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1
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, 1996
[ ] 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 27, 1997)
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.
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KANSAS GAS AND ELECTRIC COMPANY
FORM 10-K
December 31, 1996
TABLE OF CONTENTS
Description Page
PART I
Item 1. Business 3
Item 2. Properties 11
Item 3. Legal Proceedings 12
Item 4. Submission of Matters to a Vote of
Security Holders 12
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 12
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations 13
Item 8. Financial Statements and Supplementary Data 20
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 41
PART III
Item 10. Directors and Executive Officers of the
Registrant 42
Item 11. Executive Compensation 43
Item 12. Security Ownership of Certain Beneficial
Owners and Management 43
Item 13. Certain Relationships and Related Transactions 43
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 44
Signatures 47
3 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 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, 1996, the Company had no employees. All employees are provided
by the Company's parent, Western Resources.
On March 31, 1992, Western Resources, Inc. (Western Resources) through its
wholly-owned subsidiary KCA Corporation (KCA), acquired all of the outstanding
common and preferred stock of Kansas Gas and Electric Company (KGE) (the
Merger). Simultaneously, KCA and Kansas Gas and Electric Company merged and
adopted the name Kansas Gas and Electric Company (the Company, KGE).
The electric utility industry in the United States is rapidly evolving
from an historically regulated monopolistic market to a dynamic and
competitive integrated marketplace. The 1992 Energy Policy Act (Act) began
the process of deregulation of the electricity industry by permitting the
Federal Energy Regulatory Commission (FERC) to order electric utilities to
allow third parties to sell electric power to wholesale customers over their
transmission systems. Since that time, the wholesale electricity market has
become increasingly competitive as companies begin to engage in nationwide
power brokerage. In addition, various states including California and New
York have taken active steps toward allowing retail customers to purchase
electric power from third-party providers. In 1996, the Kansas Corporation
Commission (KCC) initiated a generic docket to study electric restructuring
issues. A retail wheeling task force has been created by the Kansas
Legislature to study competitive trends in retail electric services. During
the 1997 session of the Kansas Legislature, bills have been introduced to
increase competition in the electric industry. Among the matters under
consideration is the recovery by utilities of costs in excess of competitive
cost levels. There can be no assurance at this time that such costs will be
recoverable if open competition is initiated in the electric utility market.
For 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, Other Information,
Competition and Enhanced Business Opportunities included herein.
Discussion of other factors affecting the company are set forth in the
Notes to Financial Statements and Management's Discussion and Analysis
included herein.
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ELECTRIC OPERATIONS
General
The company supplies electric energy at retail to approximately 277,000
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 for the last five years were as follows:
1996 1995 1994 1993 1992
(Thousands of MWH)
Residential 2,503 2,385 2,384 2,386 2,102
Commercial 2,186 2,095 2,068 1,991 1,892
Industrial 3,501 3,542 3,371 3,323 3,248
Wholesale and
Interchange 2,706 1,292 1,590 2,004 1,267
Other 45 45 45 45 46
Total 10,941 9,359 9,458 9,749 8,555
The company's electric revenues for the last five years were as follows:
1996 1995 1994 1993 1992
(Dollars in Thousands)
Residential $226,456 $221,628 $220,067 $219,069 $194,142
Commercial 176,963 171,654 167,499 162,858 154,005
Industrial 175,420 182,930 181,119 179,256 174,226
Wholesale and
Interchange 57,242 31,143 38,750 45,843 28,086
Other 18,489 16,513 12,445 9,971 6,792
Total $654,570 $623,868 $619,880 $616,997 $557,251
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 1996 peak system net load occurred on July 19, 1996 and
amounted to 1,853 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.
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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 60 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 156 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 4 years. The company
continues to market this capacity and energy to other utilities.
Fuel Mix
The company's coal-fired units comprise 1,113 MW of the total 2,530 MW of
generating capacity and the company's nuclear unit provides 547 MW of
capacity. Of the remaining 870 MW of generating capacity, units that can burn
either natural gas or oil account for 867 MW, and the remaining unit which
burns only diesel fuel accounts for 3 MW (See Item 2. Properties).
During 1996, low sulfur coal was used to produce 62% of the company's
electricity. Nuclear produced 32% and the remainder was produced from natural
gas, oil, or diesel fuel. During 1997, based on the company's estimate of the
availability of fuel, coal will to be used to produce approximately 60% of the
company's electricity and nuclear will be used to produce 32%.
The company's fuel mix fluctuates with the operation of nuclear powered
Wolf Creek which has an 18-month refueling and maintenance schedule. The 18
- -month schedule permits uninterrupted operation every third calendar year.
Wolf Creek was taken off-line on February 3, 1996 for its eighth refueling and
maintenance outage. The outage lasted approximately 60 days during which time
electric demand was met primarily by the company's coal-fired generating
units.
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Nuclear
The owners of Wolf Creek have on hand or under contract 70% of the uranium
requirements for operation of Wolf Creek through September 2003. The balance
is expected to be obtained through spot market and term contract purchases.
The company has four contracts with the following companies for uranium:
Cameco Corporation, Geomex Minerals, Inc., and Power Resources, Inc.
A contractual arrangement is in place with Cameco Corporation for the
conversion of uranium to uranium hexafluoride sufficient for the operation of
Wolf Creek through the year 2001.
The company has two active contracts for uranium enrichment performed by
Urenco and USEC. Contracted arrangements cover 82% 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 decision not to contract for the full enrichment requirements
is one of cost rather than availability of service.
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.
The Nuclear Waste Policy Act of 1982 established schedules, guidelines and
responsibilities for the Department of Energy (DOE) to develop and construct
repositories for the ultimate disposal of spent fuel and high-level waste.
The DOE has not yet constructed a high-level waste disposal site and has
announced that a permanent storage facility may not be in operation prior to
2010 although an interim storage facility may be available earlier. Wolf
Creek contains an onsite spent fuel storage facility which, under current
regulatory guidelines, provides space for the storage of spent fuel through
2005 while still maintaining full core off-load capability. The Company is
currently investigating spent fuel storage options which should provide enough
additional storage space through at least 2020 while still maintaining full
core off-load capability. The company believes adequate additional storage
space can be obtained as necessary.
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 428 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 $1.10 per MMBtu or $18.70 per
ton during 1996.
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Coal is transported by Western Resources from Wyoming under a long-term
rail transportation contract with Burlington Northern (BN) and Union Pacific
(UP) 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 678 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 or
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 BN and Kansas City Southern Railroad (KCS) through December 31,
2000.
During 1996, the average delivered cost of all local and Powder River
Basin coal procured for La Cygne 1 was approximately $0.64 per MMBtu or $13.47
per ton and the average delivered cost of Powder River Basin coal for La Cygne
2 was approximately $0.68 per MMBtu or $11.49 per ton.
The company has entered into all of its coal and transportation contracts
during the ordinary course of business and is not substantially dependent upon
these contracts. The company believes there are other supplies for and
plentiful sources of coal available at reasonable prices to replace, if
necessary, fuel to be supplied pursuant to these contracts. In the event that
the company were required to replace its coal or transportation agreements, it
would not anticipate a substantial disruption of the company's business.
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, 1996, the company had approximately 792 thousand
gallons of No. 2 oil and 9.8 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.
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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.
1996 1995 1994 1993 1992
Per Million Btu:
Nuclear $0.50 $0.40 $0.36 $0.35 $0.34
Coal 0.88 0.91 0.90 0.96 1.25
Gas 2.30 1.68 1.98 2.37 1.95
Oil 2.74 4.00 3.90 3.15 4.28
Cents per KWH Generation 0.93 0.82 0.89 0.93 0.98
Environmental Matters
The company currently holds all Federal and State environmental approvals
required for the operation of its generating units. The company believes it
is presently in substantial compliance with all air quality regulations
(including those pertaining to particulate matter, sulfur dioxide and nitrogen
oxides (NOx)) promulgated by the State of Kansas and the Environmental
Protection Agency (EPA).
The Federal sulfur dioxide standards applicable to the company's JEC and
La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur
dioxide per million Btu of heat input. Federal particulate matter emission
standards applicable to these units prohibit: (1) the emission of more than
0.1 pounds of particulate matter per million Btu of heat input and (2) an
opacity greater than 20%. Federal NOx emission standards applicable to these
units prohibit the emission of more than 0.7 pounds of NOx per million Btu of
heat input.
