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, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-7324
KANSAS GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
KANSAS 48-1093840
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
P.O. BOX 208, WICHITA, KANSAS 67201
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code 316/261-6371
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
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)
Indicate the number of shares outstanding of each of the registrant's classes of
common stock.
Common Stock, No par value 1,000 Shares
(Title of each class) (Outstanding at March 28, 2000)
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
Registrant meets the conditions of General Instruction I(1)(a) and (b) to Form
10-K for certain wholly-owned subsidiaries and is therefore filing an
abbreviated form.
KANSAS GAS AND ELECTRIC COMPANY
TABLE OF CONTENTS
Page
PART I
Item 1. Business 3
Item 2. Properties 14
Item 3. Legal Proceedings 15
Item 4. Submission of Matters to a Vote of
Security Holders 15
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 15
Item 6. Selected Financial Data 15
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 16
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 29
Item 8. Financial Statements and Supplementary Data 30
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 51
PART III
Item 10. Directors and Executive Officers of the
Registrant 52
Item 11. Executive Compensation 53
Item 12. Security Ownership of Certain Beneficial
Owners and Management 53
Item 13. Certain Relationships and Related Transactions 53
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 54
Signatures 57
PART I
ITEM 1. BUSINESS
GENERAL
Kansas Gas and Electric Company is an electric utility engaged in the
generation, transmission, distribution and sale of electric energy in
southeastern Kansas including the Wichita metropolitan area. We are a wholly-
owned subsidiary of Western Resources, Inc. (Western Resources). We own 47% of
Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf
Creek Generating Station (Wolf Creek). Our corporate headquarters are located
in Wichita, Kansas. At December 31, 1999, we had no employees. All employees
are provided by our parent company, Western Resources.
On March 28, 2000, Western Resources' board of directors approved the
separation of its electric and non-electric utility businesses. The separation
is currently expected to be effected through an exchange offer to be made to
Western Resources shareholders in the third quarter of 2000. The exchange ratio
will be described in materials furnished to Western Resources shareholders
upon commencement of the exchange offer. Western Resources expects to
complete the separation in the fourth quarter of 2000, but Western Resources can
give no assurance that the separation will be completed.
On March 18, 1998, Western Resources signed an Amended and Restated Plan
of Agreement and Plan of Merger with the Kansas City Power & Light Company
(KCPL) under which KGE, KPL, a division of Western Resources, and KCPL would
have been combined into a new company called Westar Energy, Inc. KCPL has
notified Western Resources that it has terminated the contemplated transaction.
Discussion of other factors affecting the company are set forth in the
Notes to Financial Statements and Management's Discussion and Analysis included
herein.
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, compliance with debt covenants, interest and dividends, environmental
matters, changing weather, nuclear operations, accounting matters, and the
overall economy of our service area. What happens in each case could vary
materially from what we expect because of such things as electric utility
deregulation, including ongoing
municipal, state and federal activities; future economic conditions; legislative
and regulatory developments; our regulatory and competitive markets; and other
circumstances affecting anticipated operations, sales and costs.
SEGMENT INFORMATION
Financial information with respect to business segments is set forth in
Note 14 of the Notes to Financial Statements included herein.
ELECTRIC OPERATIONS
General
We supply electric energy at retail to approximately 287,000 customers in
147 communities in Kansas. We also supply electric energy to 27 communities and
1 rural electric cooperative, and have contracts for the sale, purchase or
exchange of electricity with other utilities at wholesale.
Our electric sales volumes for the last three years were as follows:
1999 1998 1997
(Thousands of MWH)
Residential . . 2,601 2,784 2,490
Commercial. . . 2,413 2,383 2,211
Industrial. . . 3,548 3,569 3,518
Other . . . . . 45 45 45
Wholesale . . . 1,832 1,541 2,101
Total . . . . 10,439 10,322 10,365
Our electric sales for the last three years were as follows:
1999 1998 1997
(Dollars in Thousands)
Residential . . $220,645 $237,571 $214,719
Commercial. . . 169,427 170,473 162,913
Industrial. . . 163,158 167,331 165,614
Other . . . . . 21,855 22,370 17,856
Wholesale . . . 63,255 50,634 53,343
Total . . . . $638,340 $648,379 $614,445
Competition: The United States electric utility industry is evolving from
a regulated monopolistic market to a competitive marketplace. The 1992 Energy
Policy Act began deregulating the electricity market for generation. The
Energy Policy Act permitted the FERC (Federal Energy Regulatory Commission) to
order electric utilities to allow third parties the use of their transmission
systems to sell electric power to wholesale customers. A wholesale sale is
defined as a utility selling electricity to a "middleman," usually a city or its
utility company, to resell to the ultimate retail customer. In 1992, we agreed
to open access of our transmission system for wholesale transactions. FERC also
requires
us to provide transmission services to others under terms comparable to those we
provide ourselves. In December 1999, FERC issued an order (FERC Order 2000)
encouraging formation of regional transmission organizations (RTOs), whose
purpose is to facilitate greater competition at the wholesale level. Due to our
participation in the formation of the Southwest Power Pool RTO, we anticipate
that FERC Order 2000 will not have a material effect on us or our operations.
In December 1999, the Wichita, Kansas, City Council authorized the hiring
of an outside consultant to determine the feasibility of creating a municipal
electric utility to replace us as the supplier of electricity in Wichita. Our
rates are currently 7% below the national average for retail customers. The
average rates charged to retail customers in territories served by Western
Resources' KPL division are 19% lower than our rates. Customers within the
Wichita metropolitan area account for approximately 56% of our total energy
sales. We have an exclusive franchise with the City of Wichita to provide
retail electric service that expires March 2002. Under Kansas law, we will
continue to have the exclusive right to serve the customers in Wichita following
the expiration of the franchise, assuming the system is not municipalized. See
also Regulations and Rates below regarding a complaint filed with the FERC
against us by the City of Wichita.
For further discussion regarding competition in the electric utility
industry and the potential impact on the company, see Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Regulation and Rates: As a Kansas electric utility, we are subject to the
jurisdiction of the KCC which has general regulatory authority over our rates,
extensions and abandonments of service and facilities, valuation of property,
the classification of accounts and various other matters. We are also subject
to the jurisdiction of the KCC with respect to the issuance of certain
securities.
Additionally, we are subject to the jurisdiction of the FERC, which has
authority over wholesale sales of electricity and the issuance of certain
securities. We are also subject to the jurisdiction of the Nuclear Regulatory
Commission for nuclear plant operations and safety.
In September 1999, the City of Wichita filed a complaint with the FERC
against us, alleging improper affiliate transactions between us and KPL, a
division of Western Resources. The City of Wichita requests the FERC to
equalize the generation costs between us and KPL, in addition to other matters.
FERC has issued an order setting this matter for hearing and has referred the
case to a settlement judge. The hearing has been suspended pending settlement
discussions between the parties. We believe that the City of Wichita's
complaint is without merit and intend to defend against it vigorously.
On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization
of commercial and industrial users of electricity in Kansas, filed a complaint
with the KCC requesting an investigation of Western Resources' and KGE's
rates. The KIC alleges that these rates are not based on current costs. We
will oppose this request vigorously but are unable to predict whether the KCC
will open an investigation.
Additional information with respect to Regulation and Rates is discussed
in Notes 1 and 4 of the Notes to Financial Statements and Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Environmental Matters: We currently hold all Federal and State
environmental approvals required for the operation of our generating units. We
believe we are presently in substantial compliance with all air quality
regulations (including those pertaining to particulate matter, sulfur dioxide
and nitrogen oxides (NOx)) promulgated by the State of Kansas and the
Environmental Protection Agency (EPA).
The Jeffrey Energy Center (JEC) and La Cygne 2 units have met: (1) the
Federal sulfur dioxide standards through the use of low sulfur coal (See Coal);
(2) the Federal particulate matter standards through the use of electrostatic
precipitators; and (3) the Federal NOx standards through boiler design and
operating procedures. The JEC units are also equipped with flue gas scrubbers
providing additional sulfur dioxide and particulate matter emission reduction
capability when needed to meet permit limits.
The Kansas Department of Health and Environment (KDHE) regulations,
applicable to our other generating facilities, prohibit the emission of more
than 3.0 pounds of sulfur dioxide per million Btu of heat input. We have
sufficient low sulfur coal under contract (See Coal) to allow compliance with
such limits at La Cygne 1 for the life of the contract. All facilities burning
coal are equipped with flue gas scrubbers and/or electrostatic precipitators.
We must comply with the provisions of The Clean Air Act Amendments of 1990
that require a two-phase reduction in certain emissions. We have installed
continuous monitoring and reporting equipment to meet the acid rain
requirements. We do not expect any material capital expenditures to be required
to meet Phase II sulfur dioxide and nitrogen oxide requirements.
All of our generating facilities are in substantial compliance with the
Best Practicable Technology and Best Available Technology regulations issued by
the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are
administered in Kansas by the KDHE.
Additional information with respect to Environmental Matters is discussed
in Note 2 of the Notes to Financial Statements included herein.
Fossil Fuel Generation
Capacity: The aggregate net generating capacity of our system is presently
2,605 megawatts (MW). The system comprises interests in twelve fossil fueled
steam generating units, one nuclear generating unit (47% interest) and one
diesel generator, located at seven generating stations.
Our 1999 peak system net load occurred on August 11, and amounted to 2,111
MW. Our net generating capacity together with power available from firm
interchange and purchase contracts, provided a capacity margin of approximately
12% above system peak responsibility at the time of the peak.
We are a member of the Southwest Power Pool (SPP). SPP's responsibility
is to maintain system reliability on a regional basis and is working with us and
other members to become an RTO. The region encompasses areas within the eight
states of Kansas, Missouri, Oklahoma, New Mexico, Texas, Louisiana, Arkansas,
and Mississippi. We are also a member of the SPP transmission tariff along with
ten other transmission providers in the region. Revenues from this tariff are
divided among the tariff members based upon calculated impacts to their
respective system. The tariff allows for both non-firm and firm transmission
access.
We are a member of the Western Systems Power Pool (WSPP). Under this
arrangement, electric utilities and marketers throughout the western United
States have agreed to market energy. Services available include short-term and
long-term economy energy transactions, unit commitment service, firm capacity
and energy sales and energy exchanges.
We have an agreement with Midwest Energy, Inc. (MWE) to provide MWE with
peaking capacity of 61 MW through May, 2007. We also have an agreement with
Empire District Electric Company (Empire) to provide Empire with peaking and
base load capacity of 80 MW through May, 2000.
Future Capacity: We do 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, Liquidity and
Capital Resources).
Fuel Mix: Our coal-fired units comprise 1,126 MW of the total 2,605 MW of
generating capacity and our nuclear unit provides 550 MW of capacity. Of the
remaining 929 MW of generating capacity, units that can burn either natural gas
or oil account for 926 MW, and the remaining unit which burns only diesel fuel
accounts for 3 MW (See Item 2. Properties).
During 1999, low sulfur coal was used to produce 54% of our electricity.
Nuclear produced 34% and the remainder was produced from natural gas, oil, or
diesel fuel. During 2000, based on our estimate of the availability of fuel,
coal will be used to produce approximately 54% of our electricity and nuclear
will be used to produce approximately 33%.
