UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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, 19961997
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-3523
WESTERN RESOURCES, INC.
(Exact name of registrant as specified in its charter)
KANSAS 48-0290150
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
818 KANSAS AVENUE, TOPEKA, KANSAS 66612
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code 913/785/575-6300
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $5.00 par value New York Stock Exchange
(Title of each class) (Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, 4 1/2% Series, $100 par value
(Title of Class)
Indicated 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)
State the aggregate market value of the voting stock held by nonaffiliates of
the registrant. Approximately $1,897,474,000$2,816,701,029 of Common Stock and $11,398,000$13,882,108 of
Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which there
is no readily ascertainable market value) at March 18, 1996.16, 1997.
Indicate the number of shares outstanding of each of the registrant's classes of
common stock.
Common Stock, $5.00 par value 64,872,14665,409,603
(Class) (Outstanding at March 19, 1997)17, 1998)
Documents Incorporated by Reference:
Part Document
III Items 10-13 of the Company's Definitive Proxy Statement for
the Annual Meeting of Shareholders to be held May 29, 1997.12, 1998.
WESTERN RESOURCES, INC.
FORM 10-K
December 31, 19961997
TABLE OF CONTENTS
Description Page
PART I
Item 1. Business 3
Item 2. Properties 2120
Item 3. Legal Proceedings 2321
Item 4. Submission of Matters to a Vote of
Security Holders 2422
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 2422
Item 6. Selected Financial Data 2623
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 2724
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 37
Item 8. Financial Statements and Supplementary Data 3938
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 7568
PART III
Item 10. Directors and Executive Officers of the
Registrant 7568
Item 11. Executive Compensation 7568
Item 12. Security Ownership of Certain Beneficial
Owners and Management 7568
Item 13. Certain Relationships and Related Transactions 7568
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 7669
Signatures 8073
PART I
ITEM 1. BUSINESS
GENERAL
The company is a publicly traded holding company, incorporated in 1924. The
company's primary business activities are providing electric generation,
transmission and distribution services to approximately 614,000 customers in
Kansas; providing security alarm monitoring services to approximately 950,000
customers located throughout the United States, providing natural gas
transmission and distribution services to approximately 1.4 million customers in
Oklahoma and Kansas through its wholly-owned subsidiaries, includeownership of a 45% equity interest in ONEOK Inc.
(ONEOK) and investing in international power projects. Rate regulated electric
service is provided by KPL, a
rate-regulated electric and gas division of the company KGE, a
rate-regulated electric utility and wholly-owned subsidiary of the company,
Westar Security, Inc.Kansas Gas and
Electric Company (KGE), a wholly-owned subsidiary which provides monitored
electronic securitysubsidiary. Security services Westar Energy,are
provided by Protection One, Inc. (Protection One), a wholly-owned subsidiary
which provides non-regulated energy services, Westar Capital, Inc., a
wholly-owned subsidiary which holds equity investments in technology,
electronic monitored security and energy-related companies, The Wing Group
Ltd (The Wing Group), a wholly-owned developer of international power projects,
and Mid Continent Market Center, Inc. (Market Center), a regulated gas
transmission service provider.publicly-traded,
82.4%-owned subsidiary. KGE owns 47% of Wolf Creek Nuclear Operating
Corporation (WCNOC), the operating company for Wolf Creek Generating Station
(Wolf Creek). Corporate headquarters of the company is located at 818 Kansas
Avenue, Topeka, Kansas 66612. At December 31, 1996,1997, the company had 5,9602,412
employees.
The company is an investor-owned holding company. The company is engaged
principally in the production, purchase, transmission, distribution and sale
of electricity and the delivery and sale of natural gas. The company serves
approximately 606,000 electric customers in eastern and central Kansas and
approximately 650,000 natural gas customers in Kansas and northeastern
Oklahoma. The company's non-utility subsidiaries market natural gas primarily
to large commercial and industrial customers, provide electronic monitoring
security services, and provide other energy-related products and services.
On February 7, 1997, the company signed a merger agreement with Kansas City
Power & Light Company (KCPL) and the
company entered into an agreement wherebyby which KCPL would be merged with and into the
company.company in exchange for company stock. In December 1997, representatives of the
company's 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. The merger agreement provides for a tax-free, stock-for-stock
transaction valued at approximately $2 billion. Under the terms of the
agreement, KCPL shareowners will receive $32 of company common stock per KCPL
share, subject to an exchange ratio collar of not less than 0.917 and no more
than 1.100 common shares. Consummation of the KCPL Merger is
subject to
customary conditions including obtaining the approval of KCPL'scurrently being renegotiated and the company's shareowners and various regulatory agencies. See Note 2 of Notes to
Consolidated Financial Statements (Notes)approval process for more information regarding the
proposedoriginal merger with KCPL.agreement has been suspended.
On December 12, 1996, the company and ONEOK Inc. (ONEOK) announced an agreement to form
a strategic alliance combining the natural gas assets of both companies. UnderIn
November 1997, the agreement for the proposedcompany completed its strategic alliance thewith ONEOK. The
company will contributecontributed substantially all of its regulated and non-regulated natural
gas business to a new company (New ONEOK)ONEOK in exchange for a 45% ownership interest in ONEOK. The
company will account for its common ownership in accordance with the equity
interest. The recorded net property value being
contributed at December 31, 1996 is estimated at $600 million. No gain or
loss is expectedmethod of accounting. Subsequent to be recorded as a resultthe formation of the proposed transaction.strategic alliance,
the consolidated energy sales, related cost of sales and operating expenses for
the company's natural gas business were replaced by investment earnings in
ONEOK. The proposed transaction is subject to satisfaction of customary conditions,
including approval by ONEOK shareownersrelated assets and regulatory authorities. The
company is working towards consummation ofliabilities were removed from the transaction during the second
half ofConsolidated
Balance Sheets at November 30, 1997. See Note 6 for more information regarding this strategic
alliance.
During 1996, the company purchased approximately 38 millionacquired 27% of the common shares of ADT Limited,
Inc. (ADT) for approximately $589 million. The shares
purchased represent approximately 27% of ADT's common equity making the
company the largest shareowner of ADT. ADT's principal business is providing
electronic security services.
On December 18, 1996, the company announced its intention toand made an offer to exchange $22.50acquire the remaining ADT common shares. ADT
rejected this offer and in cash ($7.50)July 1997, ADT merged with Tyco International Ltd.
(Tyco). ADT and shares ($15.00) of the company'sTyco completed their merger by exchanging ADT common stock for
each outstandingTyco common share of ADT not already owned by the
company or its subsidiaries (ADT Offer). The value ofstock. Following the ADT Offer, assumingand Tyco merger, the company's average stock price prior to closing is above $29.75 per common
share, is approximately $3.5 billion, including the company's existingequity
investment in ADT. Following completionADT became an available-for-sale security. During the third
quarter of the ADT Offer, the company
presently intends to propose and seek to have ADT effect an amalgamation,
pursuant to which a newly created subsidiary of the company incorporated under
the laws of Bermuda will amalgamate with and into ADT (Amalgamation). Based
upon the closing stock price of the company on March 13, 1997, approximately
60.1 million shares of company common stock would be issuable pursuant to the
acquisition of ADT. However, the actual number of shares of company common
stock that would be issuable in connection with the ADT Offer and the
Amalgamation will depend on the exchange ratio and the number of shares
validly tendered prior to the expiration date of the ADT Offer and the number
of shares of ADT outstanding at the time the Amalgamation is completed.
On March 3, 1997, the company announced a change in the ADT Offer.
Under the terms of the revised ADT Offer, ADT shareowners would receive $10
cash plus 0.41494 of a share of companysold its Tyco common stockshares for each share of ADT
tendered not already owned by the company, based on the closing price of the
company's common stock on March 13, 1997. ADT shareowners would not,
however, receive more than 0.42017 shares of company common stock for each
ADT common share.
Concurrent with the announcement of the ADT Offer on December 18, 1996,
the company filed a registration statement on Form S-4 with the Securities and
Exchange Commission (SEC) related to the ADT Offer. On March 14, 1997, the
registration statement was declared effective by the SEC. The expiration date
of the ADT Offer is 5 p.m., EDT, April 15, 1997, and may be extended from time
to time by the company until the various conditions to the ADT Offer have been
satisfied or waived. The ADT Offer will be subject to the approval of ADT and
company shareowners.
On March 17, 1997, ADT announced that it had entered into a definitive
merger agreement pursuant to which Tyco International Ltd. (Tyco), a
diversified manufacturer of industrial and commercial products, would
effectively acquire ADT in a stock for stock transaction valued at $5.6
billion, or approximately $29 per ADT share of common stock.
On March 18, 1997, the company issued a press release indicating that
it had mailed the details of the ADT Offer to ADT shareowners and that it
would be reviewing the Tyco offer as well as considering its alternatives to
such offer and assessing its rights as an ADT shareowner. See Note 3 for more
information regarding this investment and the proposed ADT Offer.$1.5
billion.
On December 31, 1996, the company purchased the assets and assumed certain
liabilities comprising Westinghouse Security Systems, Inc. (WSS), a security
alarm monitoring company, for approximately $358 million. The net assets and
operations of WSS were contributed to Protection One in November, 1997 when the
company acquired its equity interest in Protection One.
In 1997 the company acquired three monitored security service provider with over 300,000 accounts in the United
States.alarm companies. The
company paid $358acquired Network Multi-Family Security Corporation (Network
Multi-Family) in September 1997 for approximately $171 million and acquired
Centennial Holdings, Inc. (Centennial) in cash, subject to adjustment. See
Note 4November 1997 for further information.
approximately $94
million. The company also acquired an approximate 82.4% equity interest in
Protection One, a publicly traded security alarm monitoring company, in November
1997. The company contributed all of its existing security business net assets,
other than Network Multi-Family, in exchange for its ownership interest in
Protection One.
In February 1998, Protection One exercised its option to acquire the stock
of Network Holdings, Inc., the parent company of Network Multi-Family, from the
company for approximately $178 million.
In March 1998, Protection One acquired the security alarm monitoring business
of Multimedia Security Services, Inc. (Multimedia Security) for approximately
$233 million. Multimedia Security has approximately 140,000 subscribers
concentrated primarily in California, Florida, Kansas, Oklahoma and Texas.
Protection One borrowed money from Westar Capital, a subsidiary of the company,
to complete this transaction.
In February 1996, the company purchased The Wing Group. See Note 4
for further information.Group Limited (The Wing
Group). The electric utility industry in the United StatesWing Group is rapidly evolving
from an historically regulated monopolistic market to a dynamic and
competitive integrated marketplace. The 1992 Energy Policy Act (Act) began
the processwholly-owned developer of deregulation of the electricity industry by permitting the
Federal Energy Regulatory Commission (FERC) to order electric utilities to
allow third parties to sell electricinternational power
to wholesale customers over their
transmission systems. Since that time, the wholesale electricity market has
become increasingly competitive as companies begin to engage in nationwide
power brokerage. In addition, various states including California and New
York have taken active steps toward allowing retail customers to purchase
electric power from third-party providers. In 1996, the Kansas Corporation
Commission (KCC) initiated a generic docket to study electric restructuring
issues. A retail wheeling task force has been created by the Kansas
Legislature to study competitive trends in retail electric services. During
the 1997 session of the Kansas Legislature, bills have been introduced to
increase competition in the electric industry. Among the matters under
consideration is the recovery by utilities of costs in excess of competitive
cost levels. There can be no assurance at this time that such costs will be
recoverable if open competition is initiated in the electric utility market.
For further discussion regarding competition and the potential impact
on the company, see Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations, Other Information, Competition and
Enhanced Business Opportunities.projects.
On July 1, 1995, the company established Midcontinent Market Center (Market
Center) which providesprovided natural gas transportation, storage, and gathering
services, as well as balancing and title transfer capability. The company
contributed certain natural gas transmission assets having a net book value of
approximately $50 million to the Market Center. The Market Center providesprovided no
notice natural gas transportation and storage services to the company under a
long-term contract. When the alliance with ONEOK is completed,The assets of the Market Center will bewere transferred to NewONEOK
in November 1997, upon the completion of the strategic alliance with ONEOK.
On January 31, 1994, the company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union) for $404 million. The company sold the remaining Missouri
properties to United Cities Gas Company (United Cities) for $665,000 on February
28, 1994. The properties sold to Southern Union and United Cities are referred
to herein as the "Missouri Properties." During the first quarter of 1994, the company recognized a gain of
approximately $19.3 million, net of tax, on the sales of the Missouri
Properties. As of the respective dates of the sales
of the Missouri Properties, the company ceased recording the results of
operations, and removed the assets and liabilities from the Consolidated Balance
Sheets related to the Missouri Properties.
The following table reflectsUnited States electric utility industry is evolving from a regulated
monopolistic market to a competitive marketplace. The 1992 Energy Policy Act
began deregulating the approximate operating revenues and
operating income included inelectricity industry. The Energy Policy Act permitted
the company's consolidated resultsFederal Energy Regulatory Commission (FERC) to order electric utilities to
allow third parties the use of operations
for the year ended December 31, 1994, relatedtheir 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 Missouri Properties:
1994
Percentultimate retail customer. As part of Total
Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. . . . . . . . . . $ 77,008 4.8%
Operating income. . . . . . . . . . . 4,997 1.9%
Separate audited financial information was not kept bythe 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.
For further discussion regarding competition and the potential impact on the
company, for
the Missouri Properties. This unaudited financial information is based on
assumptionssee Item 7. Management's Discussion and allocationsAnalysis of expensesFinancial Condition
and Results of the company as a whole.
On March 31, 1992, the company through its wholly-owned subsidiary KCA
Corporation (KCA) acquired all of the outstanding common and preferred stock
of Kansas Gas and Electric Company. Simultaneously, KCA and Kansas Gas and
Electric Company merged and adopted the name Kansas Gas and Electric Company
(KGE).
The following information includes the operations of KGE since March
31, 1992 and excludes the activities related to the Missouri Properties
following the sales of those properties in the first quarter of 1994.
The percentages of Total Operating Revenues and Operating Income Before
Income Taxes attributable to the company's electric and regulated natural gas
operations for the past five years were as follows:
Total Operating Income
Operating Revenues Before Income Taxes
Regulated Regulated
Year Electric Natural Gas Electric Natural Gas
1996 69% 31% 90% 10%
1995 73% 27% 98% 2%
1994 69% 31% 97% 3%
1993 58% 42% 85% 15%
1992 57% 43% 89% 11%
The difference between the percentage of electric operating revenues to
total operating revenues and the percentage of electric operating income to
total operating income as compared to the same percentages for regulated
natural gas operations is due to the company's level of investment in plant
and its fuel costs in each of these segments. The reduction in the
percentages for the regulated natural gas operations in 1994 is due to the
sales of the Missouri Properties.
The amount of the company's plant in service (net of accumulated
depreciation) at December 31, for each of the past five years was as follows:
Year Electric Natural Gas Total
(Dollars in Thousands)
1996 $3,669,662 $554,561 $4,224,223
1995 3,676,576 525,431 4,202,007
1994 3,676,347 496,753 4,173,100
1993 3,641,154 759,619 4,400,773
1992 3,645,364 696,036 4,341,400
Under the agreement for the proposed strategic alliance with ONEOK, the
company will contribute its natural gas business to New ONEOK in exchange for
a 45% equity interest. See Note 2 for further information.Operations.
ELECTRIC OPERATIONS
General
The company supplies electric energy at retail to approximately 606,000614,000
customers in 462 communities in Kansas. These include Wichita, Topeka,
Lawrence, Manhattan, Salina, and Hutchinson. The company also supplies electric
energy at wholesale to the electric distribution systems of 67 communities and 5
rural electric cooperatives. The company has contracts for the sale,
purchase or exchange of electricity with other utilities. The company also
receives a limited amount of electricity through parallel generation.
The company's electric sales for the last five years were as follows
(includes KGE since March 31, 1992):follows:
1997 1996 1995 1994 1993
1992
(Thousands of MWH)
ResidentialResidential. . . . 5,310 5,265 5,088 5,003 4,960
3,842
Commercial . . . . 5,803 5,667 5,453 5,368 5,100
4,473
Industrial . . . . 5,714 5,622 5,619 5,410 5,301
4,419
Wholesale and
InterchangeInterchange. . . 5,334 5,908 4,012 3,899 4,525
3,028
OtherOther. . . . . . . 107 105 108 106 103
91
TotalTotal. . . . . . 22,268 22,567 20,280 19,786 19,989 15,853
The company's electric revenues for the last five years were as follows
(includes KGE since March 31, 1992):follows:
1997(1) 1996 1995 1994 1993
1992
(Dollars in Thousands)
Residential $ 392,751 $ 403,588 $ 396,025 $ 388,271 $ 384,618
$296,917
Commercial 339,167 351,806 340,819 334,059 319,686
271,303
Industrial 254,076 262,989 268,947 265,838 261,898
211,593
Wholesale and
Interchange 142,506 143,380 104,992 106,243 118,401
98,183
Other 101,493 35,670 35,112 27,370 19,934
4,889
Total $1,229,993 $1,197,433 $1,145,895 $1,121,781 $1,104,537
$882,885(1) The increase in 1997 other electric revenues reflects power marketing
revenues. See Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations for further discussion of power
marketing.
Capacity
The aggregate net generating capacity of the company's system is presently
5,3125,319 megawatts (MW). The system comprises interests in 22 fossil fueled steam
generating units, one nuclear generating unit (47% interest), seven combustion
peaking turbines and two diesel generators located at eleven generating
stations. Two units of the 22 fossil fueled units (aggregating 100 MW of
capacity) have been "mothballed" for future use (See Item 2. Properties).
The company's 19961997 peak system net load occurred July 19, 199624, 1997 and amounted
to 3,9974,016 MW. The company's net generating capacity together with power
available from firm interchange and purchase contracts, provided a capacity
margin of approximately 18% above system peak responsibility at the time of the
peak.
The company and twelve companies in Kansas and western Missouri have agreed
to provide capacity (including margin), emergency and economy services for each
other. This arrangement is called the MOKAN Power Pool. The pool participants
also coordinate the planning of electric generating and transmission facilities.
The company is one of 6054 members of the Southwest Power Pool (SPP). SPP's
responsibility is to maintain system reliability on a regional basis. The
region encompasses areas within the eight states of Kansas, Missouri, Oklahoma,
New Mexico, Texas, Louisiana, Arkansas, and Mississippi.
In 1994, theThe company joinedis a member of the Western Systems Power Pool (WSPP). Under this
arrangement, over 156172 electric utilities and marketers throughout the western
United States have agreed to market energy and to provide transmission services.
WSPP's intent is to increase the efficiency of the interconnected power systems
operations over and above existing operations. Services available include
short-term and long-term economy energy transactions, unit commitment service,
firm capacity and energy sales, energy exchanges, and transmission service by
intermediate systems.
In January 1994, theThe company entered intohas an agreement with Oklahoma Municipal Power Authority (OMPA),
whereby, the company received a prepayment in 1994 of approximately $41 million
for capacity (42 MW) and transmission charges through the year 2013.
During 1994, KGE entered intohas an agreement with Midwest Energy, Inc. (MWE), whereby KGE will
provide MWE with peaking capacity of 61 MW through the year 2008. KGE also
entered into an agreement with Empire District Electric Company (Empire),
whereby KGE will provide Empire with peaking and base load capacity (20 MW in
1994 increasing to 80 MW in 2000) through the year 2000. In January 1995, theThe company entered intohas
another agreement with Empire, whereby the company will provide Empire with
peaking and base load capacity (10 MW in 1995 increasing to 162 MW in 2000)
through the year 2010.
Future Capacity
The company does not contemplate any significant expenditures in connection
with construction of any major generating facilities for the next five years.
(See Item 7. Management's Discussion and Analysis Liquidityof Financial Condition and
Capital Resources)Results of Operations).
Fuel Mix
The company's coal-fired units comprise 3,2953,311 MW of the total 5,3125,319 MW of
generating capacity and the company's nuclear unit provides 547 MW of capacity.
Of the remaining 1,4701,461 MW of generating capacity, units that can burn either
natural gas or oil account for 1,3861,377 MW, and the remaining units which burn only
diesel fuel account for 84 MW (See Item 2. Properties).
During 1996,1997, low sulfur coal was used to produce 81%78% of the company's
electricity. Nuclear produced 16%17% and the remainder was produced from natural
gas, oil, or diesel fuel. During 1997,1998, based on the company's estimate of the
availability of fuel, coal will be used to produce approximately 80%77% of the
company's electricity and nuclear will be used to produce approximately 16%18%.
The company's fuel mix fluctuates with the operation of nuclear powered Wolf
Creek which has an 18-month refueling and maintenance schedule. The 18-month
schedule permits uninterrupted operation every third calendar year. Wolf Creek
was taken off-line on February 3, 1996October 4, 1997 for its eighthninth refueling and maintenance
outage which lasted approximately 6058 days during which time electric demand was
met primarily by the company's coal-fired generating units.
Nuclear
The owners of Wolf Creek have on hand or under contract 70%100% of their uranium
needs for 1998 and 59% of the uranium requirements for operation ofrequired to operate Wolf Creek through
the yearSeptember 2003. The balance is expected to be obtained through spot market and
contract purchases. The company has fourthree active contracts with the following
companies for uranium: Cameco Corporation, Geomex Minerals, Inc., and Power
Resources, Inc.
A contractual arrangement is in place with Cameco Corporation for the
conversion of uranium to uranium hexafluoride sufficient for the operation of
Wolf Creek through the year 2001.
The company has two active contracts for uranium enrichment performed by
Urenco and USEC. Contracted arrangements cover 82%80% of Wolf Creek's uranium
enrichment requirements for operation of Wolf Creek through March 2005. The
balance is expected to be obtained through spot market and term contract
purchases.
The company has entered into all of its uranium, uranium hexaflouride and
uranium enrichment arrangements during the ordinary course of business and is
not substantially dependent upon these agreements. The company believes there
are other suppliers available at reasonable prices to replace, if necessary,
these contracts. In the event that the company were required to replace these
contracts, it would not anticipate a substantial disruption of its business.
TheNuclear fuel is amortized to cost of sales based on the quantity of heat
produced for the generation of electricity. Under the Nuclear Waste Policy Act
of 1982, established schedules, guidelines
and responsibilities for the Department of Energy (DOE) to develop and construct
repositoriesis responsible for the ultimatepermanent
disposal of spent nuclear fuel. The company pays the DOE a quarterly fee of
one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered
and sold for future disposal of spent nuclear fuel. These disposal costs are
charged to cost of sales and currently recovered through rates.
In 1996, a U.S. Court of Appeals issued a decision that the Nuclear Waste
Act unconditionally obligated the DOE to begin accepting spent fuel for disposal
in 1998. In late 1997, the same court issued another decision precluding 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. By the end of 1997, KGE and high-level waste.
Theother utilities had petitioned
the DOE has not yet constructed a high-level wastefor authority to suspend payments of their quarterly fees until such
time as the DOE begins accepting spent fuel. In January 1998, the DOE denied
the petition of the utilities.
A permanent disposal site and has
announced that a permanent storage facility may not be in operation prior toavailable for the industry until 2010
or later, although an interim storage facility may be available earlier. 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 contains anmay
not be available prior to 2016. Wolf Creek has on-site temporary storage for
spent nuclear fuel. Under current regulatory guidelines, this facility can
provide storage space until about 2005. Wolf Creek has started plans to
increase its on-site spent fuel storage facility which, under current
regulatory guidelines, provides spacecapacity. That project, expected to be
completed by 2000, should provide storage capacity for the storage ofall spent fuel expected
to be generated by Wolf Creek through 2005 while still maintaining full core off-load capability.the end of its licensed life in 2025.
The companyLow-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 and selected a site in northern Nebraska to
locate a disposal facility. The present estimate of the cost for such a
facility is currently investigating spent fuel storage options which should provide enough
additional storage spaceabout $154 million. WCNOC and the owners of the other five nuclear
units in the compact have provided most of the pre-construction financing for
this project.
There is uncertainty as to whether this project will be completed.
Significant opposition to the project has been raised by Nebraska officials and
residents in the area of the proposed facility, and attempts have been made
through at least 2020 while still maintaining full
core off-load capability. The company believes adequate additional storage
space can be obtained as necessary.litigation and proposed legislation in Nebraska to slow down or stop
development of the facility.
Additional information with respect to insurance coverage applicable to the
operations of the company's nuclear generating facility is set forth in Note 87
of the Notes to Consolidated Financial Statements.
Coal
The three coal-fired units at Jeffrey Energy Center (JEC) have an aggregate
capacity of 1,8241,839 MW (company's 84% share) (See Item 2. Properties). The
company has a long-term coal supply contract with Amax Coal West, Inc. (AMAX), a
subsidiary of Cyprus Amax Coal Company, to supply low sulfur coal to JEC from
AMAX's Eagle Butte Mine or an alternate mine source of AMAX's Belle Ayr Mine,
both located in the Powder River Basin in Campbell County, Wyoming. The
contract expires December 31, 2020. The contract contains a schedule of minimum
annual delivery quantities based on MMBtu provisions. The coal to be supplied
is surface mined and has an average Btu content of approximately 8,300 Btu per
pound and an average sulfur content of .43 lbs/MMBtu (See Environmental
Matters). The average delivered cost of coal for JEC was approximately $1.10$1.13
per MMBtu or $18.70$18.92 per ton during 1996.1997.
Coal is transported from Wyoming under a long-term rail transportation
contract with Burlington Northern (BN)Santa Fe (BNSF) and Union Pacific (UP)
railroads to JEC through December 31, 2013. Rates are based on net load
carrying capabilities of each rail car. The company provides 868 aluminum rail
cars, under a 20 year lease, to transport coal to JEC.
The two coal-fired units at La Cygne Station have an aggregate generating
capacity of 678677 MW (KGE's 50% share) (See Item 2. Properties). The operator,
KCPL, maintains coal contracts as summarized in the following paragraphs.
La Cygne 1 uses low sulfur Powder River Basin coal which is supplied under
a variety of spot market transactions, discussed below. High Btu Kansas/Missouri
coal is blended with the Powder River Basin coal and is secured from time to
time under spot market arrangements. La Cygne 1 uses a blended fuel mix
containing approximately 85% Powder River Basin coal.
La Cygne 2 and additional La Cygne 1 Powder River Basin coal is supplied
through several contracts, expiring at various times through 1999. This low
sulfur coal had an average Btu content of approximately 8,500 Btu per pound and
a maximum sulfur content of .50 lbs/MMBtu (See Environmental Matters).
Transportation is covered by KCPL through its Omnibus Rail Transportation
Agreement with BNBNSF and Kansas City Southern Railroad (KCS) through December 31, 2000.
During 1996,1997, the average delivered cost of all local and Powder River Basin
coal procured for La Cygne 1 was approximately $0.64$0.70 per MMBtu or $13.47$12.31 per ton
and the average delivered cost of Powder River Basin coal for La Cygne 2 was
approximately $0.68$0.67 per MMBtu or $11.49$11.32 per ton.
The coal-fired units located at the Tecumseh and Lawrence Energy Centers have
an aggregate generating capacity of 793795 MW (See Item 2. Properties). The
company contracted with Cyprus Amax Coal Company's Foidel Creek Mine located in
Routt County, Colorado for low sulfur coal through December 31, 1998. This
coal is transported by SouthernUnion Pacific Lines and Atchison, Topeka and Santa Fe Railway CompanyBNSF railroads under a contractcontracts
expiring December 31, 1998. The company anticipates that the Cyprus agreement
will supply the minimum requirements of the Tecumseh and Lawrence Energy Centers
and supplemental coal requirements will continue to be supplied from coal
markets in Montana, Wyoming, Utah, Colorado and/or New Mexico. The company is
currently seeking coal supply through 2000 to replace the expiring Cyprus coal
agreement. Additional spot market coal for 19971998 has been secured from COLOWYOKennecott
Coal Company on a delivered
basis.with rail transportation supplied by BNSF railroad. During 1996,1997,
the average delivered cost of coal for the Lawrence units was approximately
$1.19$1.24 per MMBtu or $26.91$26.89 per ton and the average delivered cost of coal for the
Tecumseh units was approximately $1.21$1.24 per MMBtu or $27.11$26.76 per ton. The coal
supplied from Cyprus hasin 1997 had an average Btu content of approximately 11,20010,842 Btu per
pound and an average sulfur content of .47.42 lbs/MMBtu (See Environmental
Matters).
The company has entered into all of its coal and transportation contracts during the ordinary
course of business and is not substantially dependent upon these contracts. The
company believes there are other suppliers for and plentiful sources of coal
available at reasonable prices to replace, if necessary, fuel to be supplied
pursuant to these contracts. In the event that the company were required to
replace its coal or transportation agreements, it would not anticipate a substantial disruption of
the company's business.
The company has entered into all of its transportation contracts during the
ordinary course of business. At the time of entering into these contracts, the
company was not substantially dependent upon these contracts due to the
availability of competitive rail options. Due to recent rail consolidation,
there are now only two rail carriers capable of serving the company's origin
coal mines and its generating stations. In the event one of these carriers
became unable to provide reliable service, the company could experience a
short-term disruption of its business. However, due to the obligation of the
remaining carriers to provide service under the Interstate Commerce Act, the
company does not anticipate any substantial long-term disruption of its
business. See also Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Natural Gas
The company uses natural gas as a primary fuel in its Gordon Evans, Murray
Gill, Abilene, and Hutchinson Energy Centers and in the gas turbine units at its
Tecumseh generating station. Natural gas is also used as a supplemental fuel in
the coal-fired units at the Lawrence and Tecumseh generating stations. Natural
gas for Gordon Evans and Murray Gill Energy
Centersall facilities is supplied by readily available gas from the spot market.
Short-termshort-term
economical spot market purchasesand will supply the system with the flexible natural gas
supply to meet operational needs for the Gordon Evans
and Murray Gill Energy Centers. Natural gas for the company's Abilene and
Hutchinson stations is supplied from the company's main system (See Natural
Gas Operations).needs.
Oil
The company uses oil as an alternate fuel when economical or when
interruptions to natural gas make it necessary. Oil is also used as a
supplemental fuel at JEC and La Cygne generating stations. All oil burned by
the company during the past several years has been obtained by spot market
purchases. At December 31, 1996,1997, the company had approximately 3 million
gallons of No. 2 oil and 1317 million gallons of No. 6 oil which is believedit believes to be
sufficient to meet emergency requirements and protect against lack of
availability of natural gas and/or the loss of a large generating unit.
Other Fuel Matters
The company's contracts to supply fuel for its coal 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, when the price is favorable, to
take advantage of economic opportunities.
Set forth in the table below is information relating to the weighted average
cost of fuel used by the company.
KPL Plants 1997 1996 1995 1994 1993
1992
Per Million Btu:
Coal . . . . . . . . $1.17 $1.14 $1.15 $1.13 $1.13
$1.30
GasGas. . . . . . . . . 2.88 2.50 1.63 2.66 2.71
2.15
OilOil. . . . . . . . . 3.72 4.01 4.34 4.27 4.41
4.19
Cents per KWH Generation . 1.32 1.30 1.31 1.32 1.31
1.49
KGE Plants 1997 1996 1995 1994 1993
1992
Per Million Btu:
NuclearNuclear. . . . . . . $0.51 $0.50 $0.40 $0.36 $0.35
$0.34
Coal . . . . . . . . 0.89 0.88 0.91 0.90 0.96
1.25
GasGas. . . . . . . . . 2.56 2.30 1.68 1.98 2.37
1.95
OilOil. . . . . . . . . 3.32 2.74 4.00 3.90 3.15
4.28
Cents per KWH Generation . 1.00 0.93 0.82 0.89 0.93 0.98
Environmental Matters
The company currently holds all Federal and State environmental approvals
required for the operation of its generating units. The company believes it is
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 Federal sulfur dioxide standards, applicable to the company's JEC and
La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur
dioxide per million Btu of heat input. Federal particulate matter emission
standards applicable to these units prohibit: (1) the emission of more than
0.1 pounds of particulate matter per million Btu of heat input and (2) an
opacity greater than 20%. Federal NOx emission standards applicable to these
units prohibit the emission of more than 0.7 pounds of NOx per million Btu of
heat input.
The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards
through the use of low sulfur coal (See Coal); (2) the particulate matter
standards through the use of electrostatic precipitators; and (3) the 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 the company's other generating facilities, prohibit the emission
of more than 2.5 pounds of sulfur dioxide per million Btu of heat input at two
of the company's Lawrence generating units and 3.0 pounds at all other
generating units. There is sufficient low sulfur coal under contract (See Coal)
to allow compliance with such limits at Lawrence, Tecumseh and La Cygne 1 for
the life of the contracts. All facilities burning coal are equipped with flue
gas scrubbers and/or electrostatic precipitators.
The company must comply with the provisions of The Clean Air Act Amendments
of 1990 (the Act)that require a two-phase reduction in sulfur dioxide and NOx emissions with Phase I effective in 1995
and Phase II effective in 2000 and a probable reduction in toxic emissions by
a future date yet to be determined. To meet the monitoring and reporting
requirements under the Act's acid rain program, thecertain emissions. The company
has installed continuous monitoring and reporting equipment at a total cost of approximately
$10 million as of December 31, 1996.to meet the acid
rain requirements. The company does not expect material capital expenditures to
be neededrequired to meet Phase II sulfur dioxide requirements.
Although the company currently has no Phase I affected units, the company has
applied for and has been accepted for an early substitution permit to bring
the co-owned La Cygne Unit 1 under the Phase I regulations.
The NOx and toxic limits, which were not set in the law, were
proposed by the EPA in January 1996. The company is currently evaluating the
steps it will need to take in order to comply with the proposed new rules.
The company will have three years from the date the limits were proposed to
comply with the new NOx rules.nitrogen oxide requirements.
All of the company's 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 87 of the Notes to Consolidated Financial Statements included herein.
NATURAL GAS OPERATIONS
General
Under the agreement for the proposed strategic alliance with ONEOK, the company
will contributecontributed substantially all of its natural gas business to New ONEOK on November
30, 1997, in exchange for a 45% equity interest. See Note 24 of the Notes to the
Consolidated Financial Statements for further information.