The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards
through the use of low sulfur coal (See Coal); (2) the particulate matter
standards through the use of electrostatic precipitators; and (3) the NOx
standards through boiler design and operating procedures. The JEC units are
also equipped with flue gas scrubbers providing additional sulfur dioxide and
particulate matter emission reduction capability when needed to meet permit
limits.
The Kansas Department of Health and Environment (KDHE) regulations,
applicable to the company's other generating facilities, prohibit the emission
of more than 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.
9
The Clean Air Act Amendments of 1990 (the Act) require a two-phase
reduction in sulfur dioxide and NOx emissions with Phase I effective in 1995
and Phase II effective in 2000 and a probable reduction in toxic emissions by
a future date not yet determined. To meet the monitoring and reporting
requirements under the Act's acid rain program, the company has installed
continuous monitoring and reporting equipment at a total cost of approximately
$2.3 million as of December 31, 1996. The company does not expect material
expenditures to be needed to meet Phase II sulfur dioxide requirements.
Although the company currently has no Phase I affected units, the company has
applied for and has been accepted for an early substitution permit to bring
the co-owned La Cygne Unit 1 under the Phase I regulations.
The NOx and toxic limits, which were not set in the law, were proposed by
the EPA in January 1996. The company is currently evaluating the steps it
would need to take in order to comply with the proposed new rules. The
company will have three years from the date the limits were proposed to comply
with the new NOx rules.
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, 1996,
approximately $1.0 billion principal amount of additional first mortgage bonds
could be issued (7.75% 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,
1996, 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 $950 million principal amount of additional bonds. As of December 31,
1996, $17 million in additional bonds could be issued on the basis of retired
bonds.
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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.
EXECUTIVE OFFICERS OF THE COMPANY
Other Offices or Positions
Name Age Present Office Held During Past Five Years
William B. Moore 44 Chairman of the Board Vice President, Finance -
and President (since Western Resources, Inc.
June 1995)
Richard D. Terrill 42 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.
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ITEM 2. PROPERTIES
The company owns or leases and operates an electric generation,
transmission, and distribution system in Kansas.
During the five years ended December 31, 1996, the company's gross
property additions totaled $383,081,000 and retirements were $135,730,000.
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 141
La Cygne Station (50%) (2):
Steam Turbines 1 1973 Coal 343
2 1977 Coal 335
Murray Gill Energy Center:
Steam Turbines 1 1952 Gas--Oil 46
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%).
(3) This unit has been "mothballed" for future use.
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ITEM 3. LEGAL PROCEEDINGS
Information on legal proceedings involving the company is set forth in
Notes 2, 3, and 9 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.
ITEM 6. SELECTED FINANCIAL DATA
1996 1995 1994 1993 1992
(Dollars in Thousands)
Income Statement Data:
Operating revenues . . . . . . . $ 654,570 $ 623,868 $ 619,880 $ 616,997 $ 554,251
Operating expenses . . . . . . . 513,579 477,541 470,869 469,616 424,089
Operating income . . . . . . . . 140,991 146,327 149,011 147,381 130,162
Net income . . . . . . . . . . . 96,274 110,873 104,526 108,103 77,981
Balance Sheet Data:
Gross electric plant in service. $3,574,980 $3,427,928 $3,390,406 $3,339,832 $3,293,365
Construction work in progress. . 33,197 40,810 32,874 28,436 29,634
Total assets . . . . . . . . . . 3,318,887 3,203,414 3,237,684 3,187,479 3,279,232
Long-term debt . . . . . . . . . 684,068 684,082 699,992 653,543 871,652
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 3.28 4.11 4.02 3.58 2.35
Ratio of Earnings to Fixed Charges 2.19 2.58 2.61 2.60 1.89
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION
GENERAL: The company had net income of $96.3 million for 1996 compared to
net income of $110.9 million in 1995. The decrease in net income is primarily
due to the amortization of the acquisition adjustment as a result of the
Merger and the $8.7 million rate reduction implemented on an interim basis on
May 23, 1996, and made permanent on January 15, 1997. Abnormally cool summer
weather during the third quarter of 1996 compared to 1995 also adversely
affected earnings.
FORWARD LOOKING INFORMATION: Certain matters discussed in this Form 10-K
are "forward-looking statements" intended to qualify for the safe harbors from
liability established by the Private Securities Litigation Reform Act of 1995.
Such statements address future plans, objectives, expectations and events or
conditions concerning various matters such as capital expenditures, earnings,
litigation, rate and other regulatory matters, pending transactions,
liquidity and capital resources, and accounting matters. Actual results in
each case could differ materially from those currently anticipated in such
statements, by reason of factors such as electric utility restructuring,
including ongoing state and federal activities; future economic conditions;
legislation; regulation; competition; and other circumstances affecting
anticipated rates, revenues and costs.
LIQUIDITY AND CAPITAL RESOURCES: The company's liquidity is a function of
its ongoing construction and maintenance program designed to improve
facilities which provide electric service and meet future customer service
requirements.
During 1996, construction expenditures for the company's electric system
were approximately $66 million and nuclear fuel expenditures were
approximately $3 million. It is projected that adequate capacity margins will
be maintained without the addition of any major generating facilities for the
next five years. The construction program is focused on providing service to
new customers and improving present electric facilities.
Capital expenditures for 1997 through 1999 are anticipated to be as
follows:
Electric Nuclear Fuel
(Dollars in Thousands)
1997. . . . . . . . . . $55,116 $21,300
1998. . . . . . . . . . 56,761 21,500
1999. . . . . . . . . . 58,471 3,800
These expenditures are estimates prepared for planning purposes and are
subject to revisions.
Cash provided by operating activities is the primary source for meeting
cash requirements. The company anticipates all of its cash requirements for
capital expenditures through 1999 will be provided from internally generated
funds.
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The embedded cost of long-term debt excluding the revolving credit
facility was 7.3% at December 31, 1996 and 1995.
In 1986, the company purchased corporate-owned life insurance policies
(COLI) on certain employees. The annual cash outflow for the premiums on
these policies was approximately $26 million for 1996, $30 million for 1995
and $26 million for 1994. During 1996, the company increased its borrowings
against the accumulated cash surrender values of the policies by $46 million.
Total 1996 COLI borrowings amounted to $394 million. The borrowings are
expected to produce annual cash inflows, net of expenses, through the
remaining life of the policies. Borrowings against the policies will be
repaid from death proceeds.
On August 2, 1996, Congress passed legislation that will phase out tax
benefits associated with certain COLI policies. The legislation had minimal
impact on the company's COLI policies as all policies entered into prior to
July 1, 1986 were grandfathered under the legislation. See Note 1 for
additional information on COLI.
The company's short-term financing requirements are satisfied, as needed,
through short-term bank loans and borrowings under other lines of credit
maintained with banks. Short-term borrowings amounted to $222.3 million at
December 31, 1996 and $50 million at December 31. 1995.
The company's capital structure at December 31, 1996 and 1995, was 63%
common stock equity and 37% long-term debt.
RESULTS OF OPERATIONS
The following is an explanation of significant variations from prior year
results in revenues, operating expenses, other income and deductions, and
interest charges. Additional information relating to changes between years is
provided in the Notes to Financial Statements.
REVENUES
The operating revenues of the company 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. Future electric sales will be affected by weather
conditions, the electric rate reduction which was implemented on February 1,
1997, changes in the industry, changes in the regulatory environment,
competition from other sources of energy, competing fuel sources, customer
conservation efforts, and the overall economy of the company's service area.
Electric fuel costs are included in base rates. Therefore, if the
company wished to recover an increase in fuel costs, it would have to file a
request for recovery in a rate filing with the KCC which could be denied in
whole or in part. The company's fuel costs represented 24% and 22% of its
total operating expenses for the years ended December 31, 1996 and 1995,
respectively. Any increase in fuel costs from the projected average which the
company did not recover through rates would reduce the company's earnings.
The degree of any such impact would be affected by a variety of factors,
however, and thus cannot be predicted.
15
1996 Compared to 1995: Total operating revenues for 1996 of $654.6
million increased five percent from 1995 operating revenues of $623.9 million
primarily due to higher wholesale and interchange sales 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 experienced during the first six months of 1996 compared to 1995.
The company's service territory experienced a 17% increase in heating degree
days during the first quarter and cooling degree days more than doubled during
the second quarter of 1996 compared to the same periods in 1995. Partially
offsetting this increase was abnormally cool summer weather during the third
quarter of 1996 compared to 1995 and the $8.7 million electric rate reduction
implemented on an interim basis on May 23, 1996 and made permanent on January
15, 1997. For more information related to electric rate decreases, see Note
3.