Our fuel mix fluctuates with the operation of the nuclear powered Wolf
Creek as discussed below under Nuclear Generation.
Coal: The three coal-fired units at Jeffrey Energy Center (JEC) have an
aggregate capacity of 445 MW (KGE's 20% share) (See Item 2. Properties).
Western Resources, the operator of JEC, and KGE have a long-term coal supply
contract with Amax Coal West, Inc. (AMAX), a subsidiary of RAG America 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 $1.12 per MMBtu or $18.69 per ton during 1999.
Coal is transported by Western Resources from Wyoming under a long-term
rail transportation contract with Burlington Northern Santa Fe (BNSF) and Union
Pacific railroads to JEC through December 31, 2013. Rates are based on net load
carrying capabilities of each rail car. Western Resources 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 681 MW (KGE's 50% share) (See Item 2. Properties). The operator,
KCPL, maintains coal contracts as discussed 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 83% 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 2003. This low
sulfur coal had an average Btu content of approximately 8,458 Btu per pound and
a maximum sulfur content of .80 lbs/MMBtu (See Environmental Matters).
Transportation is covered by KCPL through its Omnibus Rail Transportation
Agreement with BNSF and Kansas City Southern Railroad through December 31,
2000. KCPL is currently negotiating an extension of rail service beyond
December 31, 2000. We anticipate that the negotiation of the transportation
agreements will not have a material effect on our operations.
During 1999, the average delivered cost of all local and Powder River Basin
coal procured for La Cygne 1 was approximately $0.78 per MMBtu or $13.00 per ton
and the average delivered cost of Powder River Basin coal for La Cygne 2 was
approximately $0.68 per MMBtu or $11.55 per ton.
We have entered into all of our coal contracts during the ordinary course
of business and are not substantially dependent upon these contracts. We
believe 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 we were required to replace our coal
agreements, we would not anticipate a substantial disruption of our business.
We have entered into all of our transportation contracts in the ordinary
course of business. We are not substantially dependent upon these contracts due
to the availability of competitive rail options. There are two rail carriers
capable of serving our origin coal mines and our generating stations. In the
event one of these carriers became unable to provide reliable service, we could
experience a short-term disruption of our business. However, due to the
obligation of the remaining carrier to provide service under the Interstate
Commerce Act, we do not anticipate any substantial long-term disruption of our
business.
Natural Gas: We use natural gas as a primary fuel in our Gordon Evans,
Murray Gill and Neosho Energy Centers. Natural gas for these generating
stations is purchased in the short-term spot market. We maintain firm natural
gas transportation capacity through Williams Gas Pipelines Central for the above
facilities through April 1, 2010.
Oil: We use oil as an alternate fuel when economical or when interruptions
to natural gas make it necessary. Oil is also used as a start-up fuel at JEC
and La Cygne generating stations. All of the oil we have burned during the past
several years has been obtained by spot market purchases. At December 31, 1999,
we had approximately 1 million gallons of No. 2 oil and 12 million gallons of
No. 6 oil which is believed to be sufficient to meet emergency requirements and
protect against lack of availability of natural gas for limited periods and/or
the loss of a large generating unit.
Other Fuel Matters: Our contracts to supply fuel for our 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 that we have used.
1999 1998 1997
Per Million Btu:
Nuclear . . . . . $0.45 $0.48 $0.51
Coal. . . . . . . 0.87 0.86 0.89
Gas . . . . . . . 2.31 2.28 2.56
Oil . . . . . . . 2.11 4.05 3.32
Per KWH Generation. . $0.98 $0.94 $1.00
Nuclear Generation
The owners of Wolf Creek have on hand or under contract 100% of their
uranium needs for 2000 and 77% of the uranium required to operate Wolf Creek
through March 2005. The balance is expected to be obtained through spot market
and contract purchases. Wolf Creek has active contracts to acquire uranium
from Cameco Corporation and Geomex Minerals, 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 March 2005.
Wolf Creek has active contracts for uranium enrichment with Urenco and
USEC. Contracted arrangements cover 85% 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.
Wolf Creek 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. Wolf Creek believes there
are other supplies available at reasonable prices to replace, if necessary,
these contracts. In the event that Wolf Creek were required to replace these
contracts, Wolf Creek would not anticipate a substantial disruption of its
operations.
Nuclear 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 (NWPA), the Department of Energy (DOE) is responsible for the permanent
disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee of one-
tenth of a cent for each kilowatt-hour of net nuclear generation delivered and
sold for the future disposal of spent nuclear fuel. These disposal costs are
charged to cost of sales and currently recovered through rates.
In 1996 and 1997, a U.S. Court of Appeals (the Court) issued decisions that
(1) the NWPA unconditionally obligated the DOE to begin accepting spent fuel for
disposal in 1998, and (2) precluded the DOE from concluding that its delay in
accepting spent fuel is "unavoidable" under its contracts with utilities due to
lack of a repository or interim storage authority.
In May 1998, the Court issued an order in response to the utilities'
petitions for remedies for DOE's failure to begin accepting spent fuel for
disposal. The Court affirmed its conclusion that the sole remedy for DOE's
breach of its statutory obligation under the NWPA is a contract remedy, and made
clear that the court will not revisit the matter until the utilities have
completed their pursuit of that remedy. Wolf Creek intends to pursue its claims
against the DOE.
A permanent disposal site may not be available for the industry until 2010
or later, although an interim 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 may
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 begun replacement of
spent fuel storage racks to increase its on-site storage capacity for all spent
fuel expected to be generated by Wolf Creek through the end of its licensed life
in 2025.
The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that
the various states, individually or through interstate compacts, develop
alternative low-level radioactive waste disposal facilities. The states of
Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate
Low-Level Radioactive Waste Compact (the Compact) and selected a site in
Nebraska to locate a disposal facility. WCNOC and the owners of the other five
nuclear units in the Compact have provided most of the pre-construction
financing for this project. Our share of Wolf Creek's net investment at
December 31, 1999, was approximately $7.4 million.
On December 18, 1998, the application for a license to construct this
project was denied. The license applicant has sought a hearing on the license
denial, but a U.S. District Court has delayed indefinitely proceedings related
to the hearing. In late December 1998, the utilities filed a federal court
lawsuit contending Nebraska officials acted in bad faith while handling the
license application and seeking damages related to the utilities' costs incurred
because of the delay in processing the application. In May 1999, the Nebraska
legislature passed a bill withdrawing Nebraska from the Compact. In August
1999, the Nebraska governor gave official notice of the withdrawal to the other
member states. Withdrawal will not be effective for five years and will not, of
itself, nullify the site license proceeding.
Wolf Creek disposes of all classes of its low-level radioactive waste at
existing third-party repositories. Should disposal capability become
unavailable, Wolf Creek is able to store its low-level radioactive waste in an
on-site facility for up to five years under current regulations. Wolf Creek
believes that a temporary loss of low-level radioactive waste disposal
capability will not affect continued operation of the power plant.
Wolf Creek has an 18-month refueling and maintenance schedule which permits
uninterrupted operation every third calendar year. Wolf Creek is scheduled to
be taken off-line in September 2000, for its eleventh refueling and maintenance
outage. During the outage, electric demand is expected to be met primarily by
our coal-fired generating units.
Additional information with respect to insurance coverage applicable to the
operations of our nuclear generating facility is set forth in Note 2 of the
Notes to Financial Statements.
RISK FACTORS
The following risk factors highlight factors that may affect our financial
condition and results of operation:
Efforts by Wichita to Equalize Rates May Affect Operations and Results:
The average rates charged to retail customers in territories served by Western
Resources' KPL division are 19% lower than our rates. As a result of this rate
disparity, the City of Wichita, Kansas has taken preliminary steps toward the
creation of a municipal electric utility to replace KGE as the supplier of
electricity in Wichita, including authorizing the hiring of an outside
consultant to determine the feasibility of creating a municipal electric
utility. The City of Wichita has also filed a complaint with the FERC against
KGE seeking to
equalize the generation costs between KGE and KPL, in addition to other matters.
We are unable to predict whether the City of Wichita will proceed with efforts
to create a municipal electric utility and, if so, whether these efforts would
be successful. We are also unable to predict whether settlement discussions
between the parties in the FERC proceeding will be successful. Given the
current status of these matters, the potential impact on our operations and
financial condition is unclear. We can give no assurance that the impact will
not be material and adverse.
Deregulation May Reduce Our Earnings: Electric utilities have historically
operated in a rate regulated environment. Federal and state regulatory agencies
having jurisdiction over our rates and services and other utilities are
initiating steps that are expected to result in a more competitive environment
for utility services. Increased competition may create greater risks to the
stability of utility earnings. In a deregulated environment, formerly regulated
utility companies that are not responsive to a competitive energy marketplace
may suffer erosion in market share, revenues and profits as competitors gain
access to their service territories. This anticipated increased competition for
retail electricity sales may in the future reduce our earnings which could
impact our ability to pay dividends and have a material adverse impact on our
operations and our financial condition. A material non-cash charge to earnings
would be required should we discontinue accounting under Statement of Financial
Accounting Standard 71.
Downgrade in Credit Ratings Would Increase Cost of Borrowing and Reduce
Earnings: Credit rating agencies are applying more stringent guidelines when
rating utility companies due to increasing competition and utility investment in
non-utility businesses. Moody's has announced that our ratings are on review
for possible downgrade. Both Standard & Poor's Rating Group and Fitch Investors
Service have given our credit ratings a negative outlook. A downgrade in our
credit ratings may effect our ability to finance and increase our cost of
borrowing and decrease earnings.
Electric Fuel Costs are Included in Base Rates: Electric fuel costs are
included in base rates. Therefore, if we wished to recover an increase in fuel
costs, we 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 we did not recover through rates would reduce our
earnings. The degree of any such impact would be affected by a variety of
factors, including the amount by which fuel costs increased, and thus cannot be
predicted.
Purchased Power Prices are Volatile: In 1999 and 1998, the wholesale power
market experienced extreme volatility in prices and supply. This volatility
impacts our costs of power purchased. If we were unable to generate an adequate
supply of electricity for our customers, we would have to purchase power in the
wholesale market or implement curtailment or interruption procedures. The
increased expenses associated with this could be material and adverse to our
results of operations and financial condition.
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years
Ronald W. Holt 53 Chairman of the Board Assistant Secretary
and President (since (January 1998 to January
January 2000) 2000), Kansas Gas and
Electric Company.
Senior Director, Corporate
and Community Affairs
(January 1999 to January
2000); Director, Community
and Support Services (March
1992 to December 1998),
Western Resources, Inc.
Richard D. Terrill 45 Secretary, Treasurer
and General Counsel
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
We own or lease and operate an electric generation, transmission, and
distribution system in Kansas.
ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW)
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 151
2 1967 Gas--Oil 376
Jeffrey Energy Center (20%) (a):
Steam Turbines 1 1978 Coal 149
2 1980 Coal 148
3 1983 Coal 148
Wind Turbines 1 1999 - (c)
2 1999 - (c)
La Cygne Station (50%):
Steam Turbines 1 (a) 1973 Coal 344
2 (b) 1977 Coal 337
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 44
2 1954 Gas--Oil 74
3 1956 Gas--Oil 108
4 1959 Gas--Oil 106
Neosho Energy Center:
Steam Turbine 3 1954 Gas--Oil 67
Wichita Plant:
Diesel Generator 5 1969 Diesel 3
Wolf Creek
Generating Station (47%)(a):
Nuclear 1 1985 Uranium 550
Total 2,605
(a) We jointly own Jeffrey Energy Center (20%), La Cygne 1 generating unit (50%)
and Wolf Creek Generating Station (47%). Western Resources jointly owns
64% of Jeffrey Energy Center. KCPL jointly owns 50% of La Cygne Station
and 47% of Wolf Creek Generating Station.
