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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, 1997
[ ] 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 316/261-6611
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 30, 1998)
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 J(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
FORM 10-K
December 31, 1997
TABLE OF CONTENTS
Description Page
PART I
Item 1. Business 3
Item 2. Properties 12
Item 3. Legal Proceedings 13
Item 4. Submission of Matters to a Vote of
Security Holders 13
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 13
Item 6. Selected Financial Data 13
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 14
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 22
Item 8. Financial Statements and Supplementary Data 23
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 40
PART III
Item 10. Directors and Executive Officers of the
Registrant 41
Item 11. Executive Compensation 42
Item 12. Security Ownership of Certain Beneficial
Owners and Management 42
Item 13. Certain Relationships and Related Transactions 42
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 43
Signatures 46
PART I
ITEM 1. BUSINESS
GENERAL
The company is an electric public utility engaged in the generation,
transmission, distribution and sale of electric energy in the southeastern
quarter of Kansas including the Wichita metropolitan area. The company is a
wholly-owned subsidiary of Western Resources, Inc. The company owns 47% of
Wolf Creek Nuclear Operating Corporation, the operating company for Wolf Creek
Generating Station (Wolf Creek). Corporate headquarters of the company is
located in Wichita, Kansas. The company has no gas properties. At December
31, 1997, the company had no employees. All employees are provided by the
company's parent, Western Resources.
On February 7, 1997, the Western Resources signed a merger agreement with
Kansas City Power & Light Company (KCPL) by which KCPL would be merged with
and into Western Resources in exchange for Western Resources common stock. In
December 1997, representatives of the Western Resources' financial advisor
indicated that they believed it was unlikely that they would be in a position
to issue a fairness opinion required for the merger on the basis of the
previously announced terms.
On March 18, 1998, Western Resources and Kansas City Power & Light Company
(KCPL) announced a restructuring of their February 7, 1997, merger agreement
which will result in the formation of Westar Energy, a new electric company.
Under the terms of the merger agreement, the electric utility operations of
Western Resources will be transferred to the company, and KCPL and the company
will be merged into NKC, Inc., a subsidiary of Western Resources. NKC, Inc.
will be renamed Westar Energy. In addition, under the merger agreement, KCPL
shareowners will receive $23.50 of Western Resources common stock per KCPL
share, subject to a collar mechanism, and one share of Westar Energy common
stock per KCPL share. Upon consummation of the combination, Western Resources
will own approximately 80.1% of the outstanding equity of Westar Energy and
KCPL shareowners will own approximately 19.9%. As part of the combination,
Westar Energy will assume all of the electric utility related assets and
liabilities of Western Resources, KCPL, and the company.
Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion
of indebtedness23 for borrowed money of Western Resources and the company, and
$800 million of debt of KCPL. Long-term debt of Western Resources and the
company was $2.1 billion at December 31, 1997. Under the terms of the merger
agreement, it is intended that the company will be released from its
obligations with respect to the company's debt to be assumed by Westar Energy.
For additional information concerning the company's long-term debt and
obligations under the La Cygne sale leaseback arrangements which will become
obligations of Westar Energy, see Note 5 and Note 6 of "Notes to Financial
Statements".
Consummation of the merger is subject to customary conditions including
obtaining the approval of Western Resources' and KCPL's shareowners and
various regulatory agencies. Western Resources estimates the transaction to
close by mid-1999, subject to receipt of all necessary approvals.
KCPL is a public utility company engaged in the generation, transmission,
distribution, and sale of electricity to customers in western Missouri and
eastern Kansas. KCPL, Western Resources, and the company have joint interests
in certain electric generating assets, including Wolf Creek. For additional
information, see "Financing" below, Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and Note 14 of
"Notes to Financial Statements".
The United States electric utility industry is evolving from a regulated
monopolistic market to a competitive marketplace. The 1992 Energy Policy Act
began deregulating the electricity industry. The Energy Policy Act permitted
the Federal Energy Regulatory Commission (FERC) to order electric utilities to
allow third parties the use of their transmission systems to sell electric
power to wholesale customers. A wholesale sale is defined as a utility
selling electricity to a "middleman", usually a city or its utility company,
to resell to the ultimate retail customer. As part of the 1992 acquisition of
the company by Western Resources, we agreed to open access of our transmission
system for wholesale transactions. FERC also requires us to provide
transmission services to others under terms comparable to those we provide to
ourselves. For 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".
Discussion of other factors affecting the company are set forth in the
Notes to Financial Statements and Management's Discussion and Analysis
included herein.
ELECTRIC OPERATIONS
General
The company supplies electric energy at retail to approximately 280,000
customers in 139 communities in Kansas. The company also supplies electric
energy to 27 communities and 1 rural electric cooperative, and has contracts
for the sale, purchase or exchange of electricity with other utilities at
wholesale.
The company's electric sales volumes for the last five years were as follows:
1997 1996 1995 1994 1993
(Thousands of MWH)
Residential 2,490 2,503 2,385 2,384 2,386
Commercial 2,211 2,186 2,095 2,068 1,991
Industrial 3,518 3,501 3,542 3,371 3,323
Wholesale and
Interchange 2,101 2,706 1,292 1,590 2,004
Other 45 45 45 45 45
Total 10,365 10,941 9,359 9,458 9,749
The company's electric sales for the last five years were as follows:
1997(1) 1996 1995 1994 1993
(Dollars in Thousands)
Residential $214,719 $226,456 $221,628 $220,067 $219,069
Commercial 162,913 176,963 171,654 167,499 162,858
Industrial 165,614 175,420 182,930 181,119 179,256
Wholesale and
Interchange 53,343 57,242 31,143 38,750 45,843
Other 17,856 18,489 16,813 12,458 9,981
Total $614,445 $654,570 $624,168 $619,893 $617,007
(1) Electric sales decreased primarily due to electric rate decrease
implemented on February 1, 1997.
Capacity
The aggregate net generating capacity of the company's system is presently
2,530 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. One of the twelve
fossil fueled units (70 MW capacity) has been "mothballed" for future use (See
Item 2. Properties).
The company's 1997 peak system net load occurred on July 24, 1997 and
amounted to 1,868 MW. The company's net generating capacity together with
power available from firm interchange and purchase contracts, provided a
capacity margin of approximately 19% above system peak responsibility at the
time of the peak.
The company and twelve companies in Kansas and western Missouri have
agreed to provide capacity (including margin), emergency and economy services
for each other. This arrangement is called the MOKAN Power Pool. The pool
participants also coordinate the planning of electric generating and
transmission facilities.
The company is one of 54 members of the Southwest Power Pool (SPP). SPP's
responsibility is to maintain system reliability on a regional basis. The
region encompasses areas within the eight states of Kansas, Missouri,
Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi.
In 1994, the company joined the Western Systems Power Pool (WSPP). Under
this arrangement, over 172 electric utilities and marketers throughout the
western United States have agreed to market energy and to provide transmission
services. WSPP's intent is to increase the efficiency of the interconnected
power systems operations over and above existing operations. Services
available include short-term and long-term economy energy transactions, unit
commitment service, firm capacity and energy sales, energy exchanges, and
transmission service by intermediate systems.
During 1994, the company entered into an agreement with Midwest Energy,
Inc. (MWE), whereby the company will provide MWE with peaking capacity of 61
MW through the year 2008. The company also entered into an agreement with
Empire District Electric Company (Empire), whereby the company will provide
Empire with peaking and base load capacity (20 MW in 1994 increasing to 80 MW
in 2000) through the year 2000.
Future Capacity
The company does not contemplate any significant expenditures in
connection with construction of any major generating facilities for the next
five years. (See Item 7. Management's Discussion and Analysis, Liquidity and
Capital Resources). The company has capacity available which may not be fully
utilized by growth in customer demand for at least 5 years. The company
continues to market this capacity and energy to other utilities.
Fuel Mix
The company's coal-fired units comprise 1,115 MW of the total 2,530 MW of
generating capacity and the company's nuclear unit provides 547 MW of
capacity. Of the remaining 868 MW of generating capacity, units that can burn
either natural gas or oil account for 865 MW, and the remaining unit which
burns only diesel fuel accounts for 3 MW (See Item 2. Properties).
During 1997, low sulfur coal was used to produce 56% of the company's
electricity. Nuclear produced 35% and the remainder was produced from natural
gas, oil, or diesel fuel. During 1998, based on the company's estimate of the
availability of fuel, coal will to be used to produce approximately 56% of the
company's electricity and nuclear will be used to produce 36%.
The company's fuel mix fluctuates with the operation of nuclear powered
Wolf Creek which has an 18-month refueling and maintenance schedule. The 18-
month schedule permits uninterrupted operation every third calendar year.
Wolf Creek was taken off-line on October 4, 1997 for its ninth refueling and
maintenance outage. The outage lasted approximately 58 days during which time
electric demand was met primarily by the company's coal-fired generating
units.
