ITEM 1. BUSINESS
GENERAL
Kansas Gas and Electric Company is an electric utility engaged in the generation, transmission, distribution and sale of electric energy in southeastern Kansas including the Wichita metropolitan area. We are a wholly- owned subsidiary of Western Resources, Inc. (Western Resources). We own 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). Our corporate headquarters are located in Wichita, Kansas. At December 31, 1999, we had no employees. All employees are provided by our parent company, Western Resources.
On March 28, 2000, Western Resources' board of directors approved the separation of its electric and non-electric utility businesses. The separation is currently expected to be effected through an exchange offer to be made to Western Resources shareholders in the third quarter of 2000. The exchange ratio will be described in materials furnished to Western Resources shareholders upon commencement of the exchange offer. Western Resources expects to complete the separation in the fourth quarter of 2000, but Western Resources can give no assurance that the separation will be completed.
On March 18, 1998, Western Resources signed an Amended and Restated Plan of Agreement and Plan of Merger with the Kansas City Power & Light Company (KCPL) under which KGE, KPL, a division of Western Resources, and KCPL would have been combined into a new company called Westar Energy, Inc. KCPL has notified Western Resources that it has terminated the contemplated transaction.
Discussion of other factors affecting the company are set forth in the Notes to Financial Statements and Management's Discussion and Analysis included herein.
FORWARD-LOOKING STATEMENTS
Certain matters discussed here and elsewhere in this Annual Report are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe," "anticipate," "expect" or words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning capital expenditures, earnings, litigation, rate and other regulatory matters, possible corporate restructurings, mergers, acquisitions, dispositions, liquidity and capital resources, compliance with debt covenants, interest and dividends, environmental matters, changing weather, nuclear operations, accounting matters, and the overall economy of our service area. What happens in each case could vary materially from what we expect because of such things as electric utility deregulation, including ongoing
municipal, state and federal activities; future economic conditions; legislative and regulatory developments; our regulatory and competitive markets; and other circumstances affecting anticipated operations, sales and costs.
SEGMENT INFORMATION
Financial information with respect to business segments is set forth in Note 14 of the Notes to Financial Statements included herein.
ELECTRIC OPERATIONS
General
We supply electric energy at retail to approximately 287,000 customers in 147 communities in Kansas. We also supply electric energy to 27 communities and 1 rural electric cooperative, and have contracts for the sale, purchase or exchange of electricity with other utilities at wholesale.
Our electric sales volumes for the last three years were as follows:
1999 1998 1997 (Thousands of MWH) Residential . . 2,601 2,784 2,490 Commercial. . . 2,413 2,383 2,211 Industrial. . . 3,548 3,569 3,518 Other . . . . . 45 45 45 Wholesale . . . 1,832 1,541 2,101 Total . . . . 10,439 10,322 10,365
Our electric sales for the last three years were as follows:
1999 1998 1997 (Dollars in Thousands) Residential . . $220,645 $237,571 $214,719 Commercial. . . 169,427 170,473 162,913 Industrial. . . 163,158 167,331 165,614 Other . . . . . 21,855 22,370 17,856 Wholesale . . . 63,255 50,634 53,343 Total . . . . $638,340 $648,379 $614,445
Competition: The United States electric utility industry is evolving from a regulated monopolistic market to a competitive marketplace. The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted the FERC (Federal Energy Regulatory Commission) to order electric utilities to allow third parties the use of their transmission systems to sell electric power to wholesale customers. A wholesale sale is defined as a utility selling electricity to a "middleman," usually a city or its utility company, to resell to the ultimate retail customer. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires
us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order 2000) encouraging formation of regional transmission organizations (RTOs), whose purpose is to facilitate greater competition at the wholesale level. Due to our participation in the formation of the Southwest Power Pool RTO, we anticipate that FERC Order 2000 will not have a material effect on us or our operations.
In December 1999, the Wichita, Kansas, City Council authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace us as the supplier of electricity in Wichita. Our rates are currently 7% below the national average for retail customers. The average rates charged to retail customers in territories served by Western Resources' KPL division are 19% lower than our rates. Customers within the Wichita metropolitan area account for approximately 56% of our total energy sales. We have an exclusive franchise with the City of Wichita to provide retail electric service that expires March 2002. Under Kansas law, we will continue to have the exclusive right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. See also Regulations and Rates below regarding a complaint filed with the FERC against us by the City of Wichita.
For further discussion regarding competition in the electric utility industry and the potential impact on the company, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Regulation and Rates: As a Kansas electric utility, we are subject to the jurisdiction of the KCC which has general regulatory authority over our rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts and various other matters. We are also subject to the jurisdiction of the KCC with respect to the issuance of certain securities.
Additionally, we are subject to the jurisdiction of the FERC, which has authority over wholesale sales of electricity and the issuance of certain securities. We are also subject to the jurisdiction of the Nuclear Regulatory Commission for nuclear plant operations and safety.
In September 1999, the City of Wichita filed a complaint with the FERC against us, alleging improper affiliate transactions between us and KPL, a division of Western Resources. The City of Wichita requests the FERC to equalize the generation costs between us and KPL, in addition to other matters. FERC has issued an order setting this matter for hearing and has referred the case to a settlement judge. The hearing has been suspended pending settlement discussions between the parties. We believe that the City of Wichita's complaint is without merit and intend to defend against it vigorously.
On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization of commercial and industrial users of electricity in Kansas, filed a complaint with the KCC requesting an investigation of Western Resources' and KGE's rates. The KIC alleges that these rates are not based on current costs. We will oppose this request vigorously but are unable to predict whether the KCC will open an investigation.
Additional information with respect to Regulation and Rates is discussed in Notes 1 and 4 of the Notes to Financial Statements and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Environmental Matters: We currently hold all Federal and State environmental approvals required for the operation of our generating units. We believe we are presently in substantial compliance with all air quality regulations (including those pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx)) promulgated by the State of Kansas and the Environmental Protection Agency (EPA).
The Jeffrey Energy Center (JEC) and La Cygne 2 units have met: (1) the Federal sulfur dioxide standards through the use of low sulfur coal (See Coal); (2) the Federal particulate matter standards through the use of electrostatic precipitators; and (3) the Federal NOx standards through boiler design and operating procedures. The JEC units are also equipped with flue gas scrubbers providing additional sulfur dioxide and particulate matter emission reduction capability when needed to meet permit limits.
The Kansas Department of Health and Environment (KDHE) regulations, applicable to our other generating facilities, prohibit the emission of more than 3.0 pounds of sulfur dioxide per million Btu of heat input. We have sufficient low sulfur coal under contract (See Coal) to allow compliance with such limits at La Cygne 1 for the life of the contract. All facilities burning coal are equipped with flue gas scrubbers and/or electrostatic precipitators.
We must comply with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. We have installed continuous monitoring and reporting equipment to meet the acid rain requirements. We do not expect any material capital expenditures to be required to meet Phase II sulfur dioxide and nitrogen oxide requirements.
All of our generating facilities are in substantial compliance with the Best Practicable Technology and Best Available Technology regulations issued by the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are administered in Kansas by the KDHE.
Additional information with respect to Environmental Matters is discussed in Note 2 of the Notes to Financial Statements included herein.
Fossil Fuel Generation
Capacity: The aggregate net generating capacity of our system is presently 2,605 megawatts (MW). The system comprises interests in twelve fossil fueled steam generating units, one nuclear generating unit (47% interest) and one diesel generator, located at seven generating stations.
Our 1999 peak system net load occurred on August 11, and amounted to 2,111 MW. Our net generating capacity together with power available from firm interchange and purchase contracts, provided a capacity margin of approximately
12% above system peak responsibility at the time of the peak.
We are a member of the Southwest Power Pool (SPP). SPP's responsibility is to maintain system reliability on a regional basis and is working with us and other members to become an RTO. The region encompasses areas within the eight states of Kansas, Missouri, Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi. We are also a member of the SPP transmission tariff along with ten other transmission providers in the region. Revenues from this tariff are divided among the tariff members based upon calculated impacts to their respective system. The tariff allows for both non-firm and firm transmission access.
We are a member of the Western Systems Power Pool (WSPP). Under this arrangement, electric utilities and marketers throughout the western United States have agreed to market energy. Services available include short-term and long-term economy energy transactions, unit commitment service, firm capacity and energy sales and energy exchanges.
We have an agreement with Midwest Energy, Inc. (MWE) to provide MWE with peaking capacity of 61 MW through May, 2007. We also have an agreement with Empire District Electric Company (Empire) to provide Empire with peaking and base load capacity of 80 MW through May, 2000.
Future Capacity: We do not contemplate any significant expenditures in connection with construction of any major generating facilities for the next five years. (See Item 7. Management's Discussion and Analysis, Liquidity and Capital Resources).
