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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1995
[ ] 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, 1996)
Indicated by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes x No
Registrant meets the conditions of General Instruction J(1)(a) and (b) to Form
10-K for certain wholly-owned subsidiaries and is therefore filing an
abbreviated form.
KANSAS GAS AND ELECTRIC COMPANY
FORM 10-K
December 31, 1995
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 18
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 40
PART III
Item 10. Directors and Executive Officers of the
Registrant 41
Item 11. Executive Compensation 42
Item 12. Security Ownership of Certain Beneficial
Owners and Management 42
Item 13. Certain Relationships and Related Transactions 42
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 43
Signatures 46
PART I
ITEM 1. BUSINESS
ACQUISITION AND MERGER
On March 31, 1992, Western Resources, Inc. (formerly The Kansas Power and
Light Company) (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).
Additional information relating to the Merger can be found in Management's
Discussion and Analysis of Financial Condition and Results of Operations.
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, 1995, the Company had no employees. All employees are provided
by the Company's parent, Western Resources, Inc. (Western Resources).
In January 1996, the KCC initiated an order for a generic investigation to
analyze matters related to the potential restructuring of the electric
industry and the overall implications to both utilities and public interests
within the state of Kansas. This order was initiated given recent
developments at the Federal Energy Regulatory Commission (FERC), other state
regulatory agencies and increased competition among utilities related to large
industrial electric customers. The order was established as a means to define
the KCC's role within the electric generation industry as it may become more
competitive, and address any developments as they may occur. Currently, there
are no proceedings or actions at the KCC which would open the Company's
current electric markets to greater competition, nor establish guidelines at
to a change in the degree of regulatory oversight that the KCC has on the
Company's operations.
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 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.
ELECTRIC OPERATIONS
General
The Company supplies electric energy at retail to approximately 275,000
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:
1995 1994 1993 1992 1991
(Thousands of MWH)
Residential 2,385 2,384 2,386 2,102 2,341
Commercial 2,095 2,068 1,991 1,892 1,908
Industrial 3,542 3,371 3,323 3,248 3,194
Wholesale and
Interchange 1,292 1,590 2,004 1,267 1,168
Other 45 45 45 46 46
Total 9,359 9,458 9,749 8,555 8,657
The Company's electric revenues for the last five years were as follows:
1995 1994 1993 1992 1991
(Dollars in Thousands)
Residential $221,628 $220,067 $219,069 $194,142 $219,907
Commercial 171,654 167,499 162,858 154,005 155,847
Industrial 182,930 181,119 179,256 174,226 172,953
Wholesale and
Interchange 31,143 38,750 45,843 28,086 29,989
Other 16,513 12,445 9,971 6,792 16,272
Total $623,868 $619,880 $616,997 $554,251 $594,968
Capacity
The aggregate net generating capacity of the Company's system is presently
2,501 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 1995 peak system net load occurred on July 11, 1995 and
amounted to 1,855 MW. The Company's net generating capacity together with
power available from firm interchange and purchase contracts, provided a
capacity margin of approximately 17% above system peak responsibility at the
time of the peak.
The Company and ten 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 47 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 103 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
megawatts 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 megawatts in 1994
increasing to 80 megawatts 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 through the
turn of the century (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 1,100 MW of the total 2,501 MW of
generating capacity and the Company's nuclear unit provides 548 MW of
capacity. Of the remaining 853 MW of generating capacity, units that can burn
either natural gas or oil account for 850 MW, and the remaining unit which
burns only diesel fuel accounts for 3 MW (See Item 2. Properties).
During 1995, low sulfur coal was used to produce 52% of the Company's
electricity. Nuclear produced 40% and the remainder was produced from natural
gas, oil, or diesel fuel. During 1996, based on the Company's estimate of the
availability of fuel, coal will to be used to produce approximately 61% of the
Company's electricity and nuclear will be used to produce 31%.
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 is expected to last approximately 60 days
during which time electric demand will be met primarily by the Company's
coal-fired operating units.
Nuclear
The owners of Wolf Creek have on hand or under contract 75% of the uranium
required for operation of Wolf Creek through the year 2003. The balance is
expected to be obtained through spot market and contract purchases. The
Company has four contracts with the following three suppliers for uranium:
Cameco, Geomex Minerals, Inc., and Power Resources, Inc.
The Company has three contracts for uranium enrichment performed by USEC,
Urenco and Nuexco Trading Corp. These contractual arrangements cover 100% of
Wolf Creek's uranium enrichment requirements for 1996-1997, 90% for 1998-1999,
95% for 2000-2001 and 100% for 2005-2014. The balance of the 1998-2005
requirements is expected to be obtained through a combination of spot market
and contract purchases. The decision not to contract for the full enrichment
requirements is one of cost rather than availability of service.
A contractual arrangement is in place with Cameco for the conversion of
uranium to uranium hexafluoride sufficient to meet Wolf Creek's requirements
through the year 2000.
The Company has entered into all of its uranium, uranium enrichment and
uranium hexaflouride arrangements during the ordinary course of business and
is not substantially dependent upon these agreements. The Company believes
there are other suppliers and plentiful sources 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 on-site spent fuel storage facility which, under current
regulatory guidelines, provides space for the storage of spent fuel through
2006 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 operating facility is set forth in
Note 2 of the Notes to 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 $1.13 per MMBtu or $18.71 per
ton during 1995.
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 890 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 672 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. Illinois 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
blend of 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 1998. 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).
For 1996, KCPL has secured Powder River Basin coal from Powder River Coal
Company, a subsidiary of Peabody Coal Company. Transportation is covered by
KCPL through its Omnibus Rail Transportation Agreement with BN and Kansas City
Southern Railroad through December 31, 2000.
During 1995, the average delivered cost of all local and Powder River
Basin coal procured for La Cygne 1 was approximately $0.88 per MMBtu or $15.31
per ton and the average delivered cost of Powder River Basin coal for La Cygne
2 was approximately $0.75 per MMBtu or $12.56 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, 1995, the Company had approximately 676 thousand
gallons of No. 2 oil and 11 million gallons of No. 6 oil which is believed to
be sufficient to meet emergency requirements and protect against lack of
availability of natural gas and/or the loss of a large generating unit.
Other Fuel Matters
The Company's contracts to supply fuel for its coal and natural gas-fired
generating units, with the exception of JEC, do not provide full fuel
requirements at the various stations. Supplemental fuel is procured on the
spot market to provide operational flexibility and, when the price is
favorable, to take advantage of economic opportunities.
Set forth in the table below is information relating to the weighted
average cost of fuel used by the Company.
1995 1994 1993 1992 1991
Per Million Btu:
Nuclear $0.40 $0.36 $0.35 $0.34 $0.32
Coal 0.91 0.90 0.96 1.25 1.32
Gas 1.68 1.98 2.37 1.95 1.74
Oil 4.00 3.90 3.15 4.28 4.13
Cents per KWH Generation 0.82 0.89 0.93 0.98 1.09
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.
The Kansas Department of Health and Environment 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. All facilities
burning coal are equipped with flue gas scrubbers and/or electrostatic
precipitators.