(b) In 1987, KGE sold and leased back its 50% individual interest in the La
Cygne 2 generating unit.
(c) Our share is less than 0.5 MW.
FINANCING
Substantially all of our utility properties are encumbered by a first
priority mortgage pursuant to which bonds have been issued.
ITEM 3. LEGAL PROCEEDINGS
Information on legal proceedings involving the company is set forth in
Notes 2, 3, and 4 of Notes to Financial Statements included herein. See also
Item 1. Business, Environmental Matters, and Regulation and Rates.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Information required by Item 4 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of our common stock is owned by Western Resources and is not traded on
an established public trading market.
ITEM 6. SELECTED FINANCIAL DATA
1999 1998 1997 1996 1995
(Dollars in Thousands)
Income Statement Data:
Sales. . . . . . . . . . . . . . $ 638,340 $ 648,379 $ 614,445 $ 654,570 $ 624,168
Net income . . . . . . . . . . . 84,261 103,765 52,128 96,274 110,873
Balance Sheet Data:
Total assets . . . . . . . . . . $3,063,829 $3,057,971 $3,117,108 $3,318,887 $3,203,414
Long-term debt (net) . . . . . . 684,271 684,167 684,128 684,068 684,082
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 the company. We explain:
- What factors impact our business
- What our earnings and costs were in 1999 and 1998
- 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 1999
- What we expect our capital expenditures to be for the years 2000
through 2002
- 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
Statements of Income on page 33. These statements show our operating results
for 1999, 1998 and 1997. In Management's Discussion and Analysis, we analyze
and explain the significant annual changes of specific line items in the
Statements of Income.
Summary of Factors Affecting Net Income
Net income decreased $19.5 million from 1998 to 1999 for several reasons.
Retail sales were lower as a result of milder weather and rate decreases.
Operating expenses were higher primarily because of increased costs associated
with dispatching electric power and a scheduled outage at Wolf Creek. Other
income was lower because we received less proceeds from our corporate-owned life
insurance policies in 1999 compared to 1998.
Termination of Merger Agreement with Kansas City Power & Light Company
On March 18, 1998, Western Resources signed an Amended and Restated Plan
of Agreement and Plan of Merger with the Kansas City Power & Light Company
(KCPL) under which KGE, KPL, a division of Western Resources, and KCPL would
have been combined into a new company called Westar Energy, Inc. KCPL has
notified Western Resources that it has terminated the contemplated transaction.
OPERATING RESULTS
The KCC and the Federal Energy Regulatory Commission (FERC) authorize rates
for our sales. Changing weather affects the amount of electricity our customers
use. Very hot summers and very cold winters prompt more demand, especially
among our residential customers. Mild weather reduces demand.
Many things will affect our future sales. They include:
- The weather
- Our electric rates
- Competitive forces
- Customer conservation efforts
- Wholesale demand
- The overall economy of our service area
- The City of Wichita's attempt to create a municipal electric utility
- The cost of fuel included in base rates
The following tables reflect the changes in electric sales volumes, as
measured by megawatt hours, for the years ended December 31, 1999, 1998 and
1997:
1999 1998 % Change
Residential. . . . . . . 2,601,308 2,783,998 (6.6)%
Commercial . . . . . . . 2,413,126 2,383,197 1.3 %
Industrial . . . . . . . 3,548,216 3,568,948 (0.6)%
Other . . . . . . . . . 44,753 45,485 (1.6)%
Total Retail . . . . . 8,607,403 8,781,628 (2.0)%
Wholesale . . . . . . . 1,831,943 1,540,546 18.9 %
Total . . . . . . . . 10,439,346 10,322,174 1.1 %
1998 1997 % Change
Residential. . . . . . . 2,783,998 2,489,796 11.8 %
Commercial . . . . . . . 2,383,197 2,211,016 7.8 %
Industrial . . . . . . . 3,568,948 3,517,539 1.5 %
Other. . . . . . . . . . 45,485 45,323 0.4 %
Total Retail . . . . . 8,781,628 8,263,674 6.3 %
Wholesale . . . . . . . 1,540,546 2,100,888 (26.7)%
Total. . . . . . . . . 10,322,174 10,364,562 (0.4)%
1999 compared to 1998: Gross profit margin as a percentage of sales
increased 1.5%. Total sales decreased $10 million. Our service territories
averaged 27% fewer cooling degree days in 1999, lowering our retail sales by
$12.7 million. The implementation of our electric rate decreases on June 1,
1999, and June 1, 1998 further decreased our retail sales $10 million.
Increased wholesale sales of $12.6 million partially offset the retail sales
decreases. Due to warmer than normal weather throughout the Midwest in July
1999 and increased availability of our coal-fired generation stations, we were
able to sell more electricity to wholesale customers in 1999.
Cost of sales decreased approximately $11.9 million primarily due to lower
purchased power expense. We purchased less power to serve our retail customers
because of milder weather which reduced demand.
1998 compared to 1997: Gross profit increased 3%, or $14.3 million. This
increase is primarily due to increased retail sales volumes as a result of
warmer summer temperatures in 1998. The implementation of a $10 million
electric rate decrease in 1998 and decreased wholesale sales volumes partially
offset the higher retail sales. See Note 4 for further information on our
electric rate
decreases.
Increased cost of sales partially offset the increased sales. Actual cost
of fuel to generate electricity (coal, nuclear fuel, natural gas and oil) and
the amount of power purchased from other utilities was $19.6 million higher in
1998. With an increase in customer demand for electricity and the availability
of our Wolf Creek nuclear generating station and La Cygne coal generating
station during 1998, we were able to produce more electricity. The increase in
net generation caused our fuel costs to increase during 1998.
Items included in energy cost of sales are fuel expense and purchased power
expense (electricity we purchase from others for resale.)
Business Segments
We have defined two business segments, electric operations and nuclear
generation, based on how management currently evaluates our business. Our
business segments are based on differences in products and services, production
processes and management responsibility.
We manage our business segments' performance based on our earnings before
interest and taxes (EBIT). EBIT does not represent cash flow from operations as
defined by generally accepted accounting principles, nor should it be construed
as an alternative to operating income and is indicative neither of operating
performance nor cash flows available to fund the cash needs of our company.
Items excluded from EBIT are significant components in understanding and
assessing the financial performance of our company. We believe presentation of
EBIT enhances an understanding of financial condition, results of operations and
cash flows because EBIT is used by our company to satisfy its debt service
obligations, capital expenditures and other operational needs, as well as to
provide funds for growth. Our computation of EBIT may not be comparable to
other similarly titled measures of other companies. The following discussion
identifies key factors affecting our business segments.
1999 1998 1997
Electric Operations: (Dollars in Thousands)
External sales. . . . . . . . . . . $ 638,340 $ 648,379 $ 614,445
Depreciation and amortization . . . 61,531 59,239 57,521
EBIT. . . . . . . . . . . . . . . . 193,980 219,014 180,954
Nuclear Generation:
Internal sales. . . . . . . . . . . $ 108,445 $ 117,517 $ 102,330
Depreciation and amortization . . . 39,629 39,583 65,902
EBIT. . . . . . . . . . . . . . . . (25,214) (20,920) (60,968)
Electric Operations
External sales reflect power produced for sale to wholesale and retail
customers.
1999 compared to 1998: External sales decreased $10 million. This decrease
is primarily due to decreased retail sales volumes as a result of milder
temperatures in 1999 and the implementation of our rate decreases. Increased
wholesale sales partially offset these decreases. In 1999 and 1998, the
wholesale power market experienced extreme volatility in prices and supply.
EBIT decreased $25 million primarily because of lower gross profit and
increased operating expenses. Operating expenses were higher primarily because
KGE's costs associated with dispatching electric power were higher. The
restarting of our Neosho generation station, and a boiler outage at our Gordon
Evans generation station also contributed to our increased operating expenses.
1998 compared to 1997: External sales increased $33.9 million. This
increase is primarily due to increased sales volumes as a result of warmer
summer temperatures in 1998. The implementation of a $10 million electric rate
decrease in 1998 partially offset the higher sales. See Note 4 for further
information on our electric rate decreases.
EBIT increased $38.1 million. This increase is primarily attributable to
increased sales and lower operating and maintenance costs.
Nuclear Generation
Nuclear generation has no external sales because it provides all of its
power to its co-owners KGE, KCPL and Kansas Electric Power Cooperative, Inc.
Internal sales include the internal transfer price that Nuclear Generation
charges electric operations. The amounts above are our 47% share of Wolf
Creek's operating results. EBIT is negative because internal sales are less
than Wolf Creek's costs.
Wolf Creek has a scheduled refueling and maintenance outage approximately
every 18 months. The next outage is scheduled in September 2000. During an
outage, Wolf Creek produces no power for its co-owners; therefore internal sales
and EBIT decrease and nuclear fuel expense decreases.
1999 compared to 1998: Internal sales and EBIT decreased primarily due to
the scheduled 36-day refueling and maintenance outage at Wolf Creek in 1999. In
1998 Wolf Creek operated the entire year without any outages.
1998 compared to 1997: Internal sales and EBIT were primarily higher in
1998 than in 1997 because the Wolf Creek facility was off line for 58 days in
1997 for a scheduled refueling and maintenance outage.
Depreciation and amortization expense decreased $26.3 million primarily
because we had fully amortized a regulatory asset during 1997. This decrease in
amortization expense increased EBIT for 1998.
Other Income (Expense)
Other income (expense) includes miscellaneous income and expenses not
directly related to our operations.
1999 compared to 1998: Other income (expense) decreased $11.8 million. No
significant corporate-owned life insurance proceeds were received in 1999. In
1998 we received $13.7 million in proceeds pursuant to our corporate-owned life
insurance policies.
1998 compared to 1997: Other income (expense) increased $12.7 million. The
increase is primarily attributable to benefits received during 1998 pursuant to
our corporate-owned life insurance policies totaling $13.7 million.
Interest Expense
1999 compared to 1998: Interest expense includes the interest we paid on
outstanding debt. Interest expense remained materially unchanged in 1999.
1998 compared to 1997: In 1998 interest expense on short-term debt
decreased $1 million. We repaid our outstanding short-term debt balance during
January 1998. After January 1998, no short-term debt was held. Our average
short-term debt balance during 1998 was $0.6 million compared to $22.9 million
during 1997. The interest we paid on long-term debt did not materially change.
Income Taxes
1999 compared to 1998: Our effective income tax rates are affected by the
receipt of proceeds from our corporate-owned life insurance policies and the
amortization of prior years' investment tax credits. Income taxes decreased $10
million due to lower pre-tax income. Pre-tax income was lower primarily because
of higher operating expenses and the absence of death proceeds received from
corporate-owned life insurance policies.
