Annual Report (Form 10-K), fiscal year 1993

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 (KG&E) for $454 million in cash and 23,479,380 shares of Western Resources common stock (the Merger). Western Resources also paid approximately $20 million in costs to complete the Merger. Simultaneously, KCA and Kansas Gas and Electric Company merged and adopted the name Kansas Gas and Electric Company (the Company, KG&E).
Additional information relating to the Merger can be found in Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 1 of the Notes to Financial Statements.
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 percent 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, 1993, the Company had no employees. All employees are provided by Western Resources.
As a regulated utility, the Company does not have 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 Company's business is subject to seasonal fluctuations with the peak period occurring during the summer. Approximately one-third of residential kilowatthour sales occur in the third quarter. Accordingly, earnings and revenue information for any quarterly period should not be considered as a basis for estimating results of operations for a full year.
Electric utilities have been experiencing problems such as controversy over the safety and use of coal and nuclear power plants, compliance with changing environmental requirements, long construction periods required to complete new generating units resulting in high fixed costs for those facilities, difficulties in obtaining timely and adequate rate relief to recover these high fixed costs, uncertainties in predicting future load requirements, competition from independent power producers and cogenerators, and the effects of changing accounting standards.
The problems which most significantly affect the Company are the use, or potential use, of cogeneration and self-generation facilities by large commercial and industrial customers, and compliance with environmental requirements. For additional information see Management's Discussion and Analysis and Notes 3 and 4 of the Notes to Financial Statements.
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 268,000 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:
1993 1992 1991 1990 1989 (Thousands of MWH)
Residential 2,386 2,102 2,341 2,270 2,105 Commercial 1,991 1,892 1,908 1,838 1,748 Industrial 3,323 3,248 3,194 3,093 2,978 Other 2,049 1,313 1,214 1,736 2,113 Total 9,749 8,555 8,657 8,937 8,944
The Company's electric revenues for the last five years were as follows:
1993 1992 1991 1990 (1) 1989 (Thousands of Dollars)
Residential $219,069 $194,142 $219,907 $214,544 $187,657 Commercial 162,858 154,005 155,847 151,098 135,740 Industrial 179,256 174,226 172,953 168,294 153,360 Other 55,814 31,878 46,261 52,705 56,776 Total $616,997 $554,251 $594,968 $586,641 $533,533
(1) See Note 4 of the Notes to Financial Statements for impact of rate refund orders.
Capacity. The aggregate net generating capacity of the Company's system is presently 2,472 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 has been "mothballed" for future use (see Item 2.



Item 2. Properties).
The Company's 1993 peak system net load occurred on August 16, 1993 and amounted to 1,811 MW. The Company's net generating capacity together with power available from firm interchange and purchase contracts, provided a capacity margin of approximately 22% 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.
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 Management's Discussion and Analysis, Liquidity and Capital Resources). The Company has capacity available which may not be fully utilized by growth in customer demand for at least 5 years. The Company continues to market this capacity and energy to other utilities.
Fuel Mix. The Company's coal-fired units comprise 1,092 MW of the total 2,472 MW of generating capacity and the Company's nuclear unit provides 533 MW of capacity. Of the remaining 847 MW of generating capacity, units that can burn either natural gas or oil account for 844 MW, and the remaining unit which burns only diesel accounts for 3 MW (see Item 2, Properties).
During 1993, low sulfur coal was used to produce 60% of the Company's electricity. Nuclear produced 33% and the remainder was produced from natural gas, oil, or diesel. Based on the Company's estimate of the availability of fuel, coal will continue to be used to produce approximately 61% of the Company's electricity and 33% from nuclear.
The Company anticipates the fuel mix to fluctuate with the operation of the nuclear powered Wolf Creek which operates on an 18-month refueling and maintenance schedule. The 18-month schedule permits uninterrupted operation every third calendar year. Beginning March 5, 1993, Wolf Creek was taken off- line for its sixth refueling and maintenance outage. The refueling outage took approximately 73 days to complete, during which time electric demand was met primarily by the Company's coal-fired generating units.
Nuclear. The owners of Wolf Creek have on hand or under contract 73 percent of the uranium required for operation of Wolf Creek through the year 2001. The balance is expected to be obtained through spot market and contract purchases.
Contractual arrangements are in place for 100 percent of Wolf Creek's uranium enrichment requirements for 1993-1996, 70 percent for 1997-1998 and 100 percent for 2003-2014. The balance of the 1997-2002 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.
Contractual arrangements are in place for the conversion of uranium to uranium hexafluoride sufficient to meet Wolf Creek's requirements through 1995 as well as the fabrication of fuel assemblies to meet Wolf Creek's requirements through 2012. During 1994, the Company plans to begin securing additional arrangements, for the post 1995 period.
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.
Coal. Western Resources, the operator of Jeffrey Energy Center (JEC) and KG&E (20% interest in JEC), 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 with deficient mmBTU provisions applicable to deficiencies in the scheduled delivery. 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 $1.045 per mmBTU or $17.35 per ton during 1993.
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 770 aluminum rail cars, under a 20 year lease, to transport coal to JEC. During 1994 Western Resources will provide an additional 120 rail cars under a similar lease.
The two coal fired units at La Cygne generating station have an aggregate generating capacity of 677 MW (KG&E's 50 percent share) (see Item 2. Properties). The operator, Kansas City Power & Light Company (KCP&L), maintains coal contracts as discussed in the following paragraphs.
During 1993, La Cygne 1 was converted to use low sulfur Powder River Basin coal which is supplied under the AMAX contract for La Cygne 2, 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 percent Powder River Basin coal. During the third and fourth quarters of 1993, the Company along with the operator secured supplemental Illinois or Kansas/Missouri coal, for blending purposes, on a short-term basis through spot market purchase orders.
La Cygne 2 and additional La Cygne 1 Powder River Basin coal was supplied, through a contract that expired December 31, 1993, by AMAX from its mines in Gillette, Wyoming. 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 1994, the operator has secured Powder River Basin coal, similar to the AMAX coal, from two sources; Carter Mining Company's Caballo Mine, a subsidiary of Exxon Coal USA; and Caballo Rojo Inc's Caballo Rojo Mine, a subsidiary of Drummond Inc. Transportation is covered by KCP&L through its Omnibus Rail Transportation Agreement with BN and Kansas City Southern Railroad through December 31, 1995. An alternative rail transportation agreement with Western Railroad Property, Inc. (WRPI), a partnership between UP and Chicago Northwestern (CNW), lasts through December 31, 1995. The WRPI/UP/CNW agreement is a supplemental access contract to handle tonnages not covered by the Omnibus contract.
During 1993, the average delivered cost of all coal procured for La Cygne 1 was approximately $0.81 per mmBTU or $14.24 per ton and the average delivered cost of Powder River Basin coal for La Cygne 2 was approximately $0.84 per mmBTU or $14.18 per ton.
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 under a firm contract that runs through 1995 by Kansas Gas Supply (KGS). Short-term economical spot market purchases from the Williams Natural Gas (WNG) system provide the Company flexible natural gas 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 each of the coal plants. All oil burned by the Company during the past several years has been obtained by spot market purchases. At December 31, 1993, the Company had approximately 770 thousand gallons of No. 2 oil and 11.5 million gallons of No. 6 oil which is 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.
On March 26, 1992, in connection with the Merger, the Kansas Corporation Commission (KCC) approved the elimination of the Energy Cost Adjustment Clause (ECA) for most Kansas retail customers of the Company effective April 1, 1992. The provisions for fuel costs included in base rates were established at a level intended by the KCC to equal the projected average cost of fuel through August 1995 and to include recovery of costs provided by previously issued orders relating to coal contract settlements and storm damage recovery. Any increase or decrease in fuel costs from the projected average will be absorbed by the Company.
Set forth in the table below is information relating to the weighted average cost of fuel used by the Company. 1993 1992 1991 1990 1989 Per Million BTU: Nuclear $0.35 $0.34 $0.32 $0.34 $0.34 Coal 0.96 1.25 1.32 1.32 1.38 Gas 2.37 1.95 1.74 1.96 1.91 Oil 3.15 4.28 4.13 3.01 3.30
Cents per KWH Generation 0.93 0.98 1.09 1.01 0.96
Environmental Matters. The Company currently holds all Federal and State environmental approvals required for the operation of all 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) 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 percent. Federal nitrogen oxides emission standards applicable to these units prohibit the emission of more than 0.7 pounds of nitrogen oxides 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 nitrogen oxides 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 contracted to purchase low sulfur coal (see Coal) which will allow compliance with such limits at La Cygne. 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 nitrogen oxide emissions effective in 1995 and 2000 and a probable reduction in toxic emissions. To meet the monitoring and reporting requirements under the acid rain program, the Company is installing continuous monitoring and reporting equipment at a total cost of approximately $2.3 million. At December 31, 1993, the Company had completed approximately $850 thousand of these capital expenditures with the remaining $1.4 million of capital expenditures to be completed in 1994 and 1995. The Company does not expect additional equipment to reduce sulfur emissions to be necessary under Phase II. The Company currently has no Phase I affected units.
The nitrogen oxide and toxic limits, which were not set in the law, will be specified in future EPA regulations. The EPA has issued, for public comment, preliminary nitrogen oxide regulations for Phase I group 1 units. Nitrogen oxide regulations for Phase II units and Phase I group 2 units are mandated in the Act to be promulgated by January 1, 1997. Although the Company has no Phase I units, the final nitrogen oxide regulations for Phase 1 group 1 may allow for early compliance for Phase II group 1 units. Until such time as the Phase I group 1 nitrogen oxide regulations are final, the Company will be unable to determine its compliance options or related compliance costs.
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 3 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, 1993, approximately $1 billion principal amount of additional first mortgage bonds could be issued (7.5 percent interest rate assumed).
Additional KG&E 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, 1993, 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 $882 million principal amount of additional bonds. As of December 31, 1993, the Company could also issue up to $115 million bonds on the basis of retired bonds.
REGULATION AND RATES
The Company is subject as an operating electric utility to the jurisdiction of the KCC which has general regulatory authority over the Company's rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts and various other matters. The Company is also subject to the jurisdiction of the FERC and the KCC with respect to the issuance of the Company's securities.
Additionally, the Company is subject to the jurisdiction of the FERC, including jurisdiction as to rates with respect to sales of electricity for resale, and the Nuclear Regulatory Commission as to nuclear plant operations and safety.
Additional information with respect to Regulation and Rates is discussed in Notes 1 and 4 of the Notes to Financial Statements.
EXECUTIVE OFFICERS OF THE COMPANY Other Offices or Positions Name Age Present Office Held During Past Five Years
Kent R. Brown 48 Chairman of the Board, Group Vice President (since June 1992) (1982 to 1992) President and Chief Executive Officer (since March 1992)
Richard D. LaGree 63 Vice President, Field Vice President, Electric Operations (since Distribution Operations, April 1992) (1990 to 1992) Western Resources, Inc. Vice President, Western Region Operations (1985 to 1990) Western Resources, Inc.
Richard D. Terrill 39 Secretary, Treasurer Secretary and Attorney and General Counsel (1983 to 1992) (since April 1992)
The present term of office of each of the executive officers extends to May 3, 1994, or until their respective successors are chosen and appointed by 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 elected 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, 1993, the Company's gross property additions totalled $330,737,000, and retirements were $93,737,000.
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%): Steam Turbines 1 1978 Coal 140 2 1980 Coal 135 3 1983 Coal 140
La Cygne Station (50%): Steam Turbines 1 1973 Coal 342 2 1977 Coal 335
Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 46 2 1954 Gas--Oil 69 3 1956 Gas--Oil 107 4 1959 Gas--Oil 105
Neosho Energy Center: Steam Turbine 3 1954 Gas--Oil 0 (1)
Wichita Plant: Diesel Generator 5 1969 Diesel 3
Wolf Creek Generating Station (47%): Nuclear 1 1985 Uranium 533
Total 2,472
(1) This unit has been "mothballed" for future use.
(2) Based on MOKAN rating.
The Company jointly-owns Jeffrey Energy Center (20%), La Cygne Station (50%) and Wolf Creek Generating Station (47%).
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
Information on legal proceedings involving the Company is set forth in Note 10 of Notes to Financial Statements included herein.
ITEM 4.

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.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
On March 31, 1992, Western Resources through its wholly-owned subsidiary KCA, acquired all of the outstanding common and preferred stock of KG&E. As a result, the Company's common stock was delisted by the New York Stock Exchange and the Pacific Stock Exchange.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION
The results of operations for the year ended December 31, 1993, and the nine months ended December 31, 1992, included herein, refer to the Company following the merger with Western Resources, Inc. (formerly The Kansas Power and Light Company) through its wholly-owned subsidiary, KCA Corporation, on March 31, 1992 (the Merger) (see Note 1).
Pro forma results of operations for the twelve months ended December 31, 1992 presented herein, give effect to the Merger as if it occurred on January 1, 1992 and were derived by combining the historical information for the three month period ended March 31, 1992 and the nine month period ended December 31, 1992. The results of operations for the year ended December 31, 1991, refer to the Company prior to the Merger but are not materially different than if presented on a pro forma basis. Additional information relating to changes between years is provided in the Notes to Financial Statements.
General: The Company had net income of $108.1 million for 1993 compared to pro forma net income of $78 million in 1992. The increase in net income is a result of the increase in energy sales due to the return of more normal temperatures compared to unusually mild winter and summer temperatures in 1992, Merger-related cost savings, and reduced interest charges.
Liquidity and Capital Resources: The Company's liquidity is a function of its ongoing construction program, designed to improve facilities which provide electric service and meet future customer service requirements.
During 1993, construction expenditures for the Company's electric system were approximately $61 million and nuclear fuel expenditures were approximately $6 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.