Fuel Mix: Our coal-fired units comprise 1,126 MW of the total 2,605 MW of generating capacity and our nuclear unit provides 550 MW of capacity. Of the remaining 929 MW of generating capacity, units that can burn either natural gas or oil account for 926 MW, and the remaining unit which burns only diesel fuel accounts for 3 MW (See Item 2.
ITEM 2. PROPERTIES
We own or lease and operate an electric generation, transmission, and distribution system in Kansas.
ELECTRIC FACILITIES Unit Year Principal Unit Capacity Name No. Installed Fuel (MW)
Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 151 2 1967 Gas--Oil 376
Jeffrey Energy Center (20%) (a): Steam Turbines 1 1978 Coal 149 2 1980 Coal 148 3 1983 Coal 148 Wind Turbines 1 1999 - (c) 2 1999 - (c)
La Cygne Station (50%): Steam Turbines 1 (a) 1973 Coal 344 2 (b) 1977 Coal 337
Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 44 2 1954 Gas--Oil 74 3 1956 Gas--Oil 108 4 1959 Gas--Oil 106
Neosho Energy Center: Steam Turbine 3 1954 Gas--Oil 67
Wichita Plant: Diesel Generator 5 1969 Diesel 3
Wolf Creek Generating Station (47%)(a): Nuclear 1 1985 Uranium 550
Total 2,605
(a) We jointly own Jeffrey Energy Center (20%), La Cygne 1 generating unit (50%) and Wolf Creek Generating Station (47%). Western Resources jointly owns 64% of Jeffrey Energy Center. KCPL jointly owns 50% of La Cygne Station and 47% of Wolf Creek Generating Station. (b) In 1987, KGE sold and leased back its 50% individual interest in the La Cygne 2 generating unit. (c) Our share is less than 0.5 MW.
FINANCING
Substantially all of our utility properties are encumbered by a first priority mortgage pursuant to which bonds have been issued.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Information on legal proceedings involving the company is set forth in Notes 2, 3, and 4 of Notes to Financial Statements included herein. See also Item 1. Business, Environmental Matters, and Regulation and Rates.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Information required by Item 4 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of our common stock is owned by Western Resources and is not traded on an established public trading market.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
In Management's Discussion and Analysis we explain the general financial condition and the operating results for the company. We explain:
- What factors impact our business - What our earnings and costs were in 1999 and 1998 - Why these earnings and costs differed from year to year - How our earnings and costs affect our overall financial condition - What our capital expenditures were for 1999 - What we expect our capital expenditures to be for the years 2000 through 2002 - How we plan to pay for these future capital expenditures - Any other items that particularly affect our financial condition or earnings
As you read Management's Discussion and Analysis, please refer to our Statements of Income on page 33. These statements show our operating results for 1999, 1998 and 1997. In Management's Discussion and Analysis, we analyze and explain the significant annual changes of specific line items in the Statements of Income.
Summary of Factors Affecting Net Income
Net income decreased $19.5 million from 1998 to 1999 for several reasons. Retail sales were lower as a result of milder weather and rate decreases. Operating expenses were higher primarily because of increased costs associated with dispatching electric power and a scheduled outage at Wolf Creek. Other income was lower because we received less proceeds from our corporate-owned life insurance policies in 1999 compared to 1998.
Termination of Merger Agreement with Kansas City Power & Light Company
On March 18, 1998, Western Resources signed an Amended and Restated Plan of Agreement and Plan of Merger with the Kansas City Power & Light Company (KCPL) under which KGE, KPL, a division of Western Resources, and KCPL would have been combined into a new company called Westar Energy, Inc. KCPL has notified Western Resources that it has terminated the contemplated transaction.
OPERATING RESULTS
The KCC and the Federal Energy Regulatory Commission (FERC) authorize rates for our sales. Changing weather affects the amount of electricity our customers use. Very hot summers and very cold winters prompt more demand, especially among our residential customers. Mild weather reduces demand.
Many things will affect our future sales. They include: - The weather - Our electric rates - Competitive forces - Customer conservation efforts - Wholesale demand - The overall economy of our service area - The City of Wichita's attempt to create a municipal electric utility - The cost of fuel included in base rates
The following tables reflect the changes in electric sales volumes, as measured by megawatt hours, for the years ended December 31, 1999, 1998 and 1997:
1999 1998 % Change Residential. . . . . . . 2,601,308 2,783,998 (6.6)% Commercial . . . . . . . 2,413,126 2,383,197 1.3 % Industrial . . . . . . . 3,548,216 3,568,948 (0.6)% Other . . . . . . . . . 44,753 45,485 (1.6)% Total Retail . . . . . 8,607,403 8,781,628 (2.0)% Wholesale . . . . . . . 1,831,943 1,540,546 18.9 % Total . . . . . . . . 10,439,346 10,322,174 1.1 %
1998 1997 % Change Residential. . . . . . . 2,783,998 2,489,796 11.8 % Commercial . . . . . . . 2,383,197 2,211,016 7.8 % Industrial . . . . . . . 3,568,948 3,517,539 1.5 % Other. . . . . . . . . . 45,485 45,323 0.4 % Total Retail . . . . . 8,781,628 8,263,674 6.3 % Wholesale . . . . . . . 1,540,546 2,100,888 (26.7)% Total. . . . . . . . . 10,322,174 10,364,562 (0.4)%
1999 compared to 1998: Gross profit margin as a percentage of sales increased 1.5%. Total sales decreased $10 million. Our service territories averaged 27% fewer cooling degree days in 1999, lowering our retail sales by $12.7 million. The implementation of our electric rate decreases on June 1, 1999, and June 1, 1998 further decreased our retail sales $10 million. Increased wholesale sales of $12.6 million partially offset the retail sales decreases. Due to warmer than normal weather throughout the Midwest in July 1999 and increased availability of our coal-fired generation stations, we were able to sell more electricity to wholesale customers in 1999.
Cost of sales decreased approximately $11.9 million primarily due to lower purchased power expense. We purchased less power to serve our retail customers because of milder weather which reduced demand.
1998 compared to 1997: Gross profit increased 3%, or $14.3 million. This increase is primarily due to increased retail sales volumes as a result of warmer summer temperatures in 1998. The implementation of a $10 million electric rate decrease in 1998 and decreased wholesale sales volumes partially offset the higher retail sales. See Note 4 for further information on our electric rate
decreases.
Increased cost of sales partially offset the increased sales. Actual cost of fuel to generate electricity (coal, nuclear fuel, natural gas and oil) and the amount of power purchased from other utilities was $19.6 million higher in 1998. With an increase in customer demand for electricity and the availability of our Wolf Creek nuclear generating station and La Cygne coal generating station during 1998, we were able to produce more electricity. The increase in net generation caused our fuel costs to increase during 1998.
Items included in energy cost of sales are fuel expense and purchased power expense (electricity we purchase from others for resale.)
Business Segments
We have defined two business segments, electric operations and nuclear generation, based on how management currently evaluates our business. Our business segments are based on differences in products and services, production processes and management responsibility.
We manage our business segments' performance based on our earnings before interest and taxes (EBIT). EBIT does not represent cash flow from operations as defined by generally accepted accounting principles, nor should it be construed as an alternative to operating income and is indicative neither of operating performance nor cash flows available to fund the cash needs of our company. Items excluded from EBIT are significant components in understanding and assessing the financial performance of our company. We believe presentation of EBIT enhances an understanding of financial condition, results of operations and cash flows because EBIT is used by our company to satisfy its debt service obligations, capital expenditures and other operational needs, as well as to provide funds for growth. Our computation of EBIT may not be comparable to other similarly titled measures of other companies. The following discussion identifies key factors affecting our business segments.
1999 1998 1997 Electric Operations: (Dollars in Thousands) External sales. . . . . . . . . . . $ 638,340 $ 648,379 $ 614,445 Depreciation and amortization . . . 61,531 59,239 57,521 EBIT. . . . . . . . . . . . . . . . 193,980 219,014 180,954
Nuclear Generation: Internal sales. . . . . . . . . . . $ 108,445 $ 117,517 $ 102,330 Depreciation and amortization . . . 39,629 39,583 65,902 EBIT. . . . . . . . . . . . . . . . (25,214) (20,920) (60,968)
Electric Operations
External sales reflect power produced for sale to wholesale and retail customers.
1999 compared to 1998: External sales decreased $10 million. This decrease is primarily due to decreased retail sales volumes as a result of milder temperatures in 1999 and the implementation of our rate decreases. Increased wholesale sales partially offset these decreases. In 1999 and 1998, the wholesale power market experienced extreme volatility in prices and supply.
EBIT decreased $25 million primarily because of lower gross profit and increased operating expenses. Operating expenses were higher primarily because KGE's costs associated with dispatching electric power were higher. The restarting of our Neosho generation station, and a boiler outage at our Gordon Evans generation station also contributed to our increased operating expenses.
