ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
In Management's Discussion and Analysis we explain the general financial
condition and the operating results for Western Resources, Inc. and its
subsidiaries. We explain:
- What factors impact our business
- What our earnings and costs were in 1998 and 1997
- Why these earnings and costs differed from year to year
- How our earnings and costs affect our overall financial condition
- What our capital expenditures were for 1998
- What we expect our capital expenditures to be for the years 1999
through 2001
- How we plan to pay for these future capital expenditures
- Any other items that particularly affect our financial condition or
earnings
As you read Management's Discussion and Analysis, please refer to our
Consolidated Statements of Income on page 63. These statements show our
operating results for 1998, 1997 and 1996. In Management's Discussion and
Analysis, we analyze and explain the significant annual changes of specific line
items in the Consolidated Statements of Income.
Forward-Looking Statements
Certain matters discussed here and elsewhere in this Annual Report are
"forward-looking statements." The Private Securities Litigation Reform Act of
1995 has established that these statements qualify for safe harbors from
liability. Forward-looking statements may include words like we "believe,"
"anticipate," "expect" or words of similar meaning. Forward-looking statements
describe our future plans, objectives, expectations or goals. Such statements
address future events and conditions concerning capital expenditures, earnings,
litigation, rate and other regulatory matters, possible corporate
restructurings, mergers, acquisitions, dispositions, liquidity and capital
resources, interest and dividend rates, Year 2000 Issue, environmental matters,
changing weather, nuclear operations, ability to enter new markets successfully
and capitalize on growth opportunities in nonregulated businesses, events in
foreign markets in which investments have been made, and accounting matters.
What happens in each case could vary materially from what we expect because of
such things as electric utility deregulation, including ongoing state and
federal activities; future economic conditions; legislative developments; our
regulatory and competitive markets; and other circumstances affecting
anticipated operations, sales and costs.
1998 HIGHLIGHTS
Continued Expansion of Monitored Services
Protection One, Inc. (Protection One) had a year of rapid expansion and
continued growth. During the year, Protection One doubled the size of its
customer base from about 750,000 customers to about 1.5 million customers. This
growth was achieved through acquisitions and Protection One's Dealer Program.
During 1998, Protection One invested approximately $549 million in
security company acquisitions. Highlights of this activity include:
- Network Multi-Family - A leading provider of monitored services
to multi-family dwellings. This acquisition added approximately
200,000 customers.
- Multimedia Security Services - A purchase of assets, including a large
security monitoring center in Wichita, Kansas, that added about
147,000 customers.
- Compagnie Europeenne de Telesecurite (CET) - An acquisition of a French
monitored services provider which added 60,000 customers and
established a major presence in Western Europe.
Protection One financed these acquisitions primarily with cash advances
from Western Resources and from the sale of common shares. In June, Protection
One completed an equity offering that raised approximately $406 million in
aggregate proceeds. We purchased approximately 37.6 million Protection One
common shares of the 42.8 million common shares sold. The shares, which sold
for $9.50 per common share, increased our investment in Protection One by $357
million. Our approximate 85% investment in Protection One totals about $1.1
billion at December 31, 1998. During the year, Protection One refinanced a
large portion of its debt by issuing $250 million of senior unsecured notes,
issuing $350 million of senior subordinated notes and obtaining a $500 million
credit facility. Part of the proceeds from these offerings were used to repay
a $395 million intercompany obligation to us.
The Lifeline Transaction
In October 1998, Protection One announced an agreement to acquire
Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal
emergency response and support services in North America. Based on the average
closing price for the three trading days prior to April 8, 1999, the value of
the consideration to be paid under the merger agreement is approximately
$129.2 million or $22.05 per Lifeline share in cash and stock. Lifeline has
advised Protection One that it is evaluating the restatement of Protection One's
financial statements. The consideration to be given in the Lifeline transaction
is by design variable and is subject to change within certain parameters until
the closing date. Interested parties should obtain the most recent
proxy/registration statement for further analysis of the transaction.
Investment in ONEOK, INC.
We received approximately $40 million in cash dividends from our ONEOK,
Inc. (ONEOK) investment in 1998. Tax rules allow us to exclude 70% of these
dividends from the determination of taxable income. This 70% exclusion saves
us about $11 million in income taxes annually.
In December 1998, ONEOK announced its intention to purchase Southwest
Gas Corporation (Southwest). ONEOK will pay Southwest shareholders $28.50 per
common share and assume debt for a total transaction value of approximately $1.8
billion. ONEOK will add 1.2 million customers in higher growth markets in
Arizona, Nevada and California to its existing base of 1.4 million customers as
a result of this purchase. The merger is expected to create the largest
stand-alone gas distribution company in the United States.
In February 1999, ONEOK was advised by Southwest that it had received an
unsolicited offer of $32 per share of common stock from Southern Union Company.
Southwest is evaluating both offers.
In November 1997, we completed our strategic alliance with ONEOK and
contributed substantially all of our natural gas business to ONEOK in exchange
for a 45% ownership interest in ONEOK. Our ownership interest is comprised of
approximately 3.2 million common shares and approximately 20.1 million
convertible preferred shares. If all the preferred shares were converted, we
would own approximately 45% of ONEOK's common shares presently outstanding.
Following the strategic alliance, the consolidated energy sales, related cost of
sales and operating expenses in 1997 for our natural gas business have been
replaced by investment earnings in ONEOK.
Electric Utility Operations
We experienced warmer weather during the summer months in 1998 than we
did in 1997 which improved net income by $19.8 million. The effect of our
electric rate decrease lowered 1998 net income $6.6 million.
In January 1997, the Kansas Corporation Commission (KCC) entered an
order reducing electric rates for both our KPL division (KPL) and Kansas Gas and
Electric Company (KGE). Significant terms of the order are as follows:
- We made permanent the May 1996 interim $8.7 million decrease in KGE
rates on February 1, 1997
- We reduced KGE's rates by $36 million annually on February 1, 1997
- We reduced KPL's rates by $10 million annually on February 1, 1997
- We rebated $5 million to all of our electric customers in January
1998
- We reduced KGE's rates by $10 million annually on June 1, 1998
- We rebated $5 million to all of our electric customers in January
1999
- We will reduce KGE's rates by $10 million more annually on June 1,
1999
These electric rate decreases have negatively impacted our net income.
The total annual cumulative effect of these rate decreases is approximately $75
million. All rate decreases are cumulative. Rebates are one-time events and do
not influence future rates.
Electric utility net income totaled approximately $133 million,
excluding one-time events, for 1998. Electric utility net income reflects a
debt allocation of $1.9 billion. Westar Energy, the new company to be created
as a result of the Kansas City Power & Light Company (KCPL) merger, will
assume $1.9 billion of debt from us and KGE after closing the KCPL merger. We
expect to own an 80.1% interest in Westar Energy which will combine our electric
operations with those of KCPL. For more information on the KCPL merger, see
OTHER INFORMATION.
Charge to Income to Exit International Power Development Activity
We decided to exit the international power development business during
the fourth quarter of 1998 in order to focus more attention on our consumer
service businesses. As a result of this decision, we recorded a charge to
income approximating $99 million, or $0.98 per share. The charge accrued exit
and shutdown costs, including severance
to affected employees who were notified of the shutdown in December, recognized
the write-off of deferred development costs for projects we will cease
developing and recognized the write-off of goodwill created when we acquired The
Wing Group in 1996. We have also written down the value of certain equity
investments in foreign countries to their estimated fair value. We believe
negative political, economic, operating, and regulatory factors reduced the
value of our ownership interests in these investments and that this decrease is
not temporary. See Note 11 for further information.
Other Charges to Income
In the fourth quarter, we sold our investment in an equity security that
was unrelated to our core utility and monitored services businesses and
realized a pre-tax loss of about $13 million. In addition, we wrote down the
value of another investment due to declines in value which we believe were not
temporary. The pre-tax charge related to this investment approximated $6
million. Operating results for 1998 also included pre-tax severance
obligations and employee benefits of approximately $20 million.