First mortgage bond maturities and sinking fund requirements through 1998 are $18.6 million. This capital as well as capital required for construction will be provided from internal and external sources available under then existing financial conditions. During 1993, the Company issued and retired long-term debt to take advantage of favorable long-term interest rates and increased borrowings against the accumulated cash surrender values of the corporate-owned life insurance policies.
The embedded cost of long-term debt was 7.3% at December 31, 1993, a decrease from 7.5% at December 31, 1992. The decrease was primarily accomplished through refinancing of higher cost debt.
On November 22, 1993, the Company redeemed three series of first mortgage bonds, $25 million principal amount of First Mortgage Bonds, 7 3/8% Series due 2002, $25 million principal of First Mortgage Bonds, 8 3/8% Series due 2006, and $25 million principal of First Mortgage Bonds, 8 1/2% Series due 2007.
On September 20, 1993, the Company terminated a long-term revolving credit agreement which provided for borrowings of up to $150 million. The loan agreement, which was effective through October 1994, was repaid without penalty.
At December 31, 1993, the Company had $150 million of First Mortgage Bonds available to be issued under a shelf registration filed on August 24, 1993. On January 20, 1994, the Company issued $100 million of First Mortgage Bonds, 6.20% Series due January 15, 2006 under this shelf registration. The net proceeds were used to reduce short-term debt.
On August 12, 1993, the Company issued $65 million of First Mortgage Bonds, 6 1/2% Series due August 1, 2005. The net proceeds from the new issue, together with available cash, were used to refund $35 million of First Mortgage Bonds, 8 1/8% Series due 2001, and $30 million of First Mortgage Bonds, 8 7/8% Series due 2008.
The Company has a long-term agreement that expires in 1995 which contains provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables are accounted for as sales while those related to phase-in revenues are accounted for as collateralized borrowings. At December 31, 1993, the Company had receivables amounting to $56.8 million which were considered sold.
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 from 1991 through 1993 was approximately $27 million. On August 23, 1993, the Company increased its borrowings against the accumulated cash surrender values of the policies by $164.7 million and received $6.9 million from increased borrowings on Wolf Creek Nuclear Operating Company (WCNOC) policies. Total 1993 COLI borrowings amounted to $184.6 million. See Note 2 of the Notes to Financial Statements for additional information on the accumulated cash surrender value. After 1993, 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.
The Company's short-term financing requirements are satisfied, as needed, through short-term bank loans and borrowings under other unsecured lines of credit maintained with banks. At December 31, 1993, short-term borrowings amounted to $155.8 million (see Note 5).
The KG&E common and preferred stock was redeemed in connection with the Merger, leaving 1,000 shares of common stock held by Western Resources. The debt structure of the Company and available sources of funds were not affected by the Merger.
RESULTS OF OPERATIONS
The following is an explanation of significant variations from prior year results in revenues, operating expenses, other income and deductions, and interest charges. Additional information relating to changes between years is provided in the Notes to Financial Statements.
Revenues: The operating revenues of the Company are based on sales volumes and rates, authorized by the Kansas Corporation Commission (KCC) and the FERC, charged for the sale and delivery of electricity. Rates are designed to recover the cost of service and allow investors a fair rate of return. Future electric sales will continue to be affected by weather conditions, competing fuel sources, customer conservation efforts and the overall economy of the Company's service area.
The KCC order approving the Merger provided a moratorium on increases, with certain exceptions, in the Company's electric rates until August 1995. The KCC ordered refunds totalling $32 million to the combined companies' (Western Resources and the Company) customers to share with customers the Merger-related cost savings achieved during the moratorium period. The first refund was made in April 1992 and amounted to approximately $4.9 million for the Company. A refund of approximately $4.9 million was made in December 1993 and an additional refund of approximately $8.7 million will be made in September 1994 (see Note 1).
On March 26, 1992, in connection with the Merger, 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. Any increase or decrease in fuel costs from the projected average will be absorbed by the Company.
1993 COMPARED TO 1992: Total operating revenues increased $62.7 million or 11.3 percent in 1993 compared to 1992 pro forma revenues. The increase is due to the return of near normal temperatures during 1993 compared to unusually mild winter and summer temperatures in 1992. All customer classes experienced increased sales volumes during 1993. The number of cooling degree days recorded for the city of Wichita were 1,546 for 1993, a 23 percent increase from 1992. Contributing to the increase in wholesale sales were sales to neighboring utilities to meet peak demand periods while those utilities' units were down as a result of the summer flooding.
Partially offsetting these increases in revenues was the amortization of the Merger-related refund.
1992 COMPARED TO 1991: Pro forma operating revenues were $554 million in 1992, a 6.8 percent decrease from 1991. The decrease is a result of unusually mild temperatures during 1992 compared to 1991. Revenues from residential customers decreased 11.7 percent compared to 1991 primarily due to reduced air conditioning load. The Company experienced only 1,258 cooling degree days in Wichita in 1992, a 38.9 percent decrease from 1991 and a 22.7 percent decrease from normal weather. Commercial, industrial and wholesale revenues also reflected small decreases in 1992. Also decreasing revenues was the amortization of the Merger-related refund discussed previously.
Operating Expenses: 1993 COMPARED TO 1992: Total operating expenses increased $45.5 million or 10.7 percent in 1993 compared to 1992. Fuel, and purchased power expenses increased $21.4 million or 22.5 percent primarily due to increased generation resulting from increased customer demand for electricity during the summer peak season. Federal and state income taxes increased $28.6 million primarily as a result of higher net income. General taxes increased $4.8 million primarily due to an increase in plant, the property tax assessment ratio, and higher mill levies.
Partially offsetting these increases in total operating expenses was a decrease in other operations expense of $10.1 million primarily as a result of merger-related savings for the entire year of 1993 and reduced net lease expense for La Cygne 2 (see Note 7) compared to pro forma operating expenses of 1992.
At December 31, 1993, the Company completed the accelerated amortization of deferred income tax reserves related to the allowance for borrowed funds used during construction capitalized for Wolf Creek Generating Station. The amortization of these deferred income tax reserves amounted to approximately $12 million in 1993. In accordance with the provisions of the Merger order (see Note 1), the Company is precluded from recovering the $12 million annual amortization in rates until the next rate filing. Therefore the Company's earnings will be impacted negatively until these income taxes are recovered in future rates.
1992 COMPARED TO 1991: Pro forma operating expenses decreased $44.8 million or 9.6 percent in 1992 compared to 1991. Fossil fuel expenses decreased $23.3 million or 24.1 percent primarily due to decreased generation resulting from reduced demand for electricity during the summer peak season and decreased generation by natural gas-fired units with the availability of Wolf Creek. Merger-related cost savings, an early retirement plan, a voluntary separation program and unseasonable mild weather allowed other operating expenses to decrease $19.2 million. Maintenance expenses decreased $6.2 million primarily due to the scheduled major overhaul at La Cygne 2 during 1991.
Partially offsetting these decreases were higher nuclear fuel expenses of $4 million as a result of the increased availability of Wolf Creek in 1992 compared to 1991. Property taxes also increased as a result of increased plant and tax mill levies.
As permitted under the La Cygne 2 generating station lease agreement, in 1992, KG&E 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 the Company's recurring future net lease expense. To accomplish this transaction, a one-time payment of approximately $27 million was made which will be amortized over the remaining life of the lease and will be included in operating expense as part of the future lower lease expense. On September 29, 1992 the Trustee Lessor refinanced bonds having a coupon rate of approximately 11.7% with bonds having a coupon rate of approximately 7.7%.
Expenses related to the merger with Western Resources were $1.1 million for the three months ended March 31, 1992. Other operations expense for 1991, included $3.8 for expenses related to the Company's response to the unsolicited tender offer by Kansas City Power & Light Company (KCPL) and the merger with Western Resources.
Other Income and Deductions: Other income and deductions, net of taxes, increased slightly in 1993 compared to 1992 due to the increased cash surrender values of COLI policies and the receipt of death benefit proceeds. Partially offsetting these increases was higher interest expense on COLI borrowings.
Pro forma other income and deductions, net of taxes, increased significantly for 1992 compared to 1991 as a result of increased cash surrender values of corporate-owned life insurance polices and the recognition of the recovery of $4.2 million of the previously written-off investment in Drexel Burnham Lambert Group Inc. (Drexel) commercial paper.
In April 1992, the Company completed the sale of its 80% interest in CIC Systems, Inc. (CIC). The Company had recorded a $1 million charge in 1991 representing the annual net loss incurred by CIC.
Interest Charges: Interest charges decreased $12.4 million in 1993 compared to 1992 as the Company continued to take advantage of lower interest rates on variable-rate and fixed-rate debt by retiring and refinancing higher cost debt. The Company's embedded cost of long-term debt decreased to 7.3% at December 31, 1993 compared to 7.5% and 7.9% at December 31, 1992 and 1991, respectively.
Pro forma interest charges decreased $3.3 million in 1992, primarily as a result of the refinancing of higher cost fixed-rate debt and lower interest rates on variable-rate debt.
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 revenues as depreciation. 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 recognized the importance of environmental responsibility and has taken a proactive position with respect to the potential environmental liability associated with former manufactured gas sites. The Company has an agreement with the Kansas Department of Health and Environment to systematically evaluate these sites in Kansas (see Note 3).
The Company currently has no Phase I affected units under the Clean Air Act of 1990. Until such time that additional regulations become final the Company will be unable to determine its compliance options or related compliance costs. (see Note 3).
Energy Policy Act: The 1992 Energy Policy Act (the Act) requires increased efficiency of energy usage and will potentially change 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 to its transmission system. Another part of the Act requires a special assessment to be 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.
Statement of Financial Accounting Standards No. 106 (SFAS 106) and No. 112 (SFAS 112): For discussion regarding the effect of SFAS 106 and SFAS 112 on the Company see Note 8 of the Notes to Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Independent Auditors' Report 20
Financial Statements:
Balance Sheets, December 31, 1993 and 1992 22 Statements of Income for the year ended December 31, 1993 23 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Cash Flows for the year ended December 31, 1993 24 (Successor), the period March 31 to December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Taxes for the year ended December 31, 1993 25 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Capitalization, December 31, 1993 and 1992 26 Statements of Common Stock Equity for the year ended 27 December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Notes to Financial Statements 28
Financial Statement Schedules:
V- Utility Plant for the year ended December 31, 1993, 50 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) VI- Accumulated Depreciation of Utility Plant for the year ended 53 December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor) the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor)
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, VII, VIII, IX, X, XI, XII and XIII.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Kansas Gas and Electric Company:
We have audited the accompanying balance sheet and statement of capitalization of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, inc.) as of December 31, 1993, and the related statements of income, cash flows, taxes, and common stock equity for the year then ended. 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 audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit 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 audit provides 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, 1993, and the results of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles.
As explained in Note 8 to the financial statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits.
Our audit was made for the purpose of forming an opinion on the 1993 basic financial statements taken as a whole. The financial statement schedules listed in the table of contents on page 19 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules for 1993 have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Kansas City, Missouri, ARTHUR ANDERSEN & CO. January 28, 1994
INDEPENDENT AUDITORS' REPORT
Kansas Gas and Electric Company:
We have audited the 1992 and 1991 financial statements of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) listed in the accompanying table of contents. Our audits also included the 1992 and 1991 financial statement schedules listed in the accompanying table of contents. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 1992 and the results of its operations and its cash flows for the periods indicated in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information shown therein.
DELOITTE & TOUCHE
Kansas City, Missouri January 29, 1993
KANSAS GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS
1. 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 (KG&E) for $454 million in cash and 23,479,380 shares of Western Resources common stock (the Merger). Western Resources also paid $20 million in costs to complete the Merger. The total cost of the acquisition to Western Resources was $1.066 billion. Simultaneously, KCA and KG&E merged and adopted the name of Kansas Gas and Electric Company. The Merger was accounted for as a purchase. For income tax purposes the tax basis of the Company's assets was not changed by the Merger. In the accompanying statements, KG&E prior to the Merger is labeled as the "Predecessor" and after the Merger as the "Successor". Throughout the notes to financial statements, the "Company, KG&E" refers to both Predecessor and Successor.
As Western Resources acquired 100% of the common and preferred stock of KG&E, the Company recorded an acquisition premium of $490 million on the balance sheet for the difference in purchase price and book value and increased common stock equity to reflect the new cost basis of Western Resources' investment in the Company. This acquisition premium and related income tax requirement of $294 million under Statement of Financial Accounting Standards No. 109 (SFAS 109) have been classified as plant acquisition adjustment in electric plant in service on the balance sheets. Under the provisions of the order of the Kansas Corporation Commission (KCC), the acquisition premium is recorded as an acquisition adjustment and not allocated to the other assets and liabilities of the Company.
The pro forma information for the year ended December 31, 1992 in the accompanying financial statements gives effect to the Merger as if it occurred on January 1, 1992, and was derived by combining the historical information for the three month period ended March 31, 1992 and the nine month period ended December 31, 1992. No purchase accounting adjustments were made for periods prior to the Merger in determining pro forma amounts, other than the elimination of preferred dividends, because such adjustments would be immaterial. This pro forma information is not necessarily indicative of the results of operations that would have occurred had the Merger been consummated on January 1, 1992, nor is it necessarily indicative of future operating results or financial position. The pro forma effects on the Company's net income for 1991 presented giving effect to the Merger as if it had occurred at the beginning of the earliest period presented would not be materially different from that shown in the income statements included herein.
