the future disposal of spent nuclear fuel. These
disposal costs are charged to cost of sales.
A permanent disposal site will not be available for the nuclear industry
until 2010 or later. Under current DOE policy, once a permanent site is
available, the DOE will accept spent nuclear fuel on a priority basis. The
owners of the oldest spent fuel will be given the highest priority. As a result,
disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek
has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek
completed replacement of spent fuel storage racks to increase its on-site
storage capacity for all spent fuel expected to be generated by Wolf Creek
through the end of its licensed life in 2025.
Asset Retirement Obligations
----------------------------
In August 2001, the Financial Accounting Standards Board issued SFAS No.
143, "Accounting for Asset Retirement Obligations." The standard requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When it is initially recorded,
we will capitalize the estimated asset retirement obligation by increasing the
carrying amount of the related long-lived asset. The liability will be accreted
to its present value each period and the capitalized cost will be depreciated
over the life of the asset. The standard is effective for fiscal years beginning
after June 15, 2002. We expect to adopt this standard January 1, 2003. This
standard will impact the way we currently account for the decommissioning of
Wolf Creek. In addition to the accounting for the Wolf Creek decommissioning, we
are also reviewing what impact this pronouncement will have on our current
accounting practices and our results of operations as it relates to other asset
retirement obligations we may identify. The impact is unknown at this time.
Nuclear Insurance
-----------------
The Price-Anderson Act, originally passed by Congress in 1957 and most
recently amended in 1988, requires nuclear power plants to show evidence of
financial protection in the event of a nuclear accident. This protection must
consist of two levels. The primary level provides liability insurance coverage
of $200 million. If this amount is not sufficient to cover claims arising from
an accident, the second level - Secondary Financial Protection - applies. For
the second level, each licensed nuclear unit must pay a retroactive premium
equal to its proportionate share of the excess loss, up to a maximum of $88.1
million per unit per accident.
Currently, 106 nuclear units are participating in the Secondary Financial
Protection program - 103 operating units and three closed units that still
handle used nuclear fuel. The number of units participating in the program will
be reduced as decommissioned units apply for and receive exemptions. Nuclear
power plants provide a total of $9.5 billion in insurance coverage to compensate
the public in the event of a nuclear accident. Taxpayers and the federal
government pay nothing for this coverage.
The Nuclear Regulatory Commission (NRC) was required to submit a report to
Congress, which was submitted in September 1998 and describes the benefits that
the act provides to the public. It also recommends that the act be extended for
an additional ten years. The DOE submitted a report to Congress in March 1999,
recommending renewal of the act.
Bipartisan legislation was introduced in the 106th Congress in the Senate
providing a simple renewal of Price-Anderson based on the DOE and NRC reports.
The nuclear industry supports such a legislative approach for consideration
early in the 107th Congress.
96
Unless Congress renews the Price-Anderson Act, it will expire in part on
August 1, 2002 as follows:
. The only part of Price-Anderson that expires on August 1, 2002, is
the authority of the NRC and the DOE to enter into new indemnity
agreements after that date. Existing indemnity agreements would
continue in full force and effect.
. Without renewal, new nuclear power plants could not be covered, nor
could new DOE contracts have the indemnity provision (including the
proposed high-level radioactive waste disposal site in Yucca
Mountain, Nevada).
The Price-Anderson Act limits the combined public liability of the owners
of nuclear power plants to $9.5 billion for a single nuclear incident. If this
liability limitation is insufficient, the United States Congress will consider
taking whatever action is necessary to compensate the public for valid claims.
However, on February 2, 2002, the United States Senate announced that it is
considering discontinuing the federal insurance provision.
The Wolf Creek owners have purchased the maximum available private
insurance of $200 million. The remaining balance is provided by an assessment
plan mandated by the NRC. Under this plan, the owners are jointly and severally
subject to a retrospective assessment of up to $88.1 million in the event there
is a major nuclear incident involving any of the nation's licensed reactors.
This assessment is subject to an inflation adjustment based on the Consumer
Price Index and applicable premium taxes. There is a limitation of $10 million
in retrospective assessments per incident, per year.
The owners carry decontamination liability, premature decommissioning
liability and property damage insurance for Wolf Creek totaling approximately
$2.8 billion ($1.3 billion our share). This insurance is provided by Nuclear
Electric Insurance Limited (NEIL). In the event of an accident, insurance
proceeds must first be used for reactor stabilization and site decontamination
in accordance with a plan mandated by the NRC. Our share of any remaining
proceeds can be used to pay for property damage or decontamination expenses or,
if certain requirements are met including decommissioning the plant, toward a
shortfall in the decommissioning trust fund.
The owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If losses incurred at
any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves and other NEIL resources, we may be subject to retrospective
assessments under the current policies of approximately $10.7 million per year.
Although we maintain various insurance policies to provide coverage for
potential losses and liabilities resulting from an accident or an extended
outage, our insurance coverage may not be adequate to cover the costs that could
result from a catastrophic accident or extended outage at Wolf Creek. Any
substantial losses not covered by insurance, to the extent not recoverable
through rates, would have a material adverse effect on our financial condition
and results of operations.
Fuel Commitments
----------------
To supply a portion of the fuel requirements for our generating plants, we
have entered into various commitments to obtain nuclear fuel and coal. Some of
these contracts contain provisions for price escalation and minimum purchase
commitments. At December 31, 2001, WCNOC's nuclear fuel commitments (our share)
were approximately $3.2 million for uranium concentrates expiring in 2003, $0.6
million for conversion expiring in 2003, $22.7 million for enrichment expiring
at various times through 2006 and $57.5 million for fabrication through 2025.
At December 31, 2001, our coal and coal transportation contract
commitments in 2001 dollars under the remaining terms of the contracts were
approximately $2.0 billion. The largest contract expires in 2020, with the
remaining contracts expiring at various times through 2013.
At December 31, 2001, our natural gas transportation commitments in 2001
dollars under the remaining terms of the contracts were approximately $56.8
million. The natural gas transportation contracts provide firm
97
service to several of our gas burning facilities and expire at various times
through 2010, except for one contract that expires in 2016.
Energy Act
----------
As part of the 1992 Energy Policy Act, a special assessment is being
collected from utilities for a uranium enrichment decontamination and
decommissioning fund. Our portion of the assessment for Wolf Creek is
approximately $9.6 million, payable over 15 years. Such costs are recovered
through the ratemaking process.
15. PNM MERGER AND SPLIT-OFF OF WESTAR INDUSTRIES
PNM Transaction
---------------
On November 8, 2000, we entered into an agreement with Public Service
Company of New Mexico (PNM), pursuant to which PNM would acquire our electric
utility businesses in a tax-free stock-for-stock merger. Under the terms of the
agreement, both PNM and we are to become subsidiaries of a new holding company,
subject to customary closing conditions including regulatory and shareholder
approvals. Immediately prior to closing, all of the Westar Industries common
stock we own would be distributed to our shareholders in exchange for a portion
of their Western Resources common stock. At the same time we entered into the
agreement with PNM, we and Westar Industries entered into an Asset Allocation
and Separation Agreement which, among other things, provided for this split-off
and related matters.
On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court
of the State of New York. The lawsuit seeks, among other things, declaratory
judgment that PNM is not obligated to proceed with the proposed merger based in
part upon the KCC orders discussed below and other KCC orders reducing rates for
our electric utility business. PNM believes the orders constitute a material
adverse effect and make the condition that the split-off of Westar Industries
occur prior to closing incapable of satisfaction. PNM also seeks unspecified
monetary damages for breach of representation.
On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court
of the State of New York. The lawsuit seeks substantial damages for PNM's breach
of the merger agreement providing for PNM's purchase of our electric utility
operations and for PNM's breach of its duty of good faith and fair dealing. In
addition, we filed a motion to dismiss or stay the declaratory judgment action
previously filed by PNM seeking a declaratory judgment that PNM has no further
obligations under the merger agreement.
On January 7, 2002, PNM sent a letter to us purporting to terminate the
merger in accordance with the terms of the merger agreement. We have notified
PNM that we believe the purported termination of the merger agreement was
ineffective and that PNM remains obligated to perform thereunder. We intend to
contest PNM's purported termination of the merger agreement. However, based upon
PNM's actions and the related uncertainties, we believe the closing of the
proposed merger is not likely.
KCC Proceedings and Orders
--------------------------
The merger with PNM contemplated the completion of a rights offering for
shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an
investigation of the proposed separation of our electric utility businesses from
our non-utility businesses, including the rights offering, and other aspects of
our unregulated businesses. The order opening the investigation indicated that
the investigation would focus on whether the separation and other transactions
involving our unregulated businesses are consistent with our obligation to
provide efficient and sufficient electric service at just and reasonable rates
to our electric utility customers. The KCC staff was directed to investigate,
among other matters, the basis for and the effect of the Asset Allocation and
Separation Agreement we entered into with Westar Industries in connection with
the proposed separation and the intercompany payable owed by us to Westar
Industries, the separation of Westar Industries, the effect of the business
difficulties faced by our unregulated businesses and whether they should
continue to be affiliated with our electric utility business, and our present
and prospective capital structures. On May 22, 2001, the KCC issued an order
nullifying
98
the Asset Allocation and Separation Agreement, prohibiting Westar Industries and
us from taking any action to complete the rights offering for common stock of
Westar Industries, which was to be a first step in the separation, and
scheduling a hearing to consider whether to make the order permanent.
On July 20, 2001, the KCC issued an order that, among other things: (1)
confirmed its May 22, 2001 order prohibiting us and Westar Industries from
taking any action to complete the proposed rights offering and nullifying the
Asset Allocation and Separation Agreement; (2) directed us and Westar Industries
not to take any action or enter into any agreement not related to normal utility
operations that would directly or indirectly increase the share of debt in our
capital structure applicable to our electric utility operations, which has the
effect of prohibiting us from borrowing to make a loan or capital contribution
to Westar Industries; and (3) directed us to present a financial plan consistent
with parameters established by the KCC's order to restore financial health,
achieve a balanced capital structure and protect ratepayers from the risks of
our non-utility businesses. In its order, the KCC also acknowledged that we are
presently operating efficiently and at reasonable cost and stated that it was
not disapproving the PNM transaction or a split-off of Westar Industries. We
appealed the orders issued by the KCC to the District Court of Shawnee County,
Kansas. On February 5, 2002, the District Court issued a decision finding that
the KCC orders were not final orders and that the District Court lacked
jurisdiction to consider the appeal. Accordingly, the matter was remanded to the
KCC for review of the financial plan.
On February 11, 2002, the KCC issued an order primarily related to
procedural matters for the review of the financial plan, as discussed below. In
addition, the order required that we and the KCC staff make filings addressing
whether the filing of applications by us and KGE at FERC, seeking renewal of
existing borrowing authority, violated the July 20, 2001 KCC order directing
that we not increase the share of debt in our capital structure applicable to
our electric utility operations. The KCC staff subsequently filed comments
asserting that the refinancing of existing indebtedness with new indebtedness
secured by utility assets would in certain circumstances violate the July 20,
2001 KCC order. The KCC filed a motion to intervene in the proceeding at FERC
asserting the same position. We are unable to predict whether the KCC will adopt
the KCC staff position, the extent to which FERC will incorporate the KCC
position in orders renewing our borrowing authority, or the impact of the
adoption of the KCC staff position, if that occurs, on our ability to refinance
indebtedness maturing in the next several years. Our inability to refinance
existing indebtedness on a secured basis would likely increase our borrowing
costs and adversely affect results of operations.
The Financial Plan
------------------
The July 20, 2001 KCC order directed us to present a financial plan to the
KCC. We presented a financial plan to the KCC on November 6, 2001, which we
amended on January 29, 2002. The principal objective of the financial plan is to
reduce our total debt as calculated by the KCC to approximately $1.8 billion, a
reduction of approximately $1.2 billion. The financial plan contemplates that we
will proceed with a rights offering and that, in the event that the PNM merger
and related split-off do not close, we will use our best efforts to sell our
share of Westar Industries common stock, or shares of our common stock, upon the
occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to
review the financial plan. We are unable to predict whether or not the KCC will
approve the financial plan or what other action with respect to the financial
plan the KCC may take.
The financial plan provides that:
. Westar Industries will use its best efforts to sell at least 4.14
million shares of its common stock, representing approximately 5.1%
of its outstanding shares, but no more than the number of shares of
its common stock (approximately 19.13 million shares) representing
19.9% of its outstanding shares. After the offering, we would
continue to own 77.0 million shares representing between 80.1% and
94.9% of Westar Industries' outstanding shares. The offering will
remain open for no less than 45 calendar days.
. In the rights offering, each of our shareholders will receive the
right to purchase one share of Westar Industries' common stock for
every three shares of our stock held on the record date of the
offering. There will be no over-subscription privilege in the
offering. However, each shareholder participating in the offering
will be issued, with respect to each right exercised in the
offering, a warrant to purchase
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from Westar Industries two shares of its common stock at the
subscription price in the offering, subject to proration so that in
no event will we hold less than 80.1% of Westar Industries'
outstanding shares. This right will be exercisable at any time in
the 30-day period preceding January 31, 2003.
. So long as we and Westar Industries are tax consolidated, Westar
Industries' common stock sold in the offering will have one vote per
share and Westar Industries common stock held by us will have 10
votes per share. Any shares sold by us will automatically convert to
shares with one vote per share.
. The exercise price in the offering will be a fixed price determined
on the day the offer is mailed to shareholders by calculating the
"Westar Industries Valuation" as set forth in an exhibit to the plan
and then applying a 10% initial public offering discount.