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 installed
continuous monitoring and reporting equipment at a total cost of approximately
$2.3 million. The Company does not expect additional equipment to reduce
sulfur emissions to be necessary under Phase II. 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
Generating Station under the Phase I regulations.
The NOx and toxic limits, which were not set in the law, were proposed by
the EPA in January 1996. The Company is currently evaluating the steps it
will need to take in order to comply with the proposed new rules, but is
unable to determine its compliance options or related compliance costs until
the evaluation is finished later this year. The Company will have three years
to comply with the new rules.
All of the Company's generating facilities are in substantial compliance
with the Best Practicable Technology and Best Available Technology regulations
issued by EPA pursuant to the Clean Water Act of 1977. Most EPA regulations
are administered in Kansas by the Kansas Department of Health and Environment.
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, 1995,
approximately $937 million principal amount of additional first mortgage bonds
could be issued (7.25% interest rate assumed).
KGE bonds may be issued, subject to the restrictions in the preceding
paragraph, on the basis of property additions not subject to an unfunded prior
lien and on the basis of bonds which have been retired. As of December 31,
1995, the Company had approximately $1.3 billion of net bondable property
additions not subject to an unfunded prior lien entitling the Company to issue
up to $922 million principal amount of additional bonds. As of December 31,
1995, $1 million in additional bonds could be issued on the basis of retired
bonds.
REGULATION AND RATES
The Company is subject as an operating electric utility to the
jurisdiction of the Kansas Corporation Commission (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 43 Chairman of the Board Vice President, Finance
and President (since Western Resources, Inc.
June 1995)
Richard D. Terrill 41 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/she
was appointed as an officer.
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, 1995, the Company's gross
property additions totaled $389,689,000 and retirements were $127,740,000.
ELECTRIC FACILITIES
Unit Year Principal Unit Capacity
Name No. Installed Fuel (MW) (2)
Gordon Evans Energy Center:
Steam Turbines 1 1961 Gas--Oil 150
2 1967 Gas--Oil 367
Jeffrey Energy Center (20%) (3):
Steam Turbines 1 1978 Coal 140
2 1980 Coal 147
3 1983 Coal 141
La Cygne Station (50%) (3):
Steam Turbines 1 1973 Coal 341
2 1977 Coal 331
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 (1)
Wichita Plant:
Diesel Generator 5 1969 Diesel 3
Wolf Creek Generating Station (47%)(3):
Nuclear 1 1985 Uranium 548
Total 2,501
(1) This unit has been "mothballed" for future use.
(2) Based on MOKAN rating.
(3) The Company jointly owns Jeffrey Energy Center (20%), La Cygne Station
(50%) and Wolf Creek Generating Station (47%).
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
1995 1994 1993 1992 1991
(Dollars in Thousands)
Income Statement Data:
Operating revenues . . . . . . . $ 623,868 $ 619,880 $ 616,997 $ 554,251 $ 594,968
Operating expenses . . . . . . . 474,864 470,869 469,616 424,089 468,885
Operating income . . . . . . . . 149,004 149,011 147,381 130,162 126,083
Net income . . . . . . . . . . . 110,873 104,526 108,103 77,981 53,602
Balance Sheet Data:
Gross electric plant in service. $3,427,928 $3,390,406 $3,339,832 $3,293,365 $2,468,959
Construction work in progress. . 40,810 32,874 28,436 29,634 13,612
Total assets . . . . . . . . . . 3,203,414 3,237,684 3,187,479 3,279,232 2,350,546
Long-term debt . . . . . . . . . 684,082 699,992 653,543 871,652 850,851
Interest coverage ratio (before
income taxes, including
AFUDC) . . . . . . . . . . . . 4.11 4.02 3.58 2.35 1.90
Ratio of Earnings to Fixed Charge 2.58 2.61 2.60 1.89 1.59
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FINANCIAL CONDITION
GENERAL: The Company had net income of $110.9 million for 1995 compared
to net income of $104.5 million in 1994. The increase in net income is
primarily due to increased retail sales and the receipt of death benefit
proceeds from corporate-owned life insurance policies in the fourth quarter of
1995.
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 1995, construction expenditures for the Company's electric system
were approximately $65 million and nuclear fuel expenditures were
approximately $28 million. It is projected that adequate capacity margins
will be maintained through the turn of the century. The construction program
is focused on providing service to new customers and improving present
electric facilities.
Capital expenditures for 1996 through 1998 are anticipated to be as
follows:
Electric Nuclear Fuel
(Dollars in Thousands)
1996. . . . . . . . . . $51,800 $ 3,300
1997. . . . . . . . . . 51,900 22,300
1998. . . . . . . . . . 49,200 20,800
These expenditures are estimates prepared for planning purposes and are
subject to revisions.
The Company's net cash flows to capital expenditures exceeded 100% for
1995 and during the last five years has also averaged in excess of 100%. This
ratio indicates the extent to which the Company is able to fund its capital
expenditures with cash flow from operating activities. This ratio is
calculated from the Company's Statements of Cash Flows as net cash flow from
operating activities, less changes in working capital, less dividends on
common stock, divided by additions to utility plant. The Company anticipates
all of its cash requirements for capital expenditures through 1998 will be
provided from net cash flows. The Company also has $16 million of bonds
maturing through 2000, all in 1996, which will be provided from internal and
external sources available under then existing financial conditions.
The embedded cost of long-term debt was 7.3% at December 31, 1995 and
December 31, 1994.
In 1986, the Company purchased corporate-owned life insurance policies
(COLI) on certain of its employees. The annual cash outflow for the premiums
on these policies was approximately $30 million for 1995 and $27 million for
1994 and 1993. In June, 1995, the Company increased its borrowings against
the accumulated cash surrender values of the policies by $45 million. Total
1995 COLI borrowings amounted to $353 million. See Note 1 of the Notes to
Financial Statements for additional information on the accumulated cash
surrender value. 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 (See Note 1).
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 $50 million at
December 31, 1995 and December 31. 1994.
The Company's capital structure at December 31, 1995, was 63% common stock
equity and 37% long-term debt. The capital structure at December 31, 1995,
including short-term debt was 61% common stock equity and 39% 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 KCC and the 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, competition from other sources of energy, competing fuel sources,
customer conservation efforts and the overall economy of the Company's service
area.
In March 1992, in connection with the acquisition of the Company by
Western Resources, the KCC approved the elimination of the Energy Cost
Adjustment Clause (ECA) for most retail customers of the Company effective
April 1, 1992. The fuel costs are now included in base rates and were
established at a level intended by the KCC to equal the projected average cost
of fuel through August 1995. Therefore, if the Company wished to recover an
increase in fuel costs above the projected average cost it would have to file
a request for recovery in a rate filing with the KCC which request could be
denied in whole or in part. The Company's fuel costs represented 22% and 24%
of its total operating expenses for the years ended December 31, 1995 and
1994, respectively. Any increase in fuel costs from the projected average
which the Company did not recover through rates would impact the Company's
earnings. The degree of any such impact would be affected by a variety of
factors, however, and thus cannot now be predicted.