1995 Compared to 1994: Total operating revenues for 1995 of $623.9
million increased less than one percent from revenues of $619.9 million for
1994 as a result of increased sales in all retail customer classes. The
increase is primarily attributable to a higher demand for air conditioning
load during the third quarter of 1995 compared to 1994. The company's service
territory experienced a 14% increase in the number of cooling degree days
during that quarter, as compared to the third quarter of 1994.
OPERATING EXPENSES
1996 Compared to 1995: Total operating expenses for 1996 were $513.6
million compared to $477.5 million for 1995, an increase of over seven
percent. The increase is primarily due to a full year of amortization of the
acquisition adjustment related to the Merger and increased fuel expense,
purchased power, and natural gas purchases for electric generating stations
due to Wolf Creek having been taken off-line for its eighth refueling and
maintenance outage during the first quarter of 1996. Also contributing to the
increases in fuel and purchased power expenses was the increase in net
generation due to increased interchange sales.
1995 Compared to 1994: Total operating expenses for 1995 were $477.5
million compared to $470.9 million for 1994, an increase of over one percent.
The increase is a result of increased depreciation and amortization expense as
a result of the amortization of the acquisition premium attributable to the
Merger which began in August 1995 as discussed in Merger Implementation below.
OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of taxes,
decreased for the twelve months ended December 31, 1996 compared to 1995
primarily as a result of the gain from the sale of utility plant recorded in
the first quarter of 1995.
Other income and deductions, net of taxes, increased for the twelve months
ended December 31, 1995 compared to 1994 as a result of the additional
interest expense on increased corporate-owned life insurance (COLI)
borrowings. Partially offsetting this increase was the recognition of income
from death benefit proceeds under COLI contracts during the fourth quarter of
1995.
INTEREST CHARGES: Total interest charges increased 14% for the twelve
months ended December 31, 1996 as compared to 1995 due to increased interest
expense on higher short-term debt balances. Interest charges decreased 4% in
1995 compared to 1994 due to an increased AFUDC credit in 1995 compared to
1994 and decreased interest charges on long-term debt.
16
MERGER IMPLEMENTATION: In accordance with the KCC merger order,
amortization of the acquisition adjustment commenced August 1995. The
amortization will amount to approximately $20 million (pre-tax) per year for
40 years. Western Resources and the company (combined companies) are
recovering the amortization of the acquisition adjustment through cost savings
under a sharing mechanism approved by the KCC.
16
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
INFLATION: Under the ratemaking procedures prescribed by the regulatory
commissions to which the company is subject, only the original cost of plant
is recoverable in rates charged to customers. Therefore, because of
inflation, present and future depreciation provisions are inadequate for
purposes of maintaining the purchasing power invested by common shareholders
and the related cash flows are inadequate for replacing property. The impact
of this ratemaking process on common shareholders is mitigated to the extent
depreciable property is financed with debt that can be repaid with dollars of
less purchasing power. While the company has experienced relatively low
inflation in the recent past, the cumulative effect of inflation on operating
costs may require the company to seek regulatory rate relief to recover these
higher costs.
ENVIRONMENTAL: The company has taken a proactive position with respect to
the potential environmental liability associated with former manufactured gas
sites and has an agreement with the Kansas Department of Health and
Environment to systematically evaluate these sites in Kansas.
The company is one of numerous potentially responsible parties at a
groundwater contamination site in Wichita, Kansas which is listed by the
Environmental Protection Agency (EPA) as a Superfund site.
The nitrogen oxides (NOx) and toxic limits, which were not set in the law,
were proposed by the EPA in January 1996. The company is currently evaluating
the steps it will need to take in order to comply with the proposed new rules.
The company will have three years from the date the limits were proposed to
comply with the new NOx rules. See Note 2 for more information regarding
environmental matters.
17
DECOMMISSIONING: The staff of the SEC has questioned certain current
accounting practices used by nuclear electric generating station owners
regarding the recognition, measurement, and classification of decommissioning
costs for nuclear electric generating stations. In response to these
questions, the Financial Accounting Standards Board is expected to issue new
accounting standards for closure and removal costs, including decommissioning,
in 1997. The company is not able to predict what effect such changes would
have on results of operations, financial position, or related regulatory
practices until the final issuance of revised accounting guidance, but such
effect could be material. Refer to Note 2 for additional information
relating to new accounting standards for decommissioning.
On August 30, 1996, WCNOC submitted the 1996 Decommissioning Cost Study to
the KCC for approval. Approval of this study was received from the KCC on
February 28, 1997. Based on the study, the company's share of these
decommissioning costs, under the immediate dismantlement method, is estimated
to be approximately $624 million during the period 2025 through 2033, or
approximately $192 million in 1996 dollars. These costs were calculated using
an assumed inflation rate of 3.6% over the remaining service life from 1996 of
29 years. Refer to Note 2 for additional information relating to the 1996
Decommissioning Cost Study.
COMPETITION AND ENHANCED BUSINESS OPPORTUNITIES: The electric utility
industry in the United States is rapidly evolving from an historically
regulated monopolistic market to a dynamic and competitive integrated
marketplace. The 1992 Energy Policy Act (Act) began the process of
deregulation of the electricity industry by permitting the FERC to order
electric utilities to allow third parties to sell electric power to wholesale
customers over their transmission systems. As part of the KGE merger, the
company agreed to open access of its transmission system for wholesale
transactions. During 1996, wholesale electric revenues represented
approximately 9% of the company's total electric revenues.
Since that time, the wholesale electricity market has become increasingly
competitive as companies begin to engage in nationwide power brokerage. In
addition, various states including California and New York have taken active
steps toward allowing retail customers to purchase electric power from third
-party providers. In 1996, the KCC initiated a generic docket to study electric
restructuring issues. A retail wheeling task force has been created by the
Kansas Legislature to study competitive trends in retail electric services.
During the 1997 session of the Kansas Legislature, bills have been introduced
to increase competition in the electric industry. Among the matters under
consideration is the recovery by utilities of costs in excess of competitive
cost levels. There can be no assurance at this time that such costs will be
recoverable if open competition is initiated in the electric utility market.
Operating in this competitive environment will place pressure on utility
profit margins and credit quality. Wholesale and industrial customers may
threaten to pursue cogeneration, self-generation, retail wheeling,
municipalization or relocation to other service territories in an attempt to
obtain reduced energy costs. Increasing competition has resulted in credit
rating agencies applying more stringent guidelines when making utility credit
rating determinations. See discussion of Statement of Financial Accounting
Standards No. 71 "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71) in "Regulatory" below.
18
The company is providing competitive electric rates for industrial
expansion projects and economic development projects in an effort to maintain
and increase electric load. During 1996, the company lost a major industrial
customer to cogeneration resulting in a reduction to pre-tax earnings of $8.6
million annually. This customer's decision to develop its own cogeneration
project was based largely on factors unique to the customer, other than energy
cost.
REGULATORY: On April 24, 1996, FERC issued its final rule on Order No.
888, "Promoting Wholesale Competition Through Open Access Non-discriminatory
Transmission Services by Public Utilities; Recovery of Stranded Costs by
Public Utilities and Transmitting Utilities". The company does not presently
expect the order to have a material effect on its operations in large part
because it is already operating in substantially the required manner due to
its agreement with the KCC during the KGE merger (See discussion above).
On May 23, 1996, the company implemented an $8.7 million electric rate
reduction to customers on an interim basis. On October 22, 1996, Western
Resources, the KCC Staff, the City of Wichita, and the Citizens Utility
Ratepayer Board filed an agreement at the KCC whereby the company's retail
electric rates would be reduced, subject to approval by the KCC. This
agreement was approved by the KCC on January 15, 1997. Under the agreement,
on February 1, 1997, the company's rates were reduced by $36.3 million and the
May, 1996 interim reduction became permanent. The company's rates will be
reduced by another $10 million effective June 1, 1998, and again on June 1,
1999. Two one-time rebates of $5 million will be credited to the customers of
Western Resources in January 1998 and 1999. A portion of these rebates will
be credited to the company's customers. The agreement also fixed annual
savings from the KGE merger at $40 million. This level of merger savings
provides for complete recovery of the acquisition premium amortization expense
and a return on the acquisition premium. See Note 3 for additional
information regarding rate matters.