Nuclear
The owners of Wolf Creek have on hand or under contract 100% of their uranium
needs for 1998 and 59% of the uranium required to operate Wolf Creek through
September 2003. The balance is expected to be obtained through spot market
and contract purchases. The company has three active contracts with the
following companies for uranium: Cameco Corporation, Geomex Minerals, Inc.,
and Power Resources, Inc.
A contractual arrangement is in place with Cameco Corporation for the
conversion of uranium to uranium hexafluoride sufficient for the operation of
Wolf Creek through the year 2001.
The company has two active contracts for uranium enrichment performed by
Urenco and USEC. Contracted arrangements cover 80% of Wolf Creek's uranium
enrichment requirements for operation of Wolf Creek through March 2005. The
balance is expected to be obtained through spot market and term contract
purchases.
The company has entered into all of its uranium, uranium hexaflouride and
uranium enrichment arrangements during the ordinary course of business and is
not substantially dependent upon these agreements. The company believes there
are other suppliers available at reasonable prices to replace, if necessary,
these contracts. In the event that the company were required to replace these
contracts, it would not anticipate a substantial disruption of its business.
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, the Department of Energy (DOE) is responsible for the permanent
disposal of spent nuclear fuel. The company pays the DOE a quarterly fee of
one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered
and sold for future disposal of spent nuclear fuel. These disposal costs are
charged to cost of sales and currently recovered through rates.
In 1996, a U.S. Court of Appeals issued a decision that the Nuclear Waste
Act unconditionally obligated the DOE to begin accepting spent fuel for
disposal in 1998. In late 1997, the same court issued another decision
precluding the DOE from concluding that its delay in accepting spent fuel is
"unavoidable" under its contracts with utilities due to lack of a repository
or interim storage authority. By the end of 1997, the company and other
utilities had petitioned the DOE for authority to suspend payments of their
quarterly fees until such time as the DOE begins accepting spent fuel. In
January 1998, the DOE denied the petition of the utilities. The company is
considering its response to the DOE's action.
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 started
plans to increase its on-site spent fuel storage capacity. That project,
expected to be completed by 2000, should provide 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 and selected a site in northern
Nebraska to locate a disposal facility. The present estimate of the cost for
such a facility is about $154 million. WCNOC and the owners of the other five
nuclear units in the compact have provided most of the pre-construction
financing for this project.
There is uncertainty as to whether this project will be completed.
Significant opposition to the project has been raised by Nebraska officials
and residents in the area of the proposed facility, and attempts have been
made through litigation and proposed legislation in Nebraska to slow down or
stop development of the facility.
Additional information with respect to insurance coverage applicable to
the operations of the company's nuclear generating facility is set forth in
Note 2 of the Notes to Consolidated Financial Statements.
Coal
The three coal-fired units at Jeffrey Energy Center (JEC) have an
aggregate capacity of 438 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 Cyprus Amax Coal
Company, to supply low sulfur coal to JEC from AMAX's Eagle Butte Mine or an
alternate mine source of AMAX's Belle Ayr Mine, both located in the Powder
River Basin in Campbell County, Wyoming. The contract expires December 31,
2020. The contract contains a schedule of minimum annual delivery quantities
based on MMBtu provisions. The coal to be supplied is surface mined and has
an average Btu content of approximately 8,300 Btu per pound and an average
sulfur content of .43 lbs/MMBtu (See Environmental Matters). The average
delivered cost of coal for JEC was approximately $1.13 per MMBtu or $18.92 per
ton during 1997.
Coal is transported by Western Resources from Wyoming under a long-term
rail transportation contract with Burlington Northern Santa Fe 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 677 MW (KGE's 50% share) (See Item 2. Properties). The operator,
Kansas City Power & Light Company (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 85% Powder River Basin coal.
La Cygne 2 and additional La Cygne 1 Powder River Basin coal is supplied
through several contracts, expiring at various times through 1999. This low
sulfur coal had an average Btu content of approximately 8,500 Btu per pound
and a maximum sulfur content of .50 lbs/MMBtu (See Environmental Matters).
Transportation is covered by KCPL through its Omnibus Rail Transportation
Agreement with Burlington Northern Santa Fe Railroad and Kansas City Southern
Railroad through December 31, 2000.
During 1997, the average delivered cost of all local and Powder River
Basin coal procured for La Cygne 1 was approximately $0.70 per MMBtu or $12.31
per ton and the average delivered cost of Powder River Basin coal for La Cygne
2 was approximately $0.67 per MMBtu or $11.32 per ton.
The company has entered into all of its coal contracts during the ordinary
course of business and is not substantially dependent upon these contracts.
The company believes there are other suppliers for and plentiful sources of
coal available at reasonable prices to replace, if necessary, fuel to be
supplied pursuant to these contracts. In the event that the company were
required to replace its coal agreements, it would not anticipate a substantial
disruption of the company's business.
The company has entered into all of its transportation contracts during
the ordinary course of business. At the time of entering into these
contracts, the company was not substantially dependent upon these contracts
due to the availability of competitive rail options. Due to recent rail
consolidation, there are now only two rail carriers capable of serving the
company's origin coal mines and its generating stations. In the event one of
these carriers became unable to provide reliable service, the company could
experience a short-term disruption of its business. However, due to the
obligation of the remaining carriers to provide service under the Interstate
Commerce Act, the company does not anticipate any substantial long-term
disruption of its business.
Natural Gas
The company uses natural gas as a primary fuel in its Gordon Evans and
Murray Gill Energy Centers. Natural gas for these generating stations is
supplied by readily available gas from the spot market. Short-term economical
spot market purchases will supply the system with the flexible natural gas
supply to meet operational needs.
Oil
The company uses oil as an alternate fuel when economical or when
interruptions to natural gas make it necessary. Oil is also used as a
supplemental fuel at JEC and La Cygne generating stations. All oil burned by
the company during the past several years has been obtained by spot market
purchases. At December 31, 1997, the company had approximately one million
gallons of No. 2 oil and eleven 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 and/or the loss of a large generating unit.
Other Fuel Matters
The company's contracts to supply fuel for its coal and natural gas-fired
generating units, with the exception of JEC, do not provide full fuel
requirements at the various stations. Supplemental fuel is procured on the
spot market to provide operational flexibility and, when the price is
favorable, to take advantage of economic opportunities.
Set forth in the table below is information relating to the weighted
average cost of fuel used by the company.
1997 1996 1995 1994 1993
Per Million Btu:
Nuclear $0.51 $0.50 $0.40 $0.36 $0.35
Coal 0.89 0.88 0.91 0.90 0.96
Gas 2.56 2.30 1.68 1.98 2.37
Oil 3.32 2.74 4.00 3.90 3.15
Cents per KWH Generation 1.00 0.93 0.82 0.89 0.93
Environmental Matters
The company currently holds all Federal and State environmental approvals
required for the operation of its generating units. The company believes it
is presently in substantial compliance with all air quality regulations
(including those pertaining to particulate matter, sulfur dioxide and nitrogen
oxides (NOx)) promulgated by the State of Kansas and the Environmental
Protection Agency (EPA).
The Federal sulfur dioxide standards applicable to the company's JEC and
La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur
dioxide per million Btu of heat input. Federal particulate matter emission
standards applicable to these units prohibit: (1) the emission of more than
0.1 pounds of particulate matter per million Btu of heat input and (2) an
opacity greater than 20%. Federal NOx emission standards applicable to these
units prohibit the emission of more than 0.7 pounds of NOx per million Btu of
heat input.
The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards
through the use of low sulfur coal (See Coal); (2) the particulate matter
standards through the use of electrostatic precipitators; and (3) the NOx
standards through boiler design and operating procedures. The JEC units are
also equipped with flue gas scrubbers providing additional sulfur dioxide and
particulate matter emission reduction capability when needed to meet permit
limits.
The Kansas Department of Health and Environment (KDHE) regulations,
applicable to the company's other generating facilities, prohibit the emission
of more than 3.0 pounds of sulfur dioxide per million Btu of heat input at the
company's generating units. The company has 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.
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.
All of the company's generating facilities are in substantial compliance
with the Best Practicable Technology and Best Available Technology regulations
issued by the EPA pursuant to the Clean Water Act of 1977. Most EPA
regulations are administered in Kansas by the KDHE.
Additional information with respect to Environmental Matters is discussed
in Note 2 of the "Notes to Financial Statements".
FINANCING
The company's ability to issue additional debt is restricted under
limitations imposed by the Mortgage and Deed of Trust of the company.
The company's mortgage prohibits additional first mortgage bonds from
being issued (except in connection with certain refundings) unless the
company's net earnings before income taxes and before provision for retirement
and depreciation of property for a period of 12 consecutive months within 15
months preceding the issuance are not less than two and one-half times the
annual interest charges on, or 10% of the principal amount of, all first
mortgage bonds outstanding after giving effect to the proposed issuance.