ONEOK is a diversified energy company engaged in the production, gathering,
storage, transportation, distribution and marketing of natural gas and natural
gas products. ONEOK's regulated business operations provides natural gas
distribution and transmission in Oklahoma and Kansas. ONEOK's nonregulated
business operations include natural gas marketing, gas processing and
production.
The company's natural gas operations areprior to November 30, 1997, were
comprised primarily of the following four components: a local natural gas
distribution division which iswas subject to rate-regulation; Market Center, a
Kansas subsidiary of the company that engagesengaged primarily in intrastate gas
transmission, as well as gas wheeling, parking, balancing and storage services,
and iswas also subject to rate-regulation; Westar Gas Marketing, Inc., (Westar Gas
Marketing) a Kansas non-regulated indirect subsidiary of the company that engageswas
engaged primarily in marketing and selling natural gas to small and medium-sized
commercial and industrial customers; and Westar Gas Company, a Delaware
non-regulated subsidiary of Westar Gas Marketing that engageswas engaged in extracting,
processing and selling natural gas liquids.
At December 31, 1996,During, 1997, the company supplied natural gas at retail to approximately
650,000652,000 customers in 362 communities and at wholesale to eight communities and
two utilities in Kansas and Oklahoma. The natural gas systems of the company
consistconsisted of distribution systems in both states purchasing natural gas from
various suppliers and transported by interstate pipeline companies and the main
system, an integrated storage, gathering, transmission and distribution system.
The company also transportstransported gas for its large commercial and industrial
customers which purchasepurchased gas on the spot market. The company earnsearned
approximately the same margin on the volume of gas transported as on volumes
sold except where discounting occursoccurred in order to retain the customer's load.
As discussed under General, above, onOn January 31, 1994, the company sold substantially all of its Missouri
natural gas distribution properties and operations to Southern Union and sold
the remaining Missouri Properties to United Cities on February 28, 1994.
Additional information with respect to
the impact of the sales of the Missouri Properties is set forth in Note 19 of
the Notes to Consolidated Financial Statements.
The percentage of total natural gas deliveries, including transportation and
operating revenues for 1996,1997 (through November 30, 1997), by state were as
follows:
Total Natural Total Natural Gas
Gas Deliveries Operating Revenues
Kansas 96.6% 95.7%96.8% 95.2%
Oklahoma 3.4% 4.3%
3.2% 4.8%
The company's natural gas deliveries for the last five years were as follows:
1997(1) 1996 1995 1994(2)1994(3) 1993 1992
(Thousands of MCF)
Residential 47,602 62,728 55,810 64,804 110,045
93,779
Commercial 16,968 22,841 21,245 26,526 47,536
40,556
Industrial 296 450 548 605 1,490
2,214
Other 26,448 21,067 17,078(1)17,078(2) 43 41
94
Transportation 41,635 45,947 48,292 51,059 73,574
68,425
Total 132,949 153,033 142,973 143,037 232,686 205,068
The company's natural gas revenues related to deliveries for the last five
years were as follows:
1997(1) 1996 1995 1994(2)1994(3) 1993 1992
(Dollars in Thousands)
Residential $312,665 $352,905 $274,550 $332,348 $529,260
$440,239
Commercial 100,394 120,927 94,349 125,570 209,344
169,470
Industrial 1,632 2,885 3,051 3,472 7,294
7,804
Other 63,608 48,643 31,860 11,544 30,143
27,457
Transportation 22,552 23,354 22,366 23,228 28,781
28,393
Total $500,851 $548,714 $426,176 $496,162 $804,822
$673,363
(1) The decrease in gas deliveries and revenues reflects the contribution
of the company's natural gas business to ONEOK on November 30, 1997.
(2) The increase in other gas salesdeliveries reflects an increase in
as-available gas sales.
(2)(3) Information reflects the sales of the Missouri Properties effective
January 31, and February 28, 1994.
As-available gas is excess natural gas under contract that the company did
not require for customer sales or storage that is typically sold to gas
marketers. According to the company's tariff, the nominal margin made on
as-available gas sales is returned 75% to customers through the cost of gas
rider and 25% is reflected in wholesale revenues of the company.
In compliance with orders of the state commissions applicable to all
natural gas utilities, the company has established priority categories for
service to its natural gas customers. The highest priority is for residential
and small commercial customers and the lowest for large industrial customers.
Natural gas delivered by the company from its main system for use as fuel for
electric generation is classified in the lowest priority category.
Interstate System
The company distributesdistributed natural gas at retail to approximately 520,000
customers located in central and eastern Kansas and northeastern Oklahoma. The
largest cities served in 19961997 were Wichita and Topeka, Kansas and Bartlesville,
Oklahoma. The company hashad transportation agreements for delivery of this gas
which havewith terms varying in length from one to twenty years, with the following
non-affiliated pipeline transmission companies: Williams Natural Gas CompanyPipelines
Central (WNG), Kansas Pipeline CompanyPartnership (KPP), Panhandle Eastern Pipeline
Company (Panhandle), and various other intrastate suppliers. The volumes
transported under these agreements in 1996 and 1995for the past three years were as follows:
Transportation Volumes (BCF's)
1997(1) 1996 1995
WNGWNG. . . . . . . 74.1 79.4 61.8
KPPKPP. . . . . . . 5.2 7.3 7.1
PanhandlePanhandle. . . . 1.1 1.2 1.0
Others . . . . . 0.8 2.1 8.0
(1) Information reflects the contribution of the company's natural gas
business to ONEOK on November 30, 1997.
The company purchasespurchased this gas from various producers and marketers under
contracts expiring at various times. The company purchased approximately 78.471.5
BCF or 91.9%88.1% of its natural gas supply from these sources in 19961997 and 61.778.4 BCF
or 79.3%91.9% during 1995. Approximately 85.3 BCF of natural gas is made
available annually under these contracts which extend for various terms
through the year 2005.1996.
In October 1994, the company executed a long-term gas purchase contract (Base
Contract) and a peaking supply contract with Amoco Production Company for the
purpose of meeting at least 50% of the requirements of the customers served from
the company's interstate system over the WNG pipeline system.
The company anticipates that the Base Contract will supply between 50% and 65% of the
company's demand served by the WNG pipeline system. Amoco is one of various
suppliers over the WNG pipeline system and if this contract were canceled, the
company could replace gas supplied by Amoco with gas from other suppliers.
Gas available under the Amoco contract is also available for sale by the
company to other parties and sales are recorded as wholesale revenues of the
company.
The company also purchasespurchased natural gas from KPP under contracts expiring at
various times. These purchases were approximately 5.23.3 BCF or 5.8%4.1% of its
natural gas supply in 19961997 and 5.35.2 BCF or 6.7%5.8% during 1995.1996. The company
purchasespurchased natural gas for the interstate system from intrastate pipelines and
from spot market suppliers under short-term contracts. These sources totaled
5.6 BCF and 0.6 BCF for 1997 and 3.6 BCF for 1996 representing 6.8% and 1995 representing 0.7% and
4.6% of the system
requirements, respectively.
During 1997 and 1996, and 1995, approximately 1.50.8 BCF and 7.31.5 BCF, respectively, were
transferred from the company's main system to serve a portion of the demand for
the interstate system representing 1.6%1.0% and 9.4%1.6%, respectively, of the
interstate system supply.
The average wholesale cost per thousand cubic feet (MCF) purchased for the
distribution systems for the past five years waswere as follows:
Interstate Pipeline Supply
(Average Cost per MCF)
1997 1996 1995 1994 1993
1992
WNG . . . . . . . . . $ - $ - $ - $ - $3.57
$3.64
Other . . . . . . . . 3.65 3.09 2.78 3.32 3.01
2.30
Total Average CostCost. . 3.65 3.09 2.78 3.32 3.23
2.88
Main System
TheDuring 1997, the company servesserved approximately 130,000 customers in central
and north central Kansas with natural gas supplied through the main system. The
principal market areas include Salina, Manhattan, Junction City, Great Bend,
McPherson and Hutchinson, Kansas.
Natural gas for the company's main system iswas purchased from a combination
of direct wellhead production, from the outlet of natural gas processing plants, and
from natural gas marketers and production companies. Such purchases arewere transported
entirely through company ownedcompany-owned transmission lines in Kansas.
Natural gas purchased for the company's main system customer requirements iswas
transported and/or stored by the Market Center. The company retainsretained a priority
right to capacity on the Market Center necessary to serve the main system
customers. The company hashad the opportunity to negotiate for the purchase of
natural gas with producers or marketers utilizing Market Center services, which
increasesincreased the potential supply available to meet main system customer demands.
During 1996, the
The company purchased approximately 4.4 BCF and 7.6 BCF of natural gas during
1997 and 1996, respectively, through the spot market which allowed the company to avoid minimum take
requirements associated with long-term contracts. This purchase representsmarket. These purchases
represented approximately 35.2% and 45.5% of the company's main system
requirements during 1996.1997 and 1996, respectively.
Spivey-Grabs field in south-central Kansas supplied approximately 4.23.9 BCF of
natural gas in both 19961997 and 4.84.2 BCF in 1995,1996, constituting 25.1%31.0% and 20.2%25.1%,
respectively, of the main system's requirements during such periods.
Such natural gas is supplied pursuant to contracts with producers
in the Spivey-Grabs field, most of which are for the life of the field.
Based on a reserve study performed by an independent petroleum engineering
firm in 1995, significant quantities of gas will be available from the
Spivey-Grabs field until at least the year 2015.
Other sources of gas for the main system of 3.0 BCF or 24.0% and 2.7 BCF or
16.0% of the system requirements were purchased from or transported through
interstate pipelines during 1996.1997 and 1996, respectively. The remainder of the
supply for the main system during 1997 and 1996 and 1995 of 2.21.2 BCF and 2.2 BCF
representing 13.4%9.8% and 9.9%13.4%, respectively, was purchased directly from producers
or gathering systems.
During 1997 and 1996, and 1995, approximately 1.50.8 BCF and 7.31.5 BCF, respectively, of the
total main system supply was transferred to the company's interstate system (See
Interstate System).
The company believes there is adequate natural gas available under
contract or otherwise available to meet the currently anticipated needs of the
main system customers.
The main system's average wholesale cost per MCF purchased for the past five
years was as follows:
Natural Gas Supply - Main System
(Average Cost per MCF)
1997 1996 1995 1994 1993
1992
Mesa-Hugoton ContractContract. . $ - $ - $1.44 $1.81 $1.78(1)
$1.47(2)
OtherOther. . . . . . . . . . 3.43 2.48 2.47 2.92 2.69
2.66
Total Average Cost . . . 3.43 2.48 2.06 2.23 2.20
2.00
(1) Includes 2.5 BCF @ $1.31/MCF of make-up deliveries.
(2) Includes 2.1 BCF @ $1.31/MCF of make-up deliveries.
The load characteristics of the company's natural gas customers createscreated
relatively high volume demand on the main system during cold winter days. To
assure peak day service to high priority customers the company ownsowned and
operatesoperated and hashad under contract natural gas storage facilities (See Item 2.
Properties).
WESTAR GAS MARKETING
Westar Gas Marketing was formed in 1988 to pursue natural gas marketing
opportunities. Westar Gas Marketing purchasespurchased and marketsmarketed natural gas to
approximately 925 customers located in Kansas, Missouri, Nebraska, Colorado,
Oklahoma, Iowa, Wyoming and Arkansas. Westar Gas Marketing purchasespurchased natural
gas under both long-term and short-term contracts from producers and operators
in the Hugoton, Arkoma and Anadarko gas basins. Westar Gas Marketing engagesengaged in
certain transactions to hedge natural gas prices in its gas marketing
activities. The net assets and operations of Westar Gas Marketing were
contributed to ONEOK in November 1997, upon the completion of the strategic
alliance with ONEOK.
WESTAR GAS COMPANY
Westar Gas Company ownsowned and operatesoperated the Minneola Gas Processing Plant
(Minneola) in Ford County, Kansas. Minneola extracts liquids from natural gas
provided by outside producers and sells the residue gas to third-party
marketers. A portion of the residue gas is sold to Westar Gas Marketing.
Westar Gas Company, through its participation in various joint ventures,
ownsowned a 41.4% beneficial interest in the Indian Basin Processing Plant (Indian
Basin) near Artesia, New Mexico. Indian Basin is operated by Marathon Oil and
extracts natural gas liquids for third party producers. The net assets and
operations of Westar Gas Company were contributed to ONEOK in November 1997,
upon the completion of the strategic alliance with ONEOK.
SECURITY ALARM MONITORING OPERATIONS
On July 30, 1997, the company agreed to combine its security alarm monitoring
business with Protection One, a publicly held security alarm monitoring
provider. On November 24, 1997, the company completed the transaction by
contributing approximately $532 million in security alarm monitoring business
net assets and approximately $258 million in cash in exchange for an 82.4%
ownership in Protection One.
Protection One is a leading provider of security alarm monitoring and related
services in the United States with approximately 950,000 subscribers.
Protection One has grown rapidly since its inception by participating in both
the growth and consolidation of the security alarm monitoring industry.
Protection One has focused its customer growth in major metropolitan areas
demonstrating strong demand for security alarms.
Protection One's revenues consist primarily of subscribers' recurring
payments for monitoring and related services. Protection One monitors digital
signals arising from burglaries, fires, and other events utilizing security
systems installed at subscribers' premises. Through a network of approximately
60 branches, Protection One provides maintenance and repair of security systems
and, in select markets, armed response to verify that an actual emergency,
rather than a false alarm, has occurred.
Protection One provides its services to the residential, commercial and
wholesale segments of the alarm monitoring market. Protection One believes the
residential segment, which represents in excess of 80% of its customer base, is
the most attractive because of its growth prospects, growth margins and size.
Within the residential segment, 19% of Protection One's customer base resides in
multi-family complexes such as apartments and condominiums and 62% occupy
single-family households. The remainder of Protection One's customer base is
split between commercial subscribers and subscribers owned by independent alarm
dealers that subcontract monitoring services to Protection One.
SEGMENT INFORMATION
Financial information with respect to business segments is set forth in Note
1820 of the Notes to Consolidated Financial Statements included herein.
FINANCING
The company's ability to issue additional debt and equity securities is
restricted under limitations imposed by the charter and the Mortgage and Deed
of Trust of Western Resources (formerly KPL) and KGE.
Western Resources' mortgage prohibits additional Western Resources first
mortgage bonds from being issued (except in connection with certain refundings)
unless the company's net earnings available for interest, depreciation and
property retirement 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. Based on the
company's results for the 12 months ended December 31, 1996,
approximately $772 million principal amount of additional1997, no first mortgage
bonds could be issued (7.75%(7.25% interest rate assumed).
Western ResourcesResources' bonds may be issued, subject to the restrictions in the
preceding paragraph, on the basis of property additions not subject to an
unfunded prior lien and on the basis of bonds which have been retired. As of
December 31, 1996,1997, the company had approximately $1.0 billion$25 million of net bondable
property additions not subject to an unfunded prior lien entitling the company
to issue up to $618$135 million principal amount of additional bonds. As of
December 31, 1996, $3 million in1997, no first mortgage bonds could be issued on the basis of
retired bonds.
KGE's mortgage prohibits additional KGE 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 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. Based on KGE's
results for the 12 months ended December 31, 1996,1997, approximately $1.0 billion$935 million
principal amount of additional KGE first mortgage bonds could be issued
(7.75%(7.25% interest rate assumed).
KGEKGE's bonds may be issued, subject to the restrictions in the preceding
paragraph, on the basis of property additions not subject to an unfunded prior
lien and on the basis of bonds which have been retired. As of December 31,
1996,1997, KGE had approximately $1.4 billion of net bondable property additions not
subject to an unfunded prior lien entitling KGE to issue up to $950$961 million
principal amount of additional KGE bonds. As of December 31, 1996,1997, $17
million in additional bonds could be issued on the basis of retired bonds.
The most restrictive provision of the company's charter permits the issuance
of additional shares of preferred stock without certain specified preferred
stockholder approval only if, for a period of 12 consecutive months within 15
months preceding the issuance, net earnings available for payment of interest
exceed one and one-half times the sum of annual interest requirements plus
dividend requirements on preferred stock after giving effect to the proposed
issuance. After giving effect to the annual interest and dividend requirements
on all debt and preferred stock outstanding at December 31, 1996,1997, such ratio
was 1.964.17 for the 12 months ended December 31, 1996.1997.
KCPL has outstanding first mortgage bonds (the "KCPL Bonds") which are
secured by a lien on substantially all of KCPL's fixed property and franchises
purported to be conveyed by the General Mortgage Indenture and Deed of Trust and
the various Supplemental Indentures creating the KCPL Bonds (collectively, the
"KCPL Mortgage"). IfIn the event KCPL and the company consummates its planned merger with KCPL,
the company, as the successor corporation to such merger, would be required
pursuant to the terms ofcombine, the KCPL Mortgage to confirm the liens thereunder and
to keep the mortgaged property with respect thereto as far as practicable
identifiable. In the absence of an express grant, however,mortgage
will have a prior lien on the KCPL Mortgage
will not constitute or become a lien on any property or franchises owned by
the company prior to such merger or on any property or franchises which may be
purchased, constructed or otherwise acquired by the company except for such as
form an integral part of the mortgage property under the KCPL Mortgage. Upon
consummation of the KCPL Merger, the after-acquired property clauses of the
company's mortgage would cause the lien of the Mortgage to attach (But in a
subordinate position to the prior lien of the KCPL Mortgage) to the property
of KCPL at the date of combination.and franchises.
REGULATION AND RATES
The company is subject as an operating electric utility to the jurisdiction
of the KCC and as a natural gas utility to the jurisdiction of
the KCC and theKansas Corporation Commission of the State of Oklahoma (OCC),(KCC) which havehas general regulatory
authority over the company's rates, extensions and abandonments of service and
facilities, valuation of property, the classification of accounts and various
other matters. The company is subject to the jurisdiction of the FERC and KCC
with respect to the issuance of securities.
There is no state regulatory bodyElectric fuel costs are included in Oklahoma having jurisdiction overbase rates. Therefore, if the issuancecompany
wished to recover an increase in fuel costs, it would have to file a request for
recovery in a rate filing with the KCC which could be denied in whole or in
part. Any increase in fuel costs from the projected average which the company
did not recover through rates would reduce its earnings. The degree of the company's securities.any such
impact would be affected by a variety of factors, however, and thus cannot be
predicted.
The company is 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). Additionally, the company is subject to the
jurisdiction of the FERC, including jurisdiction as to rates with respect to
sales of electricity for resale. The company is not engaged
in the interstate transmission or sale of natural gas which would subject it
to the regulatory provisions of the Natural Gas Act. KGE is also subject to the jurisdiction of the
Nuclear Regulatory Commission as to nuclear plant operations and safety.
Additional information with respect to Rate Matters and Regulation as set
forth in Note 98 of Notes to Consolidated Financial Statements is included
herein.
EMPLOYEE RELATIONS
As of December 31, 1996,1997, the company had 5,9602,412 employees. The company did
not experience any strikes or work stoppages during 1996.1997. The company's current
contract with the International Brotherhood of Electrical Workers extends
through June 30, 1997 and is currently being negotiated.1999. The contract covers approximately 1,9331,483 employees.
The company has contracts
with three gas unions representing approximately 586 employees. These
contracts were negotiated in 1996 and will expire June 4, 1998. Upon
consummation of the strategic alliance with ONEOK, approximately 1,500 company
employees will be transferred to New ONEOK.
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years
John E. Hayes, Jr. 5960 Chairman of the Board President
and Chief Executive
Officer
David C. Wittig 4142 President Executive Vice President,
(since March 1996) Corporate Strategy
(since
May 1995)(May 1995 to March 1996)
Salomon Brothers Inc -
Managing Director, Co-Head of
Mergers and Acquisitions
Norman E. Jackson 5960 Executive Vice President, Executive Vice President,
Electric Operations Electric Transmission and
(since November 1996) Engineering Services
(May 1995 to November 1996)
Executive Vice President,
Electric Engineering and Field
Operations (1992 to 1995)
Steven L. Kitchen 5152 Executive Vice President
and Chief Financial
Officer
Carl M. Koupal, Jr. 4344 Executive Vice President Executive Vice President
and Chief Administrative Corporate Communications,
Officer (since July 1995) Marketing, and Economic Development
(January 1995 to July 1995)
Vice President, Corporate Marketing,And Economic Development, (1992 to
1994)
Director, Economic Development,
(1985 to 1992) Jefferson City,
Missouri
John K. Rosenberg 5152 Executive Vice President
and General Counsel
Jerry D. Courington 5152 Controller
Executive officers serve at the pleasure of the Board of Directors. There are
no family relationships among any of the executive officers, nor any
arrangements or understandings between any executive officer and other persons
pursuant to which he was appointed as an executive officer.
Executive officers serve at the pleasure of the Board of Directors. There are
no family relationships among any of the officers, nor any arrangements or
understandings between any officer and other persons pursuant to which he was
appointed as an officer.
ITEM 2. PROPERTIES
The company owns or leases and operates an electric generation, transmission,
and distribution system in Kansas, a natural gas integrated
storage, gathering, transmission and distribution system in Kansas, and a
natural gas distribution system in Kansas and Oklahoma.
During the five years ended December 31, 1996, the company's gross
property additions totaled $1,109,037,000 and retirements were $238,434,000.Kansas.
ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (1)
Abilene Energy Center:
Combustion Turbine 1 1973 Gas 66
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 152
2 1967 Gas--Oil 382
Hutchinson Energy Center:
Steam Turbines 1 1950 Gas 1816
2 1950 Gas 17
3 1951 Gas 2826
4 1965 Gas 197
Combustion Turbines 1 1974 Gas 5150
2 1974 Gas 49
3 1974 Gas 5452
4 1975 Diesel 78
Diesel Generator 1 1983 Diesel 3
Jeffrey Energy Center (84%)(2):
Steam Turbines 1 1978 Coal 616617
2 1980 Coal 617
3 1983 Coal 591605
La Cygne Station (50%)(2):
Steam Turbines 1 1973 Coal 343
2 1977 Coal 335334
Lawrence Energy Center:
Steam Turbines 2 1952 Gas 0 (3)
3 1954 Coal 58
4 1960 Coal 115
5 1971 Coal 384
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 4644
2 1954 Gas--Oil 74
3 1956 Gas--Oil 107
4 1959 Gas--Oil 106
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (1)
Neosho Energy Center:
Steam Turbines 3 1954 Gas--Oil 0 (3)
Tecumseh Energy Center:
Steam Turbines 7 1957 Coal 8885
8 1962 Coal 148153
Combustion Turbines 1 1972 Gas 19
2 1972 Gas 20
Wichita Plant:
Diesel Generator 5 1969 Diesel 3
Wolf Creek Generating Station (47%)(2):
Nuclear 1 1985 Uranium 547
Total 5,3125,319
(1) Based on MOKAN rating.
(2) The company jointly owns Jeffrey Energy Center (84%), La Cygne Station
(50%) and Wolf Creek Generating Station (47%).
(3) These units have been "mothballed" for future use.
NATURAL GAS COMPRESSOR STATIONS AND STORAGE FACILITIES
Under the agreement for the proposed strategic alliance with ONEOK, the
company will contribute its natural gas business to New ONEOK in exchange for
a 45% equity interest. See Note 2 for further information.
The company's transmission and storage facility compressor stations,
all located in Kansas, as of December 31, 1996, are as follows:
Mfr Ratings
of MCF/Hr
Capacity at
Driving Type of Mfr hp 14.65 Psia
Location Units Year Installed Fuel Ratings at 60 F
Abilene . . . . . 4 1930 Gas 4,000 5,920
Bison . . . . . . 1 1951 Gas 440 316
Brehm Storage . . 2 1982 Gas 800 486
Calista . . . . . 3 1987 Gas 4,400 7,490
Hope. . . . . . . 1 1970 Electric 600 44
Hutchinson. . . . 2 1989 Gas 1,600 707
Manhattan . . . . 1 1963 Electric 250 313
Marysville. . . . 1 1964 Electric 250 202
McPherson . . . . 1 1972 Electric 3,000 7,040
Minneola. . . . . 5 1952 - 1978 Gas 9,650 14,018
Pratt . . . . . . 3 1963 - 1983 Gas 1,700 3,145
Spivey. . . . . . 4 1957 - 1964 Gas 7,200 1,368
Ulysses . . . . . 12 1949 - 1981 Gas 17,430 6,667
Yaggy Storage . . 3 1993 Electric 7,500 5,000
The company has contracted with the Market Center for underground
storage of working storage capacity of 2.08 BCF. This contract enables the
company to supply customers up to 85 million cubic feet per day of gas supply
to meet winter peaking requirements.
The company has contracted with WNG for additional underground
storage in the Alden field in Kansas. The contract, expiring March 31, 1998,
enables the company to supply customers with up to 75 million cubic feet per
day of gas supply during winter peak periods. See Item I. Business, Gas
Operations for proven recoverable gas reserve information.
ITEM 3. LEGAL PROCEEDINGS
The company has requested that the District Court for the Southern
District of Florida require that ADT hold a special shareowners meeting no
later than March 20, 1997. In its filing, the company claims that the ADT
board of directors has breached its fiduciary and statutory duties and that
there is no reason to delay the special meeting until JulyOn January 8, 1997, as
established by ADT. See Note 3 for additional information regarding the
proposed acquisition of ADT.
On December 26, 1996, an ADT shareownerInnovative Business Systems, Ltd. (IBS) filed a purported class action
complaintsuit
against ADT, ADT's board of directors, the company and the company's
wholly-owned subsidiary, Westar Capital in the Civil Division of the Circuit
Court of the Fifteenth Judicial Circuit in Palm Beach County, Florida.
(Charles Gachot v. ADT, Ltd.Westinghouse Electric Corporation (WEC), Western Resources,Westinghouse
Security Systems, Inc., Westar Capital, Inc.,
Michael A. Ashcroft, et al., Case No. 96-10912-AN) The complaint alleges,
among other things, that the company (WSS) and Westar Capital are breaching their
fiduciary duties to ADT's shareowners by failing to offer "an appropriate
premium for the controlling interest" in ADT and by holding "an effective
blocking position" that prevents independent parties from bidding for ADT.
The complaint seeks preliminary and permanent relief enjoining the company
from acquiring the outstanding shares of ADT and unspecified damages. The
company believes it has good and valid defenses to the claims asserted and
does not anticipate any material adverse effect upon its overall financial
condition or results of operations.
Subject to the approval of the KCC, the company entered into five
new gas supply contracts with certain entities affiliated with The Bishop
Group, Ltd. (Bishop entities) which are currently regulated by the KCC. A
contested hearing was held for the approval of those contracts. While the
case was under consideration by the KCC, the FERC issued an order under which it
extended jurisdiction over the Bishop entities. On November 3, 1995, the KCC
stayed its consideration of the contracts between the company and the Bishop
entities until the FERC takes final appealable action on its assertion of
jurisdiction over the Bishop entities.
On June 28, 1996, the KCC issued its order by dismissing the company's
application for approval of the contracts and of recovery of the related costs
from its customers. The company appealed this ruling and on January 24, 1997,
the Kansas Court of Appeals reversed the KCC order and upheld the contracts
and the company's recovery of related costs from its customers were approved
by operation of law.
On November 27, 1996, the KCC issued a Suspension Order and on
December 3, 1996, an order was issued which suspended, subject to refund,
costs related to purchases from Kansas Pipeline Partnership included in the
company's cost of gas rider (COGR). On December 12, 1996, the company filed a
Petition for Reconsideration or For More
Definite Statement by Staff of the Issues to be addressed in this Docket. On
March 3, 1997, the Staff issued a More Definite Statement specifying which
charges from KPP it asserts are inappropriate for inclusion in the company's
COGR. The company responded to the More Definite Statement stating that it
does not believe any of the charges from KPP should be disallowed from its
COGR. The company does not expect this proceeding to have a material adverse
effect on its results of operations.
As part of the acquisition of WSS on December 31, 1996, WSS assigned to
WestSec, Inc. (WestSec), a wholly-owned
subsidiary of Westar Capitalthe company established to acquire the assets of WSS, a software license with Innovative Business Systems (IBS)
which is integral to the operation of its security business. On January 8,
1997, IBS filed litigation in Dallas
County, Texas district court (Cause No 97-00184) alleging, among other things,
breach of contract by WEC and interference with contract against the company in
connection with the 298th Judicial
District Court concerning the assignmentsale by WEC of the licenseassets of WSS to WestSec,
(Innovative Business Systems (Overseas) Ltd.,the company. IBS claims
that WEC improperly transferred software owned by IBS to the company and Innovative Business
Software, Inc. v. Westinghouse Electric Corporation, Westinghouse Security
Systems, Inc., WestSec, Inc., Western Resources, Inc., et al., Cause
No. 97-00184).that
the company is not entitled to its use. The company and Westar Capital havehas demanded Westinghouse
Electric CorporationWEC defend and
indemnify them. While the loss of use of
the license may have a material impact on the operations of WestSec,
management ofit. WEC and the company currentlyhave denied IBS' allegations and are
vigorously defending against them. Management does not believe that the
ultimate disposition of this matter will have a material adverse effect upon the
company's overall financial condition or results of operationsoperations.
The Securities and Exchange Commission (SEC) has commenced a private
investigation relating, among other things, to the timeliness and adequacy of
disclosure filings with the SEC by the company with respect to securities of ADT
Ltd. The company is cooperating with the SEC staff in the production of records
relating to the investigation.
Additional information on legal proceedings involving the company is set
forth in Notes 7, 8, and 9 of Notes to Consolidated Financial Statements
included herein. See also Item 1. Business, Environmental Matters, and
Regulation and Rates.Rates and Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of the fiscal year covered
by this report to a vote of the company's security holders, through the
solicitation of proxies or otherwise.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Stock Trading
Western Resources common stock, which is traded under the ticker symbol WR,
is listed on the New York Stock Exchange. As of March 3, 1997,17, 1998, there were
62,84058,669 common shareholders of record. For information regarding quarterly
common stock price ranges for 19961997 and 1995,1996, see Note 2021 of Notes to
Consolidated Financial Statements included herein.
Dividends
Western Resources common stock is entitled to dividends when and as declared
by the Board of Directors. At December 31, 1996,1997, the company's retained
earnings were restricted by $857,600 against the payment of dividends on
common stock. However, prior to the payment of common dividends, dividends must
be first paid to the holders of preferred stock and second to the holders of
preference stock based on the fixed dividend rate for each series.
Dividends have been paid on the company's common stock throughout the
company's history. Quarterly dividends on common stock normally are paid on or
about the first of January, April, July, and October to shareholders of record
as of or about the third day of the preceding month. Dividends increased four
cents per common share in 19961997 to $2.06$2.10 per share. In January 1997,1998, the Board
of Directors declared a quarterly dividend of 5253 1/2 cents per common share, an
increase of one cent over the previous quarter. The payment of dividends is at
the discretion of the Board of Directors. Future dividends depend upon such
matters as future earnings, expectations and the financial condition of the
company
and other factors.company. For information regarding quarterly dividend declarations for 19961997 and
1995,1996, see Note 2021 of Notes to Consolidated Financial Statements included herein.
See also Item 7. Management's Discussion and Anaylsis of Financial Condition and
Results of Operations.
ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31, 1997(1)(2) 1996 1995 1994(1)1994(3) 1993
1992(2)(Dollars in Thousands)
(Dollars in Thousands)
Income Statement Data:
Operating revenues:
Electric . . . . . .. . . . $1,197,433 $1,145,895 $1,121,781 $1,104,537 $ 882,885
Natural gasSales:
Energy. . . . . . . . 849,386 597,405 642,988 923,874 756,537
Total operating revenues . . 2,046,819 1,743,300 1,764,769 2,028,411 1,639,422
Operating expenses . . . . . 1,742,826 1,464,591 1,489,719 1,736,051 1,399,701
Allowance for funds used during
construction$1,999,418 $2,038,281 $1,743,930 $1,764,769 $2,028,411
Security. . . . . . . . 3,225 4,227 2,667 2,631 2,002. . 152,347 8,546 344 - -
Total sales. . . . . . . . . 2,151,765 2,046,827 1,744,274 1,764,769 2,028,411
Income from operations. . . . 142,925 388,553 373,721 370,672 370,338
Net income . . . . . . . . . 494,094 168,950 181,676 187,447 177,370
127,884
Earnings applicable toavailable for common
stock. . . . . . . . . . . 489,175 154,111 168,257 174,029 163,864
115,133
December 31, 1997(2) 1996 1995 1994(1)1994(3) 1993 1992(2)
(Dollars in Thousands)
Balance Sheet Data:
Gross plant in service . . . $6,370,586 $6,128,527 $5,963,366 $6,222,483 $6,033,023
Construction work in progress 93,834 100,401 85,290 80,192 68,041
Total assetsassets. . . . . . . . . 6,647,781 5,490,677 5,371,029 5,412,048 5,438,906$6,976,960 $6,647,781 $5,490,677 $5,371,029 $5,412,048
Long-term debt, preference
stock, and other mandatorily
redeemable securitiessecurities. . .. . . 2,451,855 1,951,583 1,641,263 1,507,028 1,673,988
2,077,459
Year Ended December 31, 1997 1996 1995 1994(1)1994(3) 1993 1992(2)
Common Stock Data:
EarningsBasic earnings per share . . . . . . .$ 7.51 $ 2.41 $ 2.71 $ 2.82 $ 2.76 $ 2.20
Dividends per share. . . . . . . . $ 2.10 $ 2.06 $ 2.02 $ 1.98 $ 1.94 $ 1.90
Book value per share . . . . . . . $30.79 $25.14 $24.71 $23.93 $23.08
$21.51
Average shares outstanding(000's) 65,128 63,834 62,157 61,618 59,294 52,272
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . . 5.52 2.67 3.14 3.42 2.79
2.27
Ratio(1) Information reflects the gain on the sale of EarningsTyco common shares.