1998 compared to 1997: Income taxes increased $27.6 million as a result
of the substantial increase in our 1998 pre-tax income. The increase in pre-tax
income is primarily due to increased electric sales because of warmer weather,
lower operating and maintenance costs, the completion of the amortization of
phase-in revenues in December 1997, and the death proceeds received from
corporate-owned life insurance policies.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Most of our cash requirements consist of capital expenditures and
maintenance costs designed to improve facilities which provide electric service
and meet future customer service requirements. Our ability to provide the cash
or debt to fund our capital expenditures depends upon many things, including
available resources, our financial condition and current market conditions.
Funds are available to us from the sale of securities we register for sale
with the Securities and Exchange Commission (SEC). As of December 31, 1999,
$50 million of KGE first mortgage bonds were registered.
Our mortgage prohibits additional first mortgage bonds from being issued
(except in connection with certain refundings) unless our 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 either less than two and one-half times the annual interest charges on,
or 10% of the principal amount of, all first mortgage bonds outstanding after
giving effect to the proposed issuance. In addition, the issuance of bonds is
subject to limitations based upon the amount of bondable property additions.
Based on our results for the 12 months ended December 31, 1999, approximately
$1.0 billion principal amount of additional first mortgage bonds could be
issued (8.25% interest rate assumed) under the most restrictive tests in the
mortgage. As of December 31, 1999, $17 million in additional bonds could be
issued on the basis of retired bonds.
While our internally generated cash is sufficient to fund operations and
debt service payments, we do not maintain independent short-term credit
facilities and rely on Western Resources for short-term cash needs. If Western
Resources is unable to borrow under its credit facilities, we could have a short
term liquidity issue which could require us to obtain a credit facility for our
short-term cash needs.
In March 2000, Western Resources amended its $300 million credit facility
to reduce the commitment to $242 million and to extend the maturity date to June
30, 2000. Western Resources also amended its credit facilities to reflect the
possibility of borrowing from them rather than using them to provide support for
commercial paper borrowings. As a result of these amendments, our cost of
borrowing will be higher. A 1% increase in the interest rate on Western
Resources' outstanding short-term debt balance as of December 31, 1999, would
have increased Western Resources' annual interest expense by $7 million.
Western Resources cannot predict the market conditions or its credit ratings at
the time it may borrow from its facilities; and therefore, cannot predict how
much higher its interest expense might be.
Amendments to the credit facilities include increased pricing to reflect
credit quality and the potential drawn nature of credit facilities rather than
support for commercial paper, redefinition of the total debt to capital
financial covenant, limitation on use of proceeds from sale of Western Resources
and our first mortgage bonds requiring payment of debt outstanding under its
credit facility before proceeds may be used for other purposes, and a commitment
by Western Resources to use its "best efforts" to pledge first mortgage bonds to
support its credit facilities if its senior unsecured credit rating drops below
"investment grade" (bonds rated below BBB by Standard & Poor's (S&P) and Fitch
and below Baa by Moody's Investors Service (Moody's)).
In order to maintain adequate short-term borrowing capacity, Western
Resources expects to replace or further amend its credit facilities prior to
their termination.
Cash Flows from Operating Activities
Cash from operating activities decreased 2%, or $4 million. The decrease
is primarily attributable to the decrease in net income.
Cash Flows from Investing Activities
Cash used in investing activities decreased 18%, or $13.8 million. The
decrease is primarily due to lower nuclear fuel capital expenditures in 1999
than 1998. In the year prior to a scheduled refueling and maintenance outage
at Wolf Creek, such as 1998, nuclear fuel capital expenditures increase in
preparation for the next scheduled refueling and maintenance outage. In 1999,
Wolf Creek had its tenth refueling and maintenance outage. The next outage is
scheduled in September 2000.
Cash Flows Used in Financing Activities
Cash used in financing activities increased 7%, or $9.9 million. This
increase is primarily due to advances we have made to Western Resources. See
Note 10 of the Notes to Financial Statements included herein.
Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and
Moody's Investors Service (Moody's) are independent credit-rating agencies that
rate our debt securities. These ratings indicate the agencies' assessment of
our ability to pay interest and principal on these securities.
At December 31, 1999, ratings with these agencies were as follows:
Senior Senior
Secured Debt Unsecured Debt
Rating Agency Rating Rating
S&P BBB+ BBB
Fitch A- -
Moody's A3 Baa3
Credit rating agencies are applying more stringent guidelines when rating
utility companies due to increasing competition and utility investment in non-
utility businesses. In January 2000, in response to the terminated KCP&L
merger, Moody's announced they were placing our ratings on review for possible
downgrade, S&P affirmed our ratings, but said the outlook is negative, and Fitch
placed our ratings on RatingAlert - Negative. We anticipate that the rating
agencies will complete their reviews and lower our credit ratings in the near
future, but we cannot predict our new ratings.
Future Cash Requirements
We believe that internally generated funds and borrowings from Western
Resources will be sufficient to meet our operating and capital expenditure
requirements and debt service payments through the year 2002. Uncertainties
affecting our ability to meet these requirements with internally generated funds
include the factors affecting sales described above, inflation on operating
expenses, regulatory actions, and compliance with future environmental
regulations.
We do not contemplate any significant expenditures in connection with
construction of any major generating facilities for the next five years.
$135 million of our bonds will mature in 2003.
Our business requires a significant capital investment. We currently
expect that through the year 2002, we will need cash mostly for ongoing utility
construction and maintenance programs designed to maintain and improve
facilities providing electric service and to pay dividends to Western Resources
on our common stock.
Our capital expenditures for 1999 and anticipated capital expenditures for
2000 through 2002 are as follows:
Electric Nuclear
Operations Generation Total
(Dollars in Thousands)
1999. . . . . . . $57,200 $10,000 $ 67,200
2000. . . . . . . 70,900 31,600 102,500
2001. . . . . . . 70,900 19,600 90,500
2002. . . . . . . 70,900 20,300 91,200
These estimates are prepared for planning purposes and may be revised.
Actual expenditures may differ from our estimates.
Capital Structure
Our capital structures at December 31, 1999, and 1998 were as follows:
1999 1998
Shareholders' Equity . . . . 62% 62%
Long-term Debt . . . . . . . 38% 38%
Total. . . . . . . . . . . . 100% 100%
Acquisition Adjustment Implementation
In accordance with the 1992 KCC merger order relating to the acquisition
of Kansas Gas and Electric Company by Western Resources, amortization of the
acquisition adjustment commenced August 1995. The amortization will amount to
approximately $20 million (pre-tax) per year for 40 years. We and Western
Resources are recovering the amortization of the acquisition adjustment through
cost savings under a sharing mechanism approved by the KCC.
As Western Resources' 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
City of Wichita Proceeding: In December 1999, the Wichita, Kansas, City
Council authorized the hiring of an outside consultant to determine the
feasibility of creating a municipal electric utility to replace us as the
supplier of electricity in Wichita. Our rates are currently 7% below the
national average for retail customers. The average rates charged to retail
customers in territories served by Western Resources' KPL division are 19% lower
than our rates. Customers within the Wichita metropolitan area account for
approximately 56% of our total energy sales. See also FERC Proceeding below for
complaint filed with the FERC against us by the City of Wichita.
We have an exclusive franchise with the City of Wichita to provide retail
electric service that expires March 2002. Under Kansas law, we will continue to
have the exclusive right to serve the customers in Wichita following the
expiration of the franchise, assuming the system is not municipalized.
We will oppose any attempt by the City of Wichita to eliminate us as the
electric provider to Wichita customers. In order to municipalize our Wichita
electric facilities, the City of Wichita would be required to purchase our
facilities or build a separate independent system.
KCC Proceeding: On March 16, 2000, the Kansas Industrial Consumers (KIC),
an organization of commercial and industrial users of electricity in Kansas,
filed a complaint with the KCC requesting an investigation of Western Resources'
and KGE's rates. The KIC alleges that these rates are not based on current
costs. We will oppose this request vigorously but are unable to predict whether
the KCC will open an investigation.
FERC Proceeding: In September 1999, the City of Wichita filed a complaint
with the Federal Energy Regulatory Commission (FERC) against the company,
alleging improper affiliate transactions between the company and KPL, a division
of Western Resources. The City of Wichita requests the FERC to equalize the
generation costs between the company and KPL, in addition to other matters.
FERC has issued an order setting this matter for hearing and has referred the
case to a settlement judge. The hearing had been suspended pending settlement
discussions between the parties. The company believes that the City of
Wichita's complaint is without merit and intends to defend against it
vigorously.
Competition and Deregulation: The United States electric utility industry
is evolving from a regulated monopolistic market to a competitive marketplace.
The 1992 Energy Policy Act began deregulating the electricity market for
generation. The Energy Policy Act permitted the FERC to order electric
utilities to allow third parties the use of their transmission systems to sell
electric power to wholesale customers. 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. During 1999, wholesale electric sales
represented approximately 10% of total electric sales. In 1992, we agreed to
open access of our transmission system for wholesale transactions. FERC also
requires us to provide transmission services to others under terms comparable to
those we provide to ourselves. In December 1999, FERC issued an order (FERC
Order 2000) encouraging formation of regional transmission organizations (RTOs),
whose purpose is to facilitate greater competition at the wholesale level. Due
to our participation in the formation of the Southwest Power Pool RTO, we
anticipate that FERC Order 2000 will not have a material effect on us or our
operations.
Various states have taken steps to allow retail customers to purchase
electric power from providers other than their local utility company. The
Kansas Legislature created a Retail Wheeling Task Force (the Task Force) in 1997
to study the effects of a deregulated and competitive market for electric
services. Legislators, regulators, consumer advocates and representatives from
the electric industry made up the Task Force. Several bills were introduced to
the Kansas Legislature in the 1999 and 2000 legislative sessions, but none
passed in 1999 and none are expected to pass in 2000. When retail wheeling will
be implemented by the legislature in Kansas remains uncertain.
When retail wheeling is implemented in Kansas, increased competition for
retail electricity sales may reduce our future electric utility earnings
compared to our historical electric utility earnings. Wholesale and industrial
customers may pursue cogeneration, self-generation, retail wheeling,
municipalization or relocation to other service territories in an attempt to cut
their energy costs. Our rates are approximately 93% of the national average for
retail customers. Because of these rates, we expect to retain a substantial
part of our current volume of sales volumes in a competitive environment. We
also expect we can maintain profitable prices in a competitive environment,
given how our current rates compare to the national average rates. We offer
competitive electric rates
for industrial improvement projects and economic development projects in an
effort to maintain and increase electric load.
Stranded Costs: The definition of stranded costs for a utility business
is the investment in and carrying costs on property, plant and equipment and
other regulatory assets which exceed the amount that can be recovered in a
competitive market. We currently apply accounting standards that recognize the
economic effects of rate regulation and record regulatory assets and liabilities
related to our fossil generation, nuclear generation and power delivery
operations. If we determine that we no longer meet the criteria of Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS 71), we may have a material extraordinary non-cash
charge to operations. Reasons for discontinuing SFAS 71 accounting treatment
include increasing competition that restricts our ability to charge prices
needed to recover costs already incurred and a significant change by regulators
from a cost-based rate regulation to another form of rate regulation. We
periodically review SFAS 71 criteria and believe our net regulatory assets,
including those related to generation, are probable of future recovery. If we
discontinue SFAS 71 accounting treatment based upon competitive or other events,
we may significantly impact the value of our net regulatory assets and our
utility plant investments, particularly the Wolf Creek nuclear generation
facility (Wolf Creek). See OTHER INFORMATION for initiatives taken to
restructure the electric industry in Kansas.
