SEC Filing | Evergy, Inc.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1995 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-7324 KANSAS GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) KANSAS 48-1093840 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) P.O. BOX 208, WICHITA, KANSAS 67201 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code 316/261-6611 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X) Indicate the number of shares outstanding of each of the registrant's classes of common stock. Common Stock, No par value 1,000 Shares (Title of each class) (Outstanding at March 27, 1996) Indicated by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No Registrant meets the conditions of General Instruction J(1)(a) and (b) to Form 10-K for certain wholly-owned subsidiaries and is therefore filing an abbreviated form. KANSAS GAS AND ELECTRIC COMPANY FORM 10-K December 31, 1995 TABLE OF CONTENTS Description Page PART I Item 1. Business 3 Item 2. Properties 11 Item 3. Legal Proceedings 12 Item 4. Submission of Matters to a Vote of Security Holders 12 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 12 Item 6. Selected Financial Data 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 13 Item 8. Financial Statements and Supplementary Data 18 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 40 PART III Item 10. Directors and Executive Officers of the Registrant 41 Item 11. Executive Compensation 42 Item 12. Security Ownership of Certain Beneficial Owners and Management 42 Item 13. Certain Relationships and Related Transactions 42 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 43 Signatures 46 PART I ITEM 1. BUSINESS ACQUISITION AND MERGER On March 31, 1992, Western Resources, Inc. (formerly The Kansas Power and Light Company) (Western Resources) through its wholly-owned subsidiary KCA Corporation (KCA), acquired all of the outstanding common and preferred stock of Kansas Gas and Electric Company (KGE) (the Merger). Simultaneously, KCA and Kansas Gas and Electric Company merged and adopted the name Kansas Gas and Electric Company (the Company, KGE). Additional information relating to the Merger can be found in Management's Discussion and Analysis of Financial Condition and Results of Operations. GENERAL The Company is an electric public utility engaged in the generation, transmission, distribution and sale of electric energy in the southeastern quarter of Kansas including the Wichita metropolitan area. The Company owns 47% of Wolf Creek Nuclear Operating Corporation, the operating company for Wolf Creek Generating Station (Wolf Creek). Corporate headquarters of the Company is located in Wichita, Kansas. The Company has no gas properties. At December 31, 1995, the Company had no employees. All employees are provided by the Company's parent, Western Resources, Inc. (Western Resources). In January 1996, the KCC initiated an order for a generic investigation to analyze matters related to the potential restructuring of the electric industry and the overall implications to both utilities and public interests within the state of Kansas. This order was initiated given recent developments at the Federal Energy Regulatory Commission (FERC), other state regulatory agencies and increased competition among utilities related to large industrial electric customers. The order was established as a means to define the KCC's role within the electric generation industry as it may become more competitive, and address any developments as they may occur. Currently, there are no proceedings or actions at the KCC which would open the Company's current electric markets to greater competition, nor establish guidelines at to a change in the degree of regulatory oversight that the KCC has on the Company's operations. For discussion regarding competition in the electric utility industry and the potential impact on the Company, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Other Information, Competition included herein. Discussion of other factors affecting the Company are set forth in the Notes to Financial Statements and Management's Discussion and Analysis included herein. ELECTRIC OPERATIONS General The Company supplies electric energy at retail to approximately 275,000 customers in 139 communities in Kansas. The Company also supplies electric energy to 27 communities and 1 rural electric cooperative, and has contracts for the sale, purchase or exchange of electricity with other utilities at wholesale. The Company's electric sales for the last five years were as follows: 1995 1994 1993 1992 1991 (Thousands of MWH) Residential 2,385 2,384 2,386 2,102 2,341 Commercial 2,095 2,068 1,991 1,892 1,908 Industrial 3,542 3,371 3,323 3,248 3,194 Wholesale and Interchange 1,292 1,590 2,004 1,267 1,168 Other 45 45 45 46 46 Total 9,359 9,458 9,749 8,555 8,657 The Company's electric revenues for the last five years were as follows: 1995 1994 1993 1992 1991 (Dollars in Thousands) Residential $221,628 $220,067 $219,069 $194,142 $219,907 Commercial 171,654 167,499 162,858 154,005 155,847 Industrial 182,930 181,119 179,256 174,226 172,953 Wholesale and Interchange 31,143 38,750 45,843 28,086 29,989 Other 16,513 12,445 9,971 6,792 16,272 Total $623,868 $619,880 $616,997 $554,251 $594,968 Capacity The aggregate net generating capacity of the Company's system is presently 2,501 megawatts (MW). The system comprises interests in twelve fossil fueled steam generating units, one nuclear generating unit (47% interest) and one diesel generator, located at seven generating stations. One of the twelve fossil fueled units (70 MW capacity) has been "mothballed" for future use (See Item 2. Properties). The Company's 1995 peak system net load occurred on July 11, 1995 and amounted to 1,855 MW. The Company's net generating capacity together with power available from firm interchange and purchase contracts, provided a capacity margin of approximately 17% above system peak responsibility at the time of the peak. The Company and ten companies in Kansas and western Missouri have agreed to provide capacity (including margin), emergency and economy services for each other. This arrangement is called the MOKAN Power Pool. The pool participants also coordinate the planning of electric generating and transmission facilities. The Company is one of 47 members of the Southwest Power Pool (SPP). SPP's responsibility is to maintain system reliability on a regional basis. The region encompasses areas within the eight states of Kansas, Missouri, Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi. In 1994, the Company joined the Western Systems Power Pool (WSPP). Under this arrangement, over 103 electric utilities and marketers throughout the western United States have agreed to market energy and to provide transmission services. WSPP's intent is to increase the efficiency of the interconnected power systems operations over and above existing operations. Services available include short-term and long-term economy energy transactions, unit commitment service, firm capacity and energy sales, energy exchanges, and transmission service by intermediate systems. During 1994, the Company entered into an agreement with Midwest Energy, Inc. (MWE), whereby the Company will provide MWE with peaking capacity of 61 megawatts through the year 2008. The Company also entered into an agreement with Empire District Electric Company (Empire), whereby the Company will provide Empire with peaking and base load capacity (20 megawatts in 1994 increasing to 80 megawatts in 2000) through the year 2000. Future Capacity The Company does not contemplate any significant expenditures in connection with construction of any major generating facilities through the turn of the century (See Item 7. Management's Discussion and Analysis, Liquidity and Capital Resources). The Company has capacity available which may not be fully utilized by growth in customer demand for at least 4 years. The Company continues to market this capacity and energy to other utilities. Fuel Mix The Company's coal-fired units comprise 1,100 MW of the total 2,501 MW of generating capacity and the Company's nuclear unit provides 548 MW of capacity. Of the remaining 853 MW of generating capacity, units that can burn either natural gas or oil account for 850 MW, and the remaining unit which burns only diesel fuel accounts for 3 MW (See Item 2. Properties). During 1995, low sulfur coal was used to produce 52% of the Company's electricity. Nuclear produced 40% and the remainder was produced from natural gas, oil, or diesel fuel. During 1996, based on the Company's estimate of the availability of fuel, coal will to be used to produce approximately 61% of the Company's electricity and nuclear will be used to produce 31%. The Company's fuel mix fluctuates with the operation of nuclear powered Wolf Creek which has an 18-month refueling and maintenance schedule. The 18-month schedule permits uninterrupted operation every third calendar year. Wolf Creek was taken off-line on February 3, 1996 for its eighth refueling and maintenance outage. The outage is expected to last approximately 60 days during which time electric demand will be met primarily by the Company's coal-fired operating units. Nuclear The owners of Wolf Creek have on hand or under contract 75% of the uranium required for operation of Wolf Creek through the year 2003. The balance is expected to be obtained through spot market and contract purchases. The Company has four contracts with the following three suppliers for uranium: Cameco, Geomex Minerals, Inc., and Power Resources, Inc. The Company has three contracts for uranium enrichment performed by USEC, Urenco and Nuexco Trading Corp. These contractual arrangements cover 100% of Wolf Creek's uranium enrichment requirements for 1996-1997, 90% for 1998-1999, 95% for 2000-2001 and 100% for 2005-2014. The balance of the 1998-2005 requirements is expected to be obtained through a combination of spot market and contract purchases. The decision not to contract for the full enrichment requirements is one of cost rather than availability of service. A contractual arrangement is in place with Cameco for the conversion of uranium to uranium hexafluoride sufficient to meet Wolf Creek's requirements through the year 2000. The Company has entered into all of its uranium, uranium enrichment and uranium hexaflouride arrangements during the ordinary course of business and is not substantially dependent upon these agreements. The Company believes there are other suppliers and plentiful sources available at reasonable prices to replace, if necessary, these contracts. In the event that the Company were required to replace these contracts, it would not anticipate a substantial disruption of its business. The Nuclear Waste Policy Act of 1982 established schedules, guidelines and responsibilities for the Department of Energy (DOE) to develop and construct repositories for the ultimate disposal of spent fuel and high-level waste. The DOE has not yet constructed a high-level waste disposal site and has announced that a permanent storage facility may not be in operation prior to 2010 although an interim storage facility may be available earlier. Wolf Creek contains an on-site spent fuel storage facility which, under current regulatory guidelines, provides space for the storage of spent fuel through 2006 while still maintaining full core off-load capability. The Company believes adequate additional storage space can be obtained as necessary. Additional information with respect to insurance coverage applicable to the operations of the Company's nuclear operating facility is set forth in Note 2 of the Notes to Financial Statements. Coal The three coal-fired units at Jeffrey Energy Center (JEC) have an aggregate capacity of 428 MW (KGE's 20% share) (See Item 2. Properties). Western Resources, the operator of JEC, and KGE, have a long-term coal supply contract with Amax Coal West, Inc. (AMAX), a subsidiary of Cyprus Amax Coal Company, to supply low sulfur coal to JEC from AMAX's Eagle Butte Mine or an alternate mine source of AMAX's Belle Ayr Mine, both located in the Powder River Basin in Campbell County, Wyoming. The contract expires December 31, 2020. The contract contains a schedule of minimum annual delivery quantities based on MMBtu provisions. The coal to be