. Westar Industries will have a rescission right through December 31,
2002. This will give Westar Industries the right to repurchase the
shares sold in the rights offering at a price equal to the greater
of (i) 1.05 times the exercise price, or (ii) the market price at
the time of the repurchase offer. The warrants issued to
participating shareholders in the offering will expire if the
rescission right is exercised. We would not be able to sell any
additional shares prior to the expiration of the rescission period.
. The proceeds from the offering (or any other subsequent sale of
stock by Westar Industries) and any dividends from the ONEOK common
or convertible preferred stock not used in Westar Industries'
business or previously committed will be used to purchase in the
market our or KGE's currently outstanding debt securities. On
February 10, 2003, such debt securities and the balance, if any, of
our intercompany payable with Westar Industries will be converted
into our common stock at the average trading price for the 20 days
prior to conversion, but in no event less than $24 per share.
However, if the PNM transaction is not terminated, such funds and
the intercompany payable will be transferred by us to Westar
Industries to purchase 7.5% Western Resources convertible preferred
stock, convertible into our common stock at $30 per share, as
provided in the PNM merger agreement. Prior to tax deconsolidation,
Westar Industries cannot receive any cash dividends from us, but
will instead reinvest those dividends in additional shares of our
common stock. Dividends on the convertible preferred stock will be
payable in additional preferred shares rather than cash. Westar
Industries will use interest received on our and KGE debt securities
it purchases as provided above to purchase additional debt
securities.
. If the PNM transaction is not terminated, the amount of our
convertible preferred stock purchased by Westar Industries will not
exceed $291 million. Westar Industries will continue to own our
common stock it currently owns. Westar Industries will retain its
option to purchase Westar Generating, Inc., a wholly owned
subsidiary of ours, which owns an interest in the State Line
Facility (see "Item 2. Properties" for a description of this
facility and "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Other Information
-- Related Party Transactions" for a discussion of this purchase
option).
. Westar Industries will not vote any of our common stock it owns as
long as we are tax consolidated.
. Westar Industries will adopt a "poison pill" that will restrict
ownership in it to 20% of the shares not owned by us.
. The rights offering and subsequent sale of Westar Industries' shares
by us pursuant to the plan do not constitute a change in control for
our employees under the terms of existing agreements and no
agreements will be executed which include a provision under which
the offering and sale of Westar Industries' shares by us pursuant to
the plan would constitute a change in control.
. We will not sell more than 19.9% of Westar Industries unless we have
$1.8 billion or less in short- and long-term debt and all of our and
KGE's first mortgage bonds are rated investment grade.
100
. In the event Westar Industries' common stock trades for 45
consecutive trading days at a price that is 15% above the price
necessary to reduce our short- and long-term debt to an amount less
than $1.8 billion (as measured at the end of the immediately
preceding fiscal quarter), we will be required to use our best
efforts to sell enough shares in Westar Industries, or us, or a
combination of both (at our option), to reduce debt to $1.8 billion.
However, in no event shall this obligation be triggered prior to
February 1, 2003, unless the PNM transaction is terminated prior to
that date. Furthermore, on each annual anniversary of the closing of
the rights offering, the amount of debt used to determine whether
our obligation has been triggered will increase by $100 million.
. We agree to reduce our total debt by at least $100 million per year
each year following the completion of the offering until the
separation is consummated.
. Our board of directors will have at least a majority of independent
directors following the separation.
16. LEGAL PROCEEDINGS
The Securities and Exchange Commission (SEC) commenced a private
investigation in 1997 relating to, among other things, the timeliness and
adequacy of disclosure filings with the SEC by us with respect to securities of
ADT Ltd. We have cooperated with the SEC staff in this investigation.
We, Westar Industries, Protection One, its subsidiary Protection One Alarm
Monitoring, Inc. (Protection One Alarm Monitoring) and certain present and
former officers and directors of Protection One are defendants in a purported
class action litigation pending in the United States District Court for the
Central District of California, "Alec Garbini, et al v. Protection One, Inc., et
al," No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999, four
pending purported class actions were consolidated into a single action. On
February 27, 2001, plaintiffs filed a Third Consolidated Amended Class Action
Complaint (Third Amended Complaint). Plaintiffs purported to bring the action on
behalf of a class consisting of all purchasers of publicly traded securities of
Protection One, including common stock and bonds, during the period of February
10, 1998 through February 2, 2001. The Third Amended Complaint asserted claims
under Section 11 of the Securities Act of 1933 and Section 10(b) of the
Securities Exchange Act of 1934 against Protection One, Protection One Alarm
Monitoring, and certain present and former officers and directors of Protection
One based on allegations that various statements concerning Protection One's
financial results and operations for 1997, 1998, 1999 and the first three
quarters of 2000 were false and misleading and not in compliance with generally
accepted accounting principles. Plaintiffs alleged, among other things, that
former employees of Protection One have reported that Protection One lacked
adequate internal accounting controls and that certain accounting information
was unsupported or manipulated by management in order to avoid disclosure of
accurate information. The Third Amended Complaint further asserted claims
against us and Westar Industries as controlling persons under Sections 11 and 15
of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities
Exchange Act of 1934. A claim was also asserted under Section 11 of the
Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP.
The Third Amended Complaint sought an unspecified amount of compensatory damages
and an award of fees and expenses, including attorneys' fees. On June 4, 2001,
the District Court dismissed plaintiffs' claims under Sections 10(b) and 20(a)
of the Securities Exchange Act. The Court granted plaintiffs leave to replead
such claims. The Court also dismissed all claims brought on behalf of
bondholders with prejudice. The Court also dismissed plaintiffs' claims against
Arthur Andersen and the plaintiffs have appealed that dismissal. On February 22,
2002, plaintiffs filed a Fourth Consolidated Amended Class Action Complaint. The
new complaint realleges claims on behalf of purchasers of common stock under
Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of
the Securities Exchange Act of 1934. The defendants have until April 5, 2002 to
respond to the new complaint. Protection One and we cannot predict the impact of
this litigation, which could be material.
We and our subsidiaries are involved in various other legal, environmental
and regulatory proceedings. We believe that adequate provision has been made and
accordingly believe that the ultimate disposition of such matters will not have
a material adverse effect upon our overall financial position or results of
operations. See also Notes 3 and 15 for discussion of FERC proceedings and the
lawsuit PNM filed against us and the KCC regulatory proceedings.
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17. LEASES
At December 31, 2001, we had leases covering various property and
equipment. Rental payments for operating leases ranging from 1 to 17 years and
estimated rental commitments are as follows:
LaCygne 2 Total
Year Ended December 31, Lease (a) Leases
------------------------------------------------------ ---------- --------
(In Thousands)
Rental payments:
1999 .............................................. $ 34,598 $ 71,771
2000 .............................................. 34,598 71,232
2001 .............................................. 34,598 75,259
Future commitments:
2002 .............................................. $ 34,598 $ 69,897
2003 .............................................. 39,420 66,772
2004 .............................................. 34,598 58,492
2005 .............................................. 38,013 57,983
2006 .............................................. 42,287 61,309
Thereafter ........................................ 422,318 516,318
-------- --------
Total future commitments ....................... $611,234 $830,771
======== ========
----------
(a) LaCygne 2 lease amounts are included in total leases.
In 1987, KGE sold and leased back its 50% undivided interest in the
LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years,
with various options to renew the lease or repurchase the 50% undivided
interest. KGE remains responsible for its share of operation and maintenance
costs and other related operating costs of LaCygne 2. The lease is an operating
lease for financial reporting purposes. We recognized a gain on the sale, which
was deferred and is being amortized over the initial lease term.
In 1992, we deferred costs associated with the refinancing of the secured
facility bonds of the Trustee and owner of LaCygne 2. These costs are being
amortized over the life of the lease and are included in operating expense.
18. COMMON STOCK, PREFERRED STOCK AND OTHER MANDATORILY REDEEMABLE SECURITIES
Our Restated Articles of Incorporation, as amended, provide for
150,000,000 authorized shares of common stock. At December 31, 2001, 86,205,417
shares were issued and outstanding, including shares owned by Westar Industries.
We have a Direct Stock Purchase Plan (DSPP). Shares issued under the DSPP
may be either original issue shares or shares purchased on the open market.
During 2001, a total of 16,643,403 shares were purchased from the company
through the issuance of 16,123,103 original issue shares and 520,300 treasury
shares. Of the total shares purchased from us in 2001, 15,047,987 were acquired
by Westar Industries and the balance of the shares were for the DSPP, ESPP,
401(k) match and other stock based plans operated under the 1996 Long-Term
Incentive and Share Award Plan. At December 31, 2001, 4,300,577 shares were
available under the DSPP registration statement.
In 2000, we purchased 540,000 shares of our common stock at an average
price of $17.01. All of these shares were reissued during the year.
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Preferred Stock Not Subject to Mandatory Redemption
---------------------------------------------------
The cumulative preferred stock is redeemable in whole or in part on 30 to
60 days notice at our option.
Total
Principal Call Amount
Rate Outstanding Price Premium to Redeem
------ ----------- ------- --------- -----------
(Dollars in Thousands)
4.500% $ 13,445 108.00% $ 1,076 $ 14,521
4.250% 5,841 101.50% 88 5,929
5.000% 4,650 102.00% 93 4,743
----------- --------- -----------
$ 23,936 $ 1,257 $ 25,193
=========== ========= ===========
The provisions of our Restated Articles of Incorporation, as amended,
contain restrictions on the payment of dividends or the making of other
distributions on our common stock while any preferred shares remain outstanding
unless certain capitalization ratios and other conditions are met.
Other Mandatorily Redeemable Securities
---------------------------------------
On December 14, 1995, Western Resources Capital I, a wholly owned trust,
issued 4.0 million preferred securities of 7-7/8% Cumulative Quarterly Income
Preferred Securities, Series A, for $100 million. The trust interests are
redeemable at the option of Western Resources Capital I on or after December 11,
2000, at $25 per preferred security plus accrued interest and unpaid dividends.
Holders of the securities are entitled to receive distributions at an annual
rate of 7-7/8% of the liquidation preference value of $25. Distributions are
payable quarterly and are tax deductible by us. These distributions are recorded
as interest expense. The sole asset of the trust is $103 million principal
amount of 7-7/8% Deferrable Interest Subordinated Debentures, Series A due
December 11, 2025.
On July 31, 1996, Western Resources Capital II, a wholly owned trust, of
which the sole asset is subordinated debentures of ours, sold in a public
offering, 4.8 million shares of 8-1/2% Cumulative Quarterly Income Preferred
Securities, Series B, for $120 million. The trust interests are redeemable at
the option of Western Resources Capital II, on or after July 31, 2001, at $25
per preferred security plus accumulated and unpaid distributions. Holders of the
securities are entitled to receive distributions at an annual rate of 8-1/2% of
the liquidation preference value of $25. Distributions are payable quarterly and
are tax deductible by us. These distributions are recorded as interest expense.
The sole asset of the trust is $124 million principal amount of 8-1/2%
Deferrable Interest Subordinated Debentures, Series B due July 31, 2036.
In addition to our obligations under the Subordinated Debentures discussed
above, we have agreed to guarantee, on a subordinated basis, payment of
distributions on the preferred securities. These undertakings constitute a full
and unconditional guarantee by us of the trust's obligations under the preferred
securities.
Treasury Stock
--------------
At December 31, 2001, all of our treasury stock was owned by Westar
Industries, except for 50,000 shares owned by Protection One.
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19. RELATED PARTY TRANSACTIONS
Below we describe significant transactions between us and Westar
Industries and other subsidiaries and related parties. We have disclosed
significant transactions even if these have been eliminated in the preparation
of our consolidated results and financial position since our proposed financial
plan, as discussed in Note 15, calls for a split-off of Westar Industries from
us to occur in the future. We cannot predict whether the KCC will aprove the
plan and if so whether we will be successful in executing the plan.
We and ONEOK have shared services agreements in which we provide and bill
one another for facilities, utility field work, information technology, customer
support and bill processing. Payments for these services are based on various
hourly charges, negotiated fees and out-of-pocket expenses.
2001 2000 1999
------ ------ ------
(In Thousands)
Charges to ONEOK ........................ $8,202 $8,463 $8,876
Charges from ONEOK ...................... 3,279 3,420 3,322
Net receivable from ONEOK,
outstanding at December 31 ............ 1,424 1,205 1,506
In 1999, we and Protection One have entered into a service agreement
pursuant to which we provide administrative services, including accounting,
human resources, legal, facilities and technology services on a year to year
basis. Fees for these services are based upon various hourly charges, negotiated
fees and out-of-pocket expenses. Protection One incurred charges of $8.1
million in 2001, $7.3 million in 2000 and $2.0 million in 1999. These
intercompany charges have been eliminated in consolidation.
We had a payable to Westar Industries of approximately $67.7 million at
December 31, 2001 on which we paid interest at the rate of 8.5% per annum. On
February 28, 2001, Westar Industries converted $350.0 million of the then
outstanding payable balance into approximately 14.4 million shares of our common
stock, representing 16.9% of our outstanding common stock after conversion.
These shares are reflected as treasury stock in our consolidated balance sheets.
During the first quarter of 2002, we repaid the remaining balance owed to Westar
Industries. The proceeds were used by Westar Industries to purchase our
outstanding debt in the open market. At February 28, 2002, Westar Industries
owned $118.7 million of our debt. Amounts outstanding and interest earned by
Westar Industries have been eliminated in our consolidated financial statements.
See Note 2 "Summary of Significant Accounting Policies -- Principles of
Consolidation."