In the November 1991 KCC order approving the Merger, a mechanism was approved to share equally between the shareholders and ratepayers the cost savings generated by the Merger in excess of the revenue requirement needed to allow recovery of the amortization of a portion of the acquisition adjustment, including income tax, calculated on the basis of a purchase price of KG&E's common stock at $29.50 per share. The order provides an amortization period
for the acquisition adjustment of 40 years commencing in August 1995, at which time the full amount of cost savings is expected to have been implemented. Merger savings will be measured by application of an inflation index to certain pre-merger operating and maintenance costs at the time of the next Kansas rate case. While the Company has achieved savings from the Merger, there is no assurance that the savings achieved will be sufficient to, or the cost savings sharing mechanism will operate as to fully offset the amortization of the acquisition adjustment. The order further provides a moratorium on increases, with certain exceptions, in the Company's Kansas electric rates until August 1995. The KCC ordered refunds totalling $32 million to the combined companies' (Western Resources and the Company) customers to share with customers the Merger-related cost savings achieved during the moratorium period. The first refund was made in April 1992 and amounted to approximately $4.9 million for the Company. A refund of approximately $4.9 million was made in December 1993 and an additional refund of approximately $8.7 million will be made in September 1994.
The KCC order approving the Merger requires the legal reorganization of the Company so that it is no longer held as a separate subsidiary after January 1, 1995, unless good cause is shown why such separate existence should be maintained. The Securities and Exchange Commission order relating to the Merger granted Western Resources an exemption under the Public Utilities Holding Company Act until January 1, 1995. In connection with a requested ruling that a merger of the Company into Western Resources would not adversely affect the tax structure of the merger, the Company received a response from the Internal Revenue Service that the IRS would not issue the requested ruling. In light of the IRS response, the Company withdrew its request for a ruling. The Company will consider alternative forms of combination or seek regulatory approvals to waive the requirements for a combination. There is no certainty as to whether a combination will occur or as to the form or timing thereof.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: The financial statements of KG&E include, through March 31, 1992, its 80% owned subsidiary, CIC Systems, Inc. (CIC). In April 1992, the Company disposed of its 80% interest in CIC. KG&E owns 47 percent 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 accounting policies of the Company are in accordance with generally accepted accounting principles as applied to regulated public utilities. The accounting and rates of the Company are subject to requirements of the KCC and the Federal Energy Regulatory Commission (FERC).
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 4.41% for 1993, 6.51% for the nine months ended December 31, 1992, 6.70% for the three months ended March 31, 1992, and 7.74% for 1991. 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.
Depreciation: Depreciation is provided on the straight-line method based on estimated useful lives of property. Composite provisions for book depreciation approximated 2.9% during 1993, 2.9% during the nine months ended December 31, 1992, 3.0% during the three months ended March 31, 1992, and 3.0% during 1991 of the average original cost of depreciable property.
Cash and Cash Equivalents: For purposes of the Statements of Cash Flows, cash and cash equivalents include cash on hand and highly liquid collateralized debt instruments purchased with maturities of three months or less.
Income Taxes: Income tax expense includes provisions for income taxes currently payable and deferred income taxes calculated in conformance with income tax laws, regulatory orders and Statement of Financial Accounting Standards No. 109 (SFAS 109) (see Note 9).
Investment tax credits are deferred as realized and 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 $22.3 and $16.6 million at December 31, 1993 and 1992, respectively, are recorded as a component of accounts receivable on the balance sheets. Certain amounts of unbilled revenues have been sold (see Note 6).
The Company had reserves for doubtful accounts receivable of $3.0 and $2.4 million at December 31, 1993 and 1992, respectively.
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, 1993 and 1992 was $17.4 and $26.0 million, respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts related to corporate-owned life insurance contracts (COLI), primarily with one highly rated major insurance company, are recorded on the balance sheets (millions of dollars):
1993 1992 Cash surrender value of contracts. . . $269.1 $230.3 Prepaid COLI . . . . . . . . . . . . . 9.5 4.8 Borrowings against contracts . . . . . (269.0) (85.8) COLI (net) . . . . . . . . . . . . $ 9.6 $149.3
The decrease in COLI (net) is a result of increased borrowings against the accumulated cash surrender value of the COLI policies. The COLI borrowings will be repaid with proceeds from death benefits. Management expects to realize increases in cash surrender value of contracts resulting from premiums and investment earnings on a tax free basis upon receipt of net proceeds from death benefits under the contracts. Interest expense included in corporate-owned life insurance (net) on the statements of income was $11.9 million for 1993, $5.3 million for the nine months ended December 31, 1992, $1.9 million for the three months ended March 31, 1992, and $7.3 for 1991.
As approved by the Kansas Corporation Commission (KCC), the Company is using a portion of the net income stream generated by COLI policies purchased in 1993 and 1992 (see Note 8) to offset Statement of Financial Accounting Standards No. 106 (SFAS 106) expenses.
Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
3. COMMITMENTS AND CONTINGENCIES
Environmental: The Company and the Kansas Department of Health and Environment entered into a consent agreement to perform preliminary assessments of six former manufactured gas sites. The preliminary assessments of these sites have been completed at minimal cost. Until such time that risk assessments are completed at these sites, it will be impossible to predict the cost of remediation. However, the Company is aware of other utilities in Region VII of the EPA (Kansas, Missouri, Nebraska, and Iowa) which have incurred remediation costs for such sites ranging between $500,000 and $10 million, depending on the site. The Company is also aware that the KCC has permitted another Kansas utility to recover a portion of the 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.
Spent Nuclear Fuel Disposal: Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from nuclear reactors. Under a contract with the DOE for disposal of spent nuclear fuel, the Company pays a quarterly fee to DOE of one mill per kilowatthour of net nuclear generation. These fees are included as part of nuclear fuel expense and amounted to $3.5 million for 1993, $1.6 million for the nine months ended December 31, 1992, $.5 million for the three months ended March 31, 1992, and $2.8 million for 1991.
Decommissioning: The Company's share of Wolf Creek decommissioning costs, currently authorized in rates, was estimated to be approximately $97 million in 1988 dollars. Decommissioning costs are being charged to operating expenses. Amounts so expensed are deposited in an external trust fund and will be used solely for the physical decommissioning of the plant. Electric rates charged to customers provide for recovery of these decommissioning costs over the estimated life of Wolf Creek. At December 31, 1993 and 1992, $13.2 and $9.3 million respectively, were on deposit in the decommissioning fund. On September 1, 1993, WCNOC filed an application with the KCC for an order approving a 1993 Wolf Creek Decommissioning Cost Study which estimates the
Company's share of Wolf Creek decommissioning costs at approximately $174 million in 1993 dollars. If approved by the KCC, management expects substantially all such cost increases to be recovered through the ratemaking process.
The Company carries $164 million in premature decommissioning insurance in the event of a shortfall in the trust fund. The insurance coverage 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. If the amount designated as decommissioning insurance is needed to implement the NRC-approved plan for stabilization and decontamination, it would not be available for decommissioning purposes.
Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.4 billion for a single nuclear incident. 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 nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index. 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 totalling approximately $2.8 billion ($1.3 billion, Company's share). This insurance is provided by a combination of "nuclear insurance pools" ($1.3 billion) and Nuclear Electric Insurance Limited (NEIL) ($1.5 billion). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. The remaining proceeds from the $2.8 billion insurance coverage ($1.3 billion, Company's share), if any, can be used for property damage up to $1.1 billion (Company's share) and premature decommissioning costs up to $117.5 million (Company's share) in excess of funds previously collected for decommissioning (as discussed under "Decommissioning"), with the remaining $47 million (Company's share) available for either property damage or premature decommissioning costs.
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 of approximately $9 million per year.
There can be no assurance that all potential losses or liabilities will be insurable or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance, to the extent not recoverable through rates, could have a material adverse effect on the Company's financial position and results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in sulfur dioxide and nitrogen oxide emissions effective in 1995 and 2000 and a probable reduction in toxic emissions. To meet the monitoring and reporting requirements under the acid rain program, the Company is installing continuous monitoring and reporting equipment at a total cost of approximately $2.3 million. At December 31, 1993, the Company had completed approximately $850 thousand of these capital expenditures with the remaining $1.4 million of capital expenditures to be completed in 1994 and 1995. The Company does not expect additional equipment to reduce sulfur emissions to be necessary under Phase II. The Company currently has no Phase I affected units.
The nitrogen oxide and toxic limits, which were not set in the law, will be specified in future EPA regulations. The EPA has issued for public comment preliminary nitrogen oxide regulations for Phase I group 1 units. Nitrogen oxide regulations for Phase II units and Phase I group 2 units are mandated in the Act to be promulgated by January 1, 1997. Although the Company has no Phase I units, the final nitrogen oxide regulations for Phase I group 1 may allow for early compliance for Phase II group 1 units. Until such time as the Phase I group 1 nitrogen oxide regulations are final, the Company will be unable to determine its compliance options or related compliance costs.
Federal Income Taxes: During 1991, the Internal Revenue Service (IRS) completed an examination of the Company's federal income tax returns for the years 1984 through 1988. In April 1992, the Company received the examination report and upon review filed a written protest in August 1992. In October 1993, the Company received another examination report for the years 1989 and 1990 covering the same issues identified in the previous examination report. Upon review of this report, the Company filed a written protest in November 1993. The most significant proposed adjustments reduce the depreciable basis of certain assets and investment tax credits generated. Management believes there are significant questions regarding the theory, computations, and sampling techniques used by the IRS to arrive at its proposed adjustments, and also believes any additional tax expense incurred or loss of investment tax credits will not be material to the Company's financial position and results of operations. Additional income tax payments, if any, are expected to be offset by investment tax credit carryforwards, alternative minimum tax credit carryforwards, or deferred tax provisions.
Other Investments: In prior years, the Company routinely purchased short-term investment grade commercial paper for special deposit interest accounts associated with tax-exempt pollution control bonds. On February 1, 1990, the Company purchased $6.6 million of Drexel Burnham Lambert Group Inc. (Drexel) commercial paper. On February 13, 1990, Drexel filed for bankruptcy. In 1990, additional claims being filed and potential lengthy litigation indicated full recovery would be unlikely; accordingly, the investment was written off in 1990. The Company recognized the recovery of approximately $4.2 million during the nine months ended December 31, 1992, of the investment, which is included in miscellaneous income.
Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the Company has entered into various commitments to obtain nuclear fuel, coal, and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1993, WCNOC's nuclear fuel commitments (Company's share) were approximately $18.0 million for uranium concentrates expiring at various times through 1997, $123.6 million for enrichment expiring at various times through 2014, and $45.5 million for fabrication through 2012. At December 31, 1993, the Company's coal and natural gas contract commitments in 1993 dollars under the remaining term of the contracts are $666 million and $20.4 million, respectively. The largest coal contract was renegotiated in early 1993 and expires in 2020 with the remaining coal contracts expiring at various times through 2013. The majority of natural gas contracts expire in 1995 with automatic one-year extension provisions. In the normal course of business, additional commitments and spot market purchases will be made to obtain adequate fuel supplies.
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.
4. RATE MATTERS AND REGULATION
Elimination of the Energy Cost Adjustment Clause (ECA): On March 26, 1992, in connection with the Merger, the KCC approved the elimination of the ECA for most retail customers effective April 1, 1992. The provisions for fuel costs included in base rates were established at a level intended by the KCC to equal the projected average cost of fuel through August 1995, and to include recovery of costs provided by previously issued orders relating to coal contract settlements and storm damage recovery discussed below. Any increase or decrease in fuel costs from the projected average will be absorbed by the Company.
Rate Stabilization Plan: In 1988, the KCC issued an order requiring that the accrual of phase-in revenues be discontinued effective December 31, 1988. Effective January 1, 1989, the Company began amortizing the phase-in revenue asset on a straight-line basis over 9-1/2 years.
Cost of Service Audit Appeal: In September 1991, the KCC ordered the Company to refund (which the Company has done) $5.6 million of revenues plus $0.6 million in interest, for the period July 2, 1990 through January 31, 1991. This order concluded the appeal of the February 1990 KCC order to reduce rates by $8.7 million. The Company had previously recorded reserves totalling $10.8 million; however, as the order also made rates permanent, the excess reserves of $3.3 million were reversed in September 1991.
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 on the balance sheets. The settlement resulted in the termination of a long-term coal contract. In June 1991, 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.
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 on the Company's balance sheet. In July 1991, 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).
Storm Damage Recovery: In October 1990, the Company asked the KCC for approval of a plan to recover the cost of damage primarily from the March 13 and June 19, 1990 storms. Approximately $15 million of capital expenditures were incurred. These costs have been included in the Company's electric plant accounts. In May 1991, the Company amended this request to include the estimated $5 million of capital expenditures associated with an April 1991 storm. In November 1991 and January 1992, the KCC approved the deferral and recovery of the capital expenditures of the 1990 and 1991 storms, respectively, as well as carrying charges thereon.
5. SHORT-TERM BORROWINGS
At December 31, 1993, the Company had bank credit arrangements available of $35 million. In addition, the Company has uncommitted loan participation agreements. Maximum short-term borrowings outstanding during 1993 and 1992 were $175.8 million on December 14, 1993 and $128 million on October 6, 1992. The weighted average interest rates, including fees, were 3.5% for 1993, 6.4% for the nine months ended December 31, 1992, 7.1% for the three months ended March 31, 1992, and 7.8% for 1991.
6. LONG-TERM DEBT
The amount of first mortgage bonds authorized by the KG&E 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. During 1993, the Company refinanced $65 million of first mortgage bonds by issuing $65 million of First Mortgage Bonds, 6 1/2% Series due 2005. In 1992, the Company refinanced $125 million of first mortgage bonds by issuing $135 million of First Mortgage Bonds, 7.6% Series due 2003.
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. The sinking fund requirements for certain pollution control series bonds can be met only through the acquisition and retirement of outstanding bonds.
The 6.80% series, due 2004, the 6% and 5 7/8% series due 2007 and the 7% series due 2031 are pledged as collateral for pollution control revenue bonds issued by Kansas municipalities.