supplied is surface mined and has an average Btu content of approximately 8,300 Btu per pound and an average sulfur content of .43 lbs/MMBtu (See Environmental Matters). The average delivered cost of coal for JEC was approximately $1.13 per MMBtu or $18.71 per ton during 1995. Coal is transported by Western Resources from Wyoming under a long-term rail transportation contract with Burlington Northern (BN) and Union Pacific (UP) to JEC through December 31, 2013. Rates are based on net load carrying capabilities of each rail car. Western Resources provides 890 aluminum rail cars, under a 20 year lease, to transport coal to JEC. The two coal-fired units at La Cygne Station have an aggregate generating capacity of 672 MW (KGE's 50% share) (See Item 2. Properties). The operator, Kansas City Power & Light Company (KCPL), maintains coal contracts as discussed in the following paragraphs. La Cygne 1 uses low sulfur Powder River Basin coal which is supplied under a variety of spot market transactions, discussed below. Illinois or Kansas/Missouri coal is blended with the Powder River Basin coal and is secured from time to time under spot market arrangements. La Cygne 1 uses a blend of 85% Powder River Basin coal. La Cygne 2 and additional La Cygne 1 Powder River Basin coal is supplied through several contracts expiring at various times through 1998. This low sulfur coal had an average Btu content of approximately 8,500 Btu per pound and a maximum sulfur content of .50 lbs/MMBtu (See Environmental Matters). For 1996, KCPL has secured Powder River Basin coal from Powder River Coal Company, a subsidiary of Peabody Coal Company. Transportation is covered by KCPL through its Omnibus Rail Transportation Agreement with BN and Kansas City Southern Railroad through December 31, 2000. During 1995, the average delivered cost of all local and Powder River Basin coal procured for La Cygne 1 was approximately $0.88 per MMBtu or $15.31 per ton and the average delivered cost of Powder River Basin coal for La Cygne 2 was approximately $0.75 per MMBtu or $12.56 per ton. The Company has entered into all of its coal and transportation contracts during the ordinary course of business and is not substantially dependent upon these contracts. The Company believes there are other supplies for and plentiful sources of coal available at reasonable prices to replace, if necessary, fuel to be supplied pursuant to these contracts. In the event that the Company were required to replace its coal or transportation agreements, it would not anticipate a substantial disruption of the Company's business. Natural Gas The Company uses natural gas as a primary fuel in its Gordon Evans and Murray Gill Energy Centers. Natural gas for these generating stations is supplied by readily available gas from the spot market. Short-term economical spot market purchases will supply the system with the flexible natural gas supply to meet operational needs. Oil The Company uses oil as an alternate fuel when economical or when interruptions to natural gas make it necessary. Oil is also used as a supplemental fuel at JEC and La Cygne generating stations. All oil burned by the Company during the past several years has been obtained by spot market purchases. At December 31, 1995, the Company had approximately 676 thousand gallons of No. 2 oil and 11 million gallons of No. 6 oil which is believed to be sufficient to meet emergency requirements and protect against lack of availability of natural gas and/or the loss of a large generating unit. Other Fuel Matters The Company's contracts to supply fuel for its coal and natural gas-fired generating units, with the exception of JEC, do not provide full fuel requirements at the various stations. Supplemental fuel is procured on the spot market to provide operational flexibility and, when the price is favorable, to take advantage of economic opportunities. Set forth in the table below is information relating to the weighted average cost of fuel used by the Company. 1995 1994 1993 1992 1991 Per Million Btu: Nuclear $0.40 $0.36 $0.35 $0.34 $0.32 Coal 0.91 0.90 0.96 1.25 1.32 Gas 1.68 1.98 2.37 1.95 1.74 Oil 4.00 3.90 3.15 4.28 4.13 Cents per KWH Generation 0.82 0.89 0.93 0.98 1.09 Environmental Matters The Company currently holds all Federal and State environmental approvals required for the operation of its generating units. The Company believes it is presently in substantial compliance with all air quality regulations (including those pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx)) promulgated by the State of Kansas and the Environmental Protection Agency (EPA). The Federal sulfur dioxide standards applicable to the Company's JEC and La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur dioxide per million Btu of heat input. Federal particulate matter emission standards applicable to these units prohibit: (1) the emission of more than 0.1 pounds of particulate matter per million Btu of heat input and (2) an opacity greater than 20%. Federal NOx emission standards applicable to these units prohibit the emission of more than 0.7 pounds of NOx per million Btu of heat input. The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards through the use of low sulfur coal (See Coal); (2) the particulate matter standards through the use of electrostatic precipitators; and (3) the NOx standards through boiler design and operating procedures. The JEC units are also equipped with flue gas scrubbers providing additional sulfur dioxide and particulate matter emission reduction capability. The Kansas Department of Health and Environment regulations, applicable to the Company's other generating facilities, prohibit the emission of more than 3.0 pounds of sulfur dioxide per million Btu of heat input at the Company's generating units. The Company has sufficient low sulfur coal under contract (See Coal) to allow compliance with such limits at La Cygne 1. All facilities burning coal are equipped with flue gas scrubbers and/or electrostatic precipitators. The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in sulfur dioxide and NOx emissions with Phase I effective in 1995 and Phase II effective in 2000 and a probable reduction in toxic emissions by a future date not yet determined. To meet the monitoring and reporting requirements under the Act's acid rain program, the Company installed continuous monitoring and reporting equipment at a total cost of approximately $2.3 million. The Company does not expect additional equipment to reduce sulfur emissions to be necessary under Phase II. Although the Company currently has no Phase I affected units, the Company has applied for and has been accepted for an early substitution permit to bring the co-owned La Cygne Generating Station under the Phase I regulations. The NOx and toxic limits, which were not set in the law, were proposed by the EPA in January 1996. The Company is currently evaluating the steps it will need to take in order to comply with the proposed new rules, but is unable to determine its compliance options or related compliance costs until the evaluation is finished later this year. The Company will have three years to comply with the new rules. All of the Company's generating facilities are in substantial compliance with the Best Practicable Technology and Best Available Technology regulations issued by EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are administered in Kansas by the Kansas Department of Health and Environment. Additional information with respect to Environmental Matters is discussed in Note 2 of the Notes to Financial Statements. FINANCING The Company's ability to issue additional debt is restricted under limitations imposed by the Mortgage and Deed of Trust of the Company. The Company's mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless the Company's net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than two and one-half times the annual interest charges on, or 10% of the principal amount of, all first mortgage bonds outstanding after giving effect to the proposed issuance. Based on the Company's results for the 12 months ended December 31, 1995, approximately $937 million principal amount of additional first mortgage bonds could be issued (7.25% interest rate assumed). KGE bonds may be issued, subject to the restrictions in the preceding paragraph, on the basis of property additions not subject to an unfunded prior lien and on the basis of bonds which have been retired. As of December 31, 1995, the Company had approximately $1.3 billion of net bondable property additions not subject to an unfunded prior lien entitling the Company to issue up to $922 million principal amount of additional bonds. As of December 31, 1995, $1 million in additional bonds could be issued on the basis of retired bonds. REGULATION AND RATES The Company is subject as an operating electric utility to the jurisdiction of the Kansas Corporation Commission (KCC) which has general regulatory authority over the Company's rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts and various other matters. The Company is also subject to the jurisdiction of the FERC and the KCC with respect to the issuance of the Company's securities. Additionally, the Company is subject to the jurisdiction of the FERC, including jurisdiction as to rates with respect to sales of electricity for resale, and the Nuclear Regulatory Commission as to nuclear plant operations and safety. Additional information with respect to Regulation and Rates is discussed in Notes 1 and 3 of the Notes to Financial Statements. EXECUTIVE OFFICERS OF THE COMPANY Other Offices or Positions Name Age Present Office Held During Past Five Years William B. Moore 43 Chairman of the Board Vice President, Finance and President (since Western Resources, Inc. June 1995) Richard D. Terrill 41 Secretary, Treasurer and General Counsel Executive officers serve at the pleasure of the Board of Directors. There are no family relationships among any of the officers, nor any arrangements or understandings between any officer and other persons pursuant to which he/she was appointed as an officer. ITEM 2. PROPERTIES The Company owns or leases and operates an electric generation, transmission, and distribution system in Kansas. During the five years ended December 31, 1995, the Company's gross property additions totaled $389,689,000 and retirements were $127,740,000. ELECTRIC FACILITIES Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (2) Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 150 2 1967 Gas--Oil 367 Jeffrey Energy Center (20%) (3): Steam Turbines 1 1978 Coal 140 2 1980 Coal 147 3 1983 Coal 141 La Cygne Station (50%) (3): Steam Turbines 1 1973 Coal 341 2 1977 Coal 331 Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 46 2 1954 Gas--Oil 74 3 1956 Gas--Oil 107 4 1959 Gas--Oil 106 Neosho Energy Center: Steam Turbine 3 1954 Gas--Oil 0 (1) Wichita Plant: Diesel Generator 5 1969 Diesel 3 Wolf Creek Generating Station (47%)(3): Nuclear 1 1985 Uranium 548 Total 2,501 (1) This unit has been "mothballed" for future use. (2) Based on MOKAN rating. (3) The Company jointly owns Jeffrey Energy Center (20%), La Cygne Station (50%) and Wolf Creek Generating Station (47%). ITEM 3. LEGAL PROCEEDINGS Information on legal proceedings involving the Company is set forth in Notes 2, 3, and 9 of Notes to Financial Statements included herein. See also Item 1. Business, Environmental Matters, and Regulation and Rates. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Information required by Item 4 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's common stock is owned by Western Resources and is not traded on an established public trading market. ITEM 6. SELECTED FINANCIAL DATA 1995 1994 1993 1992 1991 (Dollars in Thousands) Income Statement Data: Operating revenues . . . . . . . $ 623,868 $ 619,880 $ 616,997 $ 554,251 $ 594,968 Operating expenses . . . . . . . 474,864 470,869 469,616 424,089 468,885 Operating income . . . . . . . . 149,004 149,011 147,381 130,162 126,083 Net income . . . . . . . . . . . 110,873 104,526 108,103 77,981 53,602 Balance Sheet Data: Gross electric plant in service. $3,427,928 $3,390,406 $3,339,832 $3,293,365 $2,468,959 Construction work in progress. . 40,810 32,874 28,436 29,634 13,612 Total assets . . . . . . . . . . 3,203,414 3,237,684 3,187,479 3,279,232 2,350,546 Long-term debt . . . . . . . . . 684,082 699,992 653,543 871,652 850,851 Interest coverage ratio (before income taxes, including AFUDC) . . . . . . . . . . . . 4.11 4.02 3.58 2.35 1.90 Ratio of Earnings to Fixed Charge 2.58 2.61 2.60 1.89 1.59