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. The Company has filed an
electric rate reduction request with the KCC (See Note 3).
1994 Compared to 1993: Total operating revenues for 1994 of $619.9
million increased less than one percent from revenues of $617.0 million for
1993. The increase can be attributed to higher revenues in all retail
customer classes. While residential sales remained virtually unchanged,
commercial and industrial sales increased over two percent during 1994.
Partially offsetting these increases was a 21% decrease in wholesale and
interchange sales as a result of higher than normal sales in 1993 to other
utilities while their generating units were down due to the flooding of 1993.
OPERATING EXPENSES
1995 Compared to 1994: Total operating expenses for 1995 were $474.9
million compared to $470.9 million for 1994, an increase of less than 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.
The Company has filed a request with the KCC to increase the annual
depreciation expense for Wolf Creek Generating Station (See Note 3). The
Company anticipates its operating expenses (including fuel expenses) will
increase in 1996 as a result of Wolf Creek being taken out of service for
refueling and maintenance as discussed under "Fuel Mix" above.
1994 Compared to 1993: Total operating expenses for 1994 of $470.9
million increased slightly from total operating expenses of $469.6 million for
1993. Federal and state income taxes increased $13.5 million and maintenance
expense increased three percent primarily as a result of the major boiler
overhaul of the Company's coal fired La Cygne 1 generating station.
The increase in income tax expense was due to the completion at December
31, 1993, of the accelerated amortization of deferred income tax reserves
related to the allowance for borrowed funds used during construction
capitalized for Wolf Creek. The completion of the amortization of these
deferred income tax reserves increased income tax expense and thereby reduced
net income by approximately $12 million in 1994, and in the future will reduce
net income by this same amount each year.
Partially offsetting the increases in total operating expenses were lower
fuel costs, due to decreased electric generation during 1994, and lower other
operations expense.
OTHER INCOME AND DEDUCTIONS: 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 (See Notes 1 and 7 for discussion of current
legislation affecting COLI).
Other income and deductions, net of taxes, decreased significantly in 1994
compared to 1993 primarily as a result of increased interest expense on higher
COLI borrowings. Interest on COLI borrowings increased $9.1 million in 1994
compared to 1993. Also contributing to the decrease was the receipt of death
benefit proceeds from COLI policies in the third quarter of 1993.
INTEREST CHARGES: The Company's embedded cost of long-term debt was 7.3%
at December 31, 1995 and December 31, 1994 compared to 7.7% at December 31,
1993.
Interest charges decreased 12% in 1994 compared to 1993 primarily as a
result of the refinancing of higher cost fixed-rate debt. Also accounting for
the decrease was the impact of increased COLI borrowings which reduce the need
for other long-term debt and thereby reduced interest expense. COLI interest
is reflected in Other Income and Deductions on the Income Statement.
MERGER IMPLEMENTATION: In accordance with the KCC Merger order,
amortization of the acquisition adjustment commenced in August 1995. The
amortization will amount to approximately $20 million (pre-tax) per year for
40 years. Western Resources and the Company (combined companies) can recover
the amortization of the acquisition adjustment through cost savings under a
sharing mechanism approved by the KCC.
Based on the order issued by the KCC, with regard to the recovery of the
acquisition premium, the combined companies must achieve a level of savings on
an annual basis (considering sharing provisions) of approximately $27 million
in order to recover the entire acquisition premium. To the extent that the
combined companies actual operations and maintenance expense is lower than the
KCC-stipulated utility price index, the combined companies will realize merger
savings. Western Resources has calculated, in conformance with the KCC order,
annual savings associated with the acquisition to be in excess of $27 million
for 1995. 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 (See Note 3).
Although the Company currently has no Phase I affected units under the
Clean Air Act of 1990, the Company has applied for and has been accepted for
an early substitution permit to bring the co-owned La Cygne Generating Station
under the Phase I guidelines. The NOx and toxic limits, which were not set in
the law, were proposed by the EPA in January 1996. The Company is currently
evaluating the steps it will need to take in order to comply with the proposed
new rules, but is unable to determine its compliance options or related
compliance costs until the evaluation is finished later this year. The
Company will have three years to comply with the new rules. (See Note 3).
COMPETITION: As a regulated utility, the Company currently has limited
direct competition for retail electric service in its certified service area.
However, there is competition, based largely on price, from the generation, or
potential generation, of electricity by large commercial and industrial
customers, and independent power producers.
The 1992 Energy Policy Act (Act) requires increased efficiency of energy
usage and has effected the way electricity is marketed. The Act also provides
for increased competition in the wholesale electric market by permitting the
FERC to order third party access to utilities' transmission systems and by
liberalizing the rules for ownership of generating facilities. As part of the
Merger, the Company agreed to open access of its transmission system for
wholesale transactions. During 1995, wholesale revenues represented less than
five percent of the Company's total revenues.
Operating in this competitive environment could 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 Note 1 for the effects of competition on Statement
of Financial Accounting Standards No. 71).
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 will lose a major
industrial customer to cogeneration resulting in a reduction to pre-tax
earnings of approximately $7 to $8 million annually. This customer's decision
to develop its own cogeneration project was based largely on factors other
than energy cost.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 19
Financial Statements:
Balance Sheets, December 31, 1995 and 1994 20
Statements of Income for the years ended
December 31, 1995, 1994 and 1993 21
Statements of Cash Flows for the years ended
December 31, 1995, 1994 and 1993 22
Statements of Taxes for the years ended
December 31, 1995, 1994 and 1993 23
Statements of Capitalization, December 31, 1995 and 1994 24
Statements of Common Stock Equity for the years ended
December 31, 1995, 1994 and 1993 25
Notes to Financial Statements 26
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the
conditions under which they are required or the information is included
in the financial statements and schedules presented:
I, II, III, IV, and V.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Kansas Gas and Electric Company:
We have audited the accompanying balance sheets and statements of
capitalization of Kansas Gas and Electric Company (a wholly-owned subsidiary
of Western Resources, Inc.) as of December 31, 1995 and 1994, 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, 1995. 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 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, 1995 and 1994, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1995, in conformity with generally accepted accounting principles.