Westar Industries is the lender under Protection One's senior credit
facility. On November 1, 2001, this facility was amended to, among other things,
extend the maturity date to January 3, 2003, and provide for a quarterly fee for
financial advisory and management services equal to 1/8% of Protection One's
consolidated total assets at the end of each quarter, beginning with the quarter
ending March 31, 2002. As of December 31, 2001, approximately $137.5 million was
drawn under the facility. On March 25, 2002, Westar Industries further amended
the facility to increase the amount of the facility to $180 million. Amounts
outstanding have been eliminated in our consolidated financial statements.
We have a tax sharing agreement with Protection One. This pro rata tax
sharing agreement allows Protection One to be reimbursed for current tax
benefits utilized in our consolidated tax return. We and Protection One are
eligible to file on a consolidated basis for tax purposes as long as we maintain
an 80% ownership interest in Protection One. We reimbursed Protection One $11.8
million for tax year 2001 and $7.4 million for tax year 2000 for the current tax
benefit.
During 2001, Westar Industries purchased $37.9 million face value of
Protection One bonds on the open market. In October 2001, $27.6 million of these
bonds were transferred to Protection One in exchange for cash. In 2001, we
recognized an extraordinary gain from the purchase of Protection One bonds of
$22.3 million, net of tax of $12.0 million. During 2000, Westar Industries
purchased $170.0 million face value of Protection One bonds on the open market.
In exchange for cash and the settlement of certain intercompany payables and
receivables, $103.9
104
million of these debt securities were transferred to Protection One. The balance
of the bonds was sold to Protection One in March 2001. No gain or loss was
recognized on these transactions.
In the latter part of 2001 through February 28, 2002, Protection One
purchased approximately $1.8 million of our preferred stock in open market
purchases. These purchases have been accounted for as retirements.
During 2001, we extended loans to our officers for the purpose of
purchasing shares of our common stock on the open market. The loans are
unsecured and contain a variable interest rate that is equal to our short term
borrowing rate. Interest is payable quarterly. The loans mature and become due
on December 4, 2004. The balance outstanding at December 31, 2001 was
approximately $2.0 million and is classified as a reduction to shareholders'
equity in the accompanying consolidated balance sheet. The maximum amount of
loans authorized is $7.9 million.
During the fourth quarter of 2001, KGE entered into an option agreement to
sell an office building located in downtown Wichita, Kansas, to Protection One
for approximately $0.5 million. The sales price was determined by management
based on three independent appraisers' findings.
On February 29, 2000, Westar Industries purchased the European operations
of Protection One, and certain investments held be a subsidiary of Protection
One for an aggregate purchase price of $244 million. Westar Industries paid
approximately $183 million in cash and transferred Protection One debt
securities with a market value of approximately $61 million to Protection One.
Westar Industries has agreed to pay Protection One a portion of the net gain, if
any, on a subsequent sale of the European businesses on a declining basis over
the four years following the closing. Cash proceeds from the transaction were
used to reduce the outstanding balance owed to Westar Industries on Protection
One's revolving credit facility. No gain or loss was recorded on this
intercompany transaction and the net book value of the assets was unaffected.
If the KCC approves our financial plan, at the closing of the proposed
rights offering, we would enter into an option agreement that grants Westar
Industries an option to purchase the stock of Westar Generating, Inc., a wholly
owned subsidiary that owns our interest in the State Line generating facility.
The option would be exercisable at any time during the three year period
following execution of the agreement, subject to extension for two additional
one year periods. The option price is based on net book value at the time of
exercise. The option would be exercisable only if Westar Industries is unable to
obtain a permanent exemption from registration under the Investment Company Act
of 1940.
20. WORK FORCE REDUCTIONS
In late 2001, we reduced our utility work force by approximately 200
employees through involuntary separations and recorded a severance-related net
charge of approximately $14.3 million. In 2001, Protection One also reduced its
work force by approximately 500 employees in connection with facility
consolidations and recorded a severance-related net charge of approximately $3.1
million.
In the first quarter of 2002, we further reduced our utility work force by
approximately 400 employees through a voluntary separation program. We expect to
record a net charge of approximately $21.1 million in the first quarter of 2002
related to this program. We may replace some of these employees. Protection One
also reduced its work force by approximately 200 employees in connection with
facility consolidations and expects to record a net severance charge of
approximately $0.5 million in the first quarter of 2002.
21. MONITORED SERVICES DISPOSITIONS
In 2001, Protection One and Protection One Europe disposed of certain
monitored security operations for approximately $48.0 million and we recorded a
pre-tax loss of $13.1 million.
105
In 1999, Protection One sold the assets that comprised its Mobile Services
Group. Cash proceeds of this sale approximated $20 million and Protection One
recorded a pre-tax gain of approximately $17 million. This gain is reflected in
Other Income on our consolidated statements of income.
22. INTERNATIONAL POWER DEVELOPMENT COSTS
In 1998 we made a decision to terminate the employment of all employees,
close offices, discontinue all development activities, and terminate all other
matters related to the activity of The Wing Group. These activities were
substantially completed by December 31, 1999. The actual costs incurred during
1999 to complete the exit plan approximated $16.9 million, which was $5.6
million less than the amount estimated and charged to income in 1998. This was
accounted for as a change in estimate in 1999. The excess accrual was credited
to income in 1999 and reduced our selling, general and administration costs for
that period.
23. MARKETABLE SECURITIES
During the last three years, we sold substantially all of our investments
in marketable securities. These securities were classified as
available-for-sale. Realized gains and losses are included in earnings and were
derived using the specific identification method. The following table summarizes
our marketable security sales for the years ended December 31, 2001, 2000 and
1999:
Marketable Security Sales
-------------------------------
2001 2000 1999
------ -------- -------
(Dollars in Thousands)
Sales proceeds $2,829 $218,609 $73,456
Realized gains (a) -- 115,987 12,587
Realized losses 1,861 1,039 38,838
----------
(a) During 2000, we sold our equity investment in a gas compression
company and realized a pre-tax gain of $91.1 million.
In 1999, we determined that the decline in value of our investments in
paging industry companies was other than temporary and a charge to earnings for
the decline in value was required. This non-cash charge of $76.2 million was
recorded in the fourth quarter of 1999 and is presented separately in our
consolidated statements of income.
In February 2000, one of the paging companies we held an interest in made
an announcement that significantly increased the market value of paging company
securities general. During the first quarter of 2000, we sold the remainder of
these securities for a gain of $24.9 million.
During 2001, we wrote down the cost basis of certain equity securities to
their fair value. The fair value of these equity securities had declined below
our cost basis, and we determined that the decline was other than temporary. The
amount of the write down totaled $11.1 million, of which $9.6 million related to
a cost method investment. The write down is included in other income (expense).
24. SEGMENTS OF BUSINESS
In 1998, we adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." This statement requires us to define and
report our business segments based on how management currently evaluates its
business. Our business is segmented based on differences in products and
services, production processes and management responsibility. Based on this
approach, we have identified five reportable segments: Fossil Generation,
Nuclear Generation, Customer Operations, Monitored Services and Other. The
Fossil Generation, Nuclear Generation and Customer Operations segments comprise
our electric utility business. Fossil
106
Generation produces power for sale internally to the Customer Operations segment
and externally to wholesale customers. A component of our Fossil Generation
segment is power marketing, which attempts to minimize commodity price risk
associated with fuel purchases and purchased power requirements. Power marketing
also attempts to maximize utilization of generation capacity and enhance system
reliability through sales to external customers as discussed further below.
Nuclear Generation represents our 47% ownership in the Wolf Creek Generating
Station (Wolf Creek). This segment has only internal sales because it provides
all of its power to its co-owners. The Customer Operations segment consists of
the transmission and distribution of power to our retail customers in Kansas and
the customer service provided to these customers and the transmission of
wholesale energy. Monitored Services is comprised of our security alarm
monitoring business in North America and Europe. Other includes a 45% interest
in ONEOK, investments in international power generation facilities and other
investments, which in the aggregate are not material to our business or results
of operations.
The accounting policies of the segments are substantially the same as
those described in Note 2 "Summary of Significant Accounting Policies." Segment
performance is based on earnings before interest and taxes (EBIT). Unusual
items, such as charges to income and changes in accounting principle, may be
excluded from segment performance depending on the nature of the charge or
income. Interest expense is excluded from the segment analysis. Our ONEOK
investment, marketable securities investments and other equity method
investments do not represent operating segments of ours. We have no single
external customer from whom we receive ten percent or more of our revenues.
Year Ended December 31, 2001
----------------------------
Eliminating/
Fossil Nuclear Customer Monitored Reconciling
Generation(a) Generation Operations Services Other Items Total
------------- ---------- ---------- ---------- ---------- ------------ ----------
(In Thousands)
External sales .................... $ 667,953 $ -- $1,100,443 $ 416,509 $ 1,360 $ (3) $2,186,262
Internal sales .................... 560,528 117,659 317,056 -- -- (995,243) --
Depreciation and
amortization ................... 65,875 41,046 78,235 228,123 363 -- 413,642
Earnings (loss) before
interest and taxes and
cumulative effect of
accounting change .............. 120,530 (19,078) 131,917 (126,076) 32,651 (15,321) 124,623
Interest expense .................. 268,224
Earnings (loss) before income
taxes ........................... (143,601)
Additions to property,
plant and equipment ............ 116,595 27,349 83,052 9,456 -- -- 236,452
Customer account
acquisitions ................... -- -- -- 36,488 -- -- 36,488
Identifiable assets ............... 1,733,743 1,042,563 1,843,865 1,887,210 1,005,684 -- 7,513,065
107
Year Ended December 31, 2000
----------------------------
Eliminating/
Fossil Nuclear Customer Monitored Reconciling
Generation Generation Operations Services Other (c) Items (b) Total
---------- ---------- ---------- ---------- ---------- ------------ ----------
(In Thousands)
External sales ................... $ 705,536 $ -- $1,123,590 $ 537,859 $ 1,484 $ 7 $2,368,476
Internal sales ................... 572,533 107,770 291,927 -- -- (972,230) --
Depreciation and amortization .... 60,331 40,052 75,419 248,414 2,116 37 426,369
Earnings (loss) before
interest and taxes ............ 202,744 (24,323) 171,872 (91,370) 189,289 (21,533) 426,679
Interest expense 289,568
Earnings before income taxes ..... 137,111
Additions to property, plant
and equipment ................. 162,570 25,877 96,984 20,070 2,572 -- 308,073
Customer account acquisitions .... -- -- -- 47,261 -- -- 47,261
Identifiable assets .............. 1,658,986 1,064,817 1,893,884 2,175,381 1,008,654 (2) 7,801,720
Year Ended December 31, 1999
----------------------------
Eliminating/
Fossil Nuclear Customer Monitored Reconciling
Generation Generation Operations Services Other (d) Items (b) Total
---------- ---------- ---------- ---------- ---------- ------------ ----------
(In Thousands)
External sales ................... $ 365,311 $ -- $1,064,385 $ 599,105 $ 1,284 $ 2 $2,030,087
Internal sales ................... 546,683 108,445 293,522 -- -- (948,650) --
Depreciation and amortization .... 55,320 39,629 71,717 233,906 3,007 90 403,669
Earnings (loss) before
interest and taxes ............ 219,087 (25,214) 145,603 (20,675) (28,088) (26,252) 264,461
Interest expense ................. 294,104
Earnings (loss) before income
taxes ......................... (29,643)
Additions to property, plant
and equipment ................. 143,904 10,036 89,162 12,437 20,205 -- 275,744
Customer account acquisitions .... -- -- -- 268,409 -- -- 268,409
Identifiable assets .............. 1,476,716 1,083,344 1,783,937 2,539,921 1,165,145 (59,171) 7,989,892
----------
(a) EBIT shown above for Fossil Generation does not include the unrealized
gain on derivatives reported as a cumulative effect of a change in
accounting principle. If the effect had been included, EBIT for the Fossil
Generation segment for the year ended December 31, 2001 would have been
$151.6 million.
(b) Identifiable assets include eliminating and reclassing balances to
consolidate the monitored services business.
(c) EBIT includes the gain on the sale of our investment in a gas compression
company of $91.1 million and the gain on the sale of other marketable
securities of $24.9 million.
(d) EBIT includes investment earnings of $36.0 million, an impairment of
marketable securities of $76.2 million and the write-off of deferred costs
of $17.6 million.
108
Geographic Information
----------------------
Our sales and property, plant and equipment are as follows:
For the Year Ended December 31,
------------------------------------
2001 2000 1999
---------- ---------- ----------
(In Thousands)
External sales:
United States operations ........... $2,102,598 $2,254,105 $1,859,008
International operations ........... 83,664 114,371 171,079
---------- ---------- ----------
Total .......................... $2,186,262 $2,368,476 $2,030,087
========== ========== ==========
As of December 31,
------------------------------------
2001 2000 1999
---------- ---------- ----------
(In Thousands)
Property, plant and equipment, net:
United States operations ........... $4,038,648 $3,984,858 $3,880,865
International operations ........... 4,204 8,580 8,579
---------- ---------- ----------
Total .......................... $4,042,852 $3,993,438 $3,889,444
========== ========== ==========
25. IMPAIRMENT CHARGE PURSUANT TO NEW ACCOUNTING RULES
Effective January 1, 2002, we adopted the new accounting standards SFAS No.
142, "Accounting for Goodwill and Other Intangible Assets," and SFAS No. 144.,
"Accounting for the Impairment and Disposal of Long-Lived Assets." SFAS No. 142
establishes new standards for accounting for goodwill. SFAS No. 142 continues to
require the recognition of goodwill as an asset, but discontinues amortization
of goodwill. In addition, annual impairment tests must be performed using a
fair-value based approach as opposed to an undiscounted cash flow approach
required under prior standards.