(2) Information reflects the contribution of the natural gas business to Fixed Charges 2.16 2.41 2.65 2.36 2.02
Ratio of Earnings to Combined
Fixed Charges and Preferred
and Preference Dividend
Requirements . . . . . . . . . 1.96 2.18 2.37 2.14 1.84
(1)ONEOK on November 30, 1997.
(3) Information reflects the sales of the Missouri Properties (Note 19).
(2) Information reflects the merger with KGE on March 31, 1992.Properties.
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 1997 and 1996
- 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 1997
- What we expect our capital expenditures to be for the years 1998
through 2000
- 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 41. These statements show our
operating results for 1997, 1996 and 1995. 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, environmental
matters, changing weather, nuclear operations 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, revenues and costs.
1997 HIGHLIGHTS
GAIN ON SALE OF EQUITY SECURITIES: During the third quarter of 1997, we sold
all of our Tyco International Ltd. (Tyco) common shares for approximately $1.5
billion. We recorded a pre-tax gain of approximately $864 million on the sale
which is included in "Other Income" on the Consolidated Statements of Income.
We recorded tax expense of approximately $345 million in connection with this
gain. The tax on the gain is included in "Income Taxes" on the Consolidated
Statements of Income. As discussed further in "Financial Condition" below, this
significantly affected our financial results for 1997 (see Note 2).
PURCHASE OF PROTECTION ONE, INC.: On July 30, 1997, we agreed to combine our
security alarm monitoring business with Protection One, Inc. (Protection One),
a publicly held security alarm monitoring provider. On November 24, 1997, we
completed the transaction by contributing approximately $532 million in security
alarm monitoring business net assets and approximately $258 million in cash.
The cash contributed included funds used for a special dividend of $7.00 per
common share to Protection One shareowners, option holders and warrant holders
other than Western Resources. In exchange for our net security alarm monitoring
business assets and cash, we received 82.4% ownership in Protection One. We
entered the security alarm monitoring business to make our company more diverse
and to achieve growth.
In December 1997, Protection One recorded a special non-recurring charge of
approximately $40 million. Approximately $28 million of this charge reflects
the elimination of redundant facilities and activities and the write-off of
inventory and other assets which are no longer of continuing value to Protection
One. The remaining $12 million of this charge reflects the estimated costs to
transition all security alarm monitoring operations to the Protection One brand.
Protection One intends to complete these activities by the fourth quarter of
1998.
STRATEGIC ALLIANCE WITH ONEOK INC.: On December 12, 1996, we agreed to form
a strategic alliance with ONEOK Inc. (ONEOK) to combine the natural gas assets
of both companies. In November 1997, we completed this strategic alliance. We
contributed substantially all of our regulated and non-regulated natural gas
business net assets totaling approximately $594 million to a new company which
merged with ONEOK and adopted the name ONEOK. ONEOK operates its natural gas
business in Kansas using the name Kansas Gas Service Company. In exchange for
our contribution, we received a 45% ownership interest in ONEOK. The structure
of the strategic alliance had no immediate income tax consequences to our
company or our shareowners.
Our 45% ownership interest in ONEOK is comprised of 3.1 million common shares
and approximately 19.9 million convertible preferred shares. If we converted
all the preferred shares, we would own approximately 45% of ONEOK's common
shares presently outstanding. Our agreement with ONEOK allowed us to appoint
two members to ONEOK's board of directors. ONEOK currently pays a common
dividend of $1.20 per share. The initial annual dividend rate on the
convertible preferred shares is $1.80 per share.
MERGER AGREEMENT WITH KANSAS CITY POWER & LIGHT COMPANY: On February 7,
1997, we entered into a merger agreement with Kansas City Power & Light Company
(KCPL). The merger agreement contemplated a tax-free, stock for stock exchange
valued at approximately $2 billion or $32 in value for each common share of
KCPL. 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
required fairness opinion for the merger on the basis of the previously
announced terms.
We canceled our shareowner meeting scheduled for January 21, 1998 to approve
the merger. KCPL canceled a similar meeting for its shareowners. We and KCPL
have met to discuss alternative terms of a potential merger. We cannot predict
the timing or the ultimate outcome of these discussions.
On January 13, 1998, the Kansas Corporation Commission (KCC) issued an order
suspending the merger proceedings and waived an eight-month time requirement to
approve the merger. On January 26, 1998, the Missouri Public Service Commission
(MPSC) issued an order suspending the merger proceedings. We and KCPL have
agreed to these suspensions. On January 9, 1998, we asked the Federal Energy
Regulatory Commission (FERC) to hold the docket on our proposed merger in
abeyance until April 10, 1998, at which time we will advise the FERC whether to
continue to hold the docket in abeyance or that a new agreement has been reached
with KCPL.
As of December 31, 1997, we had spent and deferred on the Consolidated
Balance Sheet approximately $53 million in our efforts to acquire KCPL. We had
planned to expense these costs in the first period following the merger. Given
the status of the KCPL transaction, we have reviewed the deferred costs and have
determined that for accounting purposes, $48 million of the deferred costs
should be expensed. We recorded a special non-recurring charge of $29 million
after taxes, or $0.44 per share in December 1997, to expense the costs that were
incurred solely as a result of the original merger agreement. At December 31,
1997, we had deferred approximately $5 million related to the KCPL transaction
currently being negotiated. See "Financial Condition" below and Note 5.
OTHER SECURITY ALARM MONITORING BUSINESS PURCHASES: We acquired Network
Multi-Family Security Corporation (Network Multi-Family), a security alarm
monitoring provider for multi-unit dwellings based in Dallas, Texas, for
approximately $171 million in cash in September 1997. On February 4, 1998,
Protection One exercised its option to acquire the stock of Network Holdings,
Inc., the parent company of Network Multi-Family, from us for approximately $178
million. We expect this transaction to occur in the first quarter of 1998. We
expect Protection One to borrow money from a revolving credit agreement provided
by Westar Capital, a subsidiary of Western Resources, to purchase Network
Multi-Family.
In November 1997, we acquired Centennial Security Holdings, Inc. (Centennial)
for approximately $94 million in cash. Centennial is based in Madison, New
Jersey and provides security alarm monitoring services to more than 50,000
customers in Ohio, Michigan, New Jersey, New York and Pennsylvania. We
contributed our Centennial security alarm monitoring business to Protection One
on November 24, 1997.
In March 1998, Protection One acquired the subscribers and assets of Wichita,
Kansas-based Multimedia Security Services, Inc. Multimedia Security Services,
Inc. has approximately 140,000 subscribers concentrated primarily in California,
Florida, Kansas, Oklahoma and Texas. We expect Protection One to borrow money
from a revolving credit agreement provided by Westar Capital to complete this
transaction.
OTHER INVESTMENTS: In December 1997, we invested $28 million to acquire an
interest in two 55-megawatt power plants in the People's Republic of China. We
invested approximately $3 million in power projects in the Republic of Turkey
and Colombia in 1997 (see Note 7). We also invested in other miscellaneous
investments.
ELECTRIC RATE DECREASE: On May 23, 1996, we reduced our electric rates to
Kansas Gas and Electric Company (KGE) customers by $8.7 million annually on an
interim basis. On October 22, 1996, the KCC Staff, the City of Wichita, the
Citizens Utility Ratepayer Board and we filed an agreement asking the KCC to
reduce our retail electric rates. The KCC approved this agreement on January
15, 1997. Per the agreement:
- 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 will reduce KGE's rates by $10 million more annually on June 1,
1998
- We will rebate $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
All rate decreases are cumulative. Rebates are one-time events and do not
influence future rates. See "Financial Condition" below and Note 8.
FINANCIAL CONDITION
GENERAL:1997 compared to 1996: Earnings were $2.41increased to $489 million for 1997 from $154
million for 1996, an improvement of 218%. Basic earnings per share rose to
$7.51 for 1997 compared to $2.41 for 1996, an increase of 212%. Basic
earnings per share is calculated based upon the average weighted number of
common shares outstanding during the period. There were no significant amounts
of dilutive securities outstanding at December 31, 1997 or 1996. Four factors
primarily affected 1997 earnings and basic earnings per share compared to 1996:
- The gain on the sale of the Tyco common stock increased earnings before
taxes by $864 million and basic earnings per share by $7.97
- The write-off of approximately $48 million in costs related to the
KCPL Merger decreased basic earnings per share by $0.44
- The operating results and special one-time charges from our first
full year of security alarm monitoring business reduced 1997
earnings by $47 million and basic earnings per share by $0.72
- Our reduced electric rates implemented on February 1, 1997 decreased
revenues by $46 million and basic earnings per share by $0.42
Dividends declared for 1997 increased four cents per common share to $2.10
per share. On January 29, 1998, the Board of Directors declared a dividend of 53
1/2 cents per common share for the first quarter of 1998, an increase of one
cent from the previous quarter.
Our book value per common share was $30.79 at December 31, 1997, compared to
$25.14 at December 31, 1996. The 1997 closing stock price of $43.00 was 140% of
book value and 39% higher than the closing price of $30.875 on December 31,
1996. Book value is the total common stock equity divided by the common shares
outstanding at December 31. There were 65,409,603 common shares outstanding at
December 31, 1997.
1996 compared to 1995: Basic earnings per share were $2.41 based on
63,833,783 average common shares for 1996, a decrease from $2.71 in 1995 on
62,157,125 average common shares.1995. Net
income for 1996 decreased to $169.0$169 million compared to $181.7 million in 1995.from $182 million. The decrease in
net income andbasic earnings per share and net income is primarily due to the impact of an
$11.8 million or $0.19 per share charge, net of tax, attributable to one-time
restructuring and other charges recorded by ADT Limited (ADT). Abnormally cool
summer weather during the third quarter of 1996 and the $8.7 million electric
rate decrease to KGE customers also lowered earnings.
OPERATING RESULTS
In our "1997 Highlights", we discussed five factors that most significantly
changed our operating results for 1997 compared to 1996.
The following explains significant changes from prior year results in
which the company owns approximately
27%revenues, cost of sales, operating expenses, other income (expense), interest
expense, income taxes and preferred and preference dividends.
After 1997, because of the ONEOK alliance, we will no longer separately
report natural gas operations financial information in our financial statements,
or in our Management's Discussion and Analysis. Also, we had minimal security
alarm monitoring business operations in 1995 and, therefore, we do not discuss
variations relating to it between 1996 and 1995.
SALES: Energy revenues include electric revenues, power marketing revenues,
natural gas revenues and other insignificant energy-related revenues. Certain
state regulatory commissions and the FERC authorize rates for our electric
revenues. Our energy revenues vary with levels of sales volume. Changing
weather affects the amount of energy 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 energy sales. They include:
- The weather
- Our electric rates
- Competitive forces
- Customer conservation efforts
- Wholesale demand
- The overall economy of our service area
1997 compared to 1996: Electric revenues increased three percent because of
revenues of $70 million from the expansion of power marketing activity in 1997.
Our involvement in electric power marketing anticipates a deregulated electric
utility industry. We are involved in 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 activity
is significantly less than our margins on other energy sales. Our power
marketing activity has resulted in energy purchases and sales made in areas
outside of our historical marketing territory. In 1997, this additional power
marketing activity had an insignificant effect on operating income. Higher
electric revenues from power marketing were offset by our reduced electric rates
implemented February 1, 1997. Reduced electric rates lowered 1997 revenues by
an estimated $46 million compared to 1996. The rate decreases we have agreed to
make will impact future revenues.
Natural gas revenues decreased $58 million or seven percent in 1997 compared
to 1996 because we transferred our net natural gas business assets to ONEOK as
of November 30, 1997 and we had warmer than normal weather in the first quarter
of 1997. In December 1997, we began reporting investment income for ONEOK based
upon our common stock. Abnormallyand preferred equity interests.
Security alarm monitoring business revenues increased $144 million from our
minimal 1996 security alarm monitoring business revenues. This increase is
because of our December 31, 1996, purchase of the net assets of Westinghouse
Security Systems, Inc. (Westinghouse Security Systems) and our acquisition on
November 24, 1997, of 82.4% of Protection One. As a result, we have included a
full year of operating results from Westinghouse Security Systems and one month
of operating results from Protection One. See "1997 Highlights" above and Note
3.
1996 compared to 1995: Electric revenues were five percent higher in 1996
compared to 1995. Our service territory experienced colder winter and warmer
spring temperatures during the first six months of 1996 compared to 1995, which
yielded higher sales in the residential and commercial customer classes. We
experienced a 17% increase in heating degree days during the first quarter of
1996 and had double the cooling degree days during the second quarter of 1996
compared to the same periods in 1995. Partially offsetting the increase in
electric revenues was abnormally cool summer weather during the third quarter of
1996 compared to 1995 and thea KCC-ordered electric rate decrease of $8.7 million
electric rate reductionfor KGE customers (see Note 8).
Colder winter temperatures, higher natural gas costs passed on to Kansas Gascustomers
as permitted by the KCC and Electric Company (KGE) customers implementedmore as-available natural gas sales increased
regulated natural gas revenues 29% for 1996 as compared to 1995. The natural
gas revenue increase approved by the KCC on July 11, 1996, raised regulated
natural gas revenues $14 million for the last six months of 1996.
COST OF SALES: Items included in energy cost of sales are fuel expense,
purchased power expense (electricity we purchase from others for resale), power
marketing expense and natural gas purchased. Items included in security alarm
monitoring cost of sales are the cost of direct monitoring and the cost of
installing security monitoring equipment that is not capitalized.
1997 compared to 1996: Energy business cost of sales was $49 million or six
percent higher. Our power marketing activity in 1997 increased energy 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 in 1997 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 interim
basisextended
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 low coal inventories, 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.
Due to the contribution of our natural gas business to ONEOK, our natural gas
cost of sales decreased $24 million. We will no longer reflect such costs in
our financial statements.
The security alarm monitoring cost of sales increased $35 million. The
increase is a result of the purchase of the assets of Westinghouse Security
Systems on May 23,December 31, 1996, and made permanentour acquisition on January 15, 1997 also adversely
affected earnings.
Dividends for 1996 increased four cents per common share to $2.06 per
share. On JanuaryNovember 24, 1997, the Board of Directors declared a dividend82.4%
of 52 1/2
cents per common share forProtection One.
1996 compared to 1995: Energy business cost of sales was $220 million higher
in 1996 than 1995. We purchased more power from other utilities because our
Wolf Creek nuclear generating station was off-line in the first quarter of 1996
for a planned refueling outage. Higher net generation due to warmer weather and
higher customer demand for air conditioning during the second quarter of 1996
also contributed to the higher fuel and purchased power expenses.
Security alarm monitoring cost of sales increased $4 million due to the
purchases of several small security alarm monitoring companies.
OPERATING EXPENSES
OPERATING AND MAINTENANCE EXPENSE: Operating and maintenance expense
increased slightly from 1996 to 1997. Operating and maintenance expense
increased $23 million or six percent from 1995 to 1996 due to expenses
associated with our regulated natural gas transmission service provider, Mid
Continent Market Center.
DEPRECIATION AND AMORTIZATION EXPENSE: The amortization of capitalized
security alarm monitoring accounts and goodwill for our security alarm
monitoring business increased our depreciation and amortization expense
approximately $41 million for 1997 anversus 1996. A full year of amortization of
the acquisition adjustment for the 1992 acquisition of KGE increased our
depreciation and amortization expense for 1996 compared to 1995 by approximately
$14 million.
SELLING, GENERAL AND ADMINISTRATIVE EXPENSE: Selling, general and
administrative expense has increased $113 million from 1996 to 1997. Higher
employee benefit costs of approximately $30 million and higher security alarm
monitoring business selling, general and administrative expense of approximately
$83 million caused this increase. The security alarm monitoring business
increase is because of one cent
over the previous quarter.
The book value per share was $25.14 atour December 31, 1996, purchase of the assets of
Westinghouse Security Systems and our acquisition on November 24, 1997, of 82.4%
of Protection One.
OTHER: We recorded a special non-recurring charge in December 1997 to
expense $48 million of deferred KCPL Merger costs.
Protection One recorded a special non-recurring charge of approximately $40
million in December 1997, to reflect the phase out of certain business
activities which are no longer of continuing value to Protection One, to
eliminate redundant facilities and activities and to bring all customers under
the Protection One brand.
OTHER INCOME (EXPENSE): Other income (expense) includes miscellaneous income
and expenses not directly related to our operations. The gain on the sale of
Tyco common stock increased other income $864 million for 1997 compared to
$24.71 at December 31, 1995. The1996. Other income (expense) decreased slightly from 1995 to 1996.
INTEREST EXPENSE: Interest expense includes the interest we paid on
outstanding debt. We recognized $27 million more short-term debt interest in
1997 than in 1996. Average short-term debt balances were higher in 1997 than
1996 closing stock price of $30.875 was 123%
of book value. There were 64,625,259 common shares outstanding at December
31, 1996.
1996 HIGHLIGHTS
PROPOSED MERGER WITH KANSAS CITY POWER & LIGHT COMPANY: On
April 14,
1996,because we used short-term debt to finance our investment in a letterADT and to
Mr. A. Drue Jennings, Chairman ofpurchase the Board, President
and Chief Executive Officer of Kansas City Power & Light Company (KCPL), the
company proposed an offer to merge with KCPL (KCPL Merger).
On November 15, 1996, the company and KCPL announced that
representatives of their respective boards and managements met to discuss the
proposed merger transaction. On February 7, 1997, KCPL and the company entered
into an agreement whereby KCPL would be merged with and into the company.
The merger agreement provides for a tax-free, stock-for-stock
transaction valued at approximately $2 billion. Under the terms of the
agreement, KCPL shareowners will receive $32 of company common stock per KCPL
share, subject to an exchange ratio collar of not less than 0.917 and no more
than 1.100 common shares. Consummation of the KCPL Merger is subject to
customary conditions including obtaining the approval of KCPL's and the
company's shareowners and various regulatory agencies.
The KCPL Merger, will create a company with more than two million
security and energy customers, 9.5 billion in assets, $3.0 billion in annual
revenues and more than 8,000 megawatts of electric generation resources. As a
result of the merger agreement, the company terminated its exchange offer that
had been effective since July 3, 1996. See Note 2 of Notes to Consolidated
Financial Statements (Notes) for more information regarding the proposed merger
with KCPL.
PROPOSED STRATEGIC ALLIANCE WITH ONEOK INC.: On December 12, 1996,
the
company and ONEOK Inc. (ONEOK) announced an agreement to form a strategic
alliance combining the natural gas assets of both companies. Under the
agreement for the proposed strategic alliance, the company will contribute its
natural gas business to a new company (New
ONEOK)Westinghouse Security Systems. Short-term debt interest
expense declined in exchange for a 45% equity interest. The recorded net property value
being contributed at December 31, 1996 is estimated at $600 million. No gain
or loss is expected to be recorded as a result of the proposed transaction.
The proposed transaction is subject to satisfaction of customary conditions,
including approval by ONEOK shareowners and regulatory authorities. The
company is working towards consummation of the transaction during the second half of 1997.
The equity1997 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
would be comprisedrecorded on long-term debt increased $14 million or 13% due to the issuance of
approximately 3.0$520 million common sharesin senior unsecured notes.
We had $16 million more in interest expense on short-term and 19.3other debt in
1996 than in 1995 because we used short-term debt to finance our investment in
ADT and we issued Western Resources obligated mandatorily redeemable preferred
securities of subsidiary trusts. We also recognized $10 million convertible preferred shares. Upon consummation
of the proposed alliance, the company will record its common equitymore long-term
debt interest in New ONEOK's earnings using1996 compared to 1995 due to a higher revolving credit
agreement balance.
INCOME TAXES: Income taxes on the equity methodgain from the sale of accounting. EarningsTyco common stock
increased total income tax expense by approximately $345 million for 1997
compared to 1996. Income taxes did not vary significantly from 1995 to 1996.
PREFERRED AND PREFERENCE DIVIDENDS: We redeemed all of our 8.50% preference
stock due 2016 on July 1, 1996; therefore, 1997 preferred and preference
dividends were $10 million lower compared to 1996. Preferred and preference
dividends varied slightly from 1995 to 1996.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW: Most of our cash requirements consist of capital expenditures and
maintenance costs associated with the convertible preferred shares held willelectric utility business, continued
growth in the security alarm monitoring business, payment of common stock
dividends and investments in foreign power projects. 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, 1997, we had $77 million in cash and cash equivalents.
We consider highly liquid debt instruments purchased with a maturity of three
months or less to be recognizedcash equivalents. Our cash and recorded based upon
preferred dividends paid. The convertible preferred shares are expected to
pay an initial dividend rate of $1.80 per share. For its fiscal year ended
Augustcash equivalents increased
$73 million from December 31, 1996, ONEOK reported operating revenuesdue to cash held by Protection One. Other
than operations, our primary source of $1.2 billion and net
incomeshort-term cash is from short-term bank
loans, unsecured lines of $52.8 million.
The structure of the proposed alliance is not expected to have any
immediate income tax consequences to either company or to either company's
shareowners.
See Note 6 for more information regarding this strategic alliance.
PROPOSED ACQUISITION OF ADT LIMITED, INC.: During 1996, the company
purchased approximately 38 million common shares of ADT Limited, Inc. (ADT)
for approximately $589 million. The shares purchased represent approximately
27% of ADT's common equity making the company the largest shareowner of ADT.
On December 18, 1996, the company announced its intention to offer to
exchange $22.50 in cash ($7.50) and shares ($15.00) of the company's common
stock for each outstanding common share of ADT not already owned by the
company or its subsidiaries (ADT Offer). The value of the ADT Offer, assuming
the company's average stock price prior to closing is above $29.75 per common
share, is approximately $3.5 billion, including the company's existing
investment in ADT. Following completion of the ADT Offer, the company
presently intends to propose and seek to have ADT effect an amalgamation,
pursuant to which a newly created subsidiary of the company incorporated under
the laws of Bermuda will amalgamate with and into ADT (Amalgamation). Based
upon the closing stock price of the company on March 13, 1997, approximately
60.1 million shares of company common stock would be issuable pursuant to the
acquisition of ADT. However, the actual number of shares of company common
stock that would be issuable in connection with the ADT Offercredit and the Amalgamation will depend onsale of commercial paper. At December
31, 1997, we had approximately $237 million of short-term debt outstanding, of
which $76 million was commercial paper. An additional $773 million of
short-term debt was available from committed credit arrangements.
Other funds are available to us from the exchange ratio and the numbersale of shares
validly tendered prior to the expiration date of the ADT Offer and the number
of shares of ADT outstanding at the time the Amalgamation is completed.
On March 3, 1997, the company announced a change in the ADT Offer.
Under the terms of the revised ADT Offer, ADT shareowners would receive $10 cash
plus 0.41494 of a share of company common stocksecurities we register for
each share of ADT
tendered, based on the closing price of the company's common stock on March
13, 1997. ADT shareowners would not, however, receive more than 0.42017
shares of company common stock for each ADT common share.
Concurrent with the announcement of the ADT Offer on December 18, 1996,
the company filed a registration statement on Form S-4sale with the Securities and Exchange Commission (SEC) related. As of December 31,
1997, these included $30 million of Western Resources first mortgage bonds
which may also be issued as unsecured senior notes at our option, $50 million of
KGE first mortgage bonds and approximately 11 million Western Resources common
shares.
Our embedded cost of long-term debt was 7.5% at December 31, 1997, a drop of
0.1% from December 31, 1996.
CASH FLOWS FROM OPERATING ACTIVITIES: Cash provided by operations declined
$355 million from 1996 primarily due to income taxes paid on the ADT Offer. On March 14,gain on the
sale of Tyco stock. Individual items of working capital will vary with our
normal business cycles and operations, including the timing of receipts and
payments. Amortization of goodwill and subscriber accounts associated with the
security alarm monitoring business increased, because security alarm monitoring
operations were small during 1996.
CASH FLOWS FROM INVESTING ACTIVITIES: Cash used in investing activities
varies with the timing of capital expenditures, acquisitions and investments.
For 1997, the
registration statement was declared effective by the SEC. The expiration datewe had positive net cash flow from investing activities because of the
ADT Offer is 5 p.m., EDT, April 15,receipt of approximately $1.5 billion in proceeds on the sale of Tyco common
stock.
We had two significant investing activities during 1997 and may be extended from time
to time bywhich partially
offset the company until the various conditions to the ADT Offer have been
satisfied or waived. The ADT Offer will be
subject to the approval of ADT and company shareowners. On January 23, 1997,
the waiting period for the Hart-Scott-Rodino Antitrust Improvement Act
expired. On February 7, 1997, the company received regulatory approvalproceeds from the KCCsale of the Tyco common stock. We invested $484
million to issue companyacquire security alarm monitoring companies and accounts. We also
invested approximately $31 million in international power projects in the
People's Republic of China, the Republic of Turkey and Colombia.
CASH FLOWS FROM FINANCING ACTIVITIES: We paid off $275 million borrowed under
a multi-year revolving credit agreement with short-term debt in the first
quarter of 1997.
In August 1997, we issued $520 million in convertible first mortgage bonds.
We used the proceeds, after expenses, to reduce short-term debt. In November
1997, we converted the first mortgage bonds into unsecured senior notes having
the same principal amount, interest rate and maturity date as the first mortgage
bonds. This conversion satisfied mortgage requirements to retire bonds in order
to release our natural gas properties from the mortgage and contribute them to
ONEOK (see Note 15).
We used a portion of the proceeds from the sale of Tyco common stock andto
reduce short-term debt. In aggregate, our short-term debt necessary for the ADT Offer.
On March 17, 1997, ADT announced that it had entered into a definitive
merger agreement pursuant to which Tyco International Ltd. (Tyco), a
diversified manufacturer of industrial and commercial products, would
effectively acquire ADT in a stock for stock transaction valuedhas declined from
$981 million at $5.6
billion, or approximately $29 per ADT share of common stock. ADT is engaged
in the electronic security services business providing continuous monitoring
of commercial and residential security systems for approximately 1.2 million
customers in North America and abroad.
On March 18, 1997, the company issued a press release indicating that
it had mailed the details of the ADT Offer to ADT shareowners and that it would
be reviewing the Tyco offer as well as considering its alternatives to such
offer and assessing its rights as an ADT shareowner. See Note 3 for more
information regarding this investment and the proposed ADT Offer.
ACQUISITION OF WESTINGHOUSE SECURITY SYSTEMS, INC.: On December 31, 1996, the company purchased the assets and assumed certain liabilities
comprising Westinghouse Security Systems, Inc. (WSS), a monitored security
service provider with over 300,000 accounts in the United States. The company
paid $358to $237 million in cash, subject to adjustment. As the acquisition was
consummated on December 31, 1996, the assets of WSS are included in the
Consolidated Balance Sheets, but the results of operations are not included in
the Consolidated Statements of Income. For the year ended December 31, 1996,
WSS reported $110 million in revenues. See Note 4 for further information.
ACQUISITION OF THE WING GROUP LTD: In February of 1996 the company
purchased The Wing Group Ltd (The Wing Group), an international power
developer.
As a consequence of consummated acquisitions and investments, the
company's investments and other property increased by approximately $1.1
billion in 1996, These investments represents approximately 18% of the
company's consolidated assets at December 31, 1996. The impact of the
consummated acquisition1997.
CAPITAL STRUCTURE: Our capital structures at December 31, 1997, and investment transactions on the company's 1997
financial results is expected to be accretive to earnings.
1994 SALES OF MISSOURI GAS PROPERTIES: On January 31, 1994, the
company sold substantially all of its Missouri natural gas distribution
properties and operations to Southern Union Company (Southern Union). The
company sold the remaining Missouri properties to United Cities Gas Company
(United Cities) on February 28, 1994. The properties sold to Southern Union
and United Cities are referred to herein as the "Missouri Properties." For
additional information regarding the sales of the Missouri Properties see
Note 19.
FORWARD LOOKING INFORMATION: Certain matters discussed in this annual
report are "forward-looking statements" intended to qualify for the safe
harbors from liability established by the Private Securities Litigation Reform
Act of 1995. Such statements address future plans, objectives, expectations
and events or conditions concerning various matters such as capital
expenditures, earnings, litigation, rate and other regulatory matters,
pending transactions, liquidity and capital resources, and accounting matters.
Actual results in each case could differ materially from those currently
anticipated in such statements, by reason of factors such as electric utility
restructuring, including ongoing state and federal activities; future economic
conditions; legislation; regulation; competition; and other circumstances
affecting anticipated rates, revenues and costs.
LIQUIDITY AND CAPITAL RESOURCES: The company's liquidity is a
function of its ongoing construction and maintenance program designed to improve
facilities which provide electric and natural gas service and meet future
customer service requirements. Acquisitions and subsidiary investments also
significantly affect the company's liquidity.
During 1996 construction expenditures for the company's electric
system were approximately $138 million and nuclear fuel expenditures were
approximately $3 million. It is projected that adequate capacity margins will
be maintained without the addition of any major generating facilities for the
next five years. The construction expenditures for improvements on the
natural gas system, including the company's service line replacement program,
were approximately $59 million during 1996.
Capital expenditures for current utility operations for 1997 through
1999 are anticipated to be
as follows:
1997 1996
Common stock 45% 45%
Preferred and preference stock 2% 2%
Western Resources obligated
mandatorily redeemable preferred
securities of subsidiary trust holding
solely company subordinated debentures 5% 6%
Long-term debt 48% 47%
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 preferred equity and debt
securities. These ratings indicate the agencies' assessment of our ability to
pay interest, dividends and principal on these securities. These ratings affect
how much we will have to pay as interest or dividends on securities we sell to
obtain additional capital. The better the rating, the less we will have to pay
on preferred equity and debt securities we sell.
At December 31, 1997, ratings with these agencies were as follows:
Kansas Gas
Western Western and Electric
Nuclear Fuel Natural Gas
(Dollars in Thousands)
1997. . . . . $122,900 $21,300 $50,600
1998. . . . . 126,600 21,500 52,100
1999. . . . . 130,400 3,800 53,700
These expenditures are estimates prepared for planning purposes and are
subject to revisions (See Note 8). Electric expenditures would be
significantly more in years after 1997 following consummation of the merger
with KCPL (See Note 2). Natural gas expenditures will be significantly less
in 1997 and subsequent years upon the consummation of the alliance with ONEOK
(see Note 6).
The company expects to improve cash flow in 1997 and subsequent years
when it begins receiving annual dividends from New ONEOK upon consummation of
the alliance with ONEOK.
Cash provided by operating activities has decreased compared to 1995,
but continues to be the primary source for meeting cash requirements. The
company believesResources' Resources' Company's
Mortgage Short-term Mortgage
Bond Debt Bond
Rating Agency Rating Rating Rating
S&P A- A-2 BBB+
Fitch A- F-2 A-
Moody's A3 P-2 A3
FUTURE CASH REQUIREMENTS: We believe that internally generated funds and new
and existing credit agreements will be sufficient to meet its debt service, dividend paymentour operating and
capital expenditure requirements, for its utility operations.
The company,debt service and dividend payments through its wholly-owned subsidiary The Wing Group, has
committedthe
year 2000. Uncertainties affecting our ability to investing at least $136 million through June 1998 for power
generation projects in the People's Republic of China, Turkey and Colombia.
See Notes 4 and 8.
The company will be required to issue a significant number of its
common shares to consummate the transactions discussed above. The company will
also be required to raise a significant amount of funds to consummate the
proposed transactions and to repay short-term debt incurred in connectionmeet these requirements with
completed transactions. The company expects to raise the required funds from
internally generated funds include the effect of competition and frominflation on
operating expenses, sales volume, regulatory actions, compliance with future
environmental regulations, the issuanceavailability of debtgenerating units and equity
securities.weather.
We believe that we will meet the needs of our electric utility customers
without adding any major generation facilities in the next five years.
Our business requires a significant capital investment. We currently expect
that through the year 2000, we will need cash mostly for:
- Ongoing utility construction and maintenance program designed to
maintain and improve facilities providing electric service
- Growth within the security alarm monitoring business, including
acquisition of subscriber accounts
- Investment opportunities in international power development projects
and generation facilities
- Expansion of our nonregulated operations
Capital expenditures for 1997 and anticipated capital expenditures for 1998
through 2000 are as follows:
Security
Alarm
Electric Monitoring International Other Total
(Dollars in Thousands)
1997. . . . . $159,800 $ 45,200 $30,500 $17,300 $252,800
1998. . . . . 142,000 216,900 52,500 41,700 453,100
1999. . . . . 121,400 263,200 79,200 11,700 475,500
2000. . . . . 137,800 280,800 9,200 800 428,600
Capital expenditures in 1997 included an additional $47 million in
improvements to our natural gas system. Because we contributed our natural gas
business net assets to ONEOK, we will not incur any direct capital expenditures
related to that business in future years.
"Electric" capital expenditures include the cost of nuclear fuel. "Security
Alarm Monitoring" capital expenditures include anticipated acquisitions of
subscriber accounts.
"International" expenditures include commitments to international power
development projects and generation facilities. "Other" primarily represents
our commitments to our Affordable Housing Tax Credit program (AHTC). See
Notes 2discussion in "Other Information" below.
These estimates are prepared for planning purposes and 3 for additional discussion regarding the
proposed transactions of KCPL and ADT.
The company's capital needs through 2001 for bond maturities are
approximately $200 million. This capitalmay be revised (see
Note 7). Electric expenditures will be provided from internalsignificantly more than shown in the
table above if we complete the merger with KCPL (see Note 5).
Bond maturities and external sources available
under then existing financial conditions. There are no cashpreference stock sinking fund requirements for bonds or preference stockwill require
cash of approximately $303 million through the year 2001.
On July 1, 1996, all shares2002. Protection One is
required to retire long-term debt of the company's 8.50% Preference Stock due
2016 were redeemed.
On July 31, 1996 Western Resources Capital II, a wholly-owned trust,approximately $63 million through 1999.