On September 20, 1993, the Company terminated a long-term revolving credit agreement which provided for borrowings of up to $150 million. The loan agreement, which was effective through October 1994, was repaid without penalty. The weighted average interest rate, including fees, was 3.7% for 1993, 6.8% for the nine months ended December 31, 1992, 7.7% for the three months ended March 31, 1992, and 8.4% for 1991.
The Company has a long-term agreement, expiring in 1995, which contains provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables are accounted for as sales while those related to phase-in revenues are accounted for as collateralized borrowings. Additional receivables are continually sold to replace those collected. At December 31, 1993 and 1992, outstanding receivables amounting to $56.8 and $47.7 million, respectively, were considered sold under the agreement. The credit risk associated with the sale of customer accounts receivable is considered minimal. The weighted average interest rate, including fees, on this agreement was 3.7% for 1993, 6.6% for the nine months ended December 31, 1992, 7.9% for the three months ended March 31, 1992, and 7.8% for 1991. At December 31, 1993, an additional $16.4 million was available under the agreement.
Bonds maturing and acquisition and retirement of bonds for sinking fund requirements for the five years subsequent to December 31, 1993 are as follows:
Maturing Retiring Year Bonds Bonds (Dollars in Thousands)
1994. . . . . . . $ - $ 238 1995. . . . . . . - 253 1996. . . . . . . 16,000 270 1997. . . . . . . - 833 1998. . . . . . . - 1,050
7. SALE-LEASEBACK OF LA CYGNE 2
In 1987, the Company sold and leased back its 50 percent undivided interest in La Cygne 2 generating unit. The lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50 percent 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 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.
Future minimum annual lease payments required under the lease agreement are approximately $34.6 million for each year through 1998 and $715 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale has been deferred for financial reporting purposes, and is being amortized 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 1993, $20.6 million for the nine months ended December 31, 1992, $7.5 million for the three months ended March 31, 1992, and $30 million for 1991.
8. EMPLOYEE BENEFIT PLANS
Pension: The Company maintains noncontributory defined benefit pension plans covering substantially all employees of the Company prior to the Merger. Pension benefits are based on years of service and the employee's compensation during the five highest paid consecutive years out of ten before retirement. The Company's policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code.
The following table provides information on the components of pension cost for the Company's pension plans (millions of dollars):
April 1 | Jan.1 to 1993 to Dec.31 | March 31 1991 (Successor) | (Predecessor) Pension Cost: | Service cost . . . . . . . . . . . $ 3.2 $ 2.5 | $ .8 $ 3.1 Interest cost on projected | benefit obligation . . . . . . . 9.5 6.7 | 2.1 7.4 Return on plan assets. . . . . . . (14.1) (5.8) | (9.0) (14.0) Net amortization & deferral. . . . 4.9 (1.0) | 6.7 5.4 Net pension cost . . . . . . . . $ 3.5 $ 2.4 | $ .6 $ 1.9
The following table sets forth the plans' actuarial present value and funded status at November 30, 1993 and 1992 (the plan years) and a reconciliation of such status to the December 31, 1993 and 1992 financial statements (millions of dollars):
1993 1992 Funded Status: Actuarial present value of benefit obligations: Vested. . . . . . . . . . . . . . . . . . . . . $ 95.2 $ 82.9 Non-vested. . . . . . . . . . . . . . . . . . . 6.1 3.6 Total . . . . . . . . . . . . . . . . . . . . $101.3 $ 86.5
Plan assets at November 30 (principally debt and equity securities) at fair value. . . . . . $119.9 $113.7 Projected benefit obligation at November 30 . . . (125.5) (110.8) Plan assets in excess of projected benefit obligation at November 30 . . . . . . . . . . . (5.6) 2.9 Unrecognized transition asset . . . . . . . . . . (1.7) (2.0) Unrecognized prior service costs. . . . . . . . . 12.4 12.1 Unrecognized net gain . . . . . . . . . . . . . . (20.6) (26.1) Accrued pension costs at December 31. . . . . . . $(15.5) $(13.1)
Year Ended December 31, 1993 1992
Actuarial Assumptions: Discount rate . . . . . . . . . . . . . . . . . 7.0-7.75% 8.0-8.5% Annual salary increase rate . . . . . . . . . . 5.0 % 6.0% Long-term rate of return. . . . . . . . . . . . 8.0-8.5 % 8.0-8.5%
Early Retirement and Voluntary Separation Plans: In January 1992, the Board of Directors approved an early retirement plan and a voluntary separation program. The voluntary early retirement plan was offered to all vested participants of the Company's defined benefit pension plan who reached the age of 55 with 10 or more years of service on or before May 1, 1992. Certain pension plan improvements were made including a waiver of the actuarial reduction factors for early retirement and a cash incentive payable as a monthly supplement up to 60 months or a lump sum payment. Of the 111 employees eligible for the early retirement option, 71, representing 6% of the Company's work force, elected to retire on or before the May 1, 1992, deadline. Another 29 employees, with 10 or more years of service, elected to participate in the voluntary separation program. In addition, 61 employees received Merger-related severance benefits. The actuarial cost, based on plan provisions for early retirement and voluntary separation programs, and Merger- related severance benefits, was approximately $3.9 million of which $1.8 million was included in the pension liability at December 31, 1992. The actuarial cost was considered in purchase accounting for the Merger (See Note 1). Postretirement: The Company adopted the provisions of Statement of Financial Accounting Standards No. 106 (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. Based on actuarial projections and adoption of the transition method of implementation which allows a 20-year amortization of the accumulated benefit obligation, the annual expense under SFAS 106 was approximately $3.4 million in 1993 (as compared to approximately $1.8 million on a cash basis) and the Company's total obligation was approximately $23.9 million at December 31, 1993. To mitigate the impact of SFAS 106 expense, the Company has implemented programs to reduce health care costs. In addition, the Company has received an order from the KCC permitting the initial deferral of SFAS 106 expense. To mitigate the impact SFAS 106 expense will have on rate increases, the Company will include in the future computation of cost of service the actual SFAS 106 expense and an income stream generated from corporate-owned life insurance policies (COLI) purchased in 1993 and 1992. To the extent SFAS 106 expense exceeds income from the COLI program, this excess will be deferred (as allowed by FASB Emerging Issues Task Force Issue No. 92-12) and offset by income generated through the deferral period by the COLI program. Should the income stream generated by the COLI program not be sufficient to offset the deferred SFAS 106 expense, the KCC order allows recovery of such deficit through the ratemaking process.
Prior to the adoption of SFAS 106 the Company's policy was to recognize expenses as claims were paid. The costs of benefits were $0.8 million for the nine months ended December 31, 1992, $0.2 million for the three months ended March 31, 1992, and $2.1 million for 1991.
The following table summarizes the status of the Company's postretirement plans for financial statement purposes and the related amount included in the balance sheet:
December 31, 1993 (Dollars in Millions) Actuarial present value of postretirement benefit obligations: Retirees. . . . . . . . . . . . . . . . . . . . $ 12.4 Active employees fully eligible . . . . . . . . 2.5 Active employees not fully eligible . . . . . . 9.0 Unrecognized prior service cost . . . . . . . . (.1) Unrecognized transition obligation. . . . . . . (20.4) Unrecognized net loss . . . . . . . . . . . . . (1.7) Balance sheet liability . . . . . . . . . . . . . . $ 1.7
For measurement purposes, an annual health care cost growth rate of 13% was assumed for 1994, decreasing to 6% by 2002 and thereafter. The accumulated post retirement benefit obligation was calculated using a weighted-average discount rate of 7.75%, a weighted-average compensation increase rate of 5.0%, and a weighted-average expected rate of return of 8.5%. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by 1% each year would increase the present value of the accumulated projected benefit obligation by $.6 million and the aggregate of the service and interest cost components by $.1 million.
Postemployment: The FASB has issued Statement of Financial Accounting Standards No. 112 (SFAS 112), which establishes accounting and reporting standards for postemployment benefits. The new statement will require the Company to recognize the liability to provide postemployment benefits when the liability has been incurred. The Company adopted SFAS 112 effective January 1, 1994. To mitigate the impact adopting SFAS 112 will have on rate increases, the Company will file an application with the KCC for an order permitting the initial deferral of SFAS 112 transition costs and expenses and its inclusion in the future computation of cost of service net of an income stream generated from COLI. At December 31, 1993, the Company estimates SFAS 112 liability to total approximately $700,000.
Savings Plans: The Company maintains 401(k) savings plans in which substantially all employees participate. The Company matches employees' contributions up to a maximum limit of 3 percent of the employees' salary. Prior to the Merger, the Company's matching contribution was based on the Company's performance during the prior year and the level of employee contributions. The funds of the plans are deposited with a trustee and invested at each employee's option in one or more investment funds, including a Western Resources common stock fund. The Company's contributions were $1.3 for 1993, $1.7 million for the nine months ended December 31, 1992, $0.2 million for the three months ended March 31, 1992, and $2.0 million for 1991.
9. INCOME TAXES
The Company adopted Statement of Financial Accounting Standards No. 96 (SFAS 96) in 1987. This statement required the Company to establish deferred tax assets and liabilities, as appropriate, for all temporary differences, and to adjust deferred tax balances to reflect changes in tax rates expected to be in effect during the periods the temporary differences reverse. SFAS 96 was superseded by SFAS 109 issued in February 1992 and the Company adopted the provisions of that standard prospectively in the first quarter of 1992. The accounting for SFAS 109 is substantially the same as SFAS 96.
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 through future rates, 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. Accordingly, the adoption of SFAS 109 did not have a material effect on the Company's results of operations.
At December 31, 1993, the Company had unused investment tax credits of approximately $7.1 million available for carryforward which, if not utilized, will expire in the years 2000 through 2002 (see Note 3). In addition, the Company has alternative minimum tax credits generated prior to April 1, 1992, which carryforward without expiration, of $53.9 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, 1993.
Beginning April 1, 1992, the Company is part of the consolidated income tax return of Western Resources. However, the Company determines its income tax provisions on a separate company basis.
Deferred income taxes result from temporary differences between the financial statement and tax basis of the Company's assets and liabilities. The sources of these differences and their cumulative tax effects are as follows:
December 31, 1993 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (350,105) $ (350,105) Energy and purchased gas adjustment clauses . . . . . . . 3,257 - 3,257 Phase-in revenues. . . . . . . . . - (35,573) (35,573) Deferred gain on sale-leaseback. . 116,186 - 116,186 Alternative minimum tax credits. . 39,882 - 39,882 Deferred coal contract settlements. . . . . . . . . . . - (7,797) (7,797) Deferred compensation/pension liability. . . . . . . . . . . . 10,856 - 10,856 Acquisition premium. . . . . . . . - (300,814) (300,814) Deferred future income taxes . . . - (109,178) (109,178) Other. . . . . . . . . . . . . . . - (12,873) (12,873) Total Deferred Income Taxes. . . . . $ 170,181 $ (816,340) $ (646,159)
December 31, 1992 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (324,972) $ (324,972) Energy and purchased gas adjustment clauses . . . . . . . 2,691 - 2,691 Phase-in revenues. . . . . . . . . - (37,564) (37,564) Deferred gain on sale-leaseback. . 104,573 - 104,573 Alternative minimum tax credits. . 39,882 - 39,882 Deferred coal contract settlements. . . . . . . . . . . - (9,263) (9,263) Deferred compensation/pension liability. . . . . . . . . . . . 11,002 - 11,002 Acquisition premium. . . . . . . . - (313,721) (313,721) Deferred future income taxes . . . - (146,962) (146,962) Other. . . . . . . . . . . . . . . 3,138 - 3,138 Total Deferred Income Taxes. . . . . $ 161,286 $ (832,482) $ (671,196)
10. LEGAL PROCEEDINGS
The Company is involved in various other 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.
A provision of $12 million was recorded in miscellaneous expenses on the 1991 statement of income with respect to various legal matters.
11. 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:
Cash and Cash Equivalents- The carrying amount approximates the fair value because of the short- term maturity of these investments. Decommissioning Trust- The fair value of the decommissioning trust is based on quoted market prices at December 31, 1993 and 1992. 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 coupon 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, 1993 1992 1993 1992 (Dollars in Thousands)
Cash and cash equivalents. . . . . . . $ 63 $ 892 $ 63 $ 892 Decommissioning trust. . . 13,204 9,272 13,929 9,500 Variable-rate debt . . . . 478,743 375,909 478,743 375,909 Fixed-rate debt. . . . . . 603,920 679,145 660,750 705,970
12. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1993 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 150,265 $ 91,175 342 50 Jeffrey 1 (b) Jul 1978 65,803 28,717 140 20 Jeffrey 2 (b) May 1980 64,375 25,552 135 20 Jeffrey 3 (b) May 1983 95,336 31,084 140 20 Wolf Creek (c) Sep 1985 1,366,387 281,819 533 47
(a) Jointly owned with Kansas City Power & Light Company (KCP&L) (b) Jointly owned with Western Resources, UtiliCorp United Inc., and a third party (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 percent undivided interest in La Cygne 2 (representing 335 MW capacity) sold and leased back to the Company in 1987, are included in operating expenses in 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.
13. QUARTERLY FINANCIAL STATISTICS (Unaudited) (Dollars in Thousands)
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.