1998 compared to 1997: External sales increased $33.9 million. This increase is primarily due to increased sales volumes as a result of warmer summer temperatures in 1998. The implementation of a $10 million electric rate decrease in 1998 partially offset the higher sales. See Note 4 for further information on our electric rate decreases.
EBIT increased $38.1 million. This increase is primarily attributable to increased sales and lower operating and maintenance costs.
Nuclear Generation
Nuclear generation has no external sales because it provides all of its power to its co-owners KGE, KCPL and Kansas Electric Power Cooperative, Inc. Internal sales include the internal transfer price that Nuclear Generation charges electric operations. The amounts above are our 47% share of Wolf Creek's operating results. EBIT is negative because internal sales are less than Wolf Creek's costs.
Wolf Creek has a scheduled refueling and maintenance outage approximately every 18 months. The next outage is scheduled in September 2000. During an outage, Wolf Creek produces no power for its co-owners; therefore internal sales and EBIT decrease and nuclear fuel expense decreases.
1999 compared to 1998: Internal sales and EBIT decreased primarily due to the scheduled 36-day refueling and maintenance outage at Wolf Creek in 1999. In 1998 Wolf Creek operated the entire year without any outages.
1998 compared to 1997: Internal sales and EBIT were primarily higher in 1998 than in 1997 because the Wolf Creek facility was off line for 58 days in 1997 for a scheduled refueling and maintenance outage.
Depreciation and amortization expense decreased $26.3 million primarily because we had fully amortized a regulatory asset during 1997. This decrease in amortization expense increased EBIT for 1998.
Other Income (Expense)
Other income (expense) includes miscellaneous income and expenses not directly related to our operations.
1999 compared to 1998: Other income (expense) decreased $11.8 million. No significant corporate-owned life insurance proceeds were received in 1999. In 1998 we received $13.7 million in proceeds pursuant to our corporate-owned life insurance policies.
1998 compared to 1997: Other income (expense) increased $12.7 million. The increase is primarily attributable to benefits received during 1998 pursuant to our corporate-owned life insurance policies totaling $13.7 million.
Interest Expense
1999 compared to 1998: Interest expense includes the interest we paid on outstanding debt. Interest expense remained materially unchanged in 1999.
1998 compared to 1997: In 1998 interest expense on short-term debt decreased $1 million. We repaid our outstanding short-term debt balance during January 1998. After January 1998, no short-term debt was held. Our average short-term debt balance during 1998 was $0.6 million compared to $22.9 million during 1997. The interest we paid on long-term debt did not materially change.
Income Taxes
1999 compared to 1998: Our effective income tax rates are affected by the receipt of proceeds from our corporate-owned life insurance policies and the amortization of prior years' investment tax credits. Income taxes decreased $10 million due to lower pre-tax income. Pre-tax income was lower primarily because of higher operating expenses and the absence of death proceeds received from corporate-owned life insurance policies.
1998 compared to 1997: Income taxes increased $27.6 million as a result of the substantial increase in our 1998 pre-tax income. The increase in pre-tax income is primarily due to increased electric sales because of warmer weather, lower operating and maintenance costs, the completion of the amortization of phase-in revenues in December 1997, and the death proceeds received from corporate-owned life insurance policies.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Most of our cash requirements consist of capital expenditures and maintenance costs designed to improve facilities which provide electric service and meet future customer service requirements. Our ability to provide the cash or debt to fund our capital expenditures depends upon many things, including available resources, our financial condition and current market conditions.
Funds are available to us from the sale of securities we register for sale with the Securities and Exchange Commission (SEC). As of December 31, 1999, $50 million of KGE first mortgage bonds were registered.
Our mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless our net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not either less than two and one-half times the annual interest charges on, or 10% of the principal amount of, all first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. Based on our results for the 12 months ended December 31, 1999, approximately $1.0 billion principal amount of additional first mortgage bonds could be issued (8.25% interest rate assumed) under the most restrictive tests in the mortgage. As of December 31, 1999, $17 million in additional bonds could be issued on the basis of retired bonds.
While our internally generated cash is sufficient to fund operations and debt service payments, we do not maintain independent short-term credit facilities and rely on Western Resources for short-term cash needs. If Western Resources is unable to borrow under its credit facilities, we could have a short term liquidity issue which could require us to obtain a credit facility for our short-term cash needs.
In March 2000, Western Resources amended its $300 million credit facility to reduce the commitment to $242 million and to extend the maturity date to June 30, 2000. Western Resources also amended its credit facilities to reflect the possibility of borrowing from them rather than using them to provide support for commercial paper borrowings. As a result of these amendments, our cost of borrowing will be higher. A 1% increase in the interest rate on Western Resources' outstanding short-term debt balance as of December 31, 1999, would have increased Western Resources' annual interest expense by $7 million. Western Resources cannot predict the market conditions or its credit ratings at the time it may borrow from its facilities; and therefore, cannot predict how much higher its interest expense might be.
Amendments to the credit facilities include increased pricing to reflect credit quality and the potential drawn nature of credit facilities rather than support for commercial paper, redefinition of the total debt to capital financial covenant, limitation on use of proceeds from sale of Western Resources and our first mortgage bonds requiring payment of debt outstanding under its credit facility before proceeds may be used for other purposes, and a commitment by Western Resources to use its "best efforts" to pledge first mortgage bonds to support its credit facilities if its senior unsecured credit rating drops below "investment grade" (bonds rated below BBB by Standard & Poor's (S&P) and Fitch and below Baa by Moody's Investors Service (Moody's)).
In order to maintain adequate short-term borrowing capacity, Western Resources expects to replace or further amend its credit facilities prior to their termination.
Cash Flows from Operating Activities
Cash from operating activities decreased 2%, or $4 million. The decrease is primarily attributable to the decrease in net income.
Cash Flows from Investing Activities
Cash used in investing activities decreased 18%, or $13.8 million. The decrease is primarily due to lower nuclear fuel capital expenditures in 1999 than 1998. In the year prior to a scheduled refueling and maintenance outage at Wolf Creek, such as 1998, nuclear fuel capital expenditures increase in preparation for the next scheduled refueling and maintenance outage. In 1999, Wolf Creek had its tenth refueling and maintenance outage. The next outage is scheduled in September 2000.
Cash Flows Used in Financing Activities
Cash used in financing activities increased 7%, or $9.9 million. This increase is primarily due to advances we have made to Western Resources. See Note 10 of the Notes to Financial Statements included herein.
Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and Moody's Investors Service (Moody's) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies' assessment of our ability to pay interest and principal on these securities.
At December 31, 1999, ratings with these agencies were as follows:
Senior Senior Secured Debt Unsecured Debt Rating Agency Rating Rating S&P BBB+ BBB Fitch A- - Moody's A3 Baa3
Credit rating agencies are applying more stringent guidelines when rating utility companies due to increasing competition and utility investment in non- utility businesses. In January 2000, in response to the terminated KCP&L merger, Moody's announced they were placing our ratings on review for possible downgrade, S&P affirmed our ratings, but said the outlook is negative, and Fitch placed our ratings on RatingAlert - Negative. We anticipate that the rating agencies will complete their reviews and lower our credit ratings in the near future, but we cannot predict our new ratings.
Future Cash Requirements
We believe that internally generated funds and borrowings from Western Resources will be sufficient to meet our operating and capital expenditure requirements and debt service payments through the year 2002. Uncertainties affecting our ability to meet these requirements with internally generated funds include the factors affecting sales described above, inflation on operating expenses, regulatory actions, and compliance with future environmental regulations.
We do not contemplate any significant expenditures in connection with construction of any major generating facilities for the next five years.
$135 million of our bonds will mature in 2003.
Our business requires a significant capital investment. We currently expect that through the year 2002, we will need cash mostly for ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service and to pay dividends to Western Resources on our common stock.
Our capital expenditures for 1999 and anticipated capital expenditures for 2000 through 2002 are as follows:
Electric Nuclear Operations Generation Total (Dollars in Thousands) 1999. . . . . . . $57,200 $10,000 $ 67,200 2000. . . . . . . 70,900 31,600 102,500 2001. . . . . . . 70,900 19,600 90,500 2002. . . . . . . 70,900 20,300 91,200
These estimates are prepared for planning purposes and may be revised. Actual expenditures may differ from our estimates.
Capital Structure
Our capital structures at December 31, 1999, and 1998 were as follows:
1999 1998 Shareholders' Equity . . . . 62% 62% Long-term Debt . . . . . . . 38% 38% Total. . . . . . . . . . . . 100% 100%
Acquisition Adjustment Implementation
In accordance with the 1992 KCC merger order relating to the acquisition of Kansas Gas and Electric Company by Western Resources, amortization of the acquisition adjustment commenced August 1995. The amortization will amount to approximately $20 million (pre-tax) per year for 40 years. We and Western Resources are recovering the amortization of the acquisition adjustment through cost savings under a sharing mechanism approved by the KCC.