Our currently authorized quarterly dividend of which the sole asset53 1/2 cents per common share
or $2.14 on an annual basis is subordinated debenturespaid from our earnings. The payment of the company, 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
represented by the preferred securities are redeemabledividends
is at the optiondiscretion of Western Resources Capital II, on or after July 31, 2001, at $25 per preferred
security plus accumulated and unpaid distributions. Holdersour board of directors. Each quarter, 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
in substance are tax deductible by the company. These distributions are
recorded as interest chargesboard makes
a determination on the Consolidated Statements of Income. 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. These preferred
securities are included under Western Resources Obligated Mandatorily
Redeemable Preferred Securities of Subsidiary Trusts holding solely company
Subordinated Debentures (Other Mandatorily Redeemable Securities) ondividends to declare, considering such matters
as future earnings expectations and our financial condition.
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
Consolidated Balance Sheets and Consolidated Statements of Capitalization (See
Note 11).electricity industry. The company's short-term financing requirements are satisfied, as
needed, through the sale of commercial paper, short-term bank loans and
borrowings under lines of credit maintained with banks. At December 31, 1996,
short-term borrowings amounted to $981 million, of which $293 million was
commercial paper (See Notes 14 and 15). At December 31, 1996, the company had
committed credit arrangements available of $973 million.
The company's short-term debt balance at December 31, 1996, increased
approximately $777 million from December 31, 1995. The increase was primarily
a result of the company's purchases of an approximate 27% common equity
interest in ADT and its purchase of WSS. See Notes 3 and 4 for further
discussion of these purchases.
On February 12, 1997, the company filed an application with the KCC to
issue $550 million in first mortgage bonds or senior unsecured debt to
refinance short-term and long-term debt and for other corporate purposes.
The embedded cost of long-term debt, excluding the revolving credit
facility, was 7.6% at December 31, 1996, a decrease from 7.7% at December 31,
1995. Lower interest rates on the company's variable rate pollution control
bonds resulted in this decrease.
The company has a Dividend Reinvestment and Stock Purchase Plan
(DRIP). Shares issued under the DRIP may be either original issue shares or
shares purchased on the open market. The company has been issuing original
issue shares since January 1, 1995 with 935,461 shares issued in 1996 under the
DRIP.
The company's capital structure at December 31, 1996, was 45% common
stock equity, 2% preferred and preference stock, 6% other mandatorily redeemable
securities, and 47% long-term debt. The capital structure at December 31,
1996, including short-term debt and current maturities of long-term debt, was
35% common stock equity, 2% preferred and preference stock, 5% other
mandatorily redeemable securities, and 58% debt.
As of December 31, 1996, the company's bonds were rated "A3" by Moody's
Investors Service, "A-" by Fitch Investors Service, and "A-" by Standard &
Poor's Ratings Group (S&P). In January of 1997, reflecting S&P's increased
financial rating standards and as a result of the company's increased
short-term debt related to its acquisitions, S&P regraded the company's bond
rating to BBB+. Pending the resolution of the ADT Offer, the company remains on
CreditWatch with negative implications with S&P.
RESULTS OF OPERATIONS
The following is an explanation of significant variations from prior
year results in revenues, operating expenses, other income and deductions,
interest charges, and preferred and preference dividend requirements. The
results of operations of the company exclude the activities related to the
Missouri Properties following the sales of those properties in the first
quarter of 1994. For additional information regarding the sales of the Missouri
Properties, see Note 19.
REVENUES
The operating revenues of the company are based on sales volumes and
rates authorized by certain state regulatory commissions andEnergy Policy Act permitted the Federal Energy
Regulatory Commission (FERC). Future electric and natural gas sales will be
affected by weather conditions, the electric rate reduction which was
implemented on February 1, 1997, changes in the industry, changes in the
regulatory environment, competition from other sources of energy, competing
fuel sources, customer conservation efforts, and the overall economy of the
company's service area.
Electric fuel costs are included in base rates. Therefore, if the
company wished to recover an increase in fuel costs, it would have to file a
request for recovery in a rate filing with the Kansas Corporation Commission
(KCC) which could be denied in whole or in part. The company's fuel costs
represented 17% of its total operating expenses for the years ended December
31, 1996 and 1995. Any increase in fuel costs from the projected average
which the company did not recover through rates would reduce the company's
earnings. The degree of any such impact would be affected by a variety of
factors, however, and thus cannot be predicted.
1996 Compared to 1995: Electric revenues were five percent higher in
1996 compared to 1995 due to higher sales in the residential and commercial
customer classes as a result of colder winter and warmer spring temperatures
experienced during the first six months of 1996 compared to 1995. The
company's service territory experienced a 17% increase in heating degree days
during the first quarter and cooling degree days more than doubled during the
second quarter of 1996 compared to the same periods in 1995. Wholesale and
interchange sales were also higher due to an increased number of customers.
Partially offsetting this increase was abnormally cool summer weather during
the third quarter of 1996 compared to 1995 and the $8.7 million electric rate
reduction to KGE customers implemented on an interim basis on May 23, 1996 and
made permanent on January 15, 1997. For more information related to electric
rate decreases, see Note 9.
Regulated natural gas revenues increased 29% for 1996 as compared to
1995 as a result of colder winter temperatures, higher gas costs passed on to
customers through the cost of gas rider (COGR), and increased as-available gas
sales. Regulated natural gas revenues for the last six months of 1996 were
also higher due to the gas revenue increase ordered by the KCC on July 11,
1996. For additional information on the gas rate increase, see Note 9.
As-available gas is excess natural gas under contract that the company
did not require for customer sales or storage that is typically sold to gas
marketers. According to the company's tariff, the nominal margin made on
as-available gas sales, is returned 75% to customers through the COGR and 25%
is reflected in wholesale revenues of the company.
Natural gas revenues will be significantly less in 1997 and subsequent
years following consummation of the alliance with ONEOK (see Note 6).
Non-regulated gas revenues increased from approximately $170 million to
approximately $250 million, or 47%, for 1996 as compared to 1995 as a result
of a 12% increase in sales volumes of the company's wholly-owned subsidiary
Westar Gas Marketing, Inc. (Westar Gas Marketing). When the alliance with
ONEOK is complete, Westar Gas Marketing will be transferred to New ONEOK.
1995 Compared to 1994: Electric revenues increased two percent in
1995 as a result of increased sales in all customer classes. The increase is
primarily attributable to a higher demand for air conditioning load during the
summer months of 1995 compared to 1994. The company's service territory
experienced normal temperatures during the summer of 1995, but were more than
20% warmer, based on cooling degree days, compared to the summer of 1994.
Natural gas revenues decreased in 1995 primarily as a result of the
sales of Missouri Properties in the first quarter of 1994. The Consolidated
Statements of Income include revenues of $77 million related to the Missouri
Properties for the first quarter of 1994.
Excluding natural gas sales related to the Missouri Properties, natural
gas revenues increased six percent due to an increase in non-regulated gas
revenues. Non-regulated gas revenues increased from approximately $145
million to approximately $170 million, or 17%, for 1995 as compared to 1994 as
a result of a 44% increase in sales volumes of Westar Gas Marketing.
OPERATING EXPENSES
1996 Compared to 1995: A 19% increase in total operating expenses in
1996 compared to 1995 is primarily due to a full year of amortization of the
acquisition adjustment related to the acquisition of KGE in 1992 and
increased fuel expense, purchased power, and natural gas purchases for
electric generating stations due to Wolf Creek having been taken off-line for
its eighth refueling and maintenance outage during the first quarter of 1996.
Also contributing to the increases in fuel and purchased power expenses was
the increased net generation due to the increase in customer demand for air
conditioning load during the second quarter of 1996. The increase in
operating expenses was partially offset by decreased maintenance expense and
income tax expense.
1995 Compared to 1994: Total operating expenses decreased two percent
in 1995 compared to 1994. The decrease is largely due to the sales of the
Missouri Properties, lower natural gas purchases resulting from lower sales,
and lower fuel expense resulting from a lower unit cost of fuel used for
generation.
Partially offsetting this decrease were expenses related to an early
retirement program. In the second quarter of 1995, $7.6 million related to
early retirement programs was recorded as an expense.
OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of
taxes, decreased for the year ended December 31, 1996 compared to 1995
primarily as a result of a decrease in certain miscellaneous regulated gas
revenues which ceased during 1996 in accordance with a KCC order.
Other income and deductions, net of taxes, decreased for the twelve
months ended December 31, 1995 compared to 1994 as a result of the gain on the
sales of the Missouri Properties recorded in the first quarter of 1994.
INTEREST CHARGES AND PREFERRED AND PREFERENCE DIVIDEND
REQUIREMENTS:
Total interest charges increased 22% for the twelve months ended December 31,
1996 as compared to 1995 due to increased interest expense on higher balances of
the mandatorily redeemable preferred securities and increases in short-term
borrowings to finance the purchase of the investment in ADT. Total interest
charges increased three percent for the twelve months ended December 31, 1995
as compared to 1994, primarily due to higher debt balances and higher interest
rates on short-term borrowings and variable long-term debt.
KGE MERGER IMPLEMENTATION: In accordance with the KCC KGE merger
order, amortization of the acquisition adjustment commenced August 1995. The
amortization will amount to approximately $20 million (pre-tax) per year for
40 years. The company is recovering the amortization of the acquisition
adjustment through cost savings under a sharing mechanism approved by the KCC.
Based on the order issued by the KCC, with regard to the recovery of
the acquisition premium, the company must achieve a level of savings on an
annual basis (considering sharing provisions) of approximately $27 million in
order to recover the entire acquisition premium.
On January 15, 1997, the KCC fixed the annual merger savings level at
$40 million which provides complete recovery of the acquisition premium
amortization expense and a return on the acquisition premium. See Note 9 for
further information relating to rate matters and regulation.
As management presently expects to continue this level of savings, the
amount is expected to be sufficient to allow for the full recovery of the
acquisition premium.
OTHER INFORMATION
INFLATION: Under the rate making procedures prescribed by the
regulatory commissions to which the company is subject, only the original cost
of plant is recoverable in rates charged to customers. Therefore, because of
inflation, present and future depreciation provisions are inadequate for
purposes of maintaining the purchasing power invested by common shareowners
and the related cash flows are inadequate for replacing property. The impact
of this ratemaking process on common shareowners is mitigated to the extent
depreciable property is financed with debt that can be repaid with dollars of
less purchasing power. While the company has experienced relatively low
inflation in the recent past, the cumulative effect of inflation on operating
costs may require the company to seek regulatory rate relief to recover these
higher costs.
ENVIRONMENTAL: The company has taken a proactive position with
respect to the potential environmental liability associated with former
manufactured gas sites and has an agreement with the Kansas Department of
Health and Environment to systematically
evaluate these sites in Kansas. In accordance with the terms of the ONEOK
agreement, ownership of twelve of the fifteen aforementioned sites will be
transferred to New ONEOK upon consummation of the ONEOK alliance. The ONEOK
agreement limits the company's liabilities to an immaterial amount for future
remediation of these sites.
The company is one of numerous potentially responsible parties at a
groundwater contamination site in Wichita, Kansas which is listed by the
Environmental Protection Agency (EPA) as a Superfund site.
The nitrogen oxides (NOx) and toxic limits, which were not set in the
law, were proposed by the EPA in January 1996. The company is currently
evaluating the steps it will need to take in order to comply with the proposed
new. The company will have three years from the date the limits were proposed
to comply with the new NOx rules. See Note 8 for more information regarding
environmental matters.
DECOMMISSIONING: The staff of the SEC has questioned certain current
accounting practices used by nuclear electric generating station owners
regarding the recognition, measurement, and classification of decommissioning
costs for nuclear electric generating stations. In response to these
questions, the Financial Accounting Standards Board is expected to issue new
accounting standards for closure and removal costs, including decommissioning,
in 1997. The company is not able to predict what effect such changes would
have on its results of operations, financial position, or related regulatory
practices until the final issuance of revised accounting guidance, but such
effect could be material. Refer to Note 8 for additional information relating
to new accounting standards for decommissioning.
On August 30, 1996, Wolf Creek Nuclear Operating Corporation submitted
the 1996 Decommissioning Cost Study to the KCC for approval. Approval of this
study was received from the KCC on February 28, 1997. Based on the study, the
company's share of these decommissioning costs, under the immediate
dismantlement method, is estimated to be approximately $624 million during the
period 2025 through 2033, or approximately $192 million in 1996 dollars.
These costs were calculated using an assumed inflation rate of 3.6% over the
remaining service life from 1996 of 29 years. Refer to Note 8 for additional
information relating to the 1996 Decommissioning Cost Study.
CORPORATE-OWNED LIFE INSURANCE: A regulatory asset totaling $41
million and $35 million is outstanding at December 31, 1996 and 1995,
respectively related to deferred postretirement and postemployment costs. In
order to offset these costs, the company purchased corporate-owned life
insurance (COLI) policies on its employees in 1992 and 1993. On August 2, 1996,
Congress passed legislation that will phase out tax benefits associated with
the 1992 and 1993 COLI contracts. The loss of tax benefits will significantly
reduce the COLI earnings. The company is evaluating other methods to replace
the 1992 and 1993 COLI contracts. The company also has the ability to seek
recovery of postretirement and postemployment costs through the ratemaking
process. Regulatory precedents established by the KCC are expected to permit
the accrued costs of postretirement and postemployment benefits to be
recovered in rates. If these costs cannot be recovered in rates, the company
will be required to expense the regulatory asset. (See Notes 1 and 12.)
COMPETITION AND ENHANCED BUSINESS OPPORTUNITIES: The electric and
natural gas utility industry in the United States is rapidly evolving from an
historically regulated monopolistic market to a dynamic and competitive
integrated marketplace. The 1992 Energy Policy Act (Act) began the process of
deregulation of the electricity industry by permitting the FERC to order electric utilities to allow third parties
the use of their transmission systems to sell electric power to wholesale
customers over their transmission systems.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, the companywe agreed to open access of
itsour 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 1996,1997, wholesale electric revenues represented
approximately 12% of the company's total electric revenues.
Since that time, the wholesale electricity market has become
increasingly competitive as companies begin to engage in nationwide power
brokerage. In addition, variousVarious states including California and New York have taken active steps toward allowingto allow retail customers to purchase
electric power from third-party providers. In 1996, the KCC initiatedproviders other than their local utility company. The Kansas
Legislature has created a generic docketRetail Wheeling Task Force (the Task Force) to study
the effects of a deregulated and competitive market for electric restructuring issues. Aservices.
Legislators, regulators, consumer advocates and representatives from the
electric industry make up the Task Force. The Task Force submitted a bill to
the Kansas Legislature without recommendation. This bill seeks competitive
retail wheeling task force has been
createdelectric service on July 1, 2001. The bill was introduced to the Kansas
Legislature in the opening days of the 1998 legislative session, but is not
expected to come to a vote this year. The Task Force also is evaluating how
to recover certain investments in generation and related facilities which were
approved and incurred under the existing regulatory model. Some of these
investments may not be recoverable in a competitive marketplace. We have
opposed the Task Force's bill for this reason. These unrecovered investments
are commonly called "stranded costs." See "Stranded Costs" below for further
discussion. Until a bill is passed by the Kansas Legislature, to study competitive trends in retail electric
services. Duringwe cannot predict
its impact on our company, but the 1997 session of the Kansas Legislature, bills have been
introduced to increase competition in the electric industry. Among the
matters under consideration is the recovery by utilities of costs in excess of
competitive cost levels. There canimpact could be no assurance at this time that such
costs will be recoverable if open competition is initiated in the electric
utility market.
The natural gas industry has been substantially deregulated, with
FERC and many state regulators requiring local natural gas distribution
companies to allow wholesale and retail customers to purchase gas from
third-party providers.
Thematerial.
We believe successful providers of energy in a deregulated market will
not
only provide electric or natural gas service but also a variety of other
services, including security. The company believes that in the newly
deregulated environment, more sophisticatedenergy-related services. We believe consumers will continue to demand
new and innovative
options and insist on the development of more efficient products and services to meet their
energy-related needs. The company believesWe believe that itsour strong core utility business provides
it with thea platform to offer the more efficient energy products and energy services that customers
will desire. Furthermore, the company believes it is necessaryWe continue to continuously seek new ways to add value to its customers'the lives and
businesses. Recognizingbusinesses of our customers. We recognize that itsour current customer base must
expand beyond itsour existing service area, the
company viewsarea. We view every person whether in the United
States orand abroad as a potential customer.
The company also recognizes that its potential to emerge
as a leading national energy and energy-related services provider is enhanced
by having a strong brand name. The company has been establishing its brand
identity through the Westar Security name. The combination of the company and
ADT would immediately provide an ideal brand name to capitalize on the
emerging security and energy marketplaces.
Although the company has been planning for the deregulation of the
energy market, increasedIncreased competition for retail electricity sales may in thereduce future reduce the company'selectric
utility earnings compared to our historical electric utility earnings. After
all electric rate decreases are implemented, our rates will range from its formerly regulated business.
During 1995, however, the company's average retail electric rates were over
9% below73% to
91% of the national average and continue to be competitive within the
midwestern United States. In 1997, the company furtherfor retail customers. Because of these reduced
its retail rates, and expects to be ablewe expect to retain a substantial portionpart of itsour current sales volume in a
competitive environment. Finally, we believe the company believes that the
deregulation of thederegulated energy market may
prove beneficial to the company, since
any potentialus. We also plan to compensate for competitive pressure
in its formerlyour current regulated business is
expected to be more than offset bywith the nationwide markets which the company
expects to enter by offering energy and security alarm monitoring
services we offer to customers.
OperatingWhile operating in this competitive environment willmay place pressure on utilityour
profit margins, common dividends and credit quality.ratings, we expect it to create
opportunities. Wholesale and industrial customers may threaten to pursue cogeneration,
self-generation, retail wheeling, municipalization or relocation to other
service territories in an attempt to obtain reducedcut their energy costs. Increasing competition has resulted in creditCredit rating
agencies are applying more stringent guidelines when makingrating utility credit rating determinations. See discussioncompanies
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.
In light of competitive developments, we are pursuing the following strategic
plan:
- Maintain a strong core energy business
- Build a national branded presence
- Create value through energy-related investments
To better position ourselves for the competitive energy environment, we have
consummated a strategic alliance with ONEOK (see Note 4), have acquired a
controlling interest in Protection One (see Note 3) and continue to develop
international power projects.
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 generation, transmission and distribution 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) in "Regulatory" below.
The company is providing competitive electric rates for industrial
expansion projects and economic development projects in an effort to maintain
and increase electric load. During 1996, the company lost a major industrial
customer to cogeneration resulting in a reduction to pre-tax earnings of $8.6
million annually. This customer's decision to develop its own cogeneration
project was based largely on factors unique to the customer, other than energy
cost.
In light of these developments, the company is pursuing the following
strategic plan: 1) maintain a strong core energy business; 2) build a national
branded presence; and 3) become a leader in the international energy business.
In order to be better positioned for the competitive environment in the energy
industry, the company is pursuing a merger with KCPL (see Note 2), seeking to
acquire ADT (see Note 3), planning a strategic alliance with ONEOK (see Note
6), and developing international power projects through its wholly-owned
subsidiary, The Wing Group (see Note 4).
REGULATORY: On April 24, 1996, FERC issued its final rule on Order No.
888, "Promoting Wholesale Competition Through Open Access Non-discriminatory
Transmission Services by Public Utilities; Recovery of Stranded Costs by
Public Utilities and Transmitting Utilities". The company does not presently
expect the order towe may have a material effect on its operations in large part
because it is already operating in substantially the required manner due to
its agreement with the KCC during the merger with KGE (See discussion above in
"Competition and Enhanced Business Opportunities").
On May 23, 1996, the company implemented an $8.7 million electric rate
reduction to KGE customers on an interim basis. On October 22, 1996, the
company, the KCC Staff, the City of Wichita, and the Citizens Utility
Ratepayer Board filed an agreement at the KCC whereby the company's retail
electric rates would be reduced, subject to approval by the KCC. This
agreement was approved by the KCC on January 15, 1997. Under the agreement,
on February 1, 1997, KGE's rates were reduced by $36.3 million and the May,
1996 interim reduction became permanent. KGE's rates will be reduced by
another $10 million effective June 1, 1998, and again on June 1, 1999. KPL's
rates were reduced by $10 million effective February 1, 1997. Two one-time
rebates of $5 million will be credited to the company's customers in January
1998 and 1999. The agreement also fixed annual savings from the merger with
KGE at $40 million. This level of merger savings provides for complete
recovery of the acquisition premium amortization expense and a return on the
acquisition premium. See Note 9 for additional information regarding rate
matters.
On August 22, 1996, the company filed with the FERC an application for
approval of its proposed merger with KCPL. On December 18, 1996, the FERC
issued a Merger Policy Statement (Policy Statement) which articulates three
principal factors the FERC will apply for analyzing mergers: (1) effect on
competition, (2) customer protection, and (3) effect on regulation. The FERC
has requested the company to and pursuant to the FERC request, the company
will revise its filing to comply with the specific requirements of the Policy
Statement.
STRANDED COSTS: The company currently applies accounting standards
that recognize the economic effects of rate regulation, SFAS 71, and,
accordingly, has recorded regulatory assets and liabilities related to its
generation, transmission and distribution operations. In the event the company
determines that it no longer meets the criteria set forth in SFAS 71, the
accounting impact would be an extraordinary non-cash charge to operations of an amount that would be material. Criteria
that give rise to the discontinuance ofoperations.
Reasons for discontinuing SFAS 71 include: (1)accounting treatment include increasing
competition that restricts the company'sour ability to establishcharge prices needed to recover specific costs
already incurred and (2) a significant change in the manner in which
rates are set by regulators from a cost-based rate
regulation to another form of rate regulation. The companyWe periodically reviews these criteria to ensure the
continuing application ofreview SFAS 71
is appropriate. Based on current evaluation
of the various factorscriteria and conditions that are expected to impact future cost
recovery, the company believes that itsbelieve our net regulatory assets, including those related to
generation, are probable of future recovery. Any regulatory changes that would require the company toIf we discontinue SFAS 71
accounting treatment based upon competitive or other events, we may
significantly impact the valuationvalue of the company'sour net regulatory assets and itsour utility
plant investments, particularly the Wolf Creek facility. At this time, the
effect of competition and the amount of regulatory assets which could be
recovered in such an environment cannot be predicted. See discussion of "Competition and
Enhanced Business Opportunities" above for initiatives taken to restructure the
electric industry in Kansas.
The term "stranded costs" as it relates to capital intensive utilities
has been defined as investment in and carrying costs associated with property,
plant and equipment and other regulatory assets in excess of the level which
can be recovered in the competitive market in which the utility operates.
Regulatory changes, including the introduction of competition, could adversely impact the company'sour ability
to recover its costsour investment in these assets. As of December 31, 1996, the company has1997, we have
recorded regulatory assets which are currently subject to recovery in future
rates of approximately $458$380 million. Of this amount, $217$213 million representsis a
receivable for income tax benefits flow-throughpreviously passed on to customers. The
remainder of the regulatory assets representare items that may give rise to stranded
costs including coal contract settlement costs, deferred employee benefit costs,
deferred plant costs and debt issuance costs,
deferred post employment/retirement benefits and deferred contract settlement
costs.
Finally, the company's abilityIn a competitive environment, we may not be able to fully recover its utility plant
investments in, and decommissioning cost for, generating facilities,
particularly Wolf Creek, may be at risk in a competitive environment. This
risk will become more significant as a result of the proposed KCPL Merger as
KCPL presently owns a 47% undivided interestour entire
investment in Wolf Creek. Amounts
associated withWe presently own 47% of Wolf Creek. Our ownership
would increase to 94% if the company's recovery ofKCPL merger is completed. We also may have
stranded costs from an inability to recover our environmental remediation
costs and long-term fuel contract costs cannot be estimated with any certainty, but also
represent items that could give rise to "stranded costs" in a competitive environment. In the eventIf we
determine that the company was not allowed towe have stranded costs and we cannot recover itsour 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.
YEAR 2000 ISSUE: We are currently addressing the effect of the Year 2000
Issue on our reporting 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 may incorrectly process critical
financial and operational information, or stop processing altogether because of
the date abbreviation. Calculations using the year 2000 will affect computer
applications before January 1, 2000.
We have recognized the potential adverse effects the Year 2000 Issue could
have on our company. In 1996, we established a formal Year 2000 remediation
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 company. The goal of our program is to identify and
assess every critical system potentially affected by the year 2000 date change
and to repair or replace those systems found to be incompatible with year 2000
dates.
We plan to have our year 2000 readiness efforts substantially completed by
the end of 1998. We expect no significant operational impact on our ability to
serve our customers, pay suppliers, or operate other areas of our business.
We currently estimate that total costs to update all of our systems for year
2000 compliance will be approximately $7 million. In 1997, we expensed
approximately $3 million of these costs and based on what we now know, we expect
to incur about $4 million in 1998 to complete our efforts.
AFFORDABLE HOUSING TAX CREDIT PROGRAM: We have 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, 1997, the company had invested approximately $17
million to purchase limited partnership interests. We are committed to
investing approximately $55 million more in AHTC investments by January 1, 2000.
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. Tax
credits are recognized in the year generated.
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 SEC staff has questioned the way electric utilities recognize, measure
and classify decommissioning costs for nuclear electric generating stations in
their financial statements. In response to the SEC's questions, 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 1997
- 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 7).
REGULATORY ISSUES: On November 27, 1996, the KCC issued a Suspension Order
and on December 3, 1996, the KCC issued an order which suspended, subject to
refund, the collection of costs related to purchases from Kansas Pipeline
Partnership included in our cost of natural gas. On November 25, 1997, the KCC
issued its order lifting the suspension and closing the docket.
PRONOUNCEMENT ISSUED BUT NOT YET EFFECTIVE: In January 1998, the company
adopted Statement of Financial Accounting Standards No. 131, "Disclosures about
Segments of an Enterprise and Related Information" (SFAS 131). This statement
establishes standards for public business enterprises to report information
about operating segments in interim and annual financial statements. Interim
disclosure requirements are not required until 1999. Operating segments are
defined as components of an enterprise about which separate financial
information is available that is evaluated regularly by the chief operating
decision maker in deciding how to allocate resources and assess performance.
Adoption of the disclosure requirements of SFAS 131 will impact would be a charge to its
resultsthe
presentation of operations that would be material. If completed, the proposed KCPL
Merger and the proposed strategic alliance with ONEOK will increase the company's exposure to potential stranded costs.
business segments.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 4039
Financial Statements:
Consolidated Balance Sheets, December 31, 1997 and 1996 and 1995 4140
Consolidated Statements of Income for the years ended
December 31, 1997, 1996 and 1995 and 1994 4241
Consolidated Statements of Cash Flows for the years ended
1997, 1996 and 1995 42
Consolidated Statements of Cumulative Preferred and
1994Preference Stock, December 31, 1997 and 1996 43
Consolidated Statements of Taxes for the years ended
December 31, 1996, 1995 and 1994 44
Consolidated Statements of Capitalization, December 31, 1996
and 1995 45
Consolidated Statements of Common StockShareowners' Equity for
the years ended December 31, 1997, 1996 and 1995 and 1994 4644
Notes to Consolidated Financial Statements 4745
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 the financial
statements and schedules presented:
I, II, III, IV, and V.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareowners and Board of Directors
of Western Resources, Inc.:
We have audited the accompanying consolidated balance sheets and statements
of capitalizationcumulative preferred and preference stock of Western Resources, Inc., and
subsidiaries as of December 31, 19961997 and 1995,1996, and the related consolidated
statements of income, cash flows, taxes and common stockshareowners' equity for each of the
three years in the period ended December 31, 1996.1997. 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 generally accepted auditing
standards. 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 consolidated financial position of Western
Resources, Inc., and subsidiaries as of December 31, 19961997 and 1995,1996, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996,1997, in conformity with generally
accepted accounting principles.
As explained in Note 12 to the consolidated financial statements,
effective January 1, 1994, the company changed its method of accounting for
postemployment benefits.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 24, 1997
(February 7, 1997 with
respect to Note 2 of
the Notes to Consolidated
Financial Statements.)
29, 1998
WESTERN RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
December 31,
1997 1996
1995ASSETS
ASSETS
UTILITY PLANT (Notes 1CURRENT ASSETS:
Cash and 17):
Electric plant in servicecash equivalents . . . . . . . . . . . . . . . . $5,536,256 $5,341,074
Natural gas plant in service.$ 76,608 $ 3,724
Accounts receivable (net) . . . . . . . . . . . . . . 834,330 787,453
6,370,586 6,128,527
Less - Accumulated depreciation . . . . . . . . . . . . . 2,146,363 1,926,520
4,224,223 4,202,007
Construction work in progress 325,043 318,966
Inventories and supplies (net). . . . . . . . . . . . . . 93,834 100,401
Nuclear fuel86,398 135,255
Marketable securities . . . . . . . . . . . . . . . . . . 75,258 -
Prepaid expenses and other. . . . . . . . . . . . . . . . 25,483 36,503
Total Current Assets. . . . . . . . . . . . . . . . . . 588,790 494,448
PROPERTY, PLANT AND EQUIPMENT, NET. . . . . . . . . . . . . 3,786,528 4,384,017
OTHER ASSETS:
Investment in ADT . . . . . . . . . . . . . . . . . . . . - 590,102
Investment in ONEOK . . . . . . . . . . . . . . . . . . . 596,206 -
Subscriber accounts . . . . . . . . . . . . . . . . . . . 549,152 265,530
Goodwill (net). . . . . . . . . . . . . . . . . . . . 38,461 53,942
Net utility plant.. . 854,163 225,892
Regulatory assets . . . . . . . . . . . . . . . . . . 4,356,518 4,356,350
INVESTMENTS AND OTHER PROPERTY:
Investment in ADT (net) . . . . . . . . . . . . . . . . . 590,102 -
Security business and other property. . . . . . . . . . . 584,647 99,269
Decommissioning trust (Note 8). . . . . . . . . . . . . . 33,041 25,070
1,207,790 124,339
CURRENT ASSETS:
Cash and cash equivalents (Note 1). . . . . . . . . . . . 3,724 2,414
Accounts receivable and unbilled revenues (net) (Note 1). 318,966 257,292
Fossil fuel, at average cost. . . . . . . . . . . . . . . 39,061 54,742
Gas stored underground, at average cost . . . . . . . . . 30,027 28,106
Materials and supplies, at average cost . . . . . . . . . 66,167 57,996
Prepayments and other current assets. . . . . . . . . . . 36,503 20,426
494,448 420,976
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 10). . . . . . . . . . 217,257 282,476
Corporate-owned life insurance (net) (Notes 1 and 12) . . 86,179 44,143
Regulatory assets (Note 9). . . . . . . . . . . . . . . . 241,039 262,393380,421 458,296
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 44,550 -
589,025 589,012221,700 229,496
Total Other Assets. . . . . . . . . . . . . . . . . . . 2,601,642 1,769,316
TOTAL ASSETSASSETS. . . . . . . . . . . . . . . . . . . . . . . . $6,976,960 $6,647,781
$5,490,677
CAPITALIZATIONLIABILITIES AND LIABILITIES
CAPITALIZATION (See statements):
Common stock equitySHAREOWNERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt. . . . . . . . . . . $ 21,217 $ -
Short-term debt . . . . . . . . . . . . . . . . . . . $1,624,680 $1,553,110
Cumulative preferred and preference stock . . . . . . . . 74,858 174,858
Western Resources obligated mandatorily redeemable
preferred securities of subsidiary trusts holding
solely company subordinated debentures. . . . . . . . . 220,000 100,000
Long-term debt (net). . . . . . . . . . . . . . . . . . . 1,681,583 1,391,263
3,601,121 3,219,231
CURRENT LIABILITIES:
Short-term debt (Note 15) . . . . . . . . . . . . . . . .236,500 980,740 203,450
Long-term debt due within one year (Note 14). . . . . . . - 16,000
Accounts payable. . . . . . . . . . . . . . . . . . . . . 151,166 180,540
149,194
Accrued taxesliabilities . . . . . . . . . . . . . . . . . . . . . . 83,813 68,569249,447 140,204
Accrued interest and dividends.income taxes. . . . . . . . . . . . . . 70,193 62,157. . . . . 27,360 27,053
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 36,806 40,266
1,352,092 539,636
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Note 10)89,106 23,555
Total Current Liabilities . . . . . . . . . . . . . 1,110,372 1,167,470
Deferred investment tax credits (Note 10) . . 774,796 1,352,092
LONG-TERM LIABILITIES:
Long-term debt (net). . . . . . . . 125,528 132,286
Deferred gain from sale-leaseback (Note 16) . . . . . . . . . . . 2,181,855 1,681,583
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. . . . . 1,065,565 1,235,900
Minority interests. . . . . . . . . . . . . . . . . . . . 164,379 -
Deferred gain from sale-leaseback . . . . . . . . . . . . 221,779 233,060 242,700
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 259,521 225,608
189,354
1,694,568 1,731,810
COMMITMENTS AND CONTINGENCIES (Notes 7 and 8)
TOTAL CAPITALIZATION AND LIABILITIES.Total Long-term Liabilities . . . . . . . . . . . . . . 4,113,099 3,596,151
COMMITMENTS AND CONTINGENCIES
SHAREOWNERS' EQUITY:
Cumulative preferred and preference stock . . . . . . . . 74,858 74,858
Common stock, par value $5 per share, authorized
85,000,000 shares, outstanding 65,409,603 and
64,625,259 shares, respectively . . . . . . . . . . . . 327,048 323,126
Paid-in capital . . . . . . . . . . . . . . . . . . . . . 760,553 739,433
Retained earnings . . . . . . . . . . . . . . . . . . . . 914,487 562,121
Net change in unrealized gain on equity securities (net). 12,119 -
Total Shareowners' Equity . . . . . . . . . . . . . . . 2,089,065 1,699,538
TOTAL LIABILITIES & SHAREOWNERS' EQUITY . . . . . . . . . . $6,976,960 $6,647,781 $5,490,677
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
Year Ended December 31,
1997 1996 1995 1994(1)
OPERATING REVENUES (Notes 1 and 9):
Electric.SALES:
Energy. . . . . . . . . . . . . . . . . . . . . . . $1,197,433 $1,145,895 $1,121,781
Natural gas . . . . . . . . . . . . . . . . . . . . . 849,386 597,405 642,988
Total operating revenues. . . . . . . . . . . . . . 2,046,819 1,743,300 1,764,769
OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . . . . . . 245,990 211,994 220,766
Nuclear fuel (net). . . . . . . . . . . . . . . . . 19,962 19,425 13,562
Power purchased . . . . . . . . . . . . . . . . . . . 27,592 15,739 15,438
Natural gas purchases . . . . . . . . . . . . . . . . 354,755 263,790 312,576
Other operations. . . . . . . . . . . . . . . . . . . 607,995 479,136 438,945
Maintenance . . . . . . . . . . . . . . . . . . . . . 99,122 108,641 113,186
Depreciation and amortization . . . . . . . . . . . . 183,722 160,285 157,398
Amortization of phase-in revenues . . . . . . . . . . 17,544 17,545 17,544
Taxes (See Statements):
Federal income. . . . . . . . . . . . . . . . . . . 70,057 72,314 76,477
State income. . . . . . . . . . . . . . . . . . . . 19,035 18,883 19,145
General$1,999,418 $2,038,281 $1,743,930
Security. . . . . . . . . . . . . . . . . . . . . . . 97,052 96,839 104,682152,347 8,546 344
Total operating expenses. . . . . . . . . . . . . 1,742,826 1,464,591 1,489,719
OPERATING INCOME.Sales . . . . . . . . . . . . . . . . . . . 303,993 278,709 275,050
OTHER INCOME AND DEDUCTIONS:
Corporate-owned life insurance (net). . . . . . . . . (2,249) (2,668) (5,354)
Gain on sales of Missouri Properties (Note 19). . . . - - 30,701
Special charges from ADT (Note 3) . . . . . . . . . . (18,181) - -
Equity in earnings of investees and other (net) . . . 31,723 19,925 10,296
Income taxes (net) (See Statements) . . . . . . . . . 2,990 7,805 (4,329)
Total other income and deductions . . . . . . . . 14,283 25,062 31,314
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 318,276 303,771
306,364
INTEREST CHARGES:
Long-term debt.2,151,765 2,046,827 1,744,274
COST OF SALES:
Energy. . . . . . . . . . . . . . . . . . . . 105,741 95,962 98,483. . . . 928,324 879,328 658,935
Security. . . . . . . . . . . . . . . . . . . . . . . 38,800 3,798 68
Total Cost of Sales . . . . . . . . . . . . . . . . 967,124 883,126 659,003
GROSS PROFIT. . . . . . . . . . . . . . . . . . . . . . 1,184,641 1,163,701 1,085,271
OPERATING EXPENSES:
Operating and maintenance expense . . . . . . . . . . 383,912 374,369 351,589
Depreciation and amortization . . . . . . . . . . . . 256,725 201,331 177,830
Selling, general and administrative expense . . . . . 312,927 199,448 182,131
Write-off of deferred merger costs. . . . . . . . . . 48,008 - -
Security asset impairment charge. . . . . . . . . . . 40,144 - -
Total Operating Expenses. . . . . . . . . . . . . . 1,041,716 775,148 711,550
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . 142,925 388,553 373,721
OTHER INCOME (EXPENSE):
Gain on sale of Tyco securities . . . . . . . . . . . 864,253 - -
Special charges from ADT. . . . . . . . . . . . . . . - (18,181) -
Investment earnings . . . . . . . . . . . . . . . . . 25,646 20,647 -
Minority interest . . . . . . . . . . . . . . . . . . 4,737 - -
Other . . . . . . . . . . . . . . . . . . . . . . . . 28,403 12,841 18,657
Total Other Income (Expense). . . . . . . . . . . . 923,039 15,307 18,657
INCOME BEFORE INTEREST AND TAXES. . . . . . . . . . . . 1,065,964 403,860 392,378
INTEREST EXPENSE:
Interest expense on long-term debt. . . . . . . . . . 119,389 105,741 95,962
Interest expense on short-term debt and other . . . . 73,836 46,810 30,360
23,101
Allowance for borrowed funds used during
construction (credit)Total Interest Expense. . . . . . . . . . . . . . . 193,225 152,551 126,322
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . 872,739 251,309 266,056
INCOME TAXES. . . . . . . . . . . . . . . . (3,225) (4,227) (2,667)
Total interest charges. . . . . . . . . . . . . . 149,326 122,095 118,917378,645 82,359 84,380
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . 494,094 168,950 181,676 187,447
PREFERRED AND PREFERENCE DIVIDENDS. . . . . . . . . . . 4,919 14,839 13,419
13,418
EARNINGS APPLICABLE TOAVAILABLE FOR COMMON STOCK . . . . . . . . . . $ 489,175 $ 154,111 $ 168,257
$ 174,029
AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 65,127,803 63,833,783 62,157,125
61,617,873BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING . . . . .$ 7.51 $ 2.41 $ 2.71 $ 2.82
DIVIDENDS DECLARED PER COMMON SHARE . . . . . . . . . . $ 2.10 $ 2.06 $ 2.02 $
1.98
(1) Information reflects the sales of the Missouri Properties (Note 19).