Regulatory changes, including competition, could adversely impact our
ability to recover our investment in these assets. As of December 31, 1999, we
have recorded regulatory assets which are currently subject to recovery in
future rates of approximately $251.5 million. Of this amount, $172.3 million is
a receivable for income tax benefits previously passed on to customers. The
remainder of the regulatory assets are items that may give rise to stranded
costs and include coal contract settlement costs, deferred plant costs and debt
issuance costs.
In a competitive environment, we may not be able to fully recover our
entire investment in Wolf Creek. We presently own 47% of Wolf Creek. We may
also have stranded costs from an inability to recover our environmental
remediation costs and long-term fuel contract costs in a competitive
environment. If we determine that we have stranded costs and we cannot recover
our investment in these assets, our future net income will be lower than our
historical net income has been unless we compensate for the loss of such income
with other measures.
Nuclear Decommissioning: Decommissioning is a nuclear industry term for
the permanent shut-down of a nuclear power plant. The Nuclear Regulatory
Commission (NRC) will terminate a plant's license and release the property for
unrestricted use when a company has reduced the residual radioactivity of a
nuclear plant to a level mandated by the NRC. The NRC requires companies with
nuclear plants to prepare formal financial plans to fund decommissioning. These
plans are designed so that funds required for decommissioning will be
accumulated during the estimated remaining life of the related nuclear power
plant.
The Financial Accounting Standards Board (FASB) is reviewing the accounting
for closure and removal costs, including decommissioning of nuclear power
plants. The FASB has issued an Exposure Draft "Accounting for Obligations
Associated with the Retirement of Long-Lived Assets." The proposed Statement is
to be effective for fiscal years beginning after June 15, 2001. If current
accounting practices for nuclear power plant decommissioning are changed, the
following could occur:
- Our annual decommissioning expense could be higher than in 1999
- 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 2).
Collective Bargaining Agreement: All employees are provided by Western
Resources. Western Resources' contract with the International Brotherhood of
Electrical Workers (IBEW) was renewed on January 20, 2000, and will be due for
renewal July 1, 2002. The contract covers approximately 1,475 employees.
Year 2OOO Issue: Our electric utility operations experienced no business
disruptions as a result of the transition from December 31, 1999 to January 1,
2000 or as a result of "leap day" on February 29, 2000. Western Resources
estimated that total costs to update all of our electric utility operating
systems for Year 2000 readiness, excluding costs associated with WCNOC, would be
approximately $2.5 million. As of December 31, 1999, Western Resources has
allocated approximately $2.5 million of its $6.3 million expensed costs to our
company. Western Resources expects to incur minimal cost in 2000 to complete
remediation of less important systems. Western Resources expects no Year 2000
issues to arise in 2000.
WCNOC experienced no business disruptions as a result of the transition
from December 31, 1999 to January 1, 2000 or as a result of "leap day" on
February 29,2000. WCNOC has estimated the costs to complete the Year 2000
project at $3.5 million ($1.7 million our share). As of December 31, 1999,
WCNOC expensed $3.2 million ($1.5 million our share) to complete remediation and
testing of mission critical systems necessary to continue to provide electrical
service to our customers. We expect to incur $0.2 million (our share) in 2000
to complete remediation of less important systems. We expect no Year 2000
issues to arise in 2000.
Market Risk Disclosure
Market Price Risk: We are exposed to market risk, including changes in
commodity prices and interest rates.
Commodity Price Exposure: Given the amount of power purchased during 1999,
we would have had exposure of approximately $0.9 million of operating income for
a 10% increase in price per MW of electricity. From 1998 to 1999, we
experienced a 15% decrease in price per MW of electricity purchased for utility
operations. Due to the volatility of the power market, there are no indications
that past performance can be used to predict the future.
Based on MMBtu's of natural gas and fuel oil burned during 1999, we had
exposure of approximately $3.8 million of operating income for a 10% change in
average price paid per MMBtu. From 1998 to 1999, we experienced a 2% increase
in price per MMBtu of natural gas purchased. If we were to have a similar
increase from 1999 to 2000, we would have an exposure of approximately $0.5
million of operating income. However, we use a mix of various fuel types to
operate our system. Due to the volatility of natural gas prices, there are no
indications that past performance can be used to predict the future.
Quantities of natural gas and electricity could vary dramatically year to
year based on weather, unit outages and nuclear refueling.
Interest Rate Exposure: The company has approximately $46.4 million of
variable rate debt as of December 31, 1999. A 100 basis point change in each
debt series benchmark rate would impact net income on an annual basis by
approximately $0.3 million.
Pronouncements Issued but Not Yet Effective
In June 1998, the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
133). In June 1999, the FASB issued Statement No. 137 "Accounting for
Derivative Instruments and Hedging Activities-Deferral of the Effective Date of
FASB Statement No. 133." SFAS 133 establishes accounting and reporting
standards requiring that every derivative instrument, including certain
derivative instruments embedded in hybrid contracts, be recorded in the balance
sheet as either an asset or liability measured at its fair value. With respect
to hybrid embedded contracts, a company may elect to apply SFAS 133, as amended,
to (1) all hybrid contracts, (2) only those hybrid contracts that were issued,
acquired, or substantively modified after December 31, 1997, or (3) only those
hybrid contracts that were issued, acquired, or substantively modified after
December 31, 1998.
SFAS 133, as amended, is effective for fiscal years beginning after June
15, 2000. SFAS 133 cannot be applied retroactively. We are currently evaluating
commodity contracts and financial instruments to determine the effects of
adopting SFAS 133 on our financial statements. We have not yet quantified all
of the effects of adopting SFAS 133 on our financial statements; however, SFAS
133 could increase volatility in earnings and other comprehensive income. We
plan to adopt SFAS 133 as of January 1, 2001.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to market risk disclosure is set forth in Other
Information of Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations included herein.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 31
Financial Statements:
Balance Sheets, December 31, 1999 and 1998 32
Statements of Income for the years ended
December 31, 1999, 1998 and 1997 33
Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997 34
Statements of Shareholder's Equity for the years ended
December 31, 1999, 1998 and 1997 35
Notes to Financial Statements 36
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 Board of Directors of
Kansas Gas and Electric Company:
We have audited the accompanying balance sheets of Kansas Gas and Electric
Company (a wholly-owned subsidiary of Western Resources, Inc.) as of December
31, 1999 and 1998, and the related statements of income, cash flows and
shareholders' equity for each of the three years in the period ended December
31, 1999. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audits to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Kansas Gas and Electric
Company as of December 31, 1999 and 1998, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
1999, in conformity with accounting principles generally accepted in the United
States.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
March 16, 2000
(Except with respect to
the corporate restructuring
discussed in Note 16, as
to which the date is
March 28, 2000)
KANSAS GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Dollars in Thousands)
December 31,
1999 1998
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . . $ 37 $ 41
Accounts receivable (net) . . . . . . . . . . . . . . . . 67,751 66,513
Advances to parent company (net). . . . . . . . . . . . . 111,206 64,405
Inventories and supplies (net). . . . . . . . . . . . . . 46,179 43,121
Prepaid expenses and other. . . . . . . . . . . . . . . . 19,103 15,097
Total Current Assets. . . . . . . . . . . . . . . . . . 244,276 189,177
PROPERTY, PLANT AND EQUIPMENT (NET) . . . . . . . . . . . . 2,480,696 2,527,357
OTHER ASSETS:
Regulatory assets . . . . . . . . . . . . . . . . . . . . 251,518 260,789
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 87,339 80,648
Total Other Assets. . . . . . . . . . . . . . . . . . . 338,857 341,437
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . . . . . . $3,063,829 $3,057,971
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Accounts payable. . . . . . . . . . . . . . . . . . . . . $ 76,995 $ 78,510
Accrued liabilities . . . . . . . . . . . . . . . . . . . 28,052 34,199
Accrued income taxes. . . . . . . . . . . . . . . . . . . 70,878 29,599
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,616 6,020
Total Current Liabilities . . . . . . . . . . . . . . . 182,541 148,328
LONG-TERM LIABILITIES:
Long-term debt (net). . . . . . . . . . . . . . . . . . . 684,271 684,167
Deferred income taxes and investment tax credits. . . . . 774,961 785,116
Deferred gain from sale-leaseback . . . . . . . . . . . . 198,123 209,951
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 101,428 92,165
Total Long-term Liabilities . . . . . . . . . . . . . . 1,758,783 1,771,399
COMMITMENTS AND CONTINGENCIES
SHAREHOLDER'S EQUITY:
Common stock, without par value,
authorized and issued 1,000 shares . . . . . . . . . 1,065,634 1,065,634
Retained earnings . . . . . . . . . . . . . . . . . . . . 56,871 72,610
Total Shareholder's Equity . . . . . . . . . . . . . . . 1,122,505 1,138,244
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY . . . . . . . . . $3,063,829 $3,057,971
The Notes to Financial Statements are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Dollars in Thousands)
Year Ended December 31,
1999 1998 1997
SALES . . . . . . . . . . . . . . . . . . . . . . . . . $ 638,340 $ 648,379 $ 614,445
COST OF SALES . . . . . . . . . . . . . . . . . . . . . 137,478 149,360 129,756
GROSS PROFIT. . . . . . . . . . . . . . . . . . . . . . 500,862 499,019 484,689
OPERATING EXPENSES:
Operating and maintenance expense . . . . . . . . . . 161,953 150,502 179,991
Depreciation and amortization . . . . . . . . . . . . 101,160 98,822 123,423
Selling, general and administrative expense . . . . . 65,900 60,277 57,267
Total Operating Expenses. . . . . . . . . . . . . 329,013 309,601 360,681
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . 171,849 189,418 124,008
OTHER INCOME (EXPENSE). . . . . . . . . . . . . . . . . (3,083) 8,676 (4,022)
EARNINGS BEFORE INTEREST AND TAXES. . . . . . . . . . . 168,766 198,094 119,986
INTEREST EXPENSE:
Interest expense on long-term debt. . . . . . . . . . 45,920 45,990 46,062
Interest expense on short-term debt and other . . . . 3,598 3,368 4,388
Total Interest Expense. . . . . . . . . . . . . . 49,518 49,358 50,450
EARNINGS BEFORE INCOME TAXES. . . . . . . . . . . . . . 119,248 148,736 69,536
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . 34,987 44,971 17,408
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 84,261 $ 103,765 $ 52,128
The Notes to Financial Statements are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31,
1999 1998 1997
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 84,261 $ 103,765 $ 52,128
Depreciation and amortization . . . . . . . . . . . . . . 101,160 98,822 123,423
Amortization of deferred gain from sale-leaseback . . . . (11,828) (11,828) (11,281)
Changes in working capital items:
Accounts receivable (net) . . . . . . . . . . . . . . . (1,238) 141 9,017
Inventories and supplies (net). . . . . . . . . . . . . (3,059) (2,102) 2,627
Prepaid expenses and other. . . . . . . . . . . . . . . (4,006) 2,068 (174)
Accounts payable. . . . . . . . . . . . . . . . . . . . (1,515) (3,476) 33,167
Accrued liabilities . . . . . . . . . . . . . . . . . . (6,147) 1,454 (3,710)
Accrued income taxes. . . . . . . . . . . . . . . . . . 41,279 25,387 (7,016)
Other . . . . . . . . . . . . . . . . . . . . . . . . . 596 1,988 186
Changes in other assets and liabilities . . . . . . . . . 10,888 (1,870) (11,013)
Net cash flows from operating activities. . . . . . . 210,391 214,349 187,354
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to property, plant and equipment (net). . . . . (63,574) (77,419) (88,165)
Net cash flows (used in) investing activities . . . . (63,574) (77,419) (88,165)
CASH FLOWS (USED IN) FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . - (45,000) (177,300)
Advances to parent company (net). . . . . . . . . . . . . (46,801) 8,153 178,175
Retirements of long-term debt . . . . . . . . . . . . . . (20) (85) (65)
Dividends to parent company . . . . . . . . . . . . . . . (100,000) (100,000) (100,000)
Net cash flows (used in) financing activities. . . . . (146,821) (136,932) (99,190)
NET (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . . . . . (4) (2) (1)
CASH AND CASH EQUIVALENTS:
Beginning of period . . . . . . . . . . . . . . . . . . . 41 43 44
End of period . . . . . . . . . . . . . . . . . . . . . . $ 37 $ 41 $ 43
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized) . . . . . . . . . . . . . . . . . . . . $ 77,668 $ 75,611 $ 74,418
Income taxes . . . . . . . . . . . . . . . . . . . . . . - 37,520 52,100
The Notes to Financial Statements are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF SHAREHOLDER'S EQUITY
(Dollars in Thousands)
Year Ended December 31,
1999 1998 1997
Common Stock . . . . . . . . . . . . . . . . . . . . $1,065,634 $1,065,634 $1,065,634
Retained Earnings:
Beginning balance . . . . . . . . . . . . . . . . 72,610 68,845 116,717
Net income. . . . . . . . . . . . . . . . . . . . 84,261 103,765 52,128
Dividends to parent company . . . . . . . . . . . (100,000) (100,000) (100,000)
Ending balance. . . . . . . . . . . . . . . . . . 56,871 72,610 68,845
Total Shareholder's Equity. . . . . . . . . . . . . . $1,122,505 $1,138,244 $1,134,479
The Notes to Financial Statements are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Business: Kansas Gas and Electric Company (the company,
KGE) is a rate-regulated electric utility and wholly-owned subsidiary of Western
Resources, Inc. (Western Resources). The company is engaged principally in the
production, purchase, transmission, distribution, and sale of electricity. The
company serves approximately 287,000 electric customers in southeastern Kansas.