SFAS No. 144 establishes a new approach to determining whether our
customer account asset is impaired. The approach no longer permits us to
evaluate our customer account asset for impairment based on the net undiscounted
cash flow stream obtained over the remaining life of the goodwill associated
with the customer accounts being evaluated. Rather, the cash flow stream to be
used under SFAS No. 144 is limited to the future estimated undiscounted cash
flows of our existing customer accounts. Additionally, the new rule no longer
permits us to include estimated cash flows from forecasted customer additions.
If the undiscounted cash flow stream from existing customer accounts is less
than the combined book value of customer accounts and goodwill, an impairment
charge is required.
The new rule substantially reduces the net undiscounted cash flows used
for impairment evaluation purposes as compared to the previous accounting rules.
The undiscounted cash flow stream has been reduced from the 16-year remaining
life of the goodwill to the nine-year remaining life of customer accounts for
impairment evaluation purposes and does not include estimated cash flows from
forecasted customer additions.
109
To implement the new standards, an independent appraisal firm was engaged
to help management estimate the fair values of goodwill and customer accounts.
Based on this analysis, during the first quarter of 2002, we will record a
non-cash net charge of approximately $653.7 million, of which $464.2 million is
related to goodwill and $189.5 million is related to customer accounts. The
charge is detailed as follows:
Impairment of Impairment of
Goodwill Customer Accounts Total
------------- ----------------- ---------
(In Thousands)
Protection One ................ $498,921 $334,064 $ 832,985
Protection One Europe ......... 80,104 -- 80,104
-------- -------- --------
Total pre-tax impairment ...... $579,025 $334,064 913,089
======== ========
Income tax benefit ............ (173,650)
Minority interest ............. (85,713)
---------
Net charge .................... $ 653,726
=========
The impairment charge for goodwill will be reflected in our consolidated
statement of income as a cumulative effect of a change in accounting principle.
The impairment charge for customer accounts will be reflected in our
consolidated statement of income as an operating cost. These impairment charges
reduce the recorded value of these assets to their estimated fair values at
January 1, 2002.
In 2001, we recorded approximately $57.1 million of goodwill amortization
expense. We will no longer be permitted to amortize goodwill to income because
of adoption of the new goodwill rule. In 2001, we recorded approximately $153.0
million of customer account amortization expense. Future customer account
amortization expense will also be reduced as a result of the impairment charge.
We will be required to perform impairment tests for our monitored services
segment for long-lived assets prospectively as long as it continues to incur
recurring losses or for other matters that may negatively impact its businesses.
Goodwill will be required to be tested each year for impairment. Declines in
market values of our monitored services businesses or the value of customer
accounts that may be incurred prospectively may require additional write down of
these assets in the future.
Estimated Lives of Customer Accounts to Change Based on Customer Account Lifing
-------------------------------------------------------------------------------
Study Results
-------------
Protection One is currently evaluating the estimated life and amortization
rates for customer accounts, given the results of a lifing study performed by a
third party appraisal firm in the first quarter of 2002. Any change in its
amortization rate or estimated life will be determined in the first quarter of
2002 and accounted for prospectively as a change in estimate.
26. SUBSEQUENT EVENTS
Ice Storm
---------
In late January 2002, a severe ice storm swept through our utility service
area causing extensive damage and loss of power to numerous customers. We
estimate storm restoration costs could run as high as $25 million. On March 13,
2002, we filed an application for an accounting authority order with the KCC
requesting that we be allowed to accumulate and defer for future recovery costs
related to storm restoration. We cannot predict whether the KCC will approve our
application.
110
27. QUARTERLY RESULTS (UNAUDITED)
The amounts in the table are unaudited but, in the opinion of management,
contain all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of the results of such periods. Our electric
business is seasonal in nature and, in our opinion, comparisons between the
quarters of a year do not give a true indication of overall trends and changes
in operations.
First Second Third Fourth
---------- ---------- ---------- ----------
(In Thousands, Except Per Share Amounts)
2001
----
Sales ................................................... $ 560,741 $ 522,901 $ 667,068 $ 435,552
Gross profit ............................................ 290,162 285,597 357,077 253,876
Net income (loss) before extraordinary gain and
accounting change .................................... (19,187) (36,014) 26,722 (34,247)
Net income (loss) ....................................... 4,450 (30,188) 35,976 (31,114)
Earnings (loss) per share available for common stock
before extraordinary gain and accounting change:
Basic .......................................... $ (0.28) $ (0.51) $ 0.38 $ (0.49)
Diluted ........................................ $ (0.28) $ (0.51) $ 0.37 $ (0.48)
Cash dividend per common share .......................... $ 0.30 $ 0.30 $ 0.30 $ 0.30
Market price per common share:
High ........................................... $ 25.875 $ 25.820 $ 22.900 $ 17.801
Low ............................................ $ 21.800 $ 20.000 $ 15.620 $ 16.000
2000
----
Sales ................................................... $ 481,699 $ 546,607 $ 759,562 $ 580,608
Gross profit ............................................ 306,760 331,889 395,534 298,461
Net income (loss) before extraordinary gain and
accounting change .................................... 39,801 23,565 53,991 (26,307)
Net income (loss) ....................................... 54,483 40,912 60,707 (19,621)
Earnings (loss) per share available for common stock
before extraordinary gain and accounting change:
Basic .......................................... $ 0.58 $ 0.34 $ 0.78 $ (0.40)
Diluted ........................................ $ 0.58 $ 0.34 $ 0.77 $ (0.39)
Cash dividend per common share .......................... $ 0.535 $ 0.30 $ 0.30 $ 0.30
Market price per common share:
High ........................................... $ 18.313 $ 17.813 $ 21.953 $ 25.875
Low ............................................ $ 15.313 $ 14.688 $ 15.375 $ 20.438
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
-----------------------------------------------------------------------
FINANCIAL DISCLOSURE
--------------------
None.
111
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
-----------------------------------------------------------
Director (Class I)--Term Expiring in 2003
Charles Q. Chandler, IV (age 48)
Mr. Chandler is Chairman of the Board, President and Chief Executive
Officer of INTRUST Bank, N.A. and President of INTRUST Financial Corporation.
Both companies are located in Wichita, Kansas. Mr. Chandler is a director of
INTRUST Financial Corporation, the First National Bank of Pratt, Kansas, the
Will Rogers Bank in Oklahoma City, Oklahoma and the Wesley Medical Center in
Wichita, Kansas. He is also a trustee of the Kansas State University Endowment
Foundation. Mr. Chandler has served as our director since January 2000.
John C. Dicus (age 68)
Mr. Dicus is Chairman of the Board and Chief Executive Officer of Capitol
Federal Savings Bank. Mr. Dicus is also Chairman of the Board and Chief
Executive Officer of Capitol Federal Financial and Capitol Federal Savings Bank
MHC (since March 1999). These companies are located in Topeka, Kansas. Mr.
Dicus is a director of Security Benefit Life Insurance Company and Columbian
National Title Company, and a trustee of Stormont-Vail Health Care, Inc. and
the University of Kansas Endowment Association. He has served as our director
since May 1990.
R.A. Edwards (age 56)
Mr. Edwards is the President and Chief Executive Officer and a director of
the First National Bank of Hutchinson, Kansas. Mr. Edwards is also a director of
Douglas County Bank, Data Center, Inc., Kansas Venture Capital, Inc. and
Michellhill Seed Company. He is also a member of the University of Kansas
Business School Advisory Board and a trustee of the University of Kansas
Endowment Association.
Director (Class II)--Term Expiring in 2004
Gene A. Budig (age 63)
Dr. Budig is Senior Advisor to the Commissioner of Baseball, American
League of Professional Baseball Clubs in New York, New York (since March 2000)
and a professor at Princeton University (since July 2000). Prior to that time,
Dr. Budig was President of the American League of Professional Baseball Clubs.
Dr. Budig is a director of the Harry S. Truman Library Institute, the Ewing
Marion Kaufman Foundation, the Major League Baseball Hall of Fame and the Media
Studies Center-Freedom Forum. Dr. Budig is also a director of Protection One.
He has served as our director since July 1999. He also served as our director
from January 1987 to May 1998.
John C. Nettels, Jr. (age 45)
Mr. Nettels is a Partner with the law firm of Morrison & Hecker, L.L.P. in
Overland Park, Kansas. He has served as our director since March 2000.
David C. Wittig (age 46)
Mr. Wittig is our Chairman of the Board, President and Chief Executive
Officer (since January 1999, March 1996 and July 1998, respectively). Prior to
that time, Mr. Wittig was our Executive Vice President of Corporate
Development. Mr. Wittig is a director of WACO Instruments, Inc. and Fox Run
Holdings, Inc. Mr. Wittig is a trustee of the University of Kansas Endowment
Association and Boys Harbor, Inc. He has served as our director since February
1996.
Director (Class III)--Term Expiring in 2005
Frank J. Becker (age 66)
Mr. Becker is President of Becker Investments, Inc. in Lawrence, Kansas.
Mr. Becker is a director of the Douglas County Bank, Martin K. Eby Construction
Company and IMA Insurance, Inc., and a trustee of the University of Kansas
Endowment Association. He has served as our director since 1992.
Douglas T. Lake (age 51)
Mr. Lake is our Executive Vice President and Chief Strategic Officer (since
September 1998). Mr. Lake was Senior Managing Director at Bear, Stearns & Co.
Inc., an investment banking firm, from 1995 to September 1998. Mr. Lake is also
Chairman of the Board of Protection One and a director of ONEOK, Inc. and
Guardian International, Inc. He has served as our director since October 2000.
Section 16(a) Beneficial Ownership Reporting Compliance
The rules of the Securities and Exchange Commission require our directors
and executive officers to file reports of their holdings and transactions in
our common stock. Based solely on our review of the copies of reports filed
under Section 16(a) of the Exchange Act and written representations that no
other reports were required, we believe that, during the fiscal year ended
December 31, 2001, all required filings applicable to our executive officers,
directors and owners of more than ten percent of our common stock were made and
that such persons were in compliance with the Exchange Act requirements.
112
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During the Past Five Years
---- --- -------------- -------------------------------
David C. Wittig 46 Chairman of the Board --
(since January 1999)
Chief Executive Officer
(since July 1998)
and President
(since March 1996)
Douglas T. Lake 51 Director Bear Stearns & Co., Inc. -
(since October 2000) Senior Managing Director
Executive Vice President, (1995 to August 1998)
Chief Strategic Officer
(since September 1998)
Richard A. Dixon 58 Senior Vice President, Customer Operations Western Resources, Inc. -
(since October 2001) Vice President, Transmission Services (May 2000
to October 2001)
Executive Director, System Operations (January
1999 to April 2000)
Executive Director, Transmission Services
(September 1996 to December 1998)
Paul R. Geist 38 Senior Vice President, Chief Financial Western Resources, Inc. -
Officer and Treasurer (since October Vice President, Corporate Development (February
2001) 2001 to October 2001)
Executive Director, Corporate Strategy (November
1999 to February 2001)
Panera Bread Company -
Vice President - Finance (October 1998 to
November 1999)
Houlihan's Restaurant Group, Inc. -
Executive Vice President - Chief Financial
Officer (1997 to October 1998) Vice
President/Controller (1995 to 1997)
Shane A. Mathis 31 Senior Vice President, Commodity Strategy Western Resources, Inc. -
(since October 2001) Vice President, Commodity Strategy (October 2000
to October 2001)
Vice President, Risk Management (May 2000 to
October 2000)
Executive Director, Gas and Liquids (March 2000
to May 2000)
Executive Director, Risk Management (January
1998 to March 2000)
Director, Energy Trading (January 1998 to August
1998)
Senior Strategist (February 1997 to January 1998)
Merrill Lynch -
Financial Consultant (1995 to February 1997)
Douglas R. Sterbenz 38 Senior Vice President, Generation and Western Resources, Inc. -
Marketing (since October 2001) Manager, Bulk Power Marketing (August 1998 to
October 2001)
Energy Trader (May 1997 to July 1998)
Questar Energy Trading -
Director, Power Marketing (April 1996 to May
1997)
113
ITEM 11. EXECUTIVE COMPENSATION
-------------------------------
The following table sets forth the compensation of our named executive
officers for the last three completed fiscal years:
Summary Compensation Table
Long Term
Compensation
Annual Compensation Awards
------------------------------------ ---------------------
Other Restricted
Annual Stock Securities All Other
Compensation Awards Underlying Compensation
Name and Principal Position Year Salary $ Bonus $ $(1) $(2) Options # $(3)
--------------------------- ---- -------- --------- ------------ ---------- ---------- ------------
David C. Wittig (4) 2001 313,026 -- 163,936 2,643,245 -- 489,896
Chairman of the Board, President 2000 303,400 1,171,170 134,794 2,155,781 58,500 486,969
and Chief Executive Officer 1999 408,683 -- 105,909 1,738,625 114,000 5,756,753
Douglas T. Lake 2001 463,344 178,000 18,536 1,546,360 -- 5,758
Executive Vice President, 2000 224,476 642,706 57,417 1,317,813 9,000 700,999
Chief Strategic Officer 1999 266,849 -- 31,494 948,219 40,000 429,664
Douglas R. Sterbenz 2001 190,963 150,256 22,080 24,200 -- 7,362
Senior Vice President, Generation 2000 115,000 165,735 3,602 15,625 2,700 19,327
and Marketing 1999 113,573 318,207 573 -- 2,700 7,463
Shane A. Mathis 2001 226,276 74,600 2,628 338,800 -- 18,933
Senior Vice President, 2000 158,756 149,180 5,922 391,288 3,500 40,806
Commodity Strategy 1999 150,625 30,900 4,575 -- 3,500 28,778
Carl M. Koupal, Jr. 2001 273,453 -- 16,770 1,010,810 -- 817,254
Retired Executive Vice President, 2000 290,740 427,078 9,847 930,000 9,000 48,318
Chief Administrative Officer 1999 307,020 -- 13,045 612,313 28,000 42,327
Thomas L. Grennan 2001 212,533 -- 52,171 692,207 -- 589,832
Retired Executive Vice President, 2000 175,750 299,702 56,375 496,875 6,000 69,953
Electric Operations 1999 187,708 -- 35,965 445,000 20,000 64,292
Paul R. Geist 2001 167,111 50,000 1,014 77,440 -- 13,562
Senior Vice President, Chief 2000 118,000 31,221 125 93,750 -- 1,033
Financial Officer and Treasurer 1999 12,962 11,290 -- -- -- 354
--------
(1)Other Annual Compensation for 2001 includes the following items: (a)
payments for federal and state taxes associated with personal benefits and
financial and tax planning (Mr. Wittig, $32,762, Mr. Lake, $17,383, Mr.