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year Endedended December 31,
1997 1996 1995 1994(1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.Income. . . . . . . . . . . . . . . . . . . . . . . . $ 494,094 $ 168,950 $ 181,676
$ 187,447Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . 190,628 160,285 157,398
Amortization of nuclear fuel. . . . . . . . . . . . . . . 15,685 14,703 10,437256,725 201,331 177,830
Gain on sale of utility plant (net of tax). . . . . . . . - (951) (19,296)
Amortization of phase-in revenues . . . . . . . . . . . . 17,544 17,545 17,544
Corporate-owned life insurance policies . . . . . . . . . (29,713) (28,548) (17,246)
Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (9,640) (9,640)
Deferred acquisition costs.securities. . . . . . . . . . . . . . . . (31,518)(864,253) - -
Equity in earnings from investments . . . . . . . . . . . (25,405) (9,373) -
Write-off of investeesdeferred merger costs. . . . . . . . . . . . 48,008 - -
Security asset impairment charge. . . . . . . . . . . . . 40,144 - -
Changes in working capital items (net of effects
from acquisitions):
Accounts receivable, net. . . . . . . . . . . . . . (9,373) - -
Changes in other working capital items (net of effects
from acquisitions):
Accounts receivable and unbilled revenues (net)(Note 1). . 14,156 (47,474) (37,532)
(75,630)
Fossil fuelInventories and supplies. . . . . . . . . . . . . . . . 3,249 10,624 (715)
Marketable securities . . . . . . . . . . . . . . . . . . . . . 15,681 (15,980) (7,828)
Gas stored underground.(10,461) - -
Prepaid expenses and other. . . . . . . . . . . . . . . . (1,921) 17,116 (5,403)9,230 (14,900) 6,958
Accounts payable. . . . . . . . . . . . . . . . . . . . (48,298) 15,353 18,578
(41,682)
Accrued taxesliabilities . . . . . . . . . . . . . . . . . . 65,071 10,261 (5,079)
Accrued income taxes. . . 26,709 (19,024) 20,756. . . . . . . . . . . . . . . 9,869 26,377 (14,209)
Other . . . . . . . . . . . . . . . . . . . . . . . . 18,325 8,179 41,309. (8,584) (4,824) (28,642)
Changes in other assets and liabilities . . . . . . . . . (63,950) 537 9,625(69,353) (87,285) 5,134
Net cash flows (used in) from operating activities. . . . . . . . 275,286 306,944 267,791(85,808) 269,040 303,999
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant.property, plant and equipment (net). . . . . 210,738 195,602 232,252
Customer account acquisitions . . . . . . . . . . . . . . 45,163 - -
Proceeds from sale of securities. . 199,509 236,827 237,696
Sales. . . . . . . . . . . (1,533,530) - -
Security alarm monitoring acquisitions,
net of utility plant.cash acquired. . . . . . . . . . . . . . . . . . 438,717 368,535 - (1,723) (402,076)
Purchase of ADT common stock. . . . . . . . . . . . . . . - 589,362 -
-
Security business acquisitions. . . . . . . . . . . . . . 368,535 - -
Non-utilityOther investments (net) . . . . . . . . . . . . . . 6,563 15,408 9,041
Corporate-owned life insurance policies . . . . . . . . . 54,007 55,175 54,914
Death proceeds of corporate-owned life insurance policies (10,653) (11,187) (1,251)45,318 6,563 15,408
Net cash flows (from) used in (from) investing activities. . . 1,207,323 294,500 (101,676)(793,594) 1,160,062 247,660
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . (744,240) 777,290 (104,750)
(132,695)
Bonds issued.Proceeds of long-term debt. . . . . . . . . . . . . . . . 520,000 225,000 50,000
Retirements of long-term debt . . . . . . . . . . . . . . (293,977) (16,135) (105)
Issuance of other mandatorily redeemable securities . . . - 120,000 100,000
Issuance of common stock (net). . . . . . . . . . . . . . 25,042 33,212 36,161
Redemption of preference stock. . . . . . . . . . . . . . - (100,000) -
Cash dividends paid . . . . . . . . . . . . . . . . . . . . . . - - 235,923
Bonds retired . . . . . . . . . . . . . . . . . . . . . . (16,135) (105) (223,906)
Revolving credit agreements (net) . . . . . . . . . . . . 225,000 50,000 (115,000)
Other long-term debt retired. . . . . . . . . . . . . . . - - (67,893)
Other mandatorily redeemable securities . . . . . . . . . 120,000 100,000 -
Borrowings against life insurance policies. . . . . . . . 45,978 49,279 70,633
Repayment of borrowings against life insurance policies . (4,963) (5,384) (225)
Common stock issued (net) . . . . . . . . . . . . . . . . 33,212 36,161 -
Preference stock redeemed . . . . . . . . . . . . . . . . (100,000) - -
Dividends on preferred, preference, and common stock. . .(141,727) (147,035) (137,946)
(134,806)
Net cash flows from (used in) from financing activities. . . 933,347 (12,745) (367,969)(634,902) 892,332 (56,640)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . 72,884 1,310 (301) 1,498
CASH AND CASH EQUIVALENTS:
Beginning of the period . . . . . . . . . . . . . . . . . 3,724 2,414 2,715 1,217
End of the period . . . . . . . . . . . . . . . . . . . . $ 76,608 $ 3,724 $ 2,414 $ 2,715
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized). . . . . . . . . . . . . . . . . . . . . . $ 169,713193,468 $ 136,548170,635 $ 134,785136,526
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 404,548 66,692 84,811
90,229
(1) Information reflectsSUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During 1997, the salescompany contributed the net assets of the Missouri Properties (Note 19).its natural gas business totaling
approximately $594 million to ONEOK in exchange for an ownership interest of 45% in ONEOK.
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF TAXES
(Dollars in Thousands)
Year Ended December 31,
1996 1995 1994(1)
FEDERAL INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . $ 61,602 $ 51,218 $ 98,748
Deferred taxes arising from:
Alternative minimum tax credit. . . . . . . . . . . . . 18,491 23,925 -
Depreciation and other property related items . . . . . (1,386) (1,813) 29,506
Energy and cost of gas riders . . . . . . . . . . . . . (2,095) 5,239 9,764
Natural gas line survey and replacement program . . . . (466) 1,192 (313)
Missouri property sales . . . . . . . . . . . . . . . . - - (36,343)
Prepaid power sale. . . . . . . . . . . . . . . . . . . 376 (23) (13,759)
Other . . . . . . . . . . . . . . . . . . . . . . . . . (2,301) (7,046) (800)
Amortization of investment tax credits. . . . . . . . . . (6,652) (6,789) (6,739)
Total Federal income taxes. . . . . . . . . . . . . . 67,569 65,903 80,064
Less:
Federal income taxes applicable to non-operating items:
Missouri property sales . . . . . . . . . . . . . . . . - - 9,485
Other . . . . . . . . . . . . . . . . . . . . . . . . . (2,488) (6,411) (5,898)
Total Federal income taxes applicable to
non-operating items . . . . . . . . . . . . . . . . (2,488) (6,411) 3,587
Total Federal income taxes charged to operations. . 70,057 72,314 76,477
STATE INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . . . . 18,885 17,203 17,758
Deferred (net). . . . . . . . . . . . . . . . . . . . . . (352) 286 2,129
Total State income taxes. . . . . . . . . . . . . . . 18,533 17,489 19,887
Less:
State income taxes applicable to non-operating items. . . (502) (1,394) 742
Total State income taxes charged to operations. . . 19,035 18,883 19,145
GENERAL TAXES:
Property and other taxes. . . . . . . . . . . . . . . . . 84,776 83,738 86,687
Franchise taxes . . . . . . . . . . . . . . . . . . . . . 32 26 5,116
Payroll taxes . . . . . . . . . . . . . . . . . . . . . . 12,244 13,075 12,879
Total general taxes charged to operations . . . . . 97,052 96,839 104,682
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . . . . $186,144 $188,036
$200,304
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 rates and the
Federal statutory income tax rates are as follows:
Year Ended December 31, 1996 1995 1994(1)
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . . . . 32.8% 31.8% 35.3%
EFFECT OF:
State income taxes. . . . . . . . . . . . . . . . . . . . (5.1) (4.3) (4.6)
Amortization of investment tax credits. . . . . . . . . . 2.7 2.5 2.4
Corporate-owned life insurance policies . . . . . . . . . 3.7 3.2 2.1
Flow through and amortization, net. . . . . . . . . . . . (.2) (.2) (.7)
Other differences . . . . . . . . . . . . . . . . . . . . 1.1 2.0 .5
STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . . . . 35.0% 35.0%
35.0%
(1) Information reflects the sales of the Missouri Properties (Note 19).
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATIONCUMULATIVE PREFERRED AND PREFERENCE STOCK
(Dollars in Thousands)
December 31,
1997 1996 1995
COMMON STOCK EQUITY (See Statements):
Common stock, par value $5 per share,
authorized 85,000,000 shares, outstanding
64,625,259 and 62,855,961 shares, respectively . . $ 323,126 $ 314,280
Paid-in capital. . . . . . . . . . . . . . . . . . . 739,433 697,962
Retained earnings. . . . . . . . . . . . . . . . . . 562,121 540,868
1,624,680 45% 1,553,110 48%
CUMULATIVE PREFERRED AND PREFERENCE STOCK (Note 11):STOCK:
Preferred stock not subject to mandatory redemption,
Par value $100 per share, authorized 600,000 shares,
outstandingOutstanding -
4 1/2% Series, 138,576 shares . . . . . . . . . . . . . $ 13,858 $ 13,858
4 1/4% Series, 60,000 shares. . . . . . . . . . . . . . 6,000 6,000
5% Series, 50,000 shares. . . . . . . . . . . . . . . . 5,000 5,000
24,858 24,858
Preference stock subject to mandatory redemption,
Without par value, $100 stated value, authorized
4,000,000 shares, outstanding -
7.58% Series, 500,000 shares. . . . . . . . . 50,000 50,000
8.50% Series, 1,000,000 shares. . . . . . . . - 100,000
50,000 150,000
74,858 2% 174,858 6%
WESTERN RESOURCES OBLIGATED MANDATORILY REDEEMABLE50,000
TOTAL CUMULATIVE PREFERRED SECURITIES OF SUBSIDIARY
TRUSTS HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES (Note 11): 220,000 6% 100,000 3%
LONG-TERM DEBT (Note 14):
First mortgage bondsAND PREFERENCE STOCK . . . . . . . . . . . . . . . . 825,000 841,000
Pollution control bonds. . . . . . . . . . . . . . . 521,682 521,817
Revolving credit agreement . . . . . . . . . . . . . 275,000 50,000
Other long-term debt . . . . . . . . . . . . . . . . 65,190 -
Less:
Unamortized premium and discount (net) . . . . . . 5,289 5,554
Long-term debt due within one year . . . . . . . . - 16,000
1,681,583 47% 1,391,263 43%
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . $3,601,121 100% $3,219,231 100%$ 74,858 $ 74,858
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKSHAREOWNERS' EQUITY
(Dollars in Thousands)Thousands, Except Per Share Amounts)
Unrealized
Gain on
Equity
Common Paid-in Retained Securities
Stock Capital Earnings (net)
BALANCE DECEMBER 31, 1993,1994, 61,617,873 shares.SHARES. . . . . $308,089 $667,738
$446,348
Net income. . . . . . . . . . . . . . . . . . . . . . 187,447
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,418)
Common stock, $1.98 per share . . . . . . . . . . . (122,003)
Expenses on common stock. . . . . . . . . . . . . . . (228)
Distribution of common stock under the Dividend
Reinvestment and Stock Purchase Plan. . . . . . . . 482
BALANCE DECEMBER 31, 1994, 61,617,873 shares. . . . . 308,089 667,992 498,374$667,992 $498,374 $ -
Net income. . . . . . . . . . . . . . . . . . . . . . 181,676
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (13,419)
Common stock, $2.02 per share . . . . . . . . . . . (125,763)
Expenses on common stock. . . . . . . . . . . . . . . (772)
Issuance of 1,238,088 shares of common stock. . . . . 6,191 30,742
BALANCE DECEMBER 31, 1995, 62,855,961 shares.SHARES. . . . . 314,280 697,962 540,868 -
Net income. . . . . . . . . . . . . . . . . . . . . . 168,950
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (14,839)
Common stock, $2.06 per share . . . . . . . . . . . (131,611)
Issuance of 1,769,298 shares of common stock. . . . . 8,846 41,471 (1,247)
BALANCE DECEMBER 31, 1996, 64,625,259 shares.SHARES. . . . . $323,126 $739,433
$562,121323,126 739,433 562,121 -
Net income. . . . . . . . . . . . . . . . . . . . . . 494,094
Cash dividends:
Preferred and preference stock. . . . . . . . . . . (4,919)
Common stock, $2.10 . . . . . . . . . . . . . . . . (136,809)
Expenses on common stock. . . . . . . . . . . . . . . (5)
Issuance of 784,344 shares of common stock. . . . . . 3,922 21,125
Net change in unrealized gain on equity securities
(net of tax effect of $13,129). . . . . . . . . . . 12,119
BALANCE DECEMBER 31, 1997, 65,409,603 SHARES. . . . . $327,048 $760,553 $914,487 $ 12,119
The Notes to Consolidated Financial Statements are an integral part of this statement.
WESTERN RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: The Consolidated Financial StatementsDescription of Business: Western Resources, Inc. (the company) is a publicly
traded holding company. The company's primary business activities are providing
electric generation, transmission and distribution services to approximately
614,000 customers in Kansas; providing security alarm monitoring services to
approximately 950,000 customers located throughout the United States, providing
natural gas transmission and distribution services to approximately 1.4 million
customers in Oklahoma and Kansas through its wholly-owned subsidiaries, includeinvestment in ONEOK Inc. (ONEOK)
and investing in international power projects. Rate regulated electric service
is provided by KPL, a rate-regulated
electric and gas division of the company and Kansas Gas and Electric
Company (KGE), a rate-regulated electric utility and wholly-owned subsidiary of the
company, Westarsubsidiary. Security services are primarily
provided by Protection One, Inc. (Westar Security) a wholly-owned subsidiary
which provides monitored electronic security services, Westar Energy, Inc. a
wholly-owned subsidiary which provides non-regulated energy services, Westar
Capital, Inc. (Westar Capital) a wholly-owned subsidiary which holds equity
investments in technology and energy-related companies, The Wing Group Limited
(The Wing Group)(Protection One), a wholly-owned developerpublicly-traded,
82.4%-owned subsidiary.
Principles of international power projects,
and Mid Continent Market Center, Inc. (Market Center), a regulated gas
transmission service provider. KGE owns 47% of Wolf Creek Nuclear Operating
Corporation (WCNOC), the operating company for Wolf Creek Generating Station
(Wolf Creek). The company records its proportionate share of all transactions
of WCNOC as it does other jointly-owned facilities. All significant
intercompany transactions have been eliminated.
The company is an investor-owned holding company. The company is engaged
principally in the production, purchase, transmission, distribution and sale
of electricity, the delivery and sale of natural gas, and electronic security
services. The company serves approximately 606,000 electric customers in
eastern and central Kansas and approximately 650,000 natural gas customers in
Kansas and northeastern Oklahoma. The company's non-utility subsidiaries
provide electronic security services to approximately 400,000 customers
throughout the United States, market natural gas primarily to large commercial
and industrial customers, develop international power projects, and provide
other energy-related products and services.Consolidation: The company prepares its financial statements
in conformity with generally accepted accounting principles as appliedprinciples. The accompanying
consolidated financial statements include the accounts of Western Resources and
its wholly-owned and majority-owned subsidiaries. All material intercompany
accounts and transactions have been eliminated. Common stock investments that
are not majority-owned are accounted for using the equity method when the
company's investment allows it the ability to exert significant influence.
The company currently applies accounting standards for its rate regulated
public
utilities. The accountingelectric business that recognize the economic effects of rate regulation in
accordance with Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation", (SFAS 71) and, accordingly, has
recorded regulatory assets and liabilities when required by a regulatory order
or when it is probable, based on regulatory precedent, that future rates will
allow for recovery of the company are subject to requirements
of the Kansas Corporation Commission (KCC), the Oklahoma Corporation Commission
(OCC), and the Federal Energy Regulatory Commission (FERC).a regulatory asset.
The financial statements require management to make estimates and assumptions
that affect the reported amounts of assets and liabilities, to disclose
contingent assets and liabilities at the balance sheet dates and to report
amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Cash and Cash Equivalents: The company currently applies accounting standards that recognizeconsiders highly liquid
collateralized debt instruments purchased with a maturity of three months or
less to be cash equivalents.
Available-for-sale Securities: The company classifies marketable equity
securities accounted for under the economic effects of rate regulation Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation",
(SFAS 71)cost method as available-for-sale. These
securities are reported at fair value based on quoted market prices. Unrealized
gains and accordingly, has recorded regulatory assets and liabilities
related to its generation, transmission and distribution operations. In 1996,
the KCC initiated a generic docket to study electric restructuring issues. A
retail wheeling task force has been created by the Kansas Legislature to study
competitive trends in retail electric services. During the 1997 sessionlosses, net of the Kansas Legislature, bills have been introduced to increase competitionrelated tax effect, are reported as a separate
component of shareowners' equity until realized.
At December 31, 1997, an unrealized gain of $12 million (net of deferred
taxes of $13 million) was included in the electric industry. Among the matters under consideration is the recovery
by utilitiesshareowners' equity. These securities had
a fair value of costs in excessapproximately $75 million and a cost of competitive cost levels.approximately $50
million at December 31, 1997. There can bewere no assuranceavailable-for-sale securities held
at this time that such costs will be recoverable if open competition
is initiated in the electric utility market. In the event the company
determines that it no longer meets the criteria set forth in SFAS 71, the
accounting impact would be an extraordinary
non-cash charge to operations of an amount that would be material. Criteria
that give rise to the discontinuance of SFAS 71 include, (1) increasing
competition that restricts the company's ability to establish prices to
recover specific costs,December 31, 1996.
Property, Plant and (2) a significant change in the manner in which
rates are set by regulators from a cost-based regulation to another form of
regulation. The company periodically reviews these criteria to ensure the
continuing application of SFAS 71 is appropriate. Based on current evaluation
of the various factorsEquipment: Property, plant and conditions that are expected to impact future cost
recovery, the company believes that its net regulatory assets are probable of
future recovery. Any regulatory changes that would require the company to
discontinue SFAS 71 based upon competitive or other events may significantly
impact the valuation of the company's net regulatory assets and its utility
plant investments, particularly the Wolf Creek facility. At this time, the
effect of competition and the amount of regulatory assets which could be
recovered in such an environment cannot be predicted. See Note 9 for further
discussion on regulatory assets.
In January, 1996, the company adopted Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" (SFAS 121). This Statement imposes
stricter criteria for regulatory assets by requiring that such assets be
probable of future recovery at each balance sheet date. Based on the current
regulatory structure in which the company operates, the adoption of this
standard did not have a material impact on the financial position or results
of operations of the company. This conclusion may change in the future as
competitive factors influence wholesale or retail pricing in the electric
industry.
Utility Plant: Utility plantequipment is stated at
cost. For constructedutility plant, cost includes contracted services, direct labor and
materials, indirect charges for engineering, supervision, general and
administrative costs and an allowance for funds used during construction
(AFUDC).
The AFUDC rate was 5.7%5.80% in 1997, 5.70% in 1996 and 6.31% in 1995, and 4.08% in 1994.1995. The cost of
additions to utility plant and replacement units of property are capitalized.
Maintenance costs and replacement of minor items of property are charged to
expense as incurred. When units of depreciable property are retired, they are
removed from the plant accounts and the original cost plus removal charges less
salvage value are charged to accumulated depreciation.
In accordance with regulatory decisions made by the KCC, amortization
of the acquisition
premium of approximately $801 million resulting from the acquisition of KGE purchase began in
August of 1995. The premium1992 is being amortized over 40 years and has beenyears. The acquisition premium is classified
as electric plant in service. Accumulated amortization through December 31,
19961997 totaled $27.5$47.9 million.
See Note 9 for
further information concerning the amortization of this premium.
Depreciation: DepreciationUtility plant is provideddepreciated on the straight-line method basedat
rates approved by regulatory authorities. Utility plant is depreciated on an
average annual composite basis using group rates that approximated 2.89% during
1997, 2.97% during 1996 and 2.84% during 1995. Nonutility property, plant and
equipment of approximately $20 million is depreciated on a straight-line basis
over the estimated useful lives of property. Composite provisions for book
depreciation approximated 2.97% during 1996, 2.84% during 1995, and 2.87%
during 1994 of the average original cost of depreciable property. In the
past, the methods and rates have been determined by depreciation studies and
approved by the various regulatory bodies. The company periodically evaluates
its depreciation rates considering the past and expected future experience in
the operation of its facilities.
Environmental Remediation: Effective January 1, 1997, the company
adopted the provisions of Statement of Position (SOP) 96-1, "Environmental
Remediation Liabilities". This statement provides authoritative guidance for
recognition, measurement, display, and disclosure of environmental remediation
liabilities in financial statements. The company is currently evaluating and
in the process of
estimating the potential liability associated with environmental remediation.
Management does not expect the amount to be significant to the company's
results of operations as the company will seek recovery of these costs through
rates as has been permitted by the KCC in the case of another Kansas utility.
Additionally, the adoption of this statement is not expected to have a
material impact on the company's financial position. To the extent that such
remediation costs are not recovered through rates, the costs may be material
to the company's operating results, depending on the degree of remediation
required and number of years over which the remediation must be completed.
Cash and Cash Equivalents: For purposes of the Consolidated
Statements of Cash Flows, the company considers highly liquid collateralized
debt instruments purchased with a maturity of three months or less to be cash
equivalents.
Income Taxes: The company accounts for income taxes in accordance with
the provisions of Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" (SFAS 109). Under SFAS 109, deferred tax assets
and liabilities are recognized based on temporary differences in amounts
recorded for financial reporting purposes and their respective tax bases.
Investment tax credits previously deferred are being amortized to income over
the life of the property which gave rise to the credits (See Note 10).
Revenues: Operating revenues for both electric and natural gas services
include estimated amounts for services rendered but unbilled at the end of
each year. Revenues for security services are recognized in the period
earned. Unbilled revenues of $83 million and $66 million are recorded as a
component of accounts receivable and unbilled revenues (net) on the
Consolidated Balance Sheets as of December 31, 1996 and 1995, respectively.
The company's recorded reserves for doubtful accounts receivable
totaled $6.3 million and $4.9 million at December 31, 1996 and 1995,
respectively.
Debt Issuance and Reacquisition Expense: Debt premium, discount, and
issuance expenses are amortized over the life of each issue. Under regulatory
procedures, debt reacquisition expenses are amortized over the remaining life
of the reacquired debt or, if refinanced, the life of the new debt. See Note
9 for more information regarding regulatoryrelated assets.
Risk Management: The company is exposed to fluctuations in price on the
portfolio of natural gas transactions resulting from marketing activities of a
non-regulated subsidiary. To minimize the risk from market fluctuations, the
company enters into natural gas futures, swaps and options in order to hedge
existing physical natural gas purchase or sale commitments. These financial
instruments are designated as hedges of the underlying physical commitments
and as such, gains or losses resulting from changes in market value of the
various derivative instruments are deferred and recognized in income when the
underlying physical transaction is closed. See Note 5 for further
information.
Fuel Costs: The cost of nuclear fuel in process of refinement, conversion,
enrichment and fabrication is recorded as an asset at original cost and is
amortized to expense based upon the quantity of heat produced for the generation
of electricity. The accumulated amortization of nuclear fuel in the reactor at
December 31, 1997 and 1996, was $20.9 million and 1995, was $25.3 million, respectively.
Subscriber Accounts: The direct costs incurred to install a security system
for a customer are capitalized. These costs include the costs of accounts
purchased, the estimated fair value at the date of the acquisition for accounts
acquired in business combinations, equipment, direct labor and $28.5
million, respectively.
Cash Surrender Valueother direct
costs for internally generated accounts. These costs are amortized on a
straight-line basis over the average expected life of Life Insurance Policies:a subscriber account,
currently ten years. It is the company's policy to periodically evaluate
subscriber account attrition utilizing historical attrition experience.
Goodwill: Goodwill, which represents the excess of the purchase price over
the fair value of net assets acquired, is generally amortized on a straight-line
basis over 40 years.
Regulatory Assets and Liabilities: Regulatory assets represent probable
future revenue associated with certain costs that will be recovered from
customers through the ratemaking process. The followingcompany has recorded these
regulatory assets in accordance with Statement of Financial Accounting Standards
No. 71, "Accounting for the Effects of Certain Types of Regulation." If the
company were required to terminate application of that statement for all of its
regulated operations, the company would have to record the amounts related to corporate-owned life insurance policies (COLI) are recordedof all
regulatory assets and liabilities in Corporate-owned life insurance (net) onits Consolidated Statements of Income at
that time. The company's earnings would be reduced by the Consolidated Balance Sheets:
Attotal net amount in
the table below, net of applicable income taxes. Regulatory assets reflected in
the consolidated financial statements at December 31, 1997 are as follows:
December 31, 1997 1996 1995
(Dollars in Millions)
Cash surrender value of policies (1) . $ 563.0 $ 479.9
Borrowings against policies. . . . . . (476.8) (435.8)
COLI (net)Thousands)
Recoverable taxes. . . . . . . . . . . $ 86.2 $ 44.1
(1) Cash surrender value. $212,996 $217,257
Debt issuance costs. . . . . . . . . . . 75,336 78,532
Deferred employee benefit costs. . . . . 37,875 40,834
Deferred plant costs . . . . . . . . . . 30,979 31,272
Coal contract settlement costs . . . . . 16,032 21,037
Other regulatory assets. . . . . . . . . 7,203 8,794
Phase-in revenues. . . . . . . . . . . . - 26,317
Deferred cost of policies as presented representsnatural gas purchased . - 21,332
Service line replacement . . . . . . . . - 12,921
Total regulatory assets . . . . . . . . $380,421 $458,296
Recoverable income taxes: Recoverable income taxes represent amounts due from
customers for accelerated tax benefits which have been flowed through to
customers and are expected to be recovered when the valueaccelerated tax benefits
reverse.
Debt issuance costs: Debt reacquisition expenses are amortized over the
remaining term of the policiesreacquired 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 will be
recovered from income generated from the company's Affordable Housing Tax
Credit (AHTC) investment program.
Deferred plant costs: Disallowances related to the Wolf Creek nuclear
generating facility.
Coal contract settlement costs: The company deferred costs associated with
the termination of certain coal purchase contracts. These costs are being
amortized over periods ending in 2002 and 2013.
The company expects to recover all of the above regulatory assets in rates.
The regulatory assets noted above, with the exception of some coal contract
settlement costs and debt issuance costs, other than the refinancing of the La
Cygne 2 lease, are not included in rate base and, therefore, do not earn a
return. On November 30, 1997, deferred costs associated with the service line
replacement program and the deferred cost of natural gas purchased were
transferred to ONEOK. Phase-in revenues were fully amortized in 1997.
Minority Interests: Minority interests represent the minority shareowner's
proportionate share of the shareowners' equity and net income of Protection One.
Sales: Energy sales are recognized as ofservices are rendered and include
estimated amounts for energy delivered but unbilled at the end of the respective policy yearseach year.
Unbilled revenue of $37 million and not as of December
31, 1996 and 1995.
Income$83 million is recorded for increases in cash surrender value and net death
proceeds. Interest expense is recognized for COLI borrowings except for
certain policies entered into in 1992 and 1993. The net income generated from
COLI contracts purchased prior to 1992 including the tax benefitas a component of
the
interest deduction and premium expenses are recorded as Corporate-owned life
insuranceaccounts receivable (net) on the Consolidated StatementsBalance Sheets at December 31,
1997 and 1996, respectively. Security sales are recognized when installation
of Income.an alarm system occurs and when monitoring or other security-related services
are provided.
The company's allowance for doubtful accounts receivable totaled $23.4
million, which included approximately $20 million of Protection One allowance
for doubtful accounts receivable, and $6.3 million at December 31, 1997 and
1996, respectively.
Income Taxes: Deferred tax assets and liabilities are recognized for
temporary differences in amounts recorded for financial reporting purposes and
their respective tax bases. Investment tax credits previously deferred are
being
amortized to income over the life of the property which gave rise to the
credits.
Affordable Housing Tax Credit Program (AHTC): The company has received
authorization from increases in cash surrender value and net death proceeds was $25.4the KCC to invest up to $114 million in 1996, $22.7AHTC investments. At
December 31, 1997, the company had invested approximately $17 million to
purchase AHTC investments in 1995, and $15.6limited partnerships. The company is committed to
investing approximately $55 million more in 1994. The interest expense
deduction taken was $27.6 millionAHTC investments by January 1, 2000.
These investments are accounted for 1996, $25.4 million for 1995, and $21.0
million for 1994.
The COLI policies entered into in 1992 and 1993 were establishedusing the equity method. Based upon an
order received from the KCC, income generated from the AHTC investment,
primarily tax credits, will be used to mitigate the cost ofoffset costs associated with
postretirement and postemployment benefits. As approved
bybenefits offered to the KCC,company's employees.