At December 31, 1999, the company had no employees. All employees are provided
by the company's parent, Western Resources, which allocates costs related to the
employees of the company.
The company 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.
The company prepares its financial statements in conformity with generally
accepted accounting principles. The accounting and rates of the company are
subject to requirements of the Kansas Corporation Commission (KCC) and the
Federal Energy Regulatory Commission (FERC). 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.
The company currently applies accounting standards for its rate regulated
electric 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 a regulatory asset.
Cash and Cash Equivalents: The company considers highly liquid
collateralized debt instruments purchased with a maturity of three months or
less to be cash equivalents.
Property, Plant and Equipment: Property, plant and equipment is stated at
cost. For utility plant, cost includes contracted services, direct labor and
materials, indirect charges for engineering, supervision, general and
administrative costs and an allowance for funds used during construction
(AFUDC). The AFUDC rate was 6.00% for 1999, 6.00% for 1998, and 5.86% for 1997.
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,
the original cost and removal cost, less salvage value, are charged to
accumulated
depreciation.
In accordance with regulatory decisions made by the KCC, the acquisition
premium of approximately $801 million resulting from the KGE acquisition in 1992
is being amortized over 40 years. The acquisition premium is classified as
electric plant in service. Accumulated amortization totaled $88.1 million as of
December 31, 1999 and $68 million as of December 31, 1998.
Depreciation: Utility plant is depreciated on the straight-line method at
rates approved by regulatory authorities. Utility plant is depreciated on an
average annual composite basis using group rates that approximated 2.76% during
1999, 2.75% during 1998, and 2.76% during 1997. The company periodically
evaluates its depreciation rates considering the past and expected future
experience in the operation of its facilities.
Inventories and Supplies: Inventories and supplies for the company's
utility business are stated at average cost.
Nuclear Fuel: 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 was $29.3 million at December 31, 1999 and $39.5 million at December 31,
1998.
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 company has recorded these
regulatory assets in accordance with SFAS 71. 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 of all regulatory assets and
liabilities in its Statements of Income at that time. The company's earnings
would be reduced by the total amount in the table below, net of applicable
income taxes. Regulatory assets reflected in the financial statements are as
follows:
December 31, 1999 1998
(Dollars in Thousands)
Recoverable taxes. . . . . . . . . . . . $172,335 $175,759
Debt issuance costs. . . . . . . . . . . 37,158 40,102
Deferred plant costs . . . . . . . . . . 30,306 30,657
Coal contract settlement costs . . . . . 6,727 8,392
Other regulatory assets. . . . . . . . . 4,992 5,879
Total regulatory assets . . . . . . . $251,518 $260,789
Recoverable income taxes: Recoverable income taxes represent amounts due
from customers for accelerated tax benefits which have been previously
flowed through to customers and are expected to be recovered in the future
as the accelerated tax benefits reverse.
Debt issuance costs: Debt reacquisition expenses are amortized over the
remaining terms of the reacquired debt or, if refinanced, the term of the
new debt. Debt issuance costs are amortized over the term of the
associated debt.
Deferred 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 through the year 2002.
The company expects to recover all of the above regulatory assets in
rates. A return is allowed on deferred plant costs and coal contract settlement
costs and approximately $18 million of debt issuance costs.
Sales: Sales are recognized as services are rendered and include estimated
amounts for energy delivered but unbilled at the end of each year. Unbilled
sales are recorded as a component of accounts receivable (net) on the Balance
Sheets of $23.4 million at December 31, 1999 and $22 million at December 31,
1998.
The company's allowance for doubtful accounts receivable totaled $1.9
million at December 31, 1999 and 1998.
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.
Cash Surrender Value of Life Insurance: The following amounts related to
corporate-owned life insurance policies (COLI) are recorded in other assets on
the Balance Sheets at December 31:
1999 1998
(Dollars in Millions)
Cash surrender value of policies(1) . . $538.3 $486.3
Borrowings against policies . . . . . . (527.0) (476.9)
COLI (net). . . . . . . . . . . . . . . $ 11.3 $ 9.4
(1) Cash surrender value of policies as presented represents the value of
the policies as of the end of the respective policy years and not as of
December 31, 1999, and 1998.
Income is recorded for increases in cash surrender value and net death
proceeds. Interest incurred on amounts borrowed is offset against policy
income. Income recognized from death proceeds is highly variable from period to
period. Death benefits recognized as other income approximated $0.06 million in
1999 and $13.7 million in 1998.
New Pronouncements: In June 1998, the FASB issued Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (SFAS 133). In June 1999, the FASB issued Statement No. 137
"Accounting for Derivative Instruments and Hedging Activities-Deferral of the
Effective Date of FASB Statement No. 133." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument, including
certain derivative instruments embedded in hybrid contracts, be recorded in the
balance sheet as either an asset or liability measured at its fair value. With
respect to hybrid contracts, a company may elect to apply SFAS 133, as amended,
to (1) all hybrid contracts, (2) only those hybrid contracts that were issued,
acquired, or substantively modified after December 31, 1997, or (3) only those
hybrid contracts that were issued, acquired, or substantively modified after
December 31, 1998.
SFAS 133, as amended, is effective for fiscal years beginning after June
15, 2000. SFAS 133 cannot be applied retroactively. The company is currently
evaluating commodity contracts and financial instruments to determine what, if
any, effect adopting SFAS 133 might have on its financial statements. The
company has not yet quantified all effects of adopting SFAS 133 on its financial
statements; however, SFAS 133 could increase volatility in earnings and other
comprehensive income. The company plans to adopt SFAS 133 as of January 1, 2001.
Reclassifications: Certain amounts in prior years have been reclassified
to conform with classifications used in the current year presentation.
2. COMMITMENTS AND CONTINGENCIES
Purchase Orders and Contracts: The company has commitments under purchase
orders and contracts at WCNOC which have an unexpended balance of approximately
$5.2 million (company's share) at December 31, 1999.
Manufactured Gas Sites: The company has been associated with three 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 these 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 analysis. At December 31, 1999, the costs
incurred from preliminary site investigation and risk assessment have been
minimal.
Clean Air Act: The company must comply with the provisions of The Clean Air
Act Amendments of 1990 that require a two-phase reduction in certain emissions.
The company has installed continuous monitoring and reporting equipment to meet
the acid rain requirements. The company does not expect material capital
expenditures to be required to meet Phase II sulfur dioxide and nitrogen 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.
In February 1997, the KCC approved the 1996 Decommissioning Cost Study.
Based on the study, the company's share of WCNOC'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. On September 1,
1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for
approval. Approval of this study by the KCC is pending. The company's share of
the cost for decommissioning in the 1999 study under the dismantlement method is
$221 million in 1999 dollars.
Decommissioning costs are currently being charged to operating expense 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 $3.9 million in 1999 and will increase annually to
$5.6 million in 2024. These amounts are deposited in an external trust fund.
The average after-tax expected return on trust assets is 5.7%.
The company's investment in the decommissioning fund, including reinvested
earnings approximated $58.3 million at December 31, 1999, and $52.1 million at
December 31, 1998. Trust fund earnings accumulate in the fund balance and
increase the recorded decommissioning liability.
The FASB is reviewing the accounting for closure and removal costs,
including decommissioning of nuclear power plants. The FASB has issued an
Exposure Draft regarding "Accounting for Obligations Associated with the
Retirement of Long-Lived Assets." The proposed Statement is to be effective for
fiscal years beginning after June 15, 2001. If current accounting practices for
nuclear power plant decommissioning are changed, the following could occur:
- The company's annual decommissioning expense could be higher than in
1999
- 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
The company does not believe that such changes, if required, would
adversely affect its operating results due to its current ability to recover
decommissioning costs through rates.
Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $9.5 billion for a single
nuclear incident. If this liability limitation is insufficient, the 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. The remaining balance is
provided by an assessment plan mandated by the Nuclear Regulatory Commission
(NRC). Under this plan, the Owners are jointly and severally subject to a
retrospective assessment of up to $88.1 million ($41.4 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
Nuclear Electric Insurance Limited (NEIL). In the event of an accident,
insurance proceeds must first be used for reactor stabilization and site
decontamination in accordance with a plan mandated by the NRC. The company's
share of any remaining proceeds can be used to pay for property damage or
decontamination expenses or, if certain requirements are met including
decommissioning the plant, toward a shortfall in the decommissioning trust fund.
The Owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If losses incurred at
any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves and other NEIL resources, the company may be subject to retrospective
assessments under the current policies of approximately $6 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, coal and natural gas. Some of these contracts contain provisions
for price escalation and minimum purchase commitments. At December 31, 1999,
WCNOC's nuclear fuel commitments (company's share) were approximately $14
million for uranium concentrates expiring at various times through 2003, $26
million for enrichment expiring at various times through 2003 and $65.2 million
for fabrication through 2025.