STRANDED COSTS: The company currently applies accounting standards that
recognize the economic effects of rate regulation SFAS 71, and, accordingly,
has recorded regulatory assets and liabilities related to its generation,
transmission and distribution operations. In the event the company determines
that it no longer meets the criteria of SFAS 71, the accounting impact would
be an extraordinary non-cash charge to operations of an amount that would be
material. Criteria that give rise to the discontinuance of SFAS 71 include,
(1) increasing competition that restricts the company's ability to establish
prices to recover specific costs, and (2) a significant change in the manner
in which rates are set by regulators from a cost-based regulation to another
form of regulation. The company periodically reviews these criteria to ensure
the continuing application of SFAS 71 is appropriate. Based on current
evaluation of the various factors and conditions that are expected to impact
future cost recovery, the company believes that its net regulatory assets are
probable of future recovery. Any regulatory changes that would require the
company to discontinue SFAS 71 based upon competitive or other events may
significantly impact the valuation of the company's net regulatory assets and
its utility plant investments, particularly the Wolf Creek facility. At this
time, the effect of competition and the amount of regulatory assets which
could be recovered in such an environment cannot be predicted. See discussion
of "Competition" above for initiatives taken to restructure the electric
industry in Kansas.
19
The term "stranded costs" as it relates to capital intensive utilities has
been defined as investment in and carrying costs associated with property,
plant and equipment and other regulatory assets in excess of the level which
can be recovered in the competitive market in which the utility operates.
Regulatory changes, including the introduction of competition, could adversely
impact the company's ability to recover its costs in these assets. As of
December 31, 1996, the company has recorded regulatory assets which are
currently subject to recovery in future rates of approximately $287 million.
Of this amount, $165 million represents a receivable for income tax benefits
flow-through to customers. The remainder of the regulatory assets represent
items that may give rise to stranded costs including debt issuance costs and
deferred contract settlement costs. Finally, the company's ability to fully
recover its utility plant investments in, and decommissioning cost for,
generating facilities, particularly Wolf Creek, may be at risk in a
competitive environment. Amounts associated with the company's recovery of
environmental remediation costs and long-term fuel contract costs cannot be
estimated with any certainty, but also represent items that could give rise to
"stranded costs" in a competitive environment. In the event that the company
was not allowed to recover its investment in these assets, the accounting
impact would be a charge to its results of operations that would be material.
20
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 21
Financial Statements:
Balance Sheets, December 31, 1996 and 1995 22
Statements of Income for the years ended
December 31, 1996, 1995 and 1994 23
Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994 24
Statements of Taxes for the years ended
December 31, 1996, 1995 and 1994 25
Statements of Capitalization, December 31, 1996 and 1995 26
Statements of Common Stock Equity for the years ended
December 31, 1996, 1995 and 1994 27
Notes to Financial Statements 28
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.
21
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Kansas Gas and Electric Company:
We have audited the accompanying balance sheets and statements of
capitalization of Kansas Gas and Electric Company (a wholly-owned subsidiary
of Western Resources, Inc.) as of December 31, 1996 and 1995, and the related
statements of income, cash flows, taxes, and common stock equity for each of
the three years in the period ended December 31, 1996. 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, 1996 and 1995, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 24, 1997
(February 7, 1997 with
respect to Note 13 of
the Notes to Financial
Statements.)
22
KANSAS GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Dollars in Thousands)
December 31,
1996 1995
ASSETS
UTILITY PLANT:
Electric plant in service (Notes 1 and 11). . . . . . . . $3,574,980 $3,427,928
Less - Accumulated depreciation . . . . . . . . . . . . . 1,062,218 893,728
2,512,762 2,534,200
Construction work in progress . . . . . . . . . . . . . . 33,197 40,810
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 38,461 53,942
Net utility plant . . . . . . . . . . . . . . . . . . . 2,584,420 2,628,952
INVESTMENTS AND OTHER PROPERTY:
Decommissioning trust (Note 2). . . . . . . . . . . . . . 33,041 25,070
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 9,093 7,885
42,134 32,955
CURRENT ASSETS:
Cash and cash equivalents (Note 1). . . . . . . . . . . . 44 53
Accounts receivable and unbilled revenues (net)(Note 1) . 75,671 76,490
Advances to parent company (Note 12). . . . . . . . . . . 250,733 34,948
Fossil fuel, at average cost, . . . . . . . . . . . . . . 13,459 17,522
Materials and supplies, at average cost . . . . . . . . . 30,187 31,458
Prepayments and other current assets. . . . . . . . . . . 16,991 17,128
387,085 177,599
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 7) . . . . . . . . . . 164,520 208,367
Corporate-owned life insurance (net) (Note 1). . . .. . . 10,341 7,279
Regulatory assets (Note 3). . . . . . . . . . . . . . . . 122,388 146,116
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 7,999 2,146
305,248 363,908
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $3,318,887 $3,203,414
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Statements):
Common stock equity . . . . . . . . . . . . . . . . . . . $1,182,351 $1,186,077
Long-term debt (net). . . . . . . . . . . . . . . . . . . 684,068 684,082
1,866,419 1,870,159
CURRENT LIABILITIES:
Short-term debt (Note 4). . . . . . . . . . . . . . . . . 222,300 50,000
Long-term debt due within one year (Note 5) . . . . . . . - 16,000
Accounts payable. . . . . . . . . . . . . . . . . . . . . 48,819 50,783
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 35,358 17,766
Accrued interest. . . . . . . . . . . . . . . . . . . . . 9,445 7,903
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,726 6,608
322,648 149,060
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Note 7). . . . . . . . . . . . . . 753,511 800,934
Deferred investment tax credits (Note 7). . . . . . . . . 69,722 72,970
Deferred gain from sale-leaseback (Note 6). . . . . . . . 233,060 242,700
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 73,527 67,591
1,129,820 1,184,195
COMMITMENTS AND CONTINGENCIES (Notes 2 and 8)
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . $3,318,887 $3,203,414
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
23
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Dollars in Thousands)
Year Ended December 31,
1996 1995 1994
OPERATING REVENUES (Notes 1 and 3). . . . . . . . . . . $ 654,570 $ 623,868 $ 619,880
OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . . . . . . 91,824 80,592 90,383
Nuclear fuel. . . . . . . . . . . . . . . . . . . . 19,962 19,425 13,562
Power purchased . . . . . . . . . . . . . . . . . . . 11,483 4,577 7,144
Other operations. . . . . . . . . . . . . . . . . . . 134,720 117,876 115,060
Maintenance . . . . . . . . . . . . . . . . . . . . . 48,943 48,056 47,988
Depreciation and amortization . . . . . . . . . . . . 96,309 79,679 71,457
Amortization of phase-in revenues . . . . . . . . . . 17,544 17,545 17,544
Taxes (See Statements):
Federal income. . . . . . . . . . . . . . . . . . . 36,156 50,513 50,212
State income . . . . . . . . . . . . . . . . . . . 10,455 13,037 12,427
General . . . . . . . . . . . . . . . . . . . . . . 46,183 46,241 45,092
Total operating expenses. . . . . . . . . . . . . 513,579 477,541 470,869
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 140,991 146,327 149,011
OTHER INCOME AND DEDUCTIONS:
Corporate-owned life insurance (net). . . . . . . . . (2,249) (2,668) (5,354)
Miscellaneous (net) . . . . . . . . . . . . . . . . . 3,397 4,884 5,079
Income taxes (net) (See Statements) . . . . . . . . . 10,353 11,763 7,290
Total other income and deductions . . . . . . . . 11,501 13,979 7,015
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 152,492 160,306 156,026
INTEREST CHARGES:
Long-term debt. . . . . . . . . . . . . . . . . . . . 46,304 47,073 47,827
Other . . . . . . . . . . . . . . . . . . . . . . . . 11,758 5,190 5,183
Allowance for borrowed funds used
during construction (credit). . . . . . . . . . . . (1,844) (2,830) (1,510)
Total interest charges. . . . . . . . . . . . . . 56,218 49,433 51,500
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 96,274 $ 110,873 $ 104,526
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
24
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31,
1996 1995 1994
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 96,274 $ 110,873 $ 104,526
Depreciation and amortization . . . . . . . . . . . . . . 96,309 79,679 71,457
Amortization of nuclear fuel. . . . . . . . . . . . . . . 15,685 14,703 10,437
Gain on sales of utility plant (net of tax) . . . . . . . - (951) -
Amortization of phase-in revenues . . . . . . . . . . . . 17,544 17,545 17,544
