SEC Filing | Evergy, Inc.

1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-7324 KANSAS GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) KANSAS 48-1093840 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) P.O. BOX 208, WICHITA, KANSAS 67201 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code 316/261-6611 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X) Indicate the number of shares outstanding of each of the registrant's classes of common stock. Common Stock, No par value 1,000 Shares (Title of each class) (Outstanding at March 27, 1997) Indicated by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No Registrant meets the conditions of General Instruction J(1)(a) and (b) to Form 10-K for certain wholly-owned subsidiaries and is therefore filing an abbreviated form. 2 KANSAS GAS AND ELECTRIC COMPANY FORM 10-K December 31, 1996 TABLE OF CONTENTS Description Page PART I Item 1. Business 3 Item 2. Properties 11 Item 3. Legal Proceedings 12 Item 4. Submission of Matters to a Vote of Security Holders 12 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 12 Item 6. Selected Financial Data 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 13 Item 8. Financial Statements and Supplementary Data 20 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 41 PART III Item 10. Directors and Executive Officers of the Registrant 42 Item 11. Executive Compensation 43 Item 12. Security Ownership of Certain Beneficial Owners and Management 43 Item 13. Certain Relationships and Related Transactions 43 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 44 Signatures 47 3 PART I ITEM 1. BUSINESS GENERAL The Company is an electric public utility engaged in the generation, transmission, distribution and sale of electric energy in the southeastern quarter of Kansas including the Wichita metropolitan area. The Company owns 47% of Wolf Creek Nuclear Operating Corporation, the operating company for Wolf Creek Generating Station (Wolf Creek). Corporate headquarters of the Company is located in Wichita, Kansas. The Company has no gas properties. At December 31, 1996, the Company had no employees. All employees are provided by the Company's parent, Western Resources. On March 31, 1992, Western Resources, Inc. (Western Resources) through its wholly-owned subsidiary KCA Corporation (KCA), acquired all of the outstanding common and preferred stock of Kansas Gas and Electric Company (KGE) (the Merger). Simultaneously, KCA and Kansas Gas and Electric Company merged and adopted the name Kansas Gas and Electric Company (the Company, KGE). The electric utility industry in the United States is rapidly evolving from an historically regulated monopolistic market to a dynamic and competitive integrated marketplace. The 1992 Energy Policy Act (Act) began the process of deregulation of the electricity industry by permitting the Federal Energy Regulatory Commission (FERC) to order electric utilities to allow third parties to sell electric power to wholesale customers over their transmission systems. Since that time, the wholesale electricity market has become increasingly competitive as companies begin to engage in nationwide power brokerage. In addition, various states including California and New York have taken active steps toward allowing retail customers to purchase electric power from third-party providers. In 1996, the Kansas Corporation Commission (KCC) initiated a generic docket to study electric restructuring issues. A retail wheeling task force has been created by the Kansas Legislature to study competitive trends in retail electric services. During the 1997 session of the Kansas Legislature, bills have been introduced to increase competition in the electric industry. Among the matters under consideration is the recovery by utilities of costs in excess of competitive cost levels. There can be no assurance at this time that such costs will be recoverable if open competition is initiated in the electric utility market. For discussion regarding competition in the electric utility industry and the potential impact on the company, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Other Information, Competition and Enhanced Business Opportunities included herein. Discussion of other factors affecting the company are set forth in the Notes to Financial Statements and Management's Discussion and Analysis included herein. 4 ELECTRIC OPERATIONS General The company supplies electric energy at retail to approximately 277,000 customers in 139 communities in Kansas. The company also supplies electric energy to 27 communities and 1 rural electric cooperative, and has contracts for the sale, purchase or exchange of electricity with other utilities at wholesale. The Company's electric sales for the last five years were as follows: 1996 1995 1994 1993 1992 (Thousands of MWH) Residential 2,503 2,385 2,384 2,386 2,102 Commercial 2,186 2,095 2,068 1,991 1,892 Industrial 3,501 3,542 3,371 3,323 3,248 Wholesale and Interchange 2,706 1,292 1,590 2,004 1,267 Other 45 45 45 45 46 Total 10,941 9,359 9,458 9,749 8,555 The company's electric revenues for the last five years were as follows: 1996 1995 1994 1993 1992 (Dollars in Thousands) Residential $226,456 $221,628 $220,067 $219,069 $194,142 Commercial 176,963 171,654 167,499 162,858 154,005 Industrial 175,420 182,930 181,119 179,256 174,226 Wholesale and Interchange 57,242 31,143 38,750 45,843 28,086 Other 18,489 16,513 12,445 9,971 6,792 Total $654,570 $623,868 $619,880 $616,997 $557,251