4th Qtr. 3rd Qtr. 2nd Qtr. 1st. Qtr. (Successor)
Operating revenues. . . . . $136,097 $191,941 $150,478 $138,481 Operating income. . . . . . 26,188 52,874 35,545 32,774 Net income. . . . . . . . . 13,692 46,406 24,274 23,731 Earnings applicable to common stock . . . . . 13,692 46,406 24,274 23,731
4th Qtr. 3rd Qtr. 2nd Qtr. 1st. Qtr. (Successor) |(Predecessor) | Operating revenues. . . . . $127,058 $167,825 $128,655| $130,713 Operating income. . . . . . 29,282 49,541 29,174| 22,165 Net income. . . . . . . . . 15,528 35,987 20,426| 6,040 Earnings applicable | to common stock . . . . . 15,528 35,987 20,426| 5,835
14. RELATED PARTY TRANSACTIONS
Subsequent to the Merger, the cash management function, including cash receipts and disbursements, for KG&E has been assumed by Western Resources. As a result, the proceeds of cash collections, including short-term borrowings, less disbursements related to KG&E transactions have been recorded by the Companies through an intercompany account which, at December 31, 1993, resulted in a net advance by KG&E to Western Resources of $192.8 million. Certain of the Company's operating expenses have been allocated 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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no disagreements with accountants on accounting and financial disclosure. Information relating to a change in accountants is incorporated by reference from the Company's Current Report on Form 8-K dated March 8, 1993.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Western Resources, Inc. owns 100 percent of the Company's outstanding common stock. A Director Business Experience Since 1988 and Other Continuously Name Age Directorships Other Than The Company Since
Kent R. Brown 48 Chairman of the Board, President and 1992 Chief Executive Officer since June 1992, and prior to that President and Chief Executive Officer since March 1992, and prior to that Group Vice President Directorships Bank IV Wichita
Robert T. Crain 68 Owner, Crain Realty, Co., Fort Scott, 1992(b) (a) Kansas Directorships Citizens National Bank
Anderson E. 60 President, Jackson Mortuary, Wichita, 1994 Jackson Kansas
Donald A. 60 President, Maupintour, Inc., Lawrence, 1992(b) Johnston Kansas (Escorted Tours and Travel) (a) Directorships Commerce Bank, Lawrence Maupintour, Inc.
Steven L. 48 Executive Vice President and Chief 1992 Kitchen Financial Officer, Western Resources, Inc., (since March 1990) and prior to that Senior Vice President, Finance and Accounting (October 1987 to March 1990)
Glenn L. 68 Retired Vice President - Nuclear of the 1992(b) Koester Company
James J. Noone 73 Attorney and retired Administrative Judge 1992(b) (a) for the District Court of Sedgwick County, Kansas
Marilyn B. 44 President, Bank IV Wichita, 1994 Pauly Wichita, Kansas Directorships St. Francis Regional Medical Center Farmers Mutual Alliance Insurance Company
A Director Business Experience Since 1988 and Other Continuously Name Age Directorships Other Than The Company Since
Newton C. Smith 72 Physician and Surgeon, Arkansas City, 1992(b) Kansas
Richard Smith 60 President, Range Oil Company 1993 Directorships Bank IV Kansas Wichita HCA Wesley Medical Center
(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, Mr. Koester, Mr. Noone, and Mr. Newton Smith were directors of the former Kansas Gas & Electric Company since 1981, 1980, 1986, 1986, and 1985, respectively.
Outside Directors are paid $3,750 per quarter retainer and all Directors are paid an attendance fee of $600 for Directors' meetings ($300 if attending by phone) and $500 for committee meetings. An additional committee meeting 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.
The Board of Directors held 5 meetings during the year and the Audit Committee held 2 meetings. All Directors attended 75% or more of their applicable meetings.
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, 1993 and 1992 Statements of Income for the year ended December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Cash Flows for the year ended December 31, 1993 (Successor), the period March 31 to December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Taxes for the year ended December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Capitalization, December 31, 1993 and 1992 Statements of Common Stock Equity for the year ended December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Notes to Financial Statements
The following supplemental schedules are included herein.
SCHEDULES
Schedule V - Utility Plant for the year ended December 31, 1993, (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Schedule VI - Accumulated Depreciation of Utility Plant for the year ended December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor) the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor)
REPORTS ON FORM 8-K
Form 8-K dated January 31, 1994
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) to 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-six 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, and August 24, 1993, (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)
4(c)2 Thirty-seventh Supplemental Indenture dated as of January 15, 1994, to the Company's Mortgage and Deed of Trust (Filed electronically)
4(c)3 Thirty-eighth Supplemental Indenture dated as of March 1, 1994, to the Company's Mortgage and Deed of Trust (Filed electronically)
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)1 Severance Agreement (Filed as Exhibit 10(a)1 to Form 10-K for the I year ended December 31, 1990, File No. 1-7324).
10(a)2 Severance Agreement (Filed as Exhibit 10(a)2 to Form 10-K for the I year ended December 31, 1990, File No. 1-7324).
10(a)3 Severance Agreement (Filed as Exhibit 10(a)3 to Form 10-K for the I year ended December 31, 1990, File No. 1-7324).
10(b) 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(b)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(c) Outside Directors' Deferred Compensation Plan
12 Computation of Ratio of Consolidated Earnings to Fixed Charges. (Filed electronically)
16 Letter re Change in Certifying Accountant. (Filed as Exhibit 16 to I the Current Report on Form 8-K dated March 8, 1993.
23(a) Consent of Independent Public Accountants, Arthur Andersen & Co. (Filed electronically)
23(b) Consent of Independent Public Accountants, Deloitte & Touche (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 18, 1994 By KENT R. BROWN (Kent R. Brown, Chairman of the Board, President and Chief Executive Officer)
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Signature Title Date
Chairman of the Board, President KENT R. BROWN and Chief Executive Officer March 18, (Kent R. Brown) (Principal Executive Officer)
Secretary, Treasurer and General RICHARD D. TERRILL Counsel (Principal Financial March 18, (Richard D. Terrill) and Accounting Officer)
ROBERT T. CRAIN (Robert T. Crain)
(Anderson E. Jackson)
DONALD A. JOHNSTON (Donald A. Johnston)
S. L. KITCHEN Directors March 18, (S. L. Kitchen)
GLENN L. KOESTER (Glenn L. Koester)
JAMES J. NOONE (James J. Noone)
(Marilyn B. Pauly)
NEWTON C. SMITH, M.D. (Newton C. Smith, M. D.)
RICHARD SMITH (Richard Smith)


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION
The results of operations for the year ended December 31, 1993, and the nine months ended December 31, 1992, included herein, refer to the Company following the merger with Western Resources, Inc. (formerly The Kansas Power and Light Company) through its wholly-owned subsidiary, KCA Corporation, on March 31, 1992 (the Merger) (see Note 1).
Pro forma results of operations for the twelve months ended December 31, 1992 presented herein, give effect to the Merger as if it occurred on January 1, 1992 and were derived by combining the historical information for the three month period ended March 31, 1992 and the nine month period ended December 31, 1992. The results of operations for the year ended December 31, 1991, refer to the Company prior to the Merger but are not materially different than if presented on a pro forma basis. Additional information relating to changes between years is provided in the Notes to Financial Statements.
General: The Company had net income of $108.1 million for 1993 compared to pro forma net income of $78 million in 1992. The increase in net income is a result of the increase in energy sales due to the return of more normal temperatures compared to unusually mild winter and summer temperatures in 1992, Merger-related cost savings, and reduced interest charges.
Liquidity and Capital Resources: The Company's liquidity is a function of its ongoing construction program, designed to improve facilities which provide electric service and meet future customer service requirements.
During 1993, construction expenditures for the Company's electric system were approximately $61 million and nuclear fuel expenditures were approximately $6 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.
First mortgage bond maturities and sinking fund requirements through 1998 are $18.6 million. This capital as well as capital required for construction will be provided from internal and external sources available under then existing financial conditions. During 1993, the Company issued and retired long-term debt to take advantage of favorable long-term interest rates and increased borrowings against the accumulated cash surrender values of the corporate-owned life insurance policies.
The embedded cost of long-term debt was 7.3% at December 31, 1993, a decrease from 7.5% at December 31, 1992. The decrease was primarily accomplished through refinancing of higher cost debt.
On November 22, 1993, the Company redeemed three series of first mortgage bonds, $25 million principal amount of First Mortgage Bonds, 7 3/8% Series due 2002, $25 million principal of First Mortgage Bonds, 8 3/8% Series due 2006, and $25 million principal of First Mortgage Bonds, 8 1/2% Series due 2007.
On September 20, 1993, the Company terminated a long-term revolving credit agreement which provided for borrowings of up to $150 million. The loan agreement, which was effective through October 1994, was repaid without penalty.
At December 31, 1993, the Company had $150 million of First Mortgage Bonds available to be issued under a shelf registration filed on August 24, 1993. On January 20, 1994, the Company issued $100 million of First Mortgage Bonds, 6.20% Series due January 15, 2006 under this shelf registration. The net proceeds were used to reduce short-term debt.
On August 12, 1993, the Company issued $65 million of First Mortgage Bonds, 6 1/2% Series due August 1, 2005. The net proceeds from the new issue, together with available cash, were used to refund $35 million of First Mortgage Bonds, 8 1/8% Series due 2001, and $30 million of First Mortgage Bonds, 8 7/8% Series due 2008.
The Company has a long-term agreement that expires in 1995 which contains provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables are accounted for as sales while those related to phase-in revenues are accounted for as collateralized borrowings. At December 31, 1993, the Company had receivables amounting to $56.8 million which were considered sold.
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 from 1991 through 1993 was approximately $27 million. On August 23, 1993, the Company increased its borrowings against the accumulated cash surrender values of the policies by $164.7 million and received $6.9 million from increased borrowings on Wolf Creek Nuclear Operating Company (WCNOC) policies. Total 1993 COLI borrowings amounted to $184.6 million. See Note 2 of the Notes to Financial Statements for additional information on the accumulated cash surrender value. After 1993, 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.
The Company's short-term financing requirements are satisfied, as needed, through short-term bank loans and borrowings under other unsecured lines of credit maintained with banks. At December 31, 1993, short-term borrowings amounted to $155.8 million (see Note 5).
The KG&E common and preferred stock was redeemed in connection with the Merger, leaving 1,000 shares of common stock held by Western Resources. The debt structure of the Company and available sources of funds were not affected by the Merger.
RESULTS OF OPERATIONS
The following is an explanation of significant variations from prior year results in revenues, operating expenses, other income and deductions, and interest charges. Additional information relating to changes between years is provided in the Notes to Financial Statements.
Revenues: The operating revenues of the Company are based on sales volumes and rates, authorized by the Kansas Corporation Commission (KCC) and the FERC, charged for the sale and delivery of electricity. Rates are designed to recover the cost of service and allow investors a fair rate of return. Future electric sales will continue to be affected by weather conditions, competing fuel sources, customer conservation efforts and the overall economy of the Company's service area.
The KCC order approving the Merger provided a moratorium on increases, with certain exceptions, in the Company's electric rates until August 1995. The KCC ordered refunds totalling $32 million to the combined companies' (Western Resources and the Company) customers to share with customers the Merger-related cost savings achieved during the moratorium period. The first refund was made in April 1992 and amounted to approximately $4.9 million for the Company. A refund of approximately $4.9 million was made in December 1993 and an additional refund of approximately $8.7 million will be made in September 1994 (see Note 1).
On March 26, 1992, in connection with the Merger, 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. Any increase or decrease in fuel costs from the projected average will be absorbed by the Company.
1993 COMPARED TO 1992: Total operating revenues increased $62.7 million or 11.3 percent in 1993 compared to 1992 pro forma revenues. The increase is due to the return of near normal temperatures during 1993 compared to unusually mild winter and summer temperatures in 1992. All customer classes experienced increased sales volumes during 1993. The number of cooling degree days recorded for the city of Wichita were 1,546 for 1993, a 23 percent increase from 1992. Contributing to the increase in wholesale sales were sales to neighboring utilities to meet peak demand periods while those utilities' units were down as a result of the summer flooding.
Partially offsetting these increases in revenues was the amortization of the Merger-related refund.
1992 COMPARED TO 1991: Pro forma operating revenues were $554 million in 1992, a 6.8 percent decrease from 1991. The decrease is a result of unusually mild temperatures during 1992 compared to 1991. Revenues from residential customers decreased 11.7 percent compared to 1991 primarily due to reduced air conditioning load. The Company experienced only 1,258 cooling degree days in Wichita in 1992, a 38.9 percent decrease from 1991 and a 22.7 percent decrease from normal weather. Commercial, industrial and wholesale revenues also reflected small decreases in 1992. Also decreasing revenues was the amortization of the Merger-related refund discussed previously.
Operating Expenses: 1993 COMPARED TO 1992: Total operating expenses increased $45.5 million or 10.7 percent in 1993 compared to 1992. Fuel, and purchased power expenses increased $21.4 million or 22.5 percent primarily due to increased generation resulting from increased customer demand for electricity during the summer peak season. Federal and state income taxes increased $28.6 million primarily as a result of higher net income. General taxes increased $4.8 million primarily due to an increase in plant, the property tax assessment ratio, and higher mill levies.
Partially offsetting these increases in total operating expenses was a decrease in other operations expense of $10.1 million primarily as a result of merger-related savings for the entire year of 1993 and reduced net lease expense for La Cygne 2 (see Note 7) compared to pro forma operating expenses of 1992.
At December 31, 1993, the Company completed the accelerated amortization of deferred income tax reserves related to the allowance for borrowed funds used during construction capitalized for Wolf Creek Generating Station. The amortization of these deferred income tax reserves amounted to approximately $12 million in 1993. In accordance with the provisions of the Merger order (see Note 1), the Company is precluded from recovering the $12 million annual amortization in rates until the next rate filing. Therefore the Company's earnings will be impacted negatively until these income taxes are recovered in future rates.