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FINANCIAL CONDITION GENERAL: The Company had net income of $110.9 million for 1995 compared to net income of $104.5 million in 1994. The increase in net income is primarily due to increased retail sales and the receipt of death benefit proceeds from corporate-owned life insurance policies in the fourth quarter of 1995. LIQUIDITY AND CAPITAL RESOURCES: The Company's liquidity is a function of its ongoing construction and maintenance program designed to improve facilities which provide electric service and meet future customer service requirements. During 1995, construction expenditures for the Company's electric system were approximately $65 million and nuclear fuel expenditures were approximately $28 million. It is projected that adequate capacity margins will be maintained through the turn of the century. The construction program is focused on providing service to new customers and improving present electric facilities. Capital expenditures for 1996 through 1998 are anticipated to be as follows: Electric Nuclear Fuel (Dollars in Thousands) 1996. . . . . . . . . . $51,800 $ 3,300 1997. . . . . . . . . . 51,900 22,300 1998. . . . . . . . . . 49,200 20,800 These expenditures are estimates prepared for planning purposes and are subject to revisions. The Company's net cash flows to capital expenditures exceeded 100% for 1995 and during the last five years has also averaged in excess of 100%. This ratio indicates the extent to which the Company is able to fund its capital expenditures with cash flow from operating activities. This ratio is calculated from the Company's Statements of Cash Flows as net cash flow from operating activities, less changes in working capital, less dividends on common stock, divided by additions to utility plant. The Company anticipates all of its cash requirements for capital expenditures through 1998 will be provided from net cash flows. The Company also has $16 million of bonds maturing through 2000, all in 1996, which will be provided from internal and external sources available under then existing financial conditions. The embedded cost of long-term debt was 7.3% at December 31, 1995 and December 31, 1994. In 1986, the Company purchased corporate-owned life insurance policies (COLI) on certain of its employees. The annual cash outflow for the premiums on these policies was approximately $30 million for 1995 and $27 million for 1994 and 1993. In June, 1995, the Company increased its borrowings against the accumulated cash surrender values of the policies by $45 million. Total 1995 COLI borrowings amounted to $353 million. See Note 1 of the Notes to Financial Statements for additional information on the accumulated cash surrender value. The borrowings are expected to produce annual cash inflows, net of expenses, through the remaining life of the policies. Borrowings against the policies will be repaid from death proceeds (See Note 1). The Company's short-term financing requirements are satisfied, as needed, through short-term bank loans and borrowings under other lines of credit maintained with banks. Short-term borrowings amounted to $50 million at December 31, 1995 and December 31. 1994. The Company's capital structure at December 31, 1995, was 63% common stock equity and 37% long-term debt. The capital structure at December 31, 1995, including short-term debt was 61% common stock equity and 39% debt. RESULTS OF OPERATIONS The following is an explanation of significant variations from prior year results in revenues, operating expenses, other income and deductions, and interest charges. Additional information relating to changes between years is provided in the Notes to Financial Statements. REVENUES The operating revenues of the Company are based on sales volumes and rates authorized by the KCC and the FERC. Rates charged for the sale and delivery of electricity are designed to recover the cost of service and allow investors a fair rate of return. Future electric sales will be affected by weather conditions, competition from other sources of energy, competing fuel sources, customer conservation efforts and the overall economy of the Company's service area. In March 1992, in connection with the acquisition of the Company by Western Resources, the KCC approved the elimination of the Energy Cost Adjustment Clause (ECA) for most retail customers of the Company effective April 1, 1992. The fuel costs are now included in base rates and were established at a level intended by the KCC to equal the projected average cost of fuel through August 1995. Therefore, if the Company wished to recover an increase in fuel costs above the projected average cost it would have to file a request for recovery in a rate filing with the KCC which request could be denied in whole or in part. The Company's fuel costs represented 22% and 24% of its total operating expenses for the years ended December 31, 1995 and 1994, respectively. Any increase in fuel costs from the projected average which the Company did not recover through rates would impact the Company's earnings. The degree of any such impact would be affected by a variety of factors, however, and thus cannot now be predicted. 1995 Compared to 1994: Total operating revenues for 1995 of $623.9 million increased less than one percent from revenues of $619.9 million for 1994 as a result of increased sales in all retail customer classes. The increase is primarily attributable to a higher demand for air conditioning load during the third quarter of 1995 compared to 1994. The Company's service territory experienced a 14% increase in the number of cooling degree days during that quarter, as compared to the third quarter of 1994. The Company has filed an electric rate reduction request with the KCC (See Note 3). 1994 Compared to 1993: Total operating revenues for 1994 of $619.9 million increased less than one percent from revenues of $617.0 million for 1993. The increase can be attributed to higher revenues in all retail customer classes. While residential sales remained virtually unchanged, commercial and industrial sales increased over two percent during 1994. Partially offsetting these increases was a 21% decrease in wholesale and interchange sales as a result of higher than normal sales in 1993 to other utilities while their generating units were down due to the flooding of 1993. OPERATING EXPENSES 1995 Compared to 1994: Total operating expenses for 1995 were $474.9 million compared to $470.9 million for 1994, an increase of less than one percent. The increase is a result of increased depreciation and amortization expense as a result of the amortization of the acquisition premium attributable to the Merger which began in August 1995 as discussed in Merger Implementation below. The Company has filed a request with the KCC to increase the annual depreciation expense for Wolf Creek Generating Station (See Note 3). The Company anticipates its operating expenses (including fuel expenses) will increase in 1996 as a result of Wolf Creek being taken out of service for refueling and maintenance as discussed under "Fuel Mix" above. 1994 Compared to 1993: Total operating expenses for 1994 of $470.9 million increased slightly from total operating expenses of $469.6 million for 1993. Federal and state income taxes increased $13.5 million and maintenance expense increased three percent primarily as a result of the major boiler overhaul of the Company's coal fired La Cygne 1 generating station. The increase in income tax expense was due to the completion at December 31, 1993, of the accelerated amortization of deferred income tax reserves related to the allowance for borrowed funds used during construction capitalized for Wolf Creek. The completion of the amortization of these deferred income tax reserves increased income tax expense and thereby reduced net income by approximately $12 million in 1994, and in the future will reduce net income by this same amount each year. Partially offsetting the increases in total operating expenses were lower fuel costs, due to decreased electric generation during 1994, and lower other operations expense. OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of taxes, increased for the twelve months ended December 31, 1995 compared to 1994 as a result of the additional interest expense on increased corporate-owned life insurance (COLI) borrowings. Partially offsetting this increase was the recognition of income from death benefit proceeds under COLI contracts during the fourth quarter of 1995 (See Notes 1 and 7 for discussion of current legislation affecting COLI). Other income and deductions, net of taxes, decreased significantly in 1994 compared to 1993 primarily as a result of increased interest expense on higher COLI borrowings. Interest on COLI borrowings increased $9.1 million in 1994 compared to 1993. Also contributing to the decrease was the receipt of death benefit proceeds from COLI policies in the third quarter of 1993. INTEREST CHARGES: The Company's embedded cost of long-term debt was 7.3% at December 31, 1995 and December 31, 1994 compared to 7.7% at December 31, 1993. Interest charges decreased 12% in 1994 compared to 1993 primarily as a result of the refinancing of higher cost fixed-rate debt. Also accounting for the decrease was the impact of increased COLI borrowings which reduce the need for other long-term debt and thereby reduced interest expense. COLI interest is reflected in Other Income and Deductions on the Income Statement. MERGER IMPLEMENTATION: In accordance with the KCC Merger order, amortization of the acquisition adjustment commenced in August 1995. The amortization will amount to approximately $20 million (pre-tax) per year for 40 years. Western Resources and the Company (combined companies) can recover the amortization of the acquisition adjustment through cost savings under a sharing mechanism approved by the KCC. Based on the order issued by the KCC, with regard to the recovery of the acquisition premium, the combined companies must achieve a level of savings on an annual basis (considering sharing provisions) of approximately $27 million in order to recover the entire acquisition premium. To the extent that the combined companies actual operations and maintenance expense is lower than the KCC-stipulated utility price index, the combined companies will realize merger savings. Western Resources has calculated, in conformance with the KCC order, annual savings associated with the acquisition to be in excess of $27 million for 1995. As Western Resources' management presently expects to continue this level of savings, the amount is expected to be sufficient to allow for the full recovery of the acquisition premium. OTHER INFORMATION INFLATION: Under the ratemaking procedures prescribed by the regulatory commissions to which the Company is subject, only the original cost of plant is recoverable in rates charged to customers. Therefore, because of inflation, present and future depreciation provisions are inadequate for purposes of maintaining the purchasing power invested by common shareholders and the related cash flows are inadequate for replacing property. The impact of this ratemaking process on common shareholders is mitigated to the extent depreciable property is financed with debt that can be repaid with dollars of less purchasing power. While the Company has experienced relatively low inflation in the recent past, the cumulative effect of inflation on operating costs may require the Company to seek regulatory rate relief to recover these higher costs. ENVIRONMENTAL: The Company has taken a proactive position with respect to the potential environmental liability associated with former manufactured gas sites and has an agreement with the Kansas Department of Health and Environment to systematically evaluate these sites (See Note 3). Although the Company currently has no Phase I affected units under the Clean Air Act of 1990, the Company has applied for and has been accepted for an early substitution permit to bring the co-owned La Cygne Generating