As Western Resources' management presently expects to continue this level of savings, the amount is expected to be sufficient to allow for the full recovery of the acquisition premium.
OTHER INFORMATION
City of Wichita Proceeding: In December 1999, the Wichita, Kansas, City Council authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace us as the supplier of electricity in Wichita. Our rates are currently 7% below the national average for retail customers. The average rates charged to retail customers in territories served by Western Resources' KPL division are 19% lower than our rates. Customers within the Wichita metropolitan area account for approximately 56% of our total energy sales. See also FERC Proceeding below for complaint filed with the FERC against us by the City of Wichita.
We have an exclusive franchise with the City of Wichita to provide retail electric service that expires March 2002. Under Kansas law, we will continue to have the exclusive right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized.
We will oppose any attempt by the City of Wichita to eliminate us as the electric provider to Wichita customers. In order to municipalize our Wichita electric facilities, the City of Wichita would be required to purchase our facilities or build a separate independent system.
KCC Proceeding: On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization of commercial and industrial users of electricity in Kansas, filed a complaint with the KCC requesting an investigation of Western Resources' and KGE's rates. The KIC alleges that these rates are not based on current costs. We will oppose this request vigorously but are unable to predict whether the KCC will open an investigation.
FERC Proceeding: In September 1999, the City of Wichita filed a complaint with the Federal Energy Regulatory Commission (FERC) against the company, alleging improper affiliate transactions between the company and KPL, a division of Western Resources. The City of Wichita requests the FERC to equalize the generation costs between the company and KPL, in addition to other matters. FERC has issued an order setting this matter for hearing and has referred the case to a settlement judge. The hearing had been suspended pending settlement discussions between the parties. The company believes that the City of Wichita's complaint is without merit and intends to defend against it vigorously.
Competition and Deregulation: The United States electric utility industry is evolving from a regulated monopolistic market to a competitive marketplace. The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted the FERC to order electric utilities to allow third parties the use of their transmission systems to sell electric power to wholesale customers. A wholesale sale is defined as a utility selling electricity to a "middleman," usually a city or its utility company, to resell to the ultimate retail customer. During 1999, wholesale electric sales represented approximately 10% of total electric sales. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide to ourselves. In December 1999, FERC issued an order (FERC Order 2000) encouraging formation of regional transmission organizations (RTOs), whose purpose is to facilitate greater competition at the wholesale level. Due to our participation in the formation of the Southwest Power Pool RTO, we anticipate that FERC Order 2000 will not have a material effect on us or our operations.
Various states have taken steps to allow retail customers to purchase electric power from providers other than their local utility company. The Kansas Legislature created a Retail Wheeling Task Force (the Task Force) in 1997 to study the effects of a deregulated and competitive market for electric services. Legislators, regulators, consumer advocates and representatives from the electric industry made up the Task Force. Several bills were introduced to the Kansas Legislature in the 1999 and 2000 legislative sessions, but none passed in 1999 and none are expected to pass in 2000. When retail wheeling will be implemented by the legislature in Kansas remains uncertain.
When retail wheeling is implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. Wholesale and industrial customers may pursue cogeneration, self-generation, retail wheeling, municipalization or relocation to other service territories in an attempt to cut their energy costs. Our rates are approximately 93% of the national average for retail customers. Because of these rates, we expect to retain a substantial part of our current volume of sales volumes in a competitive environment. We also expect we can maintain profitable prices in a competitive environment, given how our current rates compare to the national average rates. We offer competitive electric rates
for industrial improvement projects and economic development projects in an effort to maintain and increase electric load.
Stranded Costs: The definition of stranded costs for a utility business is the investment in and carrying costs on property, plant and equipment and other regulatory assets which exceed the amount that can be recovered in a competitive market. We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our fossil generation, nuclear generation and power delivery operations. If we determine that we no longer meet the criteria of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), we may have a material extraordinary non-cash charge to operations. Reasons for discontinuing SFAS 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred and a significant change by regulators from a cost-based rate regulation to another form of rate regulation. We periodically review SFAS 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS 71 accounting treatment based upon competitive or other events, we may significantly impact the value of our net regulatory assets and our utility plant investments, particularly the Wolf Creek nuclear generation facility (Wolf Creek). See OTHER INFORMATION for initiatives taken to restructure the electric industry in Kansas.
Regulatory changes, including competition, could adversely impact our ability to recover our investment in these assets. As of December 31, 1999, we have recorded regulatory assets which are currently subject to recovery in future rates of approximately $251.5 million. Of this amount, $172.3 million is a receivable for income tax benefits previously passed on to customers. The remainder of the regulatory assets are items that may give rise to stranded costs and include coal contract settlement costs, deferred plant costs and debt issuance costs.
In a competitive environment, we may not be able to fully recover our entire investment in Wolf Creek. We presently own 47% of Wolf Creek. We may also have stranded costs from an inability to recover our environmental remediation costs and long-term fuel contract costs in a competitive environment. If we determine that we have stranded costs and we cannot recover our investment in these assets, our future net income will be lower than our historical net income has been unless we compensate for the loss of such income with other measures.
Nuclear Decommissioning: Decommissioning is a nuclear industry term for the permanent shut-down of a nuclear power plant. The Nuclear Regulatory Commission (NRC) will terminate a plant's license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund decommissioning. These plans are designed so that funds required for decommissioning will be accumulated during the estimated remaining life of the related nuclear power plant.
The Financial Accounting Standards Board (FASB) is reviewing the accounting for closure and removal costs, including decommissioning of nuclear power plants. The FASB has issued an Exposure Draft "Accounting for Obligations Associated with the Retirement of Long-Lived Assets." The proposed Statement is to be effective for fiscal years beginning after June 15, 2001. If current accounting practices for nuclear power plant decommissioning are changed, the following could occur:
- Our annual decommissioning expense could be higher than in 1999 - The estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation) - The increased costs could be recorded as additional investment in the Wolf Creek plant
We do not believe that such changes, if required, would adversely affect our operating results due to our current ability to recover decommissioning costs through rates (see Note 2).
Collective Bargaining Agreement: All employees are provided by Western Resources. Western Resources' contract with the International Brotherhood of Electrical Workers (IBEW) was renewed on January 20, 2000, and will be due for renewal July 1, 2002. The contract covers approximately 1,475 employees.
Year 2OOO Issue: Our electric utility operations experienced no business disruptions as a result of the transition from December 31, 1999 to January 1, 2000 or as a result of "leap day" on February 29, 2000. Western Resources estimated that total costs to update all of our electric utility operating systems for Year 2000 readiness, excluding costs associated with WCNOC, would be approximately $2.5 million. As of December 31, 1999, Western Resources has allocated approximately $2.5 million of its $6.3 million expensed costs to our company. Western Resources expects to incur minimal cost in 2000 to complete remediation of less important systems. Western Resources expects no Year 2000 issues to arise in 2000.
WCNOC experienced no business disruptions as a result of the transition from December 31, 1999 to January 1, 2000 or as a result of "leap day" on February 29,2000. WCNOC has estimated the costs to complete the Year 2000 project at $3.5 million ($1.7 million our share). As of December 31, 1999, WCNOC expensed $3.2 million ($1.5 million our share) to complete remediation and testing of mission critical systems necessary to continue to provide electrical service to our customers. We expect to incur $0.2 million (our share) in 2000 to complete remediation of less important systems. We expect no Year 2000 issues to arise in 2000.
Market Risk Disclosure
Market Price Risk: We are exposed to market risk, including changes in commodity prices and interest rates.
Commodity Price Exposure: Given the amount of power purchased during 1999, we would have had exposure of approximately $0.9 million of operating income for a 10% increase in price per MW of electricity. From 1998 to 1999, we experienced a 15% decrease in price per MW of electricity purchased for utility operations. Due to the volatility of the power market, there are no indications that past performance can be used to predict the future.
Based on MMBtu's of natural gas and fuel oil burned during 1999, we had exposure of approximately $3.8 million of operating income for a 10% change in average price paid per MMBtu. From 1998 to 1999, we experienced a 2% increase in price per MMBtu of natural gas purchased. If we were to have a similar increase from 1999 to 2000, we would have an exposure of approximately $0.5 million of operating income. However, we use a mix of various fuel types to operate our system. Due to the volatility of natural gas prices, there are no indications that past performance can be used to predict the future.
Quantities of natural gas and electricity could vary dramatically year to year based on weather, unit outages and nuclear refueling.