Based on the company's results for the 12 months ended December 31, 1997,
approximately $935 million principal amount of additional first mortgage bonds
could be issued (7.25% interest rate assumed).
KGE bonds may be issued, subject to the restrictions in the preceding
paragraph, on the basis of property additions not subject to an unfunded prior
lien and on the basis of bonds which have been retired. As of December 31,
1997, the company had approximately $1.4 billion of net bondable property
additions not subject to an unfunded prior lien entitling the company to issue
up to $961 million principal amount of additional bonds. As of December 31,
1997, $17 million in additional bonds could be issued on the basis of retired
bonds.
In connection with the combination of the electric utility operations of
Western Resources, KCPL and the company, Westar Energy will assume $1.9
billion of indebtedness for borrowed money of Western Resources and the
company comprised primarily of the companies' outstanding long-term debt.
Pursuant to the amended and restated agreement and plan of merger, the
company's mortgage, by operation of law, will be assumed by Westar Energy.
See, Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and Note 14 of "Notes to Financial Statements".
REGULATION AND RATES
The company is subject as an operating electric utility to the
jurisdiction of the KCC which has general regulatory authority over the
company's rates, extensions and abandonments of service and facilities,
valuation of property, the classification of accounts and various other
matters. The company is also subject to the jurisdiction of the FERC and the
KCC with respect to the issuance of the company's securities.
Additionally, the company is subject to the jurisdiction of the FERC,
including jurisdiction as to rates with respect to sales of electricity for
resale, and the Nuclear Regulatory Commission as to nuclear plant operations
and safety.
Additional information with respect to Regulation and Rates is discussed
in Notes 1 and 3 of the "Notes to Financial Statements" and Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations".
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years
William B. Moore 45 Chairman of the Board Vice President, Finance -
and President (since Western Resources, Inc.
June 1995)
Richard D. Terrill 43 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
The company owns or leases and operates an electric generation,
transmission, and distribution system in Kansas.
ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (1)
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 152
2 1967 Gas--Oil 382
Jeffrey Energy Center (20%) (2):
Steam Turbines 1 1978 Coal 147
2 1980 Coal 147
3 1983 Coal 144
La Cygne Station (50%) (2):
Steam Turbines 1 1973 Coal 343
2 1977 Coal 334
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 44
2 1954 Gas--Oil 74
3 1956 Gas--Oil 107
4 1959 Gas--Oil 106
Neosho Energy Center:
Steam Turbine 3 1954 Gas--Oil 0 (3)
Wichita Plant:
Diesel Generator 5 1969 Diesel 3
Wolf Creek
Generating Station (47%)(2):
Nuclear 1 1985 Uranium 547
Total 2,530
(1) Based on MOKAN rating.
(2) The company jointly owns Jeffrey Energy Center (20%), La Cygne Station (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.
(3) This unit has been "mothballed" for future use.
ITEM 3. LEGAL PROCEEDINGS
Information on legal proceedings involving the company is set forth in Notes
2, 3, and 8 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
J(2)(c) to Form 10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The company's common stock is owned by Western Resources and is not traded
on an established public trading market. See Note 14 of "Notes to Financial
Statements" for information concerning the effect on the ownership of the
company's common stock caused by the pending transaction with KCPL.
ITEM 6. SELECTED FINANCIAL DATA
1997 1996 1995 1994 1993
(Dollars in Thousands)
Income Statement Data:
Sales. . . . . . . . . . . . . . $ 614,445 $ 654,570 $ 624,168 $ 619,893 $ 617,007
Income from operations . . . . . 124,008 186,961 209,739 211,248 196,365
Net income . . . . . . . . . . . 52,128 96,274 110,873 104,526 108,103
Balance Sheet Data:
Total assets . . . . . . . . . . 3,117,108 3,318,887 3,203,414 3,237,684 3,187,479
Long-term debt . . . . . . . . . 684,128 684,068 684,082 699,992 653,543
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 2.38 3.28 4.11 4.02 3.58
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 1997 and 1996
- Why these earnings and costs differed from year to year
- How our earnings and costs affect our overall financial condition
- What our capital expenditures were for 1997
- What we expect our capital expenditures to be for the years 1998
through 2000
- How we plan to pay for these future capital expenditures
- Any other items that particularly affect our financial condition or
earnings
As you read Management's Discussion and Analysis, please refer to our
Statements of Income on page 26. These statements show our operating results
for 1997, 1996 and 1995. In Management's Discussion and Analysis, we analyze
and explain the significant annual changes of specific line items in the
Statements of Income.
FORWARD-LOOKING STATEMENTS: Certain matters discussed here and elsewhere
in this Annual Report are "forward-looking statements." The Private
Securities Litigation Reform Act of 1995 has established that these statements
qualify for safe harbors from liability. Forward-looking statements may
include words like we "believe," "anticipate," "expect" or words of similar
meaning. Forward-looking statements describe our future plans, objectives,
expectations or goals. Such statements address future events and conditions
concerning capital expenditures, earnings, litigation, rate and other
regulatory matters, possible corporate restructurings, mergers, acquisitions,
dispositions liquidity and capital resources, interest and dividend rates,
environmental matters, changing weather, nuclear operations and accounting
matters. What happens in each case could vary materially from what we expect
because of such things as electric utility deregulation, including ongoing
state and federal activities; future economic conditions; legislative
developments; our regulatory and competitive markets; and other circumstances
affecting anticipated operations, sales and costs.
1997 HIGHLIGHTS
WESTERN RESOURCES MERGER AGREEMENT WITH KANSAS CITY POWER & LIGHT COMPANY: On
February 7, 1997, the Western Resources signed a merger agreement with KCPL by
which KCPL would be merged with and into Western Resources in exchange for
Western Resources common stock. In December 1997, representatives of the
Western Resources' financial advisor indicated that they believed it was
unlikely that they would be in a position to issue a fairness opinion required
for the merger on the basis of the previously announced terms.
On March 18, 1998, Western Resources and KCPL announced a restructuring of
their February 7, 1997, merger agreement which will result in the formation of
Westar Energy, a new electric company. Under the terms of the merger
agreement, the electric utility operations of Western Resources will be
transferred to the company, and KCPL and the company will be merged into NKC,
Inc., a subsidiary of Western Resources. NKC, Inc. will be renamed Westar
Energy. In addition, under the merger agreement, KCPL shareowners will
receive $23.50 of Western Resources common stock per KCPL share, subject to a
collar mechanism, and one share of Westar Energy common stock per KCPL share.
Upon consummation of the combination, Western Resources will own approximately
80.1% of the outstanding equity of Westar Energy and KCPL shareowners will own
approximately 19.9%. As part of the combination Westar Energy will assume all
of the electric utility related assets and liabilities of Western Resources,
KCPL, and the company.
Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion
of indebtedness for borrowed money of Western Resources and the company, and
$800 million of debt of KCPL. Long-term debt of Western Resources and the
company was $2.1 billion at December 31, 1997. Under the terms of the merger
agreement, it is intended that the company will be released from its
obligations with respect to the company's debt to be assumed by Westar Energy.
For additional information concerning the company's long-term debt and
obligations under the La Cygne sale leaseback arrangements which will become
obligations of Westar Energy, see Note 5 and Note 6 of "Notes to Financial
Statements".
Consummation of the merger is subject to customary conditions including
obtaining the approval of Western Resources' and KCPL's shareowners and
various regulatory agencies. Western Resources estimates the transaction to
close by mid-1999, subject to receipt of all necessary approvals.
KCPL is a public utility company engaged in the generation, transmission,
distribution, and sale of electricity to customers in western Missouri and
eastern Kansas. We, KCPL and KGE have joint interests in certain electric
generating assets, including Wolf Creek. Following the closing of the
combination Westar Energy is expected to have approximately one million
electric utility customers in Kansas and Missouri, approximately $8.2 billion
in assets and the ability to generate more than 8,000 megawatts of
electricity. For additional information, see "Financing in Item 1. Business",
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and Note 14 of "Notes to Financial Statements".
ELECTRIC RATE DECREASE: On May 23, 1996, we reduced our electric rates by
$8.7 million annually on an interim basis. On October 22, 1996, the KCC
Staff, the City of Wichita, the Citizens Utility Ratepayer Board and we filed
an agreement asking the KCC to reduce our retail electric rates. The KCC
approved this agreement on January 15, 1997. Per the agreement:
- We made permanent the May 1996 interim $8.7 million decrease in our
annual rates on February 1, 1997
- We reduced our annual rates by $36 million on February 1, 1997
- We rebated $2.3 million to our customers in January 1998
- We will reduce our annual rates by an additional $10 million on
June 1, 1998
- We will rebate an additional $2.3 million to our customers in
January 1999
- We will reduce our annual rates by an additional $10 million on
June 1, 1999
All rate decreases are cumulative. Rebates are one-time events and do not
influence future rates. See "Financial Condition" below and Note 3.