Capacity The aggregate net generating capacity of the company's system is presently 2,530 megawatts (MW). The system comprises interests in twelve fossil fueled steam generating units, one nuclear generating unit (47% interest) and one diesel generator, located at seven generating stations. One of the twelve fossil fueled units (70 MW capacity) has been "mothballed" for future use (See Item 2. Properties). The company's 1996 peak system net load occurred on July 19, 1996 and amounted to 1,853 MW. The Company's net generating capacity together with power available from firm interchange and purchase contracts, provided a capacity margin of approximately 19% above system peak responsibility at the time of the peak. 5 The company and twelve companies in Kansas and western Missouri have agreed to provide capacity (including margin), emergency and economy services for each other. This arrangement is called the MOKAN Power Pool. The pool participants also coordinate the planning of electric generating and transmission facilities. The company is one of 60 members of the Southwest Power Pool (SPP). SPP's responsibility is to maintain system reliability on a regional basis. The region encompasses areas within the eight states of Kansas, Missouri, Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi. In 1994, the company joined the Western Systems Power Pool (WSPP). Under this arrangement, over 156 electric utilities and marketers throughout the western United States have agreed to market energy and to provide transmission services. WSPP's intent is to increase the efficiency of the interconnected power systems operations over and above existing operations. Services available include short-term and long-term economy energy transactions, unit commitment service, firm capacity and energy sales, energy exchanges, and transmission service by intermediate systems. During 1994, the company entered into an agreement with Midwest Energy, Inc. (MWE), whereby the company will provide MWE with peaking capacity of 61 MW through the year 2008. The company also entered into an agreement with Empire District Electric Company (Empire), whereby the company will provide Empire with peaking and base load capacity (20 MW in 1994 increasing to 80 MW in 2000) through the year 2000. Future Capacity The company does not contemplate any significant expenditures in connection with construction of any major generating facilities for the next five years. (See Item 7. Management's Discussion and Analysis, Liquidity and Capital Resources). The company has capacity available which may not be fully utilized by growth in customer demand for at least 4 years. The company continues to market this capacity and energy to other utilities. Fuel Mix The company's coal-fired units comprise 1,113 MW of the total 2,530 MW of generating capacity and the company's nuclear unit provides 547 MW of capacity. Of the remaining 870 MW of generating capacity, units that can burn either natural gas or oil account for 867 MW, and the remaining unit which burns only diesel fuel accounts for 3 MW (See Item 2. Properties). During 1996, low sulfur coal was used to produce 62% of the company's electricity. Nuclear produced 32% and the remainder was produced from natural gas, oil, or diesel fuel. During 1997, based on the company's estimate of the availability of fuel, coal will to be used to produce approximately 60% of the company's electricity and nuclear will be used to produce 32%. The company's fuel mix fluctuates with the operation of nuclear powered Wolf Creek which has an 18-month refueling and maintenance schedule. The 18 - -month schedule permits uninterrupted operation every third calendar year. Wolf Creek was taken off-line on February 3, 1996 for its eighth refueling and maintenance outage. The outage lasted approximately 60 days during which time electric demand was met primarily by the company's coal-fired generating units. 