Mathis, $1,995, Mr. Koupal, $11,459, Mr. Grennan, $9,427, and Mr. Geist,
$1,005); (b) interest on deferred compensation in excess of the applicable
federal long term interest rate (Mr. Wittig, $42,999, Mr. Sterbenz, $270,
Mr. Mathis, $293, Mr. Koupal, $1,928, and Mr. Grennan, $31,337); and (c)
value of discounts received on stock compensation (Mr. Wittig, $88,175, Mr.
Lake, $1,153, Mr. Sterbenz, $21,810, Mr. Mathis, $340, Mr. Koupal, $3,383,
Mr. Grennan, $11,407, and Mr. Geist, $9).
(2)The reported dollar value of restricted share units is equal to the closing
price of our common stock on the date of grant, multiplied by the total
number of restricted share units granted to the named executive officer. See
the Human Resources Committee Report for a discussion of vesting of these
restricted share units. The aggregate restricted share units held by each of
the named executive officers as of December 31, 2001 were as follows: Mr.
Wittig, 412,022, Mr. Lake, 207,999, Mr. Sterbenz, 3,310, Mr. Mathis, 36,199,
Mr. Koupal, 151,724, Mr. Grennan, 85,777, and Mr. Geist, 9,200. Based on the
closing price of our common stock on December 31, 2001 of $17.20 per share,
the restricted share units had an aggregate value on that date of: Mr.
Wittig, $7,086,778, Mr. Lake, $3,577,583, Mr. Sterbenz, $56,932, Mr. Mathis,
$622,623, Mr. Koupal,
114
$2,609,653, Mr. Grennan, $1,475,364, and Mr. Geist, $158,240. This value may
not represent the ultimate value of the restricted share units to the
employee or us. Dividend equivalents are paid on the restricted share units
from the date of grant.
(3)All Other Compensation for 2001 includes the following items: (a) company
contributions under our 401(k) savings plan, a defined contribution plan
(Mr. Wittig, Mr. Sterbenz, Mr. Mathis and Mr. Geist, $5,100 each, Mr. Lake,
$4,371, Mr. Koupal, $4,985, and Mr. Grennan, $3,575); (b) premiums paid on
term life insurance policies (Mr. Wittig, $1,608, Mr. Lake, $1,387, Mr.
Sterbenz, $187, Mr. Mathis, $275, Mr. Koupal, $727, Mr. Grennan, $552, and
Mr. Geist, $171); (c) imputed income on split dollar life insurance policies
(Mr. Wittig, $42,967 and Mr. Koupal, $16,365); (d) value of shares received
under our stock for compensation program in lieu of cash compensation (Mr.
Wittig, $440,220, Mr. Koupal, $9,726, and Mr. Grennan, $29,129); and (e)
$773,378 paid to Mr. Koupal and $544,502 payable to Mr. Grennan in
connection with their retirements.
(4)See the Human Resources Committee Report for a discussion of Mr. Wittig's
2001 short term incentive compensation.
Retirement Plans
We maintain a qualified non-contributory defined benefit pension plan and a
non-qualified supplemental retirement plan for certain of our management
employees, including executive officers, who are selected by the Human
Resources Committee of our Board of Directors. Benefits payable from the
qualified pension plan are limited by provisions of the Internal Revenue Code.
The non-qualified supplemental retirement plan provides for the payment of
retirement benefits in addition to those provided under the qualified pension
plan.
The following table sets forth the estimated annual benefits payable to the
named executive officers upon specified remuneration based on age 65 as of
January 1, 2002. The amounts presented do not take into account any reduction
for joint and survivorship payments.
ANNUAL PENSION BENEFIT FROM QUALIFIED AND NON-QUALIFIED PLANS
Average Applicable Average Applicable
Compensation Pension Benefit Compensation Pension Benefit
------------------ --------------- ------------------ ---------------
$150,000 $ 92,550 $1,150,000 $ 709,550
$200,000 $123,400 $1,200,000 $ 740,400
$250,000 $154,250 $1,250,000 $ 771,250
$300,000 $185,100 $1,300,000 $ 802,100
$350,000 $215,950 $1,350,000 $ 832,950
$400,000 $246,800 $1,400,000 $ 863,800
$450,000 $277,650 $1,450,000 $ 894,650
$500,000 $308,500 $1,500,000 $ 925,500
$550,000 $339,350 $1,550,000 $ 956,350
$600,000 $370,200 $1,600,000 $ 987,200
$650,000 $401,050 $1,650,000 $1,018,050
$700,000 $431,900 $1,700,000 $1,048,900
$750,000 $462,750 $1,750,000 $1,079,750
$800,000 $493,600 $1,800,000 $1,110,600
$850,000 $524,450 $1,850,000 $1,141,450
$900,000 $555,300 $1,900,000 $1,172,300
$950,000 $586,150 $1,950,000 $1,203,150
$1,000,000 $617,000 $2,000,000 $1,234,000
$1,050,000 $647,850 $2,050,000 $1,264,850
$1,100,000 $678,700 $2,100,000 $1,295,700
115
The supplemental retirement plan provides a retirement benefit at or after
age 65, or upon disability prior to age 65, in an amount equal to 61.7% of
final three-year average cash compensation (including share awards under the
Stock for Compensation Program) and annual incentive bonuses, reduced by the
benefits under the qualified pension plan (but not social security benefits),
such amount to be paid to the employee or his designated beneficiaries for the
employee's life with a 15-year term certain. The percentage of final three-year
average compensation to be paid commencing at age 65, before reduction for
qualified pension plan benefits, is 50% for a person retiring at age 50
increasing to 61.7% at age 65. An employee retiring at or after age 50, but
before age 65, may receive a reduced benefit, payable in the same form
commencing prior to age 65. The age 65 benefits are reduced by 5% per year if
commenced prior to age 60, but no earlier than age 50. The supplemental plan
vests 10% per year after five years of service until fully vested with 15 years
of service or at age 65. Under the qualified plan, full vesting occurs after 5
years of service. The supplemental plan also pays a death benefit if death
occurs before retirement, equal to 50% of the employee's previous three year
average compensation (or the vested retirement benefit percentage, whichever is
higher) to his or her beneficiary for fifteen years following his or her death.
All of the individuals listed in the compensation table are covered by the
qualified plan and all such individuals other than Mr. Sterbenz and Mr. Geist
are covered by the supplemental retirement plan. In the event of a change in
control of us, participants may be deemed to be 65 years of age as of the date
of such change in control for purposes of vesting and benefits.
The years of service as of January 1, 2002 for the named executive officers
are as follows: Mr. Wittig, six years; Mr. Lake, three years; Mr. Sterbenz,
four years, Mr. Mathis, four years, Mr. Koupal, ten years; Mr. Grennan,
twenty-seven years; and Mr. Geist, two years.
Split Dollar Life Insurance Program
We established a split dollar life insurance program for our benefit and
for the benefit of certain of our officers, including executive officers. Under
the split dollar life insurance program, we purchase a life insurance policy on
the insured's life and, upon termination of the policy or the insured's death,
the insured's beneficiary is entitled to a death benefit in an amount equal to
the face amount of the policy reduced by the greater of (i) all premiums paid
by us and (ii) the cash surrender value of the policy, which amount, at the
death of the insured or termination of the policy, as the case may be, will be
returned to us. We retain an equity interest in the death benefit and cash
value of the policy to secure this repayment obligation.
Subject to certain conditions, beginning on the earlier of (i) three years
from the date of the policy or (ii) the first day of the calendar year next
following the date of the insured's retirement, the insured is allowed to
transfer to us from time to time, in whole or in part, his interest in the
death benefit under the policy at a discount equal to $1 for each $1.50 of the
portion of the death benefit for which the insured may designate the
beneficiary, subject to adjustment if the participant does not retire within
six months of the date of agreement based on the total return to shareowners
from the date of the policy. Any adjustment would result in an exchange of no
more than $1 for each $1 of death benefit nor less than $1 for each $2 of death
benefit. At December 31, 2001, our liability under this program was
approximately $18.6 million. Mr. Koupal retired in October 2001 and received a
payment in January 2002 of approximately $4.6 million under the program in
exchange for his assignment to us of approximately $9.1 million of insurance
benefits. The program has been designed such that upon the insured's death we
will recover our premium payments from the policy and any amounts paid by us to
the insured for the transfer of his interest in the death benefit.
116
Compensation of Directors
Directors who are our employees do not receive additional compensation for
their services as directors. In 2001, directors who were not our employees
received an annual cash retainer fee of $25,000, paid quarterly, an annual
stock award of $18,500, and an annual restricted share unit award of $19,000.
The restricted share unit award vests ratably over three years from the date of
grant. Directors who were not our employees were also paid a fee of $1,200 for
each meeting of the Board of Directors and a fee of $1,000 for each committee
meeting they attended ($600 in each case if they participated by telephone).
Effective January 1, 2002, the annual cash retainer fee was reduced to $20,000
and the fee for attendance at each telephone meeting was reduced to $500. Also
effective January 1, 2002, the chairman of each committee of the Board of
Directors receives an annual cash fee of $4,000. Directors are also reimbursed
for expenses incurred by them which are incidental to attending meetings.
Pursuant to our Outside Directors' Deferred Compensation Plan (the
"Deferred Compensation Plan"), an outside director may elect to defer all or a
portion of any fee received for services. The Deferred Compensation Plan is a
voluntary participation plan administered by the Human Resources Committee of
our Board of Directors. In addition, an outside director may elect to have all
or a portion of any cash fees paid in stock pursuant to our Long Term Incentive
and Share Award Plan.
Human Resources Committee Report
The executive compensation programs of the Company are administered by the
Human Resources Committee of the Board of Directors (the "Committee"), which is
composed of three non-employee directors. The Committee reviews and approves
all issues pertaining to executive compensation. The objective of the Company's
three compensation programs (base salary, short term incentive and long term
incentive) is to provide compensation that enables the Company to attract,
motivate and retain talented and dedicated executives, foster a team
orientation toward the achievement of business objectives, and directly link
the success of our executives with that of our shareholders.
The Company extends participation in its long term and short term incentive
programs to certain key employees in addition to executive officers based on
their potential to contribute to increasing shareholder value.
In structuring the Company's compensation plans, the Committee takes into
consideration Section 162(m) of the Internal Revenue Code (which disallows the
deduction of compensation in excess of $1.0 million except for certain payments
based upon performance goals) and other factors the Committee deems
appropriate. As a result, if such compensation in excess of $1.0 million is
paid under the Company's compensation plans, a portion may not be deductible
under Section 162(m).
Base Salary Compensation
A base salary range is established for each executive position to reflect
the potential contribution of each position to the achievement of the Company's
business objectives and to be competitive with the base salaries paid for
comparable positions in the national market by diversified consumer services
companies, with emphasis on electric energy and monitored security services
with annual total revenues comparable to ours. Some, but not all, of such
companies are included in the Standard & Poor's Electric Companies Index. The
Committee utilized industry information for compensation purposes. Not all
companies comprising such index participate in making available such industry
information. In addition, the Committee considers information about other
companies with which the Committee believes the Company competes for
executives, but which are not part of such industry information. The mid-point
for each base salary range is intended to approximate the average base
117
salary for the relevant position in the national market. Industry surveys by
national industry associations are the primary source of this market
information. The Committee also utilizes the services of an independent
compensation consultant to provide national market data for executive positions
and to evaluate the appropriateness of the Company's executive compensation and
benefit programs.
Within the established base salary ranges, actual base salary is determined
by the Company's financial performance in relation to attainment of specific
goals, such as earnings per share and total return to shareholders, and a
subjective assessment of each executive's achievement of individual objectives
and managerial effectiveness. The Committee annually reviews the performance of
the Chairman of the Board, President and Chief Executive Officer and other
executive officers. The Committee, after consideration of the Company's
financial performance, and such other subjective factors as the Committee deems
appropriate for the period being reviewed, establishes the base compensation of
such officers.
In reviewing the annual achievement of each executive and setting the new
base annual salary levels for 2001, the Committee considered each individual's
contribution toward meeting the board-approved budgeted financial plan for the
previous year, total return to shareholders, earnings per share, customer
satisfaction, compliance with the Company's capital financial plan, the
Company's budgets, the individual's management effectiveness and the
individual's base compensation compared to the national market. In October
2001, several executive officers retired, and other officers were promoted or
new officers were appointed to assume their responsibilities. The base
compensation of these officers was increased effective November 1, 2001 to be
commensurate with their new responsibilities.
Annual Incentive Compensation
All executive officers are eligible for annual incentive compensation.