Interest Rate Exposure: The company has approximately $46.4 million of variable rate debt as of December 31, 1999. A 100 basis point change in each debt series benchmark rate would impact net income on an annual basis by approximately $0.3 million.
Pronouncements Issued but Not Yet Effective
In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). In June 1999, the FASB issued Statement No. 137 "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in hybrid contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. With respect to hybrid embedded contracts, a company may elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2) only those hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997, or (3) only those hybrid contracts that were issued, acquired, or substantively modified after December 31, 1998.
SFAS 133, as amended, is effective for fiscal years beginning after June 15, 2000. SFAS 133 cannot be applied retroactively. We are currently evaluating commodity contracts and financial instruments to determine the effects of adopting SFAS 133 on our financial statements. We have not yet quantified all of the effects of adopting SFAS 133 on our financial statements; however, SFAS 133 could increase volatility in earnings and other comprehensive income. We plan to adopt SFAS 133 as of January 1, 2001.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to market risk disclosure is set forth in Other Information of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations included herein.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 31
Financial Statements:
Balance Sheets, December 31, 1999 and 1998 32 Statements of Income for the years ended December 31, 1999, 1998 and 1997 33 Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997 34 Statements of Shareholder's Equity for the years ended December 31, 1999, 1998 and 1997 35 Notes to Financial Statements 36
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented:
I, II, III, IV, and V.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Kansas Gas and Electric Company:
We have audited the accompanying balance sheets of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) as of December 31, 1999 and 1998, and the related statements of income, cash flows and shareholders' equity for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kansas Gas and Electric Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP Kansas City, Missouri, March 16, 2000 (Except with respect to the corporate restructuring discussed in Note 16, as to which the date is March 28, 2000)
KANSAS GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Business: Kansas Gas and Electric Company (the company, KGE) is a rate-regulated electric utility and wholly-owned subsidiary of Western Resources, Inc. (Western Resources). The company is engaged principally in the production, purchase, transmission, distribution, and sale of electricity. The company serves approximately 287,000 electric customers in southeastern Kansas. At December 31, 1999, the company had no employees. All employees are provided by the company's parent, Western Resources, which allocates costs related to the employees of the company.
The company owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). The company records its proportionate share of all transactions of WCNOC as it does other jointly-owned facilities.
The company prepares its financial statements in conformity with generally accepted accounting principles. The accounting and rates of the company are subject to requirements of the Kansas Corporation Commission (KCC) and the Federal Energy Regulatory Commission (FERC). The financial statements require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, to disclose contingent assets and liabilities at the balance sheet dates, and to report amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The company currently applies accounting standards for its rate regulated electric business that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation", (SFAS 71) and, accordingly, has recorded regulatory assets and liabilities when required by a regulatory order or when it is probable, based on regulatory precedent, that future rates will allow for recovery of a regulatory asset.
Cash and Cash Equivalents: The company considers highly liquid collateralized debt instruments purchased with a maturity of three months or less to be cash equivalents.
Property, Plant and Equipment: Property, plant and equipment is stated at cost. For utility plant, cost includes contracted services, direct labor and materials, indirect charges for engineering, supervision, general and administrative costs and an allowance for funds used during construction (AFUDC). The AFUDC rate was 6.00% for 1999, 6.00% for 1998, and 5.86% for 1997. The cost of additions to utility plant and replacement units of property are capitalized. Maintenance costs and replacement of minor items of property are charged to expense as incurred. When units of depreciable property are retired, the original cost and removal cost, less salvage value, are charged to accumulated
depreciation.
In accordance with regulatory decisions made by the KCC, the acquisition premium of approximately $801 million resulting from the KGE acquisition in 1992 is being amortized over 40 years. The acquisition premium is classified as electric plant in service. Accumulated amortization totaled $88.1 million as of December 31, 1999 and $68 million as of December 31, 1998.
Depreciation: Utility plant is depreciated on the straight-line method at rates approved by regulatory authorities. Utility plant is depreciated on an average annual composite basis using group rates that approximated 2.76% during 1999, 2.75% during 1998, and 2.76% during 1997. The company periodically evaluates its depreciation rates considering the past and expected future experience in the operation of its facilities.
Inventories and Supplies: Inventories and supplies for the company's utility business are stated at average cost.
Nuclear Fuel: The cost of nuclear fuel in process of refinement, conversion, enrichment, and fabrication is recorded as an asset at original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor was $29.3 million at December 31, 1999 and $39.5 million at December 31, 1998.
Regulatory Assets and Liabilities: Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. The company has recorded these regulatory assets in accordance with SFAS 71. If the company were required to terminate application of that statement for all of its regulated operations, the company would have to record the amounts of all regulatory assets and liabilities in its Statements of Income at that time. The company's earnings would be reduced by the total amount in the table below, net of applicable income taxes. Regulatory assets reflected in the financial statements are as follows:
December 31, 1999 1998 (Dollars in Thousands) Recoverable taxes. . . . . . . . . . . . $172,335 $175,759 Debt issuance costs. . . . . . . . . . . 37,158 40,102 Deferred plant costs . . . . . . . . . . 30,306 30,657 Coal contract settlement costs . . . . . 6,727 8,392 Other regulatory assets. . . . . . . . . 4,992 5,879 Total regulatory assets . . . . . . . $251,518 $260,789
Recoverable income taxes: Recoverable income taxes represent amounts due from customers for accelerated tax benefits which have been previously flowed through to customers and are expected to be recovered in the future as the accelerated tax benefits reverse.
Debt issuance costs: Debt reacquisition expenses are amortized over the remaining terms of the reacquired debt or, if refinanced, the term of the new debt. Debt issuance costs are amortized over the term of the associated debt.
Deferred plant costs: Disallowances related to the Wolf Creek nuclear generating facility.
Coal contract settlement costs: The company deferred costs associated with the termination of certain coal purchase contracts. These costs are being amortized through the year 2002.
The company expects to recover all of the above regulatory assets in rates. A return is allowed on deferred plant costs and coal contract settlement costs and approximately $18 million of debt issuance costs.
Sales: Sales are recognized as services are rendered and include estimated amounts for energy delivered but unbilled at the end of each year. Unbilled sales are recorded as a component of accounts receivable (net) on the Balance Sheets of $23.4 million at December 31, 1999 and $22 million at December 31, 1998.
The company's allowance for doubtful accounts receivable totaled $1.9 million at December 31, 1999 and 1998.
Income Taxes: Deferred tax assets and liabilities are recognized for temporary differences in amounts recorded for financial reporting purposes and their respective tax bases. Investment tax credits previously deferred are being amortized to income over the life of the property which gave rise to the credits.
Cash Surrender Value of Life Insurance: The following amounts related to corporate-owned life insurance policies (COLI) are recorded in other assets on the Balance Sheets at December 31:
1999 1998 (Dollars in Millions) Cash surrender value of policies(1) . . $538.3 $486.3 Borrowings against policies . . . . . . (527.0) (476.9) COLI (net). . . . . . . . . . . . . . . $ 11.3 $ 9.4
(1) Cash surrender value of policies as presented represents the value of the policies as of the end of the respective policy years and not as of December 31, 1999, and 1998.
Income is recorded for increases in cash surrender value and net death proceeds. Interest incurred on amounts borrowed is offset against policy income. Income recognized from death proceeds is highly variable from period to period. Death benefits recognized as other income approximated $0.06 million in 1999 and $13.7 million in 1998.
New Pronouncements: In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). In June 1999, the FASB issued Statement No. 137 "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in hybrid contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. With respect to hybrid contracts, a company may elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2) only those hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997, or (3) only those hybrid contracts that were issued, acquired, or substantively modified after December 31, 1998.
SFAS 133, as amended, is effective for fiscal years beginning after June 15, 2000. SFAS 133 cannot be applied retroactively. The company is currently evaluating commodity contracts and financial instruments to determine what, if any, effect adopting SFAS 133 might have on its financial statements. The company has not yet quantified all effects of adopting SFAS 133 on its financial statements; however, SFAS 133 could increase volatility in earnings and other comprehensive income. The company plans to adopt SFAS 133 as of January 1, 2001.
Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
2. COMMITMENTS AND CONTINGENCIES
Purchase Orders and Contracts: The company has commitments under purchase orders and contracts at WCNOC which have an unexpended balance of approximately $5.2 million (company's share) at December 31, 1999.
Manufactured Gas Sites: The company has been associated with three former manufactured gas sites located in Kansas which may contain coal tar and other potentially harmful materials. The company and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement governing all future work at these sites. The terms of the consent agreement will allow the company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. At December 31, 1999, the costs incurred from preliminary site investigation and risk assessment have been minimal.
Clean Air Act: The company must comply with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. The company has installed continuous monitoring and reporting equipment to meet the acid rain requirements. The company does not expect material capital expenditures to be required to meet Phase II sulfur dioxide and nitrogen oxide requirements.