Tax credits are recognized in the year generated.
Risk Management: To minimize the risk from market fluctuations in the price
of electricity, the company utilizes financial and commodity instruments
(derivatives) to reduce price risk. Gains or losses on derivatives associated
with firm commitments are generally recognized as adjustments to cost of sales
or revenues when the associated transactions affect earnings. Gains or losses
on derivatives associated with forecasted transactions are generally recognized
when such forecasted transactions affect earnings.
New Pronouncements: In 1997, the company adopted Statement of Financial
Accounting Standards No. 128, "Earnings Per Share" (SFAS 128). Basic earnings
per share is usingcalculated based upon the net income stream generated by these COLI
policies to offsetaverage weighted number of common shares
outstanding during the costsperiod. There were no significant amounts of postretirement and postemployment benefits. A
regulatory asset totaling $41 million and $35 million isdilutive
securities outstanding at December 31, 1997, 1996 and 1995, respectively, related to deferred postretirement
and postemployment costs.
On August 2, 1996, Congress passed legislation that will phase out tax
benefits associated with the 1992 and 1993 COLI policies. The loss of tax
benefits will significantly reduce the COLI earnings. The company is
evaluating other methods to replace the 1992 and 1993 COLI policies. The
company also has the ability to seek recovery of postretirement and
postemployment costs through the rate making process. Regulatory precedents
established by the KCC are expected to permit the accrued costs of
postretirement and postemployment benefits to be recovered in rates. If a
suitable COLI replacement product cannot be found, or these costs cannot be
recovered in rates,1995.
Effective January 1, 1997, the company may be required to expenseadopted the regulatory
asset. The company currently expects to be able to findprovisions of Statement
of Position (SOP) 96-1, "Environmental Remediation Liabilities". This statement
provides authoritative guidance for recognition, measurement, display and
disclosure of environmental remediation liabilities in financial statements.
Adoption of this statement did not have a suitable COLI
replacement. The legislation had minimal impact onmaterial adverse effect upon the
Company's COLI
policies entered into prior to 1992. (See Notes 9 and 12).company's overall financial position or results of operations.
Reclassifications: Certain amounts in prior years have been reclassified to
conform with classifications used in the current year presentation.
2. PROPOSEDGAIN ON SALE OF EQUITY SECURITIES
During 1996, the company acquired 27% of the common shares of ADT Limited,
Inc. (ADT) and made an offer to acquire the remaining ADT common shares. ADT
rejected this offer and in July 1997, ADT merged with Tyco International Ltd.
(Tyco). ADT and Tyco completed their merger by exchanging ADT common stock for
Tyco common stock.
Following the ADT and Tyco merger, the company's equity investment in ADT
became an available-for-sale security. During the third quarter of 1997, the
company sold its Tyco common shares for approximately $1.5 billion. The company
recorded a pre-tax gain of $864 million on the sale and recorded tax expense of
approximately $345 million in connection with this gain.
3. SECURITY ALARM MONITORING BUSINESS PURCHASES
In 1997 the company acquired three monitored security alarm companies. Each
acquisition was accounted for as a purchase and, accordingly, the operating
results for each acquired company have been included in the company's
consolidated financial statements since the date of acquisition. Preliminary
purchase price allocations have been made based upon the fair value of the net
assets acquired. The company acquired Network Multi-Family Security Corporation
(Network Multi-Family) in September, 1997 for approximately $171 million and
acquired Centennial Holdings, Inc. (Centennial) in November 1997 for
approximately $94 million. The company also acquired an approximate 82.4%
equity interest in Protection One in November 1997.
Protection One is a publicly traded security company. The company paid
approximately $258 million in cash and contributed all of its existing security
business net assets, other than Network Multi-Family, in exchange for its
ownership interest in Protection One. Amounts contributed included funds used
to pay existing Protection One common shareowners, option holders and warrant
holders a dividend of $7.00 per common share. The company has an option to
purchase up to 2.8 million additional common shares of Protection One for $15.50
per share. The option period extends to a date not later than October 31,
1999. The company assigned approximately $278 million of the total purchase
price to subscriber accounts and approximately $620 million to goodwill in
connection with these security acquisitions. The subscriber accounts are being
amortized over ten years and goodwill is being amortized over 40 years.
Consideration paid, assets acquired and liabilities assumed in connection
with these security acquisitions is summarized as follows:
(Dollars in Thousands)
Fair value of assets acquired,
net of cash acquired . . . . . $1,001,094
Cash paid, net of cash acquired
of $88,822 . . . . . . . . . . (438,717)
Total liabilities assumed. . $ 562,377
The following unaudited, pro forma information for the company's security
business segment has been prepared assuming the Centennial, Network Multi-Family
and Protection One acquisitions occurred at the beginning of each period.
1997 1996
(Dollars in Thousands,
except per share data)
Net Revenues. . . . . . . $284,411 $241,841
Net Loss. . . . . . . . . (47,290) (24,762)
Net Loss per Share. . . . ($0.73) ($0.39)
The pro forma financial information is not necessarily indicative of the
results of operations had the entities been combined for the entire period, nor
do they purport to be indicative of results which will be obtained in the
future.
In December 1997, Protection One recorded a special non-recurring charge of
approximately $40 million. Approximately $28 million of this charge reflects
the elimination of redundant facilities and activities and the write-off of
inventory and other assets which are no longer of continuing value to Protection
One. The remaining $12 million of this charge reflects the estimated costs to
transition all security alarm monitoring operations to the Protection One brand.
Protection One intends to complete these exit activities by the fourth quarter
of 1998.
In January 1998, Protection One announced that it will acquire the monitored
security alarm business of Multimedia Security Services, Inc. (Multimedia
Security) for approximately $220 million in cash. The acquisition is expected
to close in the first quarter of 1998. Multimedia Security has approximately
140,000 subscribers concentrated primarily in California, Florida, Kansas,
Oklahoma and Texas.
On February 4, 1998, Protection One exercised its option to acquire the stock
of Network Holdings, Inc., the parent company of Network Multi-Family, from the
company for approximately $178 million. The company expects Protection One to
borrow money from a revolving credit agreement provided by Westar Capital, a
subsidiary of Western Resources, to purchase Network Multi-Family.
4. STRATEGIC ALLIANCE WITH ONEOK INC.
In November 1997, the company completed its strategic alliance with ONEOK.
The company contributed substantially all of its regulated and non-regulated
natural gas business to ONEOK in exchange for a 45% ownership interest in ONEOK.
The company's ownership interest in ONEOK is comprised of approximately 3.1
million common shares and approximately 19.9 million convertible preferred
shares. If all the preferred shares were converted, the company would own
approximately 45% of ONEOK's common shares presently outstanding. The agreement
with ONEOK allows the company to appoint two members to ONEOK's board of
directors. The company will account for its common ownership in accordance with
the equity method of accounting. Subsequent to the formation of the strategic
alliance, the consolidated energy revenues, related cost of sales and operating
expenses for the company's natural gas business have been replaced by investment
earnings in ONEOK.
5. MERGER AGREEMENT WITH KANSAS CITY POWER & LIGHT COMPANY
On April 14, 1996, in a letter to Mr. A. Drue Jennings, Chairman of the
Board, President and Chief Executive Officer of Kansas City Power & Light
Company (KCPL), the company proposed an offer to mergeThe original merger agreement signed with KCPL (KCPL
Merger).
On November 15, 1996, the company and KCPL announced that
representatives of their respective boards and managements met to discuss the
proposed merger transaction. Onon February 7, 1997 KCPLis
currently being renegotiated and the company entered
into anregulatory approval process for the
original merger agreement whereby KCPLhas been suspended. In December 1997, representatives
of our financial advisor indicated that they believed it was unlikely that they
would be merged with and intoin a position to issue a required fairness opinion for the company.
The merger agreement provides for a tax-free, stock-for-stock
transaction valued at approximately $2 billion. Underon
the termsbasis of the agreement, KCPL shareowners will receive $32previously announced terms. The company cannot predict the
timing or the ultimate outcome of company common stock per KCPL
common share, subject to an exchange ratio collar of not less than 0.917 to no
more than 1.100 common shares. Consummationthese discussions.
Given the status of the KCPL Merger is subject to
customary conditions including obtainingtransaction, we have reviewed the approvaldeferred costs
and have determined that for accounting purposes, $48 million of KCPL's and the company's shareowners and various regulatory agencies. The company expects todeferred
costs should be able to close the KCPL Mergerexpensed. These costs were expensed in the first halffourth quarter of
1998. See Note 9 for
discussion of rate proceedings.
The KCPL Merger, will create a company with more than two million
security and energy customers, $9.5 billion in total assets, $3.0 billion in
annual revenues and more than 8,000 megawatts of electric generation resources.
As a result of the merger agreement, the company terminated its exchange offer
that had been effective since July 3, 1996.
The KCPL Merger is designed to qualify as a pooling of interests for
financial reporting purposes. Under this method, the recorded assets and
liabilities of the company and KCPL would be carried forward at historical
amounts to a combined balance sheet. Prior period operating results and the
consolidated statements of financial position, cash flows and capitalization
would be restated to effect the combination for all periods presented.
KCPL is a public utility company engaged in the generation,
transmission, distribution, and sale of electricity to approximately 430,000
customers in western Missouri and eastern Kansas. KCPL and the company have
joint interests in certain electric generating assets, including Wolf Creek.
As of December 31, 1996, the company has incurred approximately $32
million of transaction costs associated with the KCPL Merger. The company
anticipates expensing these costs in the first reporting period subsequent to
closing the KCPL Merger. As of December 31, 1996, costs incurred have been
included in Deferred Charges and Other Assets, Other on the Consolidated
Balance Sheets.
3. ADT LIMITED, INC.
Investment in ADT Limited, Inc.: During 1996, the company purchased
approximately 38 million common shares of ADT Limited, Inc. (ADT) for
approximately $589 million. The shares purchased represent approximately 27%
of ADT's common shares making the company the largest shareowner of ADT.
These purchases were financed entirely with short-term borrowings. ADT is
North America's largest monitored security services company with $1.8 billion
in annual revenues. ADT has approximately 1.2 million customers in North
America and abroad and has approximately 18,000 employees. The company uses
the equity method of accounting for this investment. Goodwill of
approximately $369 million is associated with this investment and is being
amortized over 40 years and is presented net in Equity in earnings of
investees and other on the Consolidated Statements of Income. Accumulated
amortization approximates $6.5 million at December 31, 1996.
ADT recently announced that it would record a net charge to income of
approximately $60 million during 1996. This charge is primarily related to
one-time restructuring charges resulting from its merger with another security
company, partially offset by a gain on the sale of non-strategic assets. The
company recognized its share of this charge equal to $11.8 million or
approximately $0.19 per share, net of tax, as a component of Equity in
earnings of investees and other on the Consolidated Statements of Income.
Proposed Acquisition of ADT: On December 18, 1996, the company
announced its intention to offer to exchange $22.50 in cash ($7.50) and shares
($15.00) of the company's common stock for each outstanding common share of ADT
not already owned by the company or its subsidiaries (ADT Offer). The value of
the ADT Offer, assuming the company's average stock price prior to closing is
above $29.75 per common share, is approximately $3.5 billion, including the
company's existing investment in ADT. Following completion of the ADT Offer,
the company presently intends to propose and seek to have ADT effect an
amalgamation, pursuant to which a newly created subsidiary of the company
incorporated under the laws of Bermuda will amalgamate with and into ADT
(Amalgamation). Based upon the closing stock price of the company on March
13, 1997, approximately 60.1 million shares of company common stock would be
issuable pursuant to the acquisition of ADT. However, the actual number of
shares of company common stock that would be issuable in connection with the
ADT Offer and the Amalgamation will depend on the exchange ratio and the
number of shares validly tendered prior to the expiration date of the ADT
Offer and the number of shares of ADT outstanding at the time the Amalgamation
is completed.
On March 3, 1997, the company announced a change in the ADT Offer.
Under the terms of the revised ADT Offer, ADT shareowners would receive $10 cash
plus 0.41494 of a share of company common stock for each share of ADT
tendered, based on the closing price of the company's common stock on March
13, 1997.
ADT shareowners would not, however, receive more than 0.42017
shares of company common stock for each ADT common share.
Concurrent with the announcement of the ADT Offer on December 18, 1996,
the company filed a registration statement on Form S-4 with the Securities and
Exchange Commission (SEC) related to the ADT Offer. On March 14, 1997, the
registration statement was declared effective by the SEC. The expiration date
of the ADT Offer is 5 p.m., EDT, April 15, 1997, and may be extended from time
to time by the company until the various conditions to the ADT Offer have been
satisfied or waived. The ADT Offer will be subject to the approval of ADT and
company shareowners. On January 23, 1997, the waiting period for the
Hart-Scott-Rodino Antitrust Improvement Act expired. On February 7, 1997, the
company received regulatory approval from the KCC to issue company common
stock and debt necessary for the ADT Offer. See Note 5 for summary financial
information concerning ADT.
On March 17, 1997, ADT announced that it had entered into a definitive
merger agreement pursuant to which Tyco International Ltd. (Tyco), a
diversified manufacturer of industrial and commercial products, would
effectively acquire ADT in a stock for stock transaction valued at $5.6
billion, or approximately $29 per ADT share of common stock.
On March 18, 1997, the company issued a press release indicating that
it had mailed the details of the ADT Offer to ADT shareowners and that it would
be reviewing the Tyco offer as well as considering its alternatives to such
offer and assessing its rights as an ADT shareowner. See Note 3 for more
information regarding this investment and the proposed ADT Offer.
4. ACQUISITIONS
On December 31, 1996, Westar Capital bought the assets of Westinghouse
Security Systems, Inc. (WSS). This acquisition, which was accounted for as a
purchase, significantly expands the scope of the company's security service
operations. Westar Capital paid approximately $358 million in cash, subject
to adjustment, to purchase the assets and assume certain liabilities of WSS.
Based on a preliminary estimate of the purchase price allocation, the company
recorded approximately $275 million of goodwill to be amortized over 40 years.
This balance is included in Security business and other property on the
accompanying Consolidated Balance Sheets. Since the transaction closed on
December 31, 1996, no operating results are reflected on the Consolidated
Statements of Income. For the year ended December 31, 1996, WSS reported $110
million in revenues. As of December 31, 1996, the company consolidated WSS'
financial position in the accompanying Consolidated Balance Sheets. The
company financed this acquisition with short-term borrowings.
During 1996, the company also acquired The Wing Group and three small
security system companies. The Wing Group develops international power
projects. In connection with these acquisitions, the company gave
consideration of approximately $33.8 million in cash and 683,333 shares of
common stock. In connection with the acquisitions, liabilities were assumed
as follows:
(Dollars in Millions)
Fair value of assets acquired $ 38.8
Consideration paid $(33.8)
Liabilities assumed $ 5.0
Each acquisition was accounted for as a purchase. Goodwill related to
these acquisitions of approximately $32.9 million is presented in the
Consolidated Balance Sheets as Security business and other property and is
being amortized over 20 years. Accumulated amortization of approximately
$943,000 has been recognized to date.
The purchase agreement related to The Wing Group allows the company, at
its option, to purchase ownership interests in power projects in which the
former owners of The Wing Group have rights. In 1996, the company gave shares
of common stock to the former owners of The Wing Group in return for a nine
percent equity interest in a power project in Turkey. See Note 8 for
information with respect to investment commitments made by the company on
behalf of The Wing Group.
5. NON-REGULATED6. INVESTMENTS IN SUBSIDIARIES
Certain non-regulated subsidiaries use natural gas futures, swaps and
options contracts to reduce the effects of natural gas commodity price
volatility on operating results which include price risk and basis risk.
Price risk is the difference in price between the physical commodity being
hedged and the price of the futures contracts used for hedging. Natural gas
options held to hedge price risk provide the right, but not the requirement,
to buy or sell natural gas at a fixed price. Basis risk is the risk that an
adverse change in the futures market will not be completely offset by an equal
and opposite change in the cash price of the commodity being hedged. Basis
risk exists in natural gas primarily due to the geographical price
differentials between cash market locations and futures contract delivery
locations. In general, the company's risk management policy requires that
positions taken with derivatives be offset by positions in physical
transactions or other derivatives. All of the company's financial instruments
are held for purposes other than trading.
The derivative instruments used to hedge commodity transactions have
historically had a high correlation with commodity prices and are expected to
continue to do so. The correlation of indices and prices is regularly
evaluated by management to ensure that the instruments continue to be
effective hedges. In the event that the correlation falls below allowable
levels, the gains or losses associated with hedging instruments are recognized
in the current period to the extent that correlation was lost. The maturity
of the derivative instruments is timed to coincide with the hedged
transaction. If the hedged transaction is terminated early or if an
anticipated transaction fails to occur, the deferred gain or loss associated
with the derivative instrument is recognized in the period and the hedge is
closed.
The company has historically used natural gas futures and options
contracts traded on the New York Mercantile Exchange and natural gas financial
swaps with various third parties to reduce exposure to price risk when gas is
not bought and sold simultaneously. At December 31, 1996, the company had a
deferred gain of $3.4 million representing unrealized gains on forward
commitments that will mature through the year 2000.
The consolidated financial statements include the company's equity
investments in ADTONEOK, Guardian International (Guardian) and Hanover Compressor Company (Hanover) each accounted for under the
equity method of accounting.Onsite Energy
Corporation (Onsite). The company's equity investments, (not includingnet of the amortization
of goodwill)goodwill in these entities, at December 31, 1997 and equity in earnings in
1997, are as follows:
1996 1995Ownership Equity
Percentage Investment in Earnings
(Dollars in Thousands)
Ownership
Interest
ADT 27% $596,598 $ONEOK Inc. (1). . . . . . . 45% $596,206 $1,970
Guardian (2). . . . . . . . 41% 9,174 $25
Onsite (3). . . . . . . . . 30% 3,312 -
Hanover 24% 64,166 55,963(1) Includes equity earnings on the company's common stock investment between
ONEOK and the company.
(2) The company's equitycompany acquired a common and convertible preferred stock interest in
earningsGuardian, a Florida-based security alarm monitoring company, during October
1997, in exchange for cash.
(3) The company acquired a common and convertible preferred stock interest in
Onsite, a California energy services company, during October, 1997, in exchange
for cash and certain energy service assets of these entities is as follows:
Year Ended December 31 1996 1995
(Dollars in Thousands)
ADT $ 7,236 $ -
Hanover 2,137 33the company.
Summarized combined financial information of ADT and Hanoverfor the company's equity
investments is presented below:
As of and for the year endedbelow.
December 31, 1996(1) 1995(1)1997
(Dollars in Thousands)
Balance Sheet:
Current assets . . . . . . . $ 531,275 $ 43,603
Noncurrent535,348
Non-current assets 2,295,824 207,316. . . . . 1,771,900
Current liabilities 433,845 20,333
Noncurrent liabilities 1,493,900 64,390liabilities. . . . . 445,770
Non-current liabilities. . . 737,975
Equity 899,354 166,196. . . . . . . . . . . 1,123,503
Year ended
December 31, 1997
(Dollars in Thousands)
Income Statement:
Revenues 1,887,180 95,964. . . . . . . . . . $1,241,164
Operating expenses 2,559,707 90,350. . . . . 1,147,866
Net income (loss) (670,326)(2) 5,614
(1) Information. . . . . . . . . 57,248
Balance sheet and income statement information is presented as of and for ADTthe
most recent twelve-month period for which public information is based on ADT's quarterly report on Form
10-Q. ADT'savailable.
ONEOK's balance sheet and income statement information is presented as of and
resultsfor the twelve months ended November 30, 1997. Guardian and Onsite's balance
sheet and income statement information is presented as of operations representand for the twelve
months ended September 30, 1996, based on publicly available
information. Hanover's financial information is presented as of November 30,
1996, the most recent information available.1997. The company cannot give any assurance ofas to
the accuracy of the public information so obtained.
(2) ADT's net income through September 30, 1996 as reported in its Form 10-Q
for the nine months ended September 30, 1996, includes a one-time charge
related to the adoption of SFAS 121. This charge for approximately $745
million was incurred prior toDuring 1997, the company's equity investment in ADT.ADT was converted to an
available-for-sale security investment in Tyco. The company cannot give any assurancerecognized equity
in earnings from the ADT investment of the accuracy of the information so obtained.
6. PROPOSED STRATEGIC ALLIANCE
On December 12,$24 million and $7 million in 1997 and
1996, the company and ONEOK Inc. (ONEOK) announced an
agreement to form a strategic alliance combining the natural gas assets of
both companies. Under the agreement for the proposed strategic alliance, the
company will contribute its natural gas business to a new company (New ONEOK)
in exchange for a 45% equity interest. The recorded net property value being
contributed atrespectively. At December 31, 1996, is estimated at $600 million (unaudited). No
gain or loss is expected to be recorded as a result of the proposed
transaction. The proposed transaction is subject to satisfaction of customary
conditions, including approval by ONEOK shareowners and regulatory
authorities. The company is working towards consummation of the transaction
during the second half of 1997.
The equity interest would be comprised of approximately 3.0 million
common shares and 19.3 million convertible preferred shares. Upon consummation
of the proposed alliance, the company will record its common equity interest in
New ONEOK's earnings using the equity method of accounting. Earnings for the
convertible preferred shares held will be recognized and recorded based upon
preferred dividends paid. The convertible preferred shares are expected to
pay an initial dividend rate of $1.80 per share. For its fiscal year ended
August 31, 1996, ONEOK reported operating revenues of $1.2 billion and net
income of $52.8 million.
The structure of the proposed alliance is not expected to have any
immediate income tax consequences to either company or to either company's
shareowners.
7. LEGAL PROCEEDINGS
The company has requested that the District Court for the Southern
District of Florida require that ADT hold a special shareowners meeting no
later than March 20, 1997. In its filing, the company claims that the ADT
board of directors has breached its fiduciary and statutory duties and that
there is no reason to delay the special meeting until July 8, 1997 as
established by ADT. See Note 3 for additional information regarding the
proposed acquisition of ADT.
On December 26, 1996, an ADT shareowner filed a purported class action
complaint against ADT, ADT's board of directors, the company and the company's wholly-owned subsidiary, Westar Capital in the Civil Division of the Circuit
Court of the Fifteenth Judicial Circuit in Palm Beach County, Florida.
(Charles Gachot v. ADT, Ltd., Western Resources, Inc., Westar Capital, Inc.,
Michael A. Ashcroft, et al., Case No. 96-10912-AN) The complaint alleges,
among other things, that the company and Westar Capital are breaching their
fiduciary duties to ADT's shareowners by failing to offer "an appropriate
premium for the
controlling interest"27% investment in ADT
and by holding "an effective blocking position"
that prevents independent parties from bidding for ADT. The complaint seeks
preliminary and permanent relief enjoining the company from acquiring the
outstanding shares of ADT and unspecified damages. The company believes it
has good and valid defenses to the claims asserted and does not anticipate any
material adverse effect upon its overall financial condition or results of
operations.
Subject to the approval of the KCC, the company entered into five new
gas supply contracts with certain entities affiliated with The Bishop Group,
Ltd. (Bishop entities) which are currently regulated by the KCC. A contested
hearing was held for the approval of those contracts. While the case was
under consideration by the KCC, the FERC issued an order under which it
extended jurisdiction over the Bishop entities. On November 3, 1995, the KCC
stayed its consideration of the contracts between the company and the Bishop
entities until the FERC takes final appealable action on its assertion of
jurisdiction over the Bishop entities.
On June 28, 1996, the KCC issued its order by dismissing the company's
application for approval of the contracts and of recovery of the related costs
from its customers. The company appealed this ruling and on January 24, 1997,
the Kansas Court of Appeals reversed the KCC order and upheld the contracts
and the company's recovery of related costs from its customers were approved
by operation of law.
As part of the acquisition of WSS on December 31, 1996, WSS assigned to
WestSec, a wholly-owned subsidiary of Westar Capital established to acquire
the assets of WSS, a software license with Innovative Business Systems (IBS)
which is integral to the operation of its security business. On January 8,
1997, IBS filed litigation in Dallas County, Texas in the 298th Judicial
District Court concerning the assignment of the license to WestSec,
(Innovative Business Systems (Overseas) Ltd., and Innovative Business
Software, Inc. v. Westinghouse Electric Corporation, Westinghouse Security
Systems, Inc., WestSec, Inc., Western Resources, Inc., et al., Cause
No. 97-00184). The company and Westar Capital have demanded Westinghouse
Electric Corporation defend and indemnify them. While the loss of use of the
license may have a material impact on the operations of WestSec, management of
the company currently does not believe that the ultimate disposition of this
matter will have a material adverse effect upon the company's overall
financial condition or results of operations
The company and its subsidiaries are involved in various other legal,
environmental, and regulatory proceedings. Management believes that adequate
provision has been made and accordingly believes that the ultimate
dispositions of these matters will not have a material adverse effect upon the
company's overall financial position or results of operations.
8.approximately $597 million.
7. COMMITMENTS AND CONTINGENCIES
As part of its ongoing operations and construction program, the company has
commitments under purchase orders and contracts which have an unexpended balance
of approximately $69.9$87.8 million at December 31, 1996. Approximately
$12.8 million is attributable1997.
International Power Project Commitments: The company has ownership interests
in international power generation projects under construction in Colombia and
the Republic of Turkey and in existing power generation facilities in the
People's Republic of China. In 1998, commitments are not expected to modifications to upgrade the three turbines
at Jeffrey Energy Center to be completed by December 31, 1998.
In January 1994, the company entered into an agreement with Oklahoma
Municipal Power Authority (OMPA). Under the agreement, the company received a
prepayment
of approximately $41 million for which the company will provide capacity and
transmission services to OMPA through the year 2013.exceed $53
million. Currently, equity commitments beyond 1998 approximate $88 million.
Manufactured Gas Sites: The company has been associated with 15 former
manufactured gas sites located in Kansas which may contain coal tar and other
potentially harmful materials. The company and the Kansas Department of Health
and Environment (KDHE) entered into a consent agreement governing all future
work at the 15 sites. The terms of the consent agreement will allow the company
to investigate these sites and set remediation priorities based upon the results
of the investigations and risk analyses. The prioritized
sites will be investigated over a ten year period. The agreement will allowanalysis. At December 31, 1997, the company to set mutual objectives with the KDHE in order to expedite
effective response activities and to control costs and environmental impact.
The costs
incurred for preliminary site investigation and risk assessment in 1996 and 1995
werehave been
minimal. In accordance with the terms of the strategic alliance with ONEOK, agreement,
ownership of twelve of these sites and the aforementionedresponsibility for clean-up of these
sites will bewere transferred to New ONEOK upon
closing.ONEOK. The ONEOK agreement limits the company's liabilitiesour future
liability to an immaterial amount for future remediationamount. Our share of ONEOK income could be impacted
by these sites.
Superfund Sites:costs.
Clean Air Act: The company is onemust comply with the provisions of numerous potentially
responsible parties at a groundwater contamination site in Wichita, Kansas
(Wichita site) which is listed by the EPA as a Superfund site. The company has
previously been associated with other Superfund sites of which the company's
liability has been classified as de minimis and any potential obligations have
been settled at minimal cost. In 1994, the company settled Superfund
obligations at three sites for a total of $57,500. No Superfund obligations have
been settled since 1994. The company's obligation at the Wichita site appears to
be limited based on this experience. In the opinion of the company's
management, the resolution of this matter is not expected to have a material
impact on the company's financial position or results of operations.
Clean Air Act: The Clean Air
Act Amendments of 1990 (the Act)that require a two-phase reduction in certain emissions.
To meet the monitoring and
reporting requirements under the acid rain program, theThe company has installed continuous monitoring and reporting equipment at a total cost of approximately
$10 million as of December 31, 1996.to meet
the acid rain requirements. The company does not expect material capital
expenditures to be neededrequired to meet Phase II sulfur dioxide requirements.
Theand nitrogen oxides(NOx) and toxic limits, which were not set in the
law, were proposed by the EPA in January 1996. The company is currently
evaluating the steps it would need to take in order to comply with the proposed
new rules. The company will have three years from the date the limits were
proposed to comply with the new NOx rules.oxide
requirements.
Decommissioning: The company accrues 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 August 30, 1996, WCNOC submittedIn February 1997, the KCC approved the 1996 Decommissioning Cost Study
to the KCC for approval. Approval of this study was received from the KCC on
February 28, 1997.Study.
Based on the study, the company's share of theseWolf Creek's decommissioning costs,
under the immediate dismantlement method, is estimated to be approximately $624
million during the period 2025 through 2033, or approximately $192 million in
1996 dollars. These costs were calculated using an assumed inflation rate of
3.6% over the remaining service life from 1996 of 29 years.
Decommissioning costs are currently being charged to operating expenses in
accordance with the prior KCC orders. Electric rates charged to customers
provide for recovery of these decommissioning costs over the life of Wolf
Creek. Amounts expensed approximated $3.7 million in 19961997 and will increase
annually to $5.6 million in 2024. These expenses are deposited in an external
trust fund. The average after tax expected return on trust assets is 5.7%.
Approval of this funding schedule is still pending with the KCC.
The company's investment in the decommissioning fund, including reinvested
earnings approximated $33.0$43.5 million and $25.1$33.0 million at December 31, 19961997 and
December 31, 1995,1996, respectively. Trust fund earnings accumulate in the fund
balance and increase the recorded decommissioning liability.
These amounts
are reflected in Investments and Other Property, Decommissioning trust, and
the related liability is included in Deferred Credits and Other Liabilities,
Other, on the Consolidated Balance Sheets.
The SEC staff of the SEC has questioned certain current accounting
practices used by nuclearthe way electric generating station owners regarding the
recognition, measurement,utilities recognize, measure
and classification ofclassify decommissioning costs for nuclear electric generating stations.stations in
their financial statements. In response to thesethe SEC's questions, the Financial
Accounting Standards Board is expected to issue newreviewing the accounting standards for closure and removal
costs, including decommissioning in 1997.of nuclear power plants. If current
electric utility industry accounting
practices for suchnuclear power plant decommissioning costs
are changed: (1)changed, the following
could occur:
- The company's annual decommissioning expensesexpense could increase, (2) thebe higher
than in 1997
- The estimated present value ofcost for decommissioning costs could be recorded as a
liability rather(rather than as accumulated depreciation, and (3) trust fund income
from the external decommissioning trustsdepreciation)
- The increased costs could be reportedrecorded as additional investment income rather than as a reduction to decommissioning expense. When revised
accounting guidance is issued,in
the company will also have to evaluate its
effect on accounting for removal costs of other long-lived assets.Wolf Creek plant
The company isdoes not able to predict what effectbelieve that such changes, if required, would have onadversely
affect its operating results of
operations, financial position, or related regulatory practices until the final
issuance of revised accounting guidance, but such effect could be material.due to its current ability to recover
decommissioning costs through rates.
Nuclear Insurance: The company carries premature decommissioning insurance
which has several restrictions. One of these is that it can only be used if
Wolf Creek incurs an accident exceeding $500 million in expenses to safely
stabilize the reactor, to decontaminate the reactor and reactor station site in
accordance with a plan approved by the NRC,Nuclear Regulatory Commission (NRC) and
to pay for on-site property damages. This decommissioning insurance will only
be available if the insurance funds are not needed to implement the NRC-approved
plan for stabilization and decontamination.
Nuclear Insurance:
The Price-Anderson Act limits the combined public liability of the owners of
nuclear power plants to $8.9 billion for a single nuclear incident. If this
liability limitation is insufficient, the U.S. Congress will consider taking
whatever action is necessary to compensate the public for valid claims. The
Wolf Creek owners (Owners) have purchased the maximum available private
insurance of $200 million and themillion. 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 $79.3 million ($37.3 million,
company's share) 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 ($4.7 million, company's share) 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, company's share). This insurance is provided by
a
combination of "nuclear insurance pools" ($500 million) and Nuclear Electric Insurance Limited (NEIL) ($2.3 billion). In the event of an accident,
insurance proceeds must first be used for reactor stabilization and site
decontamination. The company's share of any remaining proceeds can be used for
property damage or premature decommissioning costs up to $1.3 billion
(company's share).costs. Premature decommissioning
insurance cost recovery is the
excess ofcoverage applies only if an accident at Wolf Creek exceeds $500 million in
property damage and decommissioning expenses and only after trust funds previously collected for decommissioning (as discussed under
"Decommissioning").have
been exhausted.
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, the company may be subject to retrospective
assessments under the current policies of approximately $8$9 million per year.
Although the company maintains various insurance policies to provide coverage
for potential losses and liabilities resulting from an accident or an extended
outage, the company's 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 the company's
financial condition and results of operations.
Fuel Commitments: To supply a portion of the fuel requirements for its
generating plants, the company has 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, 1996, WCNOC's1997, Wolf Creek's
nuclear fuel commitments (company's share) were approximately $15.4$9.9 million for
uranium concentrates expiring at various times through 2001, $59.4$35.1 million for
enrichment expiring at various times through 2003 and $70.3$67.4 million for
fabrication through 2025.
At December 31, 1996,1997, the company's coal contract commitments in 19961997 dollars
under the remaining terms of the contracts were approximately $2.6$2.4 billion. The
largest coal contract expires in 2020, with the remaining coal contracts
expiring at various times through 2013.
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. The company's portion of the
assessment for Wolf Creek is approximately $7 million, payable over 15 years.
Management expects such costs to be recovered through the ratemaking process.
Investment Commitments: During 1996, The Wing Group obtained ownership
interests in independent power generation projects under construction in
Turkey and Colombia. The Wing Group or other non-regulated company
subsidiaries are committed to future funding of equity interests in these
projects. In 1997, commitments are not expected to exceed $31 million.
Currently, equity commitments beyond 1997 are approximately $3 million. The
company has also committed $105 million through June of 1998 to power
generation projects in the People's Republic of China.
9.