The primary form of short term incentive compensation is the Company's
Short Term Incentive Plan for employees selected by the Committee, including
the named executive officers, who have an opportunity to directly and
substantially contribute to the Company's achievement of short term objectives.
Short term incentives are structured so that potential compensation is
comparable with short term compensation granted to comparable positions in the
national market. Short term incentives are targeted to approximate the median
in the national market. Some, but not all, of such companies are included in
the Standard & Poor's Electric Companies Index. Awards in excess of the targets
may be payable if the financial goals set by the Committee are exceeded. The
Committee may grant performance based awards to the Chief Executive Officer and
the other four most highly compensated officers of the Company who are or may
be subject to Section 162(m) of the Code without being subject to the $1
million limitation on deductibility for federal income tax purposes.
For 2001, Mr. Wittig was eligible for an annual short term incentive target
of 90% of base salary. Other participants were eligible for annual short term
incentive targets ranging from 15% to 80% of base salary. For executive
officers, 20% to 40% of the annual incentive was tied to the attainment of
individual goals and management skills. The balance was based upon the
Company's achievement of financial goals that are established annually by the
Committee.
Changes in annual incentive compensation to the named executive officers in
2001 compared to 2000 resulted from an individual's relative attainment of his
or her goals, the achievement of certain
118
performance standards for business units over which an executive officer had
responsibility, and the Company failing to achieve budgeted adjusted earnings
per share and shareholder value goals.
Long Term Incentives
Long term incentive compensation is offered to employees who are in
positions which can affect the Company's long term success through the
formation and execution of its business strategies. Long term incentive
compensation currently takes the form of grants of restricted share units and
dividend equivalents under the Company's 1996 Long Term Incentive and Share
Award Plan (the "Plan"). The Plan has been established to advance the interests
of the Company and its shareholders by providing a means to attract, retain,
and motivate employees and directors upon whose judgment, initiative and effort
the Company's continued success, growth and development is dependent. The
purposes of long term incentive compensation are to: (1) focus key employees'
efforts on performance which will increase the value of the Company to its
shareholders; (2) align the interests of management with those of the Company's
shareholders; (3) provide a competitive long term incentive opportunity; and
(4) provide a retention incentive for key employees.
All non-union employees are eligible for grants under the Plan. Under the
Plan, awards are provided to such participants and in such amounts as the
Committee deems appropriate. The number and form of awards vary on the basis of
position and pay grade. The level of total compensation for similar executive
positions in companies considered comparable by the Committee was used as a
reference in establishing the level of awards.
The use of restricted share units and dividend equivalents as a significant
component of compensation creates a strong and direct linkage between the
financial outcomes of the employees and the shareholders. Restricted share
units require specified appreciation in the share price of the Company's common
stock and the continued employment of the executive until the specified
appreciation occurs, unless the executive's employment terminates due to
retirement, death, disability, termination without cause by us, for good reason
by the executive or a change in control of the Company. Restricted share units
granted in 2001 vest if the share price of the Company's common stock remains
at or above $27.83 for any period of twenty consecutive trading days beginning
on February 8, 2001, the date of grant, and ending on February 7, 2011.
Dividend equivalents are paid on the restricted share units from the date of
grant. The value of a single dividend equivalent is equal to the dividends that
would have been paid or payable on a share of common stock from the date of
grant.
In April 1999, the Committee adopted a stock for compensation program which
allowed the Company's executive officers and other key employees to receive up
to a specified percentage of base compensation in the form of restricted share
units. The percentage of base compensation allowed to be paid in restricted
share units ranged from approximately 5% to approximately 60% depending on the
salary of the individual. Restricted share units were valued based upon 85% of
the closing price for the Company's common stock on the date of payment. In
2001, this program was modified to allow participants to purchase shares of the
Company's common stock, rather than receive restricted share units, at 85% of
the closing price for the Company's common stock on the date of purchase. In
addition, the limitations on the percentage of base compensation allowed to be
used to purchase shares and certain deferral requirements were eliminated. In
2001, Mr. Wittig elected to purchase shares of the Company's common stock with
approximately 58.5% of his base compensation under the program.
119
In the event of a change in control, restricted share units and dividend
equivalents may accelerate and vest with performance criteria deemed satisfied.
Chief Executive Officer
Mr. Wittig's base salary and his annual short term incentive compensation
are established annually. In recommending the base salary to be effective in
2001, while not utilizing any specific performance formula and without ranking
the relative importance of each factor, the Committee took into account
relevant salary information in the national market and the Committee's
subjective evaluation of Mr. Wittig's overall management effectiveness in his
position as Chairman of the Board, President and Chief Executive Officer of the
Company and his achievement of individual goals. Factors considered included
his continuing leadership of the Company and his contribution to strategic
direction, management of change in an increasingly competitive environment,
management of operations, and the overall productivity of the Company. The
Committee also took into account the recommendations made by an independent
compensation consultant. Mr. Wittig's base salary was not changed in 2001.
The Committee took no action with respect to Mr. Wittig's 2001 short term
incentive compensation. The Committee may re-examine whether to make an award
in the future based upon an evaluation of the effectiveness of various
management and operational changes made late in 2001. The long term incentive
compensation of Mr. Wittig included restricted share units and dividend
equivalents granted based upon the factors described under Long Term Incentives
above.
The Human Resources Committee
Frank J. Becker, Chairman
Gene A . Budig
John C. Dicus
120
Employment and Change in Control Agreements
We have entered into employment agreements with Mr. Wittig and Mr. Lake,
each of which contains change in control provisions, and change in control
agreements with Mr. Mathis and Mr. Geist and other of our officers and key
employees. The agreements have three year terms with an automatic extension of
one year on each anniversary, unless prior notice is given by the officer or by
us. The agreements are intended to insure the officers' continued service and
dedication to us and to ensure their objectivity in considering on our behalf
any transaction which would result in a change in control of us.
Under the employment agreements, an officer is entitled to benefits, if his
or her employment is terminated by us other than for Cause or upon death,
disability or retirement, or by the officer for Good Reason, each as defined in
the agreements. Under the change in control agreements, benefits are provided
for such terminations only if they occur within two years of a change in
control. Under the employment agreements, benefits would also be provided if
the officer were to terminate his or her employment, regardless of the reason,
within 90 days of a change in control or if, in connection with a change in
control, the officer were to leave our employ and become an employee of a
former subsidiary which is then a separate, publicly traded company. A
termination that would result in payments becoming payable is referred to as
"Qualifying Termination."
The employment agreements provide for annual salaries at the executive's
base salary on September 19, 2000, the date of the agreements, with annual
reviews by the Board of Directors, and participation in all employee benefit
and incentive plans, programs and perquisites offered to our senior executives
and reimbursement of business expenses. In addition to performing their duties,
the executives have also agreed to keep certain company information
confidential, not to solicit certain employees to leave our employ, and not to
disparage us or our representatives.
Upon a Qualifying Termination, we, or our successor, must make a lump-sum
cash payment to the officer, in addition to any other compensation to which the
officer is entitled, of two (2.99 in the case of Mr. Wittig and Mr. Lake) times
the higher of such officer's base salary and 90% of the position's job value
("Adjusted Salary"); two (2.99 in the case of Mr. Wittig and Mr. Lake) times
the higher of the highest bonus paid to such officer for the last three fiscal
years and the officer's target bonus ("Bonus Amount"); and for officers not
participating in our executive salary continuation plan, the actuarial
equivalent of the excess of the officer's accrued pension benefits, computed as
if the officer had two additional years of benefit accrual service, over the
officer's vested accrued pension benefits utilizing the officer's current
salary without regard for any salary limits imposed for qualified pension plans.
In addition, we must offer health, disability and life insurance coverage
to the officer and his or her dependents on the same terms and conditions that
existed immediately prior to the termination for two (three in the case of Mr.
Wittig and Mr. Lake) years, or, if earlier, until such officer is covered by
equivalent benefits, continuation of financial and legal counseling services,
participation in our matching gift program for two (three in the case of Mr.
Wittig and Mr. Lake) additional years, and outplacement services. The
employment agreements also provide for additional payments, if required, to
make the individuals whole for any excise tax imposed under Section 4999 of the
Internal Revenue Code, to pay certain relocation costs within eighteen months
of the officer's termination of employment, and provision of retiree medical
benefits.
121
In the event of a Qualifying Termination, dividend equivalents, restricted
share units and other stock based incentives or compensation accelerate and
vest and restrictions or performance criteria lapse.
Our supplemental retirement plan described above under "Annual Pension
Benefit from Qualified and Non-Qualified Plans" provides supplemental
retirement benefits to designated participants, including the named executive
officers other than Mr. Sterbenz and Mr. Geist. The plan provides in the event
of a change in control, all active participants in the plan will be deemed to
be 65 years of age for purposes of determining the maximum percentage of
retirement benefits and 100% vesting of such benefits with benefits commencing
not earlier than age 50. In addition, the plan provides for the funding of the
plan benefits through our contributions into a rabbi trust under certain
circumstances, including a change in control. The employment agreements for Mr.
Wittig and Mr. Lake, provide that full benefits under the plan shall commence
immediately upon a Qualifying Termination and shall be calculated using the
officer's Adjusted Salary and Bonus Amount.
Under the employment agreements, if the officer is entitled to benefits
under any split dollar life insurance agreement, a Qualifying Termination will
result in the vesting of the base amount benefit (as defined in the split
dollar agreement) under the program. Upon a Qualifying Termination, benefits
payable under the split dollar life insurance program are required to be
deposited into a rabbi trust.
"Cause" is defined as the willful and continued failure to perform
substantially his or her duties or the willful engaging in illegal conduct
demonstrably and materially injurious to us. "Good Reason" is defined as any
material and adverse change in the executive's position or responsibilities; a
reduction in base salary, annual target bonus opportunity or targeted long term
incentive value; relocation; reduction in benefits; or termination of the
agreement.
Mr. Lake's agreement with us relating to his initial employment provides
for a payment of $1 million on September 15, 2002 if he remains in our employ
or is terminated by us without Cause or by Mr. Lake for Good Reason. Upon a
Qualifying Termination, this payment will become due on the date of termination.
In connection with the retirements of Mr. Koupal and Mr. Grennan, we made
lump sum payments to Mr. Koupal and Mr. Grennan of $773,378 and $544,502,
respectively, which included amounts for accumulated but unused vacation and in
the case of Mr. Koupal a $25,000 payment for accounting and legal expenses. In
addition, Mr. Koupal and Mr. Grennan may continue to participate on the same
terms as active employees in our group medical and dental plans until the
earlier of October 31, 2004 or the date on which they become eligible for
coverage through employment with another employer, and are entitled to
reimbursement for outplacement services and relocation expenses up to $50,000
each. Mr. Koupal and Mr. Grennan retained restricted share units granted to
them, which will vest on the same basis as if they had remained in our active
employment. Mr. Koupal and Mr. Grennan also retained their benefits under our
defined benefit pension plan and supplemental retirement plan.
122
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
-----------------------------------------------------------------------
Certain Beneficial Owners of Common Stock
Other than as set forth in the following table, we know of no other
beneficial owner of more than five percent of our outstanding common stock. The
information provided is as of April 16, 2002.
Name and Address of Amount and Nature of
Beneficial Owner Beneficial Ownership Percent of Class
------------------------------------ -------------------- ----------------
Westar Industries, Inc.(1) 15,769,508 22.0%(2)
818 S. Kansas Avenue
Topeka, KS 66612
Mario J. Gabelli(3) 3,540,600 5.0%
Marc J. Gabelli
One Corporate Center
Rye, NY 10580
Wallace R. Weitz and Company(4) 6,578,100 9.4%
1125 S. 103rd Street, Suite 600
Omaha, NE 68124-6008
------------------
(1)Westar is our wholly owned subsidiary. We have shared investment power
with respect to, and are deemed to beneficially own these shares under
Rule 13d-3 of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"). Under Kansas law, the shares held by Westar are not
entitled to vote as long as Westar remains our majority owned
subsidiary.
(2)The percent is calculated pursuant to Section 13(d)(4) of the Exchange
Act, which excludes from outstanding shares any shares held by us or
any of our subsidiaries. The percent is 18.0% if the shares held by
Westar and Protection One are included in outstanding shares.
(3)As reported in a Schedule 13D filed with the Securities and Exchange
Commission on February 11, 2002 by Mario J. Gabelli and Marc J. Gabelli
and various entities which either one directly or indirectly controls
or for which either one acts as chief investment officer.
(4)As reported in a Schedule 13D/A filed with the Securities and Exchange
Commission on April 5, 2002.
Certain Beneficial Owners of Preferred Stock
Protection One owns 3,890 shares of our 41/4% series preferred stock,
representing 6.9% of such class, 13,458 shares of our 41/2% series preferred
stock, representing 10.8% of such class, and 12,220 shares of our 5% series
preferred stock, representing 32.3% of such class. The percent is calculated
pursuant to Section 13(d)(4) of the Exchange Act, which excludes from
outstanding shares any shares held by us or any of our subsidiaries. If the
shares held by Protection One are included in the outstanding shares,
Protection One owns 6.5% of our 41/4% series preferred stock, 9.7% of our 41/2%
series preferred stock, and 24.4% of our 5% series preferred stock. Under
Kansas law, the shares held by Protection One are not entitled to vote as long
as Protection One remains our indirect majority owned subsidiary.