Corporate-owned life insurance. . . . . . . . . . . . . . (29,713) (28,548) (17,246)
Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (9,640) (9,640)
Changes in working capital items:
Accounts receivable and unbilled
revenues (net) (Note 1) . . . . . . . . . . . . . . . 819 (8,657) (56,721)
Fossil fuel . . . . . . . . . . . . . . . . . . . . . . 4,063 (3,770) (6,158)
Accounts payable. . . . . . . . . . . . . . . . . . . . (1,964) 1,690 (2,002)
Interest and taxes accrued. . . . . . . . . . . . . . . 19,134 967 4,508
Other . . . . . . . . . . . . . . . . . . . . . . . . . 4,421 (1,980) (922)
Changes in other assets and liabilities . . . . . . . . . (9,772) 18,866 14,636
Net cash flows from operating activities. . . . . . . 203,160 190,777 130,419
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant. . . . . . . . . . . . . . . . 68,632 93,938 89,880
Sales of utility plant. . . . . . . . . . . . . . . . . . - (1,723) -
Corporate-owned life insurance policies . . . . . . . . . 25,647 30,347 26,418
Death proceeds of corporate-owned life insurance. . . . . (9,445) (10,583) -
Net cash flows used in investing activities . . . . . 84,834 111,979 116,298
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . 172,300 - (105,800)
Advances to parent company (net). . . . . . . . . . . . . (215,785) 29,445 128,399
Bonds issued. . . . . . . . . . . . . . . . . . . . . . . - - 160,422
Bonds retired . . . . . . . . . . . . . . . . . . . . . . (16,135) (25) (46,440)
Other long-term debt retired. . . . . . . . . . . . . . . - - (67,893)
Borrowings against life insurance policies. . . . . . . . 45,978 47,046 42,175
Repayment of borrowings against life insurance policies . (4,693) (5,258) -
Revolving credit agreement (net). . . . . . . . . . . . . - -
Dividends to parent company . . . . . . . . . . . . . . . (100,000) (150,000) (125,000)
Net cash flows (used in) financing activities. . . . . (118,335) (78,792) (14,137)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . (9) 6 (16)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . . . 53 47 63
CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . . . $ 44 $ 53 $ 47
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized) . . . . . . . . . . . . . . . . . . . . $ 78,712 $ 71,808 $ 68,544
Income taxes . . . . . . . . . . . . . . . . . . . . . . 32,100 42,100 28,509
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
25
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF TAXES
(Dollars in Thousands)
Year Ended December 31,
1996 1995 1994
FEDERAL INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . $ 31,135 $ 34,661 $ 24,427
Deferred (net). . . . . . . . . . . . . . . . . . . (218) 9,528 23,002
Investment tax credit-Deferral. . . . . . . . . . . - - -
-Amortization. . . . . . . . . (3,249) (3,314) (3,208)
Total Federal income taxes . . . . . . . . . . . 27,668 40,875 44,221
Less:
Federal income taxes applicable
to non-operating items . . . . . . . . . . . . . (8,488) (9,638) (5,991)
Total Federal income taxes charged to operations. . 36,156 50,513 50,212
STATE INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . 11,948 13,275 5,574
Deferred (net). . . . . . . . . . . . . . . . . . . (3,358) (2,363) 5,554
Total State income taxes . . . . . . . . . . . . 8,590 10,912 11,128
Less:
State income taxes applicable
to non-operating items . . . . . . . . . . . . . (1,865) (2,125) (1,299)
Total State income taxes charged to operations. . . 10,455 13,037 12,427
GENERAL TAXES:
Property. . . . . . . . . . . . . . . . . . . . . . 41,331 40,827 40,104
Payroll and other taxes . . . . . . . . . . . . . . 4,852 5,414 4,988
Total general taxes charged to operations. . . . 46,183 46,241 45,092
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . $ 92,794 $ 109,791 $ 107,731
The effective income tax rates set forth below are computed by dividing total Federal and State
income taxes by the sum of such taxes and net income. The difference between the effective rates
and the Federal statutory income tax rates are as follows:
Year Ended December 31, 1996 1995 1994
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . 27% 32% 35%
Effect of:
State income taxes. . . . . . . . . . . . . . . . . (4) (4) (5)
Amortization of investment tax credits. . . . . . . 2 2 2
Corporate-owned life insurance. . . . . . . . . . . 7 5 4
Flow through and amortization, net. . . . . . . . . 2 - (1)
Other differences . . . . . . . . . . . . . . . . . 1 - -
STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . 35% 35% 35%
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
26
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
December 31,
1996 1995
COMMON STOCK EQUITY (See Statements):
Common stock, without par value, authorized and issued
1,000 shares. . . . . . . . . . . . . . . . . . . . . . . $1,065,634 $1,065,634
Retained earnings . . . . . . . . . . . . . . . . . . . . . 116,717 120,443
Total common stock equity . . . . . . . . . . . . . . . . 1,182,351 63% 1,186,077 63%
LONG-TERM DEBT (Note 5):
First Mortgage Bonds:
Series Due 1996 1995
5-5/8% 1996 $ - $ 16,000
7.6% 2003 135,000 135,000
6-1/2% 2005 65,000 65,000
6.20% 2006 100,000 100,000
300,000 316,000
Pollution Control Bonds:
5.10% 2023 13,822 13,957
Variable (1) 2027 21,940 21,940
7.0% 2031 327,500 327,500
Variable (2) 2032 14,500 14,500
Variable (3) 2032 10,000 10,000
387,762 387,897
Total bonds. . . . . . . . . . . . . . . . . . . . . . 687,762 703,897
Less:
Unamortized premium and discount (net). . . . . . . . . . 3,694 3,815
Long-term debt due within one year. . . . . . . . . . . . - 16,000
Total long-term debt . . . . . . . . . . . . . . . . . 684,068 37% 684,082 37%
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . $1,866,419 100% $1,870,159 100%
Market-Adjusted Tax Exempt Securities (MATES). The interest rate is reset
periodically via an auction process. Rates at December 31, 1996: (1) 3.55%,
(2) 3.60%, and (3) 3.52%.
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
27
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF COMMON STOCK EQUITY
(Dollars in Thousands)
Common Retained
Stock Earnings
BALANCE DECEMBER 31, 1993, 1,000 shares. . . . . . . $1,065,634 $ 180,044
Net income . . . . . . . . . . . . . . . . . . . . . 104,526
Dividend to parent company . . . . . . . . . . . . . (125,000)
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
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
28
KANSAS GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: 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 277,000 electric customers in southeastern
Kansas. At December 31, 1996, the company had no employees. All employees
are provided by the company's parent, Western Resources which allocates costs
related to the employees to 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 as applied to regulated public
utilities. 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 that recognize the
economic effects of rate regulation 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
related to its generation, transmission and distribution operations. In 1996,
the KCC initiated a generic docket to study electric restructuring issues. A
retail wheeling task force has been created by the Kansas Legislature to study
competitive trends in retail electric services. During the 1997 session of
the Kansas Legislature, bills have been introduced to increase competition in
the electric industry. Among the matters under consideration is the recovery
by utilities of costs in excess of competitive cost levels. There can be no
assurance at this time that such costs will be recoverable if open competition
is initiated in the electric utility market. In the event the company
determines that it no longer meets the criteria for SFAS 71, the accounting
impact would be an extraordinary non-cash charge to operations of an amount
that would be material. Criteria that give rise to the discontinuance of SFAS
71 include, (1) increasing competition that restricts the company's ability to
establish prices to recover specific costs, and (2) a significant change in
the manner in which rates are set by regulators from a cost-based regulation
to another form of regulation. The company periodically reviews these
criteria to ensure the continuing application of SFAS 71 is appropriate.
Based on current evaluation of the various factors and conditions that are
expected to impact future cost recovery, the company believes that its net
regulatory assets are probable of future recovery. Any regulatory changes
that would require the company to discontinue SFAS 71 based upon competitive
or other events may significantly impact the valuation of the company's net
regulatory assets and its utility plant investments, particularly the Wolf
Creek facility. At this time, the effect of competition and the amount of
regulatory assets which could be recovered in such an environment cannot be
predicted. See Note 3 for further discussion on regulatory assets.
29
In January, 1996, the company adopted Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of". This Statement imposes stricter
criteria for regulatory assets by requiring that such assets be probable of
future recovery at each balance sheet date. Based on the current regulatory
structure in which the company operates, the adoption of this standard did not
have a material impact on the financial position or results of operations of
the company. This conclusion may change in the future as competitive factors
influence wholesale or retail pricing in the electric industry.