Station under the Phase I guidelines. The NOx and toxic limits, which were not set in the law, were proposed by the EPA in January 1996. The Company is currently evaluating the steps it will need to take in order to comply with the proposed new rules, but is unable to determine its compliance options or related compliance costs until the evaluation is finished later this year. The Company will have three years to comply with the new rules. (See Note 3). COMPETITION: As a regulated utility, the Company currently has limited direct competition for retail electric service in its certified service area. However, there is competition, based largely on price, from the generation, or potential generation, of electricity by large commercial and industrial customers, and independent power producers. The 1992 Energy Policy Act (Act) requires increased efficiency of energy usage and has effected the way electricity is marketed. The Act also provides for increased competition in the wholesale electric market by permitting the FERC to order third party access to utilities' transmission systems and by liberalizing the rules for ownership of generating facilities. As part of the Merger, the Company agreed to open access of its transmission system for wholesale transactions. During 1995, wholesale revenues represented less than five percent of the Company's total revenues. Operating in this competitive environment could place pressure on utility profit margins and credit quality. Wholesale and industrial customers may threaten to pursue cogeneration, self-generation, retail wheeling, municipalization or relocation to other service territories in an attempt to obtain reduced energy costs. Increasing competition has resulted in credit rating agencies applying more stringent guidelines when making utility credit rating determinations (See Note 1 for the effects of competition on Statement of Financial Accounting Standards No. 71). The Company is providing competitive electric rates for industrial expansion projects and economic development projects in an effort to maintain and increase electric load. During 1996, the Company will lose a major industrial customer to cogeneration resulting in a reduction to pre-tax earnings of approximately $7 to $8 million annually. This customer's decision to develop its own cogeneration project was based largely on factors other than energy cost. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS PAGE Report of Independent Public Accountants 19 Financial Statements: Balance Sheets, December 31, 1995 and 1994 20 Statements of Income for the years ended December 31, 1995, 1994 and 1993 21 Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993 22 Statements of Taxes for the years ended December 31, 1995, 1994 and 1993 23 Statements of Capitalization, December 31, 1995 and 1994 24 Statements of Common Stock Equity for the years ended December 31, 1995, 1994 and 1993 25 Notes to Financial Statements 26 SCHEDULES OMITTED The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented: I, II, III, IV, and V. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Kansas Gas and Electric Company: We have audited the accompanying balance sheets and statements of capitalization of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) as of December 31, 1995 and 1994, and the related statements of income, cash flows, taxes, and common stock equity for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kansas Gas and Electric Company as of December 31, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. As explained in Note 7 to the financial statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits and effective January 1, 1994, the Company changed its method of accounting for postemployment benefits. ARTHUR ANDERSEN LLP Kansas City, Missouri, January 26, 1996 KANSAS GAS AND ELECTRIC COMPANY BALANCE SHEETS (Dollars in Thousands)
December 31, 1995 1994 ASSETS UTILITY PLANT: Electric plant in service (Notes 1 and 11). . . . . . . . $3,427,928 $3,390,406 Less - Accumulated depreciation . . . . . . . . . . . . . 893,728 833,953 2,534,200 2,556,453 Construction work in progress . . . . . . . . . . . . . . 40,810 32,874 Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 53,942 39,890 Net utility plant . . . . . . . . . . . . . . . . . . . 2,628,952 2,629,217 OTHER PROPERTY AND INVESTMENTS: Decommissioning trust (Note 2). . . . . . . . . . . . . . 25,070 16,944 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 7,885 11,561 32,955 28,505 CURRENT ASSETS: Cash and cash equivalents (Note 1). . . . . . . . . . . . 53 47 Accounts receivable and unbilled revenues (net)(Note 1) . 76,490 67,833 Advances to parent company (Note 13). . . . . . . . . . . 34,948 64,393 Fossil fuel, at average cost, . . . . . . . . . . . . . . 17,522 13,752 Materials and supplies, at average cost . . . . . . . . . 31,458 30,921 Prepayments and other current assets. . . . . . . . . . . 17,128 16,662 177,599 193,608 DEFERRED CHARGES AND OTHER ASSETS: Deferred future income taxes (Note 8) . . . . . . . . . . 208,367 197,663 Deferred coal contract settlement costs (Note 3). . . . . 14,612 17,944 Phase-in revenues (Note 3). . . . . . . . . . . . . . . . 43,861 61,406 Other deferred plant costs. . . . . . . . . . . . . . . . 31,539 31,784 Corporate-owned life insurance (net) (Notes 1 and 7). . . 7,279 9,350 Unamortized debt expense. . . . . . . . . . . . . . . . . 25,605 27,777 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 32,645 40,430 363,908 386,354 TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $3,203,414 $3,237,684 CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Statements): Common stock equity . . . . . . . . . . . . . . . . . . . $1,186,077 $1,225,204 Long-term debt (net). . . . . . . . . . . . . . . . . . . 684,082 699,992 1,870,159 1,925,196 CURRENT LIABILITIES: Short-term debt (Note 4). . . . . . . . . . . . . . . . . 50,000 50,000 Long-term debt due within one year (Note 5) . . . . . . . 16,000 - Accounts payable. . . . . . . . . . . . . . . . . . . . . 50,783 49,093 Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 17,766 15,737 Accrued interest. . . . . . . . . . . . . . . . . . . . . 7,903 8,337 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,608 11,160 149,060 134,327 DEFERRED CREDITS AND OTHER LIABILITIES: Deferred income taxes (Note 8). . . . . . . . . . . . . . 800,934 784,043 Deferred investment tax credits (Note 8). . . . . . . . . 72,970 74,841 Deferred gain from sale-leaseback (Note 6). . . . . . . . 242,700 252,341 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 67,591 66,936 1,184,195 1,178,161 COMMITMENTS AND CONTINGENCIES (Notes 2 and 9) TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . $3,203,414 $3,237,684 The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (Dollars in Thousands)
Year Ended December 31, 1995 1994 1993 OPERATING REVENUES (Notes 1 and 3). . . . . . . . . . . $ 623,868 $ 619,880 $ 616,997 OPERATING EXPENSES: Fuel used for generation: Fossil fuel . . . . . . . . . . . . . . . . . . . . 80,592 90,383 93,388 Nuclear fuel. . . . . . . . . . . . . . . . . . . . 19,425 13,562 13,275 Power purchased . . . . . . . . . . . . . . . . . . . 4,577 7,144 9,864 Other operations. . . . . . . . . . . . . . . . . . . 117,876 115,060 118,948 Maintenance . . . . . . . . . . . . . . . . . . . . . 48,056 47,988 46,740 Depreciation and amortization . . . . . . . . . . . . 79,679 71,457 75,530 Amortization of phase-in revenues . . . . . . . . . . 17,545 17,544 17,545 Taxes (See Statements): Federal income. . . . . . . . . . . . . . . . . . . 48,330 50,212 39,553 State income . . . . . . . . . . . . . . . . . . . 12,543 12,427 9,570 General . . . . . . . . . . . . . . . . . . . . . . 46,241 45,092 45,203 Total operating expenses. . . . . . . . . . . . . 474,864 470,869 469,616 OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 149,004 149,011 147,381 OTHER INCOME AND DEDUCTIONS: Corporate-owned life insurance (net). . . . . . . . . (2,668) (5,354) 7,841 Miscellaneous (net) . . . . . . . . . . . . . . . . . 4,884 5,079 9,271 Income taxes (net) (See Statements) . . . . . . . . . 9,086 7,290 2,227 Total other income and deductions . . . . . . . . 11,302 7,015 19,339 INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 160,306 156,026 166,720 INTEREST CHARGES: Long-term debt. . . . . . . . . . . . . . . . . . . . 47,073 47,827 53,908 Other . . . . . . . . . . . . . . . . . . . . . . . . 5,190 5,183 6,075 Allowance for borrowed funds used during construction (credit). . . . . . . . . . . . (2,830) (1,510) (1,366) Total interest charges. . . . . . . . . . . . . . 49,433 51,500 58,617 NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 110,873 $ 104,526 $ 108,103 The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year Ended December 31, 1995 1994 1993 CASH FLOWS FROM OPERATING ACTIVITIES: Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 110,873 $ 104,526 $ 108,103 Depreciation and amortization . . . . . . . . . . . . . . 72,950 71,457 75,530 Other amortization (including nuclear fuel) . . . . . . . 15,193 10,905 11,254 Gain on sales of utility plant (net of tax) . . . . . . . (951) - - Deferred taxes and investment tax credits (net) . . . . . 3,851 25,349 22,572 Amortization of phase-in revenues . . . . . . . . . . . . 17,545 17,544 17,545 Corporate-owned life insurance. . . . . . . . . . . . . . (28,548) (17,246) (21,650) Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (9,640) (9,640) Amortization of acquisition adjustment. . . . . . . . . . 6,729 - - Changes in working capital items: Accounts receivable and unbilled revenues (net) (Note 1) . . . . . . . . . . . . . . . (8,657) (56,721) (569) Fossil fuel . . . . . . . . . . . . . . . . . . . . . . (3,770) (6,158) 8,507 Accounts payable. . . . . . . . . . . . . . . . . . . . 1,690 (2,002) (9,813) Interest and taxes accrued. . . . . . . . . . . . . . . 967 4,508 (9,053) Other . . . . . . . . . . . . . . . . . . . . . . . . . (1,980) (922) (2,191) Changes in other assets and liabilities . . . . . . . . . 14,525 (11,181) (16,530) Net cash flows from operating activities. . . . . . . 190,777 130,419 174,065 CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to utility plant. . . . . . . . . . . . . . . . 93,938 89,880 66,886 Sales of utility plant. . . . . . . . . . . . . . . . . . (1,723) - - Corporate-owned life insurance policies . . . . . . . . . 30,347 26,418 27,268 Death proceeds of corporate-owned life insurance. . . . . (10,583) - (10,160) Net cash flows used in investing activities . . . . . 111,979 116,298 83,994 CASH FLOWS FROM FINANCING ACTIVITIES: Short-term debt (net) . . . . . . . . . . . . . . . . . . - (105,800) 62,300 Advances to parent company (net). . . . . . . . . . . . . 29,445 128,399 (118,503) Bonds issued. . . . . . . . . . . . . . . . . . . . . . . - 160,422 65,000 Bonds retired . . . . . . . . . . . . . . . . . . . . . . (25) (46,440) (140,000) Other long-term debt issued . . . . . . . . . . . . . . . - - 70,999 Other long-term debt retired. . . . . . . . . . . . . . . - (67,893) (63,956) Borrowings against life insurance policies. . . . . . . . 47,046 42,175 184,550 Repayment of borrowings against life insurance policies . (5,258) - (1,290) Revolving credit agreement (net). . . . . . . . . . . . . - - (150,000) Dividends to parent company . . . . . . . . . . . . . . . (150,000) (125,000) - Net cash flows from (used in) financing activities . . (78,792) (14,137) (90,900) NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . 6 (16) (829) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . . . 47 63 892 CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . . . $ 53 $ 47 $ 63 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION CASH PAID FOR: Interest on financing activities (net of amount capitalized) . . . . . . . . . . . . . . . . . . . . $ 71,808 $ 68,544 $ 77,653 Income taxes . . . . . . . . . . . . . . . . . . . . . . 42,100 28,509 29,354 The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF TAXES (Dollars in Thousands)