Change in Control
On November 8, 2000, we entered into an agreement with Public Service
Company of New Mexico ("PNM") pursuant to which PNM would acquire our electric
utility businesses in a stock for stock merger. Under the terms of the
agreement, both we and PNM would become subsidiaries of a new holding company,
subject to customary closing conditions, including shareholder and regulatory
approvals. On January 7, 2002, PNM sent a letter to us purporting to terminate
the merger in accordance with the terms of the merger agreement. We have
notified PNM that we believe the purported termination of the merger agreement
was ineffective and that PNM remains obligated to perform thereunder. Based
upon PNM's actions and the related uncertainties, we believe the closing of the
proposed merger is not likely to occur.
123
Security Ownership of Management
The following information is furnished with respect to each of our current
directors and named executive officers individually, and with respect to our
current directors and executive officers as a group, as to ownership of shares
of our common stock and the common stock of Protection One. The information
provided is as of April 16, 2002.
Amount and Nature of Amount and Nature of
Beneficial Ownership of Percentage of Beneficial Ownership of
Name of Beneficial Owner Western Resources Stock (1) Ownership (2) Protection One Stock (3)
------------------------ --------------------------- ------------- ------------------------
Frank J. Becker 38,801(4)(5) -- 31,800(4)
Gene A. Budig 12,864(5) -- 5,014(6)
Charles Q. Chandler, IV 3,917(5) -- 3,333(6)
John C. Dicus 7,335(5)(7) -- --
R.A. Edwards 8,169(8) -- --
Paul R. Geist 34,128(5) -- 6,500
Thomas L. Grennan 80,761(5) -- --
Carl M. Koupal, Jr. 154,184(5) -- --
Douglas T. Lake 299,362(5) -- 38,800
Shane A. Mathis 57,466(5) -- --
John C. Nettels, Jr. 6,140(5)(8) -- 13,833(6)(9)
Douglas R. Sterbenz 23,400(5) -- --
David C. Wittig 807,788(1)(5)(10) 1.1% 237,500(11)
All directors and executive officers
as a group
(13 individuals) 1,545,832(12) 2.2% 336,780(13)
--------
(1)No director or executive officer, except Mr. Wittig, owns any of our equity
securities other than our common stock. Includes beneficially owned shares
held in employee savings plans and shares deferred under the Long Term
Incentive and Share Award Plan, the Stock for Compensation Program and the
Outside Directors' Deferred Compensation Plan. Mr. Wittig holds 2,800 shares
of our 4.25% series preferred stock indirectly through his sons, 2,400
shares of our 4 1/4% series preferred stock directly, and 1,458 shares of
our 4 1/2% series preferred stock directly. The shares of our 4 1/4% series
preferred stock and 4 1/2% series preferred stock beneficially owned by Mr.
Wittig represent 9.3% and 1.2% of the outstanding shares of each series,
respectively.
(2)Percentages are omitted if a person owns less than one percent of the
outstanding shares of our common stock. Percentages are calculated excluding
shares held by Westar and Protection One.
(3)Each individual and the group owns less than one percent of the outstanding
shares of Protection One's common stock. No director or executive officer
owns any equity securities of Protection One other than Protection One's
common stock.
(4)Includes 2,800 shares of our common stock and 5,000 shares of Protection One
common stock held in trusts of which Mr. Becker is a co-trustee with shared
voting and investment power and excludes shares held in trust by Douglas
County Bank, of which Mr. Becker is a director.
(5)Includes restricted share units as follows: Mr. Becker, 798; Dr. Budig, 798;
Mr. Chandler, 798; Mr. Dicus, 498; Mr. Geist, 9,200; Mr. Grennan, 45,300;
Mr. Koupal, 151,724; Mr. Lake, 207,999; Mr. Mathis, 36,199; Mr. Nettels,
798; Mr. Sterbenz, 6,970; Mr. Wittig, 412,022; and 13,586 restricted share
units granted to one other executive officer in the group.
(6)Includes stock options exercisable currently or within sixty days: Dr.
Budig, 1,014 shares; Mr. Chandler, 3,333 shares; and Mr. Nettels, 10,833
shares.
(7)Includes 500 shares held by Mr. Dicus' spouse, not subject to his voting or
investment power.
(8)Includes 1,709 shares held by Mr. Edwards' spouse, not subject to his voting
or investment power.
(9)Includes 500 shares held in a trust in which Mr. Nettels has shared
investment and voting power.
124
(10)Includes 31,484 shares held by Mr. Wittig's spouse, not subject to his
voting or investment power.
(11)Mr. Wittig holds the shares indirectly through his two sons, who each hold
118,750 shares.
(12)Includes shares referred to in items (1), (4), (5), (7), (8) and (10) above.
(13)Includes shares referred to in items (3), (4), (6), (9) and (11) above.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
-------------------------------------------------------
Transactions with Protection One
Contribution Agreement
Pursuant to the Contribution Agreement between Protection One and us dated
July 30, 1997, we contributed our monitored security businesses to Protection
One and acquired an ownership interest in Protection One. As a result, we owned,
through Westar, approximately 85% of Protection One's common stock at December
31, 1997.
The Contribution Agreement provided that during the 10-year period
following November 24, 1997, a merger or a sale of all or substantially all of
Protection One's assets involving us or any affiliate of us generally will
require the prior approval of a majority of the "Independent Directors" (as
defined in the Contribution Agreement), and we may not acquire beneficial
ownership of more than 85% of Protection One's outstanding shares of Common
Stock or other voting securities except under specified circumstances and
subject to specified limitations. On June 2001, Protection One's "Continuing
Directors" (as defined in the Contribution Agreement), approved an amendment to
the Contribution Agreement which permits our beneficial ownership of Protection
One's outstanding common stock to exceed 85% provided that our beneficial
ownership on a fully diluted basis does not exceed 81% of the outstanding
shares. On March 18, 2002, Protection One's "Continuing Directors" approved a
waiver of the ownership limitation for the period March 11, 2002 through July
1, 2002. As of December 31, 2001, the shares of Protection One common stock
owned by Westar represented approximately 88% of the outstanding shares on a
non-diluted basis.
On October 18, 2001, Protection One's "Continuing Directors" approved an
amendment to the Contribution Agreement that decreased the size of its Board of
Directors and modified the persons for whom we have agreed to vote our shares
in the election of directors. As a result of the amendment, so long as we
directly or indirectly own more than 50% of the outstanding shares of
Protection One's common stock, Protection One's Board of Directors will have
not less than nine nor more than twelve directors, and we will vote all such
shares we own to elect as directors one individual selected by us from
Protection One's executive officers, at least three "Independent Directors" (as
defined in the Contribution Agreement) and the number of additional individuals
nominated by us to fill the remaining positions on the Board of Directors.
Service Agreement
Protection One is a party to a service agreement with us. Pursuant to this
agreement, we provide administrative services including accounting, tax, audit,
human resources, legal, facilities and technology services. Protection One
incurred charges of approximately $8.1 million for the year ended December 31,
2001. These charges were based upon various hourly charges, negotiated fees and
out-of-pocket expenses. At December 31, 2001, Protection One had a net
intercompany balance due to us of approximately $1.7 million for these services.
Tax Sharing Agreement
We have a tax sharing agreement with Protection One. This pro rata tax
sharing agreement allows Protection One to be reimbursed for current tax
benefits utilized in our consolidated tax return. We and Protection One are
eligible to file on a consolidated basis for tax purposes as long as we
maintain an 80% ownership interest in Protection One. In 2001, we reimbursed
Protection One $11.8 million for tax year 2001 and $7.4 million for tax year
2000 for the tax benefit.
At December 31, 2001, we had a payable balance to Protection One of $1.7
million, which reflected the balance of the estimated tax benefit to be
utilized by us in our 2001 consolidated income tax return less an estimated
amount for alternative minimum tax carry forwards. We paid this amount to
Protection One in February 2002.
125
Office Space
Protection One leases office space from us in our general offices in Topeka
and Wichita, Kansas. During 2001, we billed Protection One approximately
$546,459 for office space.
During the fourth quarter of 2001, Kansas Gas and Electric Company ("KGE"),
our wholly owned subsidiary, entered into an option agreement to sell an office
building located in downtown Wichita, Kansas, to Protection One. Protection One
paid KGE approximately $0.5 million pursuant to this agreement. The sales price
was determined by management based on three independent appraisers' findings.
Purchases of Securities
In the latter part of 2001 through March 15, 2002, Protection One purchased
in the open market 27,495 shares of our preferred stock for approximately $1.7
million, 13,300 shares of our Quarterly Income Preferred Securities for
approximately $0.3 million, approximately $9.7 million of our 6.25% Put/Call
Notes (the "6.25% Notes"), approximately $0.1 million in ONEOK common stock and
approximately $3.0 million of our common stock. In March 2002, we purchased the
ONEOK stock, the 6.25% Notes and the Quarterly Income Preferred Securities from
Protection One for approximately $9.8 million.
Transactions with Westar
We had a payable to Westar of approximately $67.7 million at December 31,
2001 on which we paid interest at the rate of 8.5% per annum. On February 28,
2001, Westar converted $350.0 million of the then outstanding payable balance
into approximately 14.4 million shares of our common stock, representing 16.9%
of our outstanding common stock after conversion. These shares are reflected as
treasury stock in our consolidated balance sheets. During the first quarter of
2002, we repaid the remaining balance owed to Westar. The proceeds were used by
Westar to purchase our outstanding debt in the open market.
We have submitted a financial plan to the Kansas Corporation Commission
("KCC"). If the KCC approves our financial plan, at the closing of the proposed
rights offering we would enter into an option agreement that grants Westar an
option to purchase the stock of Westar Generating, Inc., a wholly owned
subsidiary that owns our interest in the State Line generating facility. The
option would be exercisable at any time during the three year period following
execution of the agreement, subject to extension for two additional one year
periods. The option price is based on net book value at the time of exercise.
The option would be exercisable only if Westar is unable to obtain a permanent
exemption from registration under the Investment Company Act of 1940.
If the KCC approves our financial plan, Westar may extend loans, or
guarantee payment of loans being extended by a bank or other lender, in an
aggregate amount not to exceed $20 million for the purchase of shares of its
common stock upon the exercise of rights by its officers and directors and
certain of our officers and directors.
Transactions Between Westar and Our Subsidiaries
Protection One Credit Facility
Westar is the lender under Protection One's senior credit facility.
Protection One had outstanding borrowings under the facility of $137.5 million
as of December 31, 2001. Protection One accrued interest expense of $10.5
million and made interest payments of $10.4 million on borrowings under the
facility for the year ended December 31, 2001.
126
In the second quarter of 2001, Protection One requested and Westar agreed
to modifications to the facility which excluded from EBITDA the costs
associated with certain work force reductions and office consolidations
resulting in expenses that otherwise would have resulted in the violation of
certain financial covenants. In addition, the leverage ratio was amended to
increase the maximum ratio to 5.75 to 1.0 and the interest coverage ratio was
amended to decrease the minimum ratio to 2.1 to 1.0.
On November 1, 2001, the facility was amended to, among other things,
extend the maturity date to January 3, 2003. On March 25, 2002, the facility
was further amended to increase the amount of the facility to $180 million. As
of April 19, 2002, approximately $142.5 million was drawn under the facility.
Purchases of Securities
During 2001, Protection One purchased 16,101,892 shares of its common stock
from Westar at then current market prices for $19.5 million.
In 2001, Protection One purchased from Westar $93.7 million face value of
Protection One bonds at their market value of $61.8 million. The prices paid by
Protection One for the debt securities were established by the board of
directors of Protection One so as not to exceed the ten day average of the
market price for such securities as quoted by a reputable New York broker who
makes a market in the debt securities. Protection One relied on these quotes in
order to meet the guidelines set by the Protection One board of directors in
establishing the purchase prices.
In 2001, Protection One purchased 1,696 shares of our preferred stock from
Westar for $0.1 million. In March 2002, Protection One purchased from Westar
approximately $8.3 million face amount of Protection One's Senior Subordinated
Discount Notes for approximately $7.5 million and $6.5 million face amount of
Protection One's Senior Subordinated Notes for approximately $4.5 million.
Other Transactions
On November 1, 2001, Protection One entered into an agreement pursuant to
which it will pay to Westar, beginning with the quarter ending March 31, 2002,
a fee for financial advisory and management services, payable quarterly, equal
to 0.125% of Protection One's consolidated total assets at the end of each
quarter. This agreement entitles Protection One, at its option, to aviation
services from Westar Aviation, Inc. ("Westar Aviation"), a wholly owned
subsidiary of Westar. This agreement was approved by the independent members of
Protection One's board of directors.
Protection One compensates Westar Aviation for the use of corporate
aircraft. During 2001, Westar Aviation billed Protection One approximately $0.6
million for aircraft use.
Loans to Officers
In 2001, our Board of Directors approved stock ownership target levels for
officers and other members of senior management. In December 2001, our Board of
Directors also approved a loan program to assist officers in meeting their
target levels. Pursuant to the program, each officer can borrow from us an
amount up to one to three times the maximum base salary for his or her
respective pay grade to purchase shares of our common stock in the market. Each
loan has a term of three years, has a variable interest rate equal to our short
term borrowing rate, requires quarterly interest payments and requires payment
in full at maturity. The loans are unsecured. In 2001, the following named
executive officers had loans outstanding under the program with the indicated
highest amount outstanding during the year: Mr. Lake, $1,000,000; Mr. Mathis,
$300,000; and Mr. Geist, $300,000. At April 29, 2002, the loans had the same
outstanding balances, except that the outstanding balance of the loan to Mr.
Geist was $400,000.