As explained in Note 7 to the financial statements, effective January 1, 1993,
the Company changed its method of accounting for postretirement benefits and
effective January 1, 1994, the Company changed its method of accounting for
postemployment benefits.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
January 26, 1996
KANSAS GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Dollars in Thousands)
December 31,
1995 1994
ASSETS
UTILITY PLANT:
Electric plant in service (Notes 1 and 11). . . . . . . . $3,427,928 $3,390,406
Less - Accumulated depreciation . . . . . . . . . . . . . 893,728 833,953
2,534,200 2,556,453
Construction work in progress . . . . . . . . . . . . . . 40,810 32,874
Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 53,942 39,890
Net utility plant . . . . . . . . . . . . . . . . . . . 2,628,952 2,629,217
OTHER PROPERTY AND INVESTMENTS:
Decommissioning trust (Note 2). . . . . . . . . . . . . . 25,070 16,944
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 7,885 11,561
32,955 28,505
CURRENT ASSETS:
Cash and cash equivalents (Note 1). . . . . . . . . . . . 53 47
Accounts receivable and unbilled revenues (net)(Note 1) . 76,490 67,833
Advances to parent company (Note 13). . . . . . . . . . . 34,948 64,393
Fossil fuel, at average cost, . . . . . . . . . . . . . . 17,522 13,752
Materials and supplies, at average cost . . . . . . . . . 31,458 30,921
Prepayments and other current assets. . . . . . . . . . . 17,128 16,662
177,599 193,608
DEFERRED CHARGES AND OTHER ASSETS:
Deferred future income taxes (Note 8) . . . . . . . . . . 208,367 197,663
Deferred coal contract settlement costs (Note 3). . . . . 14,612 17,944
Phase-in revenues (Note 3). . . . . . . . . . . . . . . . 43,861 61,406
Other deferred plant costs. . . . . . . . . . . . . . . . 31,539 31,784
Corporate-owned life insurance (net) (Notes 1 and 7). . . 7,279 9,350
Unamortized debt expense. . . . . . . . . . . . . . . . . 25,605 27,777
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 32,645 40,430
363,908 386,354
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $3,203,414 $3,237,684
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Statements):
Common stock equity . . . . . . . . . . . . . . . . . . . $1,186,077 $1,225,204
Long-term debt (net). . . . . . . . . . . . . . . . . . . 684,082 699,992
1,870,159 1,925,196
CURRENT LIABILITIES:
Short-term debt (Note 4). . . . . . . . . . . . . . . . . 50,000 50,000
Long-term debt due within one year (Note 5) . . . . . . . 16,000 -
Accounts payable. . . . . . . . . . . . . . . . . . . . . 50,783 49,093
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 17,766 15,737
Accrued interest. . . . . . . . . . . . . . . . . . . . . 7,903 8,337
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,608 11,160
149,060 134,327
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred income taxes (Note 8). . . . . . . . . . . . . . 800,934 784,043
Deferred investment tax credits (Note 8). . . . . . . . . 72,970 74,841
Deferred gain from sale-leaseback (Note 6). . . . . . . . 242,700 252,341
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 67,591 66,936
1,184,195 1,178,161
COMMITMENTS AND CONTINGENCIES (Notes 2 and 9)
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . $3,203,414 $3,237,684
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF INCOME
(Dollars in Thousands)
Year Ended December 31,
1995 1994 1993
OPERATING REVENUES (Notes 1 and 3). . . . . . . . . . . $ 623,868 $ 619,880 $ 616,997
OPERATING EXPENSES:
Fuel used for generation:
Fossil fuel . . . . . . . . . . . . . . . . . . . . 80,592 90,383 93,388
Nuclear fuel. . . . . . . . . . . . . . . . . . . . 19,425 13,562 13,275
Power purchased . . . . . . . . . . . . . . . . . . . 4,577 7,144 9,864
Other operations. . . . . . . . . . . . . . . . . . . 117,876 115,060 118,948
Maintenance . . . . . . . . . . . . . . . . . . . . . 48,056 47,988 46,740
Depreciation and amortization . . . . . . . . . . . . 79,679 71,457 75,530
Amortization of phase-in revenues . . . . . . . . . . 17,545 17,544 17,545
Taxes (See Statements):
Federal income. . . . . . . . . . . . . . . . . . . 48,330 50,212 39,553
State income . . . . . . . . . . . . . . . . . . . 12,543 12,427 9,570
General . . . . . . . . . . . . . . . . . . . . . . 46,241 45,092 45,203
Total operating expenses. . . . . . . . . . . . . 474,864 470,869 469,616
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 149,004 149,011 147,381
OTHER INCOME AND DEDUCTIONS:
Corporate-owned life insurance (net). . . . . . . . . (2,668) (5,354) 7,841
Miscellaneous (net) . . . . . . . . . . . . . . . . . 4,884 5,079 9,271
Income taxes (net) (See Statements) . . . . . . . . . 9,086 7,290 2,227
Total other income and deductions . . . . . . . . 11,302 7,015 19,339
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 160,306 156,026 166,720
INTEREST CHARGES:
Long-term debt. . . . . . . . . . . . . . . . . . . . 47,073 47,827 53,908
Other . . . . . . . . . . . . . . . . . . . . . . . . 5,190 5,183 6,075
Allowance for borrowed funds used
during construction (credit). . . . . . . . . . . . (2,830) (1,510) (1,366)
Total interest charges. . . . . . . . . . . . . . 49,433 51,500 58,617
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 110,873 $ 104,526 $ 108,103
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31,
1995 1994 1993
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 110,873 $ 104,526 $ 108,103
Depreciation and amortization . . . . . . . . . . . . . . 72,950 71,457 75,530
Other amortization (including nuclear fuel) . . . . . . . 15,193 10,905 11,254
Gain on sales of utility plant (net of tax) . . . . . . . (951) - -
Deferred taxes and investment tax credits (net) . . . . . 3,851 25,349 22,572
Amortization of phase-in revenues . . . . . . . . . . . . 17,545 17,544 17,545
Corporate-owned life insurance. . . . . . . . . . . . . . (28,548) (17,246) (21,650)
Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (9,640) (9,640)
Amortization of acquisition adjustment. . . . . . . . . . 6,729 - -
Changes in working capital items:
Accounts receivable and unbilled
revenues (net) (Note 1) . . . . . . . . . . . . . . . (8,657) (56,721) (569)
Fossil fuel . . . . . . . . . . . . . . . . . . . . . . (3,770) (6,158) 8,507
Accounts payable. . . . . . . . . . . . . . . . . . . . 1,690 (2,002) (9,813)
Interest and taxes accrued. . . . . . . . . . . . . . . 967 4,508 (9,053)
Other . . . . . . . . . . . . . . . . . . . . . . . . . (1,980) (922) (2,191)
Changes in other assets and liabilities . . . . . . . . . 14,525 (11,181) (16,530)
Net cash flows from operating activities. . . . . . . 190,777 130,419 174,065
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant. . . . . . . . . . . . . . . . 93,938 89,880 66,886
Sales of utility plant. . . . . . . . . . . . . . . . . . (1,723) - -
Corporate-owned life insurance policies . . . . . . . . . 30,347 26,418 27,268
Death proceeds of corporate-owned life insurance. . . . . (10,583) - (10,160)
Net cash flows used in investing activities . . . . . 111,979 116,298 83,994
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt (net) . . . . . . . . . . . . . . . . . . - (105,800) 62,300
Advances to parent company (net). . . . . . . . . . . . . 29,445 128,399 (118,503)
Bonds issued. . . . . . . . . . . . . . . . . . . . . . . - 160,422 65,000
Bonds retired . . . . . . . . . . . . . . . . . . . . . . (25) (46,440) (140,000)
Other long-term debt issued . . . . . . . . . . . . . . . - - 70,999
Other long-term debt retired. . . . . . . . . . . . . . . - (67,893) (63,956)
Borrowings against life insurance policies. . . . . . . . 47,046 42,175 184,550
Repayment of borrowings against life insurance policies . (5,258) - (1,290)
Revolving credit agreement (net). . . . . . . . . . . . . - - (150,000)