FINANCIAL CONDITION
1997 compared to 1996: Net income of $52.1 million for 1997 decreased
substantially from $96.3 million for 1996. The decrease in net income is
primarily attributable to the implementation of a $36 million rate reduction
on February 1, 1997, and an $8.7 million interim rate reduction which became
permanent on January 15, 1997.
1996 compared to 1995: Net income for 1996 decreased to $96.3 million or
$14.6 million from $110.9 million for 1995. The amortization of the
acquisition adjustment as a result of the Merger and a $8.7 million interim
rate reduction implemented on May 23, 1996, were primary reasons for the
decline in net income. Abnormally cool summer weather during the third
quarter of 1996 also adversely affected earnings.
OPERATING RESULTS
In our "1997 Highlights", we discussed factors that most significantly
changed our operating results for 1997 compared to 1996.
The following explains significant changes from prior year results in
sales, cost of sales, operating expenses, other income (expense), interest
expense and income taxes.
SALES: Sales are based on sales volumes and rates authorized by the
Kansas Corporation Commission (KCC) and the Federal Energy Regulatory
Commission (FERC). Rates charged for the sale and delivery of electricity are
designed to recover the cost of service and allow investors a fair rate of
return. Our sales vary with levels of sales volume. Changing weather affects
the amount of energy our customers use. Very hot summers and very cold
winters prompt more demand, especially among our residential customers. Mild
weather reduces demand.
Many things will affect our future sales. They include:
- The weather
- Our electric rates
- Competitive forces
- Customer conservation efforts
- Wholesale demand
- The overall economy of our service area
1997 compared to 1996: Sales decreased $40.1 million or six percent
because of lower electric rates which were implemented on February 1, 1997.
Reduced electric rates lowered 1997 sales by an estimated $36.8 million
compared to 1996. The rate decreases we have agreed to make will impact
future sales. Sales volumes to our retail customers remained virtually
unchanged for 1997.
1996 compared to 1995: Sales increased five percent primarily due to
higher wholesale and interchange sales volume as a result of an increase in
customers. Increased residential and commercial sales also contributed to the
increase as a result of colder winter and warmer spring temperatures. Our
service territory experienced a 17% increase in heating degree days during the
first quarter and cooling degree days more than doubled during the second
quarter of 1996 compared to the same periods in 1995. Partially offsetting
this increase was the $8.7 million electric rate reduction implemented on an
interim basis on May 23, 1996 and made permanent on February 1, 1997.
COST OF SALES: Items included in energy cost of sales are fuel expense
and purchased power expense (electricity we purchase from others for resale).
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 the company
did not recover through rates would reduce our earnings. The degree of any
such impact would be affected by a variety of factors, however, and thus
cannot be predicted.
1997 compared to 1996: Actual cost of fuel to generate electricity (coal,
nuclear fuel, natural gas or oil) and the amount of power purchased from other
utilities were $6.3 million higher in 1997 than in 1996. Our Wolf Creek
nuclear generating station was off-line in the fourth quarter of 1997 for
scheduled maintenance and our La Cygne coal generation station was off-line
during 1997 for an extended maintenance outage. As a result, we purchased
more power from other utilities and burned more natural gas to generate
electricity at our facilities. Natural gas is more costly to burn than coal
and nuclear fuel for generating electricity.
1996 compared to 1995: Cost of sales for 1996 was $18.7 million or 18%
higher than 1995. We purchased more power from other utilities because our
Wolf Creek nuclear generating station was off-line in the first quarter of
1996 for a planned refueling outage. Higher net generation due to increased
interchange sales also contributed to the higher fuel and purchased power
expenses.
OPERATING EXPENSES
Operating and Maintenance Expense: Operating and maintenance expense
increased $4.0 million in 1997 compared to 1996. An extended maintenance
outage at our La Cygne generating station accounted for most of this increase.
Operating and maintenance expense for 1996 of $176 million increased $23.8
million over 1995. This increase is attributable to an increase in KGE's
portion of costs shared between Western Resources and KGE which are associated
with the dispatching of electric power.
Depreciation and Amortization Expense: Depreciation and amortization
expense increased $9.6 million in 1997 from 1996 due to the additional
amortization of $8.8 million we recorded relating to phase-in revenues. A
full year of amortization of the acquisition adjustment relating to the Merger
increased our depreciation and amortization expense for 1996 compared to 1995
by approximately $14 million.
Selling, General and Administrative Expense: Selling, general and
administrative expense has increased $2.9 million from 1996 to 1997. Most of
this increase is attributable to higher employee benefit costs.
OTHER INCOME (EXPENSE): Other income (expense) includes miscellaneous
income and expenses not directly related to our operations. Other income
(expense) for 1997 declined $7.7 million from 1996. The decrease is primarily
due to income and expenses relating to our corporate-owned life insurance
policies. Other income (expense) decreased in 1996 from 1995 as a result of a
gain on the sale of utility plant which we recognized in the first quarter of
1995.
INTEREST EXPENSE: Interest expense includes the interest we paid on
outstanding debt. We recognized a $7.4 million decrease in short-term debt
interest in 1997 compared to 1996. During 1997 we held a smaller average
short-term debt balance than in 1996. Proceeds from the repayment of advances
to parent company were used to repay current outstanding short-term debt.
The proceeds we received are reflected in the decrease in current assets,
advances to parent company (net) on the Balance Sheets. From 1996 to 1995,
interest recorded on short-term debt increased $6.6 million due to the higher
short-term debt balances we held during 1996.
INCOME TAXES: Income taxes decreased $18.9 million in 1997 and $15.5
million in 1996. These substantial decreases are primarily due to the
decreases we have recognized in net income for the last two years.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW: The company's liquidity is a function of its ongoing
construction and maintenance program 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.
Other than operations, our primary source of short-term cash is from
short-term bank loans and unsecured lines of credit. At December 31, 1997, we
had approximately $45 million of short-term debt outstanding. An additional
$100 million of short-term debt was available from committed credit
arrangements.
Other 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, 1997, $50 million of KGE first mortgage bonds were registered.
The embedded cost of long-term debt was 7.3% at December 31, 1997 and
1996.
The company's capital structure at December 31, 1997 and 1996, was 62% and
63% common stock equity and 38% and 37% long-term debt, respectively.
SECURITY RATINGS: Standard & Poor's Ratings Group (S&P), Fitch Investors
Service (Fitch) and Moody's Investors Service (Moody's) are independent
credit-rating agencies. These agencies rate our debt securities. These
ratings indicate the agencies' assessment of our ability to pay interest,
dividends and principal on these securities. These ratings affect how much we
will have to pay as interest or dividends on securities we sell to obtain
additional capital. The better the rating, the less we will have to pay on
debt securities we sell.
At December 31, 1997, ratings with these agencies were as follows:
Mortgage
Bond
Rating Agency Rating
S&P BBB+
Fitch A-
Moody's A3
Following the announcement of Western Resources restructed merger
agreement with KCPL, S&P placed its ratings of Western Resources and the
company on CreditWatch with positive implications.
FUTURE CASH REQUIREMENTS: We believe that internally generated funds and
new and existing credit agreements will be sufficient to meet our operating
and capital expenditure requirements and debt service payments through the
year 2000. Uncertainties affecting our ability to meet these requirements
with internally generated funds include the effect of competition and
inflation on operating expenses, sales volume, regulatory actions, compliance
with future environmental regulations, the availability of generating units
and weather. The amount of these requirements and our ability to fund them
will also be significantly impacted by the pending combination of Western
Resources electric utility operations, KCPL and the company.
We believe that we will meet the needs of our electric utility customers
without adding any major generation facilities in the next five years.
During 1997, construction expenditures for the company's electric system
were approximately $69 million and nuclear fuel expenditures were
approximately $19 million. The construction program is focused on providing
service to new customers and improving present electric facilities.
Capital expenditures for 1998 through 2000 are anticipated to be as
follows:
Electric Nuclear Fuel
(Dollars in Thousands)
1998. . . . . . . . . . $55,456 $22,711
1999. . . . . . . . . . 54,519 4,040
2000. . . . . . . . . . 53,429 22,803
These expenditures are estimates prepared for planning purposes and may be
revised and do not take into account the pending combination of Western
Resources electric utility operations, KCPL and the company.
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 (combined companies) are
recovering the amortization of the acquisition adjustment through cost savings
under a sharing mechanism approved by the KCC.
Based on the order issued by the KCC, with regard to the recovery of the
acquisition premium, the combined companies must achieve a level of savings on
an annual basis (considering sharing provisions) of approximately $27 million
in order to recover the entire acquisition premium.
On January 15, 1997, the KCC fixed the annual merger savings level at $40
million which provides complete recovery of the acquisition premium
amortization expense and a return on the acquisition premium. See Note 3 for
further information relating to rate matters and regulation.