Operating Results
Operating results for 1998 are difficult to compare to 1997 due
primarily to 1998 charges as discussed above in 1998 HIGHLIGHTS and the 1997
pre-tax gain on the sale of Tyco International Ltd. (Tyco) common stock of $864
million.
In addition to the gain on the sale of Tyco common stock recorded in
1997, we recorded charges which included $48 million of deferred KCPL merger
costs and approximately $24 million recorded by Protection One to recognize
higher than expected customer attrition and to record costs related to the
acquisition of Protection One.
In November 1997, we completed our strategic alliance with ONEOK and
contributed substantially all of our natural gas business to ONEOK in exchange
for a 45% ownership interest in ONEOK. Following the strategic alliance, the
consolidated sales, related cost of sales and operating expenses in 1997 for our
natural gas business have been replaced in 1998 by investment earnings from
ONEOK. Sales and cost of sales from our natural gas business in 1997 were $739
million and $538 million.
The following explains significant changes from prior year results in
sales, cost of sales, operating expenses, other income (expense), interest
expense, income taxes, and preferred and preference dividends.
Energy sales primarily include electric sales, power marketing sales
and, through November 1997, natural gas sales. Items included in energy cost of
sales are fuel expense, purchased power expense (including electricity we
purchase from others for resale), power marketing expense and, through
November 1997, natural gas purchased.
Electric Utility
Sales
Electric sales include sales from fossil generation, power marketing and
power delivery operations. The KCC and the Federal Energy Regulatory Commission
(FERC) authorize rates for our electric sales. Power marketing is only regulated
by the FERC. Our electric sales vary with levels of energy deliveries.
Changing weather affects the
amount of electricity our customers use. Very hot summers and very cold winters
prompt more demand, especially among our residential customers. Mild weather
reduces demand.
Many things will affect our future electric sales. They include:
- The weather
- Our electric rates
- Competitive forces
- Customer conservation efforts
- Wholesale demand
- The overall economy of our service area
1998 compared to 1997: Total electric sales increased 31%. Electric
utility sales increased 6% due to increased retail energy deliveries as a result
of warmer summer temperatures and power marketing sales increased 448%. Our
annual $10 million electric rate decrease implemented on June 1, 1998, partially
offset this increase.
The following table reflects the change in electric energy deliveries,
as measured by kilowatt hours, for retail customers for 1998 compared to 1997.
Increase
Residential. . . . . 9.5%
Commercial . . . . . 6.8%
Industrial . . . . . 1.6%
Other. . . . . . . . 1.0%
Total retail . . . 5.9%
1997 compared to 1996: Electric sales increased 3% because of our
expansion of power marketing activity in 1997. Higher electric sales from power
marketing were offset by our reduced electric rates implemented February 1,
1997, which lowered revenues by an estimated $46 million annually.
Cost of Sales
1998 compared to 1997: Total electric cost of sales increased 83% in
1998 due mostly to higher power marketing cost of sales.
1997 compared to 1996: Our power marketing activity in 1997 increased
electric cost of sales by $70 million. Actual cost of fuel to generate
electricity (coal, nuclear fuel, natural gas or oil) and the amount of power
purchased from other utilities were $14 million higher. For further
explanations of cost of sales increases, see the fossil generation and nuclear
generation business segments discussion below.
Depreciation and Amortization Expense
1998 compared to 1997: Depreciation and amortization expense decreased
$22 million, or 12%, primarily because we had fully amortized a regulatory asset
during 1997. This decrease in amortization expense increased 1998 earnings
before interest and taxes from 1997.
1997 compared to 1996: Depreciation and amortization expense increased
$13 million, or 8%, primarily due to fully amortizing a regulated asset
associated with Wolf Creek nuclear generation facility (Wolf Creek).
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 which 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 power delivery operations.
If we determine that we no longer meet the criteria of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71), we may have a material extraordinary non-cash charge to
operations. Reasons for discontinuing SFAS 71 accounting treatment include
increasing competition that restricts our ability to charge prices needed to
recover costs already incurred and a significant change by regulators from a
cost-based rate regulation to another form of rate regulation. We periodically
review SFAS 71 criteria and believe our net regulatory assets, including those
related to generation, are probable of future recovery. If we discontinue SFAS
71 accounting treatment based upon competitive or other events, we may
significantly impact the value of our net regulatory assets and our utility
plant investments, particularly Wolf Creek. See OTHER INFORMATION for
initiatives taken to restructure the electric industry in Kansas.
Regulatory changes, including competition, could adversely impact our
ability to recover our investment in these assets. As of December 31, 1998, we
have recorded regulatory assets which are currently subject to recovery in
future rates of approximately $364 million. Of this amount, $205 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 coal contract settlement costs, deferred employee benefit costs,
deferred plant costs, and debt issuance costs.
In a competitive environment, we may not be able to fully recover our
entire investment in Wolf Creek. We presently own 47% of Wolf Creek. Our
ownership would increase to 94% when the KCPL combination is completed. We also
may 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.
Electric Utility Business Segments
We define and report our business segments based on how management
currently evaluates our business. Management has segmented our business based
on differences in products and services, production processes and management
responsibility. We manage our electric utility business segments' performance
based on their earnings before interest and taxes (EBIT). EBIT does not
represent cash flow from operations as defined by generally accepted accounting
principles, should not be construed as an alternative to operating income and is
indicative neither of operating performance nor cash flows available to fund the
cash needs of our company. Items excluded from EBIT are significant components
in understanding and assessing the financial performance of our company. We
believe presentation of EBIT enhances an understanding of financial condition,
results of operations and cash flows because EBIT is used by our company to
satisfy its debt service obligations, capital expenditures, dividends 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.
Allocated sales are external sales collected from customers by our power
delivery segment that are allocated to our fossil generation and nuclear
generation business segments based on demand and energy cost. The following
discussion identifies key factors affecting our electric business segments.
Fossil Generation
1998 1997 1996
(Dollars in Thousands)
External sales. . . . . . . . . $525,974 $208,836 $144,056
Allocated sales . . . . . . . . 517,363 517,167 518,199
Depreciation and amortization . 53,132 53,831 52,303
EBIT. . . . . . . . . . . . . . 144,357 149,825 188,173
External sales increased over the last two years mostly because of
increased power marketing sales of $313 million in 1998 and $70 million in 1997.
In 1997, we made a strategic decision to expand our power marketing business to
better utilize our generating assets and reduce risk associated with energy
prices. We expanded into both the marketing of electricity and risk management
services to wholesale electric customers and the purchase of electricity for
our retail customers. Our margin from power marketing activities is
significantly less than our margins on our traditional electric sales. Our
power marketing activity has resulted in electric purchases and sales made in
areas outside of our historical marketing territory. Through December 31, 1998,
our power marketing activity has had an insignificant effect on EBIT.
The availability of our generating units and purchased power from other
companies impacts power marketing sales. In 1998, due to warmer than normal
weather throughout the Midwest and a lack of power available for purchase on the
wholesale market, the wholesale power market experienced extreme volatility in
prices and availability. We believe future volatility, such as that recently
experienced in the market, could impact our cost of power purchased and impact
our ability to participate in power trades.
EBIT for 1998 decreased from 1997 because we had higher purchased power
expense of $5 million due to a coal-fired generation station being unavailable
for the summer.
EBIT for 1997 decreased from 1996 due to higher cost of fuel and
purchased power expense discussed below, a $6 million expense of obsolete
inventory and other increased operating and maintenance expenses.
In 1997, actual cost of fossil fuel to generate electricity and the
amount of power purchased from other utilities were $14 million higher than in
1996. Our Wolf Creek nuclear generating station was off-line in the fourth
quarter of 1997 for scheduled maintenance and our La Cygne coal generation
station was off-line during 1997 for an extended maintenance outage. As a
result, we burned more natural gas to generate electricity at our facilities.
Natural gas is more costly to burn than coal and nuclear fuel for generating
electricity.