6 Nuclear The owners of Wolf Creek have on hand or under contract 70% of the uranium requirements for operation of Wolf Creek through September 2003. The balance is expected to be obtained through spot market and term contract purchases. The company has four contracts with the following companies for uranium: Cameco Corporation, Geomex Minerals, Inc., and Power Resources, Inc. A contractual arrangement is in place with Cameco Corporation for the conversion of uranium to uranium hexafluoride sufficient for the operation of Wolf Creek through the year 2001. The company has two active contracts for uranium enrichment performed by Urenco and USEC. Contracted arrangements cover 82% of Wolf Creek's uranium enrichment requirements for operation of Wolf Creek through March 2005. The balance is expected to be obtained through spot market and term contract purchases. The decision not to contract for the full enrichment requirements is one of cost rather than availability of service. The company has entered into all of its uranium, uranium hexaflouride and uranium enrichment arrangements during the ordinary course of business and is not substantially dependent upon these agreements. The company believes there are other suppliers available at reasonable prices to replace, if necessary, these contracts. In the event that the company were required to replace these contracts, it would not anticipate a substantial disruption of its business. The Nuclear Waste Policy Act of 1982 established schedules, guidelines and responsibilities for the Department of Energy (DOE) to develop and construct repositories for the ultimate disposal of spent fuel and high-level waste. The DOE has not yet constructed a high-level waste disposal site and has announced that a permanent storage facility may not be in operation prior to 2010 although an interim storage facility may be available earlier. Wolf Creek contains an onsite spent fuel storage facility which, under current regulatory guidelines, provides space for the storage of spent fuel through 2005 while still maintaining full core off-load capability. The Company is currently investigating spent fuel storage options which should provide enough additional storage space through at least 2020 while still maintaining full core off-load capability. The company believes adequate additional storage space can be obtained as necessary. Additional information with respect to insurance coverage applicable to the operations of the company's nuclear generating facility is set forth in Note 2 of the Notes to Consolidated Financial Statements. Coal The three coal-fired units at Jeffrey Energy Center (JEC) have an aggregate capacity of 428 MW (KGE's 20% share) (See Item 2. Properties). Western Resources, the operator of JEC, and KGE have a long-term coal supply contract with Amax Coal West, Inc. (AMAX), a subsidiary of Cyprus Amax Coal Company, to supply low sulfur coal to JEC from AMAX's Eagle Butte Mine or an alternate mine source of AMAX's Belle Ayr Mine, both located in the Powder River Basin in Campbell County, Wyoming. The contract expires December 31, 2020. The contract contains a schedule of minimum annual delivery quantities based on MMBtu provisions. The coal to be supplied is surface mined and has an average Btu content of approximately 8,300 Btu per pound and an average sulfur content of .43 lbs/MMBtu (See Environmental Matters). The average delivered cost of coal for JEC was approximately $1.10 per MMBtu or $18.70 per ton during 1996. 7 Coal is transported by Western Resources from Wyoming under a long-term rail transportation contract with Burlington Northern (BN) and Union Pacific (UP) to JEC through December 31, 2013. Rates are based on net load carrying capabilities of each rail car. Western Resources provides 868 aluminum rail cars, under a 20 year lease, to transport coal to JEC. The two coal-fired units at La Cygne Station have an aggregate generating capacity of 678 MW (KGE's 50% share) (See Item 2. Properties). The operator, Kansas City Power & Light Company (KCPL), maintains coal contracts as discussed in the following paragraphs. La Cygne 1 uses low sulfur Powder River Basin coal which is supplied under a variety of spot market transactions, discussed below. High Btu or Kansas/Missouri coal is blended with the Powder River Basin coal and is secured from time to time under spot market arrangements. La Cygne 1 uses a blended fuel mix containing approximately 85% Powder River Basin coal. La Cygne 2 and additional La Cygne 1 Powder River Basin coal is supplied through several contracts, expiring at various times through 1999. This low sulfur coal had an average Btu content of approximately 8,500 Btu per pound and a maximum sulfur content of .50 lbs/MMBtu (See Environmental Matters). Transportation is covered by KCPL through its Omnibus Rail Transportation Agreement with BN and Kansas City Southern Railroad (KCS) through December 31, 2000. During 1996, the average delivered cost of all local and Powder River Basin coal procured for La Cygne 1 was approximately $0.64 per MMBtu or $13.47 per ton and the average delivered cost of Powder River Basin coal for La Cygne 2 was approximately $0.68 per MMBtu or $11.49 per ton. The company has entered into all of its coal and transportation contracts during the ordinary course of business and is not substantially dependent upon these contracts. The company believes there are other supplies for and plentiful sources of coal available at reasonable prices to replace, if necessary, fuel to be supplied pursuant to these contracts. In the