Decommissioning: The company accrues decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund.
In February 1997, the KCC approved the 1996 Decommissioning Cost Study. Based on the study, the company's share of WCNOC's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $624 million during the period 2025 through 2033, or approximately $192 million in 1996 dollars. These costs were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1996 of 29 years. On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. Approval of this study by the KCC is pending. The company's share of the cost for decommissioning in the 1999 study under the dismantlement method is $221 million in 1999 dollars.
Decommissioning costs are currently being charged to operating expense in accordance with the prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated $3.9 million in 1999 and will increase annually to $5.6 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.7%.
The company's investment in the decommissioning fund, including reinvested earnings approximated $58.3 million at December 31, 1999, and $52.1 million at December 31, 1998. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability.
The FASB is reviewing the accounting for closure and removal costs, including decommissioning of nuclear power plants. The FASB has issued an Exposure Draft regarding "Accounting for Obligations Associated with the Retirement of Long-Lived Assets." The proposed Statement is to be effective for fiscal years beginning after June 15, 2001. If current accounting practices for nuclear power plant decommissioning are changed, the following could occur:
- The company's annual decommissioning expense could be higher than in - The estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation) - The increased costs could be recorded as additional investment in the Wolf Creek plant
The company does not believe that such changes, if required, would adversely affect its operating results due to its current ability to recover decommissioning costs through rates.
Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.5 billion for a single nuclear incident. If this liability limitation is insufficient, the U.S. Congress will consider taking whatever action is necessary to compensate the public for valid claims. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million. The remaining balance is provided by an assessment plan mandated by the Nuclear Regulatory Commission (NRC). Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $88.1 million ($41.4 million, company's share) in the event there is a major nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million ($4.7 million, company's share) in retrospective assessments per incident, per year.
The Owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, company's share). This insurance is provided by Nuclear Electric Insurance Limited (NEIL). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. The company's share of any remaining proceeds can be used to pay for property damage or decontamination expenses or, if certain requirements are met including decommissioning the plant, toward a shortfall in the decommissioning trust fund.
The Owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves and other NEIL resources, the company may be subject to retrospective assessments under the current policies of approximately $6 million per year.
Although the company maintains various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, the company's insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on the company's financial condition and results of operations.
Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the company has entered into various commitments to obtain nuclear fuel, coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1999, WCNOC's nuclear fuel commitments (company's share) were approximately $14 million for uranium concentrates expiring at various times through 2003, $26 million for enrichment expiring at various times through 2003 and $65.2 million for fabrication through 2025.
At December 31, 1999, the company's coal contract commitments in 1999 dollars under the remaining terms of the contracts were approximately $639.4 million. The largest coal contract expires in 2020, with the remaining coal contracts expiring at various times through 2013.
At December 31, 1999, the company's natural gas transportation commitment in 1999 dollars under the remaining terms of the contract were approximately $0.5 million. The natural gas transportation contract provides firm service to the company's Neosho gas burning facility through 2003.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for an uranium enrichment decontamination and decommissioning fund. The company's portion of the assessment for Wolf Creek is approximately $9.6 million, payable over 15 years. Such costs are recovered through the ratemaking process.
3. LEGAL PROCEEDINGS
The company is involved in various legal, environmental and regulatory proceedings. Management believes that adequate provision has been made and accordingly believes that the ultimate disposition of such matters will not have a material adverse effect upon the company's overall financial position or results of operations. See also Note 4 for discussion of the FERC proceeding regarding the City of Wichita complaint.
4. RATE MATTERS AND REGULATION
KCC Proceedings: In January 1997, the KCC entered an order reducing electric rates for KGE. The order required KGE to reduce electric rates by $65 million cumulative, phased in over three years beginning in 1997.
On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization of commercial and industrial users of electricity in Kansas, filed a complaint with the KCC requesting an investigation of Western Resources' and the company's rates. The KIC alleges that the company's rates are not based on current costs. The company will oppose this request vigorously but is unable to predict whether the KCC will open an investigation.
FERC Proceeding: In September 1999, the City of Wichita filed a complaint with the Federal Energy Regulatory Commission (FERC) against the company, alleging improper affiliate transactions between the company and KPL, a division of Western Resources. The City of Wichita requests the FERC to equalize the generation costs between the company and KPL, in addition to other matters. FERC has issued an order setting this matter for hearing and has referred the case to a settlement judge. The hearing has been suspended pending settlement discussions between the parties. The company believes that the City of Wichita's complaint is without merit and intends to defend against it vigorously.
5. SHORT-TERM BORROWINGS
The company had no short-term borrowings outstanding at December 31, 1999, and 1998. The weighted average interest rate on borrowings outstanding during the year was 0.0% at December 31, 1999, and 6.44% at December 31, 1998.
The company's short-term liquidity needs are met from cash advances by Western Resources. Western Resources obtains funds from issuances of commercial paper and borrowings under its credit facilities. In March 2000, Western Resources amended its $300 million facility to reduce the commitment to $242 million and to extend the maturity date to June 30, 2000. Western Resources also amended all of its credit facilities to reflect the possibility of borrowing from them rather than using them to provide support for commercial paper borrowings.
Amendments to the credit facilities include increased pricing to reflect credit quality and the potential drawn nature of credit facilities rather than support for commercial paper, redefinition of the total debt to capital financial covenant, limitation on use of proceeds from sale of first mortgage bonds, to pay off debt outstanding under the credit facility before proceeds may be used for other purposes, and a commitment by Western Resources to use its "best efforts" to pledge first mortgage bonds to support its credit facilities if its senior unsecured credit rating drops below "investment grade" (bonds rated below BBB by S&P and Fitch and below Baa by Moody's as determined by Standard & Poor's Ratings Group (S&P) and Moody's Investors Service (Moody's)).
6. LONG-TERM DEBT
The amount of KGE's first mortgage bonds authorized by the KGE Mortgage and Deed of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion. Amounts of additional bonds which may be issued are subject to property, earnings, and certain restrictive provisions of the Mortgage. Electric plant is subject to the lien of the Mortgage except for transportation equipment.
Debt discount and expenses are being amortized over the remaining lives of each issue. The improvement and maintenance fund requirements for certain first mortgage bond series can be met by bonding additional property. With the retirement of certain company pollution control series bonds, there are no longer any bond sinking fund requirements. During the years 2000 through 2004, $135 million of bonds will mature in 2003.
Long-term debt outstanding is as follows at December 31:
1999 1998 (Dollars in Thousands) First mortgage bond series: 7.60% due 2003 . . . . . . . . . . . . . . . . . $ 135,000 $ 135,000 6.50% due 2005 . . . . . . . . . . . . . . . . . 65,000 65,000 6.20% due 2006 . . . . . . . . . . . . . . . . . 100,000 100,000 300,000 300,000 Pollution control bond series: 5.10% due 2023 . . . . . . . . . . . . . . . . . 13,653 13,673 Variable due 2027, 4.25% at December 31, 1999. . 21,940 21,940 7.0% due 2031. . . . . . . . . . . . . . . . . . 327,500 327,500 Variable due 2032, 4.20% at December 31, 1999. . 14,500 14,500 Variable due 2032, 4.30% at December 31, 1999. . 10,000 10,000 387,593 387,613 Less: Unamortized discount . . . . . . . . . . . . . . 3,322 3,446 Long-term debt (net) . . . . . . . . .. . . . . . . $ 684,271 $ 684,167
7. WESTERN RESOURCES AND KANSAS CITY POWER & LIGHT COMPANY MERGER AGREEMENT
On March 18, 1998, Western Resources signed an Amended and Restated Plan of Agreement and Plan of Merger with the Kansas City Power & Light Company (KCPL) under which KGE, KPL, a division of Western Resources, and KCPL would have been combined into a new company called Westar Energy, Inc. KCPL has notified Western Resources that it has terminated the contemplated transaction.