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
COMPETITION AND ENHANCED BUSINESS OPPORTUNITIES: The United States
electric utility industry is evolving from a regulated monopolistic market to
a competitive marketplace. The 1992 Energy Policy Act began deregulating the
electricity industry. The Energy Policy Act permitted the FERC to order
electric utilities to allow third parties the use of their transmission
systems to sell electric power to wholesale customers. A wholesale sale is
defined as a utility selling electricity to a "middleman", usually a city or
its utility company, to resell to the ultimate retail customer. As part of
the 1992 merger, we agreed to open access of our transmission system for
wholesale transactions. FERC also requires us to provide transmission
services to others under terms comparable to those we provide to ourselves.
During 1997, wholesale electric revenues represented approximately 9% of total
electric revenues.
Various states have taken steps to allow retail customers to purchase
electric power from providers other than their local utility company. The
Kansas Legislature has created a Retail Wheeling Task Force (the Task Force)
to study the effects of a deregulated and competitive market for electric
services. Legislators, regulators, consumer advocates and representatives
from the electric industry make up the Task Force. The Task Force submitted a
bill to the Kansas Legislature without recommendation. This bill seeks
competitive retail electric service on July 1, 2001. The bill was introduced
to the Kansas Legislature in the opening days of the 1998 legislative session,
but is not expected to come to a vote this year. The Task Force also is
evaluating how to recover certain investments in generation and related
facilities which were approved and incurred under the existing regulatory
model. Some of these investments may not be recoverable in a competitive
marketplace. We have opposed the Task Force's bill for this reason. These
unrecovered investments are commonly called "stranded costs." See "Stranded
Costs" below for further discussion. Until a bill is passed by the Kansas
Legislature, we cannot predict its impact on our company, but the impact could
be material.
Increased competition for retail electricity sales may reduce future
electric utility earnings compared to our historical electric utility
earnings. After all electric rate decreases are implemented, our rates will
be at 91% of the national average for retail customers. Because of these
reduced rates, we expect to retain a substantial part of our current sales
volume in a competitive environment. Finally, we believe the deregulated
energy market may prove beneficial to us.
While operating in this competitive environment may place pressure on our
profit margins and credit ratings, we expect it to create opportunities.
Wholesale and industrial customers may pursue cogeneration, self-generation,
retail wheeling, municipalization or relocation to other service territories
in an attempt to cut their energy costs. Credit rating agencies are applying
more stringent guidelines when rating utility companies due to increasing
competition.
We offer competitive electric rates for industrial improvement projects
and economic development projects in an effort to maintain and increase
electric load.
STRANDED COSTS: The definition of stranded costs for a utility business is
the investment in and carrying costs on property, plant and equipment and
other regulatory assets which exceed the amount that can be recovered in a
competitive market. We currently apply accounting standards that recognize the
economic effects of rate regulation and record regulatory assets and
liabilities related to our generation, transmission and distribution
operations. If we determine that we no longer meet the criteria of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71), 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
competition or other events, we may significantly impact the value of our net
regulatory assets and our utility plant investments, particularly the Wolf
Creek facility. See "Competition and Enhanced Business Opportunities" above
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, 1997,
we have recorded regulatory assets which are currently subject to recovery in
future rates of approximately $279 million. Of this amount, $188 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 that 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.
YEAR 2000 ISSUE: The company is currently addressing the effect of the
Year 2000 Issue on our reporting systems and operations. We face the Year
2000 Issue because many computer systems and applications abbreviate dates by
eliminating the first two digits of the year, assuming that these two digits
are always "19". On January 1, 2000, some computer programs may incorrectly
recognize the date as January 1, 1900. Some computer systems may incorrectly
process critical financial and operational information, or stop processing
altogether because of the date abbreviation. Calculations using the year 2000
will affect computer applications before January 1, 2000.
We plan to have our Year 2000 readiness efforts substantially completed by
the end of 1998. We expect no significant operational impact on our ability
to serve our customers, pay suppliers, or operate other areas of our business.
Western Resources currently estimates that the total cost to update all of
its and our systems for Year 2000 compliance will be approximately $7 million.
In 1997, Western Resources expensed approximately $3 million of these costs.
Western Resources has allocated a portion of these costs to our company.
There can be no assurance however, that our suppliers will not be affected
by the Year 2000 issue which could affect our operations.
DECOMMISSIONING: Decommissioning is a nuclear industry term for the
permanent shut-down of a nuclear power plant when the plant's license expires.
The Nuclear Regulatory Commission (NRC) will terminate a plant's license and
release the property for unrestricted use when a company has reduced the
residual radioactivity of a nuclear plant to a level mandated by the NRC. The
NRC requires companies with nuclear power plants to prepare formal financial
plans. These plans ensure that funds required for decommissioning will be
accumulated during the estimated remaining life of the related nuclear power
plant.
The SEC staff has questioned the way electric utilities recognize, measure
and classify decommissioning costs for nuclear electric generating stations in
their financial statements. In response to the SEC's questions, the Financial
Accounting Standards Board is reviewing the accounting for closure and removal
costs, including decommissioning of nuclear power plants. If current
accounting practices for nuclear power plant decommissioning are changed, the
following could occur:
- Our annual decommissioning expense could be higher than in 1997
- The estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment in the
Wolf Creek plant
We do not believe that such changes, if required, would adversely affect
our operating results due to our current ability to recover decommissioning
costs through rates.
PRONOUNCEMENT ISSUED BUT NOT YET EFFECTIVE: In January 1998, the company
adopted Statement of Financial Accounting Standards No. 131, "Disclosures
about Segments of an Enterprise and Related Information" (SFAS 131). This
statement establishes standards for public business enterprises to report
information about operating segments in interim and annual financial
statements. Interim disclosure requirements are not required until 1999.
Operating segments are defined as components of an enterprise about which
separate financial information is available that is evaluated regularly by the
chief operating decision maker in deciding how to allocate resources and
assess performance. Adoption of the disclosure requirements of SFAS 131 will
affect our presentation.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 24
Financial Statements:
Balance Sheets, December 31, 1997 and 1996 25
Statements of Income for the years ended
December 31, 1997, 1996 and 1995 26
Statements of Cash Flows for the years ended
December 31, 1997, 1996 and 1995 27
Statements of Common Shareowners' Equity for the years ended
December 31, 1997, 1996 and 1995 28
Notes to Financial Statements 29
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, 1997 and 1996, and the related statements of income, cash flows and common
shareowners' equity for each of the three years in the period ended December
31, 1997. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Kansas Gas and Electric
Company as of December 31, 1997 and 1996, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 29, 1998
(March 24, 1998 with
respect to Note 14 of the
Notes to Financial Statements.)