127
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
------------------------------------------------------------------------
FINANCIAL STATEMENTS INCLUDED HEREIN
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 2001 and 2000
Consolidated Statements of Income for the years ended December 31,
2001, 2000 and 1999
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2001, 2000 and 1999
Consolidated Statements of Cash Flows for the years ended December 31,
2001, 2000 and 1999
Consolidated Statements of Shareholders' Equity for the years ended
December 31, 2001, 2000 and 1999
Notes to Consolidated Financial Statements
SCHEDULES
Schedule II - Valuation and Qualifying Accounts
Schedules omitted as not applicable or not required under the Rules of
regulation S-X: I, III, IV, and V
REPORTS ON FORM 8-K FILED DURING THE QUARTER ENDED DECEMBER 31, 2001:
Form 8-K filed October 16, 2001 - Announcement that PNM filed a lawsuit
against us in New York court seeking monetary damages for breach of
representation and seeking, among other things, to terminate the merger
agreement.
Form 8-K filed October 26, 2001 - Announcement of changes in our Direct
Stock Purchase Plan.
Form 8-K filed November 6, 2001 - Announcement that we filed a financial
plan with the KCC.
Form 8-K filed November 20, 2001 - Announcement that we filed a lawsuit
against PNM in New York court seeking substantial damages for PNM's breach of
the merger agreement.
Form 8-K filed December 6, 2001 - Announcement of our expected 2002
operating results.
128
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference. All exhibits
marked by an asterisk are management contracts or compensatory plans or
arrangements required to be identified by Item 14(a)(3) of Form 10-K.
Description
-----------
2(a) -Agreement and Plan of Restructuring and Merger, dated as of I
November 8, 2000 among the company, Public Service Company of New
Mexico, HVOLT Enterprises, Inc., HVK, Inc., and HVNM, Inc. (filed
as Exhibit 99.1 to the November 17, 2000 Form 8-K)
3(a) -By-laws of the company, as amended March 16, 2000 (filed as Exhibit I
3(a) to December 1999 Form 10-K)
3(b) -Restated Articles of Incorporation of the company, as amended I
through May 25, 1988 (filed as Exhibit 4 to Registration Statement,
SEC File No. 33-23022)
3(c) -Certificate of Amendment to Restated Articles of Incorporation of I
the company dated March 29, 1991.
3(d) -Certificate of Designations for Preference Stock, 8.5% Series, I
without par value, dated March 31, 1991 (filed as Exhibit 3(d) to
December 1993 Form 10-K)
3(e) -Certificate of Correction to Restated Articles of Incorporation of I
the company dated December 20, 1991 (filed as Exhibit 3(b) to
December 1991 Form 10-K)
3(f) -Certificate of Designations for Preference Stock, 7.58% Series, I
without par value, dated April 8, 1992, (filed as Exhibit 3(e) to
December 1993 form 10-K)
3(g) -Certificate of Amendment to Restated Articles of Incorporation of I
the company dated May 8, 1992 (filed as Exhibit 3(c) to December
31, 1994 Form 10-K)
3(h) -Certificate of Amendment to Restated Articles of Incorporation of I
the company dated May 26, 1994 (filed as Exhibit 3 to June 1994
Form 10-Q)
3(i) -Certificate of Amendment to Restated Articles of Incorporation of I
the company dated May 14, 1996 (filed as Exhibit 3(a) to June 1996
Form 10-Q)
3(j) -Certificate of Amendment to Restated Articles of Incorporation of I
the company dated May 12, 1998 (filed as Exhibit 3 to March 1998
Form 10-Q)
3(k) -Form of Certificate of Designations for 7.5% Convertible Preference I
Stock (filed as Exhibit 99.4 to November 17, 2000 Form 8-K)
4(a) -Deferrable Interest Subordinated Debentures dated November 29, I
1995, between the company and Wilmington Trust Delaware, Trustee
(filed as Exhibit 4(c) to Registration Statement No. 33-63505)
4(b) -Mortgage and Deed of Trust dated July 1, 1939 between the company I
and Harris Trust and Savings Bank, Trustee (filed as Exhibit 4(a)
to Registration Statement No. 33-21739)
4(c) -First through Fifteenth Supplemental Indentures dated July 1, 1939, I
April 1, 1949, July 20, 1949, October 1, 1949, December 1, 1949,
October 4, 1951, December 1, 1951, May 1, 1952, October 1, 1954,
September 1, 1961, April 1, 1969, September 1, 1970, February 1,
1975, May 1, 1976 and April 1, 1977, respectively (filed as Exhibit
4(b) to Registration Statement No. 33-21739)
4(d) -Sixteenth Supplemental Indenture dated June 1, 1977 (filed as I
Exhibit 2-D to Registration Statement No. 2-60207)
4(e) -Seventeenth Supplemental Indenture dated February 1, 1978 (filed as I
Exhibit 2-E to Registration Statement No. 2-61310)
4(f) -Eighteenth Supplemental Indenture dated January 1, 1979 (filed as I
Exhibit (b) (1)-9 to Registration Statement No. 2-64231)
4(g) -Nineteenth Supplemental Indenture dated May 1, 1980 (filed as I
Exhibit 4(f) to Registration Statement No. 33-21739)
4(h) -Twentieth Supplemental Indenture dated November 1, 1981 (filed as I
Exhibit 4(g) to Registration Statement No. 33-21739)
4(i) -Twenty-First Supplemental Indenture dated April 1, 1982 (filed as I
Exhibit 4(h) to Registration Statement No. 33-21739)
4(j) -Twenty-Second Supplemental Indenture dated February 1, 1983 (filed I
as Exhibit 4(i) to Registration Statement No. 33-21739)
129
4(k) -Twenty-Third Supplemental Indenture dated July 2, 1986 (filed as I
Exhibit 4(j) to Registration Statement No. 33-12054)
4(l) -Twenty-Fourth Supplemental Indenture dated March 1, 1987 (filed as I
Exhibit 4(k) to Registration Statement No. 33-21739)
4(m) -Twenty-Fifth Supplemental Indenture dated October 15, 1988 (filed I
as Exhibit 4 to the September 1988 Form 10-Q)
4(n) -Twenty-Sixth Supplemental Indenture dated February 15, 1990 (filed I
as Exhibit 4(m) to the December 1989 Form 10-K)
4(o) -Twenty-Seventh Supplemental Indenture dated March 12, 1992 (filed I
as Exhibit 4(n) to the December 1991 Form 10-K)
4(p) -Twenty-Eighth Supplemental Indenture dated July 1, 1992 (filed as I
Exhibit 4(o) to the December 1992 Form 10-K)
4(q) -Twenty-Ninth Supplemental Indenture dated August 20, 1992 (filed as I
Exhibit 4(p) to the December 1992 Form 10-K)
4(r) -Thirtieth Supplemental Indenture dated February 1, 1993 (filed as I
Exhibit 4(q) to the December 1992 Form 10-K)
4(s) -Thirty-First Supplemental Indenture dated April 15, 1993 (filed as I
Exhibit 4(r) to Registration Statement No. 33-50069)
4(t) -Thirty-Second Supplemental Indenture dated April 15, 1994 (filed as I
Exhibit 4(s) to the December 31, 1994 Form 10-K)
4(u) -Thirty-Fourth Supplemental Indenture dated June 28, 2000 (filed as I
Exhibit 4(v) to the December 31, 2000 Form 10-K)
4(v) -Debt Securities Indenture dated August 1, 1998 (filed as Exhibit I
4.1 to the June 30, 1998 Form 10-Q)
4(w) -Form of Note for $400 million 6.25% Putable/Callable Notes due I
August 15, 2018, Putable/Callable August 15, 2003 (filed as Exhibit
4.2 to the June 30, 1998 Form 10-Q)
Instruments defining the rights of holders of other long-term debt not
required to be filed as Exhibits will be furnished to the Commission
upon request.
10(a) -Long-Term Incentive and Share Award Plan (filed as Exhibit 10(a) to I
the June 1996 Form 10-Q)*
10(b) -Form of Employment Agreements with Messers. Grennan, Koupal, Lake, I
Terrill, Wittig and Ms. Sharpe (filed as Exhibit 10(b) to the
December 31, 2000 Form 10-K)*
10(c) -A Rail Transportation Agreement among Burlington Northern Railroad I
Company, the Union Pacific Railroad Company and the Company (filed
as Exhibit 10 to the June 1994 Form 10-Q)
10(d) -Agreement between the company and AMAX Coal West Inc. effective I
March 31, 1993 (filed as Exhibit 10(a) to the December 31, 1993
Form 10-K)
10(e) -Agreement between the company and Williams Natural Gas Company I
dated October 1, 1993 (filed as Exhibit 10(b) to the December 31,
1993 Form 10-K)
10(f) -Deferred Compensation Plan (filed as Exhibit 10(i) to the December I
31, 1993 Form 10-K)*
10(g) -Short-term Incentive Plan (filed as Exhibit 10(k) to the December I
31, 1993 Form 10-K)*
10(h) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I
10(l) to the December 31, 1993 Form 10-K)*
10(i) -Executive Salary Continuation Plan of Western Resources, Inc., as I
revised, effective September 22, 1995 (filed as Exhibit 10(j) to
the December 31, 1995 Form 10-K)*
10(j) -Letter Agreement between the company and David C. Wittig, dated I
April 27, 1995 (filed as Exhibit 10(m) to the December 31, 1995
Form 10-K)*
10(k) -Form of Shareholder Agreement between New ONEOK and the company I
(filed as Exhibit 99.3 to the December 12, 1997 Form 8-K)
10(l) -Form of Split Dollar Insurance Agreement (filed as Exhibit 10.3 to I
the June 30, 1998 Form 10-Q)*
10(m) -Amendment to Letter Agreement between the company and David C. I
Wittig, dated April 27, 1995 (filed as Exhibit 10 to the June 30,
1998 Form 10-Q/A)*
10(n) -Letter Agreement between the company and Douglas T. Lake, dated I
August 17, 1998 *
10(o) -Form of Change of Control Agreement with officers of the company I
(filed as Exhibit 10(o) to the December 31, 2000 Form 10-K)*
130
10(p) -Amendment to Outside Directors' Deferred Compensation Plan dated I
May 17, 2001 (filed as Exhibit 10(p) to the December 31, 2000 Form
10-K)*
10(q) -Asset Allocation and Separation Agreement, dated as of November 8, I
2000, between the company and Westar Industries, Inc. (filed as
Exhibit 99.2 to the November 17, 2000 Form 8-K)
10(r) -Form of loan agreement with officers of the company*
12 -Computations of Ratio of Consolidated Earnings to Fixed Charges
21 -Subsidiaries of the Registrant
23 -Consent of Independent Public Accountants, Arthur Andersen LLP
99(a) -Press release issued August 13, 2001 by PNM announcing that talks I
to modify our transaction with PNM have been discontinued (filed as
Exhibit 99.1 to the June 30, 2001 Form 10-Q)
99(b) -Press release issued August 13, 2001 by Western Resources I
responding to PNM's announcement of discontinued talks (filed as
Exhibit 99.2 to the June 30, 2001 Form 10-Q)
99(c) -Letter to the SEC of assurances given by Arthur Andersen LLP
regarding their audit of December 31, 2001 financial statements to
the company
131
WESTERN RESOURCES, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Dollars in Thousands)
Balance at Charged to Balance
Beginning Costs and at End
Description of Period Expenses Deductions of Period
----------- --------- -------- ---------- ---------
(In Thousands)
Year ended December 31, 1999
Allowances deducted from assets for doubtful accounts (a) .... $ 29,544 $ 24,302 $(18,081) $ 35,765
Monitored services special charge (b) ........................ 1,025 -- (1,025) --
Accrued exit fees, shut-down and severance costs (c) ........ 22,900 (5,632) (16,888) 380
Year ended December 31, 2000
Allowances deducted from assets for doubtful accounts (a) .... 35,765 23,690 (13,639) 45,816
Accrued exit fees, shut-down and severance costs ............. 380 -- -- 380
Year ended December 31, 2001
Allowances deducted from assets for doubtful accounts (a) .... 45,816 7,075 (33,770) 19,121
Accrued exit fees, shut-down and severance costs (d) ........ 380 -- (337) 43
----------
(a) Deductions are the result of write-offs of accounts receivable.
(b) Consists of costs to close duplicate facilities and severance and
compensation benefits.
(c) See Note 22 of the "Notes to Consolidated Financial Statements" for
further information.
(d) Deductions are the result of payment of accrued severance costs.
132
SIGNATURE
Pursuant to the requirements of Sections 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
WESTERN RESOURCES, INC.
Date: April 30, 2002 By: /s/ Paul R. Geist
-------------------------------------
Paul R. Geist,
Senior Vice President,
Chief Financial Officer and Treasurer
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature Title Date
--------- ----- ----
/s/ DAVID C. WITTIG Chairman of the Board, President April 30, 2002
--------------------------- and Chief Executive Officer
(David C. Wittig) (Principal Executive Officer)
/s/ PAUL R. GEIST Senior Vice President, Chief April 30, 2002
--------------------------- Financial Officer and Treasurer
(Paul R. Geist) (Principal Financial and
Accounting Officer)
/s/ FRANK J. BECKER Director April 30, 2002
---------------------------
(Frank J. Becker)
/s/ GENE A. BUDIG Director April 30, 2002
---------------------------
(Gene A. Budig)
/s/ CHARLES Q. CHANDLER, IV Director April 30, 2002
---------------------------
(Charles Q. Chandler, IV)
/s/ JOHN C. DICUS Director April 30, 2002
---------------------------
(John C. Dicus)
/s/ R. A. EDWARDS Director April 30, 2002
---------------------------
(R. A. Edwards)
/s/ DOUGLAS T. LAKE Director April 30, 2002
---------------------------
(Douglas T. Lake)
/s/ JOHN C. NETTLES, JR. Director April 30, 2002
---------------------------
(John C. Nettles, Jr.)
133