Year Ended December 31, 1995 1994 1993 FEDERAL INCOME TAXES: Payable currently . . . . . . . . . . . . . . . . . $ 34,661 $ 24,427 $ 19,220 Deferred (net). . . . . . . . . . . . . . . . . . . 9,528 23,002 16,691 Investment tax credit-Deferral. . . . . . . . . . . - - 4,900 -Amortization. . . . . . . . . (3,314) (3,208) (3,114) Total Federal income taxes . . . . . . . . . . . 40,875 44,221 37,697 Less: Federal income taxes applicable to non-operating items . . . . . . . . . . . . . (7,455) (5,991) (1,856) Total Federal income taxes charged to operations. . 48.330 50,212 39,553 STATE INCOME TAXES: Payable currently . . . . . . . . . . . . . . . . . 13,275 5,574 5,104 Deferred (net). . . . . . . . . . . . . . . . . . . (2,363) 5,554 4,095 Total State income taxes . . . . . . . . . . . . 10,912 11,128 9,199 Less: State income taxes applicable to non-operating items . . . . . . . . . . . . . (1,631) (1,299) (371) Total State income taxes charged to operations. . . 12.543 12,427 9,570 GENERAL TAXES: Property. . . . . . . . . . . . . . . . . . . . . . 40,827 40,104 38,432 Payroll and other taxes . . . . . . . . . . . . . . 5,414 4,988 6,771 Total general taxes charged to operations. . . . 46.241 45,092 45,203 TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . $ 107.114 $ 107,731 $ 94,326 The effective income tax rates set forth below are computed by dividing total Federal and State income taxes by the sum of such taxes and net income. The difference between the effective rates and the Federal statutory income tax rates are as follows: Year Ended December 31, 1995 1994 1993 EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . 32% 35% 30% Effect of: State income taxes. . . . . . . . . . . . . . . . . (4) (5) (4) Amortization of investment tax credits. . . . . . . 2 2 2 Corporate-owned life insurance. . . . . . . . . . . 5 4 5 Flow through and amortization, net. . . . . . . . . - (1) 5 Other differences . . . . . . . . . . . . . . . . . - - (3) STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . 35% 35% 35% The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, 1995 1994 COMMON STOCK EQUITY (See Statements): Common stock, without par value, authorized and issued 1,000 shares. . . . . . . . . . . . . . . . . . . . . . . $1,065,634 $1,065,634 Retained earnings . . . . . . . . . . . . . . . . . . . . . 120,443 159,570 Total common stock equity . . . . . . . . . . . . . . . . 1,186,077 63% 1,225,204 64%
LONG-TERM DEBT (Note 5): First Mortgage Bonds: Series Due 1995 1994 5-5/8% 1996 $ 16,000 $ 16,000 7.6% 2003 135,000 135,000 6-1/2% 2005 65,000 65,000 6.20% 2006 100,000 100,000 316,000 316,000 Pollution Control Bonds: 5.10% 2023 13,957 13,982 Variable (1) 2027 21,940 21,940 7.0% 2031 327,500 327,500 Variable (2) 2032 14,500 14,500 Variable (3) 2032 10,000 10,000 387,897 387,922 Total bonds. . . . . . . . . . . . . . . . . . . . . . 703,897 703,922 Less: Unamortized premium and discount (net). . . . . . . . . . 3,815 3,930 Long-term debt due within one year. . . . . . . . . . . . 16,000 - Total long-term debt . . . . . . . . . . . . . . . . . 684,082 37% 699,992 36% TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . $1,870,159 100% $1,925,196 100% Market-Adjusted Tax Exempt Securities (MATES). The interest rate is reset periodically via an auction process. Rates at December 31, 1995: (1) 4.00%, (2) 3.925%, and (3) 4.00%. The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF COMMON STOCK EQUITY (Dollars in Thousands)
Common Retained Stock Earnings BALANCE DECEMBER 31, 1992, 1,000 shares. . . . . . . $1,065,634 $ 71,941 Net income . . . . . . . . . . . . . . . . . . . . . 108,103 BALANCE DECEMBER 31, 1993, 1,000 shares. . . . . . . 1,065,634 180,044 Net income . . . . . . . . . . . . . . . . . . . . . 104,526 Dividend to parent company . . . . . . . . . . . . . (125,000) BALANCE DECEMBER 31, 1994, 1,000 shares. . . . . . . 1,065,634 159,570 Net Income . . . . . . . . . . . . . . . . . . . . . 110,873 Dividend to parent company . . . . . . . . . . . . . (150,000) Balance December 30, 1995, 1,000 shares. . . . . . . $1,065,634 $ 120,443 The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
KANSAS GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General: Kansas Gas and Electric Company (the Company, KGE) is a rate-regulated electric utility and wholly-owned subsidiary of Western Resources, Inc. (Western Resources). The Company is engaged principally in the production, purchase, transmission, distribution, and sale of electricity. The Company serves approximately 275,000 electric customers in southeastern Kansas. The Company owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). The Company records its proportionate share of all transactions of WCNOC as it does other jointly-owned facilities. The Company prepares its financial statements in conformity with generally accepted accounting principles as applied to regulated public utilities. The accounting and rates of the Company are subject to requirements of the Kansas Corporation Commission (KCC) and the Federal Energy Regulatory Commission (FERC). The financial statements require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, to disclose contingent assets and liabilities at the balance sheet date, and to report amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company follows the accounting for regulated enterprises prescribed by Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulations" (SFAS 71). This pronouncement requires deferral of certain costs and obligations based upon approvals received from regulators to permit recovery or require refund of these costs and revenues in future periods. Consequently, the recorded net book value of certain assets and liabilities may be different than that which would otherwise be recorded by unregulated enterprises. On a continuing basis, the Company reviews the continued applicability of SFAS 71 based on the current regulatory and competitive environment. Although recent developments suggest the electric generation industry may become more competitive, the degree to which regulatory oversight of the Company will be lifted and competition will be permitted is uncertain. Currently, there are no proceedings or actions at the KCC to open the Company's electric markets to greater competition. As a result, the Company continues to believe that accounting under SFAS 71 is appropriate. If the Company were to determine that the use of SFAS 71 were no longer appropriate, it would be required to write-off the deferred costs and obligations that represent regulatory assets and liabilities referred to above. It may also be necessary for the Company to reduce the carrying value of a portion of its plant and equipment to the extent that it is expected to become impaired. At this time, it is not possible to estimate the amount of the Company's plant and equipment, if any, that would be considered unrecoverable in such circumstances, as the effect of any future competition on the Company's rates is not clear at this time. Utility Plant: Utility plant (including plant acquisition adjustment) is stated at cost. For constructed plant, cost includes contracted services, direct labor and materials, indirect charges for engineering, supervision, general and administrative costs, and an allowance for funds used during construction (AFUDC). The AFUDC rate was 6.39% for 1995, 4.07% for 1994, and 4.41% for 1993. The cost of additions to utility plant and replacement units of property is capitalized. Maintenance costs and replacement of minor items of property are charged to expense as incurred. When units of depreciable property are retired, they are removed from the plant accounts and the original cost plus removal charges less salvage are charged to accumulated depreciation. In accordance with regulatory decisions made by the KCC, amortization of the acquisition premium of approximately $801 million resulting from the KGE purchase began in August of 1995. The premium is being amortized over 40 years and has been classified as electric plant in service. Accumulated amortization through December 31, 1995 totaled $6.7 million. In March 1995, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121). This Statement imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. The Company will adopt this standard on January 1, 1996 and does not expect that adoption will have a material impact on the financial position or results of operations based on the Company's current regulatory structure. This conclusion may change in the future if increases in competition influence regulation and wholesale and retail pricing in the electric industry. Depreciation: Depreciation is provided on the straight-line method based on estimated useful lives of property. Composite provisions for book depreciation approximated 2.72% during 1995, 2.7% during 1994, and 2.9% during 1993 of the average original cost of depreciable property. The methods and rates of depreciation used by the Company have not varied materially from the methods and rates which would have been used if the Company were not regulated and not subject to the provisions prescribed by SFAS 71. In the past, the methods and rates have been determined by depreciation studies and approved by the various regulatory bodies. The Company periodically evaluates its depreciation rates considering the past and expected future experience in the operation of its facilities. The Company has proposed to more rapidly recover the Company's investment in nuclear generating assets of Wolf Creek to reduce the capital costs to a level more closely paralleling that of non-nuclear generating facilities (For information regarding such proposal, See Note 3). Cash and Cash Equivalents: For purposes of the Statements of Cash Flows, the Company considers highly liquid collateralized debt instruments purchased with a maturity of three months or less to be cash equivalents. Income Taxes: The Company accounts for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" (SFAS 109). Under SFAS 109, deferred tax assets and liabilities are recognized based on temporary differences in amounts recorded for financial reporting purposes and their respective tax bases (See Note 8). Investment tax credits previously deferred are being amortized to income over the life of the property which gave rise to the credits. Revenues: Operating revenues include amounts actually billed for services rendered and an accrual of estimated unbilled revenues. Unbilled revenues represent the estimated amount customers will be billed for service provided from the time meters were last read to the end of the accounting period. Unbilled revenues of $21.8 million and $21.4 million are recorded as a component of accounts receivable and unbilled revenue (net) on the balance sheets as of December 31, 1995 and 1994, respectively. The Company's recorded reserves for doubtful accounts receivable totaled $3.3 million and $1.9 million at December 31, 1995 and 1994, respectively. Debt Issuance and Reacquisition Expense: Debt premium, discount and issuance expenses are amortized over the life of each issue. Under regulatory procedures, debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt. Fuel Costs: The cost of nuclear fuel in process of refinement, conversion, enrichment, and fabrication is recorded as an asset at original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor at December 31, 1995 and 1994, was $28.5 and $13.6 million, respectively. Cash Surrender Value of Life Insurance Contracts: The following amounts related to corporate-owned life insurance contracts (COLI) are recorded in Corporate-owned Life Insurance (net) on the balance sheets: 1995 1994 (Dollars in Millions) Cash surrender value of contracts. . . $360.3 $320.6 Borrowings against contracts . . . . . (353.0) (311.2) COLI (net) . . . . . . . . . . . . $ 7.3 $ 9.4 Income is recorded for increases in cash surrender value and net death proceeds. Interest expense is recognized for COLI borrowings. The net income generated from COLI contracts, including the tax benefit of the interest deductions and premium expenses, are recorded as Corporate-owned Life Insurance (net) on the Statements of Income. The income from increases in cash surrender value and net death proceeds was $22.7 million for 1995, $15.6 million for 1994, and $19.7 million for 1993. The interest expense deduction taken was $25.4 million for 1995, $21.0 million for 1994, and $11.9 million for 1993. Federal legislation is pending, which, if enacted, may substantially reduce or eliminate the tax deduction for interest on COLI borrowings, and thus reduce a significant portion of the net income stream generated by the COLI contracts (see Note 7). Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation. 2. COMMITMENTS AND CONTINGENCIES Manufactured Gas Sites: The Company has been associated with three former manufactured gas sites which may contain coal tar and other potentially harmful materials. The Company and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement governing all future work at the three sites. The terms of the consent agreement will allow the Company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a 10 year period. The agreement will allow the Company to set mutual objectives with the KDHE in order to expedite effective response activities and to control costs and environmental impact. The costs incurred for site investigation and risk assessment in 1995 and 1994 were minimal. The Company is aware of other Midwestern utilities which have incurred remediation costs ranging between $500,000 and $10 million per site. The KCC has permitted another Kansas utility to recover its remediation costs through rates. To the extent that such remediation costs are not recovered through rates, the costs could be material to the Company's financial position or results of operations depending on the degree of remediation and number of years over which the remediation must be completed. Decommissioning: The Company accrues decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund. On June 9, 1994, the KCC issued an order approving the estimated decommissioning costs as determined by a 1993 Wolf Creek Decommissioning Cost Study to be recovered in rates. The cost study estimated the Company's share of decommissioning costs to be $595 million or approximately $174 million in 1993 dollars. The decommissioning costs are currently expected to be incurred during the period 2025 through 2033. These costs were calculated using an assumed inflation rate of 3.45% and an average after tax expected return on trust fund assets of 5.9%. Decommissioning costs are being charged to operating expenses in accordance with the KCC order. Amounts expensed approximated $3.6 million in 1995 and will increase annually to $5.5 million in 2024. The Company's investment in the decommissioning fund, including reinvested earnings approximated $25.0 million and $16.9 million at December 31, 1995 and December 31, 1994, respectively. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability. These amounts are reflected in Decommissioning Trust, and the related liability is included in Deferred Credits and Other Liabilities, Other, on the Consolidated Balance Sheets. The staff of the SEC has questioned certain current accounting practices used by nuclear electric generating station owners regarding the recognition, measurement and classification of decommissioning costs for nuclear electric generating stations. In response to these questions, the FASB is expected to issue new accounting standards for removal costs, including decommissioning in 1996. If current electric utility industry accounting practices for such decommissioning costs are changed: (1) annual decommissioning expenses could increase, (2) the estimated present value of decommissioning costs could be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. When revised accounting guidance is issued, the Company will also have to evaluate its effect on accounting for removal costs of other long-lived assets. At this time, the Company is not able to predict what effect such changes would have on results of operations, financial position, or related regulatory practices until the final issuance of revised accounting guidance. The Company carries premature decommissioning insurance which has several restrictions. One of these is that it can only be used if Wolf Creek incurs an accident exceeding $500 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor station site in accordance with a plan approved by the Nuclear Regulatory Commission (NRC), and to pay for on-site property damages. This decommissioning insurance will only be available if the insurance funds are not needed to implement the NRC-approved plan for stabilization and decontamination. Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $8.9 billion for a single nuclear incident. If this liability limitation is insufficient, the U.S. Congress will consider taking whatever action is necessary to compensate the public for valid claims. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million and the balance is provided by an assessment plan mandated by the NRC. Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $79.3 million ($37.3 million, Company's share) in the event there is a major nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million ($4.7 million, Company's share) in retrospective assessments per incident, per year. The Owners carry decontamination liability, premature decommissioning liability, and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, Company's share). This insurance is provided by a combination of "nuclear insurance pools" ($500 million) and Nuclear Electric Insurance Limited (NEIL) ($2.3 billion). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. The Company's share of any remaining proceeds can be used for property damage or premature decommissioning costs up to $1.3 billion (Company's share). Premature decommissioning insurance cost recovery is excess of funds previously collected for decommissioning (as discussed under "Decommissioning"). The Owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves, and other NEIL resources, the Company may be subject to retrospective assessments under the current policies of approximately $11 million per year. Although the Company maintains various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, the Company's insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on the Company's financial condition and results of operations. Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in certain emissions. To meet the monitoring and reporting requirements under the acid rain program, the Company installed continuous monitoring and reporting equipment at a total cost of approximately $2.3 million from 1993 through 1995. The Company does not expect additional equipment acquisitions or other material expenditures to be needed to meet Phase II sulfur dioxide requirements. Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the Company has entered into various commitments to obtain nuclear fuel and coal. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1995, WCNOC's nuclear fuel commitments (Company's share) were approximately $15.3 million for uranium concentrates expiring at various times through 2001, $120.8 million for enrichment expiring at various times through 2014, and $72.7 million for fabrication through 2025. At December 31, 1995, the Company's coal contract commitments in 1995 dollars under the remaining terms of the contracts were approximately $643 million. The largest coal contract expires in 2020, with the remaining coal contracts expiring at various times through 2013. Energy Act: As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment decontamination and decommissioning fund. The Company's portion of the assessment for Wolf Creek is approximately $7 million, payable over 15 years. Management expects such costs to be recovered through the ratemaking process. 3. RATE MATTERS AND REGULATION KCC Rate Proceedings: On August 17, 1995, the Company filed with the KCC a request to more rapidly recover its investment in its assets of Wolf Creek over the next seven years. If the request is granted, depreciation expense for Wolf Creek will increase by approximately $50 million for each of the next seven years. As a result of this proposal, the Company will also seek to reduce electric rates for its customers by approximately $9 million annually for the same seven year period. The request also reduces the annual depreciation by approximately $3 million for electric transmission, distribution and certain generating plant assets to reflect the effect of increasing useful lives of these properties. Hearings before the KCC on the depreciation changes and voluntary rate reductions are expected to occur in May 1996. Rate Stabilization Plan: In 1988, the KCC ordered the accrual of phase-in revenues to be discontinued effective December 31, 1988. The Company began amortizing the phase-in revenue asset on a straight-line basis over 9-1/2 years beginning January 1, 1989. At December 31, 1995, approximately $44 million of deferred phase-in revenues remain to be recovered. Coal Contract Settlements: In March 1990, the KCC issued an order allowing the Company to defer its share of a 1989 coal contract settlement with the Pittsburg and Midway Coal Mining Company amounting to $22.5 million. This amount was recorded as a deferred charge and is included in Deferred Charges and Other Assets on the balance sheet. The settlement resulted in the termination of a long-term coal contract. The KCC permitted the Company to recover this settlement as follows: 76% of the settlement plus a return over the remaining term of the terminated contract (through 2002) and 24% to be amortized to expense with a deferred return equivalent to the carrying cost of the asset. Approximately $15 million of this deferral remains on the balance sheet at December 31, 1995. In February 1991, the Company paid $8.5 million to settle a coal contract lawsuit with AMAX Coal Company and recorded the payment as a deferred charge in Deferred Charges and Other Assets on the balance sheet. The KCC approved the recovery of the settlement plus a return equivalent to the carrying cost of the asset, over the remaining term of the terminated contract (through 1996). 4. SHORT-TERM BORROWINGS The Company's short-term financing requirements are satisfied through short-term bank loans and uncommitted loan participation agreements. Maximum short-term borrowings outstanding during 1995 and 1994 were $75.8 million on January 17, 1995 and $172.3 million on January 4, 1994. The weighted average interest rates, including fees, were 6.1% for 1995, 4.5% for 1994, and 3.5% for 1993. 5. LONG-TERM DEBT The amount of KGE's first mortgage bonds authorized by the KGE Mortgage and Deed of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion. Amounts of additional bonds which may be issued are subject to property, earnings, and certain restrictive provisions of the Mortgage. Electric plant is subject to the lien of the Mortgage except for transportation equipment. Debt discount and expenses are being amortized over the remaining lives of each issue. The improvement and maintenance fund requirements for certain first mortgage bond series can be met by bonding additional property. With the retirement of certain Company pollution control series bonds, there are no longer any bond sinking fund requirements. During 1996, $16 million of bonds will mature. 6. SALE-LEASEBACK OF LA CYGNE 2 In 1987, the Company sold and leased back its 50% undivided interest in the La Cygne 2 generating unit. The La Cygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. The Company remains responsible for its share of operation and maintenance costs and other related operating costs of La Cygne 2. The lease is an operating lease for financial reporting purposes. As permitted under the La Cygne 2 lease agreement, the Company in 1992 requested the Trustee Lessor to refinance $341.1 million of secured facility bonds of the Trustee and owner of La Cygne 2. The transaction was requested to reduce recurring future net lease expense. In connection with the refinancing on September 29, 1992, a one-time payment of approximately $27 million was made by the Company which has been deferred and is being amortized over the remaining life of the lease and included in operating expense as part of the future lease expense. At December 31, 1995, approximately $23.7 million of this deferral remained on the balance sheet. Future minimum annual lease payments required under the La Cygne 2 lease agreement are approximately $34.6 million for each year through 2000 and $646 million over the remainder of the lease. The gain of approximately $322 million realized at the date of the sale of La Cygne 2 has been deferred for financial reporting purposes, and is being amortized ($9.6 million per year) over the initial lease term in proportion to the related lease expense. The Company's lease expense, net of amortization of the deferred gain and a one-time payment, was approximately $22.5 million for 1995, 1994, and 1993. 