event that the company were required to replace its coal or transportation agreements, it would not anticipate a substantial disruption of the company's business. Natural Gas The company uses natural gas as a primary fuel in its Gordon Evans and Murray Gill Energy Centers. Natural gas for these generating stations is supplied by readily available gas from the spot market. Short-term economical spot market purchases will supply the system with the flexible natural gas supply to meet operational needs. Oil The company uses oil as an alternate fuel when economical or when interruptions to natural gas make it necessary. Oil is also used as a supplemental fuel at JEC and La Cygne generating stations. All oil burned by the company during the past several years has been obtained by spot market purchases. At December 31, 1996, the company had approximately 792 thousand gallons of No. 2 oil and 9.8 million gallons of No. 6 oil which is believed to be sufficient to meet emergency requirements and protect against lack of availability of natural gas and/or the loss of a large generating unit. 8 Other Fuel Matters The company's contracts to supply fuel for its coal and natural gas-fired generating units, with the exception of JEC, do not provide full fuel requirements at the various stations. Supplemental fuel is procured on the spot market to provide operational flexibility and, when the price is favorable, to take advantage of economic opportunities. Set forth in the table below is information relating to the weighted average cost of fuel used by the company. 1996 1995 1994 1993 1992 Per Million Btu: Nuclear $0.50 $0.40 $0.36 $0.35 $0.34 Coal 0.88 0.91 0.90 0.96 1.25 Gas 2.30 1.68 1.98 2.37 1.95 Oil 2.74 4.00 3.90 3.15 4.28 Cents per KWH Generation 0.93 0.82 0.89 0.93 0.98 Environmental Matters The company currently holds all Federal and State environmental approvals required for the operation of its generating units. The company believes it is presently in substantial compliance with all air quality regulations (including those pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx)) promulgated by the State of Kansas and the Environmental Protection Agency (EPA). The Federal sulfur dioxide standards applicable to the company's JEC and La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur dioxide per million Btu of heat input. Federal particulate matter emission standards applicable to these units prohibit: (1) the emission of more than 0.1 pounds of particulate matter per million Btu of heat input and (2) an opacity greater than 20%. Federal NOx emission standards applicable to these units prohibit the emission of more than 0.7 pounds of NOx per million Btu of heat input. The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards through the use of low sulfur coal (See Coal); (2) the particulate matter standards through the use of electrostatic precipitators; and (3) the NOx standards through boiler design and operating procedures. The JEC units are also equipped with flue gas scrubbers providing additional sulfur dioxide and particulate matter emission reduction capability when needed to meet permit limits. The Kansas Department of Health and Environment (KDHE) regulations, applicable to the company's other generating facilities, prohibit the emission of more than 3.0 pounds of sulfur dioxide per million Btu of heat input at the company's generating units. The company has sufficient low sulfur coal under contract (See Coal) to allow compliance with such limits at La Cygne 1 for the life of the contract. All facilities burning coal are equipped with flue gas scrubbers and/or electrostatic precipitators. 9 The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in sulfur dioxide and NOx emissions with Phase I effective in 1995 and Phase II effective in 2000 and a probable reduction in toxic emissions by a future date not yet determined. To meet the monitoring and reporting requirements under the Act's acid rain program, the company has installed continuous monitoring and reporting equipment at a total cost of approximately $2.3 million as of December 31, 1996. The company does not expect material expenditures to be needed to meet Phase II sulfur dioxide requirements. Although the company currently has no Phase I affected units, the company has applied for and has been accepted for an early substitution permit to bring the co-owned La Cygne Unit 1 under the Phase I regulations. The NOx and toxic limits, which were not set in the law, were proposed by the EPA in January 1996. The company is currently evaluating the steps it would need to take in order to comply with the proposed new rules. The company will have three years from the date the limits were proposed to comply with the new NOx rules. All of the company's generating facilities are in substantial compliance with the Best Practicable Technology and Best Available Technology regulations issued by the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are administered in Kansas