1992 COMPARED TO 1991: Pro forma operating expenses decreased $44.8 million or 9.6 percent in 1992 compared to 1991. Fossil fuel expenses decreased $23.3 million or 24.1 percent primarily due to decreased generation resulting from reduced demand for electricity during the summer peak season and decreased generation by natural gas-fired units with the availability of Wolf Creek. Merger-related cost savings, an early retirement plan, a voluntary separation program and unseasonable mild weather allowed other operating expenses to decrease $19.2 million. Maintenance expenses decreased $6.2 million primarily due to the scheduled major overhaul at La Cygne 2 during 1991.
Partially offsetting these decreases were higher nuclear fuel expenses of $4 million as a result of the increased availability of Wolf Creek in 1992 compared to 1991. Property taxes also increased as a result of increased plant and tax mill levies.
As permitted under the La Cygne 2 generating station lease agreement, in 1992, KG&E 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 the Company's recurring future net lease expense. To accomplish this transaction, a one-time payment of approximately $27 million was made which will be amortized over the remaining life of the lease and will be included in operating expense as part of the future lower lease expense. On September 29, 1992 the Trustee Lessor refinanced bonds having a coupon rate of approximately 11.7% with bonds having a coupon rate of approximately 7.7%.
Expenses related to the merger with Western Resources were $1.1 million for the three months ended March 31, 1992. Other operations expense for 1991, included $3.8 for expenses related to the Company's response to the unsolicited tender offer by Kansas City Power & Light Company (KCPL) and the merger with Western Resources.
Other Income and Deductions: Other income and deductions, net of taxes, increased slightly in 1993 compared to 1992 due to the increased cash surrender values of COLI policies and the receipt of death benefit proceeds. Partially offsetting these increases was higher interest expense on COLI borrowings.
Pro forma other income and deductions, net of taxes, increased significantly for 1992 compared to 1991 as a result of increased cash surrender values of corporate-owned life insurance polices and the recognition of the recovery of $4.2 million of the previously written-off investment in Drexel Burnham Lambert Group Inc. (Drexel) commercial paper.
In April 1992, the Company completed the sale of its 80% interest in CIC Systems, Inc. (CIC). The Company had recorded a $1 million charge in 1991 representing the annual net loss incurred by CIC.
Interest Charges: Interest charges decreased $12.4 million in 1993 compared to 1992 as the Company continued to take advantage of lower interest rates on variable-rate and fixed-rate debt by retiring and refinancing higher cost debt. The Company's embedded cost of long-term debt decreased to 7.3% at December 31, 1993 compared to 7.5% and 7.9% at December 31, 1992 and 1991, respectively.
Pro forma interest charges decreased $3.3 million in 1992, primarily as a result of the refinancing of higher cost fixed-rate debt and lower interest rates on variable-rate debt.
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 revenues as depreciation. 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 recognized the importance of environmental responsibility and has taken a proactive position with respect to the potential environmental liability associated with former manufactured gas sites. The Company has an agreement with the Kansas Department of Health and Environment to systematically evaluate these sites in Kansas (see Note 3).
The Company currently has no Phase I affected units under the Clean Air Act of 1990. Until such time that additional regulations become final the Company will be unable to determine its compliance options or related compliance costs. (see Note 3).
Energy Policy Act: The 1992 Energy Policy Act (the Act) requires increased efficiency of energy usage and will potentially change 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 to its transmission system. Another part of the Act requires a special assessment to be 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.
Statement of Financial Accounting Standards No. 106 (SFAS 106) and No. 112 (SFAS 112): For discussion regarding the effect of SFAS 106 and SFAS 112 on the Company see Note 8 of the Notes to Financial Statements.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Independent Auditors' Report 20
Financial Statements:
Balance Sheets, December 31, 1993 and 1992 22 Statements of Income for the year ended December 31, 1993 23 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Cash Flows for the year ended December 31, 1993 24 (Successor), the period March 31 to December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Taxes for the year ended December 31, 1993 25 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Capitalization, December 31, 1993 and 1992 26 Statements of Common Stock Equity for the year ended 27 December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Notes to Financial Statements 28
Financial Statement Schedules:
V- Utility Plant for the year ended December 31, 1993, 50 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) VI- Accumulated Depreciation of Utility Plant for the year ended 53 December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor) the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor)
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, VII, VIII, IX, X, XI, XII and XIII.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Kansas Gas and Electric Company:
We have audited the accompanying balance sheet and statement of capitalization of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, inc.) as of December 31, 1993, and the related statements of income, cash flows, taxes, and common stock equity for the year then ended. 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 audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit 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 audit provides 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, 1993, and the results of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles.
As explained in Note 8 to the financial statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits.
Our audit was made for the purpose of forming an opinion on the 1993 basic financial statements taken as a whole. The financial statement schedules listed in the table of contents on page 19 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules for 1993 have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Kansas City, Missouri, ARTHUR ANDERSEN & CO. January 28, 1994
INDEPENDENT AUDITORS' REPORT
Kansas Gas and Electric Company:
We have audited the 1992 and 1991 financial statements of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) listed in the accompanying table of contents. Our audits also included the 1992 and 1991 financial statement schedules listed in the accompanying table of contents. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 1992 and the results of its operations and its cash flows for the periods indicated in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information shown therein.
DELOITTE & TOUCHE
Kansas City, Missouri January 29, 1993
KANSAS GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS
1. 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 (KG&E) for $454 million in cash and 23,479,380 shares of Western Resources common stock (the Merger). Western Resources also paid $20 million in costs to complete the Merger. The total cost of the acquisition to Western Resources was $1.066 billion. Simultaneously, KCA and KG&E merged and adopted the name of Kansas Gas and Electric Company. The Merger was accounted for as a purchase. For income tax purposes the tax basis of the Company's assets was not changed by the Merger. In the accompanying statements, KG&E prior to the Merger is labeled as the "Predecessor" and after the Merger as the "Successor". Throughout the notes to financial statements, the "Company, KG&E" refers to both Predecessor and Successor.
As Western Resources acquired 100% of the common and preferred stock of KG&E, the Company recorded an acquisition premium of $490 million on the balance sheet for the difference in purchase price and book value and increased common stock equity to reflect the new cost basis of Western Resources' investment in the Company. This acquisition premium and related income tax requirement of $294 million under Statement of Financial Accounting Standards No. 109 (SFAS 109) have been classified as plant acquisition adjustment in electric plant in service on the balance sheets. Under the provisions of the order of the Kansas Corporation Commission (KCC), the acquisition premium is recorded as an acquisition adjustment and not allocated to the other assets and liabilities of the Company.
The pro forma information for the year ended December 31, 1992 in the accompanying financial statements gives effect to the Merger as if it occurred on January 1, 1992, and was derived by combining the historical information for the three month period ended March 31, 1992 and the nine month period ended December 31, 1992. No purchase accounting adjustments were made for periods prior to the Merger in determining pro forma amounts, other than the elimination of preferred dividends, because such adjustments would be immaterial. This pro forma information is not necessarily indicative of the results of operations that would have occurred had the Merger been consummated on January 1, 1992, nor is it necessarily indicative of future operating results or financial position. The pro forma effects on the Company's net income for 1991 presented giving effect to the Merger as if it had occurred at the beginning of the earliest period presented would not be materially different from that shown in the income statements included herein.
In the November 1991 KCC order approving the Merger, a mechanism was approved to share equally between the shareholders and ratepayers the cost savings generated by the Merger in excess of the revenue requirement needed to allow recovery of the amortization of a portion of the acquisition adjustment, including income tax, calculated on the basis of a purchase price of KG&E's common stock at $29.50 per share. The order provides an amortization period
for the acquisition adjustment of 40 years commencing in August 1995, at which time the full amount of cost savings is expected to have been implemented. Merger savings will be measured by application of an inflation index to certain pre-merger operating and maintenance costs at the time of the next Kansas rate case. While the Company has achieved savings from the Merger, there is no assurance that the savings achieved will be sufficient to, or the cost savings sharing mechanism will operate as to fully offset the amortization of the acquisition adjustment. The order further provides a moratorium on increases, with certain exceptions, in the Company's Kansas electric rates until August 1995. The KCC ordered refunds totalling $32 million to the combined companies' (Western Resources and the Company) customers to share with customers the Merger-related cost savings achieved during the moratorium period. The first refund was made in April 1992 and amounted to approximately $4.9 million for the Company. A refund of approximately $4.9 million was made in December 1993 and an additional refund of approximately $8.7 million will be made in September 1994.
The KCC order approving the Merger requires the legal reorganization of the Company so that it is no longer held as a separate subsidiary after January 1, 1995, unless good cause is shown why such separate existence should be maintained. The Securities and Exchange Commission order relating to the Merger granted Western Resources an exemption under the Public Utilities Holding Company Act until January 1, 1995. In connection with a requested ruling that a merger of the Company into Western Resources would not adversely affect the tax structure of the merger, the Company received a response from the Internal Revenue Service that the IRS would not issue the requested ruling. In light of the IRS response, the Company withdrew its request for a ruling. The Company will consider alternative forms of combination or seek regulatory approvals to waive the requirements for a combination. There is no certainty as to whether a combination will occur or as to the form or timing thereof.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: The financial statements of KG&E include, through March 31, 1992, its 80% owned subsidiary, CIC Systems, Inc. (CIC). In April 1992, the Company disposed of its 80% interest in CIC. KG&E owns 47 percent 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 accounting policies of the Company are in accordance with generally accepted accounting principles as applied to regulated public utilities. The accounting and rates of the Company are subject to requirements of the KCC and the Federal Energy Regulatory Commission (FERC).
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 4.41% for 1993, 6.51% for the nine months ended December 31, 1992, 6.70% for the three months ended March 31, 1992, and 7.74% for 1991. 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.
Depreciation: Depreciation is provided on the straight-line method based on estimated useful lives of property. Composite provisions for book depreciation approximated 2.9% during 1993, 2.9% during the nine months ended December 31, 1992, 3.0% during the three months ended March 31, 1992, and 3.0% during 1991 of the average original cost of depreciable property.
Cash and Cash Equivalents: For purposes of the Statements of Cash Flows, cash and cash equivalents include cash on hand and highly liquid collateralized debt instruments purchased with maturities of three months or less.
Income Taxes: Income tax expense includes provisions for income taxes currently payable and deferred income taxes calculated in conformance with income tax laws, regulatory orders and Statement of Financial Accounting Standards No. 109 (SFAS 109) (see Note 9).
Investment tax credits are deferred as realized and 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 $22.3 and $16.6 million at December 31, 1993 and 1992, respectively, are recorded as a component of accounts receivable on the balance sheets. Certain amounts of unbilled revenues have been sold (see Note 6).
The Company had reserves for doubtful accounts receivable of $3.0 and $2.4 million at December 31, 1993 and 1992, respectively.
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, 1993 and 1992 was $17.4 and $26.0 million, respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts related to corporate-owned life insurance contracts (COLI), primarily with one highly rated major insurance company, are recorded on the balance sheets (millions of dollars):
1993 1992 Cash surrender value of contracts. . . $269.1 $230.3 Prepaid COLI . . . . . . . . . . . . . 9.5 4.8 Borrowings against contracts . . . . . (269.0) (85.8) COLI (net) . . . . . . . . . . . . $ 9.6 $149.3
The decrease in COLI (net) is a result of increased borrowings against the accumulated cash surrender value of the COLI policies. The COLI borrowings will be repaid with proceeds from death benefits. Management expects to realize increases in cash surrender value of contracts resulting from premiums and investment earnings on a tax free basis upon receipt of net proceeds from death benefits under the contracts. Interest expense included in corporate-owned life insurance (net) on the statements of income was $11.9 million for 1993, $5.3 million for the nine months ended December 31, 1992, $1.9 million for the three months ended March 31, 1992, and $7.3 for 1991.
As approved by the Kansas Corporation Commission (KCC), the Company is using a portion of the net income stream generated by COLI policies purchased in 1993 and 1992 (see Note 8) to offset Statement of Financial Accounting Standards No. 106 (SFAS 106) expenses.
Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
3. COMMITMENTS AND CONTINGENCIES
Environmental: The Company and the Kansas Department of Health and Environment entered into a consent agreement to perform preliminary assessments of six former manufactured gas sites. The preliminary assessments of these sites have been completed at minimal cost. Until such time that risk assessments are completed at these sites, it will be impossible to predict the cost of remediation. However, the Company is aware of other utilities in Region VII of the EPA (Kansas, Missouri, Nebraska, and Iowa) which have incurred remediation costs for such sites ranging between $500,000 and $10 million, depending on the site. The Company is also aware that the KCC has permitted another Kansas utility to recover a portion of the 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.
Spent Nuclear Fuel Disposal: Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from nuclear reactors. Under a contract with the DOE for disposal of spent nuclear fuel, the Company pays a quarterly fee to DOE of one mill per kilowatthour of net nuclear generation. These fees are included as part of nuclear fuel expense and amounted to $3.5 million for 1993, $1.6 million for the nine months ended December 31, 1992, $.5 million for the three months ended March 31, 1992, and $2.8 million for 1991.
Decommissioning: The Company's share of Wolf Creek decommissioning costs, currently authorized in rates, was estimated to be approximately $97 million in 1988 dollars. Decommissioning costs are being charged to operating expenses. Amounts so expensed are deposited in an external trust fund and will be used solely for the physical decommissioning of the plant. Electric rates charged to customers provide for recovery of these decommissioning costs over the estimated life of Wolf Creek. At December 31, 1993 and 1992, $13.2 and $9.3 million respectively, were on deposit in the decommissioning fund. On September 1, 1993, WCNOC filed an application with the KCC for an order approving a 1993 Wolf Creek Decommissioning Cost Study which estimates the
Company's share of Wolf Creek decommissioning costs at approximately $174 million in 1993 dollars. If approved by the KCC, management expects substantially all such cost increases to be recovered through the ratemaking process.