7. EMPLOYEE BENEFIT PLANS Pension: In 1995, the Company's qualified noncontributory defined benefit pension plan was merged into Western Resources, Inc. Retirement Plan (the Plan). The Plan covers substantially all employees of the Company. Pension benefits under the Plan are based on years of service and the employee's compensation during the five highest paid consecutive years out of ten before retirement. Western Resources' policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code. Pension expense of $1.6 million was allocated to the Company by Western Resources in 1995. Also, substantially all Wolf Creek employees are covered under a plan similar to the Plan. The following table provides information on the components of pension cost under Statement of Financial Accounting Standards No. 87 "Employers' Accounting for Pension Plans" (SFAS 87), funded status and actuarial assumptions for the Company: 1995(1) 1994 1993 (Dollars in Millions) SFAS 87 Expense: Service cost. . . . . . . . . . . . . . $ 1.2 $ 3.7 $ 3.2 Interest cost on projected benefit obligation. . . . . . . . . . 1.0 9.7 9.5 (Gain) loss on plan assets. . . . . . . (1.7) 2.1 (14.1) Net amortization and deferral . . . . . 1.1 (11.4) 4.9 Net expense . . . . . . . . . . . . . $ 1.6 $ 4.1 $ 3.5 The following table sets forth the plans' actuarial present value and funded status at November 30, 1995 and 1994 (the plan years) and a reconciliation of such status to the December 31, 1995, 1994, and 1993 financial statements: 1995(1) 1994 1993 (Dollars in Millions) Reconciliation of Funded Status: Actuarial present value of benefit obligations: Vested. . . . . . . . . . . . . . . $ 7.3 $ 94.0 $ 95.2 Non-vested. . . . . . . . . . . . . 1.9 6.3 6.1 Total . . . . . . . . . . . . . . $ 9.2 $100.3 $101.3 Plan assets at November 30 (principally debt and equity securities) at fair value . . . . . . . . . . . . . $ 8.8 $115.4 $119.9 Projected benefit obligation at November 30 . . . . . . . . . . . . (17.8) (125.4) (125.5) Funded status at November 30. . . . . . . (9.0) (10.0) (5.6) Unrecognized transition asset . . . . . . 0.9 (1.5) (1.7) Unrecognized prior service costs. . . . . 0.4 9.6 12.4 Unrecognized net gain . . . . . . . . . . (0.4) (11.1) (20.6) Accrued pension costs at December 31. . . $ (8.1) $(13.0) $(15.5) Year Ended December 31, 1995 1994 1993 Actuarial Assumptions: Discount rate . . . . . . . . . . 7.5 % 8.0-8.5 % 7.0-7.75% Annual salary increase rate . . . (2) 5.0 % 5.0 % Long-term rate of return. . . . . 8.5 % 8.0-8.5 % 8.0-8.5 % (1) 1995 includes only the Company's 47% share of the Wolf Creek Plan. (2) Graded based on age: 6.5% at age 20 graded to 4.5% at age 60. Postretirement: Western Resources and the Company adopted the provisions of Statement of Financial Accounting Standards No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106) in the first quarter of 1993. This statement requires the accrual of postretirement benefits other than pensions, primarily medical benefits costs, during the years an employee provides service. The Company's total obligation is recorded by Western Resources, and the related postretirement benefits expenses are allocated to the Company. The total postretirement benefits expenses allocated to the Company by Western Resources under SFAS 106 were approximately $3.7 million in 1995 and $3.8 million in 1994. The KCC issued an order permitting Western Resources to defer the initial SFAS 106 expense. To mitigate the impact incremental SFAS 106 expense will have on rate increases, Western Resources will include in future computations of cost of service the actual postretirement benefits expenses and an income stream generated from COLI contracts purchased in 1993 and 1992. To the extent postretirement benefits expenses exceed income from the COLI program, this excess is being deferred (in accordance with the provisions of the FASB Emerging Issues Task Force Issue No. 92-12) and will be offset by income generated through the deferral period by the COLI program. Because these expenses were deferred by Western Resources, the Company's results of continuing operations are not affected. At December 31, 1995, approximately $7.0 million related to the Company's portion of postretirement expenses had been deferred by Western Resources pursuant to the KCC order. Pending federal legislation may substantially reduce or eliminate tax benefits associated with COLI contracts. If this legislation is enacted or should the income stream generated by the COLI program not be sufficient to offset postretirement benefit costs on an accrual basis, the KCC order allows Western Resources and the Company to seek recovery of a deficiency through the ratemaking process. Regulatory precedents established by the KCC generally permit the accrual costs of postretirement benefits to be recovered in rates. The Company also records, based on actuarial projections, the postretirement benefit expenses related to its 47% ownership in Wolf Creek, which approximated $0.3 million and $0.4 million for 1995 and 1994, respectively. The following table summarizes the status of the Company's postretirement plan for financial statement purposes and the related amounts included in the balance sheet: December 31, 1995(2) 1994 1993 (Dollars in Millions) Reconciliation of Funded Status: Actuarial present value of postretirement benefit obligations: Retirees. . . . . . . . . . . . . . . . . . . $ (1.7) $(12.9) $(12.4) Active employees fully eligible . . . . . . . - ( 3.0) ( 2.5) Active employees not fully eligible . . . . . (1.0) ( 9.4) ( 9.0) Funded status. . . . . . . . . . . . . . . . (2.7) (25.3) (23.9) Unrecognized prior service cost . . . . . . . - 3.2 .1 Unrecognized transition obligation. . . . . . 0.7 19.3 20.4 Unrecognized net (gain) loss. . . . . . . . . 0.9 (.9) 1.7 Accrued postretirement benefit costs. . . . . . . $ (1.1) $ (3.7) $ (1.7) Year Ended December 31, 1995 1994 1993 Assumptions: Discount rate. . . . . . . . . . . . . . . . . 7.5 % 8.0-8.5 % 7.75% Annual compensation increase rate. . . . . . . 4.75% 5.0 % 5.0 % Expected rate of return. . . . . . . . . . . . 9.0 % 8.5 % 8.5 % (2) 1995 includes only the Company's 47% share of the Wolf Creek Plan. For measurement purposes, an annual health care cost growth rate of 10.5% was assumed for 1995, decreasing to six percent in 1997. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by one percent each year would increase the present value of the accumulated projected benefit obligation by $1.4 million and the aggregate of the service and interest cost components by $0.2 million. Postemployment: Western Resources and the Company adopted the provisions of Statement of Financial Accounting Standards No. 112 "Employers' Accounting for Postemployment Benefits" (SFAS 112) in the first quarter of 1994. This statement requires the recognition of the liability to provide postemployment benefits when the liability has been incurred. Due to the immaterial amounts and the rate treatment from the Company's regulators, there was no material impact upon the Company's continuing operations. The Company's total obligation is recorded by Western Resources, and the related postemployment benefits expenses are allocated to the Company. The total postemployment benefits expenses allocated to the Company by Western Resources under SFAS 112 were approximately $0.9 million in 1995 and $0.8 million in 1994, respectively. The KCC issued an order permitting Western Resources to defer the initial SFAS 112 expense. At December 31, 1995, approximately $1.9 million related to the Company's portion of postemployment expenses had been deferred pursuant to the KCC order. Savings: Effective January 1, 1995, the Company's 401(k) savings plan was merged with Western Resources savings plan. Western Resources maintains a savings plan in which substantially all employees participate. Prior to the merger of the savings plans, funds of the plans were deposited with a trustee and invested at each employee's option in one or more investment funds, including a Western Resources common stock fund. The Company's contributions were $1.8 million for 1994 and $2.0 million for 1993. In 1995, 401(k) contribution expense allocated to the Company was $1.7 million. 8. INCOME TAXES Under SFAS 109, temporary differences gave rise to deferred tax assets and deferred tax liabilities at December 31, 1995 and 1994, respectively, as follows: Deferred Tax Assets: 1995 1994 (Dollars in Thousands) Deferred gain on sale-leaseback. . . . . $ 105,007 $ 110,556 Alternative Minimum tax carry forwards . 18,740 41,163 Other. . . . . . . . . . . . . . . . . . 10,870 11,253 Total Deferred Tax Assets. . . . . . . $ 134,617 $ 162,972 Deferred Tax Liabilities: Accelerated Depreciation & Other . . . . $ 375,079 $ 381,800 Acquisition Premium. . . . . . . . . . . 314,933 317,610 Deferred Future Income Taxes . . . . . . 208,367 197,663 Other. . . . . . . . . . . . . . . . . . 37,172 49,942 Total Deferred Tax Liabilities . . . . $ 935,551 $ 947,015 Accumulated Deferred Income Taxes, Net $ 800,934 $ 784,043 In accordance with various rate orders received from the KCC, the Company has not yet collected through rates the amounts necessary to pay a significant portion of the net deferred income tax liabilities. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers, it has recorded a deferred asset for these amounts. These assets are also a temporary difference for which deferred income tax liabilities have been provided. At December 31, 1995, the Company has alternative minimum tax credits generated prior to April 1, 1992, which carry forward without expiration, of $18.7 million which may be used to offset future regular tax to the extent the regular tax exceeds the alternative minimum tax. These credits have been applied in determining the Company's net deferred income tax liability and corresponding deferred future income taxes at December 31, 1995. 9. LEGAL PROCEEDINGS The Company is involved in various legal and environmental proceedings. Management believes that adequate provision has been made within the financial statements for these matters and accordingly believes their ultimate dispositions will not have a material adverse effect upon the financial position or results of operations of the Company. 10. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in Statement of Financial Accounting Standards No. 107 "Disclosures About Fair Value of Financial Instruments": Cash and Cash Equivalents- The carrying amount approximates the fair value because of the short-term maturity of these investments. Decommissioning Trust- The carrying amount is recorded at the fair value of the decommissioning trust and is based on quoted market prices at December 31, 1995 and 1994. Variable-rate Debt- The carrying amount approximates the fair value because of the short-term variable rates of these debt instruments. Fixed-rate Debt- The fair value of the fixed-rate debt is based on the sum of the estimated value of each issue taking into consideration the interest rate, maturity, and redemption provisions of each issue. The estimated fair values of the Company's financial instruments are as follows: Carrying Value Fair Value December 31, 1995 1994 1995 1994 (Dollars in Thousands) Cash and cash equivalents. . . . . . . $ 53 $ 47 $ 53 $ 47 Decommissioning trust. . . 25,070 16,944 25,070 16,633 Variable-rate debt . . . . 449,433 407,645 449,433 407,645 Fixed-rate debt. . . . . . 657,457 657,482 675,471 623,331 11. JOINT OWNERSHIP OF UTILITY PLANTS Company's Ownership at December 31, 1995 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 155,566 $ 99,133 341 50 Jeffrey 1 (b) Jul 1978 67,322 28,312 140 20 Jeffrey 2 (b) May 1980 68,151 26,951 147 20 Jeffrey 3 (b) May 1983 96,031 36,333 141 20 Wolf Creek (c) Sep 1985 1,371,878 335,941 548 47 (a) Jointly owned with Kansas City Power & Light Company (KCPL) (b) Jointly owned with Western Resources and UtiliCorp United Inc. (c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc. Amounts and capacity represent the Company's share. The Company's share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in La Cygne 2 (representing 335 MW capacity) sold and leased back to the Company in 1987, are included in operating expenses on the Statements of Income. The Company's share of other transactions associated with the plants is included in the appropriate classification in the Company's financial statements. 