Railroad transportation limitations prevented scheduled fuel deliveries,
reducing our coal inventories. To compensate for a lack of coal, we purchased
more power from other utilities and burned more expensive natural gas to meet
our energy requirements. We also purchased more power from other utilities
because our Wolf Creek and La Cygne generating stations were not generating
electricity for parts of 1997.
Nuclear Generation
1998 1997 1996
(Dollars in Thousands)
Allocated sales . . . . . . . . $117,517 $102,330 $100,592
Depreciation and amortization . 39,583 65,902 57,242
EBIT. . . . . . . . . . . . . . (20,920) (60,968) (51,585)
Nuclear fuel generation has no external sales because it provides all of
its power to its co-owners KGE, KCPL and Kansas Electric Power Cooperative, Inc.
The amounts above are our 47% share of Wolf Creek's operating results.
Allocated sales and EBIT were higher in 1998 because Wolf Creek operated
the entire year without any outages. In 1997, the Wolf Creek facility was
off-line for 58 days for a scheduled maintenance outage.
Depreciation and amortization expense for 1998 compared to 1997
decreased $26 million because we had fully amortized a regulatory asset during
1997. This decrease in amortization expense increased EBIT for 1998.
Decommissioning: Decommissioning is a nuclear industry term for the
permanent shut-down of a nuclear power plant when the plant's license expires.
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 power plants to prepare formal financial
plans. These plans ensure that funds required for decommissioning will be
accumulated during the estimated remaining life of the related nuclear power
plant.
The Financial Accounting Standards Board is reviewing the accounting for
closure and removal costs, including decommissioning of nuclear power plants.
If current accounting practices for nuclear power plant decommissioning are
changed, the following could occur:
- Our annual decommissioning expense could be higher than in 1998
- The estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment in the
Wolf Creek plant
We do not believe that such changes, if required, would adversely affect
our operating results due to our current ability to recover decommissioning
costs through rates (see Note 10).
Power Delivery
1998 1997 1996
(Dollars in Thousands)
External sales. . . . . . . . . $1,085,711 $1,021,212 $1,053,359
Allocated sales . . . . . . . . 66,492 66,492 71,492
Depreciation and amortization . 68,297 63,590 60,713
EBIT. . . . . . . . . . . . . . 196,398 173,809 218,936
External sales and EBIT increased from 1997 to 1998. In addition to our
normal customer growth, we experienced warmer weather during the summer months
in 1998 than we did in 1997 which improved external sales approximately $42
million. The effect of our electric rate decrease lowered 1998 external sales
approximately $11 million.
External sales and EBIT decreased from 1996 to 1997 due to reduced
electric rates implemented February 1, 1997, which lowered revenues by an
estimated $46 million.
Monitored Services
1998 1997 1996
(Dollars in Thousands)
External sales. . . . . . . . . $421,095 $152,347 $8,546
Depreciation and amortization . 117,651 41,179 944
EBIT. . . . . . . . . . . . . . 56,727 (38,517) (3,555)
Restatement of 1997 Financial Statements: As a result of a decision by
Protection One to restate its 1997 financial statements, we have chosen to
restate our financial statements to conform to the changes reflected by
Protection One. We do not believe the restated operating results and financial
position are materially different from those which were reported in our December
31, 1997, Annual Report on Form 10K/A. See Note 2 to the consolidated financial
statements for further discussion of the restatement.
1998 compared to 1997: In 1998, Protection One operated and managed our
monitored services interests. The results discussed below reflect Protection
One on a stand-alone basis and do not take into consideration the minority
interest of about 15% at December 31, 1998. Results of operations for 1998
reflect adjustments made to restate quarterly earnings as discussed in Note 22
to the consolidated financial statements.
Monitored services business sales increased $269 million. The increase
is due to acquisitions and new customers purchased through Protection One's
Dealer Program. The Dealer Program consists of independent companies with
residential and small commercial sales, marketing and installation skills
provide Protection One with new monitoring customers for purchase on an ongoing
basis. Monthly recurring revenue represents the monthly fees paid by customers
for on-going monitored security service. At December 31, 1998, monthly
recurring revenue totaled about $38 million. Protection One added approximately
$17 million of monthly recurring revenue from acquisitions and approximately $5
million of monthly recurring revenue from its Dealer Program. Because
acquisitions and purchases from the Dealer Program occurred throughout the year,
not all of the $22 million of acquired monthly recurring revenue is reflected in
1998 results. Offsetting these revenue increases was Protection One's net
monthly recurring revenue attrition of 9%, a decrease from 13% in 1997 (see
further discussion below).
Cost of sales increased $93 million. Monitoring and related services
expenses increased by $71 million, or 217%, due to the acquisition of three
major service centers and three smaller satellite monitoring facilities in the
United States, as well as two service centers in Canada and two in Europe.
Monitoring and service activities at existing facilities increased as
well due to new customers generated by Protection One's Dealer Program.
Selling, general and administrative expenses rose $31 million. The
increase in expenses resulted primarily from acquisitions, offset by a decrease
in sales and related expenses. Selling, general and administrative expenses as
a percentage of total revenues declined from 56% in 1997 to 27% in 1998. The
transition of Protection One's primary distribution channel from an internal
sales force to the Dealer Program resulted in sales commissions declining by
approximately $9 million. Protection One also reduced advertising and
telemarketing activities that formerly supported the internal sales force.
Amortization of intangibles and depreciation expense totaled $118
million in 1998. Protection One recorded $582 million of customer intangibles
and $549 million in cost allocated to goodwill during 1998 from its purchases of
monitored services companies, portfolios of customer accounts and individual new
customers through its Dealer Program. Protection One amortizes customer
accounts over 10 years and goodwill over 40 years, in each case using a
straight-line method.
Like most monitored services companies, Protection One invests
significant amounts to generate new customers and seeks to maintain
relationships with its customers by providing excellent service. Protection One
measures the loss of customers and revenues to verify that investments in new
customers are generating a satisfactory rate of return and that the policy of
amortizing the cost to acquire customer accounts over 10 years is reasonable.
Protection One calculates both gross customer losses and net monthly recurring
revenue loss as meaningful statistics. If future losses were to increase
substantially, Protection One could be required to shorten the 10-year period
used to amortize the investment in new customers. The resulting increase in
amortization expense could be significant. In addition, the SEC staff is
reviewing Protection One's amortization methodology used on customer accounts.
The SEC staff has questioned the appropriateness of the current accounting
method which Protection One believes is consistent with industry practices. A
significant change in the amortization method would likely have a material
effect on the company's results of operations. The intangible amortization
represents a non-cash charge to income. The net balance of customer accounts at
December 31, 1998, was approximately $1 billion.
EBIT increased $95 million in 1998. Included in 1998 EBIT is a
non-recurring gain approximating $16 million on the repurchase of customer
contracts covered by a financing arrangement. A charge of approximately $24
million adversely affected 1997 EBIT. The charge was needed to recognize higher
than expected customer attrition and to record costs related to the acquisition
of Protection One.
1997 compared to 1996: Monitored services business sales increased $144
million from a minimal amount recorded in 1996. This increase is because of our
December 30, 1996, purchase of the net assets of Westinghouse Security Systems,
Inc. (Westinghouse Security Systems) and the acquisition on November 24, 1997,
of 82.4% of Protection One.
Other Operating Expenses
In 1998, we recorded a $99 million charge to income associated with our
decision to exit the international power project development business as
previously discussed in 1998 HIGHLIGHTS.
In 1997, we recorded a charge totaling $48 million to write-off the
original merger costs associated with the KCPL transaction. In addition,
Protection One recorded a charge of $24 million in 1997 as discussed above in
Monitored Services.
Other Income (Expense)
Other income (expense) includes miscellaneous income and expenses not
directly related to our operations.