The Company carries $164 million in premature decommissioning insurance in the event of a shortfall in the trust fund. The insurance coverage 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. If the amount designated as decommissioning insurance is needed to implement the NRC-approved plan for stabilization and decontamination, it would not be available for decommissioning purposes.
Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.4 billion for a single nuclear incident. 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 nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index. 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 totalling approximately $2.8 billion ($1.3 billion, Company's share). This insurance is provided by a combination of "nuclear insurance pools" ($1.3 billion) and Nuclear Electric Insurance Limited (NEIL) ($1.5 billion). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. The remaining proceeds from the $2.8 billion insurance coverage ($1.3 billion, Company's share), if any, can be used for property damage up to $1.1 billion (Company's share) and premature decommissioning costs up to $117.5 million (Company's share) in excess of funds previously collected for decommissioning (as discussed under "Decommissioning"), with the remaining $47 million (Company's share) available for either property damage or premature decommissioning costs.
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 of approximately $9 million per year.
There can be no assurance that all potential losses or liabilities will be insurable or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance, to the extent not recoverable through rates, could have a material adverse effect on the Company's financial position and results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in sulfur dioxide and nitrogen oxide emissions effective in 1995 and 2000 and a probable reduction in toxic emissions. To meet the monitoring and reporting requirements under the acid rain program, the Company is installing continuous monitoring and reporting equipment at a total cost of approximately $2.3 million. At December 31, 1993, the Company had completed approximately $850 thousand of these capital expenditures with the remaining $1.4 million of capital expenditures to be completed in 1994 and 1995. The Company does not expect additional equipment to reduce sulfur emissions to be necessary under Phase II. The Company currently has no Phase I affected units.
The nitrogen oxide and toxic limits, which were not set in the law, will be specified in future EPA regulations. The EPA has issued for public comment preliminary nitrogen oxide regulations for Phase I group 1 units. Nitrogen oxide regulations for Phase II units and Phase I group 2 units are mandated in the Act to be promulgated by January 1, 1997. Although the Company has no Phase I units, the final nitrogen oxide regulations for Phase I group 1 may allow for early compliance for Phase II group 1 units. Until such time as the Phase I group 1 nitrogen oxide regulations are final, the Company will be unable to determine its compliance options or related compliance costs.
Federal Income Taxes: During 1991, the Internal Revenue Service (IRS) completed an examination of the Company's federal income tax returns for the years 1984 through 1988. In April 1992, the Company received the examination report and upon review filed a written protest in August 1992. In October 1993, the Company received another examination report for the years 1989 and 1990 covering the same issues identified in the previous examination report. Upon review of this report, the Company filed a written protest in November 1993. The most significant proposed adjustments reduce the depreciable basis of certain assets and investment tax credits generated. Management believes there are significant questions regarding the theory, computations, and sampling techniques used by the IRS to arrive at its proposed adjustments, and also believes any additional tax expense incurred or loss of investment tax credits will not be material to the Company's financial position and results of operations. Additional income tax payments, if any, are expected to be offset by investment tax credit carryforwards, alternative minimum tax credit carryforwards, or deferred tax provisions.
Other Investments: In prior years, the Company routinely purchased short-term investment grade commercial paper for special deposit interest accounts associated with tax-exempt pollution control bonds. On February 1, 1990, the Company purchased $6.6 million of Drexel Burnham Lambert Group Inc. (Drexel) commercial paper. On February 13, 1990, Drexel filed for bankruptcy. In 1990, additional claims being filed and potential lengthy litigation indicated full recovery would be unlikely; accordingly, the investment was written off in 1990. The Company recognized the recovery of approximately $4.2 million during the nine months ended December 31, 1992, of the investment, which is included in miscellaneous income.
Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the Company has entered into various commitments to obtain nuclear fuel, coal, and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1993, WCNOC's nuclear fuel commitments (Company's share) were approximately $18.0 million for uranium concentrates expiring at various times through 1997, $123.6 million for enrichment expiring at various times through 2014, and $45.5 million for fabrication through 2012. At December 31, 1993, the Company's coal and natural gas contract commitments in 1993 dollars under the remaining term of the contracts are $666 million and $20.4 million, respectively. The largest coal contract was renegotiated in early 1993 and expires in 2020 with the remaining coal contracts expiring at various times through 2013. The majority of natural gas contracts expire in 1995 with automatic one-year extension provisions. In the normal course of business, additional commitments and spot market purchases will be made to obtain adequate fuel supplies.
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.
4. RATE MATTERS AND REGULATION
Elimination of the Energy Cost Adjustment Clause (ECA): On March 26, 1992, in connection with the Merger, the KCC approved the elimination of the ECA for most retail customers effective April 1, 1992. The provisions for fuel costs included in base rates were established at a level intended by the KCC to equal the projected average cost of fuel through August 1995, and to include recovery of costs provided by previously issued orders relating to coal contract settlements and storm damage recovery discussed below. Any increase or decrease in fuel costs from the projected average will be absorbed by the Company.
Rate Stabilization Plan: In 1988, the KCC issued an order requiring that the accrual of phase-in revenues be discontinued effective December 31, 1988. Effective January 1, 1989, the Company began amortizing the phase-in revenue asset on a straight-line basis over 9-1/2 years.
Cost of Service Audit Appeal: In September 1991, the KCC ordered the Company to refund (which the Company has done) $5.6 million of revenues plus $0.6 million in interest, for the period July 2, 1990 through January 31, 1991. This order concluded the appeal of the February 1990 KCC order to reduce rates by $8.7 million. The Company had previously recorded reserves totalling $10.8 million; however, as the order also made rates permanent, the excess reserves of $3.3 million were reversed in September 1991.
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 on the balance sheets. The settlement resulted in the termination of a long-term coal contract. In June 1991, 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.
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 on the Company's balance sheet. In July 1991, 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).
Storm Damage Recovery: In October 1990, the Company asked the KCC for approval of a plan to recover the cost of damage primarily from the March 13 and June 19, 1990 storms. Approximately $15 million of capital expenditures were incurred. These costs have been included in the Company's electric plant accounts. In May 1991, the Company amended this request to include the estimated $5 million of capital expenditures associated with an April 1991 storm. In November 1991 and January 1992, the KCC approved the deferral and recovery of the capital expenditures of the 1990 and 1991 storms, respectively, as well as carrying charges thereon.
5. SHORT-TERM BORROWINGS
At December 31, 1993, the Company had bank credit arrangements available of $35 million. In addition, the Company has uncommitted loan participation agreements. Maximum short-term borrowings outstanding during 1993 and 1992 were $175.8 million on December 14, 1993 and $128 million on October 6, 1992. The weighted average interest rates, including fees, were 3.5% for 1993, 6.4% for the nine months ended December 31, 1992, 7.1% for the three months ended March 31, 1992, and 7.8% for 1991.
6. LONG-TERM DEBT
The amount of first mortgage bonds authorized by the KG&E 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. During 1993, the Company refinanced $65 million of first mortgage bonds by issuing $65 million of First Mortgage Bonds, 6 1/2% Series due 2005. In 1992, the Company refinanced $125 million of first mortgage bonds by issuing $135 million of First Mortgage Bonds, 7.6% Series due 2003.
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. The sinking fund requirements for certain pollution control series bonds can be met only through the acquisition and retirement of outstanding bonds.
The 6.80% series, due 2004, the 6% and 5 7/8% series due 2007 and the 7% series due 2031 are pledged as collateral for pollution control revenue bonds issued by Kansas municipalities.
On September 20, 1993, the Company terminated a long-term revolving credit agreement which provided for borrowings of up to $150 million. The loan agreement, which was effective through October 1994, was repaid without penalty. The weighted average interest rate, including fees, was 3.7% for 1993, 6.8% for the nine months ended December 31, 1992, 7.7% for the three months ended March 31, 1992, and 8.4% for 1991.
The Company has a long-term agreement, expiring in 1995, which contains provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables are accounted for as sales while those related to phase-in revenues are accounted for as collateralized borrowings. Additional receivables are continually sold to replace those collected. At December 31, 1993 and 1992, outstanding receivables amounting to $56.8 and $47.7 million, respectively, were considered sold under the agreement. The credit risk associated with the sale of customer accounts receivable is considered minimal. The weighted average interest rate, including fees, on this agreement was 3.7% for 1993, 6.6% for the nine months ended December 31, 1992, 7.9% for the three months ended March 31, 1992, and 7.8% for 1991. At December 31, 1993, an additional $16.4 million was available under the agreement.
Bonds maturing and acquisition and retirement of bonds for sinking fund requirements for the five years subsequent to December 31, 1993 are as follows:
Maturing Retiring Year Bonds Bonds (Dollars in Thousands)
1994. . . . . . . $ - $ 238 1995. . . . . . . - 253 1996. . . . . . . 16,000 270 1997. . . . . . . - 833 1998. . . . . . . - 1,050
7. SALE-LEASEBACK OF LA CYGNE 2
In 1987, the Company sold and leased back its 50 percent undivided interest in La Cygne 2 generating unit. The lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50 percent 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 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.
Future minimum annual lease payments required under the lease agreement are approximately $34.6 million for each year through 1998 and $715 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale has been deferred for financial reporting purposes, and is being amortized 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 1993, $20.6 million for the nine months ended December 31, 1992, $7.5 million for the three months ended March 31, 1992, and $30 million for 1991.
8. EMPLOYEE BENEFIT PLANS
Pension: The Company maintains noncontributory defined benefit pension plans covering substantially all employees of the Company prior to the Merger. Pension benefits are based on years of service and the employee's compensation during the five highest paid consecutive years out of ten before retirement. The Company's policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code.
The following table provides information on the components of pension cost for the Company's pension plans (millions of dollars):
April 1 | Jan.1 to 1993 to Dec.31 | March 31 1991 (Successor) | (Predecessor) Pension Cost: | Service cost . . . . . . . . . . . $ 3.2 $ 2.5 | $ .8 $ 3.1 Interest cost on projected | benefit obligation . . . . . . . 9.5 6.7 | 2.1 7.4 Return on plan assets. . . . . . . (14.1) (5.8) | (9.0) (14.0) Net amortization & deferral. . . . 4.9 (1.0) | 6.7 5.4 Net pension cost . . . . . . . . $ 3.5 $ 2.4 | $ .6 $ 1.9
The following table sets forth the plans' actuarial present value and funded status at November 30, 1993 and 1992 (the plan years) and a reconciliation of such status to the December 31, 1993 and 1992 financial statements (millions of dollars):
1993 1992 Funded Status: Actuarial present value of benefit obligations: Vested. . . . . . . . . . . . . . . . . . . . . $ 95.2 $ 82.9 Non-vested. . . . . . . . . . . . . . . . . . . 6.1 3.6 Total . . . . . . . . . . . . . . . . . . . . $101.3 $ 86.5
Plan assets at November 30 (principally debt and equity securities) at fair value. . . . . . $119.9 $113.7 Projected benefit obligation at November 30 . . . (125.5) (110.8) Plan assets in excess of projected benefit obligation at November 30 . . . . . . . . . . . (5.6) 2.9 Unrecognized transition asset . . . . . . . . . . (1.7) (2.0) Unrecognized prior service costs. . . . . . . . . 12.4 12.1 Unrecognized net gain . . . . . . . . . . . . . . (20.6) (26.1) Accrued pension costs at December 31. . . . . . . $(15.5) $(13.1)
Year Ended December 31, 1993 1992
Actuarial Assumptions: Discount rate . . . . . . . . . . . . . . . . . 7.0-7.75% 8.0-8.5% Annual salary increase rate . . . . . . . . . . 5.0 % 6.0% Long-term rate of return. . . . . . . . . . . . 8.0-8.5 % 8.0-8.5%
Early Retirement and Voluntary Separation Plans: In January 1992, the Board of Directors approved an early retirement plan and a voluntary separation program. The voluntary early retirement plan was offered to all vested participants of the Company's defined benefit pension plan who reached the age of 55 with 10 or more years of service on or before May 1, 1992. Certain pension plan improvements were made including a waiver of the actuarial reduction factors for early retirement and a cash incentive payable as a monthly supplement up to 60 months or a lump sum payment. Of the 111 employees eligible for the early retirement option, 71, representing 6% of the Company's work force, elected to retire on or before the May 1, 1992, deadline. Another 29 employees, with 10 or more years of service, elected to participate in the voluntary separation program. In addition, 61 employees received Merger-related severance benefits. The actuarial cost, based on plan provisions for early retirement and voluntary separation programs, and Merger- related severance benefits, was approximately $3.9 million of which $1.8 million was included in the pension liability at December 31, 1992. The actuarial cost was considered in purchase accounting for the Merger (See Note 1). Postretirement: The Company adopted the provisions of Statement of Financial Accounting Standards No. 106 (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. Based on actuarial projections and adoption of the transition method of implementation which allows a 20-year amortization of the accumulated benefit obligation, the annual expense under SFAS 106 was approximately $3.4 million in 1993 (as compared to approximately $1.8 million on a cash basis) and the Company's total obligation was approximately $23.9 million at December 31, 1993. To mitigate the impact of SFAS 106 expense, the Company has implemented programs to reduce health care costs. In addition, the Company has received an order from the KCC permitting the initial deferral of SFAS 106 expense. To mitigate the impact SFAS 106 expense will have on rate increases, the Company will include in the future computation of cost of service the actual SFAS 106 expense and an income stream generated from corporate-owned life insurance policies (COLI) purchased in 1993 and 1992. To the extent SFAS 106 expense exceeds income from the COLI program, this excess will be deferred (as allowed by FASB Emerging Issues Task Force Issue No. 92-12) and offset by income generated through the deferral period by the COLI program. Should the income stream generated by the COLI program not be sufficient to offset the deferred SFAS 106 expense, the KCC order allows recovery of such deficit through the ratemaking process.