12. QUARTERLY FINANCIAL STATISTICS (Unaudited) The amounts in the table are unaudited but, in the opinion of management, contain all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results of such periods. The business of the Company is seasonal in nature and, in the opinion of management, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations. 1995 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. (Dollars in Thousands) Operating revenues. . . . . $138,182 $202,382 $144,747 $138,557 Operating income. . . . . . 25,974 63,684 30,779 28,567 Net income. . . . . . . . . 21,598 51,836 19,567 17,872 1994 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. (Dollars in Thousands) Operating revenues. . . . . $139,087 $189,202 $154,987 $136,604 Operating income. . . . . . 33,607 56,978 33,548 24,878 Net income. . . . . . . . . 22,212 45,481 23,623 13,210 13. RELATED PARTY TRANSACTIONS The cash management function, including cash receipts and disbursements, for KGE is performed by Western Resources. An intercompany account is used to record net receipts and dusbursements handled by Western Resources. The net amount advanced by KGE to Western Resources approximated $35 million and $64 million at December 31, 1995 and 1994, respectively. These amounts are recorded as advances to parent company in Current Assets on the balance sheet. Certain operating expenses have been allocated to the Company from Western Resources. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers, and/or other appropriate allocators. Management believes such allocation procedures are reasonable. During 1995, the Company declared a dividend to Western Resources of $150 million. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There were no disagreements with accountants on accounting and financial disclosure. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Western Resources, Inc. owns 100% of the Company's outstanding common stock. A Director Business Experience Since 1990 and Other Continuously Name Age Directorships Other Than The Company Since William B. 43 Chairman of the Board and President 1995 Moore (since June 1995), and prior to that Vice President, Finance, Western Resources, Inc. Robert T. 70 Owner, Crain Realty, Co., Fort Scott, 1992(b) Crain Kansas (a) Directorships Citizens National Bank Ft. Scott Industries, Inc. Anderson E. 62 President, Jackson Mortuary, Wichita, 1994 Jackson Kansas Donald A. 62 Retired President, Maupintour, Inc., 1992(b) Johnston Lawrence, Kansas (Escorted Tours (a) And Travel) Directorships Commerce Bank, Lawrence Steven L. 50 Executive Vice President and Chief 1992 Kitchen Financial Officer, Western Resources, Inc. Glenn L. 70 Retired Vice President - Nuclear of the 1992(b) Koester Company Marilyn B. 46 President, Wichita (since October 1993) 1994 Pauly and prior to that Executive Vice (a) President, Wichita, Bank IV, N.A., Wichita, Kansas Directorships Farmers Mutual Alliance Insurance Company Richard D. 62 President, Range Oil Company 1993 Smith Directorships Boatmen's National Bank of Kansas (a) Member of the Audit Committee of which Mr. Johnston is Chairman. The Audit Committee has responsibility for the investigation and review of the financial affairs of the Company and its relations with independent accountants. (b) Mr. Crain, Mr. Johnston, and Mr. Koester were directors of the former Kansas Gas & Electric Company since 1981, 1980, and 1986, respectively. Outside Directors are paid $3,750 per quarter retainer and are paid an attendance fee of $600 for Directors' meetings ($300 if attending by phone). A committee attendance fee of $800 is paid to the outside Director Audit Committee Chairman, and $500 to other outside Committee members. All outside Directors are reimbursed mileage and expenses while attending Directors' and Committee Meetings. During 1995, the Board of Directors met five times and the Audit Committee met once. Each director attended at least 75% of the total number of Board and Committee meetings held while he/she served as a director or a member of the committee. Other information required by Item 10 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. ITEM 11. EXECUTIVE COMPENSATION Information required by Item 11 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required by Item 12 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information required by Item 13 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K The following financial statements are included herein under Item 8. FINANCIAL STATEMENTS Balance Sheets, December 31, 1995 and 1994 Statements of Income for the year ended December 31, 1995, 1994 and 1993 Statements of Cash Flows for the year ended December 31, 1995, 1994 and 1993 Statements of Taxes for the year ended December 31, 1995, 1994 and 1993 Statements of Capitalization, December 31, 1995 and 1994 Statements of Common Stock Equity for the year ended December 31, 1995 Notes to Financial Statements REPORTS ON FORM 8-K None EXHIBIT INDEX All exhibits marked "I" are incorporated herein by reference. Description 2(a) Agreement and Plan of Merger (Filed as Exhibit 2 to Form 10-K I for the year ended December 31, 1990, File No. 1-7324) 2(b) Amendment No. 1 to Agreement and Plan of Merger (Filed as I Exhibit 2 to Form 10-K for the year ended December 31, 1990, File No. 1-7324) 3(a) Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K I for the year ended December 31, 1992, File No. 1-7324) 3(b) Certificate of Merger of Kansas Gas and Electric Company into I KCA Corporation (Filed as Exhibit 3(b) to Form 10-K for the year ended December 31, 1992, File No. 1-7324) 3(c) By-laws as amended (Filed as Exhibit 3(c) Form 10-K I for the year ended December 31, 1992, File No. 1-7324) 4(c)1 Mortgage and Deed of Trust, dated as of April 1, 1940 to I Guaranty Trust Company of New York (now Morgan Guaranty Trust Company of New York) and Henry A. Theis (to whom W. A. Spooner is successor), Trustees, as supplemented by thirty-eight Supplemental Indentures, dated as of June 1, 1942, March 1, 1948, December 1, 1949, June 1, 1952, October 1, 1953, March 1, 1955, February 1, 1956, January 1, 1961, May 1, 1966, March 1, 1970, May 1, 1971, March 1, 1972, May 31, 1973, July 1, 1975, December 1, 1975, September 1, 1976, March 1, 1977, May 1, 1977, August 1, 1977, March 15, 1978, January 1, 1979, April 1, 1980, July 1, 1980, August 1, 1980, June 1, 1981, December 1, 1981, May 1, 1982, March 15, 1984, September 1, 1984 (Twenty-ninth and Thirtieth), February 1, 1985, April 15, 1986, June 1, 1991 March 31, 1992, December 17, 1992, August 24, 1993, January 15, 1994 and March 1, 1994, (Filed, respectively, as Exhibit A-1 to Form U-1, File No. 70-23; Exhibits 7(b) and 7(c), File No. 2-7405; Exhibit 7(d), File No. 2-8242; Exhibit 4(c), File No. 2-9626; Exhibit 4(c), File No. 2-10465; Exhibit 4(c), File No. 2-12228; Exhibit 4(c), File No. 2-15851; Exhibit 2(b)-1, File No. 2-24680; Exhibit 2(c), File No. 2-36170; Exhibits 2(c) and 2(d), File No. 2-39975; Exhibit 2(d), File No. 2-43053; Exhibit 4(c)2 to Form 10-K, for December 31, 1989, File No. 1-7324; Exhibit 2(c), File No. 2-53765; Exhibit 2(e), File No. 2-55488; Exhibit 2(c), File No. 2-57013; Exhibit 2(c), File No. 2-58180; Exhibit 4(c)3 to Form 10-K for December 31, 1989, File No. 1-7324; Exhibit 2(e), File No. 2-60089; Exhibit 2(c), File No. 2-60777; Exhibit 2(g), File No. 2-64521; Exhibit 2(h), File No. 2-66758; Exhibits 2(d) and 2(e), File No. 2-69620; Exhibits 4(d) and 4(e), File No. 2-75634; Exhibit 4(d), File No. 2-78944; Exhibit 4(d), File No. 2-87532; Exhibits 4(c)4, 4(c)5 and 4(c)6 to Form 10-K for December 31, 1989, File No. 1-7324; Exhibits 4(c)2 and 4(c)3 to Form 10-K for Description December 31, 1992, File No. 1-7324; Exhibit 4(b) to Form S-3, File No. 33-50075; Exhibits 4(c)2 and 4(c)3 to Form 10-K for December 31, 1993, File No. 1-7324; Exhibit 4(c)2 to Form 10-K for December 31, 1994, File No. 1-7324) Instruments defining the rights of holders of other long-term debt not required to be filed as exhibits will be furnished to the Commission upon request. 10(a) La Cygne 2 Lease (Filed as Exhibit 10(a) to Form 10-K for the year I ended December 31, 1988, File No. 1-7324) 10(a)1 Amendment No. 3 to La Cygne 2 Lease Agreement dated as of September I 29, 1992 (Filed as Exhibit 10(b)1 to Form 10-K for the year ended December 31, 1992, File No. 1-7324) 10(b) Outside Directors' Deferred Compensation Plan (Filed as Exhibit I 10(c) to the Form 10-K for the year ended December 31, 1993, File No. 1-7324) 12 Computation of Ratio of Consolidated Earnings to Fixed Charges (Filed electronically) 23 Consent of Independent Public Accountants, Arthur Andersen LLP (Filed electronically) 27 Financial Data Schedule (Filed electronically) SIGNATURE Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. KANSAS GAS AND ELECTRIC COMPANY March 27, 1996 By WILLIAM B. MOORE William B. Moore, Chairman of the Board and President

Exhibit 12
KANSAS GAS AND ELECTRIC COMPANY Computations of Ratio of Earnings to Fixed Charges (Dollars in Thousands) 1995 1994 1993 Net Income. . . . . . . . . . . . . $110,873 $104,526 $108,103 Taxes on Income . . . . . . . . . . 51,787 55,349 46,896 Net Income Plus Taxes. . . . . 162,660 159,875 154,999 Fixed Charges: Interest on Long-Term Debt. . . . 47,073 47,827 53,908 Interest on Other Indebtedness. . 5,190 5,183 6,075 Interest on Corporate-owned Life Insurance Borrowings . . . 25,357 20,990 11,865 Interest Applicable to Rentals. . 25,375 25,096 24,967 Total Fixed Charges . . . . . 102,995 99,096 96,815 Earnings (1). . . . . . . . . . . . $265,655 $258,971 $251,814 Ratio of Earnings to Fixed Charges. 2.58 2.61 2.60
1992 Pro Forma April 1 | January 1 1992 (2) to Dec. 31 | to March 31 1991 (Successor) |(Predecessor) Net Income. . . . . . . . . . . . . $ 77,981 $ 71,941 | $ 6,040 $ 53,602 Taxes on Income . . . . . . . . . . 20,378 23,551 | (3,173) 15,955 Net Income Plus Taxes. . . . . 98,359 95,492 | 2,867 69,557 | Fixed Charges: | Interest on Long-Term Debt. . . . 57,862 42,889 | 14,973 59,668 Interest on Other Indebtedness. . 15,121 11,777 | 3,344 17,838 Interest on Corporate-owned | Life Insurance Borrowings . . . 7,155 5,294 | 1,861 7,304 Interest Applicable to Rentals. . 30,212 22,133 | 8,079 32,193 Total Fixed Charges . . . . . 110,350 82,093 | 28,257 117,003 | Earnings (1). . . . . . . . . . . . $208,709 $177,585 | $ 31,124 $186,560 | Ratio of Earnings to Fixed Charges. 1.89 2.16 | 1.10 1.59 (1) Earnings are deemed to consist of net income to which has been added income taxes (including net deferred investment tax credit) and fixed charges. Fixed charges consist of all interest on indebtedness, amortization of debt discount and expense, and the portion of rental expense which represents an interest factor. (2) The pro forma information for the year ended December 31, 1992 was derived by combining the historical information of the three month period ended March 31, 1992 (Predecessor) and the nine month period ended December 31, 1992 (Successor). No purchase accounting adjustments were made for periods prior to the Merger in determining pro forma amounts because such adjustments would be immaterial. (See Note 1 of Notes to Financial Statements)

Exhibit 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-K, into the Company's previously filed Registration Statements File No. 33-50075 of Kansas Gas and Electric Company on Form S-3. ARTHUR ANDERSEN LLP Kansas City, Missouri, March 26, 1996

UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE BALANCE SHEET AT DECEMBER 31, 1995 AND THE STATEMENT OF INCOME AND THE STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1995 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1995 DEC-31-1995 PER-BOOK 2,628,952 32,955 177,599 363,908 0 3,203,414 1,065,634 0 120,443 1,186,077 0 0 684,082 50,000 0 0 16,000 0 0 0 1,267,255 3,203,414 623,868 51,787 413,991 474,864 149,004 11,302 160,306 49,433 110,873 0 110,873 0 47,073 190,777 0 0