1998 compared to 1997: Other income (expense) decreased $866 million due
to the following factors:
(Millions)
Other Income (Expense) in 1997 . . . . . . . . $ 922
1997
Non-recurring gain on the sale of our
TYCO common stock. . . . . . . . . . . . (864)
Investment earnings recorded on Hanover
and ADT investments. . . . . . . . . . . (33)
1998
Increase in earnings from the investment
in ONEOK . . . . . . . . . . . . . . . . 37
Recorded investment losses . . . . . . . . (22)
Non-recurring Protection One gains. . . . . 19
Increase in COLI death proceeds . . . . . . 13
Other miscellaneous . . . . . . . . . . . . (16)
Other income (expense) in 1998. . . . . . . $56
Interest Expense
1998 compared to 1997: Interest expense represents the interest we paid
on outstanding debt. Interest expense increased 17% due to higher long-term
debt. Our long-term debt balance increased $875 million due to our and
Protection One's issuance of new long-term debt used to reduce existing
short-term debt, to fund nonregulated operations and to finance a substantial
portion of Protection One's customer account growth. Lower short-term debt
interest expense partially offset the higher long-term debt interest expense.
Our short-term debt had a lower weighted average interest rate than the
long-term debt which replaced it.
1997 compared to 1996: We incurred $27 million more short-term debt
interest in 1997. Average short-term debt balances were higher in 1997 because
we used short-term debt to finance our investment in ADT Limited (which later
converted to Tyco) and to purchase the assets of Westinghouse Security Systems.
Short-term debt interest expense declined in the second half of 1997 after we
used the proceeds from the sale of Tyco common stock and a long-term debt
financing to reduce our short-term debt balance. From December 31, 1996, to
December 31, 1997, our short-term debt balance decreased $744 million. From
1996 to 1997, interest recorded on long-term debt increased $14 million, or 13%,
due to the issuance of $520 million in senior unsecured notes.
Income Taxes
1998 compared to 1997: Income tax expense declined significantly due to
the decline in taxable net income. In 1998, charges, primarily the charge to
income to exit the international power development business, significantly
lowered tax expense. Tax expense for 1997 included taxes related to the gain on
the sale of Tyco common stock.
Our effective tax rate also declined from 1997. This decline is largely
attributable to non-taxable proceeds from our corporate-owned life insurance
policies and the benefit of excluding 70% of ONEOK dividends received from the
determination of taxable income. Non-deductible goodwill amortization, state
income taxes, depreciation, and other adjustments to our tax provision partially
offset the tax benefits described above.
1997 compared to 1996: Income taxes on the gain from the sale of Tyco
common stock increased total income tax expense by approximately $345 million.
Preferred and Preference Dividends
On April 1, 1998, we redeemed the 7.58% preference stock due 2007. On
July 1, 1996, we redeemed all the 8.5% preference stock due 2016. These
redemptions have resulted in a significant decline in preferred and preference
dividends since 1996. In accordance with the terms of the KCPL merger
agreement, we will be required to redeem all of the remaining preferred stock
prior to the merger.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Most of our cash requirements consist of capital expenditures and
maintenance costs associated with the electric utility business, continued
growth in the monitored services business and payment 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
acquisitions with cash on hand, or the issuance of stock 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.
As of December 31, 1998, we had $16 million in cash and cash
equivalents. We consider highly liquid debt instruments purchased with a
maturity of three months or less to be cash equivalents. Other than operations,
our primary source of short-term cash is from short-term bank loans, unsecured
lines of credit and the sale of commercial paper. At December 31, 1998, we had
approximately $313 million of short-term debt outstanding, of which $148 million
was commercial paper and $165 million was bank loans. We have arrangements with
certain banks to provide unsecured short-term lines of credit on a committed
basis totaling approximately $821 million.
We have also registered securities for sale with the Securities and
Exchange Commission. As of December 31, 1998, these included $400 million of
unsecured senior notes, $50 million of KGE first mortgage bonds and
approximately 11 million Western Resources common shares.
Our embedded cost of long-term debt was 7.4% at December 31, 1998, a
drop of 0.1% from December 31, 1997.
Cash Flows from Operating Activities
Cash from operations increased significantly from 1997 because of two
factors. First, taxes paid of approximately $345 million on the gain on the
sale of Tyco common stock reduced 1997 operating cash flow. Secondly, 1998
includes the first full year
of Protection One operations. This increased operating cash flow from our
monitored services business by about $90 million from 1997.
Cash Flows from Investing Activities
During 1998, most of our cash used for investing purposes was to
continue the growth of our monitored services business. We used net cash of
about $827 million to expand this business through acquisitions, the Dealer
Program and installations. Protection One does not anticipate its 1999
expansion activity to be as significant as in 1998.
Capital expenditures totaled $183 million in 1998, slightly less than
1997 and 1996. We also purchased marketable securities and additional interests
in affordable housing tax credits.
In October 1998, Protection One announced an agreement to acquire
Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal
emergency response and support services in North America. Based on the average
closing price for the three trading days prior to April 8, 1999, the value of
the consideration to be paid under the merger agreement is approximately $129.2
million or $22.05 per Lifeline share in cash and stock. Lifeline has advised
Protection One that it is evaluating the restatement of Protection One's
financial statements. The consideration to be given in the Lifeline transaction
is by design variable and is subject to change within certain parameters until
the closing date. Interested parties should obtain the most recent
proxy/registration statement for further analysis of the transaction.
On January 25, 1999, Protection One's Board of Directors authorized a
private placement of common shares to Westar Capital, Inc., a wholly-owned
subsidiary of our company.
The private placement will allow us to maintain ownership in excess of
80% of Protection One's issued and outstanding common shares following the
issuance of Protection shares to Lifeline shareholders.
We may also acquire shares of Protection One common stock in open market
or privately negotiated transactions depending upon market conditions. Any open
market or private purchases will reduce or eliminate our need to purchase shares
in the private placement to maintain our ownership of at least 80%.
Cash Flows from Financing Activities
In July 1998, we issued $30 million of 6.8% Senior Notes due July 15,
2018. The notes are unsecured and unsubordinated obligations of the company.
In July 1998, we filed a shelf registration for $800 million in senior,
unsecured obligations of the company. In August 1998, we issued $400 million of
6.25% Putable/Callable Notes due on August 15, 2018, putable/callable on
August 15, 2003 under this shelf registration. Proceeds from these issuances
were used to reduce short-term debt incurred in connection with investments in
unregulated operations, the redemption of preferred securities and other general
corporate purposes.
On April 1, 1998, we redeemed our 7.58% Preference Stock due 2007 at a
premium, including dividends, for $53 million.
Financing activities provided Protection One with $744 million of cash.
Protection One raised $642 million through the following new debt instruments:
(Dollars in Millions)
August 17, 1998: Senior unsecured
7 3/8% notes due in 2005 . . . . . . . . . . . $250
December 16, 1998: Senior subordinated
8 1/8% notes due in 2009 . . . . . . . . . . . 350
December, 1998: Borrowings under a
revolving credit facility. . . . . . . . . . . 42
$642
In December 1998, Protection One obtained a revolving credit facility.
Protection One can borrow under this facility at a range of interest rates based
on either (1) the Prime Rate or (2) a Eurodollar Rate. At December 31, 1998 the
senior credit facility had a weighted average interest rate of 6.8% and had an
outstanding balance of $42 million. The facility matures in December 2001.
Among other restrictions, Protection One is required under the revolving
credit facility to maintain a ratio of earnings before interest, taxes,
depreciation and amortization (EBITDA) to interest expense of not less than 2.75
to one and total debt cannot be greater than 5 times annualized most recent
quarter EBITDA for 1999 and 4.5 times thereafter. In addition, in light of the
restatement of its financial statements, Protection One has obtained a bank
waiver for prior representations concerning its financial statements.
Protection One also raised $406 million in aggregate proceeds through
the sale of common stock. We paid approximately $357 million of the total
amount raised; therefore, the proceeds net of applicable fees obtained from the
sale of common stock approximated $46 million.