Dividends to parent company . . . . . . . . . . . . . . . (150,000) (125,000) -
Net cash flows from (used in) financing activities . . (78,792) (14,137) (90,900)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . 6 (16) (829)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . . . 47 63 892
CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . . . $ 53 $ 47 $ 63
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID FOR:
Interest on financing activities (net of amount
capitalized) . . . . . . . . . . . . . . . . . . . . $ 71,808 $ 68,544 $ 77,653
Income taxes . . . . . . . . . . . . . . . . . . . . . . 42,100 28,509 29,354
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF TAXES
(Dollars in Thousands)
Year Ended December 31,
1995 1994 1993
FEDERAL INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . $ 34,661 $ 24,427 $ 19,220
Deferred (net). . . . . . . . . . . . . . . . . . . 9,528 23,002 16,691
Investment tax credit-Deferral. . . . . . . . . . . - - 4,900
-Amortization. . . . . . . . . (3,314) (3,208) (3,114)
Total Federal income taxes . . . . . . . . . . . 40,875 44,221 37,697
Less:
Federal income taxes applicable
to non-operating items . . . . . . . . . . . . . (7,455) (5,991) (1,856)
Total Federal income taxes charged to operations. . 48.330 50,212 39,553
STATE INCOME TAXES:
Payable currently . . . . . . . . . . . . . . . . . 13,275 5,574 5,104
Deferred (net). . . . . . . . . . . . . . . . . . . (2,363) 5,554 4,095
Total State income taxes . . . . . . . . . . . . 10,912 11,128 9,199
Less:
State income taxes applicable
to non-operating items . . . . . . . . . . . . . (1,631) (1,299) (371)
Total State income taxes charged to operations. . . 12.543 12,427 9,570
GENERAL TAXES:
Property. . . . . . . . . . . . . . . . . . . . . . 40,827 40,104 38,432
Payroll and other taxes . . . . . . . . . . . . . . 5,414 4,988 6,771
Total general taxes charged to operations. . . . 46.241 45,092 45,203
TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . $ 107.114 $ 107,731 $ 94,326
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, 1995 1994 1993
EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . 32% 35% 30%
Effect of:
State income taxes. . . . . . . . . . . . . . . . . (4) (5) (4)
Amortization of investment tax credits. . . . . . . 2 2 2
Corporate-owned life insurance. . . . . . . . . . . 5 4 5
Flow through and amortization, net. . . . . . . . . - (1) 5
Other differences . . . . . . . . . . . . . . . . . - - (3)
STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . 35% 35% 35%
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
December 31,
1995 1994
COMMON STOCK EQUITY (See Statements):
Common stock, without par value, authorized and issued
1,000 shares. . . . . . . . . . . . . . . . . . . . . . . $1,065,634 $1,065,634
Retained earnings . . . . . . . . . . . . . . . . . . . . . 120,443 159,570
Total common stock equity . . . . . . . . . . . . . . . . 1,186,077 63% 1,225,204 64%
LONG-TERM DEBT (Note 5):
First Mortgage Bonds:
Series Due 1995 1994
5-5/8% 1996 $ 16,000 $ 16,000
7.6% 2003 135,000 135,000
6-1/2% 2005 65,000 65,000
6.20% 2006 100,000 100,000
316,000 316,000
Pollution Control Bonds:
5.10% 2023 13,957 13,982
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
387,897 387,922
Total bonds. . . . . . . . . . . . . . . . . . . . . . 703,897 703,922
Less:
Unamortized premium and discount (net). . . . . . . . . . 3,815 3,930
Long-term debt due within one year. . . . . . . . . . . . 16,000 -
Total long-term debt . . . . . . . . . . . . . . . . . 684,082 37% 699,992 36%
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . $1,870,159 100% $1,925,196 100%
Market-Adjusted Tax Exempt Securities (MATES). The interest rate is reset
periodically via an auction process. Rates at December 31, 1995: (1) 4.00%,
(2) 3.925%, and (3) 4.00%.
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
STATEMENTS OF COMMON STOCK EQUITY
(Dollars in Thousands)
Common Retained
Stock Earnings
BALANCE DECEMBER 31, 1992, 1,000 shares. . . . . . . $1,065,634 $ 71,941
Net income . . . . . . . . . . . . . . . . . . . . . 108,103
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
The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 275,000 electric customers in southeastern
Kansas.
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 follows the accounting for regulated enterprises prescribed
by Statement of Financial Accounting Standards No. 71 "Accounting for the
Effects of Certain Types of Regulations" (SFAS 71). This pronouncement
requires deferral of certain costs and obligations based upon approvals
received from regulators to permit recovery or require refund of these costs
and revenues in future periods. Consequently, the recorded net book value of
certain assets and liabilities may be different than that which would
otherwise be recorded by unregulated enterprises. On a continuing basis, the
Company reviews the continued applicability of SFAS 71 based on the current
regulatory and competitive environment. Although recent developments suggest
the electric generation industry may become more competitive, the degree to
which regulatory oversight of the Company will be lifted and competition will
be permitted is uncertain. Currently, there are no proceedings or actions at
the KCC to open the Company's electric markets to greater competition. As a
result, the Company continues to believe that accounting under SFAS 71 is
appropriate. If the Company were to determine that the use of SFAS 71 were no
longer appropriate, it would be required to write-off the deferred costs and
obligations that represent regulatory assets and liabilities referred to
above. It may also be necessary for the Company to reduce the carrying value
of a portion of its plant and equipment to the extent that it is expected to
become impaired. At this time, it is not possible to estimate the amount of
the Company's plant and equipment, if any, that would be considered
unrecoverable in such circumstances, as the effect of any future competition
on the Company's rates is not clear at this time.
Utility Plant: Utility plant (including plant acquisition adjustment) 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 6.39% for 1995, 4.07% for 1994, and
4.41% for 1993. 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, 1995 totaled $6.7 million.
In March 1995, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
(SFAS 121). This Statement imposes stricter criteria for regulatory assets by
requiring that such assets be probable of future recovery at each balance
sheet date. The Company will adopt this standard on January 1, 1996 and does
not expect that adoption will have a material impact on the financial position
or results of operations based on the Company's current regulatory structure.
This conclusion may change in the future if increases in competition influence
regulation and wholesale and retail pricing in the electric industry.
Depreciation: Depreciation is provided on the straight-line method based
on estimated useful lives of property. Composite provisions for book
depreciation approximated 2.72% during 1995, 2.7% during 1994, and 2.9% during
1993 of the average original cost of depreciable property. The methods and
rates of depreciation used by the Company have not varied materially from the
methods and rates which would have been used if the Company were not regulated
and not subject to the provisions prescribed by SFAS 71. 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. The Company has proposed to more rapidly recover
the Company's investment in nuclear generating assets of Wolf Creek to reduce
the capital costs to a level more closely paralleling that of non-nuclear
generating facilities
(For information regarding such proposal, See Note 3).