Utility Plant: Utility plant is stated at cost. For constructed plant,
cost includes contracted services, direct labor and materials, indirect
charges for engineering, supervision, general and administrative costs, and an
allowance for funds used during construction (AFUDC). The AFUDC rate was
5.71% for 1996, 6.39% for 1995, and 4.07% for 1994. The cost of additions to
utility plant 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, amortization of
the acquisition premium of approximately $801 million resulting from the KGE
purchase began in August of 1995. The premium is being amortized over 40
years and has been classified as electric plant in service. Accumulated
amortization through December 31, 1996 totaled $27.5 million. See Note 3 for
further information concerning the amortization of this premium.
Depreciation: Depreciation is provided on the straight-line method based
on estimated useful lives of property. Composite provisions for book
depreciation approximated 2.81% during 1996, 2.72% during 1995, and 2.7%
during 1994 of the average original cost of depreciable property. In the
past, the methods and rates have been determined by depreciation studies and
approved by the various regulatory bodies. The company periodically evaluates
its depreciation rates considering the past and expected future experience in
the operation of its facilities.
Environmental Remediation: Effective January 1, 1997, the company
adopted the provisions of Statement of Position (SOP) 96-1, "Environmental
Remediation Liabilities". This statement provides authoritative guidance for
recognition, measurement, display, and disclosure of environmental remediation
liabilities in financial statements. The company is currently evaluating and
in the process of estimating the potential liability associated with
environmental remediation. Management does not expect the amount to be
significant to the company's results of operations as the company will seek
recovery of these costs through rates as has been permitted by the KCC in the
case of another Kansas utility. Additionally, the adoption of this statement
is not expected to have a material impact on the company's financial position.
To the extent that such remediation costs are not recovered through rates,
the costs may be material to the company's operating results, depending on the
degree of remediation required and number of years over which the remediation
must be completed.
30
Cash and Cash Equivalents: For purposes of the Statements of Cash Flows,
the company considers highly liquid collateralized debt instruments purchased
with a maturity of three months or less to be cash equivalents.
Income Taxes: The company accounts for income taxes in accordance with
the provisions of Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" (SFAS 109). Under SFAS 109, deferred tax assets
and liabilities are recognized based on temporary differences in amounts
recorded for financial reporting purposes and their respective tax bases.
Investment tax credits previously deferred are being amortized to income over
the life of the property which gave rise to the credits (See Note 7).
Revenues: Operating revenues include amounts actually billed for
services rendered and an accrual of estimated unbilled revenues. Unbilled
revenues represent the estimated amount customers will be billed for service
provided from the time meters were last read to the end of the accounting
period. Unbilled revenues of $23.5 million and $21.8 million are recorded as
a component of accounts receivable and unbilled revenue (net) on the balance
sheets as of December 31, 1996 and 1995, respectively.
The company's recorded reserves for doubtful accounts receivable totaled
$1.9 million and $2.7 million at December 31, 1996 and 1995, respectively.
Debt Issuance and Reacquisition Expense: Debt premium, discount and
issuance expenses are amortized over the life of each issue. Under regulatory
procedures, debt reacquisition expenses are amortized over the remaining life
of the reacquired debt or, if refinanced, the life of the new debt. See Note
3 for more information regarding regulatory assets.
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, 1996 and 1995, was $25.3 and $28.5 million,
respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts
related to corporate-owned life insurance contracts (COLI) are recorded in
Corporate-owned Life Insurance (net) on the balance sheets:
1996 1995
(Dollars in Millions)
Cash surrender value of contracts.(1). $404.6 $360.3
Borrowings against contracts . . . . . (394.3) (353.0)
COLI (net) . . . . . . . . . . . . $ 10.3 $ 7.3
(1) Cash surrender value of contracts as presented represents the value of the
policies as of the end of the respective policy years and not as of December
31, 1996 and 1995.
Income is recorded for increases in cash surrender value and net death
proceeds. Interest expense is recognized for COLI borrowings. The net income
generated from COLI contracts, including the tax benefit of the interest
deductions and premium expenses, are recorded as Corporate-owned Life
Insurance (net) on the Statements of Income. The income from increases in
cash surrender value and net death proceeds was $25.4 million for 1996, $22.7
million for 1995, and $15.6 million for 1994. The interest expense deduction
taken was $27.6 million for 1996, $25.4 million for 1995, and $21.0 million
for 1994.
31
On August 2, 1996, Congress passed legislation that will phase out tax
benefits associated with certain COLI policies. The legislation had minimal
impact on the company's COLI policies as all policies entered into prior to
July 1, 1986 were grandfathered under the legislation.
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. The prioritized sites will
be investigated over a ten year period. The agreement will allow the company
to set mutual objectives with the KDHE in order to expedite effective response
activities and to control costs and environmental impact. The costs incurred
for site investigation and risk assessment in 1996 and 1995 were minimal. To
the extent that such remediation costs are not recovered through rates, the
costs could be material to the company's financial position or results of
operations depending on the degree of remediation and number of years over
which the remediation must be completed.
Decommissioning: The company accrues decommissioning costs over the
expected life of the Wolf Creek generating facility. The accrual is based on
estimated unrecovered decommissioning costs which consider inflation over the
remaining estimated life of the generating facility and are net of expected
earnings on amounts recovered from customers and deposited in an external
trust fund.
On August 30, 1996, WCNOC submitted the 1996 Decommissioning Cost Study
to the KCC for approval. Approval of this study was received from the KCC on
February 28, 1997. Based on the study, the company's share of these
decommissioning costs, under the immediate dismantlement method, is estimated
to be approximately $624 million during the period 2025 through 2033, or
approximately $192 million in 1996 dollars. These costs were calculated using
an assumed inflation rate of 3.6% over the remaining service life from 1996 of
29 years.
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 1996 and will increase
annually to $5.6 million in 2024. These expenses are deposited in an external
trust fund. The average after tax expected return on trust assets is 5.7%.
Approval of this funding schedule is still pending with the KCC.
32
The company's investment in the decommissioning fund, including
reinvested earnings approximated $33.0 million and $25.1 million at December
31, 1996 and December 31, 1995, respectively. Trust fund earnings accumulate
in the fund balance and increase the recorded decommissioning liability.
These amounts are reflected in Investments and Other Property, Decommissioning
trust, and the related liability is included in Deferred Credits and Other
Liabilities, Other, on the Balance Sheets.
The staff of the SEC has questioned certain current accounting practices
used by nuclear electric generating station owners regarding the recognition,
measurement, and classification of decommissioning costs for nuclear electric
generating stations. In response to these questions, the Financial Accounting
Standards Board is expected to issue new accounting standards for removal
costs, including decommissioning, in 1997. If current electric utility
industry accounting practices for such decommissioning costs are changed: (1)
annual decommissioning expenses could increase, (2) the estimated present
value of decommissioning costs could be recorded as a liability rather than as
accumulated depreciation, and (3) trust fund income from the external
decommissioning trusts could be reported as investment income rather than as a
reduction to decommissioning expense. When revised accounting guidance is
issued, the company will also have to evaluate its effect on accounting for
removal costs of other long-lived assets. The company is not able to predict
what effect such changes would have on results of operations, financial
position, or related regulatory practices until the final issuance of revised
accounting guidance, but such effect could be material.
The company carries premature decommissioning insurance which has several
restrictions. One of these is that it can only be used if Wolf Creek incurs
an accident exceeding $500 million in expenses to safely stabilize the
reactor, to decontaminate the reactor and reactor station site in accordance
with a plan approved by the NRC, and to pay for on-site property damages.
This decommissioning insurance will only be available if the insurance funds
are not needed to implement the NRC-approved plan for stabilization and
decontamination.
Nuclear Insurance: The Price-Anderson Act limits the combined public
liability of the owners of nuclear power plants to $8.9 billion for a single
nuclear incident. If this liability limitation is insufficient, the U.S.
Congress will consider taking whatever action is necessary to compensate the
public for valid claims. The Wolf Creek owners (Owners) have purchased the
maximum available private insurance of $200 million and the balance is
provided by an assessment plan mandated by the NRC. Under this plan, the
Owners are jointly and severally subject to a retrospective assessment of up
to $79.3 million ($37.3 million, company's share) in the event there is a
major nuclear incident involving any of the nation's licensed reactors. This
assessment is subject to an inflation adjustment based on the Consumer Price
Index and applicable premium taxes. There is a limitation of $10 million
($4.7 million, company's share) in retrospective assessments per incident, per
year.