by the KDHE. Additional information with respect to Environmental Matters is discussed in Note 2 of the Notes to Financial Statements. FINANCING The company's ability to issue additional debt is restricted under limitations imposed by the Mortgage and Deed of Trust of the Company. The company's mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless the company's net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than two and one-half times the annual interest charges on, or 10% of the principal amount of, all first mortgage bonds outstanding after giving effect to the proposed issuance. Based on the company's results for the 12 months ended December 31, 1996, approximately $1.0 billion principal amount of additional first mortgage bonds could be issued (7.75% interest rate assumed). KGE bonds may be issued, subject to the restrictions in the preceding paragraph, on the basis of property additions not subject to an unfunded prior lien and on the basis of bonds which have been retired. As of December 31, 1996, the company had approximately $1.4 billion of net bondable property additions not subject to an unfunded prior lien entitling the company to issue up to $950 million principal amount of additional bonds. As of December 31, 1996, $17 million in additional bonds could be issued on the basis of retired bonds. 10 REGULATION AND RATES The company is subject as an operating electric utility to the jurisdiction of the KCC which has general regulatory authority over the company's rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts and various other matters. The company is also subject to the jurisdiction of the FERC and the KCC with respect to the issuance of the company's securities. Additionally, the company is subject to the jurisdiction of the FERC, including jurisdiction as to rates with respect to sales of electricity for resale, and the Nuclear Regulatory Commission as to nuclear plant operations and safety. Additional information with respect to Regulation and Rates is discussed in Notes 1 and 3 of the Notes to Financial Statements. EXECUTIVE OFFICERS OF THE COMPANY Other Offices or Positions Name Age Present Office Held During Past Five Years William B. Moore 44 Chairman of the Board Vice President, Finance - and President (since Western Resources, Inc. June 1995) Richard D. Terrill 42 Secretary, Treasurer and General Counsel Executive officers serve at the pleasure of the Board of Directors. There are no family relationships among any of the officers, nor any arrangements or understandings between any officer and other persons pursuant to which he was appointed as an officer. 11 ITEM 2. PROPERTIES The company owns or leases and operates an electric generation, transmission, and distribution system in Kansas. During the five years ended December 31, 1996, the company's gross property additions totaled $383,081,000 and retirements were $135,730,000. ELECTRIC FACILITIES Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (1) Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 152 2 1967 Gas--Oil 382 Jeffrey Energy Center (20%) (2): Steam Turbines 1 1978 Coal 147 2 1980 Coal 147 3 1983 Coal 141 La Cygne Station (50%) (2): Steam Turbines 1 1973 Coal 343 2 1977 Coal 335 Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 46 2 1954 Gas--Oil 74 3 1956 Gas--Oil 107 4 1959 Gas--Oil 106 Neosho Energy Center: Steam Turbine 3 1954 Gas--Oil 0 (3) Wichita Plant: Diesel Generator 5 1969 Diesel 3 Wolf Creek Generating Station (47%)(2): Nuclear 1 1985 Uranium 547 Total 2,530 (1) Based on MOKAN rating. (2) The company jointly owns Jeffrey Energy Center (20%), La Cygne Station (50%) and Wolf Creek Generating Station (47%). (3) This unit has been "mothballed" for future use. 12 ITEM 3. LEGAL PROCEEDINGS Information on legal proceedings involving the company is set forth in Notes 2, 3, and 9 of Notes to Financial Statements included herein. See also Item 1. Business, Environmental Matters, and Regulation and Rates. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Information required by Item 4 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The company's common stock is owned by Western Resources and is not traded on an established public trading market. ITEM 6. SELECTED FINANCIAL DATA 1996 1995 1994 1993 1992 (Dollars in Thousands) Income Statement Data: Operating revenues . . . . . . . $ 654,570 $ 623,868 $ 619,880 $ 616,997 $ 554,251 Operating expenses . . . . . . . 513,579 477,541 470,869 469,616 424,089 Operating income . . . . . . . . 140,991 146,327 149,011 147,381 130,162 Net income . . . . . . . . . . . 96,274 110,873 104,526 108,103 77,981 Balance Sheet Data: Gross electric plant in service. $3,574,980 $3,427,928 $3,390,406 $3,339,832 $3,293,365 Construction work in progress. . 33,197 40,810 32,874 28,436 29,634 Total assets . . . . . . . . . . 3,318,887 3,203,414 3,237,684 3,187,479 3,279,232 Long-term debt . . . . . . . . . 684,068 684,082 699,992 653,543 871,652 Interest coverage ratio (before income taxes, including AFUDC) . . . . . . . . . . . . 3.28 4.11 4.02 3.58 2.35 Ratio of Earnings to Fixed Charges 2.19 2.58 2.61 2.60 1.89