Protection One used proceeds from these financing transactions primarily
to fund acquisitions and Dealer Program growth. Protection One also repaid $512
million of existing debt, including a $395 million intercompany obligation with
us.
Capital Structure
Our capital structures at December 31, 1998, and 1997 were as follows:
1998 1997
Common stock . . . . . . . . . . . . . . . 37% 45%
Preferred and preference stock . . . . . . 1% 2%
Western Resources obligated
mandatorily redeemable preferred
securities of subsidiary trust holding
solely company subordinated debentures . 4% 5%
Long-term debt . . . . . . . . . . . . . . 58% 48%
Total. . . . . . . . . . . . . . . . . . . 100% 100%
Security Ratings
Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch)
and Moody's Investors Service (Moody's) are independent credit-rating agencies.
These agencies rate our debt securities. These ratings indicate the agencies'
assessment of
our ability to pay interest and principal on these securities. These ratings
affect how much we will have to pay as interest on securities we sell to obtain
additional capital. The better the rating, the less interest we will have to
pay on the new debt securities we sell.
At December 31, 1998, ratings with these agencies were as follows:
Kansas Gas
Western Western and Electric
Resources' Western Resources' Company's
Mortgage Resources' Short-term Mortgage
Bond Unsecured Debt Bond
Rating Agency Rating Debt Rating Rating
S&P A- BBB A-2 BBB+
Fitch A- BBB+ F-2 A-
Moody's A3 Baa1 P-2 A3
Following the announcement of our restructured merger agreement with
KCPL, S&P placed its ratings of Western Resources and KGE bonds on CreditWatch
with positive implications. Moody's changed the direction of its ongoing review
of Western Resources' debt rating from possible downgrade to possible upgrade.
Future Cash Requirements
We believe that internally generated funds and new and existing credit
agreements will be sufficient to meet our operating and capital expenditure
requirements, debt service and dividend payments through the year 2001.
Uncertainties affecting our ability to meet these requirements with internally
generated funds include the effect of competition and inflation on operating
expenses, sales volume, regulatory actions, compliance with future environmental
regulations, availability of earnings to pay dividends, the availability of
generating units and weather. The amount of these requirements and our ability
to fund them will also be significantly impacted by the pending combination of
our electric utility operations with KCPL.
In order to meet the needs of our electric utility customers, we plan to
install three new combustion turbine generators for use as peaking units. The
installed capacity of the three new generators will approximate 300 MW. The
first two units are scheduled to be placed in operation in 2000 and the third is
scheduled to be placed in operation in 2001. We estimate that the project will
require $120 million in capital resources through the completion of the projects
in 2001. In addition, we are planning to return our inactive generation plant
in Neosho, Kansas to active service in 1999 at an estimated cost of $0.7
million.
On January 4, 1999, we and the Empire District Electric Company (Empire)
signed a memorandum of understanding that provides for the joint ownership of a
500-megawatt combined cycle generating unit, which Empire will operate. We
estimate that the project will require $90 million in capital resources and we
will own 40% of the generating unit. Construction of the unit is expected to
begin in the fall of 1999 with operation beginning approximately 20 months
later.
Our business requires a significant capital investment. We currently
expect that through the year 2001, we will need cash mostly for:
- Ongoing utility construction and maintenance programs designed
to maintain and improve facilities providing electric service.
- Growth within the monitored services business,
including acquisition of customer accounts.
Capital expenditures for 1998 and anticipated capital expenditures for
1999 through 2001 are as follows:
Fossil Nuclear Power Monitored
Generation Generation Delivery Services Other Total
(Dollars in Thousands)
1998 . . $ 46,400 $25,800 $78,000 $859,500 $47,700 $1,057,400
1999 . . 117,900 19,700 90,800 434,400 20,700 683,500
2000 . . 149,900 32,200 79,700 355,100 2,300 619,200
2001 . . 109,100 21,200 78,600 373,700 200 582,800
Monitored services capital expenditures include anticipated acquisitions
and purchases of customer accounts. Other primarily represents our commitments
to our Affordable Housing Tax Credit (AHTC) program. See discussion in OTHER
INFORMATION below.
These estimates are prepared for planning purposes and may be revised
(see Note 10). Actual expenditures may differ from our estimates. Electric
expenditures shown in the table above do not take into account the pending
combination of our electric utility operations with KCPL (see Note 21).
Bond maturities will require cash of approximately $435 million through
the year 2003. Protection One is required to retire its $500 million revolving
credit facility in the year 2001. At December 31, 1998, $42 million was
outstanding under this facility.
Dividend Policy
Our currently authorized quarterly dividend for 1999 of 53 1/2 cents per
common share or $2.14 on an annual basis is paid from our earnings and remains
unchanged from 1998. Our board of directors reviews our dividend policy on an
annual basis. We expect the next review to be made in January 2000. Among the
factors typically considered in determining our dividend policy are earnings,
cash flows, capitalization ratios, competition and regulatory conditions. In
addition, we expect the board of directors in its next review to consider
various factors such as greater participation in our dividend reinvestment
program, our new compensation plan that pays senior management part of their
annual compensation in stock and our business profile upon completion of the
KCPL merger.
OTHER INFORMATION
Competition and Enhanced Business Opportunities
The United States electric utility industry is evolving from a regulated
monopolistic market to a competitive marketplace. The 1992 Energy Policy Act
began deregulating the electricity industry. 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. A wholesale
sale is defined as a
utility selling electricity to a "middleman", usually a city or its utility
company, to resell to the ultimate retail customer. As part of the 1992 KGE
merger, 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 to ourselves. During 1998,
wholesale electric sales represented approximately 12% of total electric sales,
excluding power marketing sales.
Various states have taken steps to allow retail customers to purchase
electric power from providers other than their local utility company. The Kansas
Legislature created a Retail Wheeling Task Force (the Task Force) in 1997 to
study the effects of a deregulated and competitive market for electric services.
Legislators, regulators, consumer advocates and representatives from the
electric industry made up the Task Force. Several bills were introduced to the
Kansas Legislature in the 1998 legislative session, but none passed. Hearings
on retail wheeling bills are being held in the 1999 legislature. The outcome
of retail wheeling legislation in Kansas remains uncertain.
We believe successful providers of energy in a deregulated market will
provide energy-related services. We believe consumers will demand innovative
options and insist on efficient products and services to meet their
energy-related needs. We believe that our strong core utility business provides
a platform to offer the efficient energy products and services that customers
will desire. We continue to seek new ways to add value to the lives and
businesses of our customers. We recognize that our current customer base must
expand beyond our existing service area.
Increased competition for retail electricity sales may reduce future
electric utility earnings compared to our historical electric utility earnings.
After all ordered electric rate decreases are implemented, our rates will range
from 73% to 90% of the national average for retail customers. Because of these
reduced rates, we expect to retain a substantial part of our current volume of
energy deliveries in a competitive environment.
While operating in this competitive environment may place pressure on
our profit margins, common dividends and credit ratings, we expect it to create
opportunities. Wholesale and industrial customers may pursue cogeneration,
self-generation, retail wheeling, municipalization or relocation to other
service territories in an attempt to cut their energy costs. Credit rating
agencies are applying more stringent guidelines when rating utility companies
due to increasing competition.
We offer competitive electric rates for industrial improvement projects
and economic development projects in an effort to maintain and increase electric
load.
To better position ourselves for the competitive energy environment, we
are pursuing a merger with KCPL, we have consummated a strategic alliance with
ONEOK (see Note 8) and we hold a controlling interest in Protection One
(see Note 4).
In light of competitive developments, we are pursuing the following
strategic plan:
- Maintain a strong core energy business.
- Seek out and pursue business lines that are compatible
with our investment criteria and growth strategies;
i.e., customer growth and monthly, recurring revenues.
- Promote cross-marketing strategies among our consumer
services businesses.
Year 2OOO Issue
We are currently addressing the effect of the Year 2000 Issue on
information systems and operations. We face the Year 2000 Issue because many
computer systems and applications abbreviate dates by eliminating the first two
digits of the year, assuming that these two digits are always "19". On January
1, 2000, some computer programs may incorrectly recognize the date as January 1,
1900. Some computer systems and applications may incorrectly process critical
information or may stop processing altogether because of the date abbreviation.