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 (See
Note 8).
Investment tax credits previously deferred are being amortized to income
over the life of the property which gave rise to the credits.
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 $21.8 million and $21.4 million are recorded as
a component of accounts receivable and unbilled revenue (net) on the balance
sheets as of December 31, 1995 and 1994, respectively.
The Company's recorded reserves for doubtful accounts receivable totaled
$3.3 million and $1.9 million at December 31, 1995 and 1994, 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.
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, 1995 and 1994, was $28.5 and $13.6 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:
1995 1994
(Dollars in Millions)
Cash surrender value of contracts. . . $360.3 $320.6
Borrowings against contracts . . . . . (353.0) (311.2)
COLI (net) . . . . . . . . . . . . $ 7.3 $ 9.4
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 $22.7 million for 1995, $15.6
million for 1994, and $19.7 million for 1993. The interest expense deduction
taken was $25.4 million for 1995, $21.0 million for 1994, and $11.9 million
for 1993.
Federal legislation is pending, which, if enacted, may substantially
reduce or eliminate the tax deduction for interest on COLI borrowings, and
thus reduce a significant portion of the net income stream generated by the
COLI contracts (see Note 7).
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 analysis. The prioritized sites will
be investigated over a 10 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 1995 and 1994 were minimal. The
Company is aware of other Midwestern utilities which have incurred remediation
costs ranging between $500,000 and $10 million per site. The KCC has
permitted another Kansas utility to recover its remediation costs through
rates. 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 June 9, 1994, the KCC issued an order approving the estimated
decommissioning costs as determined by a 1993 Wolf Creek Decommissioning Cost
Study to be recovered in rates. The cost study estimated the Company's share
of decommissioning costs to be $595 million or approximately $174 million in
1993 dollars. The decommissioning costs are currently expected to be incurred
during the period 2025 through 2033. These costs were calculated using an
assumed inflation rate of 3.45% and an average after tax expected return on
trust fund assets of 5.9%. Decommissioning costs are being charged to
operating expenses in accordance with the KCC order. Amounts expensed
approximated $3.6 million in 1995 and will increase annually to $5.5 million
in 2024.
The Company's investment in the decommissioning fund, including
reinvested earnings approximated $25.0 million and $16.9 million at December
31, 1995 and December 31, 1994, respectively. Trust fund earnings accumulate
in the fund balance and increase the recorded decommissioning liability.
These amounts are reflected in Decommissioning Trust, and the related
liability is included in Deferred Credits and Other Liabilities, Other, on the
Consolidated 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 FASB is expected to
issue new accounting standards for removal costs, including decommissioning in
1996. 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. At this time, 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.
The Company carries premature decommissioning insurance which has several
restrictions. One of these is that it can only be used if Wolf Creek incurs
an accident exceeding $500 million in expenses to safely stabilize the
reactor, to decontaminate the reactor and reactor station site in accordance
with a plan approved by the Nuclear Regulatory Commission (NRC), and to pay
for on-site property damages. This decommissioning insurance will only be
available if the insurance funds are not needed to implement the NRC-approved
plan for stabilization and decontamination.
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
for property damage or premature decommissioning costs up to $1.3 billion
(Company's share). Premature decommissioning insurance cost recovery is
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 $11
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 installed
continuous monitoring and reporting equipment at a total cost of approximately
$2.3 million from 1993 through 1995. The Company does not expect additional
equipment acquisitions or other material expenditures to be needed to meet
Phase II sulfur dioxide requirements.
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, 1995, WCNOC's
nuclear fuel commitments (Company's share) were approximately $15.3 million
for uranium concentrates expiring at various times through 2001, $120.8
million for enrichment expiring at various times through 2014, and $72.7
million for fabrication through 2025. At December 31, 1995, the Company's
coal contract commitments in 1995 dollars under the remaining terms of the
contracts were approximately $643 million. The largest coal contract expires
in 2020, with the remaining coal contracts expiring at various times through
2013.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment
is being collected from utilities for a uranium enrichment decontamination and
decommissioning fund. The Company's portion of the assessment for Wolf Creek
is approximately $7 million, payable over 15 years. Management expects such
costs to be recovered through the ratemaking process.
3. RATE MATTERS AND REGULATION
KCC Rate Proceedings: 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. If the request is granted, depreciation expense
for Wolf Creek will increase by approximately $50 million for each of the next
seven years. As a result of this proposal, the Company will also seek to
reduce electric rates for its customers by approximately $9 million annually
for the same seven year period.
The request also reduces the annual depreciation by approximately $3
million for electric transmission, distribution and certain generating plant
assets to reflect the effect of increasing useful lives of these properties.
Hearings before the KCC on the depreciation changes and voluntary rate
reductions are expected to occur in May 1996.
Rate Stabilization Plan: 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, 1995, approximately
$44 million of deferred phase-in revenues remain to be recovered.
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 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. Approximately $15 million of this deferral remains on the balance
sheet at December 31, 1995.
In February 1991, the Company paid $8.5 million to settle a coal contract
lawsuit with AMAX Coal Company and recorded the payment as a deferred charge
in Deferred Charges and Other Assets on the balance sheet. The KCC approved
the recovery of the settlement plus a return equivalent to the carrying cost
of the asset, over the remaining term of the terminated contract (through
1996).
4. SHORT-TERM BORROWINGS
The Company's short-term financing requirements are satisfied through
short-term bank loans and uncommitted loan participation agreements. Maximum
short-term borrowings outstanding during 1995 and 1994 were $75.8 million on
January 17, 1995 and $172.3 million on January 4, 1994. The weighted average
interest rates, including fees, were 6.1% for 1995, 4.5% for 1994, and 3.5%
for 1993.
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. During 1996, $16 million of bonds
will mature.
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, 1995, approximately $23.7
million of this deferral remained 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 2000 and $646
million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale
of La Cygne 2 has been deferred for financial reporting purposes, and is being
amortized ($9.6 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 1995, 1994, and 1993.
7. EMPLOYEE BENEFIT PLANS
Pension: In 1995, the Company's qualified noncontributory defined benefit
pension plan was merged into Western Resources, Inc. Retirement Plan (the
Plan). The Plan covers substantially all employees of the Company. Pension
benefits under the Plan are based on years of service and the employee's
compensation during the five highest paid consecutive years out of ten before
retirement. Western Resources' policy is to fund pension costs accrued,
subject to limitations set by the Employee Retirement Income Security Act of
1974 and the Internal Revenue Code. Pension expense of $1.6 million was
allocated to the Company by Western Resources in 1995. Also, substantially
all Wolf Creek employees are covered under a plan similar to the Plan.