8. INCOME TAXES
Income tax expense is composed of the following components at December 31:
1999 1998 1997 (Dollars in Thousands) Currently payable: Federal. . . . . . . . . $ 38,710 $ 53,297 $ 34,641 State. . . . . . . . . . 9,453 12,080 7,982 Deferred: Federal. . . . . . . . . (8,531) (14,299) (18,503) State. . . . . . . . . . (1,407) (2,866) (3,467) Amortization of investment tax credits. . . . . . . (3,238) (3,241) (3,245) Total income tax expense . $ 34,987 $ 44,971 $ 17,408
Under SFAS 109, temporary differences gave rise to deferred tax assets and deferred tax liabilities as follows at December 31:
1999 1998 (Dollars in Thousands) Deferred tax assets: Deferred gain on sale-leaseback. . . . . $ 87,220 $ 92,427 Other. . . . . . . . . . . . . . . . . . 40,969 42,806 Total deferred tax assets. . . . . . . 128,189 135,233 Deferred tax liabilities: Accelerated depreciation and other . . . 375,917 376,113 Acquisition premium. . . . . . . . . . . 282,578 290,576 Deferred future income taxes . . . . . . 172,336 175,759 Other. . . . . . . . . . . . . . . . . . 12,322 14,667 Total deferred tax liabilities . . . . 843,153 857,115
Investment tax credits . . . . . . . . . . 59,997 63,234
Accumulated deferred income taxes, net . . $ 774,961 $ 785,116
In accordance with various rate orders, the company has not yet collected through rates certain accelerated tax deductions which have been passed on to customers. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers, it has recorded a deferred asset for these amounts. These assets are also a temporary difference for which deferred income tax liabilities have been provided.
The effective income tax rates set forth below are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective tax rates and the federal statutory income tax rates are as follows:
Year Ended December 31, 1999 1998 1997
Effective Income Tax Rate . . . . . . . . . 29% 30% 25% Effect of: State income taxes . . . . . . . . . . . . (4) (4) (4) Amortization of investment tax credits . . 3 2 5 Corporate-owned life insurance policies. . 7 9 12 Accelerated depreciation flow through and amortization, net. . . . . . . . . . (2) (2) (4) Other. . . . . . . . . . . . . . . . . . . 2 - 1
Statutory Federal Income Tax Rate . . . . . 35% 35% 35%
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in Statement of Financial Accounting Standards No. 107 "Disclosures about Fair Value of Financial Instruments."
Cash and cash equivalents, short-term borrowings and variable-rate debt are carried at cost which approximates fair value. The decommissioning trust is recorded at fair value and is based on the quoted market prices at December 31, 1999 and 1998. The fair value of fixed-rate debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions.
The recorded amount of accounts receivable and other current financial instruments approximate fair value.
The fair value estimates presented herein are based on information available at December 31, 1999 and 1998. These fair value estimates have not been comprehensively revalued for the purpose of these financial statements since that date and current estimates of fair value may differ significantly from the amounts presented herein. Because the company's operations are regulated, the company believes that any gains or losses related to the retirement of debt would not have a material effect on the company's financial position or results of operations.
The carrying values and estimated fair values of the company's financial instruments are as follows:
Carrying Value Fair Value December 31, 1999 1998 1999 1998 (Dollars in Thousands)
Decommissioning trust. . . $ 58,286 $ 52,093 $ 58,286 $ 52,093 Fixed-rate debt. . . . . . 699,573 641,172 693,384 684,125
1O. RELATED PARTY TRANSACTIONS
The cash management function, including cash receipts and disbursements, for the company is performed by Western Resources. An intercompany account is used to record net receipts and disbursements handled by Western Resources. The net amount advanced by the company to Western Resources approximated $111.2 million at December 31, 1999 and $64.4 million at December 31, 1998. These amounts are recorded as advances to parent company in current assets on the Balance Sheets.
Certain operating expenses have been allocated to the company from Western Resources. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers, and/or other
appropriate factors. Management believes such allocation procedures are reasonable. During 1999, the company declared dividends to Western Resources of $100 million.
11. LEASES
At December 31, 1999, the company had leases covering various property and equipment. The company currently has no capital leases.
Rental payments for operating leases and estimated rental commitments are as follows:
Operating Year Ended December 31, Leases (Dollars in Thousands) Rental payments: 1997 . . . . . . . . . . . . . $ 42,503 1998 . . . . . . . . . . . . . 44,075 1999 . . . . . . . . . . . . . 43,827
Future Commitments: 2000 . . . . . . . . . . . . . 43,041 2001 . . . . . . . . . . . . . 42,151 2002 . . . . . . . . . . . . . 41,152 2003 . . . . . . . . . . . . . 45,356 2004 . . . . . . . . . . . . . 40,416 Thereafter . . . . . . . . . . 543,293 Total future commitments . . $755,409
In 1987, the company sold and leased back its 50% undivided interest in the La Cygne 2 generating unit. The La Cygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. The company remains responsible for its share of operation and maintenance costs and other related operating costs of La Cygne 2. The lease is an operating lease for financial reporting purposes.
As permitted under the La Cygne 2 lease agreement, the company in 1992 requested the Trustee Lessor to refinance $341.1 million of secured facility bonds of the Trustee and owner of La Cygne 2. The transaction was requested to reduce recurring future net lease expense. In connection with the refinancing on September 29, 1992, a one-time payment of approximately $27 million was made by the company which has been deferred and is being amortized over the remaining life of the lease and included in operating expense as part of the future lease expense. At December 31, 1999, approximately $19.1 million of this deferral remained in regulatory assets on the Balance Sheet.
Future minimum annual lease payments required under the La Cygne 2 lease agreement are approximately $34.6 million for each year through 2002, $39.4 million in 2003, $34.6 million in 2004, and $502.6 million over the remainder of
the lease.
The gain realized at the date of the sale of La Cygne 2 has been deferred for financial reporting purposes, and is being amortized ($11.8 million per year) over the initial lease term in proportion to the related lease expense. The company's lease expense, net of amortization of the deferred gain and refinancing costs, was approximately $28.9 million for 1999, $28.9 million for 1998, and $27.3 million for 1997.
12. PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at December 31:
1999 1998 (Dollars in Thousands)
Electric plant in service. . . . . . $3,623,852 $3,580,433 Less - Accumulated depreciation. . . 1,206,607 1,125,735 2,417,245 2,454,698 Construction work in progress. . . . 35,219 32,943 Nuclear fuel (net) . . . . . . . . . 28,013 39,497 Net Utility Plant. . . . . . . . . 2,480,477 2,527,138 Non-utility plant in service . . . . 219 219 Net Property, Plant and Equipment. $2,480,696 $2,527,357
13. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1999 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 174,450 $ 113,415 344 50 Jeffrey 1 (b) Jul 1978 72,197 32,267 149 20 Jeffrey 2 (b) May 1980 69,106 32,105 148 20 Jeffrey 3 (b) May 1983 101,031 42,957 148 20 Jeffrey wind 1 (b) May 1999 201 3 (d) 20 Jeffrey wind 2 (b) May 1999 200 2 (d) 20 Wolf Creek (c) Sep 1985 1,378,238 460,880 550 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL) (which owns 50%) (b) Jointly owned with Western Resources (which owns 64%) and UtiliCorp United Inc. (which owns 16%) (c) Jointly owned with KCPL (which owns 47%) and Kansas Electric Power Cooperative, Inc. (which owns 6%) (d) The company's share is less than 0.5 MW
Amounts and capacity represent the company's share. The company's share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in La Cygne 2 (representing 337 MW capacity) sold and leased back to the company in 1987, are included in operating expenses on the Statements of Income. The company's share of other transactions associated with the plants is included in the appropriate classification in the company's financial statements.
14. SEGMENTS OF BUSINESS
In 1998, the company adopted SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." This statement requires the company to define and report the company's business segments based on how management currently evaluates its business. Based on management's approach to determining business segments, the company has two business segments, electric operations and nuclear generation.
Electric operations and nuclear generation comprise the company's regulated electric utility business in Kansas. Electric operations involve the production, transmission and distribution of electric power for sale to approximately 287,000 retail and wholesale customers in Kansas. Nuclear generation represents the company's 47% ownership in the Wolf Creek nuclear generating facility. This segment does not have any external sales.
The accounting policies of the segments are substantially the same as those described in the summary of significant accounting policies. The company evaluates segment performance based on earnings before interest and taxes. The company has no single external customer from which it receives ten percent or more of revenues.