Calculations using dates beyond December 31, 1999, may affect computer
applications before January 1, 2000.
Electric Utility Operations: We have recognized the potential adverse
effects the Year 2000 Issue could have on our utility operations. In 1996, we
established a formal Year 2000 readiness program to investigate and correct
these problems in the main computer systems of our company. In 1997, we
expanded the program to include all business units and departments of our
utility operations, using a common methodology. The Year 2000 Issues concerning
the Wolf Creek nuclear operating plant are discussed below.
The goal of our Year 2000 readiness program is to identify and assess
all critical computer programs, computer hardware and embedded systems
potentially affected by the Year 2000 date change, to repair or replace those
systems found to be incompatible with Year 2000 dates, and to develop
predetermined actions to be used as contingencies in the event any critical
business function fails unexpectedly or is interrupted. The program is directed
by a written policy which provides the guidance and methodology to the
departments and business units to follow. Due to varying degrees of exposure
of departments and business units to the Year 2000 Issue, some departments and
business units are further along in their readiness efforts than others. All
departments have completed the awareness, inventory, and assessment phases, and
have developed their initial contingency plans. Most smaller departments and
business units have completed the assessment, remediation, and testing phases.
The majority of our current efforts are in the remediation and testing phases.
Overall, based on manhours as a measure of work effort, we believe we are
approximately 74% complete with our readiness efforts.
The estimated progress of our departments and business units, exclusive
of Protection One and Wolf Creek Nuclear Operating Corporation (WCNOC), at
December 31, 1998, based on manhours, is as follows:
Percentage
Department/Business Unit Completion
Fossil Fuel . . . . . . . . . . . . . . . 81%
Power Delivery . . . . . . . . . . . . . 73%
Information Technology. . . . . . . . . . 76%
Administrative. . . . . . . . . . . . . . 69%
Our Year 2000 readiness program addresses all Information Technology
(IT) and non-IT issues which may be impacted by the Year 2000 Issue. We have
included commercial computer software, including mainframe, client/server, and
desktop software; internally developed computer software, including mainframe,
client/server, and desktop software; computer hardware, including mainframe,
client/server, desktop, network, communications, and peripherals; devices using
embedded computer chips, including plant equipment, controls, sensors,
facilities equipment, heating, ventilating, and air
conditioning (HVAC) equipment; and relationships with third-party vendors,
suppliers, and customers. Our program requires testing as a method for
verifying the Year 2000 readiness of an item. For those items which are
impossible to test, other methods are being used to identify the readiness
status, provided adequate contingency plans are established to provide a
workaround or backup for the item. Our Year 2000 readiness efforts for
utility operations were substantially completed at the end of 1998 except for
those items scheduled for normal maintenance or upgrade during 1999.
We estimate that total costs to update all of our electric utility
operating systems for Year 2000 readiness, excluding costs associated with WCNOC
discussed below, to be approximately $6.5 million, of which $4.2 million
represents IT costs and $2.3 million represents non-IT costs. As of December
31, 1998, we have expended approximately $4.1 million of these costs, of which
$3.2 million represent IT costs and $0.9 million represent non-IT costs. Based
on what we know, we expect to incur the remaining $2.4 million, of which $1.0
million represents IT costs and $1.4 million represents non-IT costs, by the
end of 1999. These costs include labor costs for both company employees and
contract personnel used in our Year 2000 program, and non-labor costs for
software tools used in our remediation and testing efforts, replacement
software, replacement hardware, replacement embedded devices, and miscellaneous
costs associated with their testing and replacement.
We have identified the following major areas of risk relating to our
Year 2000 Issue exposure: 1) vendors and suppliers, 2) internal plant controls
and systems, 3) telecommunications, including phone systems and cellular phones,
4) large customers, and 5) rail transportation. We consider vendors and
suppliers a risk because of the lack of control we have over their operations.
We are in the process of contacting by letter each vendor or supplier critical
to our operations for information pertaining to their Year 2000 readiness. We
consider our plant controls and systems a risk due to the complexity, variety,
and extent of the embedded systems. We consider telecommunications a risk
because it performs a critical function in a large number of our business
processes and plant control functions. We consider large customers a risk
because of the influence their electrical usage patterns have on our electrical
generation and distribution systems. We consider rail transportation a risk
because of our dependence for delivery of coal used at our coal-fired generating
plants.
The most reasonably likely worst case scenario we anticipate is the loss
or partial interruption of local and long-distance telephone service, the
interruption or significant delay to rail service affecting the coal deliveries
to our generating plants, the unscheduled shut-down of the Wolf Creek nuclear
operating plant, the potential loss of load from one or more large customers,
and the loss of minimal generating capacity in the region for brief periods of
time. Approximately 62% of our generating capacity utilizes coal as fuel.
We are addressing these risks in our contingency plans, and have or will
be implementing a number of action plans in advance to mitigate these and other
potential risks. Our contingency plans include pre-established actions to deal
with potential operational impacts. For example, we have installed a
company-wide trunked radio system which can be used in place of the commercial
telecommunications systems, in the event those systems are interrupted. We plan
to place in service, at reduced output, generating units which would normally
not be in service to help accommodate load shifts that would be caused by a
large customer suddenly dropping or significantly reducing their electricity
usage, or in the event of unexpected loss of some of our generation capacity or
generation capacity of others in the region. In addition, we generally maintain
more than a 30-day supply of coal at each of our coal-fired generating plants,
reducing the effect of any temporary interruption of rail transportation and an
unscheduled temporary shut-down of the Wolf Creek nuclear operating plant
discussed below.
While all business units and departments have developed contingency
plans to cover essential business functions and anticipated possible Year
2000-related failure or interruption, these plans are continually reviewed and
updated based on information learned as our Year 2000 readiness efforts
proceed.
Wolf Creek Nuclear Operating Corporation: WCNOC has been evaluating and
adjusting all known date-sensitive systems and equipment for Year 2000
compliance. WCNOC is developing a plan to effect the readiness of the plant for
the coming of the Year 2000. This plan is designed to closely parallel the
guidance provided by the Nuclear Energy Institute and the NRC. WCNOC is
partnering with several industry groups to share information regarding
evaluating items that are Year 2000 sensitive. As applications and devices are
confirmed to be Year 2000 non-compliant, business decisions are being made to
repair or retire the item.
On May 11,1998 the NRC issued Generic Letter 98-01 entitled "Year 2000
Readiness of Computer Systems at Nuclear Power Plants." This letter expressed
the NRC's expectations with regard to Year 2000 readiness. The letter also
requires the licensee to file its Year 2000 plan and status report no later than
July 1, 1999.
WCNOC is developing contingency plans to address risk associated with
Year 2000 Issues. These plans generally follow the guidance contained in
NUCLEAR ENERGY INSTITUTE/NUCLEAR UTILITY SOFTWARE MANAGEMENT GROUP 98-07,
NUCLEAR UTILITY READINESS CONTINGENCY PLANNING. The steps to be taken involve
the determination of which items present a critical risk to the facility, review
of the identified risks, determining mitigation strategies, and ensuring that
each responsible organization develops appropriate contingency plans.
In order to assess the licensees progress in preparing for Year 2000,
the NRC scheduled audits at various nuclear power plant facilities during 1998
and early 1999. One of these audits was conducted at WCNOC during the month of
November 1998. The findings of this audit were as follows:
- The NEI/NUSMG 97-07 guidance is being followed. The Wolf Creek licensee
has not identified any systems needed for safe shutdown as having Year
2000 problems.
- Wolf Creek is making use of its existing quality assurance and
modification programs and procedures to achieve Year 2000 readiness.
Furthermore, Wolf Creek is engaged in extensive information sharing
and interfaces with other entities on Year 2000 Issues.