The following table provides information on the components of pension
cost under Statement of Financial Accounting Standards No. 87 "Employers'
Accounting for Pension Plans" (SFAS 87), funded status and actuarial
assumptions for the Company:
1995(1) 1994 1993
(Dollars in Millions)
SFAS 87 Expense:
Service cost. . . . . . . . . . . . . . $ 1.2 $ 3.7 $ 3.2
Interest cost on projected
benefit obligation. . . . . . . . . . 1.0 9.7 9.5
(Gain) loss on plan assets. . . . . . . (1.7) 2.1 (14.1)
Net amortization and deferral . . . . . 1.1 (11.4) 4.9
Net expense . . . . . . . . . . . . . $ 1.6 $ 4.1 $ 3.5
The following table sets forth the plans' actuarial present value and
funded status at November 30, 1995 and 1994 (the plan years) and a
reconciliation of such status to the December 31, 1995, 1994, and 1993
financial statements:
1995(1) 1994 1993
(Dollars in Millions)
Reconciliation of Funded Status:
Actuarial present value of
benefit obligations:
Vested. . . . . . . . . . . . . . . $ 7.3 $ 94.0 $ 95.2
Non-vested. . . . . . . . . . . . . 1.9 6.3 6.1
Total . . . . . . . . . . . . . . $ 9.2 $100.3 $101.3
Plan assets at November 30 (principally
debt and equity securities)
at fair value . . . . . . . . . . . . . $ 8.8 $115.4 $119.9
Projected benefit obligation
at November 30 . . . . . . . . . . . . (17.8) (125.4) (125.5)
Funded status at November 30. . . . . . . (9.0) (10.0) (5.6)
Unrecognized transition asset . . . . . . 0.9 (1.5) (1.7)
Unrecognized prior service costs. . . . . 0.4 9.6 12.4
Unrecognized net gain . . . . . . . . . . (0.4) (11.1) (20.6)
Accrued pension costs at December 31. . . $ (8.1) $(13.0) $(15.5)
Year Ended December 31, 1995 1994 1993
Actuarial Assumptions:
Discount rate . . . . . . . . . . 7.5 % 8.0-8.5 % 7.0-7.75%
Annual salary increase rate . . . (2) 5.0 % 5.0 %
Long-term rate of return. . . . . 8.5 % 8.0-8.5 % 8.0-8.5 %
(1) 1995 includes only the Company's 47% share of the Wolf Creek Plan.
(2) Graded based on age: 6.5% at age 20 graded to 4.5% at age 60.
Postretirement: Western Resources and the Company adopted the provisions
of Statement of Financial Accounting Standards No. 106 "Employers' Accounting
for Postretirement Benefits Other Than Pensions" (SFAS 106) in the first
quarter of 1993. This statement requires the accrual of postretirement
benefits other than pensions, primarily medical benefits costs, during the
years an employee provides service.
The Company's total obligation is recorded by Western Resources, and the
related postretirement benefits expenses are allocated to the Company. The
total postretirement benefits expenses allocated to the Company by Western
Resources under SFAS 106 were approximately $3.7 million in 1995 and $3.8
million in 1994.
The KCC issued an order permitting Western Resources to defer the initial
SFAS 106 expense. To mitigate the impact incremental SFAS 106 expense will
have on rate increases, Western Resources will include in future computations
of cost of service the actual postretirement benefits expenses and an income
stream generated from COLI contracts purchased in 1993 and 1992. To the
extent postretirement benefits expenses exceed income from the COLI program,
this excess is being deferred (in accordance with the provisions of the FASB
Emerging Issues
Task Force Issue No. 92-12) and will be offset by income generated through the
deferral period by the COLI program. Because these expenses were deferred by
Western Resources, the Company's results of continuing operations are not
affected.
At December 31, 1995, approximately $7.0 million related to the Company's
portion of postretirement expenses had been deferred by Western Resources
pursuant to the KCC order. Pending federal legislation may substantially
reduce or eliminate tax benefits associated with COLI contracts. If this
legislation is enacted or should the income stream generated by the COLI
program not be sufficient to offset postretirement benefit costs on an accrual
basis, the KCC order allows Western Resources and the Company to seek recovery
of a deficiency through the ratemaking process. Regulatory precedents
established by the KCC generally permit the accrual costs of postretirement
benefits to be recovered in rates.
The Company also records, based on actuarial projections, the
postretirement benefit expenses related to its 47% ownership in Wolf Creek,
which approximated $0.3 million and $0.4 million for 1995 and 1994,
respectively.
The following table summarizes the status of the Company's postretirement
plan for financial statement purposes and the related amounts included in the
balance sheet:
December 31, 1995(2) 1994 1993
(Dollars in Millions)
Reconciliation of Funded Status:
Actuarial present value of postretirement
benefit obligations:
Retirees. . . . . . . . . . . . . . . . . . . $ (1.7) $(12.9) $(12.4)
Active employees fully eligible . . . . . . . - ( 3.0) ( 2.5)
Active employees not fully eligible . . . . . (1.0) ( 9.4) ( 9.0)
Funded status. . . . . . . . . . . . . . . . (2.7) (25.3) (23.9)
Unrecognized prior service cost . . . . . . . - 3.2 .1
Unrecognized transition obligation. . . . . . 0.7 19.3 20.4
Unrecognized net (gain) loss. . . . . . . . . 0.9 (.9) 1.7
Accrued postretirement benefit costs. . . . . . . $ (1.1) $ (3.7) $ (1.7)
Year Ended December 31, 1995 1994 1993
Assumptions:
Discount rate. . . . . . . . . . . . . . . . . 7.5 % 8.0-8.5 % 7.75%
Annual compensation increase rate. . . . . . . 4.75% 5.0 % 5.0 %
Expected rate of return. . . . . . . . . . . . 9.0 % 8.5 % 8.5 %
(2) 1995 includes only the Company's 47% share of the Wolf Creek Plan.
For measurement purposes, an annual health care cost growth rate of 10.5%
was assumed for 1995, decreasing to six percent in 1997. The health care cost
trend rate has a significant effect on the projected benefit obligation.
Increasing the trend rate by one percent each year would increase the present
value of the accumulated projected benefit obligation by $1.4 million and the
aggregate of the service and interest cost components by $0.2 million.
Postemployment: Western Resources and the Company adopted the provisions
of Statement of Financial Accounting Standards No. 112 "Employers' Accounting
for Postemployment Benefits" (SFAS 112) in the first quarter of 1994. This
statement requires the recognition of the liability to provide postemployment
benefits when the liability has been incurred. Due to the immaterial amounts
and the rate treatment from the Company's regulators, there was no material
impact upon the Company's continuing operations.
The Company's total obligation is recorded by Western Resources, and the
related postemployment benefits expenses are allocated to the Company. The
total postemployment benefits expenses allocated to the Company by Western
Resources under SFAS 112 were approximately $0.9 million in 1995 and $0.8
million in 1994, respectively.
The KCC issued an order permitting Western Resources to defer the initial
SFAS 112 expense. At December 31, 1995, approximately $1.9 million related to
the Company's portion of postemployment expenses had been deferred pursuant to
the KCC order.
Savings: Effective January 1, 1995, the Company's 401(k) savings plan
was merged with Western Resources savings plan. Western Resources maintains a
savings plan in which substantially all employees participate. Prior to the
merger of the savings plans, funds of the plans were deposited with a trustee
and invested at each employee's option in one or more investment funds,
including a Western Resources common stock fund. The Company's contributions
were $1.8 million for 1994 and $2.0 million for 1993. In 1995, 401(k)
contribution expense allocated to the Company was $1.7 million.