KANSAS GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Dollars in Thousands)
December 31,
1997 1996
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . . $ 43 $ 44
Accounts receivable, net. . . . . . . . . . . . . . . . . 66,654 75,671
Advances to parent company (net). . . . . . . . . . . . . 72,558 250,733
Inventories and supplies, at average cost . . . . . . . . 41,019 43,646
Prepaid expenses and other. . . . . . . . . . . . . . . . 17,165 16,991
Total Current Assets. . . . . . . . . . . . . . . . . . 197,439 387,085
PROPERTY, PLANT AND EQUIPMENT (net) . . . . . . . . . . . . 2,565,175 2,584,632
OTHER ASSETS:
Regulatory assets . . . . . . . . . . . . . . . . . . . . 278,568 286,908
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 75,926 60,262
Total Other Assets. . . . . . . . . . . . . . . . . . . 354,494 347,170
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . . . . . . $3,117,108 $3,318,887
LIABILITIES AND SHAREOWNERS' EQUITY
CURRENT LIABILITIES:
Short-term debt . . . . . . . . . . . . . . . . . . . . . $ 45,000 $ 222,300
Accounts payable. . . . . . . . . . . . . . . . . . . . . 81,986 48,819
Accrued liabilities . . . . . . . . . . . . . . . . . . . 32,745 36,455
Accrued income taxes. . . . . . . . . . . . . . . . . . . 4,212 11,228
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 4,032 3,846
Total Current Liabilities . . . . . . . . . . . . . . . 167,975 322,648
LONG-TERM LIABILITIES:
Long-term debt (net). . . . . . . . . . . . . . . . . . . 684,128 684,068
Deferred income taxes and investment tax credits. . . . . 820,838 823,233
Deferred gain from sale-leaseback . . . . . . . . . . . . 221,779 233,060
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 87,909 73,527
Total Long-term Liabilities . . . . . . . . . . . . . . 1,814,654 1,813,888
COMMITMENTS AND CONTINGENCIES
SHAREOWNERS' EQUITY (See Statements):
Common stock, without par value,
authorized and issued 1,000 shares . . . . . . . . . 1,065,634 1,065,634
Retained earnings . . . . . . . . . . . . . . . . . . . . 68,845 116,717
Total Shareowners' Equity . . . . . . . . . . . . . . . 1,134,479 1,182,351
TOTAL LIABILITIES AND SHAREOWNERS' EQUITY . . . . . . . . . $3,117,108 $3,318,887
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,
1997 1996 1995
SALES . . . . . . . . . . . . . . . . . . . . . . . . . $ 614,445 $ 654,570 $ 624,168
COST OF SALES . . . . . . . . . . . . . . . . . . . . . 129,594 123,269 104,594
GROSS PROFIT. . . . . . . . . . . . . . . . . . . . . . 484,851 531,301 519,574
OPERATING EXPENSES:
Operating and maintenance expense . . . . . . . . . . 180,153 176,113 152,321
Depreciation and amortization . . . . . . . . . . . . 123,423 113,853 97,224
Selling, general and administrative expense . . . . . 57,267 54,374 60,290
Total Operating Expenses. . . . . . . . . . . . . 360,843 344,340 309,835
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . 124,008 186,961 209,739
OTHER INCOME (EXPENSE). . . . . . . . . . . . . . . . . (4,022) 3,633 5,184
INCOME BEFORE INTEREST AND TAXES. . . . . . . . . . . . 119,986 190,594 214,923
INTEREST EXPENSE:
Interest expense on long-term debt. . . . . . . . . . 46,062 46,304 47,073
Interest expense on short-term debt and other . . . . 4,388 11,758 5,190
Total Interest Expense. . . . . . . . . . . . . . 50,450 58,062 52,263
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . 69,536 132,532 162,660
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . 17,408 36,258 51,787
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 52,128 $ 96,274 $ 110,873
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,
1997 1996 1995
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 52,128 $ 96,274 $ 110,873
Depreciation and amortization . . . . . . . . . . . . . . 123,423 113,853 97,224
Amortization of deferred gain from sale-leaseback . . . . (11,281) (9,640) (9,640)
Changes in working capital items:
Accounts receivable, (net). . . . . . . . . . . . . . . 9,017 819 (8,657)
Inventories and supplies. . . . . . . . . . . . . . . . 2,627 5,333 (4,306)
Prepaid expenses and other. . . . . . . . . . . . . . . (174) 138 (467)
Accounts payable. . . . . . . . . . . . . . . . . . . . 33,167 (1,964) 1,690
Accrued liabilities . . . . . . . . . . . . . . . . . . (3,710) 17,744 (11,591)
Accrued income taxes. . . . . . . . . . . . . . . . . . (7,016) 1,555 9,472
Other . . . . . . . . . . . . . . . . . . . . . . . . . 186 (47) (838)
Changes in other assets and liabilities . . . . . . . . . (11,013) 3,641 30,525
Net cash flows from operating activities. . . . . . . 187,354 227,706 214,285
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to property, plant and equipment, (net) . . . . 88,165 68,095 93,699
Net cash flows used in investing activities . . . . . 88,165 68,095 93,699
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . (177,300) 172,300 -
Advances to parent company (net). . . . . . . . . . . . . 178,175 (215,785) 29,445
Retirements of long-term debt . . . . . . . . . . . . . . (65) (16,135) (25)
Dividends to parent company . . . . . . . . . . . . . . . (100,000) (100,000) (150,000)
Net cash flows (used in) financing activities. . . . . (99,190) (159,620) (120,580)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . (1) (9) 6
CASH AND CASH EQUIVALENTS:
Beginning of period . . . . . . . . . . . . . . . . . . . 44 53 47
End of period . . . . . . . . . . . . . . . . . . . . . . $ 43 $ 44 $ 53
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized) . . . . . . . . . . . . . . . . . . . . $ 74,418 $ 78,712 $ 71,808
Income taxes . . . . . . . . . . . . . . . . . . . . . . 52,100 32,100 42,100
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF COMMON SHAREOWNERS' EQUITY
(Dollars in Thousands)
Common Retained
Stock Earnings
BALANCE DECEMBER 31, 1994, 1,000 shares. . . . . . . $1,065,634 $ 159,570
Net Income . . . . . . . . . . . . . . . . . . . . . 110,873
Dividend to parent company . . . . . . . . . . . . . (150,000)
Balance December 30, 1995, 1,000 shares. . . . . . . 1,065,634 120,443
Net Income . . . . . . . . . . . . . . . . . . . . . 96,274
Dividend to parent company . . . . . . . . . . . . . (100,000)
Balance December 31, 1996, 1,000 shares. . . . . . . 1,065,634 116,717
Net Income . . . . . . . . . . . . . . . . . . . . . 52,128
Dividend to parent company . . . . . . . . . . . . . (100,000)
Balance December 31, 1997, 1,000 shares. . . . . . . $1,065,634 $ 68,845
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 280,000 electric customers
in southeastern Kansas. At December 31, 1997, 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 date, 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.
Property, Plant and Equipment: Property, plant and equipment is stated at
cost that includes: contracted services, direct labor and materials, indirect
charges for engineering, supervision, general and administrative costs, and an
allowance for funds used during construction (AFUDC). The AFUDC rate was
5.86% for 1997, 5.71% for 1996, and 6.39% for 1995. The cost of additions and
replacement units of property is capitalized. Maintenance costs and
replacement of minor items of property are charged to expense as incurred.
When units of depreciable property are retired, they are removed from the
plant accounts and the original cost plus removal charges less salvage 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 property, plant and equipment. Accumulated amortization through December
31, 1997 totaled $47.9 million.
Depreciation: Property, plant and equipment is depreciated on the
straight-line method at rates approved by regulatory authorities. Property,
plant and equipment is depreciated on an average annual composite basis using
group rates that approximated 2.76% during 1997, 2.81% during 1996, and 2.72%
during 1995. The company periodically evaluates its depreciation rates
considering the past and expected future experience in the operation of its
facilities.
Fuel Costs: The cost of nuclear fuel in process of refinement,
conversion, enrichment, and fabrication is recorded as an asset at original
cost and is amortized to expense based upon the quantity of heat produced for
the generation of electricity. The accumulated amortization of nuclear fuel
in the reactor at December 31, 1997 and 1996, was $20.9 and $25.3 million,
respectively.
Regulatory Assets and Liabilities: Regulatory assets represent probable
future sales 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 was 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 Consolidated Statements of Income at that time. The
company's earnings would be reduced by the total below, net of applicable
income taxes. Regulatory assets reflected in the consolidated financial
statements at December 31, 1997 are as follows:
December 31, 1997 1996
(Dollars in Thousands)
Recoverable taxes. . . . . . . . . . . . $187,801 $164,520
Debt issuance costs. . . . . . . . . . . 43,045 45,989
Deferred plant costs . . . . . . . . . . 30,979 31,272
Coal contract settlement costs . . . . . 10,035 11,655
Other regulatory assets. . . . . . . . . 6,708 7,155
Phase-in revenues. . . . . . . . . . . . - 26,317
Total regulatory assets . . . . . . . $278,568 $286,908
Recoverable income taxes: Recoverable income taxes represent amounts due
from customers for accelerated tax benefits which have been flowed
through to customers and are expected to be recovered when the
accelerated tax benefits reverse.
Debt issuance costs: Debt reacquisition expenses are amortized over the
remaining term of the reacquired debt or, if refinanced, the term of the
new debt. Debt issuance costs are amortized over the term of the
associated debt.
Deferred 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. The regulatory assets noted above, with the exception of some coal
contract settlement costs and debt issuance costs, other than the refinancing
of the La Cygne 2 lease, are not included in rate base and, therefore, do not
earn a return. Phase-in revenues were fully amortized in 1997.
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.
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.
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 of $21.5 million and $23.5 million are recorded as a component
of accounts receivable (net) on the Balance Sheets as of December 31, 1997 and
1996, respectively.
The company's allowance for doubtful accounts receivable totaled $1.7
million and $1.9 million at December 31, 1997 and 1996, respectively.
New Pronouncements: Effective January 1, 1997, the company adopted the
provisions of Statement of Position (SOP) 96-1, "Environmental Remediation
Liabilities". This statement provides authoritative guidance for recognition,
measurement, display and disclosure of environmental remediation liabilities
in financial statements. Adoption of this statement did not have a material
adverse effect upon the company's overall financial position or results of
operations.
Reclassifications: Certain amounts in prior years have been reclassified
to conform with classifications used in the current year presentation.
2. COMMITMENTS AND CONTINGENCIES
Manufactured Gas Sites: The company has been associated with three
former manufactured gas sites which may contain coal tar and other potentially
harmful materials. The company and the Kansas Department of Health and
Environment (KDHE) entered into a consent agreement governing all future work
at the three sites. The terms of the consent agreement will allow the company
to investigate these sites and set remediation priorities based upon the
results of the investigations and risk analyses. At December 31, 1997, 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.
Decommissioning costs are currently being charged to operating expenses
in accordance with the prior KCC orders. Electric rates charged to customers
provide for recovery of these decommissioning costs over the life of Wolf
Creek. Amounts expensed approximated $3.7 million in 1997 and will increase
annually to $5.6 million in 2024. These expenses are deposited in an external
trust fund. The average after tax expected return on trust assets is 5.7%.