- The need for Year 2000 contingency planning is understood by the Wolf Creek
licensee and in keeping with the NEI/NUSMG 98-07 recommendation, one
individual has been designated as the single point of contact for
contingency planning.
- Wolf Creek is at the detailed assessment phase except for the items of
minimal significance designated as Limited Use Databases and
spreadsheets, which come under the category of Limited Use Hardware/
Software. Year 2000 readiness for Wolf Creek is scheduled for
September 15, 1999, and can be achieved based on the effort underway.
- Executive management support was found to be aggressive at Wolf Creek.
Management at Wolf Creek has dedicated the fiscal resources needed
for successful completion of the year 2000 readiness program.
Since Wolf Creek was designed during the 1970s and 1980s, most of the
originally installed electronic plant equipment did not contain microprocessors.
During this time frame, the NRC would not allow components required for safe
shutdown of the plant to contain microprocessors. For these reasons, there is
minimal Year 2000 risk associated with being able to safely shutdown the plant
and maintain it in a safe shutdown condition. During the years since original
construction, microprocessor based electronic components have been added in
non-safe shutdown applications. Some of these (only two identified thus far and
no others are anticipated) could shutdown the plant. Special attention will be
paid to these devices to ensure that there is minimal Year 2000 risk associated
with them.
In the original design and through plant modifications, microprocessor
based components were installed in plant monitoring applications such as the
radiation monitoring equipment and the plant information computer. Similarly,
in the area of non-plant operation computers and applications, WCNOC has several
items which will require remediation. There is a possibility that these devices
could cause a Year 2000 problem. Failure to adequately remediate any Year 2000
problems could require the plant's operations be limited or shutdown.
WCNOC estimates that the most reasonably likely worst case scenario
would be a temporary plant shutdown due to external electrical grid
disturbances. While these disturbances may result in a temporary shutdown, the
safety of the plant will not be compromised and the unit should restart shortly
after the grid disturbance has been corrected.
The table below sets forth estimates of the status of the components of
WCNOC's Year 2000 readiness program at December 31, 1998.
Estimated
Completion Percentage
Phase Date Completion
Identification and assessment of plant components Mar 99 89%
Identification and assessment of computers/software (Note 1) Jun 99 64%
Identification and Assessment of Other Areas (Note 2) Jun 99 47%
Identified remediations complete (Note 3) Sep 99 31%
Comprehensive testing guidelines 100%
Comprehensive testing (Note 4) Jun 99 13%
Contingency planning guidelines 100%
Contingency planning individual plans Mar 99 15%
Note 1 - Several computers are on three year lease and will not be obtained until 1999.
Note 2 - Includes items such as measuring/test and telecommunications equipment.
Note 3 - Two major modifications are currently scheduled to be completed after June 1999,
the remaining remediations are presently scheduled for completion prior to July 1999.
Note 4 - Several tests will not be performed until remediations are complete.
WCNOC has established a goal of completing all assessments of affected
systems by the end of the second quarter of 1999, with remediations being
completed by the end of the third quarter. Remediations are being planned and
initiated as the detailed assessment phase identifies the need, not at the end
of the assessment period. The areas where the greatest potential for necessary
remediations and/or more complex remediations could result were the first ones
targeted for assessment so remediation
planning could be started earlier. Many remediations will be completed before
the end of the assessment period. In addition, WCNOC is communicating with
others with which its systems interface or on which they rely with respect to
those companies' Year 2000 compliance. Letters have been sent to all pertinent
vendors to acquire this information.
WCNOC has estimated the costs to complete the Year 2000 project at $4.6
million ($2.1 million, our share). As of December 31, 1998, $1.4 million ($0.6
million, our share) had been spent on the project. A summary of the projected
costs to complete and actual costs incurred through December 31, 1998, is as
follows:
Projected Actual
Costs Costs
(Dollars in Thousands)
Wolf Creek Labor and Expenses. . $ 494 $ 261
Contractor Costs . . . . . . . . 646 493
Remediation Costs. . . . . . . . 3,493 611
Total. . . . . . . . . . . . . $4,633 $1,365
Approximately $3.5 million ($1.6 million, our share) of WCNOC's total
Year 2000 cost is associated with remediation. Of these remediation costs, $2.4
million ($1.1 million, our share) are associated with seven major jobs which are
in the initial stages. All of these costs are being expensed as they are
incurred and are being funded on a daily basis along with our normal costs of
operations. In order to minimize the effects of delaying other information
technology projects, WCNOC has and will continue to augment staffing during the
identification and remediation phases of the project. This staffing, which will
include both programmers and technical support personnel, will also be available
during the testing and initial operating phases of the various systems.
Monitored Services Operations: Protection One is reviewing its computer
programs, computer hardware and embedded systems critical to its businesses and
operational needs to identify and correct any components that could be affected
by the change of the date to January 1, 2000. Protection One will continue its
reviews until January 1, 2000, particularly with respect to the acquisition of
businesses that include additional computer systems and equipment. In addition,
changes in the date of compliance or preparedness within companies that provide
services or equipment to Protection One will require management to continue its
evaluations.
Protection One's Year 2000 readiness program addresses:
- Commercial computer software, including mainframe, client/service
and desktop software
- Internally developed computer software, including mainframe, client/
server and desktop software
- Computer hardware, including mainframe, client/server and desk top,
network, communications, and peripherals
- Devices using embedded computer chips, including controls, sensors,
facilities equipment, heating, ventilating and air conditioning
equipment
- Relationships with third-party vendors and suppliers
Based on the results of its on-going reviews, Protection One believes
that the Year 2000 Issue does not pose material operational problems. However,
the most reasonably likely worst case scenario is to be found in the area of
external services, specifically firms providing electrical power, heating,
ventilating and air conditioning, and local and long distance
telecommunications.
While Protection One believes the total collapse of service provided is
highly unlikely, one or more of the following scenarios could occur:
- Temporary disruption or unpredictable provision of nationwide long-
distance service
- Temporary or unpredictable provision of local telephone service, or
- Temporary interruption or unpredictable provision of electrical power.
To the extent customers did not receive timely and adequate responses to
alarms, Protection One would be required to rely on its specific disclaimer, in
most of its customers agreements of liability for the acts or omissions of third
party agencies. The enforcability of such disclaimers may be subject to
judicial scrutiny in jurisdictions in which Protection One operates.
Protection One estimates the total cost to update all critical operating
systems for Year 2000 readiness will be approximately $5 million. At December
31, 1998, approximately $1.1 million of these costs had been incurred. The
costs of the Year 2000 project and the date on which Protection One plans to
complete the Year 2000 modifications, estimated to be during 1999, is based on
the best estimates, which were derived utilizing numerous assumptions of future
events including the continued availability of certain resources, third party
modification plans and other factors. However, there can be no guarantee that
these estimates will be achieved and actual results could differ materially from
those plans. Specific factors that might cause such material differences
include, but are not limited to, the availability and cost of personnel trained
in this area, the ability to locate and correct all relevant computer codes, and
similar uncertainties.
Market Risk Disclosure
Market Price Risks: We are exposed to market risk, including changes in
commodity prices, equity and debt instrument investment prices and interest
rates.
Commodity Price Exposure: In our commodity price risk management
activities, we engage in both trading and non-trading activities. In these
activities, we utilize a variety of financial instruments, including forward
contracts involving cash settlements or physical delivery of an energy
commodity, options, swaps which require payments (or receipt of payments) from
counterparties based on the differential between specified prices for the
related commodity, and futures traded on electricity and natural gas.
We are involved in trading activities primarily to minimize risk from
market fluctuations, to maintain a market presence and to enhance system
reliability. Although we attempt to balance our physical and financial purchase
and sale contracts in terms of quantities and contract terms, net open positions
can 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 an open position, we are exposed to the risk that fluctuating market prices
may adversely impact our financial position or results from operations.
We manage and measure the exposure of our trading portfolio using a
variance/covariance value-at-risk (VAR) model, which simulates forward price
curves in the energy markets to estimate the size of future potential losses.