8. INCOME TAXES
Under SFAS 109, temporary differences gave rise to deferred tax assets
and deferred tax liabilities at December 31, 1995 and 1994, respectively, as
follows:
Deferred Tax Assets: 1995 1994
(Dollars in Thousands)
Deferred gain on sale-leaseback. . . . . $ 105,007 $ 110,556
Alternative Minimum tax carry forwards . 18,740 41,163
Other. . . . . . . . . . . . . . . . . . 10,870 11,253
Total Deferred Tax Assets. . . . . . . $ 134,617 $ 162,972
Deferred Tax Liabilities:
Accelerated Depreciation & Other . . . . $ 375,079 $ 381,800
Acquisition Premium. . . . . . . . . . . 314,933 317,610
Deferred Future Income Taxes . . . . . . 208,367 197,663
Other. . . . . . . . . . . . . . . . . . 37,172 49,942
Total Deferred Tax Liabilities . . . . $ 935,551 $ 947,015
Accumulated Deferred
Income Taxes, Net $ 800,934 $ 784,043
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.
At December 31, 1995, the Company has alternative minimum tax credits
generated prior to April 1, 1992, which carry forward without expiration, of
$18.7 million which may be used to offset future regular tax to the extent the
regular tax exceeds the alternative minimum tax. These credits have been
applied in determining the Company's net deferred income tax liability and
corresponding deferred future income taxes at December 31, 1995.
9. 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.
10. 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-
The carrying amount approximates the fair value because of the
short-term maturity of these investments.
Decommissioning Trust-
The carrying amount is recorded at the fair value of the
decommissioning trust and is based on quoted market prices at December
31, 1995 and 1994.
Variable-rate Debt-
The carrying amount approximates the fair value because of the
short-term variable rates of these debt instruments.
Fixed-rate Debt-
The fair value of the fixed-rate debt is based on the sum of the
estimated value of each issue taking into consideration the interest
rate, maturity, and redemption provisions of each issue.
The estimated fair values of the Company's financial instruments are as
follows:
Carrying Value Fair Value
December 31, 1995 1994 1995 1994
(Dollars in Thousands)
Cash and cash
equivalents. . . . . . . $ 53 $ 47 $ 53 $ 47
Decommissioning trust. . . 25,070 16,944 25,070 16,633
Variable-rate debt . . . . 449,433 407,645 449,433 407,645
Fixed-rate debt. . . . . . 657,457 657,482 675,471 623,331
11. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1995
In-Service Invest- Accumulated Net Per-
Dates ment Depreciation (MW) cent
(Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 155,566 $ 99,133 341 50
Jeffrey 1 (b) Jul 1978 67,322 28,312 140 20
Jeffrey 2 (b) May 1980 68,151 26,951 147 20
Jeffrey 3 (b) May 1983 96,031 36,333 141 20
Wolf Creek (c) Sep 1985 1,371,878 335,941 548 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.
12. QUARTERLY FINANCIAL STATISTICS (Unaudited)
The amounts in the table are unaudited but, in the opinion of management,
contain all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of the results of such periods. The
business of the Company is seasonal in nature and, in the opinion of
management, comparisons between the quarters of a year do not give a true
indication of overall trends and changes in operations.
1995
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
(Dollars in Thousands)
Operating revenues. . . . . $138,182 $202,382 $144,747 $138,557
Operating income. . . . . . 25,974 63,684 30,779 28,567
Net income. . . . . . . . . 21,598 51,836 19,567 17,872
1994
4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
(Dollars in Thousands)
Operating revenues. . . . . $139,087 $189,202 $154,987 $136,604
Operating income. . . . . . 33,607 56,978 33,548 24,878
Net income. . . . . . . . . 22,212 45,481 23,623 13,210
13. RELATED PARTY TRANSACTIONS
The cash management function, including cash receipts and disbursements,
for KGE is performed by Western Resources. An intercompany account is used to
record net receipts and dusbursements handled by Western Resources. The net
amount advanced by KGE to Western Resources approximated $35 million and $64
million at December 31, 1995 and 1994, 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 1995, the Company declared a dividend to
Western Resources of $150 million.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There were no disagreements with accountants on accounting and financial
disclosure.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Western Resources, Inc. owns 100% of the Company's outstanding common
stock.
A Director
Business Experience Since 1990 and Other Continuously
Name Age Directorships Other Than The Company Since
William B. 43 Chairman of the Board and President 1995
Moore (since June 1995), and prior to that
Vice President, Finance, Western
Resources, Inc.
Robert T. 70 Owner, Crain Realty, Co., Fort Scott, 1992(b)
Crain Kansas
(a) Directorships
Citizens National Bank
Ft. Scott Industries, Inc.
Anderson E. 62 President, Jackson Mortuary, Wichita, 1994
Jackson Kansas
Donald A. 62 Retired President, Maupintour, Inc., 1992(b)
Johnston Lawrence, Kansas (Escorted Tours
(a) And Travel)
Directorships
Commerce Bank, Lawrence
Steven L. 50 Executive Vice President and Chief 1992
Kitchen Financial Officer, Western Resources,
Inc.
Glenn L. 70 Retired Vice President - Nuclear of the 1992(b)
Koester Company
Marilyn B. 46 President, Wichita (since October 1993) 1994
Pauly and prior to that Executive Vice
(a) President, Wichita, Bank IV, N.A.,
Wichita, Kansas
Directorships
Farmers Mutual Alliance Insurance Company
Richard D. 62 President, Range Oil Company 1993
Smith Directorships
Boatmen's National Bank of 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. Crain, Mr. Johnston, and Mr. Koester were directors of the
former Kansas Gas & Electric Company since 1981, 1980, and 1986,
respectively.
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 1995, the Board of Directors met five times and the Audit
Committee met once. Each director attended at least 75% of the total number
of Board and Committee meetings held while he/she served as a director or a
member of the committee.
Other information required by Item 10 is omitted pursuant to General
Instruction J(2)(c) to Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General
Instruction J(2)(c) to Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by Item 12 is omitted pursuant to General
Instruction J(2)(c) to Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Item 13 is omitted pursuant to General
Instruction J(2)(c) to Form 10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
The following financial statements are included herein under Item 8.
FINANCIAL STATEMENTS
Balance Sheets, December 31, 1995 and 1994
Statements of Income for the year ended December 31, 1995, 1994 and 1993
Statements of Cash Flows for the year ended December 31, 1995, 1994 and 1993
Statements of Taxes for the year ended December 31, 1995, 1994 and 1993
Statements of Capitalization, December 31, 1995 and 1994
Statements of Common Stock Equity for the year ended December 31, 1995
Notes to Financial Statements
REPORTS ON FORM 8-K
None
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
2(a) 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)1 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
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)1 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)
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, 1996 By WILLIAM B. MOORE
William B. Moore, Chairman of the Board
and President