8. RATE MATTERS AND REGULATION
Utility expenses and credits recognized as regulatory assets and
liabilities on the Consolidated Balance Sheets are recognized in income as the
related amounts are included in service rates and recovered from or refunded
to customers in utility revenues. The company expects to recover the
following regulatory assets in rates:
December 31, 1996 1995
(Dollars in Thousands)
Coal contract settlement costs $ 21,037 $ 27,274
Service line replacement 12,921 14,164
Post employment/retirement benefits (See
Note 12) 40,834 35,057
Deferred plant costs 31,272 31,539
Phase-in revenues 26,317 43,861
Debt issuance costs (See Note 1) 78,532 80,354
Deferred cost of gas purchased 21,332 20,318
Other regulatory assets 8,794 9,826
Total regulatory assets $241,039 $262,393
Coal Contract Settlements: In March 1990, the KCC issued an order
allowing KGE to defer its share of a 1989 coal contract settlement with the
Pittsburg and Midway Coal Mining Company amounting to $22.5 million. This
amount was recorded as a deferred charge and is included in Deferred Charges
and Other Assets, Regulatory assets, on the Consolidated Balance Sheets. The
settlement resulted in the termination of a long-term coal contract. The KCC
permitted KGE to recover this settlement as follows: 76% of the settlement
plus a return over the remaining term of the terminated contract (through
2002) and 24% to be amortized to expense with a deferred return equivalent to
the carrying cost of the asset.
In September 1994, the FERC issued an order allowing the company to
defer $24.5 million in costs associated with the buy-out of a long-term coal
supply contract with American Metal Climax (AMAX) to supply the Lawrence and
Tecumseh Energy Centers. The deferred costs are included in the Deferred
Charges and Other Assets, Regulatory assets, section of the Consolidated Balance
Sheets and are amortized monthly to expense over the life of the original AMAX
contract (through 2013).
Service Line Replacement: On January 24, 1992, the KCC issued an order
allowing the company to continue the deferral of service line replacement
program costs incurred since January 1, 1992, including depreciation, property
taxes, and carrying costs for recovery. As part of the natural gas
distribution rate case settlement on July 11, 1996 (See discussion of natural
gas distribution rate case above), the company was permitted to begin
amortizing these costs in July 1996. Approximately $431,000 will be amortized
each month through June 1999. At December 31, 1996, approximately $12.9
million of these deferrals have been included in Deferred Charges and Other
Assets, Regulatory assets, on the Consolidated Balance Sheets. These
deferrals will become a responsibility of New ONEOK, when the alliance with
ONEOK is consummated.
Deferred Plant Costs: In 1986, KGE recognized the effects of Wolf Creek
related disallowances in accordance with Statement of Financial Accounting
Standards No. 90 "Regulated Enterprises - Accounting for Abandonments and
Disallowances of Plant Costs".
Phase-in Revenues: In 1988, the KCC ordered the accrual of phase-in
revenues to be discontinued by KGE effective December 31, 1988. KGE began
amortizing the phase-in revenue asset on a straight-line basis over 9 l/2
years beginning January 1, 1989. At December 31, 1996, approximately $26
million of deferred phase-in revenues remain to be recovered.
Deferred Cost of Gas Purchased: The company, under rate orders from
the KCC, OCC, and FERC, recovers increases in fuel and natural gas costs through
fuel adjustment clauses for wholesale and certain retail electric customers
and various cost of gas riders (COGR) for natural gas customers. The KCC and
the OCC
require the annual difference between actual gas cost incurred and cost
recovered through the application of the COGR be deferred and amortized
through rates in subsequent periods.
KCC Rate Proceedings: On August 17, 1995, the company and KGE filed
three proceedings with the KCC. The first sought a $36 million increase in
revenues from the company's natural gas distribution business. In separate
dockets, the company and KGE filed withJanuary 1997, the KCC a request to more rapidly
recover KGE's investment in its assets of Wolf Creek over the next seven years
by increasing depreciation by $50 million each year and a request to reduce
annual depreciation expense by approximately $11 million for electric
transmission, distribution and certain generating plant assets to reflect the
useful lives of these properties more accurately. The company sought to reduceapproved an agreement that
reduced electric rates for KGE customers by approximatelyboth KPL and KGE. Significant terms of the agreement
are as follows:
- The company made permanent an interim $8.7 million annually in each
of the seven years of accelerated Wolf Creek depreciation.
On April 15, 1996, the KCC issued an order allowing a revenue increase
of $33.8 million in the company's natural gas distribution business. On May 3,
1996, the company filed a Petition for Reconsideration and on July 11, 1996,
the KCC issued its Order on Reconsideration allowing the revenue to be
increased to $34.4 million.
On May 23, 1996, the company implemented an $8.7 million electric rate reduction
toimplemented by KGE customers on an interim basis. On October 22, 1996, the
company, the KCC Staff, the City of Wichita, and the Citizens Utility
Ratepayer Board filed an agreement with the KCC whereby the company's retail
electric rates would be reduced, subject to approval by the KCC.in May 1996. This agreementreduction was approved on January 15, 1997. Under the agreement, oneffective February
1, 1997,1997.
- The company reduced KGE's annual rates were reduced by $36.3 million and, in addition, the May
1996 interim reduction became permanent. KGE's rates will be reduced by
another $10$36 million effective JuneFebruary
1, 1998, and again on June 1, 1999.1997.
- The company reduced KPL's annual rates were reduced by $10 million effective February
1, 1997.
Two one-time
rebates of- The company rebated $5 million will be credited to the company'sall of it electric customers in
January 19981998.
- The company will reduce KGE's annual rates by an additional $10 million
on June 1, 1998.
- The company will rebate an additional $5 million to all of its electric
customers in January 1999.
- The company will reduce KGE's annual rates by an additional $10 million
on June 1, 1999.
All rate decreases are cumulative. Rebates are one-time events and 1999. The agreement also fixed annual savings from the merger with
KGE at $40 million. This level of merger savings provides for complete
recovery of and a return on the acquisition premium.do not
influence future rates.
9. LEGAL PROCEEDINGS
On April 15, 1996,January 8, 1997, Innovative Business Systems, Ltd. (IBS) filed suit
against the company filed an applicationand Westinghouse Electric Corporation (WEC), Westinghouse
Security Systems, Inc. (WSS) and WestSec, Inc. (WestSec), a wholly-owned
subsidiary of the company established to acquire the assets of WSS, in Dallas
County, Texas district court (Cause No 97-00184) alleging, among other things,
breach of contract by WEC and interference with contract against the company in
connection with the KCC
requesting an order approving its proposalsale by WEC of the assets of WSS to merge with KCPL and for other
related relief. On July 29, 1996,the company. IBS claims
that WEC improperly transferred software owned by IBS to the company filed its First Amended
Application with the KCC in its proceeding for approval to merge with KCPL.
The amended application proposed an incentive rate mechanism requiring all
regulated earnings in excess of the merged company's 12.61% return on equity
to be split among customers, shareowners, and additional depreciation on Wolf
Creek.
On November 27, 1996, the KCC issued a Suspension Order and on December
3, 1996, an order was issued which suspended, subject to refund, costs related
to purchases from Kansas Pipeline Partnership included in the company's COGR.
On December 12, 1996,that
the company filed a Petition for Reconsideration or For
More Definite Statement by Staff of the Issuesis not entitled to be addressed in this Docket.
On March 3, 1997, the Staff issued a More Definite Statement specifying which
charges from Kansas Pipeline Partnership (KPP) it asserts are inappropriate
for inclusion in the company's COGR.its use. The company responded tohas demanded WEC defend and
indemnify it. WEC and the More
Definite Statement stating that itcompany have denied IBS' allegations and are
vigorously defending against them. Management does not believe anythat the
ultimate disposition of the charges from
KPP should be disallowed from its COGR. The company does not expect this proceeding tomatter will have a material adverse effect on itsupon the
company's overall financial condition or results of operations.
MPSC Proceedings: On May 3, 1996,The company and its subsidiaries are involved in various other legal,
environmental and regulatory proceedings. Management believes that adequate
provision has been made and accordingly believes that the ultimate dispositions
of these matters will not have a material adverse effect upon the company's
overall financial position or results of operations.
10. EMPLOYEE BENEFIT PLANS
Pension: The company filed an application
with the MPSC requesting an order approving its proposal to merge with KCPL.
The application includes the same regulatory plan as proposed before the KCC and
includes an annual rate reductionmaintains qualified noncontributory defined benefit
pension plans covering substantially all utility employees. Pension benefits
are based on years of $21 million for KCPL retail electric
customers.
FERC Proceedings: On August 22, 1996, the company filed with the FERC
an application for approval of its proposed merger with KCPL. On December 18,
1996, the FERC issued a Merger Policy Statement (Policy Statement) which
articulates three principal factors the FERC will apply for analyzing mergers:
(1) effect on competition, (2) customer protection, and (3) effect on
regulation. The FERC has requested the company toservice and the employee's compensation during the five
highest paid consecutive years out of ten before retirement. The company's
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.
Salary Continuation: The company will revise
its filing to comply withmaintains a non-qualified Executive Salary
Continuation Program for the specific requirementsbenefit of certain management employees, including
executive officers.
The following tables provide information on the Policy Statement.
10. INCOME TAXES
Under SFAS 109, temporary differences gave rise to deferred tax assetscomponents of pension and
deferred tax liabilities atsalary continuation costs funded status and actuarial assumptions for the
company:
Year Ended December 31, 1996 and 1995, respectively, as
follows:1997 1996 1995
(Dollars in Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback.SFAS 87 Expense:
Service cost. . . . . . . . . . $ 99,46611,337 $ 105,007
Alternative minimum tax carryforwards.11,644 $ 11,059
Interest cost on projected
benefit obligation. . 250 18,740
Other.. . . . 35,836 34,003 32,416
(Gain) loss on plan assets. . . (113,287) (65,799) (102,731)
Deferred investment gain (loss) 73,731 30,119 70,810
Net amortization. . . . . . . . 1,084 2,140 1,132
Other . . . . . . . . . . . . . 519 - -
Net expense . . . . . . . . $ 9,220 $ 12,107 $ 12,686
December 31, 1997 1996 1995
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of
benefit obligations:
Vested . . . . . . . . . . . $365,809 $347,734 $331,027
Non-vested . . . . . . . . . 21,024 23,220 21,775
Total. . . . . . . . . . . $386,833 $370,954 $352,802
Plan assets (principally debt
and equity securities) at
fair value . . . . . . . . . . . $584,792 $495,993 $444,608
Projected benefit obligation . . . 462,964 483,862 456,707
Funded status. . . . . . . . . . . 121,828 12,131 (12,099)
Unrecognized transition asset. . . (369) (448) (527)
Unrecognized prior service costs . 39,763 62,434 57,087
Unrecognized net (gain). . . . . . (193,313) (103,132) (75,312)
Accrued liability. . . . . . . . $(32,091) $(29,015) $(30,851)
Year Ended December 31, 1997 1996 1995
Actuarial Assumptions:
Discount rate. . . . . . . . . . 7.5% 7.5% 7.5%
Annual salary increase rate. . . 3.5-4.75% 4.75% 4.75%
Long-term rate of return . . . . 9.0-9.25% 8.5-9.0% 8.5-9.0%
Postretirement and Postemployment Benefits: The company accrues the cost of
postretirement benefits, primarily medical benefit costs, during the years an
employee provides service. The company accrues postemployment benefits when the
liability has been incurred.
Based on actuarial projections and adoption of the transition method of
implementation which allows a 20-year amortization of the accumulated benefit
obligation, postretirement benefits expense approximated $16.6 million, $16.4
million and $15.0 million for 1997, 1996 and 1995, respectively. The company's
total postretirement benefit obligation approximated $83.7 million and $123.0
million at December 31, 1997 and 1996, respectively. The following table
summarizes the status of the company's postretirement benefit plans for
financial statement purposes and the related amounts included in the
Consolidated Balance Sheets:
December 31, 1997 1996 1995
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . $ 53,910 $ 76,588 $ 81,402
Active employees fully eligible . . 6,814 10,060 7,645
Active employees not fully eligible 22,949 36,345 34,144
Total . . . . . . . . . . . . . . 83,673 122,993 123,191
Fair value of plan assets . . . . . . . 118 78 46
Funded status . . . . . . . . . . . . . (83,555) (122,915) (123,145)
Unrecognized prior service cost . . . . (4,592) (8,157) (8,900)
Unrecognized transition obligation. . . 60,146 104,920 111,443
Unrecognized net (gain) . . . . . . . . (828) (8,137) (7,271)
Accrued postretirement benefit costs $(28,829) $(34,289) $(27,873)
Year Ended December 31, 1997 1996 1995
Actuarial Assumptions:
Discount rate . . . . . . . . . . . . 7.5% 7.5% 7.5%
Annual salary increase rate . . . . . 4.75% 4.75% 4.75%
Expected rate of return . . . . . . . 9.0% 9.0% 9.0%
For measurement purposes, an annual health care cost growth rate of 9% was
assumed for 1997, decreasing one percent per year to five percent in 2001 and
thereafter. The health care cost trend rate has a significant effect on the
projected benefit obligation. Increasing the trend rate by one percent each
year would increase the present value of the accumulated projected benefit
obligation by $3.5 million and the aggregate of the service and interest cost
components by $0.3 million.
In accordance with an order from the KCC, the company has deferred
postretirement and postemployment expenses in excess of actual costs paid. In
1997 the company received authorization from the KCC to invest in AHTC
investments. Income from the AHTC investments will be used to offset the
deferred and incremental costs associated with postretirement and postemployment
benefits offered to the company's employees. The income generated from the AHTC
investments replaces the income stream from COLI contracts purchased in 1992 and
1993 which was used for the same purpose.
Savings: The company maintains savings plans in which substantially all
employees participate. The company matches employees' contributions up to
specified maximum limits. The funds of the plans are deposited with a trustee
and invested at each employee's option in one or more investment funds,
including a company stock fund. The company's contributions were $5.0 million,
$4.6 million and $5.1 million for 1997, 1996 and 1995, respectively.
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 contribution to the plan for 1997 was $34,000.
Protection One maintains a qualified employee stock purchase plan that allows
eligible employees to acquire shares of Protection One common shares at 85% of
fair market value of the common stock. A total of 650,000 shares of common
stock
have been reserved for issuance in this program.
Stock Based Compensation Plans: The company has two stock-based compensation
plans, a long-term incentive and share award plan (LTISA Plan) and a long-term
incentive program (LTI Program). The company accounts for these plans under
Accounting Principles Board Opinion No. 25 and the related Interpretations. Had
compensation cost been determined pursuant to Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" (SFAS 123), the
company would have recognized additional compensation costs during 1997, 1996
and 1995. However, recognition of the compensation costs would not have been
material to the Consolidated Statements of Income nor would these costs have
affected basic earnings per share.
The LTISA Plan was implemented to help ensure that managers and board members
(Plan Participants) were properly incented to increase shareowner value. It was
established to replace the company's LTI Program, discussed below. Under the
LTISA Plan, the company may grant awards in the form of stock options, dividend
equivalents, share appreciation rights, restricted shares, restricted share
units, performance shares and performance share units to Plan Participants. Up
to three million shares of common stock may be granted under the LTISA Plan.
The LTISA Plan granted 459,700 and 205,700 stock options and 459,700 and
205,700 dividend equivalents to Plan Participants during 1997 and 1996,
respectively. The exercise price of the stock options granted was $30.75 and
$29.25 in 1997 and 1996, respectively. These options vest in nine years.
Accelerated vesting allows stock options to vest within three years, dependent
upon certain company performance factors. The options expire in approximately
ten years. The weighted-average grant-date fair value of the dividend
equivalent was $6.21 and $5.82 in 1997 and 1996, respectively. The value of
each dividend equivalent is calculated as a percentage of the accumulated
dividends that would have been paid or payable on a share of company common
stock. This percentage ranges from zero to 100%, based upon certain company
performance factors. The dividend equivalents expire after nine years from the
date of grant. All stock options and dividend equivalents granted were
outstanding at December 31, 1997.
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 a dividend yield of 6.58% and 6.33%, expected volatility of 13.56% and
14.12%; and an expected life of 9.0 and 8.7 years for 1997 and 1996,
respectively. Additionally, the stock option model assumed a risk-free interest
rate of 6.72% and 6.45% for 1997 and 1996, respectively. The dividend
equivalent model assumed a risk-free interest rate of 6.36% and 6.61% for
1997 and 1996, respectively, an award percentage of 100% and a dividend
accumulation period of five years.
The LTI Program is a performance-based stock plan which awards performance
shares to executive officers (Program Participants) of the company equal in
value to 10% of the officer's annual base compensation. Each performance share
is equal in value to one share of the company's common stock. Each Program
Participant may be entitled to receive a common stock distribution based on the
value of performance shares awarded multiplied by a distribution percentage not
to exceed 110%. This distribution percentage is based upon the Program
Participants' and the company's performance. Program Participants also receive
cash equivalent to dividends on common stock for performance shares awarded.
In 1995, the company granted 14,756 performance shares, with a
weighted-average fair value of $28.81. The fair value of each performance share
is based on market price at the date of grant. No performance shares were
granted in 1997 or 1996. At December 31, 1997, shares granted in 1995 no longer
have a remaining contractual life and will be paid in March 1998.
11. PROTECTION ONE STOCK WARRANTS AND OPTIONS
Protection One has outstanding stock warrants and options which were
considered reissued and exercisable upon the company's acquisition of Protection
One on November 24, 1997. In lieu of adjusting the number of outstanding
options and warrants, holders of options or warrants received a $7 per share
equivalent cash payment in the acquisition. Stock option activity subsequent to
the acquisition was as follows:
Warrants
and Options Price Range
Balance at November 24, 1997. . . . . . 2,198,389 $0.05-$16.375
Granted . . . . . . . . . . . . . . . . . 29,945 30,789
Total deferred tax assets. . . . . . . $ 129,661 $ 154,536
Deferred Tax Liabilities:
Accelerated depreciation and other . . . $ 654,102 $ 653,134
Acquisition premium. . . . . . . . . . . 307,242 315,513
Deferred future income taxes . . . . . . 217,257 282,476
Other.- -
Exercised . . . . . . . . . . . . . . . . . 61,432 70,883
Total deferred tax liabilities . . . . $1,240,033 $1,322,006
Accumulated deferred
income taxes, net.(306) $ 0.05
Surrendered . . . . . . . . . . . $1,110,372 $1,167,470
In. . . - -
Balance at December 31, 1997. . . . . . 2,198,083 $0.05-$16.375
Stock options and warrants outstanding at December 31, 1997 are as follows:
Number Weighted Weighted
Range of Outstanding Average Average
Exercise and Remaining Life Exercise
Price Exercisable (Years) Price
$ 5.875-$ 9.125 244,560 8 $ 6.566
$ 8.000-$10.313 444,000 8 $ 8.076
$12.125-$16.375 148,000 8 $14.857
$ 9.50 278,000 9 $ 9.50
$15.00 50,000 9 $15.00
$ 0.05 1,425 9 $ 0.05
$ 3.633 103,697 4 $ 3.633
$ 0.167 462,001 6 $ 0.167
$ 6.60 466,400 8 $ 6.60
The company holds a call option for an additional 2,750,238 shares of
Protection One, exercisable at a price of $15.50. The option expires no later
than October 31, 1999.
Certain options outstanding have been issued as incentive awards to
directors, officers, and key employees in accordance with various rate orders receivedProtection One's 1994
Stock Option Plan. Had the fair value based method been used to determine
compensation expense for these stock options, recognition of the compensation
costs would not have been material.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value as set forth in Statement of Financial Accounting Standards No. 107
"Disclosures about Fair Value of Financial Instruments".
Cash and cash equivalents, short-term borrowings and variable-rate debt are
carried at cost which approximates fair value. The decommissioning trust is
recorded at fair value and is based on the quoted market prices at December 31,
1997 and 1996. The fair value of fixed-rate debt, redeemable preference stock
and other mandatorily redeemable securities 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
estimated fair values of contracts related to commodities have been determined
using quoted market prices of the same or similar securities.
The recorded amount of accounts receivable and other current financial
instruments approximate fair value.
The fair value estimates presented herein are based on information available
at December 31, 1997 and 1996. These fair value estimates have not been
comprehensively revalued for the purpose of these financial statements since
that date and current estimates of fair value may differ significantly from the
KCC and the OCC,
the company has not yet collected through rates the amounts necessary to paypresented herein. Because a significantsubstantial portion of the net accumulated deferred income tax liabilities.
Ascompany's
operations are regulated, the company believes that any gains or losses related
to the retirement of debt or redemption of preferred securities would not have
a material effect on the company's financial position or results of operations.
The carrying values and estimated fair values of the company's financial
instruments are as follows:
Carrying Value Fair Value
December 31, 1997 1996 1997 1996
(Dollars in Thousands)
Decommissioning trust. . $ 43,514 $ 33,041 $ 43,514 $ 33,041
Fixed-rate debt. . . . . 2,019,103 1,224,743 2,101,167 1,260,722
Redeemable preference
stock. . . . . . . . . 50,000 50,000 51,750 52,500
Other mandatorily
redeemable securities. 220,000 220,000 226,088 214,800
The company is involved in both the marketing of electricity and risk
management believesservices to wholesale electric customers and the purchase of
electricity for the company's retail customers. In addition to the purchase and
sale of electricity, the company engages in price risk management activities,
including the use of forward contracts, futures, swap agreements and put and
call options. The availability and use of these types of contracts allow the
company to manage and hedge its contractual commitments, reduce its exposure
relative to the volatility of cash market prices and take advantage of selected
arbitrage opportunities via open positions. Such open positions during 1997
were not material to the company's financial position or results of operations.
In general, the company does not seek to take significant commodity risk for
the purpose of generating margins in the ordinary course of its trading
activities. The company has established a risk management policy designed to
limit the company's exposure to price risk, and it continually monitors and
reviews this policy to ensure that it is probableresponsive to changing business
conditions. This policy requires that, in general, positions taken with
derivatives be offset by positions in physical transactions or other
derivatives. Due to the illiquid nature of the emerging electric markets, net
future increasesopen positions in income
taxes payable will be recovered from customers, it has recordedterms of price, volume and specified delivery point can occur.
December 31, 1997 1996
(Dollars in Thousands)
Notional Notional
Volumes Estimated Gain/ Volumes Estimated Gain/
(MWH's) Fair Value (loss) (mmbtu's) Fair Value (loss)
Forward
contracts 359,200 $9,086 $202 - - -
Options 924,000 $1,790 ($329) - - -
Natural gas
futures - $ - $ - 6,540,000 $16,032 $2,061
Natural gas
swaps - $ - $ - 2,344,000 $ 5,500 $1,315
In November 1997, the company contributed its natural gas marketing business
to ONEOK. As a deferred
asset for these amounts. These assets are also a temporary difference for
which deferred income tax liabilitiesresult, the company did not have been provided.
11.any natural gas futures or
natural gas swaps as of December 31, 1997.
13. COMMON STOCK, PREFERRED STOCK, PREFERENCE STOCK,
AND OTHER MANDATORILY REDEEMABLE SECURITIES
The company's Restated Articles of Incorporation, as amended, provide for
85,000,000 authorized shares of common stock. At December 31, 1996,
64,625,2591997, 65,409,603
shares were outstanding.
The company has a Dividend Reinvestment andDirect Stock Purchase Plan (DRIP). Shares issued under the
DRIP may be either original issue shares or shares purchased on the open
market. The company has been issuingissued original issue shares sinceunder DRIP from January 1,
1995 with 935,461until October 15, 1997. On November 1, 1997, DRIP began issuing shares
purchased on the open market. During 1997, a total of 837,549 shares were
issued in 1996 under DRIP including 784,344 original issue shares and 53,205 shares
purchased on the DRIP.open market. At December 31, 1996, 2,082,1661997, 1,244,617 shares were
available under the DRIP registration statement.
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 the
option of the company.
Preference Stock Subject to Mandatory Redemption: On July 1, 1996, all shares of the
company's 8.50% Preference Stock due 2016 were redeemed. The mandatory sinking fund
provisions of the 7.58% Series preference stock require the company to redeem
25,000 shares annually beginning on April 1, 2002 and each April 1 through 2006
and the remaining shares on April 1, 2007, all at $100 per share. The company
may, at its option, redeem up to an additional 25,000 shares on each April 1 at
$100 per share. The 7.58% Series also is redeemable in whole or in part, at the
option of the company, subject to certain restrictions on refunding, at a
redemption price of $104.55,
$103.79, $103.03 and $103.03$102.27 per share beginning April 1,
1996, 1997, 1998 and 1998,1999, respectively.
Other Mandatorily Redeemable Securities: On December 14, 1995, Western
Resources Capital I, a wholly-owned trust, issued four million preferred
securities of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A,
for $100 million. The trust interests represented by the preferred securities
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 in substance are tax deductible
by the company. These distributions are recorded as interest charges on the Consolidated Statements of Income.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 (the
Subordinated Debentures).
On July 31, 1996, Western Resources Capital II, a wholly-owned trust, of
which the sole asset is subordinated debentures of the company, 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 represented by the
preferred securities 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 in substance are tax deductible by
the company. These distributions are recorded as interest charges on the Consolidated Statements of Income.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.
The preferred securities are included under Western Resources obligated
mandatorily redeemable preferred securities of subsidiary trusts holding
solely company subordinated debentures (Other Mandatorily Redeemable
Securities) on the Consolidated Balance Sheets and Consolidated Statements of
Capitalization.
In addition to the company's obligations under the Subordinated Debentures,
the company has agreed pursuant to guarantees issued to the
trusts, the provisions of the trust agreements establishing the trusts and
related expense agreements, to guarantee, on a subordinated basis, payment of
distributions on the preferred securities (but not if the applicable trust
does not have sufficient funds to pay such distributions) and to pay all of
the expenses of the trusts (collectively, the "Back-up Undertakings").
Considered together, the Back-up Undertakingssecurities. These undertakings constitute a full
and unconditional guarantee by the company of the truststrust's obligations under the
preferred securities.
12. EMPLOYEE BENEFIT PLANS
Pension:14. LEASES
At December 31, 1997, the company had leases covering various property and
equipment. The company maintains qualified noncontributory defined
benefit pension plans covering substantially all employees. Pension benefitscurrently has no significant capital leases.
Rental payments for operating leases and estimated rental commitments are based on years of service and the employee's compensation during the five
highest paid consecutive years out of ten before retirement. The company's
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.
Salary Continuation: The company maintains a non-qualified Executive
Salary Continuation Program for the benefit of certain management employees,
including executive officers.
The following tables provide information on the components of pension
and salary continuation costs under Statement of Financial Accounting Standards
No. 87 "Employers' Accounting for Pension Plans" (SFAS 87), funded status and
actuarial assumptions for the company:as
follows:
Operating
Year Ended December 31, 1996 1995 1994Leases
(Dollars in Thousands)
SFAS 87 Expense:
Service cost.1995 . . . . . . . . . $ 11,644 $ 11,059 $ 10,197
Interest cost on projected
benefit obligation. . . . . . 34,003 32,416 29,734
(Gain) loss on plan assets. . . (65,799) (102,731) 7,351
Deferred investment gain (loss) 30,119 70,810 (38,457)
Net amortization. . . . . . . . 2,140 1,132 245
Net expense . . . . . . . . $ 12,107 $ 12,686 $ 9,070
December 31, 1996 1995 1994
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of
benefit obligations:
Vested . . . . . . . . . . . $347,734 $331,027 $278,545
Non-vested . . . . . . . . . 23,220 21,775 19,132
Total. . . . . . . . . . . $370,954 $352,802 $297,677
Plan assets (principally debt
and equity securities) at
fair value . . . . . . . . . . . $495,993 $444,608 $375,521
Projected benefit obligation . . . 483,862 456,707 378,146
Funded status. . . . . . . . . . . 12,131 (12,099) (2,625)
Unrecognized transition asset. . . (448) (527) (2,205)
Unrecognized prior service costs . 62,434 57,087 47,796
Unrecognized net (gain). . . . . . (103,132) (75,312) (56,079)
Accrued liability. . . . . . . . $(29,015) $(30,851) $(13,113)
Year Ended December 31, 1996 1995 1994
Actuarial Assumptions:
Discount rate. . . . . . . . . . 7.5% 7.5% 8.0-8.5%
Annual salary increase rate. . . 4.75% 4.75% 5.0%
Long-term rate of return . . . . 8.5-9.0% 8.5-9.0% 8.0-8.5%
Postretirement: The company follows the provisions of Statement of
Financial Accounting Standards No. 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106). This statement
requires the accrual of
postretirement benefits other than pensions, primarily medical benefit costs,
during the years an employee provides service.
Based on actuarial projections and adoption of the transition method of
implementation which allows a 20-year amortization of the accumulated benefit
obligation, postretirement benefits expenses approximated $16.4 million, $15.0
million, and $12.4 million for 1996, 1995, and 1994, respectively. The
company's total postretirement benefit obligation approximated $123.0 million
and $123.2 million at December 31, 1996 and 1995, respectively. In addition,
the company received an order from the KCC permitting the initial deferral of
SFAS 106 expense in excess of amounts previously recognized. The following
table summarizes the status of the company's postretirement benefit plans for
financial statement purposes and the related amounts included in the
Consolidated Balance Sheets:
December 31, 1996 1995 1994
(Dollars in Thousands)
Reconciliation of Funded Status:
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . $ 76,588 $ 81,402 $68,570
Active employees fully eligible . 10,060 7,645 13,549
Active employees not fully eligible 36,345 34,144 32,484
Total63,353
1996 . . . . . . . . . . . . 122,993 123,191 114,603
Fair value of plan assets . . . . . 78 46 -
Funded status63,181
1997 . . . . . . . . . . . (122,915) (123,145) (114,603)
Unrecognized prior service cost . . (8,157) (8,900) ( 9,391)
Unrecognized transition obligation. 104,920 111,443 117,967
Unrecognized net (gain) . . . . . . (8,137) (7,271) ( 14,489)
Accrued postretirement benefit costs $(34,289) $(27,873) $(20,516)
Year Ended December 31, 1996 1995 1994
Actuarial Assumptions:
Discount rate71,126
Future Commitments:
1998 . . . . . . . . . . 7.5 % 7.5 % 8.0-8.5%
Annual salary increase rate . . . 4.75 % 4.75 % 5.0 %
Expected rate of return . . . . . 9.0 % 9.0 % 8.5 %
For measurement purposes, an annual health care cost growth rate of 10%
was assumed for 1996, decreasing one percent per year to five percent in 2001
and thereafter. The health care cost trend rate has a significant effect on
the projected benefit obligation. Increasing the trend rate by one percent
each year would increase the present value of the accumulated projected
benefit obligation by $5.5 million and the aggregate of the service and
interest cost components by $0.5 million.
Postemployment: The company adopted Statement of Financial Accounting
Standards No. 112 "Employers' Accounting for Postemployment Benefits" (SFAS
112) in the first quarter of 1994, which established accounting and reporting
standards for postemployment benefits. The statement requires the company to
recognize the liability to provide postemployment benefits when the liability
has been incurred. The company received an order from the KCC permitting the
initial deferral of SFAS 112 expense.
In accordance with the provision of an order from the KCC, the company
has deferred postretirement and postemployment expenses representing the excess
expense incurred upon adoption of SFAS 106 and SFAS 112. In 1992 and 1993,
the company purchased COLI policies whose associated income stream was
intended to offset actual
postretirement and postemployment costs incurred. See Note 1 regarding
legislative action related to COLI. As of December 31, 1996 and 1995, the
company recognized a regulatory asset for postretirement expense of
approximately $31.6 million and $25.3 million and for postemployment expense
of approximately $9.3 million and $9.8 million, respectively.
Savings: The company maintains savings plans in which substantially
all employees participate. The company matches employees' contributions up to
specified maximum limits. The funds of the plans are deposited with a trustee
and invested at each employee's option in one or more investment funds,
including a company stock fund. The company's contributions were $4.6
million, $5.1 million, and $5.1 million for 1996, 1995, and 1994,
respectively.
Stock Based Compensation Plans: The company has two stock-based
compensation plans, a long term incentive and share award plan (LTISA Plan)
and a long term incentive program (LTI Program). The company accounts for
these plans under Accounting Principles Board Opinion No. 25 and the related
Interpretations. Had compensation cost been determined pursuant to Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" (SFAS 123), the company would have recognized compensation costs
during 1996 and 1995. However, recognition of the compensation costs would
not have been material to the Consolidated Statements of Income nor would
these costs have affected earnings per share.
The LTISA Plan was implemented to help ensure that managers and board
members (Plan Participants) were properly incented to increase shareowner
value. It was established to replace the company's LTI Program, discussed
below. Under the LTISA Plan, the company may grant awards in the form of
stock options, dividend equivalents, share appreciation rights, restricted
shares, restricted share units, performance shares, and performance share
units to Plan Participants. Up to three million shares of common stock may be
granted under the LTISA Plan.
In 1996, the LTISA Plan granted 205,700 stock options and 205,700
dividend equivalents to Plan Participants. The exercise price of the stock
options granted was $29.25. These options vest in nine years. Accelerated
vesting allows stock options to vest within three years, dependent upon certain
company performance factors. The options expire in approximately ten years.
The weighted-average grant-date fair value of the dividend equivalent was
$5.82. The value of each dividend equivalent is calculated as a percentage of
the accumulated dividends that would have been paid or payable on a share of
company common stock. This percentage ranges from zero to 100%, based upon
certain company performance factors. The dividend equivalents expire after
nine years from the date of grant. All stock options and dividend equivalents
granted were outstanding at December 31, 1996.
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 a dividend yield of 6.33%, expected volatility of 14.12%; and an
expected life of 8.7 years. Additionally, the stock option model assumed a
risk-free interest rate of 6.45%. The dividend equivalent model assumed a
risk-free interest rate of 6.61%, an award percentage of 100% and a dividend
accumulation period of five years.
The LTI Program is a performance-based stock plan which awards
performance shares to executive officers (Program Participants) of the company
equal in value to 10% of the officer's annual base compensation. Each
performance share is equal in value to one share of the company's common stock.
Each Program Participant may be entitled to receive a common stock distribution
based on the value of performance shares awarded multiplied by a distribution
percentage not to exceed 110%. This distribution percentage is based upon the
Program Participants' and the company's
performance. Program Participants also receive cash equivalent to dividends
on common stock for performance shares awarded.