Prior to the adoption of SFAS 106 the Company's policy was to recognize expenses as claims were paid. The costs of benefits were $0.8 million for the nine months ended December 31, 1992, $0.2 million for the three months ended March 31, 1992, and $2.1 million for 1991.
The following table summarizes the status of the Company's postretirement plans for financial statement purposes and the related amount included in the balance sheet:
December 31, 1993 (Dollars in Millions) Actuarial present value of postretirement benefit obligations: Retirees. . . . . . . . . . . . . . . . . . . . $ 12.4 Active employees fully eligible . . . . . . . . 2.5 Active employees not fully eligible . . . . . . 9.0 Unrecognized prior service cost . . . . . . . . (.1) Unrecognized transition obligation. . . . . . . (20.4) Unrecognized net loss . . . . . . . . . . . . . (1.7) Balance sheet liability . . . . . . . . . . . . . . $ 1.7
For measurement purposes, an annual health care cost growth rate of 13% was assumed for 1994, decreasing to 6% by 2002 and thereafter. The accumulated post retirement benefit obligation was calculated using a weighted-average discount rate of 7.75%, a weighted-average compensation increase rate of 5.0%, and a weighted-average expected rate of return of 8.5%. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by 1% each year would increase the present value of the accumulated projected benefit obligation by $.6 million and the aggregate of the service and interest cost components by $.1 million.
Postemployment: The FASB has issued Statement of Financial Accounting Standards No. 112 (SFAS 112), which establishes accounting and reporting standards for postemployment benefits. The new statement will require the Company to recognize the liability to provide postemployment benefits when the liability has been incurred. The Company adopted SFAS 112 effective January 1, 1994. To mitigate the impact adopting SFAS 112 will have on rate increases, the Company will file an application with the KCC for an order permitting the initial deferral of SFAS 112 transition costs and expenses and its inclusion in the future computation of cost of service net of an income stream generated from COLI. At December 31, 1993, the Company estimates SFAS 112 liability to total approximately $700,000.
Savings Plans: The Company maintains 401(k) savings plans in which substantially all employees participate. The Company matches employees' contributions up to a maximum limit of 3 percent of the employees' salary. Prior to the Merger, the Company's matching contribution was based on the Company's performance during the prior year and the level of employee contributions. The funds of the plans are deposited with a trustee and invested at each employee's option in one or more investment funds, including a Western Resources common stock fund. The Company's contributions were $1.3 for 1993, $1.7 million for the nine months ended December 31, 1992, $0.2 million for the three months ended March 31, 1992, and $2.0 million for 1991.
9. INCOME TAXES
The Company adopted Statement of Financial Accounting Standards No. 96 (SFAS 96) in 1987. This statement required the Company to establish deferred tax assets and liabilities, as appropriate, for all temporary differences, and to adjust deferred tax balances to reflect changes in tax rates expected to be in effect during the periods the temporary differences reverse. SFAS 96 was superseded by SFAS 109 issued in February 1992 and the Company adopted the provisions of that standard prospectively in the first quarter of 1992. The accounting for SFAS 109 is substantially the same as SFAS 96.
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 through future rates, 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. Accordingly, the adoption of SFAS 109 did not have a material effect on the Company's results of operations.
At December 31, 1993, the Company had unused investment tax credits of approximately $7.1 million available for carryforward which, if not utilized, will expire in the years 2000 through 2002 (see Note 3). In addition, the Company has alternative minimum tax credits generated prior to April 1, 1992, which carryforward without expiration, of $53.9 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, 1993.
Beginning April 1, 1992, the Company is part of the consolidated income tax return of Western Resources. However, the Company determines its income tax provisions on a separate company basis.
Deferred income taxes result from temporary differences between the financial statement and tax basis of the Company's assets and liabilities. The sources of these differences and their cumulative tax effects are as follows:
December 31, 1993 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (350,105) $ (350,105) Energy and purchased gas adjustment clauses . . . . . . . 3,257 - 3,257 Phase-in revenues. . . . . . . . . - (35,573) (35,573) Deferred gain on sale-leaseback. . 116,186 - 116,186 Alternative minimum tax credits. . 39,882 - 39,882 Deferred coal contract settlements. . . . . . . . . . . - (7,797) (7,797) Deferred compensation/pension liability. . . . . . . . . . . . 10,856 - 10,856 Acquisition premium. . . . . . . . - (300,814) (300,814) Deferred future income taxes . . . - (109,178) (109,178) Other. . . . . . . . . . . . . . . - (12,873) (12,873) Total Deferred Income Taxes. . . . . $ 170,181 $ (816,340) $ (646,159)
December 31, 1992 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (324,972) $ (324,972) Energy and purchased gas adjustment clauses . . . . . . . 2,691 - 2,691 Phase-in revenues. . . . . . . . . - (37,564) (37,564) Deferred gain on sale-leaseback. . 104,573 - 104,573 Alternative minimum tax credits. . 39,882 - 39,882 Deferred coal contract settlements. . . . . . . . . . . - (9,263) (9,263) Deferred compensation/pension liability. . . . . . . . . . . . 11,002 - 11,002 Acquisition premium. . . . . . . . - (313,721) (313,721) Deferred future income taxes . . . - (146,962) (146,962) Other. . . . . . . . . . . . . . . 3,138 - 3,138 Total Deferred Income Taxes. . . . . $ 161,286 $ (832,482) $ (671,196)
10. LEGAL PROCEEDINGS
The Company is involved in various other 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.
A provision of $12 million was recorded in miscellaneous expenses on the 1991 statement of income with respect to various legal matters.
11. 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:
Cash and Cash Equivalents- The carrying amount approximates the fair value because of the short- term maturity of these investments. Decommissioning Trust- The fair value of the decommissioning trust is based on quoted market prices at December 31, 1993 and 1992. 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 coupon 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, 1993 1992 1993 1992 (Dollars in Thousands)
Cash and cash equivalents. . . . . . . $ 63 $ 892 $ 63 $ 892 Decommissioning trust. . . 13,204 9,272 13,929 9,500 Variable-rate debt . . . . 478,743 375,909 478,743 375,909 Fixed-rate debt. . . . . . 603,920 679,145 660,750 705,970
12. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1993 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands)
La Cygne 1 (a) Jun 1973 $ 150,265 $ 91,175 342 50 Jeffrey 1 (b) Jul 1978 65,803 28,717 140 20 Jeffrey 2 (b) May 1980 64,375 25,552 135 20 Jeffrey 3 (b) May 1983 95,336 31,084 140 20 Wolf Creek (c) Sep 1985 1,366,387 281,819 533 47
(a) Jointly owned with Kansas City Power & Light Company (KCP&L) (b) Jointly owned with Western Resources, UtiliCorp United Inc., and a third party (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 percent undivided interest in La Cygne 2 (representing 335 MW capacity) sold and leased back to the Company in 1987, are included in operating expenses in 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.
13. QUARTERLY FINANCIAL STATISTICS (Unaudited) (Dollars in Thousands)
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.
4th Qtr. 3rd Qtr. 2nd Qtr. 1st. Qtr. (Successor)
Operating revenues. . . . . $136,097 $191,941 $150,478 $138,481 Operating income. . . . . . 26,188 52,874 35,545 32,774 Net income. . . . . . . . . 13,692 46,406 24,274 23,731 Earnings applicable to common stock . . . . . 13,692 46,406 24,274 23,731
4th Qtr. 3rd Qtr. 2nd Qtr. 1st. Qtr. (Successor) |(Predecessor) | Operating revenues. . . . . $127,058 $167,825 $128,655| $130,713 Operating income. . . . . . 29,282 49,541 29,174| 22,165 Net income. . . . . . . . . 15,528 35,987 20,426| 6,040 Earnings applicable | to common stock . . . . . 15,528 35,987 20,426| 5,835
14. RELATED PARTY TRANSACTIONS
Subsequent to the Merger, the cash management function, including cash receipts and disbursements, for KG&E has been assumed by Western Resources. As a result, the proceeds of cash collections, including short-term borrowings, less disbursements related to KG&E transactions have been recorded by the Companies through an intercompany account which, at December 31, 1993, resulted in a net advance by KG&E to Western Resources of $192.8 million. Certain of the Company's operating expenses have been allocated 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.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no disagreements with accountants on accounting and financial disclosure. Information relating to a change in accountants is incorporated by reference from the Company's Current Report on Form 8-K dated March 8, 1993.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Western Resources, Inc. owns 100 percent of the Company's outstanding common stock. A Director Business Experience Since 1988 and Other Continuously Name Age Directorships Other Than The Company Since
Kent R. Brown 48 Chairman of the Board, President and 1992 Chief Executive Officer since June 1992, and prior to that President and Chief Executive Officer since March 1992, and prior to that Group Vice President Directorships Bank IV Wichita
Robert T. Crain 68 Owner, Crain Realty, Co., Fort Scott, 1992(b) (a) Kansas Directorships Citizens National Bank
Anderson E. 60 President, Jackson Mortuary, Wichita, 1994 Jackson Kansas
Donald A. 60 President, Maupintour, Inc., Lawrence, 1992(b) Johnston Kansas (Escorted Tours and Travel) (a) Directorships Commerce Bank, Lawrence Maupintour, Inc.
Steven L. 48 Executive Vice President and Chief 1992 Kitchen Financial Officer, Western Resources, Inc., (since March 1990) and prior to that Senior Vice President, Finance and Accounting (October 1987 to March 1990)
Glenn L. 68 Retired Vice President - Nuclear of the 1992(b) Koester Company
James J. Noone 73 Attorney and retired Administrative Judge 1992(b) (a) for the District Court of Sedgwick County, Kansas
Marilyn B. 44 President, Bank IV Wichita, 1994 Pauly Wichita, Kansas Directorships St. Francis Regional Medical Center Farmers Mutual Alliance Insurance Company
A Director Business Experience Since 1988 and Other Continuously Name Age Directorships Other Than The Company Since
Newton C. Smith 72 Physician and Surgeon, Arkansas City, 1992(b) Kansas
Richard Smith 60 President, Range Oil Company 1993 Directorships Bank IV Kansas Wichita HCA Wesley Medical Center
(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, Mr. Koester, Mr. Noone, and Mr. Newton Smith were directors of the former Kansas Gas & Electric Company since 1981, 1980, 1986, 1986, and 1985, respectively.
Outside Directors are paid $3,750 per quarter retainer and all Directors are paid an attendance fee of $600 for Directors' meetings ($300 if attending by phone) and $500 for committee meetings. An additional committee meeting 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.
The Board of Directors held 5 meetings during the year and the Audit Committee held 2 meetings. All Directors attended 75% or more of their applicable meetings.
Other information required by Item 10 is omitted pursuant to General Instruction J(2)(c) to Form 10-K.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction J(2)(c) to Form 10-K.
ITEM 12.

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.

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.

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, 1993 and 1992 Statements of Income for the year ended December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Cash Flows for the year ended December 31, 1993 (Successor), the period March 31 to December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Taxes for the year ended December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Statements of Capitalization, December 31, 1993 and 1992 Statements of Common Stock Equity for the year ended December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Notes to Financial Statements
The following supplemental schedules are included herein.
SCHEDULES
Schedule V - Utility Plant for the year ended December 31, 1993, (Successor), the nine months ended December 31, 1992 (Successor), the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor) Schedule VI - Accumulated Depreciation of Utility Plant for the year ended December 31, 1993 (Successor), the nine months ended December 31, 1992 (Successor) the three months ended March 31, 1992 (Predecessor), and the year ended December 31, 1991 (Predecessor)
REPORTS ON FORM 8-K
Form 8-K dated January 31, 1994
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) to 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-six 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, and August 24, 1993, (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)
4(c)2 Thirty-seventh Supplemental Indenture dated as of January 15, 1994, to the Company's Mortgage and Deed of Trust (Filed electronically)
4(c)3 Thirty-eighth Supplemental Indenture dated as of March 1, 1994, to the Company's Mortgage and Deed of Trust (Filed electronically)
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)1 Severance Agreement (Filed as Exhibit 10(a)1 to Form 10-K for the I year ended December 31, 1990, File No. 1-7324).
10(a)2 Severance Agreement (Filed as Exhibit 10(a)2 to Form 10-K for the I year ended December 31, 1990, File No. 1-7324).
10(a)3 Severance Agreement (Filed as Exhibit 10(a)3 to Form 10-K for the I year ended December 31, 1990, File No. 1-7324).
10(b) 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(b)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(c) Outside Directors' Deferred Compensation Plan
12 Computation of Ratio of Consolidated Earnings to Fixed Charges. (Filed electronically)
16 Letter re Change in Certifying Accountant. (Filed as Exhibit 16 to I the Current Report on Form 8-K dated March 8, 1993.
23(a) Consent of Independent Public Accountants, Arthur Andersen & Co. (Filed electronically)
23(b) Consent of Independent Public Accountants, Deloitte & Touche (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 18, 1994 By KENT R. BROWN (Kent R. Brown, Chairman of the Board, President and Chief Executive Officer)
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Signature Title Date
Chairman of the Board, President KENT R. BROWN and Chief Executive Officer March 18, (Kent R. Brown) (Principal Executive Officer)
Secretary, Treasurer and General RICHARD D. TERRILL Counsel (Principal Financial March 18, (Richard D. Terrill) and Accounting Officer)
ROBERT T. CRAIN (Robert T. Crain)
(Anderson E. Jackson)
DONALD A. JOHNSTON (Donald A. Johnston)
S. L. KITCHEN Directors March 18, (S. L. Kitchen)
GLENN L. KOESTER (Glenn L. Koester)
JAMES J. NOONE (James J. Noone)
(Marilyn B. Pauly)
NEWTON C. SMITH, M.D. (Newton C. Smith, M. D.)
RICHARD SMITH (Richard Smith)