Year Ended December 31, 1999:
Electric Nuclear Eliminating Operations Generation Items Total (Dollars in Thousands) External sales . . . $ 638,340 $ - $ - $ 638,340 Internal sales . . . - 108,445 (108,445) - Depreciation and amortization. . . . 61,531 39,629 - 101,160 Earnings before interest and taxes 193,980 (25,214) - 168,766 Interest expense . . 49,518 Earnings before income taxes . . . 119,248 Identifiable assets 1,980,485 1,083,344 - 3,063,829
Year Ended December 31, 1998:
Electric Nuclear Eliminating Operations Generation Items Total (Dollars in Thousands) External sales. . . $ 648,379 $ - $ - $ 648,379 Internal sales. . . - 117,517 (117,517) - Depreciation and amortization . . . 59,239 39,583 - 98,822 Earnings before interest and taxes 219,014 (20,920) - 198,094 Interest expense. . 49,358 Earnings before income taxes . . . 148,736 Identifiable assets 1,936,462 1,121,509 - 3,057,971
Year Ended December 31, 1997:
Electric Nuclear Eliminating Operations Generation Items Total (Dollars in Thousands) External sales. . . $ 614,445 $ - $ - $ 614,445 Internal sales. . . - 102,330 (102,330) - Depreciation and amortization . . . 57,521 65,902 - 123,423 Earnings before interest and taxes 180,954 (60,968) - 119,986 Interest expense. . 50,450 Earnings before income taxes . . . 69,536 Identifiable assets 1,962,586 1,154,522 - 3,117,108
15. QUARTERLY FINANCIAL STATISTICS (Unaudited)
The amounts in the table are unaudited but, in the opinion of management, contain all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results of such periods. The business of the company is seasonal in nature and, in the opinion of management, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. (Dollars in Thousands) Sales . . . . . . . . . . . $133,910 $147,170 $217,986 $139,274 Income from Operations. . . 30,172 31,735 86,982 22,960 Net income. . . . . . . . . 12,905 14,070 49,512 7,774
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. (Dollars in Thousands) Sales . . . . . . . . . . . $134,566 $162,816 $216,034 $134,963 Income from Operations. . . 36,033 44,112 81,063 28,210 Net income. . . . . . . . . 22,415 28,507 43,329 9,514
16. SUBSEQUENT EVENT
On March 28, 2000, Western Resources' board of directors approved the separation of its electric and non-electric utility businesses. The separation is currently expected to be effected through an exchange offer to be made to Western Resources shareholders in the third quarter of 2000. The exchange ratio will be described in materials furnished to Western Resources shareholders upon commencement of the exchange offer. Western Resources expects to complete the separation in the fourth quarter of 2000, but Western Resources can give no assurance that the separation will be completed.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no disagreements with accountants on accounting and financial disclosure.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Western Resources, Inc. owns 100% of the Company's outstanding common stock.
A Director Business Experience Since 1994 and Other Continuously Name Age Directorships Other Than The Company Since
Ronald W. 53 Chairman of the Board and President 2000 Holt (since January 2000), Assistant Secretary (January 1998 to January 2000), Kansas Gas and Electric Company. Senior Director, Corporate and Community Affairs (January 1999 to January 2000); Director, Community and Support Services (March 1992 to December 1998), Western Resources, Inc. Directorships Commerce Bank, N.A., Wichita, Kansas Via Christi Medical Center, Wichita, Kansas
James A. 42 Vice President (since July 1995); 1997 Martin and prior to that Executive Director Regulatory and Rates, Western Resources, Inc.
Marilyn B. 50 Executive Vice President, Bank of 1994 Pauly America, N.A., Wichita, Kansas (1) Directorships Farmers Mutual Alliance Insurance Company
Richard D. 67 President, Range Oil Company 1993 Smith Directorships (1) Bank of America, N.A., Wichita, Kansas HCA Wesley Medical Center, Wichita, Kansas
(1) Member of the Audit Committee of which Marilyn B. Pauly is Chairperson. The Audit Committee has responsibility for the investigation and review of the financial affairs of the company and its relations with independent accountants.
Outside directors are paid a $3,750 per quarter retainer and are paid an attendance fee of $600 for board meetings ($300 if attending by phone). A committee attendance fee of $800 is paid to the outside director Audit Committee Chairperson, and $500 to other outside Committee members. All outside directors are reimbursed expenses while attending board and Committee Meetings.
During 1999, the Board of Directors met four times and the Audit Committee met once. Each director attended at least 75% of the total number of Board and Committee meetings held while he/she served as a director or a member of the committee.
Other information required by Item 10 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 is omitted pursuant to General Instruction I(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 I(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 I(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, 1999 and 1998 Statements of Income for the years ended December 31, 1999, 1998 and 1997 Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997 Statements of Shareholder's Equity for the years ended December 31, 1999, 1998 and 1997 Notes to Financial Statements
REPORTS ON FORM 8-K
None
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K I for the year ended December 31, 1992, File No. 1-7324)
3(b) Certificate of Merger of Kansas Gas and Electric Company into I KCA Corporation (Filed as Exhibit 3(b) to Form 10-K for the year ended December 31, 1992, File No. 1-7324)
3(c) By-laws as amended (Filed as Exhibit 3(c) Form 10-K I for the year ended December 31, 1992, File No. 1-7324)
4(c) Mortgage and Deed of Trust, dated as of April 1, 1940 to I Guaranty Trust Company of New York (now Morgan Guaranty Trust Company of New York) and Henry A. Theis (to whom W. A. Spooner is successor), Trustees, as supplemented by thirty-eight Supplemental Indentures, dated as of June 1, 1942, March 1, 1948, December 1, 1949, June 1, 1952, October 1, 1953, March 1, 1955, February 1, 1956, January 1, 1961, May 1, 1966, March 1, 1970, May 1, 1971, March 1, 1972, May 31, 1973, July 1, 1975, December 1, 1975, September 1, 1976, March 1, 1977, May 1, 1977, August 1, 1977, March 15, 1978, January 1, 1979, April 1, 1980, July 1, 1980, August 1, 1980, June 1, 1981, December 1, 1981, May 1, 1982, March 15, 1984, September 1, 1984 (Twenty-ninth and Thirtieth), February 1, 1985, April 15, 1986, June 1, 1991 March 31, 1992, December 17, 1992, August 24, 1993, January 15, 1994 and March 1, 1994, (Filed, respectively, as Exhibit A-1 to Form U-1, File No. 70-23; Exhibits 7(b) and 7(c), File No. 2-7405; Exhibit 7(d), File No. 2-8242; Exhibit 4(c), File No. 2-9626; Exhibit 4(c), File No. 2-10465; Exhibit 4(c), File No. 2-12228; Exhibit 4(c), File No. 2-15851; Exhibit 2(b)-1, File No. 2-24680; Exhibit 2(c), File No. 2-36170; Exhibits 2(c) and 2(d), File No. 2-39975; Exhibit 2(d), File No. 2-43053; Exhibit 4(c)2 to Form 10-K, for December 31, 1989, File No. 1-7324; Exhibit 2(c), File No. 2-53765; Exhibit 2(e), File No. 2-55488; Exhibit 2(c), File No. 2-57013; Exhibit 2(c), File No. 2-58180; Exhibit 4(c)3 to Form 10-K for December 31, 1989, File No. 1-7324; Exhibit 2(e), File No. 2-60089; Exhibit 2(c), File No. 2-60777; Exhibit2(g),File No. 2-64521; Exhibit 2(h), File No. 2-66758; Exhibits 2(d) and 2(e), File No. 2-69620; Exhibits 4(d) and 4(e), File No. 2-75634; Exhibit 4(d), File No. 2-78944; Exhibit 4(d), File No. 2-87532; Exhibits 4(c)4, 4(c)5 and 4(c)6 to Form 10-K for December 31, 1989, File No. 1-7324; Exhibits 4(c)2 and 4(c)3 to Form 10-K for
December 31, 1992, File No. 1-7324; Exhibit 4(b) to Form S-3, File No. 33-50075; Exhibits 4(c)2 and 4(c)3 to Form 10-K for December 31, 1993, File No. 1-7324; Exhibit 4(c)2 to Form 10-K for December 31, 1994, File No. 1-7324)
Instruments defining the rights of holders of other long-term debt not required to be filed as exhibits will be furnished to the Commission upon request.
10(a) La Cygne 2 Lease (Filed as Exhibit 10(a) to Form 10-K for the year I ended December 31, 1988, File No. 1-7324)
10(a) Amendment No. 3 to La Cygne 2 Lease Agreement dated as of SeptemberI 29, 1992 (Filed as Exhibit 10(b)1 to Form 10-K for the year ended December 31, 1992, File No. 1-7324)
10(b) Outside Directors' Deferred Compensation Plan (Filed as Exhibit I 10(c) to the Form 10-K for the year ended December 31, 1993, File No. 1-7324)
12 Computation of Ratio of Consolidated Earnings to Fixed Charges (Filed electronically)
23 Consent of Independent Public Accountants, Arthur Andersen LLP (Filed electronically)
27 Financial Data Schedule (Filed electronically)
SIGNATURE
Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KANSAS GAS AND ELECTRIC COMPANY
March 28, 2000 By /s/ Ronald W. Holt Ronald W. Holt Chairman of the Board and President
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Signature Title Date
/s/ RONALD W. HOLT Chairman of the Board and (Ronald W. Holt) President (Principal Executive March 28, 2000 Officer)
/s/ RICHARD D. TERRILL Secretary, Treasurer and General (Richard D. Terrill) Counsel (Principal Financial March 28, 2000 and Accounting Officer)
/s/ JAMES A. MARTIN Director March 28, 2000 (James A. Martin)
/s/ MARILYN B. PAULY Director (Marilyn B. Pauly)
/s/ RICHARD D. SMITH Director (Richard D. Smith)