The Owners carry decontamination liability, premature decommissioning
liability, and property damage insurance for Wolf Creek totaling approximately
$2.8 billion ($1.3 billion, company's share). This insurance is provided by a
combination of "nuclear insurance pools" ($500 million) and Nuclear Electric
Insurance Limited (NEIL) ($2.3 billion). In the event of an accident,
insurance proceeds must first be used for reactor stabilization and site
decontamination. The company's share of any remaining proceeds can be used
33
for property damage or premature decommissioning costs up to $1.3 billion
(company's share). Premature decommissioning insurance cost recovery is the
excess of funds previously collected for decommissioning (as discussed under
"Decommissioning").
The Owners also carry additional insurance with NEIL to cover costs of
replacement power and other extra expenses incurred during a prolonged outage
resulting from accidental property damage at Wolf Creek. If losses incurred
at any of the nuclear plants insured under the NEIL policies exceed premiums,
reserves, and other NEIL resources, the company may be subject to
retrospective assessments under the current policies of approximately $8
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.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a
two-phase reduction in certain emissions. To meet the monitoring and
reporting requirements under the acid rain program, the company has installed
continuous monitoring and reporting equipment at a total cost of approximately
$2.3 million as of December 31, 1996. The company does not expect material
expenditures to be needed to meet Phase II sulfur dioxide requirements.
The nitrogen oxides (NOx) and toxic limits, which were not set in the
law, were proposed by the EPA in January 1996. The company is currently
evaluating the steps it would need to take in order to comply with the
proposed new rules. The company will have three years from the date the
limits were proposed to comply with the new NOx rules.
Fuel Commitments: To supply a portion of the fuel requirements for its
generating plants, the company has entered into various commitments to obtain
nuclear fuel and coal. Some of these contracts contain provisions for price
escalation and minimum purchase commitments. At December 31, 1996, WCNOC's
nuclear fuel commitments (company's share) were approximately $15.4 million
for uranium concentrates expiring at various times through 2001, $59.4 million
for enrichment expiring at various times through 2003, and $70.3 million for
fabrication through 2025. At December 31, 1996, the company's coal contract
commitments in 1996 dollars under the remaining terms of the contracts were
approximately $671 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
Utility expenses and credits recognized as regulatory assets and
liabilities on the Consolidated Balance Sheets are recognized in income as the
related amounts are included in service rates and recovered from or refunded
34
to customers in utility revenues. The company expects to recover the
following regulatory assets in rates:
December 31, 1996 1995
(Dollars in Thousands)
Coal contract settlement costs $ 11,655 $ 14,612
Deferred plant costs 31,272 31,539
Phase-in revenues 26,317 43,861
Debt issuance costs (See Note 1 and 6) 45,989 49,279
Other regulatory assets 7,155 6,825
Total regulatory assets $122,388 $146,116
Coal Contract Settlements: In March 1990, the KCC issued an order
allowing the company to defer its share of a 1989 coal contract settlement
with the Pittsburg and Midway Coal Mining Company amounting to $22.5 million.
This amount was recorded as a deferred charge and is included in Deferred
Charges and Other Assets, Regulatory Assets, on the balance sheet. The
settlement resulted in the termination of a long-term coal contract. The KCC
permitted the company to recover this settlement as follows: 76% of the
settlement plus a return over the remaining term of the terminated contract
(through 2002) and 24% to be amortized to expense with a deferred return
equivalent to the carrying cost of the asset.
Deferred Plant Costs: In 1986, the company recognized the effects of Wolf
Creek related disallowances in accordance with Statement of Financial
Accounting Standard No. 90 "Regulated Enterprises - Accounting for
Abandonments and Disallowances of Plant Costs".
Phase-in Revenues: In 1988, the KCC ordered the accrual of phase-in
revenues to be discontinued effective December 31, 1988. The company began
amortizing the phase-in revenue asset on a straight-line basis over 9-1/2
years beginning January 1, 1989. At December 31, 1996, approximately $26
million of deferred phase-in revenues remain to be recovered.
KCC Rate Proceedings: On August 17, 1995, the company filed with the KCC
a request to more rapidly recover its investment in its assets of Wolf Creek
over the next seven years by increasing depreciation by $50 million each year
and reduce annual depreciation expense by approximately $3 million for
electric transmission, distribution and certain generating plant assets to
reflect the useful lives of these properties more accurately. The company
sought to reduce electric rates for its customers by approximately $8.7
million annually in each of the seven years of accelerated Wolf Creek
depreciation.
On May 23, 1996, the company implemented an $8.7 million electric rate
reduction on an interim basis. On October 22, 1996, Western Resources, the
company, the KCC Staff, the City of Wichita, and the Citizens Utility
Ratepayer Board filed an agreement with the KCC whereby the company's retail
electric rates would be reduced, subject to approval by the KCC. This
agreement was approved on January 15, 1997. Under the agreement, on February
1, 1997, the company's rates were reduced by $36.3 million, and in addition,
the May 1996 interim reduction became permanent. The company's rates will be
reduced by another $10 million effective June 1, 1998, and again on June 1,
1999. Two one-time rebates of $5 million will be credited to customers of
Western Resources in January 1998 and 1999. A portion of these rebates will
be credited to the company's customers. The agreement also fixed annual
savings from the 1992 merger with Western Resources at $40 million. This
level of merger savings provides for complete recovery of and a return on the
acquisition premium.
35
4. SHORT-TERM BORROWINGS
The company's short-term financing requirements are satisfied through
short-term bank loans and uncommitted loan participation agreements.
The company has arrangements with certain banks to provide unsecured
short-term lines of credit on a committed basis totaling $200 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, 1996 1995 1994
(Dollars in Thousands)
Borrowings outstanding at year end:
Lines of credit $200,000 $ - $ -
Bank loans 22,300 50,000 50,000
Total $222,300 $ 50,000 $ 50,000
Weighted average interest rate on
debt outstanding at year end
(including fees) 5.93% 6.03% 6.26%
Weighted average short-term debt
outstanding during the year $147,556 $ 32,296 $ 47,566
Weighted daily average interest
rates during the year
(including fees) 5.83% 6.10% 4.50%
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 1997.
36
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, 1996, approximately $22.5
million of this deferral remained in Deferred Charges and Other Assets,
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 2001 and $611
million over the remainder of the lease.
The gain realized at the date of the sale of La Cygne 2 has been deferred
for financial reporting purposes, and is being amortized ($9.7 million per
year) over the initial lease term in proportion to the related lease expense.
The company's lease expense, net of amortization of the deferred gain and a
one-time payment, was approximately $22.5 million for 1996, 1995, and 1994.
37
7. INCOME TAXES
Under SFAS 109, temporary differences gave rise to deferred tax assets
and deferred tax liabilities at December 31, 1996 and 1995, respectively, as
follows:
1996 1995
(Dollars in Thousands)
Deferred Tax Assets:
Deferred gain on sale-leaseback. . . . . $ 99,466 $ 105,007
Alternative minimum tax carry forwards . 250 18,740
Other. . . . . . . . . . . . . . . . . . 11,246 10,870
Total Deferred Tax Assets. . . . . . . $ 110,962 $ 134,617
Deferred Tax Liabilities:
Accelerated depreciation & other . . . . $ 363,647 $ 375,079
Acquisition premium. . . . . . . . . . . 306,662 314,933
Deferred future income taxes . . . . . . 164,520 208,367
Other. . . . . . . . . . . . . . . . . . 29,644 37,172
Total Deferred Tax Liabilities . . . . $ 864,473 $ 935,551
Accumulated Deferred
Income Taxes, Net $ 753,511 $ 800,934
In accordance with various rate orders received from the KCC, the company
has not yet collected through rates the amounts necessary to pay a significant
portion of the net deferred income tax liabilities. 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.
8. LEGAL PROCEEDINGS
The company is involved in various legal and environmental proceedings.
Management believes that adequate provision has been made within the financial
statements for these matters and accordingly believes their ultimate
dispositions will not have a material adverse effect upon the financial
position or results of operations of the company.
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, 1996 and 1995. The fair value of long-term 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.