At December 31, 1999, the company's coal contract commitments in 1999
dollars under the remaining terms of the contracts were approximately $639.4
million. The largest coal contract expires in 2020, with the remaining coal
contracts expiring at various times through 2013.
At December 31, 1999, the company's natural gas transportation commitment
in 1999 dollars under the remaining terms of the contract were approximately
$0.5 million. The natural gas transportation contract provides firm service to
the company's Neosho gas burning facility through 2003.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment
is being collected from utilities for an uranium enrichment decontamination and
decommissioning fund. The company's portion of the assessment for Wolf Creek is
approximately $9.6 million, payable over 15 years. Such costs are recovered
through the ratemaking process.
3. LEGAL PROCEEDINGS
The company is involved in various legal, environmental and regulatory
proceedings. Management believes that adequate provision has been made and
accordingly believes that the ultimate disposition of such matters will not have
a material adverse effect upon the company's overall financial position or
results of operations. See also Note 4 for discussion of the FERC proceeding
regarding the City of Wichita complaint.
4. RATE MATTERS AND REGULATION
KCC Proceedings: In January 1997, the KCC entered an order reducing
electric rates for KGE. The order required KGE to reduce electric rates by $65
million cumulative, phased in over three years beginning in 1997.
On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization
of commercial and industrial users of electricity in Kansas, filed a complaint
with the KCC requesting an investigation of Western Resources' and the
company's rates. The KIC alleges that the company's rates are not based on
current costs. The company will oppose this request vigorously but is unable
to predict whether the KCC will open an investigation.
FERC Proceeding: In September 1999, the City of Wichita filed a complaint
with the Federal Energy Regulatory Commission (FERC) against the company,
alleging improper affiliate transactions between the company and KPL, a division
of Western Resources. The City of Wichita requests the FERC to equalize the
generation costs between the company and KPL, in addition to other matters.
FERC has issued an order setting this matter for hearing and has referred the
case to a settlement judge. The hearing has been suspended pending settlement
discussions between the parties. The company believes that the City of
Wichita's complaint is without merit and intends to defend against it
vigorously.
5. SHORT-TERM BORROWINGS
The company had no short-term borrowings outstanding at December 31, 1999,
and 1998. The weighted average interest rate on borrowings outstanding during
the year was 0.0% at December 31, 1999, and 6.44% at December 31, 1998.
The company's short-term liquidity needs are met from cash advances by
Western Resources. Western Resources obtains funds from issuances of commercial
paper and borrowings under its credit facilities. In March 2000, Western
Resources amended its $300 million facility to reduce the commitment to $242
million and to extend the maturity date to June 30, 2000. Western Resources
also amended all of its credit facilities to reflect the possibility of
borrowing from them rather than using them to provide support for commercial
paper borrowings.
Amendments to the credit facilities include increased pricing to reflect
credit quality and the potential drawn nature of credit facilities rather than
support for commercial paper, redefinition of the total debt to capital
financial covenant, limitation on use of proceeds from sale of first mortgage
bonds, to pay off debt outstanding under the credit facility before proceeds may
be used for other purposes, and a commitment by Western Resources to use its
"best efforts" to pledge first mortgage bonds to support its credit facilities
if its senior unsecured credit rating drops below "investment grade" (bonds
rated below BBB by S&P and Fitch and below Baa by Moody's as determined by
Standard & Poor's Ratings Group (S&P) and Moody's Investors Service (Moody's)).
6. LONG-TERM DEBT
The amount of KGE's first mortgage bonds authorized by the KGE Mortgage and
Deed of Trust (Mortgage) 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 the
Mortgage. Electric plant is subject to the lien of the Mortgage except for
transportation equipment.
Debt discount and expenses are being amortized over the remaining lives of
each issue. The improvement and maintenance fund requirements for certain first
mortgage bond series can be met by bonding additional property. With the
retirement of certain company pollution control series bonds, there are no
longer any bond sinking fund requirements. During the years 2000 through 2004,
$135 million of bonds will mature in 2003.
Long-term debt outstanding is as follows at December 31:
1999 1998
(Dollars in Thousands)
First mortgage bond series:
7.60% due 2003 . . . . . . . . . . . . . . . . . $ 135,000 $ 135,000
6.50% due 2005 . . . . . . . . . . . . . . . . . 65,000 65,000
6.20% due 2006 . . . . . . . . . . . . . . . . . 100,000 100,000
300,000 300,000
Pollution control bond series:
5.10% due 2023 . . . . . . . . . . . . . . . . . 13,653 13,673
Variable due 2027, 4.25% at December 31, 1999. . 21,940 21,940
7.0% due 2031. . . . . . . . . . . . . . . . . . 327,500 327,500
Variable due 2032, 4.20% at December 31, 1999. . 14,500 14,500
Variable due 2032, 4.30% at December 31, 1999. . 10,000 10,000
387,593 387,613
Less:
Unamortized discount . . . . . . . . . . . . . . 3,322 3,446
Long-term debt (net) . . . . . . . . .. . . . . . . $ 684,271 $ 684,167
7. WESTERN RESOURCES AND KANSAS CITY POWER & LIGHT COMPANY MERGER AGREEMENT
On March 18, 1998, Western Resources signed an Amended and Restated Plan
of Agreement and Plan of Merger with the Kansas City Power & Light Company
(KCPL) under which KGE, KPL, a division of Western Resources, and KCPL would
have been combined into a new company called Westar Energy, Inc. KCPL has
notified Western Resources that it has terminated the contemplated transaction.
8. INCOME TAXES
Income tax expense is composed of the following components at December 31:
1999 1998 1997
(Dollars in Thousands)
Currently payable:
Federal. . . . . . . . . $ 38,710 $ 53,297 $ 34,641
State. . . . . . . . . . 9,453 12,080 7,982
Deferred:
Federal. . . . . . . . . (8,531) (14,299) (18,503)
State. . . . . . . . . . (1,407) (2,866) (3,467)
Amortization of investment
tax credits. . . . . . . (3,238) (3,241) (3,245)
Total income tax expense . $ 34,987 $ 44,971 $ 17,408
Under SFAS 109, temporary differences gave rise to deferred tax assets and
deferred tax liabilities as follows at December 31:
1999 1998
(Dollars in Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback. . . . . $ 87,220 $ 92,427
Other. . . . . . . . . . . . . . . . . . 40,969 42,806
Total deferred tax assets. . . . . . . 128,189 135,233
Deferred tax liabilities:
Accelerated depreciation and other . . . 375,917 376,113
Acquisition premium. . . . . . . . . . . 282,578 290,576
Deferred future income taxes . . . . . . 172,336 175,759
Other. . . . . . . . . . . . . . . . . . 12,322 14,667
Total deferred tax liabilities . . . . 843,153 857,115
Investment tax credits . . . . . . . . . . 59,997 63,234
Accumulated deferred income taxes, net . . $ 774,961 $ 785,116
In accordance with various rate orders, the company has 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 are also 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 state income taxes by the sum of such taxes and net income.
The difference between the effective tax rates and the federal statutory income
tax rates are as follows:
Year Ended December 31, 1999 1998 1997
Effective Income Tax Rate . . . . . . . . . 29% 30% 25%
Effect of:
State income taxes . . . . . . . . . . . . (4) (4) (4)
Amortization of investment tax credits . . 3 2 5
Corporate-owned life insurance policies. . 7 9 12
Accelerated depreciation flow through
and amortization, net. . . . . . . . . . (2) (2) (4)
Other. . . . . . . . . . . . . . . . . . . 2 - 1
Statutory Federal Income Tax Rate . . . . . 35% 35% 35%
9. 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,
1999 and 1998. The fair value of fixed-rate debt is estimated based on quoted
market prices for the same or similar issues or on the current rates offered for
instruments of the same remaining maturities and redemption provisions.
The recorded 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, 1999 and 1998. 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 the company's operations are
regulated, the company believes that any gains or losses related to the
retirement of debt 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, 1999 1998 1999 1998
(Dollars in Thousands)
Decommissioning trust. . . $ 58,286 $ 52,093 $ 58,286 $ 52,093
Fixed-rate debt. . . . . . 699,573 641,172 693,384 684,125
1O. RELATED PARTY TRANSACTIONS
The cash management function, including cash receipts and disbursements,
for the company is performed by Western Resources. An intercompany account is
used to record net receipts and disbursements handled by Western Resources. The
net amount advanced by the company to Western Resources approximated $111.2
million at December 31, 1999 and $64.4 million at December 31, 1998. These
amounts are recorded as advances to parent company in current assets on the
Balance Sheets.
Certain operating expenses have been allocated to the company from Western
Resources. These expenses are allocated, depending on the nature of the
expense, based on allocation studies, net investment, number of customers,
and/or other
appropriate factors. Management believes such allocation procedures are
reasonable. During 1999, the company declared dividends to Western Resources of
$100 million.
11. LEASES
At December 31, 1999, the company had leases covering various property and
equipment. The company currently has no capital leases.
Rental payments for operating leases and estimated rental commitments are
as follows:
Operating
Year Ended December 31, Leases
(Dollars in Thousands)
Rental payments:
1997 . . . . . . . . . . . . . $ 42,503
1998 . . . . . . . . . . . . . 44,075
1999 . . . . . . . . . . . . . 43,827
Future Commitments:
2000 . . . . . . . . . . . . . 43,041
2001 . . . . . . . . . . . . . 42,151
2002 . . . . . . . . . . . . . 41,152
2003 . . . . . . . . . . . . . 45,356
2004 . . . . . . . . . . . . . 40,416
Thereafter . . . . . . . . . . 543,293
Total future commitments . . $755,409
In 1987, the company 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. The company 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, 1999, approximately $19.1 million of this deferral
remained in regulatory assets on the Balance Sheet.
Future minimum annual lease payments required under the La Cygne 2 lease
agreement are approximately $34.6 million for each year through 2002, $39.4
million in 2003, $34.6 million in 2004, and $502.6 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 ($11.8 million per
year) over the initial lease term in proportion to the related lease expense.
The company's lease expense, net of amortization of the deferred gain and
refinancing costs, was approximately $28.9 million for 1999, $28.9 million for
1998, and $27.3 million for 1997.
12. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December 31:
1999 1998
(Dollars in Thousands)
Electric plant in service. . . . . . $3,623,852 $3,580,433
Less - Accumulated depreciation. . . 1,206,607 1,125,735
2,417,245 2,454,698
Construction work in progress. . . . 35,219 32,943
Nuclear fuel (net) . . . . . . . . . 28,013 39,497
Net Utility Plant. . . . . . . . . 2,480,477 2,527,138
Non-utility plant in service . . . . 219 219
Net Property, Plant and Equipment. $2,480,696 $2,527,357
13. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1999
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 174,450 $ 113,415 344 50
Jeffrey 1 (b) Jul 1978 72,197 32,267 149 20
Jeffrey 2 (b) May 1980 69,106 32,105 148 20
Jeffrey 3 (b) May 1983 101,031 42,957 148 20
Jeffrey wind 1 (b) May 1999 201 3 (d) 20
Jeffrey wind 2 (b) May 1999 200 2 (d) 20
Wolf Creek (c) Sep 1985 1,378,238 460,880 550 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL) (which owns
50%)
(b) Jointly owned with Western Resources (which owns 64%) and UtiliCorp
United Inc. (which owns 16%)
(c) Jointly owned with KCPL (which owns 47%) and Kansas Electric Power
Cooperative, Inc. (which owns 6%)
(d) The company's share is less than 0.5 MW
Amounts and capacity 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 337 MW capacity) sold
and leased back to the company in 1987, are included in operating expenses on
the Statements of Income. The company's share of other transactions associated
with the plants is included in the appropriate classification in the company's
financial statements.