In 1995, the company granted 14,756 performance shares, with a
weighted-average fair value of $28.81. The fair value of each performance share
is based on market price at the date of grant. No performance shares were
granted in 1996. As of December 31, 1996, shares granted in 1995 have a
remaining contractual life of one year.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is practicable to
estimate that value as set forth in Statement of Financial Accounting Standards
No. 107 "Disclosures about Fair Value of Financial Instruments".
Cash and cash equivalents, short-term borrowings and variable-rate debt
are carried at cost which approximates fair value. The decommissioning trust
is recorded at fair value and is based on the quoted market prices at December
31, 1996 and 1995. The fair value of fixed-rate debt, redeemable preference
stock, and other mandatorily redeemable securities is estimated based on
quoted market prices for the same or similar issues or on the current rates
offered for instruments of the same remaining maturities and redemption
provisions. The estimated fair values of contracts related to commodities
have been determined using quoted market prices of the same or similar
securities.
The carrying values and estimated fair values of the company's financial
instruments are as follows:
Carrying Value Fair Value
December 31, 1996 1995 1996 1995
(Dollars in Thousands)
Decommissioning trust. . .$ 33,041 $ 25,070 $ 33,041 $ 25,070
Fixed-rate debt. . . . . . 1,224,743 1,240,877 1,260,722 1,294,365
Redeemable preference
stock.66,998
1999 . . . . . . . . . 50,000 150,000 52,500 160,405
Other mandatorily
redeemable securities. . 220,000 100,000 214,800 102,000. . . . 59,634
2000 . . . . . . . . . . . . . . 53,456
2001 . . . . . . . . . . . . . . 50,303
2002 . . . . . . . . . . . . . . 49,999
Thereafter . . . . . . . . . . . 655,558
Total. . . . . . . . . . . . . . $935,948
In 1987, KGE sold and leased back its 50% undivided interest in the La Cygne
2 generating unit. The La Cygne 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 La Cygne 2. The lease is an operating lease
for financial reporting purposes. The company recognized a gain on the sale
which was deferred and is being amortized over the initial lease term.
In 1992, the company deferred costs associated with the refinancing of the
secured facility bonds of the Trustee and owner of La Cygne 2. These costs are
being amortized over the life of the lease and are included in operating
expense. Approximately $21.4 million of this deferral remained on the
Consolidated Balance Sheet at December 31, 1996 1995
Notional Notional
Volumes Estimated Gain/ Volumes Estimated Gain/
(mmbtu's) Fair Value (loss) (mmbtu's) Fair Value (loss)
Natural gas
futures 6,540,000 $16,032 $2,061 7,440,000 $16,380 $2,678
Natural gas
swaps 2,344,000 $ 5,500 $1,315 2,624,000 $ 3,406 $ 18
The recorded amount1997.
Future minimum annual lease payments, included in the table above, required
under the La Cygne 2 lease agreement are approximately $34.6 million for each
year through 2002 and $576.6 million over the remainder of accounts receivablethe lease. KGE's
lease expense, net of amortization of the deferred gain and other current financial
instruments approximate fair value.
The fair value estimates presented herein are based on information
available as of December 31,refinancing costs,
was approximately $27.3 million for 1997 and $22.5 million for 1996 and 1995.
These fair value estimates have
not been comprehensively revalued for the purpose of these financial
statements since that date, and current estimates of fair value may differ
significantly from the amounts
presented herein. Because a substantial portion of the company's operations
are regulated, the company believes that any gains or losses related to the
retirement of debt or redemption of preferred securities would not have a
material effect on the company's financial position or results of operations.
14.15. LONG-TERM DEBT
The amount of the company's first mortgage bonds authorized by its 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 Deed of
Trust, dated April 1, 1940, as supplemented, is limited to a maximum of $2
billion. Amounts of additional bonds which may be issued are subject to
property, earnings and certain restrictive provisions of each Mortgage.mortgage.
Debt discount and expenses are being amortized over the remaining lives of
each issue. During the years 19971998 through 2001,2002, $21 million of other long-term
debt will mature in 1998, $125 million of bonds and $42 million of other
long-term debt will mature in 1999, and $75 million of bonds will mature in 2000.2000 and
$100 million of bonds will mature in 2002. No other bonds will mature and there are no cash sinking fund requirements for preference
stock or bonds during
this time period.
The company maintains a $350 million revolving credit agreement that
expires on October 5, 1999. Under the terms of this agreement, the company
may, at its option, borrow at different market-based interest rates and is
required, among other restrictions, to maintain a total debt to total
capitalization ratio of not greater than 65% at all times. A facility fee is
paid on the $350 million commitment. The unused portion of the revolving
credit facility may be used to provide support for commercial paper. At
December 31, 1996, the company had $275 million borrowed under the facility
and had available $75 million of unused capacity under the facility.
Long-term debt outstanding is as follows at December 31,31:
1997 1996 and 1995, was as follows:
1996 1995
(Dollars in Thousands)
Western Resources
First mortgage bond series:
7 1/4% due 1999. . . . . . . . . . . . . $ 125,000 $ 125,000
8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000
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
525,000 525,000
Pollution control bond series:
Variable due 2032 (1). . . . . . . . . . 45,000 45,000
Variable due 2032 (2). . . . . . . . . . 30,500 30,500
6% due 2033. . . . . . . . . . . . . 58,420 58,420
133,920 133,920
KGE
First mortgage bond series:
5 5/8% due 1996. . . . . . . . . . . . . - 16,000
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
300,000 316,000300,000
Pollution control bond series:
5.10 % due 2023. . . . . . . . . . . . . 13,757 13,822 13,957
Variable due 2027 (3). . . . . . . . . . 21,940 21,940
7.0 % due 2031. . . . . . . . . . . . . 327,500 327,500
Variable due 2032 (4). . . . . . . . . . 14,500 14,500
Variable due 2032 (5). . . . . . . . . . 10,000 10,000
387,697 387,762
387,897
Revolving credit agreement . . . . . . . . . - 275,000
50,000Western Resources 6 7/8% unsecured
senior notes due 2004. . . . . . . . . . . 370,000 -
Western Resources 7 1/8% unsecured
senior notes due 2009 . . . . . . . . . . 150,000 -
Protection One 6.4% senior subordinated
discount notes due 2005. . . . . . . . . 171,926 -
Protection One 6.75% convertible senior
subordinated discount notes due 2003. . . 102,500 -
Other long-term agreements . . . . . . . . . 67,748 65,190 -
Less:
Unamortized debt discount. . . . . . . . 5,719 5,289 5,554
Long-term debt due within one year . . . 21,217 - 16,000
Long-term debt (net). . . . . . . . . . . . $2,181,855 $1,681,583 $1,391,263
Rates at December 31, 1996:1997: (1) 3.68%4.00%, (2) 3.582%4.05%, (3) 3.55%3.95%,
(4) 3.60%3.85% and (5) 3.52%
15.3.89%
Protection One maintains a $100 million revolving credit facility that
expires in January 2000. Under the terms of this agreement, Protection One may,
at its option, borrow at different market-based interest rates. At December 31,
1997, there were no borrowings under this facility.
16. SHORT-TERM DEBT
The company has arrangements with certain banks to provide unsecured
short-term lines of credit on a committed basis totaling $973approximately $773
million. The agreements provide the company with the ability to borrow at
different market-based interest rates. The company pays commitment or facility
fees in support of these lines of credit. Under the terms of the agreements,
the company is required, among other restrictions, to maintain a total debt to
total capitalization ratio of not greater than 65% at all times. The unused
portion of these lines of credit are used to provide support for commercial
paper.
In addition, the company has agreements with several banks to borrow on an
uncommitted, as available, basis at money-market rates quoted by the banks.
There are no costs, other than interest, for these agreements. The company also
uses commercial paper to fund its short-term borrowing requirements.
Information regarding the company's short-term borrowings, comprised of
borrowings under the credit agreements, bank loans and commercial paper, is as
follows:
December 31, 1997 1996 1995 1994
(Dollars in Thousands)
Borrowings outstanding at year end:
Lines of credit $525,000 $ - $525,000 $ -
Bank loans 161,000 162,300 177,600 151,000
Commercial paper notes 75,500 293,440 25,850
157,200
Total $236,500 $980,740 $203,450 $308,200
Weighted average interest rate on
debt outstanding at year end
(including fees) 6.28% 5.94% 6.02% 6.25%
Weighted average short-term debt
outstanding during the year $787,507 $491,136 $301,871
$214,180
Weighted daily average interest
rates during the year
(including fees) 5.93% 5.72% 6.15% 4.63%
Unused lines of credit supporting
commercial paper notes $772,850 $447,850 $121,075
$145,000
16. LEASES
At17. INCOME TAXES
Income tax expense is composed of the following components at December 31,31:
1997 1996 1995
(Dollars in Thousands)
Currently payable:
Federal. . . . . . . . . $336,150 $54,644 $50,674
State. . . . . . . . . . 72,143 20,280 17,003
Deferred:
Federal. . . . . . . . . (19,766) 14,808 22,911
State. . . . . . . . . . (3,217) (615) 601
Amortization of investment
tax credits . . . . . . . (6,665) (6,758) (6,809)
Total income tax expense . $378,645 $82,359 $84,380
Under SFAS 109, temporary differences gave rise to deferred tax assets and
deferred tax liabilities as follows at December 31:
1997 1996
(Dollars in Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback. . . . . $ 97,634 $ 99,466
Security business deferred tax assets. . 103,054 -
Other. . . . . . . . . . . . . . . . . . 94,008 30,195
Total deferred tax assets. . . . . . . $ 294,696 $ 129,661
Deferred tax liabilities:
Accelerated depreciation and other . . . $ 625,176 $ 654,102
Acquisition premium. . . . . . . . . . . 299,162 307,242
Deferred future income taxes . . . . . . 213,658 217,257
Other. . . . . . . . . . . . . . . . . . 112,555 61,432
Total deferred tax liabilities . . . . $1,250,551 $1,240,033
Investment tax credits . . . . . . . . . . $ 109,710 $ 125,528
Accumulated deferred income taxes, net . . $1,065,565 $1,235,900
In accordance with various rate orders, the company had leases covering various propertyhas not yet collected
through rates certain accelerated tax deductions which have been passed on to
customers. As management believes it is probable that the net future increases
in income taxes payable will be recovered from customers, it has recorded a
deferred asset for these amounts. These assets also are a temporary difference
for which deferred income tax liabilities have been provided.
The effective income tax rates set forth below are computed by dividing total
federal and equipment.state income taxes by the sum of such taxes and net income. The
company currently has no capital leases.
Rental payments for operating leasesdifference between the effective tax rates and estimated rental commitmentsthe federal statutory income tax
rates are as follows:
Operating
Year Ended December 31, Leases1997 1996 1995
Effective Income Tax Rate. . . . . . . . . 43.4% 32.8% 31.8%
Effect of:
State income taxes. . . . . . . . . . . . (5.0) (5.1) (4.3)
Amortization of investment tax credits. . 0.8 2.7 2.5
Corporate-owned life insurance policies . 0.9 3.7 3.2
Accelerated depreciation flow through
and amortization, net . . . . . . . . . (0.4) (.2) (.2)
Adjustment to tax provision . . . . . . . (3.7) - -
Other . . . . . . . . . . . . . . . . . . (1.0) 1.1 2.0
Statutory Federal Income Tax Rate. . . . . 35.0% 35.0% 35.0%
18. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December 31:
1997 1996
(Dollars in Thousands)
1994 $ 55,076
1995 63,353
1996 66,181
Future Commitments:
1997 60,247
1998 52,643
1999 47,276
2000 43,877
2001 42,592
Thereafter 688,231
Total $ 934,866
In 1987, KGE soldElectric plant in service. . . . . . . $5,564,695 $5,448,489
Natural gas plant in service . . . . . - 834,330
5,564,695 6,282,819
Less - accumulated depreciation. . . . 1,895,084 2,058,596
3,669,611 4,224,223
Construction work in progress. . . . . 60,006 93,834
Nuclear fuel (net) . . . . . . . . . . 40,696 38,461
Net utility plant. . . . . . . . . . 3,770,313 4,356,518
Non-utility plant in service . . . . . 20,237 41,965
Less - accumulated depreciation. . . . 4,022 14,466
Net property, plant and leased back its 50% undivided interestequipment. . $3,786,528 $4,384,017
The carrying value of long-lived assets, including intangibles are reviewed
for impairment whenever events or changes in the La
Cygne 2 generating unit. The La Cygne 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 La Cygne 2. The lease is an operating lease for financial
reporting purposes.
As permitted under the La Cygne 2 lease agreement, the company in 1992
requested the Trustee Lessor to refinance $341.1 million of secured facility
bonds of the Trustee and owner of La Cygne 2. The transaction was requested
to reduce recurring future net lease expense. In connection with the
refinancing on September 29, 1992, a one-time payment of approximately $27
million was made by the company which has been deferred and is being amortized
over the remaining life of the lease and included in operating expense as part
of the future lease expense. At December 31, 1996, approximately $22.5
million of this deferral remained on the Consolidated Balance Sheets.
Future minimum annual lease payments, included in the table above,
required under the La Cygne 2 lease agreement are approximately $34.6 million
for each year through 2001 and $611 million over the remainder of the lease.
The gain realized at the date of the sale of La Cygne 2 has been
deferred for financial reporting purposes, and is being amortized ($9.7 million
per year) over the initial lease term in proportion to the related lease
expense. KGE's lease expense, net of amortization of the deferred gain and a
one-time payment, was approximately $22.5 million for 1996, 1995, and 1994.
17.circumstances indicate they may not
be recoverable.
19. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 19961997
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 160,541 $ 105,043162,400 $109,481 343 50
Jeffrey 1 (b) Jul 1978 290,617 121,307 616291,624 131,397 617 84
Jeffrey 2 (b) May 1980 289,944 115,025290,468 121,854 617 84
Jeffrey 3 (b) May 1983 389,350 152,579 591403,046 153,084 605 84
Wolf Creek (c) Sep 1985 1,382,000 369,1821,380,660 399,551 547 47
(a) Jointly owned with KCPL
(b) Jointly owned with UtiliCorp United Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity presented above represent the company's share. The
company's share of operating expenses of the plants in service above, as well
as
such expenses for a 50% undivided interest in La Cygne 2 (representing 335334 MW
capacity) sold and leased back to the company in 1987, are included in operating
expenses on the Consolidated Statements of Income. The company's share of other
transactions associated with the plants is included in the appropriate
classification in the company's Consolidated Financial Statements.
18.20. SEGMENTS OF BUSINESS
The company is a public utilitydiversified energy and security alarm monitoring service
company principally engaged in the generation, transmission, distribution and
sale of electricity in Kansas and a security alarm monitoring provider for
residential and multi-family units operating in 48 states in the transportation, distribution,U.S. through
Protection One.
Electric consists of the company's regulated electric utility business.
Natural gas includes the company's regulated and sale ofnon-regulated natural gas
in Kansasbusiness. Security alarm monitoring includes the company's security alarm
monitoring business activities, including installation activities. Energy
related includes the company's international power development projects and
Oklahoma.
Substantially all of the results of operations and financial position
of the natural gas segment will be exchanged for an equity interest in New ONEOK
in the strategic alliance which is expected to close in the second half of
1997. Upon contribution of the natural gas net assets to New ONEOK, the
company will record its equity investment in New ONEOK.other domestic energy related services.
Year Ended December 31, 1997 1996 1995 1994(1)
(Dollars in Thousands)
Operating revenues:Sales:
Electric. . . . . . . . . . . $1,197,433 $1,145,895 $1,121,781$1,160,166 $1,197,441 $1,146,869
Natural gas(2)gas(1). . . . . . . . 849,386 597,405 642,988
2,046,819 1,743,300 1,764,769
Operating expenses excluding
income taxes:739,059 797,021 436,692
Security alarm monitoring . . 152,347 8,546 344
Energy related. . . . . . . . 100,193 43,819 160,369
2,151,765 2,046,827 1,744,274
Income from operations:
Electric. . . . . . . . . . . 843,672 788,900 768,317207,026 347,097 360,321
Natural gas gas(1). . . . . . . . 27,840 43,111 8,457
Security alarm monitoring . 810,062 584,494 625,780
1,653,734 1,373,394 1,394,097
Income taxes:
Electric.. (48,442) (3,553) (787)
Energy related. . . . . . . . . . . 84,108 96,719 100,078
Natural gas . . . . . . . . . 4,984 (5,522) (4,456)
89,092 91,197 95,622
Operating income:
Electric. . . . . . . . . . . 269,653 260,245 253,386
Natural gas . . . . . . . . . 34,340 18,464 21,664(43,499) 1,898 5,730
$ 303,993142,925 $ 278,709388,553 $ 275,050373,721
Identifiable assets at
December 31:
Electric. . . . . . . . . . . $4,379,435 $4,470,359 $4,346,312$4,640,322 $4,735,335 $4,740,817
Natural gas gas(1). . . . . . . . . 769,417 712,858 654,483
Other corporate assets(3)- 724,302 623,198
Security alarm monitoring . . 1,498,929 307,460 370,2341,504,738 488,849 5,615
Energy related. . . . . . . . 831,900 699,295 121,047
$6,976,960 $6,647,781 $5,490,677 $5,371,029
Other Information--
Depreciation and amortization:
Electric. . . . . . . . . . . $ 152,549183,339 $ 133,452170,094 $ 123,696150,997
Natural gas gas(1). . . . . . . . 29,941 28,011 25,075
Security alarm monitoring . 31,173 26,833 33,702
183,722 $ 160,285 $ 157,398
Maintenance:
Electric.. 41,179 944 45
Energy related. . . . . . . . . . .2,266 2,282 1,713
$ 81,972256,725 $ 87,942201,331 $ 88,162
Natural gas . . . . . . . . . 17,150 20,699 25,024
$ 99,122 $ 108,641 $ 113,186177,830
Capital expenditures:
Electric. . . . . . . . . . . $ 138,361159,760 $ 153,931138,475 $ 152,384
Nuclear fuel. 179,090
Natural gas(1). . . . . . . . 2,629 28,465 20,590
Natural gas47,151 57,128 62,901
Security alarm monitoring . . 45,163 - -
Energy related. . . . . . . . . . 58,519 54,431 64,72247,845 - -
$ 199,509299,919 $ 236,827195,603 $ 237,696241,991
(1) Information reflects the sales of the Missouri Properties (Note 19).
(2) For the years ended December 31, 1996 and 1995, operating revenues
associated with the natural gas segment include immaterial amounts of revenues
related to operations of non-regulated subsidiaries in non-gas related
businesses.
(3) As of December 31, 1996, this balance principally represents the equity
investment in ADT, security business and other property, non-utility assets
and deferred charges. As of December 31, 1995 and 1994, this balance
represents primarily cash, non-utility assets and deferred charges.
The portion of the table above related to the Missouri Properties is as
follows:
1994
(Dollars in Thousands, Unaudited)
Natural gas revenues. . . . . . . . . $ 77,008
Operating expenses excluding
income taxes. . . . . . . . 69,114
Income taxes. . . . . . . . . . . . . 2,897
Operating income. . . . . . . . . . . 4,997
Identifiable assets . . . . . . . . . -
Depreciation and amortization . . . . 1,274
Maintenance . . . . . . . . . . . . . 1,099
Capital expenditures. . . . . . . . . 3,682
19. SALES OF MISSOURI NATURAL GAS DISTRIBUTION PROPERTIES
On January 31, 1994,November 30, 1997 the company soldcontributed substantially all of its
Missouri
natural gas distribution properties and operations to Southern Union Company
(Southern Union)segment in exchange for $404 million. The company sold the remaining Missouri
properties to United Cities Gas Company (United Cities) for $665,000 on
February 28, 1994. The properties sold to Southern Union and United Cities
are referred to herein as the "Missouri Properties."
During the first quarter of 1994, the company recognized a gain of
approximately $19.3 million, net of tax, on the sales of the Missouri
Properties. As of the respective dates of the sales of the Missouri
Properties, the company ceased recording the results of operations, and
removed the assets and liabilities from the Consolidated Balance Sheets
related to the Missouri Properties. The gain is reflectedan equity interest in Other Income and
Deductions, on the Consolidated Statements of Income.
The following table reflects the approximate operating revenues and
operating income included in the company's consolidated results of operations
for the year ended December 31, 1994, related to the Missouri Properties:
1994
Percent
of Total
Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. . . . . . . . . . $ 77,008 4.8%
Operating income. . . . . . . . . . . 4,997 1.9%
Separate audited financial information was not kept by the company for
the Missouri Properties. This unaudited financial information is based on
assumptions and allocations of expenses of the company as a whole.
20.ONEOK.
21. 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. The business
of the company is seasonal in nature and, in the opinion of management,
comparisons between the quarters of a year do not give a true indication of
overall trends and changes in operations.
First Second Third Fourth
(Dollars in Thousands, except Per Share Amounts)
1996
Operating revenues. . . . . . . $555,622 $436,121 $490,172 $564,904
Operating income.1997
Sales . . . . . . . 75,273 59,020 93,587 76,113. . . . . . $626,198 $454,006 $559,996 $511,565
Income from operations(1) . . . 103,297 57,498 110,391 (128,261)
Net income(1),(2) . . . . . . . 41,033 24,335 508,372 (79,646)
Earnings applicable to
common stock. . . . . . . . . 39,803 23,106 507,142 (80,876)
Basic earnings per share. . . . $ 0.61 $ 0.36 $ 7.77 $ (1.23)
Dividends per share . . . . . . $ 0.525 $ 0.525 $ 0.525 $ 0.525
Average common shares
outstanding . . . . . . . . . 64,807 65,045 65,243 65,408
Common stock price:
High. . . . . . . . . . . . . $ 31.50 $ 32.75 $ 35.00 $ 43.438
Low . . . . . . . . . . . . . $ 30.00 $ 29.75 $ 32.25 $ 33.625
1996
Sales . . . . . . . . . . . . . $555,623 $436,123 $490,175 $564,906
Income from operations. . . . . 95,475 73,196 129,504 90,378
Net income. . . . . . . . . . . 44,789 28,746 62,949 32,466
Earnings applicable to
common stock. . . . . . . . . 41,434 25,392 56,049 31,236
EarningsBasic earnings per share. . . . . . . $ 0.66 $ 0.40 $ 0.87 $ 0.48
Dividends per share . . . . . . $ 0.515 $ 0.515 $ 0.515 $ 0.515
Average common shares
outstanding . . . . . . . . . 63,164 63,466 64,161 64,523
Common stock price:
High. . . . . . . . . . . . . $ 34.875 $ 30.75 $ 30.75 $ 31.75
Low . . . . . . . . . . . . . $ 29.25 $ 28.00 $ 28.25 $ 28.625
1995
Operating revenues. . . . . . . $443,375 $372,295 $470,289 $457,341
Operating income. . . . . . . . 69,441 49,891 99,481 59,896
Net income. . . . . . . . . . . 41,575 21,716 71,905 46,480
Earnings applicable(1) During the fourth quarter of 1997, the company expensed deferred costs of
approximately $48 million associated with the original KCPL merger agreement.
Protection One recorded a special charge to income of approximately $40 million.
(2) During the third quarter of 1997, the company recorded a pre-tax gain of
approximately $864 million upon selling its Tyco common stock.
. . . . . . . . 38,220 18,362 68,550 43,125
Earnings per share. . . . . . . $ 0.62 $ 0.30 $ 1.10 $ 0.69
Dividends per share . . . . . . $ 0.505 $ 0.505 $ 0.505 $ 0.505
Average common shares
outstanding . . . . . . . . . 61,747 61,886 62,244 62,712
Common stock price:
High. . . . . . . . . . . . . $ 33.375 $ 32.50 $ 32.875 $ 34.00
Low . . . . . . . . . . . . . $ 28.625 $ 30.25 $ 29.75 $ 31.00
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to the company's Directors required by Item 10 is
set forth in the company's definitive proxy statement for its 19971998 Annual
Meeting of Shareholders to be filed with the SEC. Such information is
incorporated herein by reference to the material appearing under the caption
Election of Directors in the proxy statement to be filed by the company with the
SEC. See EXECUTIVE OFFICERS OF THE COMPANY on page 19in the proxy statement for the
information relating to the company's Executive Officers as required by Item 10.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is set forth in the company's definitive
proxy statement for its 19971998 Annual Meeting of Shareholders to be filed with the
SEC. Such information is incorporated herein by reference to the material
appearing under the captions Information Concerning the Board of Directors,
Executive Compensation, Compensation Plans, and Human Resources Committee Report
in the proxy statement to be filed by the company with the SEC.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is set forth in the company's definitive
proxy statement for its 19971998 Annual Meeting of Shareholders to be filed with the
SEC. Such information is incorporated herein by reference to the material
appearing under the caption Beneficial Ownership of Voting Securities in the
proxy statement to be filed by the company with the SEC.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
The following financial statements are included herein.
FINANCIAL STATEMENTS
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 19961997 and 19951996
Consolidated Statements of Income, for the years ended December 31, 1997,
1996 1995 and 19941995
Consolidated Statements of Cash Flows, for the years ended December 31, 1996, 1995 and 1994
Consolidated Statements of Taxes, for the years ended December 31, 1996,
1995 and 1994
Consolidated Statements of Capitalization, December 31,1997,
1996 and 1995
Consolidated Statements of Cumulative Preferred and Preference Stock, December
31,
1997 and 1996
Consolidated Statements of Common StockShareowners' Equity, for the years ended
December 31, 1997, 1996 1995 and 19941995
Notes to Consolidated Financial Statements
SCHEDULES
Schedules omitted as not applicable or not required under the Rules of
regulation S-X: I, II, III, IV, and V
REPORTS ON FORM 8-K
Form 8-K filed April 15, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed April 23, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed April 25, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed April 26, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed April 29, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed May 3, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed May 6, 1996 - Press release regarding the company's
offer to merge with KCPL.
Forms 8-K filed May 7, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed May 13, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed MayNovember 24, 1996 - Press release about the company filing
testimony to the electric rate case at the KCC.
Form 8-K filed June 17, 1996 - Press release regarding the company's
offer to merge with KCPL.
Form 8-K filed July 23, 1996 - 6/30/96 earnings release.
Form 8-K filed July 26, 1996 - Press release regarding KCC Staff and
the company reaching agreement in rate case.
Form 8-K filed October 24, 1996 - Press release regarding KCC Staff
and the company reaching an amended agreement in rate case.
Form 8-K filed December 18, 1996 - Press release regarding the
company's strategic alliance with ONEOK, including Agreement between the company
and ONEOK dated as of December 12, 1996 and Form of Shareholder Agreement
between New ONEOK and the company.
Form 8-K filed February 10, 1997 - Press release regarding the company's merger with KCPL, including Agreement and Planclosing of Merger betweenthe
combination of the security businesses of the company and KCPL, dated as of February 7, 1997.Protection One, Inc.
Form 8-K filed January 5, 1998 - Press release regarding merger with Kansas
City Power and Light Company.
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) -By-laws of the company. (filed as Exhibit 3 to the I
March 31, 1997 Form 10-Q)
3(b) -Agreement and Plan of Merger between the company and KCPL, I
dated as of February 7, 1997. (filed as Exhibit 99.2 to the
February 10, 1997 Form 8-K)
3(b)3(c) -Agreement between the company and ONEOK dated as of I
December 12, 1996. (filed as Exhibit 99.2 to the December 12,
1997 Form 8-K)
3(c)3(d) -Form of Shareholder Agreement between New ONEOK and the I
company. (filed as Exhibit 99.3 to the December 12, 1997
Form 8-K)
3(d)3(e) -Restated Articles of Incorporation of the Company,company, as amended I
May 7, 1996. (filed as Exhibit 3(a) to June, 1996 Form 10-Q)
3(e)3(f) -Restated Articles of Incorporation of the company, as amended I
May 25, 1988. (filed as Exhibit 4 to Registration Statement
No. 33-23022)
3(f)3(g) -Certificate of Correction to Restated Articles of Incorporation. I
(filed as Exhibit 3(b) to the December 1991 Form 10-K)
3(g)3(h) -Amendment to the Restated Articles of Incorporation, as amended I
May 5, 1992. (filed as Exhibit 3(c) to the December 31, 1995
Form 10-K)
3(h)3(i) -Amendments to the Restated Articles of Incorporation of the I
Company (filed as Exhibit 3 to the June 1994 Form 10-Q)
3(i) -By-laws of the Company. (filed as Exhibit 3(e) to the I
December 31, 1995 Form 10-K)
3(j) -Certificate of Designation of Preference Stock, 8.50% Series, I
without par value. (filed as Exhibit 3(d) to the December
1993 Form 10-K)
3(k) -Certificate of Designation of Preference Stock, 7.58% Series, I
without par value. (filed as Exhibit 3(e) to the December
1993 Form 10-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, I
1939, 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. I
(filed as Exhibit 2-E to Registration Statement No. 2-61310)
4(f) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I
as 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 I
as Exhibit 4(g) to Registration Statement No. 33-21739)
4(i) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I
as Exhibit 4(h) to Registration Statement No. 33-21739)
4(j) -Twenty-Second Supplemental Indenture dated February 1, 1983. I
(filed as Exhibit 4(i) to Registration Statement No. 33-21739)
4(k) -Twenty-Third Supplemental Indenture dated July 2, 1986. I
(filed as Exhibit 4(j) to Registration Statement No. 33-12054)
4(l) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. I
(filed as Exhibit 4(k) to Registration Statement No. 33-21739)
4(m) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I
(filed as Exhibit 4 to the September 1988 Form 10-Q)
4(n) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I
(filed as Exhibit 4(m) to the December 1989 Form 10-K)
4(o) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I
(filed as exhibit 4(n) to the December 1991 Form 10-K)
4(p) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I
(filed as exhibit 4(o) to the December 1992 Form 10-K)
4(q) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I
(filed as exhibit 4(p) to the December 1992 Form 10-K)
4(r) -Thirtieth Supplemental Indenture dated February 1, 1993. I
(filed as exhibit 4(q) to the December 1992 Form 10-K)
4(s) -Thirty-First Supplemental Indenture dated April 15, 1993. I
(filed as exhibit 4(r) to Registration Statement No. 33-50069)
4(t) -Thirty-Second Supplemental Indenture dated April 15, 1994,
(filed as Exhibit 4(s) to the December 31, 1994 Form 10-K)
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 I
10(a) to the June 1996 Form 10-Q)
10(b) -Form of Employment Agreement with officers of the Company I
(filed as Exhibit 10(b) to the June 1996 Form 10-Q)
10(c) -A Rail Transportation Agreement among Burlington Northern I
Railroad 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. I
effective 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) -Letter of Agreement between The Kansas Power and Light Company I
and John E. Hayes, Jr., dated November 20, 1989. (filed as
Exhibit 10(w) to the December 31, 1989 Form 10-K)
10(g) -Amended Agreement and Plan of Merger by and among The Kansas I
Power and Light Company, KCA Corporation, and Kansas Gas and
Electric Company, dated as of October 28, 1990, as amended by
Amendment No. 1 thereto, dated as of January 18, 1991. (filed
as Annex A to Registration Statement No. 33-38967)
10(h) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I
December 31, 1993 Form 10-K)
10(i) -Long-term Incentive Plan (filed as Exhibit 10(j) to the I
December 31, 1993 Form 10-K)
10(j) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I
December 31, 1993 Form 10-K)
10(k) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I
10(l) to the December 31, 1993 Form 10-K)
10(l) -Executive Salary Continuation Plan of Western Resources, Inc., I
as revised, effective September 22, 1995. (filed as Exhibit
10(j)to the December 31, 1995 Form 10-K)
10(m) -Executive Salary Continuation Plan for John E. Hayes, Jr., I
Dated March 15, 1995. (filed as Exhibit 10(k) to the
December 31, 1995 Form 10-K)
10(n) -Stock Purchase Agreement between the company and Laidlaw I
Transportation Inc., dated December 21, 1995. (filed as
Exhibit 10(l) to the December 31, 1995 Form 10-K)
10(o) -Equity Agreement between the company and Laidlaw Transportation I
Inc., dated December 21, 1995. (filed as Exhibit 10(l)1 to the
December 31, 1995 Form 10-K)
10(p) -Letter Agreement between the Companycompany and David C. Wittig, I
dated April 27, 1995. (filed as Exhibit 10(m) to the
December 31, 1995 Form 10-K)
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges.
(filed electronically)
21 -Subsidiaries of the Registrant. (filed electronically)
23 -Consent of Independent Public Accountants, Arthur Andersen LLP
(filed electronically)
27 -Financial Data Schedule (filed electronically)
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.
March 19, 199717, 1998
By /s/ JOHN E. HAYES, JR.
John E. Hayes, Jr., Chairman of the Board
and Chief Executive Officer
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature Title Date
Chairman of the Board,
/s/ JOHN E. HAYES, JR. and Chief Executive Officer March 19,
199717, 1998
(John E. Hayes, Jr.) (Principal Executive Officer)
Executive Vice President and
/s/ S. L. KITCHEN Chief Financial Officer March 19,
199717, 1998
(S. L. Kitchen) (Principal Financial and
Accounting Officer)
/s/ FRANK J. BECKER
(Frank J. Becker)
/s/ GENE A. BUDIG
(Gene A. Budig)
/s/ C. Q. CHANDLER
(C. Q. Chandler)
/s/ THOMAS R. CLEVENGER
(Thomas R. Clevenger)
/s/ JOHN C. DICUS Directors March 19,
199717, 1998
(John C. Dicus)
/s/ DAVID H. HUGHES
(David H. Hughes)
/s/ RUSSELL W. MEYER, JR.
(Russell W. Meyer, Jr.)
/s/ JOHN H. ROBINSON
(John H. Robinson)
/s/ SUSAN M. STANTON
(Susan M. Stanton)
/s/ LOUIS W. SMITH
(Louis W. Smith)
/s/ KENNETH J. WAGNON
(Kenneth J. Wagnon)
/s/ DAVID C. WITTIG
(David C. Wittig)