38
The estimated fair values of the company's financial instruments are as
follows:
Carrying Value Fair Value
December 31, 1996 1995 1996 1995
(Dollars in Thousands)
Decommissioning trust. . . $ 33,041 $ 25,070 $ 33,041 $ 25,070
Fixed-rate debt. . . . . . 641,322 657,457 665,300 675,471
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 as of December 31, 1996 and 1995. These fair value estimates have
not been comprehensively revalued for the purpose of these financial
statements since that date, and current estimates of fair value may differ
significantly from the amounts presented herein. Because the company's
operations are regulated, the company believes that any gains or losses
related to the retirement of debt would not have a material effect on the
company's financial position or results of operations.
10. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1996
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 160,541 $ 105,043 343 50
Jeffrey 1 (b) Jul 1978 69,043 27,962 147 20
Jeffrey 2 (b) May 1980 67,896 28,125 147 20
Jeffrey 3 (b) May 1983 95,844 38,487 141 20
Wolf Creek (c) Sep 1985 1,382,000 369,182 547 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL)
(b) Jointly owned with Western Resources and UtiliCorp United Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
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 335 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.
39
11. 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.
1996
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
(Dollars in Thousands)
Operating revenues. . . . . $153,300 $193,198 $163,038 $145,034
Operating income. . . . . . 35,066 49,432 27,439 29,054
Net income. . . . . . . . . 22,585 40,736 17,253 15,700
1995
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
(Dollars in Thousands)
Operating revenues. . . . . $138,182 $202,382 $144,747 $138,557
Operating income. . . . . . 25,021 61,960 30,779 28,567
Net income. . . . . . . . . 21,598 51,836 19,567 17,872
12. 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 $251
million and $35 million at December 31, 1996 and 1995, respectively. These
amounts are recorded as advances to parent company in Current Assets on the
balance sheet.
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 1996, the company declared a dividend to
Western Resources of $100 million.
13. WESTERN RESOURCES AND KANSAS CITY POWER & LIGHT COMPANY MERGER AGREEMENT
On February 7, 1997, KCPL and the Western Resources entered into an
agreement whereby KCPL would be merged with and into Western Resources (KCPL
Merger). The merger agreement provides for a tax-free, stock-for-stock
transaction valued at approximately $2 billion. Under the terms of the
agreement, KCPL shareholders will receive $32 of Western Resources common
stock per KCPL share, subject to an exchange ratio collar of not less than
0.917 to no more than 1.100 common shares. Consummation of the KCPL Merger is
subject to customary conditions including obtaining the approval of KCPL's and
the Western Resources' shareholders and various regulatory agencies. Western
Resources expects to be able to close the KCPL Merger in the first half of
1998.
40
KCPL is a public utility company engaged in the generation, transmission,
distribution, and sale of electricity to approximately 430,000 customers in
western Missouri and eastern Kansas. KCPL, Western Resources, and the company
have joint interests in certain electric generating assets, including Wolf
Creek.
41
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There were no disagreements with accountants on accounting and financial
disclosure.
42
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 1991 and Other Continuously
Name Age Directorships Other Than The Company Since
William B. 44 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. 63 President, Jackson Mortuary, 1994
Jackson Wichita, Kansas
Directorships
The National Business League
Donald A. 63 Retired President and Chairman (Emeritus), 1992(b)
Johnston Maupintour, Inc. Lawrence, Kansas,
(a) Consultant - Commerce Bank, Lawrence,
Kansas (since July 1996)
Directorships
Commerce Bank, Lawrence, Kansas
Steven L. 51 Executive Vice President and Chief 1992
Kitchen Financial Officer, Western Resources,
Inc.
Directorships
Central National Bank
Marilyn B. 47 President Wichita, NationsBank N.A. 1994
Pauly (Midwest), Wichita, Kansas (since
(a) 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
NationsBank N.A. (Midwest)
43
Richard D. 63 President, Range Oil Company 1993
Smith Directorships
NationsBank N.A. (Midwest), (Advisory)
HCA Wesley Medical Center,
Wichita, Kansas
(a) 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.
(b) 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 1996, the Board of Directors met four times and the Audit
Committee met once. Each director attended at least 75% of the total number
of Board and Committee meetings held while he/she served as a director or a
member of the committee.
Other information required by Item 10 is omitted pursuant to General
Instruction 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.
44
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, 1996 and 1995
Statements of Income for the year ended December 31, 1996, 1995 and 1994
Statements of Cash Flows for the year ended December 31, 1996, 1995 and 1994
Statements of Taxes for the year ended December 31, 1996, 1995 and 1994
Statements of Capitalization, December 31, 1996 and 1995
Statements of Common Stock Equity for the year ended December 31, 1996
Notes to Financial Statements
REPORTS ON FORM 8-K
None
45
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
2(a) Agreement and Plan of Merger (Filed as Exhibit 2 to Form 10-K I
for the year ended December 31, 1990, File No. 1-7324)
2(b) Amendment No. 1 to Agreement and Plan of Merger (Filed as I
Exhibit 2 to Form 10-K for the year ended December 31, 1990,
File No. 1-7324)
3(a) Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K I
for the year ended December 31, 1992, File No. 1-7324)
3(b) Certificate of Merger of Kansas Gas and Electric Company into I
KCA Corporation (Filed as Exhibit 3(b) to Form 10-K
for the year ended December 31, 1992, File No. 1-7324)
3(c) By-laws as amended (Filed as Exhibit 3(c) Form 10-K I
for the year ended December 31, 1992, File No. 1-7324)
4(c) Mortgage and Deed of Trust, dated as of April 1, 1940 to I
Guaranty Trust Company of New York (now Morgan Guaranty Trust
Company of New York) and Henry A. Theis (to whom W. A. Spooner
is successor), Trustees, as supplemented by thirty-eight
Supplemental Indentures, dated as of June 1, 1942, March 1, 1948,
December 1, 1949, June 1, 1952, October 1, 1953, March 1, 1955,
February 1, 1956, January 1, 1961, May 1, 1966, March 1, 1970,
May 1, 1971, March 1, 1972, May 31, 1973, July 1, 1975,
December 1, 1975, September 1, 1976, March 1, 1977, May 1, 1977,
August 1, 1977, March 15, 1978, January 1, 1979, April 1, 1980,
July 1, 1980, August 1, 1980, June 1, 1981, December 1, 1981,
May 1, 1982, March 15, 1984, September 1, 1984 (Twenty-ninth
and Thirtieth), February 1, 1985, April 15, 1986, June 1, 1991
March 31, 1992, December 17, 1992, August 24, 1993, January 15,
1994 and March 1, 1994, (Filed, respectively, as Exhibit A-1 to
Form U-1, File No. 70-23; Exhibits 7(b) and 7(c), File No. 2-7405;
Exhibit 7(d), File No. 2-8242; Exhibit 4(c), File No. 2-9626;
Exhibit 4(c), File No. 2-10465; Exhibit 4(c), File No. 2-12228;
Exhibit 4(c), File No. 2-15851; Exhibit 2(b)-1, File No. 2-24680;
Exhibit 2(c), File No. 2-36170; Exhibits 2(c) and 2(d), File
No. 2-39975; Exhibit 2(d), File No. 2-43053; Exhibit 4(c)2 to
Form 10-K, for December 31, 1989, File No. 1-7324; Exhibit 2(c),
File No. 2-53765; Exhibit 2(e), File No. 2-55488; Exhibit 2(c),
File No. 2-57013; Exhibit 2(c), File No. 2-58180; Exhibit 4(c)3
to Form 10-K for December 31, 1989, File No. 1-7324; Exhibit 2(e),
File No. 2-60089; Exhibit 2(c), File No. 2-60777; 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
46
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(c) to the Form 10-K for the year ended December 31, 1993,
File No. 1-7324)
12 Computation of Ratio of Consolidated Earnings to Fixed Charges
(Filed electronically)
23 Consent of Independent Public Accountants, Arthur Andersen LLP
(Filed electronically)
27 Financial Data Schedule (Filed electronically)
47
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 27, 1997 By /s/ William B. Moore
William B. Moore,
Chairman of the Board
and President
48
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 27, 1997
Officer)
Secretary, Treasurer and General
/s/ RICHARD D. TERRILL Counsel (Principal Financial March 27, 1997
(Richard D. Terrill) and Accounting Officer)
/s/ ANDERSON E. JACKSON
(Anderson E. Jackson)
/s/ DONALD A. JOHNSTON
(Donald A. Johnston)
/s/ S. L. KITCHEN Directors March 27, 1997
(S. L. Kitchen)
/s/ MARILYN B. PAULY
(Marilyn B. Pauly)
/s/ RICHARD D. SMITH
(Richard D. Smith)