14. SEGMENTS OF BUSINESS
In 1998, the company adopted SFAS 131, "Disclosures about Segments of an
Enterprise and Related Information." This statement requires the company to
define and report the company's business segments based on how management
currently evaluates its business. Based on management's approach to determining
business segments, the company has two business segments, electric operations
and nuclear generation.
Electric operations and nuclear generation comprise the company's regulated
electric utility business in Kansas. Electric operations involve the
production, transmission and distribution of electric power for sale to
approximately 287,000 retail and wholesale customers in Kansas. Nuclear
generation represents the company's 47% ownership in the Wolf Creek nuclear
generating facility. This segment does not have any external sales.
The accounting policies of the segments are substantially the same as those
described in the summary of significant accounting policies. The company
evaluates segment performance based on earnings before interest and taxes. The
company has no single external customer from which it receives ten percent or
more of revenues.
Year Ended December 31, 1999:
Electric Nuclear Eliminating
Operations Generation Items Total
(Dollars in Thousands)
External sales . . . $ 638,340 $ - $ - $ 638,340
Internal sales . . . - 108,445 (108,445) -
Depreciation and
amortization. . . . 61,531 39,629 - 101,160
Earnings before
interest and taxes 193,980 (25,214) - 168,766
Interest expense . . 49,518
Earnings before
income taxes . . . 119,248
Identifiable assets 1,980,485 1,083,344 - 3,063,829
Year Ended December 31, 1998:
Electric Nuclear Eliminating
Operations Generation Items Total
(Dollars in Thousands)
External sales. . . $ 648,379 $ - $ - $ 648,379
Internal sales. . . - 117,517 (117,517) -
Depreciation and
amortization . . . 59,239 39,583 - 98,822
Earnings before
interest and taxes 219,014 (20,920) - 198,094
Interest expense. . 49,358
Earnings before
income taxes . . . 148,736
Identifiable assets 1,936,462 1,121,509 - 3,057,971
Year Ended December 31, 1997:
Electric Nuclear Eliminating
Operations Generation Items Total
(Dollars in Thousands)
External sales. . . $ 614,445 $ - $ - $ 614,445
Internal sales. . . - 102,330 (102,330) -
Depreciation and
amortization . . . 57,521 65,902 - 123,423
Earnings before
interest and taxes 180,954 (60,968) - 119,986
Interest expense. . 50,450
Earnings before
income taxes . . . 69,536
Identifiable assets 1,962,586 1,154,522 - 3,117,108
15. QUARTERLY FINANCIAL STATISTICS (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.
1999
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
(Dollars in Thousands)
Sales . . . . . . . . . . . $133,910 $147,170 $217,986 $139,274
Income from Operations. . . 30,172 31,735 86,982 22,960
Net income. . . . . . . . . 12,905 14,070 49,512 7,774
1998
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
(Dollars in Thousands)
Sales . . . . . . . . . . . $134,566 $162,816 $216,034 $134,963
Income from Operations. . . 36,033 44,112 81,063 28,210
Net income. . . . . . . . . 22,415 28,507 43,329 9,514
16. SUBSEQUENT EVENT
On March 28, 2000, Western Resources' board of directors approved the
separation of its electric and non-electric utility businesses. The separation
is currently expected to be effected through an exchange offer to be made to
Western Resources shareholders in the third quarter of 2000. The exchange
ratio will be described in materials furnished to Western Resources
shareholders upon commencement of the exchange offer. Western Resources
expects to complete the separation in the fourth quarter of 2000, but Western
Resources can give no assurance that the separation will be completed.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There were no disagreements with accountants on accounting and financial
disclosure.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Western Resources, Inc. owns 100% of the Company's outstanding common
stock.
A Director
Business Experience Since 1994 and Other Continuously
Name Age Directorships Other Than The Company Since
Ronald W. 53 Chairman of the Board and President 2000
Holt (since January 2000), Assistant
Secretary (January 1998 to January
2000), Kansas Gas and Electric Company.
Senior Director, Corporate and
Community Affairs (January 1999
to January 2000); Director, Community
and Support Services (March 1992 to
December 1998), Western Resources, Inc.
Directorships
Commerce Bank, N.A., Wichita, Kansas
Via Christi Medical Center, Wichita,
Kansas
James A. 42 Vice President (since July 1995); 1997
Martin and prior to that Executive
Director Regulatory and Rates,
Western Resources, Inc.
Marilyn B. 50 Executive Vice President, Bank of 1994
Pauly America, N.A., Wichita, Kansas
(1) Directorships
Farmers Mutual Alliance Insurance Company
Richard D. 67 President, Range Oil Company 1993
Smith Directorships
(1) Bank of America, N.A., Wichita, Kansas
HCA Wesley Medical Center, Wichita, Kansas
(1) Member of the Audit Committee of which Marilyn B. Pauly is Chairperson.
The Audit Committee has responsibility for the investigation and
review of the financial affairs of the company and its relations
with independent accountants.
Outside directors are paid a $3,750 per quarter retainer and are paid an
attendance fee of $600 for board meetings ($300 if attending by phone). A
committee attendance fee of $800 is paid to the outside director Audit Committee
Chairperson, and $500 to other outside Committee members. All outside directors
are reimbursed expenses while attending board and Committee Meetings.
During 1999, the Board of Directors met four times and the Audit Committee
met once. Each director attended at least 75% of the total number of Board and
Committee meetings held while he/she served as a director or a member of the
committee.
Other information required by Item 10 is omitted pursuant to General
Instruction I(2)(c) to Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by Item 12 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Item 13 is omitted pursuant to General Instruction
I(2)(c) to Form 10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
The following financial statements are included herein under Item 8.
FINANCIAL STATEMENTS
Balance Sheets, December 31, 1999 and 1998
Statements of Income for the years ended December 31, 1999, 1998 and 1997
Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997
Statements of Shareholder's Equity for the years ended December 31, 1999,
1998 and 1997
Notes to Financial Statements
REPORTS ON FORM 8-K
None
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K I
for the year ended December 31, 1992, File No. 1-7324)
3(b) Certificate of Merger of Kansas Gas and Electric Company into I
KCA Corporation (Filed as Exhibit 3(b) to Form 10-K
for the year ended December 31, 1992, File No. 1-7324)
3(c) By-laws as amended (Filed as Exhibit 3(c) Form 10-K I
for the year ended December 31, 1992, File No. 1-7324)
4(c) Mortgage and Deed of Trust, dated as of April 1, 1940 to I
Guaranty Trust Company of New York (now Morgan Guaranty Trust
Company of New York) and Henry A. Theis (to whom W. A. Spooner
is successor), Trustees, as supplemented by thirty-eight
Supplemental Indentures, dated as of June 1, 1942, March 1, 1948,
December 1, 1949, June 1, 1952, October 1, 1953, March 1, 1955,
February 1, 1956, January 1, 1961, May 1, 1966, March 1, 1970,
May 1, 1971, March 1, 1972, May 31, 1973, July 1, 1975,
December 1, 1975, September 1, 1976, March 1, 1977, May 1, 1977,
August 1, 1977, March 15, 1978, January 1, 1979, April 1, 1980,
July 1, 1980, August 1, 1980, June 1, 1981, December 1, 1981,
May 1, 1982, March 15, 1984, September 1, 1984 (Twenty-ninth
and Thirtieth), February 1, 1985, April 15, 1986, June 1, 1991
March 31, 1992, December 17, 1992, August 24, 1993, January 15,
1994 and March 1, 1994, (Filed, respectively, as Exhibit A-1 to
Form U-1, File No. 70-23; Exhibits 7(b) and 7(c), File No. 2-7405;
Exhibit 7(d), File No. 2-8242; Exhibit 4(c), File No. 2-9626;
Exhibit 4(c), File No. 2-10465; Exhibit 4(c), File No. 2-12228;
Exhibit 4(c), File No. 2-15851; Exhibit 2(b)-1, File No. 2-24680;
Exhibit 2(c), File No. 2-36170; Exhibits 2(c) and 2(d), File
No. 2-39975; Exhibit 2(d), File No. 2-43053; Exhibit 4(c)2 to
Form 10-K, for December 31, 1989, File No. 1-7324; Exhibit 2(c),
File No. 2-53765; Exhibit 2(e), File No. 2-55488; Exhibit 2(c),
File No. 2-57013; Exhibit 2(c), File No. 2-58180; Exhibit 4(c)3
to Form 10-K for December 31, 1989, File No. 1-7324; Exhibit 2(e),
File No. 2-60089; Exhibit 2(c), File No. 2-60777; Exhibit2(g),File
No. 2-64521; Exhibit 2(h), File No. 2-66758; Exhibits 2(d) and
2(e), File No. 2-69620; Exhibits 4(d) and 4(e), File No. 2-75634;
Exhibit 4(d), File No. 2-78944; Exhibit 4(d), File No. 2-87532;
Exhibits 4(c)4, 4(c)5 and 4(c)6 to Form 10-K for December 31,
1989, File No. 1-7324; Exhibits 4(c)2 and 4(c)3 to Form 10-K for
December 31, 1992, File No. 1-7324; Exhibit 4(b) to Form S-3,
File No. 33-50075; Exhibits 4(c)2 and 4(c)3 to Form 10-K for
December 31, 1993, File No. 1-7324; Exhibit 4(c)2 to Form 10-K
for December 31, 1994, File No. 1-7324)
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) La Cygne 2 Lease (Filed as Exhibit 10(a) to Form 10-K for the year I
ended December 31, 1988, File No. 1-7324)
10(a) Amendment No. 3 to La Cygne 2 Lease Agreement dated as of SeptemberI
29, 1992 (Filed as Exhibit 10(b)1 to Form 10-K for the year ended
December 31, 1992, File No. 1-7324)
10(b) Outside Directors' Deferred Compensation Plan (Filed as Exhibit I
10(c) to the Form 10-K for the year ended December 31, 1993,
File No. 1-7324)
12 Computation of Ratio of Consolidated Earnings to Fixed Charges
(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.
KANSAS GAS AND ELECTRIC COMPANY
March 28, 2000 By /s/ Ronald W. Holt
Ronald W. Holt
Chairman of the Board
and President
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated:
Signature Title Date
/s/ RONALD W. HOLT Chairman of the Board and
(Ronald W. Holt) President (Principal Executive March 28, 2000
Officer)
/s/ RICHARD D. TERRILL Secretary, Treasurer and General
(Richard D. Terrill) Counsel (Principal Financial March 28, 2000
and Accounting Officer)
/s/ JAMES A. MARTIN Director March 28, 2000
(James A. Martin)
/s/ MARILYN B. PAULY Director
(Marilyn B. Pauly)
/s/ RICHARD D. SMITH Director
(Richard D. Smith)