The quantification of market risk using VAR methodologies provides a consistent
measure of risk across diverse energy markets and products. The use of this
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. As of December 31, 1998, our VAR
(unaudited) for our trading activities was approximately $100,000. Our Risk
Oversight Committee sets the VAR limit. We employ additional risk control
mechanisms such as stress testing, daily loss limits, and commodity position
limits.
We have considered 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, product
location (basis) differentials and other risks which management policy dictates.
The counterparties in our portfolio consist primarily of large energy marketers
and major utility companies. The creditworthiness of our counterparties could
impact our overall exposure to credit risk, either positively or negatively.
However, we maintain credit policies with regard to our counterparties that in
our 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 cash market prices. Given the amount of
power purchased for utility operations during 1998, we would have had exposure
of approximately $5 million of operating income for a 10% increase in price per
MW of electricity. Based upon mmbtu's of natural gas and fuel oil burned during
1998, we had exposure of approximately $4 million of operating income for a 10%
change in average price paid per mmbtu. Quantities of natural gas and
electricity could vary dramatically year to year based on weather, unit outages
and nuclear refueling.
Investment Portfolio: We have approximately $288 million of equity and
debt securities as of December 31, 1998. We do not hedge these investments and
are exposed to the risk of changing market prices. We classify these securities
as "available for sale" for accounting purposes and mark them to market on the
balance sheet at the end of each period. However, net income is not affected
until the securities are sold. Management estimates that its investments will
generally be consistent with trends and movements of the overall stock market
barring any unusual situations. An immediate 10% change in the market price of
our equity securities would have a $13 million effect on other comprehensive
income. The value of the debt securities in our portfolio changes inversely
with fluctuations in interest rates.
Interest Rate Exposure: We have approximately $602 million of variable
rate debt, including current maturities of fixed rate debt, as of December 31,
1998. A 100 basis point change in each debt series benchmark rate would impact
net income on an annual basis by approximately $5 million.
Merger Agreement with Kansas City Power & Light Company
On February 7, 1997, we signed a merger agreement with KCPL by which
KCPL would be merged with and into the company in exchange for company stock.
In December 1997, representatives of our financial advisor indicated that they
believed it was unlikely that they would be in a position to issue a fairness
opinion required for the merger on the basis of the previously announced terms.
On March 18, 1998, we and KCPL agreed to a restructuring of our
February 7, 1997, merger agreement which will result in the formation of Westar
Energy, a new electric company. Under the terms of the merger agreement, our
electric utility operations will be transferred to KGE, and KCPL and KGE will be
merged into NKC, Inc., a subsidiary of the company. NKC, Inc. will be renamed
Westar Energy. In addition, under the terms of the merger agreement, KCPL
shareholders will receive company common stock which is subject to a collar
mechanism of not less than .449 nor greater than .722, provided the amount of
company common stock received may not exceed $30.00, and one share of Westar
Energy common stock per KCPL share. The Western Resources Index Price is the
20 day average of the high and low sale prices for company common stock on the
New York Stock Exchange ending ten days prior to closing. If the Western
Resources Index Price is less than or equal to $29.78 on the fifth day prior to
the effective date of the combination, either party may terminate the agreement.
Upon consummation of the combination, we will own approximately 80.1% of the
outstanding equity of Westar Energy and KCPL shareholders will own approximately
19.9%. As part of the combination, Westar Energy will assume all of the
electric utility related assets and liabilities of Western Resources, KCPL and
KGE.
Westar Energy will assume $2.7 billion in debt, consisting of $1.9
billion of indebtedness for borrowed money of Western Resources and KGE, and
$800 million of debt of KCPL. Long-term debt of the company, excluding
Protection One, was $2.5 billion at December 31,1998. Under the terms of the
merger agreement, it is intended that we will be released from our obligations
with respect to our debt to be assumed by Westar Energy.
Pursuant to the merger agreement, we have agreed, among other things, to
call for redemption all outstanding shares of our 4 1/2% Series Preferred Stock,
par value $100 per share, 4 1/4% Series Preferred Stock, par value $100 per
share, and 5% Series Preferred Stock, par value $100 per share.
Consummation of the merger is subject to customary conditions. On July
30, 1998, our shareholders and the shareholders of KCPL voted to approve the
amended merger agreement at special meetings of shareholders. We estimate the
transaction to close in 1999, subject to receipt of all necessary approvals from
regulatory and government agencies.
In testimony filed in February 1999, the KCC staff recommended the
merger be approved but with conditions which we believe would make the merger
uneconomical. The merger agreement allows us to terminate the agreement if
regulatory approvals are not acceptable. The KCC is under no obligation to
accept the KCC staff recommendation. In addition, legislation has been proposed
in Kansas that could impact the transaction. We do not anticipate the proposed
legislation to pass in its current form. We are not able to predict whether any
of these initiatives will be adopted or their impact on the transaction, which
could be material.
On August 7, 1998, we and KCPL filed an amended application with the
FERC to approve the Western Resources/KCPL merger and the formation of Westar
Energy.
We have received procedural schedule orders in Kansas and Missouri.
These schedules indicate hearing dates beginning May 3, 1999, in Kansas and July
26, 1999, in Missouri.
In February 1999, KCPL advised us that its Hawthorne generating station
(479 MW coal facility) suffered material damage to its boiler which could
prevent the unit's operation for an extended period. We are not able to
ascertain at this time the impact of this matter on the merger.
KCPL is a public utility company engaged in the generation,
transmission, distribution, and sale of electricity to customers in western
Missouri and eastern Kansas. We, KCPL and KGE have joint interests in certain
electric generating assets, including Wolf Creek. For additional information,
see Note 21. Following the closing of the combination, Westar Energy is expected
to have approximately one million electric utility customers in Kansas and
Missouri, approximately $8.2 billion in assets and the ability to generate
almost 8,800 megawatts of electricity.
At December 31, 1998, we had deferred approximately $14 million related
to the KCPL transaction. These costs will be included in the determination of
total consideration upon consummation of the transaction.
Affordable Housing Tax Credit Program
In 1997, we received authorization from the KCC to invest up to $114
million in AHTC investments. An example of an AHTC project is housing for
residents who are elderly or meet certain income requirements. At December 31,
1998, we had invested approximately $65 million to purchase limited partnership
interests. We are committed to investing approximately $25 million more in AHTC
investments by April 1, 2001. These investments are accounted for using the
equity method of accounting. Based upon an order received from the KCC, income
generated from the AHTC investments, primarily tax credits, will be used to
offset costs associated with postretirement and postemployment benefits offered
to our employees.
Pronouncements Issued but Not Yet Effective
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). This statement establishes
accounting and reporting standards requiring that every derivative instrument,
including certain derivative instruments embedded in other contracts, be
recorded in the balance sheet as either an asset or liability measured at its
fair value. SFAS 133 requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income statement, and
requires that a company must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting. SFAS 133 is
effective for fiscal years beginning after June 15, 1999. SFAS 133 cannot be
applied retroactively. SFAS 133 must be applied to (a) derivative instruments
and (b) certain derivative instruments embedded in hybrid contracts that were
issued, acquired, or substantively modified after December 31, 1997, and, at the
company's election, before January 1, 1998. The company will adopt SFAS 133 no
later than January 1, 2000.
Management is presently evaluating the impact that adoption of SFAS 133 will
have on the company's financial position and results of operations. Adoption of
SFAS 133, however, could increase volatility in earnings and other comprehensive
income.
In December 1998, the Emerging Issues Task Force reached consensus on
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (EITF Issue 98-10). EITF Issue 98-10 is effective for
fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires
energy trading contracts to be recorded at fair value on the balance sheet, with
the changes in the fair value included in earnings. The company will adopt EITF
Issue 98-10 during 1999. Management does not expect the impact of adopting EITF
Issue 98-10 to be material to the company's financial position or results of
operations.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to market risk disclosure is set forth in Other
Information of Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations included herein.