The company's investment in the decommissioning fund, including
reinvested earnings approximated $43.5 million and $33.0 million at December
31, 1997 and December 31, 1996, respectively. Trust fund earnings accumulate
in the fund balance and increase the recorded decommissioning liability.
The SEC staff has questioned the way electric utilities recognize,
measure and classify decommissioning costs for nuclear electric generating
stations in their financial statements. In response to the SEC's questions,
the Financial Accounting Standards Board is reviewing the accounting for
closure and removal costs, including decommissioning of nuclear power plants.
If current accounting practices for nuclear power plant decommissioning are
changed, the following could occur:
- The company's annual decommissioning expense could be higher than in
1997
- The estimated cost for decommissioning could be recorded as a
liability (rather than as accumulated depreciation)
- The increased costs could be recorded as additional investment
in the Wolf Creek plant
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 company carries premature decommissioning
insurance which has several restrictions. One of these is that it can only be
used if Wolf Creek incurs an accident exceeding $500 million in expenses to
safely stabilize the reactor, to decontaminate the reactor and reactor station
site in accordance with a plan approved by the Nuclear Regulatory Commission
(NRC) and to pay for on-site property damages. This decommissioning insurance
will only be available if the insurance funds are not needed to implement the
NRC-approved plan for stabilization and decontamination.
The Price-Anderson Act limits the combined public liability of the owners
of nuclear power plants to $8.9 billion for a single nuclear incident. If
this liability limitation is insufficient, the U.S. Congress will consider
taking whatever action is necessary to compensate the public for valid claims.
The Wolf Creek owners (owners) have purchased the maximum available private
insurance of $200 million. The remaining balance is provided by an assessment
plan mandated by the NRC. Under this plan, the owners are jointly and
severally subject to a retrospective assessment of up to $79.3 million ($37.3
million, company's share) in the event there is a major nuclear incident
involving any of the nation's licensed reactors. This assessment is subject
to an inflation adjustment based on the Consumer Price Index and applicable
premium taxes. There is a limitation of $10 million ($4.7 million, company's
share) in retrospective assessments per incident, per year.
The owners carry decontamination liability, premature decommissioning
liability and property damage insurance for Wolf Creek totaling approximately
$2.8 billion ($1.3 billion, company's share). This insurance is provided by
Nuclear Electric Insurance Limited (NEIL). In the event of an accident,
insurance proceeds must first be used for reactor stabilization and site
decontamination. The company's share of any remaining proceeds can be used
for property damage or premature decommissioning costs. Premature
decommissioning coverage applies only if an accident at WCNOC exceeds $500
million in property damage and decommissioning expenses and only after trust
funds have been exhausted.
The owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If losses incurred
at any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves and other NEIL resources, the company may be subject to retrospective
assessments under the current policies of approximately $9 million per year.
Although the company maintains various insurance policies to provide
coverage for potential losses and liabilities resulting from an accident or an
extended outage, the company's insurance coverage may not be adequate to cover
the costs that could result from a catastrophic accident or extended outage at
Wolf Creek. Any substantial losses not covered by insurance, to the extent
not recoverable through rates, would have a material adverse effect on the
company's financial condition and results of operations.
Fuel Commitments: To supply a portion of the fuel requirements for its
generating plants, the company has entered into various commitments to obtain
nuclear fuel and coal. Some of these contracts contain provisions for price
escalation and minimum purchase commitments. At December 31, 1997, WCNOC's
nuclear fuel commitments (company's share) were approximately $9.9 million for
uranium concentrates expiring at various times through 2001, $35.1 million for
enrichment expiring at various times through 2003 and $67.4 million for
fabrication through 2025.
At December 31, 1997, the company's coal contract commitments in 1997
dollars under the remaining terms of the contracts were approximately $587.5
million. The largest coal contract expires in 2020, with the remaining coal
contracts expiring at various times through 2013.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment
is being collected from utilities for a uranium enrichment decontamination and
decommissioning fund. The company's portion of the assessment for Wolf Creek
is approximately $7 million, payable over 15 years. Management expects such
costs to be recovered through the ratemaking process.
3. RATE MATTERS AND REGULATION
KCC Rate Proceedings: In January 1997, the KCC approved an agreement
that reduced electric rates for the company. Significant terms of the
agreement are as follows:
- The company made permanent an interim $8.7 million rate reduction
implemented in May 1996. This reduction was effective February
1, 1997.
- The company reduced annual rates by $36 million effective February
1, 1997.
- The company rebated $2.3 million to its customers in January 1998.
- The company will reduce annual rates by an additional $10 million
on June 1, 1998.
- The company will rebate an additional $2.3 million to its
customers in January 1999.
- The company will reduce annual rates by an additional $10 million
on June 1, 1999.
All rate decreases are cumulative. Rebates are one-time events and do
not influence future rates.
4. SHORT-TERM BORROWINGS
The company has arrangements with certain banks to provide unsecured
short-term lines of credit on a committed basis totaling $100 million. The
agreements provide the company with the ability to borrow at different
market-based interest rates. The company pays commitment or facility fees in
support of these lines of credit. Under the terms of the agreements, the
company is required, among other restrictions, to maintain a total debt to
total capitalization ratio of not greater than 65% at all times. The unused
portion of these lines of credit are used to provide support for commercial
paper.
Information regarding the company's short-term borrowings, comprised of
borrowings under the credit agreements and bank loans, is as follows:
Year ended December 31, 1997 1996 1995
(Dollars in Thousands)
Borrowings outstanding at year end:
Lines of credit $ - $200,000 $ -
Bank loans 45,000 22,300 50,000
Total $ 45,000 $222,300 $ 50,000
Weighted average interest rate on
debt outstanding at year end
(including fees) 6.44% 5.93% 6.03%
Weighted average short-term debt
outstanding during the year $ 22,945 $147,556 $ 32,296
Weighted daily average interest
rates during the year
(including fees) 6.46% 5.83% 6.10%
5. 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. No bonds will mature during 1998.
Long-term debt outstanding is as follows at December 31:
1997 1996
(Dollars in Thousands)
First mortgage bond series:
7.6% due 2003. . . . . . . . . . $ 135,000 $ 135,000
6-1/2% due 2005. . . . . . . . . 65,000 65,000
6.20% due 2006 . . . . . . . . . 100,000 100,000
300,000 300,000
Pollution control bond series:
5.10% due 2023 . . . . . . . . . 13,757 13,822
Variable due 2027 (1). . . . . . 21,940 21,940
7.0% due 2031. . . . . . . . . . 327,500 327,500
Variable due 2032 (2). . . . . . 14,500 14,500
Variable due 2032 (3). . . . . . 10,000 10,000
387,697 387,762
Less:
Unamortized discount . . . . . . 3,569 3,694
Long-term debt (net) . . . . . . . . $ 684,128 $ 684,068
6. SALE-LEASEBACK OF LA CYGNE 2
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, 1997, approximately $21.4
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 and
$576.6 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 ($9.7 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 $27.3 million for 1997 and $22.5 million
for 1996 and 1995.
In addition the company has future minimum annual lease payments of
approximately $970,000 for each year through 2002 and $3.9 million over the
remainder of the lease.
7. INCOME TAXES
Income tax expense is composed of the following components at December
31:
1997 1996 1995
(Dollars in Thousands)
Currently Payable:
Federal. . . . . . . . . $ 34,641 $ 31,135 $ 34,661
State. . . . . . . . . . 7,982 11,948 13,275
Deferred:
Federal. . . . . . . . . (18,503) (218) 9,528
State. . . . . . . . . . (3,467) (3,358) (2,363)
Amortization of Investment
Tax Credits . . . . . . . (3,245) (3,249) (3,314)
Total Income Tax Expense . $ 17,408 $ 36,258 $ 51,787
Temporary differences gave rise to deferred tax assets and deferred tax
liabilities at December 31, 1997 and 1996, respectively, as follows:
1997 1996
(Dollars in Thousands)
Deferred Tax Assets:
Deferred gain on sale-leaseback. . . . . $ 97,634 $ 99,466
Other. . . . . . . . . . . . . . . . . . 43,330 11,496
Total Deferred Tax Assets. . . . . . . 140,964 110,962
Deferred Tax Liabilities:
Accelerated depreciation & other . . . . 386,382 363,647
Acquisition premium. . . . . . . . . . . 298,582 306,662
Deferred future income taxes . . . . . . 187,801 164,520
Other. . . . . . . . . . . . . . . . . . 22,561 29,644
Total Deferred Tax Liabilities . . . . 895,326 864,473
Investment tax credits . . . . . . . . . . 66,476 69,722
Accumulated Deferred Income Taxes, Net . . $ 820,838 $ 823,233
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, 1997 1996 1995
(Dollars in Thousands)
Effective Income Tax Rate 25% 27% 32%
Effect of:
State income taxes (4) (4) (4)
Amortization of investment tax credits 5 2 2
Corporate-owned life insurance policies 12 7 5
Accelerated depreciation flow through
and amortization, net (4) 2 -
Other 1 1 -
Statutory Federal Income Tax Rate 35% 35% 35%
8. 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 dispositions of these matters will not
have a material adverse effect upon the company's overall financial position
or results of operations.
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, 1997 and 1996. 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, 1997 and 1996. These fair value estimates have not
been comprehensively revalued for the purpose of these financial statements
since that date and current estimates of fair value may differ significantly
from the amounts presented herein. Because the company's operations are
regulated, the company believes that any gains or losses related to the
retirement of debt or redemption of preferred securities would not have a
material effect on the company's financial position or results of operations.
The carrying values and estimated fair values of the company's financial
instruments are as follows:
Carrying Value Fair Value
December 31, 1997 1996 1997 1996
(Dollars in Thousands)
Decommissioning trust. . . $ 43,514 $ 33,041 $ 43,514 $ 33,041
Fixed-rate debt. . . . . . 641,257 641,322 660,266 665,300
10. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December
31:
1997 1996
(Dollars in Thousands)
Electric plant in service $3,545,942 $3,487,213
Less - Accumulated depreciation 1,051,107 974,451
2,494,835 2,512,762
Construction work in progress 29,432 33,197
Nuclear fuel (net) 40,696 38,461
Net Utility Plant 2,564,963 2,584,420
Non-utility plant in service 212 212
Net Plant $2,565,175 $2,584,632
The carrying value of long-lived assets, including intangibles are
reviewed for impairment whenever events or changes in circumstances indicate
they may not be recoverable.
11. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1997
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 162,400 $ 109,481 343 50
Jeffrey 1 (b) Jul 1978 69,651 30,691 147 20
Jeffrey 2 (b) May 1980 67,899 29,859 147 20
Jeffrey 3 (b) May 1983 100,368 39,560 144 20
Wolf Creek (c) Sep 1985 1,380,660 399,551 547 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%)
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 334 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.
12. 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.
1997
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
(Dollars in Thousands)
Sales . . . . . . . . . . . $143,791 $148,826 $191,066 $130,762
Income from Operations. . . 30,364 32,421 66,724 (5,501)
Net income. . . . . . . . . 11,172 15,492 31,775 (6,311)
1996
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
(Dollars in Thousands)
Sales . . . . . . . . . . . $145,034 $163,038 $193,198 $153,300
Income from Operations. . . 33,593 39,112 72,369 41,887
Net income. . . . . . . . . 15,700 17,253 40,736 22,585
13. 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 $73
million and $251 million at December 31, 1997 and 1996, respectively. 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 allocators. Management believes such allocation
procedures are reasonable. During 1997, the company declared dividends to
Western Resources of $100 million.
14. WESTERN RESOURCES AND KANSAS CITY POWER & LIGHT COMPANY MERGER AGREEMENT
On February 7, 1997, the Western Resources signed a merger agreement with
KCPL by which KCPL would be merged with and into Western Resources in exchange
for Western Resources common stock. In December 1997, representatives of the
Western Resources' financial advisor indicated that they believed it was
unlikely that they would be in a position to issue a fairness opinion required
for the merger on the basis of the previously announced terms.
On March 18, 1998, Western Resources and KCPL announced a restructuring
of their February 7, 1997, merger agreement which will result in the formation
of Westar Energy, a new electric company. Under the terms of the merger
agreement, the electric utility operations of Western Resources will be
transferred to the company, and KCPL and the company will be merged into NKC,
Inc., a subsidiary of Western Resources. NKC, Inc. will be renamed Westar
Energy. In addition, under the merger agreement, KCPL shareowners will
receive $23.50 of Western Resources common stock per KCPL share, subject to a
collar mechanism, and one share of Westar Energy common stock per KCPL share.
Upon consummation of the combination, Western Resources will own approximately
80.1% of the outstanding equity of Westar Energy and KCPL shareowners will own
approximately 19.9%. As part of the combination Westar Energy will assume all
of the electric utility related assets and liabilities of Western Resources,
KCPL, and the company.
Westar Energy will assume $2.7 billion in debt, consisting of $1.9
billion of indebtedness for borrowed money of Western Resources and the
company, and $800 million of debt of KCPL. Long-term debt of Western
Resources and the company was $2.1 billion at December 31, 1997. Under the
terms of the merger agreement, it is intended that the company will be
released from its obligations with respect to the company's debt to be assumed
by Westar Energy. For additional information concerning the company's long-
term debt and obligations under the La Cygne sale leaseback arrangements see
Note 5 and Note 6.
Consummation of the merger is subject to customary conditions including
obtaining the approval of Western Resources' and KCPL's shareowners and
various regulatory agencies. Western Resources estimates the transaction to
close by mid-1999, subject to receipt of all necessary approvals.
KCPL is a public utility company engaged in the generation, transmission,
distribution, and sale of electricity to customers in western Missouri and
eastern Kansas. We, KCPL and KGE have joint interests in certain electric
generating assets, including Wolf Creek. Following the closing of the
combination Westar Energy is expected to have approximately one million
electric utility customers in Kansas and Missouri, approximately $8.2 billion
in assets and the ability to generate more than 8,000 megawatts of
electricity. For additional information, see "Financing in Item 1. Business",
"Management's Discussion and Analysis of Financial Condition and Results of
Operations".
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 1993 and Other Continuously
Name Age Directorships Other Than The Company Since
William B. 45 Chairman of the Board and President 1995
Moore (since June 1995), and prior to that
Vice President, Finance,
Western Resources, Inc.
Directorships
Intrust Bank
Anderson E. 64 President, Jackson Mortuary, 1994
Jackson Wichita, Kansas
Directorships
The National Business League
Donald A. 64 Retired President and Chairman (Emeritus), 1992
Johnston Maupintour, Inc., Lawrence, Kansas,
(1)(2) Consultant - Commerce Bank, Lawrence,
Kansas (since July 1996)
Directorships
Commerce Bank, Lawrence, Kansas
James A. 40 Vice President, Finance (since July 1995) 1997
Martin and Treasurer (since Nov. 1997), and prior
to that Executive Director Regulatory and
Rates (since Dec. 1994), and prior to that
Director Revenue and Forecasting
Western Resources, Inc.
Marilyn B. 48 President Wichita, NationsBank N.A. 1994
Pauly Wichita, Kansas (since
(1) October 1993) and prior to that
Executive Vice President, Bank IV, N.A.,
Wichita, Kansas
Directorships
Farmers Mutual Alliance Insurance Company
Bank IV Community Development Corporation
Richard D. 64 President, Range Oil Company 1993
Smith Directorships
NationsBank N.A. (Midwest), (Advisory)
HCA Wesley Medical Center,
Wichita, Kansas
(1) Member of the Audit Committee of which Mr. Johnston is Chairman.
The Audit Committee has responsibility for the investigation and
review of the financial affairs of the Company and its relations
with independent accountants.
(2) Mr. Johnston was a director of the former Kansas Gas and Electric
Company since 1980.
Outside Directors are paid $3,750 per quarter retainer and are paid an
attendance fee of $600 for Directors' meetings ($300 if attending by phone).
A committee attendance fee of $800 is paid to the outside Director Audit
Committee Chairman, and $500 to other outside Committee members. All outside
Directors are reimbursed mileage and expenses while attending Directors' and
Committee Meetings.
During 1997, the Board of Directors met five 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 J(2)(c) to Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General
Instruction J(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 J(2)(c) to Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Item 13 is omitted pursuant to General
Instruction J(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, 1997 and 1996
Statements of Income for the years ended December 31, 1997, 1996 and 1995
Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995
Statements of Common Shareowners' Equity for the years ended December 31,
1997, 1996, and 1995
Notes to Financial Statements
REPORTS ON FORM 8-K
None
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
2(a) Amended and Restated Agreement and Plan of Merger
dated March 18, 1998 (Filed electronically)
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 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; Exhibit 2(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
Description
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 September I
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 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 30, 1998 By /s/ William B. Moore
William B. Moore,
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/ WILLIAM B. MOORE Chairman of the Board and
(William B. Moore) President (Principal Executive March 30, 1998
Officer)
Secretary, Treasurer and General
/s/ RICHARD D. TERRILL Counsel (Principal Financial March 30, 1998
(Richard D. Terrill) and Accounting Officer)
/s/ ANDERSON E. JACKSON
(Anderson E. Jackson)
/s/ DONALD A. JOHNSTON
(Donald A. Johnston)
/s/ JAMES A. MARTIN Directors March 30, 1998
(James A. Martin)
/s/ MARILYN B. PAULY
(Marilyn B. Pauly)
/s/ RICHARD D. SMITH
(Richard D. Smith)