13 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FINANCIAL CONDITION GENERAL: The company had net income of $96.3 million for 1996 compared to net income of $110.9 million in 1995. The decrease in net income is primarily due to the amortization of the acquisition adjustment as a result of the Merger and the $8.7 million rate reduction implemented on an interim basis on May 23, 1996, and made permanent on January 15, 1997. Abnormally cool summer weather during the third quarter of 1996 compared to 1995 also adversely affected earnings. FORWARD LOOKING INFORMATION: Certain matters discussed in this Form 10-K are "forward-looking statements" intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, litigation, rate and other regulatory matters, pending transactions, liquidity and capital resources, and accounting matters. Actual results in each case could differ materially from those currently anticipated in such statements, by reason of factors such as electric utility restructuring, including ongoing state and federal activities; future economic conditions; legislation; regulation; competition; and other circumstances affecting anticipated rates, revenues and costs. LIQUIDITY AND CAPITAL RESOURCES: The company's liquidity is a function of its ongoing construction and maintenance program designed to improve facilities which provide electric service and meet future customer service requirements. During 1996, construction expenditures for the company's electric system were approximately $66 million and nuclear fuel expenditures were approximately $3 million. It is projected that adequate capacity margins will be maintained without the addition of any major generating facilities for the next five years. The construction program is focused on providing service to new customers and improving present electric facilities. Capital expenditures for 1997 through 1999 are anticipated to be as follows: Electric Nuclear Fuel (Dollars in Thousands) 1997. . . . . . . . . . $55,116 $21,300 1998. . . . . . . . . . 56,761 21,500 1999. . . . . . . . . . 58,471 3,800 These expenditures are estimates prepared for planning purposes and are subject to revisions. Cash provided by operating activities is the primary source for meeting cash requirements. The company anticipates all of its cash requirements for capital expenditures through 1999 will be provided from internally generated funds. 14 The embedded cost of long-term debt excluding the revolving credit facility was 7.3% at December 31, 1996 and 1995. In 1986, the company purchased corporate-owned life insurance policies (COLI) on certain employees. The annual cash outflow for the premiums on these policies was approximately $26 million for 1996, $30 million for 1995 and $26 million for 1994. During 1996, the company increased its borrowings against the accumulated cash surrender values of the policies by $46 million. Total 1996 COLI borrowings amounted to $394 million. The borrowings are expected to produce annual cash inflows, net of expenses, through the remaining life of the policies. Borrowings against the policies will be repaid from death proceeds. On August 2, 1996, Congress passed legislation that will phase out tax benefits associated with certain COLI policies. The legislation had minimal impact on the company's COLI policies as all policies entered into prior to July 1, 1986 were grandfathered under the legislation. See Note 1 for additional information on COLI. The company's short-term financing requirements are satisfied, as needed, through short-term bank loans and borrowings under other lines of credit maintained with banks. Short-term borrowings amounted to $222.3 million at December 31, 1996 and $50 million at December 31. 1995. The company's capital structure at December 31, 1996 and 1995, was 63% common stock equity and 37% long-term debt. RESULTS OF OPERATIONS The following is an explanation of significant variations from prior year results in revenues, operating expenses, other income and deductions, and interest charges. Additional information relating to changes between years is provided in the Notes to Financial Statements. REVENUES The operating revenues of the company are based on sales volumes and rates authorized by the Kansas Corporation Commission (KCC) and the Federal Energy Regulatory Commission (FERC). Rates charged for the sale and delivery of electricity are designed to recover the cost of service and allow investors a fair rate of return. Future electric sales will be affected by weather conditions, the electric rate reduction which was implemented on February 1, 1997, changes in the industry, changes in the regulatory environment, competition from other sources of energy, competing fuel sources, customer conservation efforts, and the overall economy of the company's service area. Electric fuel costs are included in base rates. Therefore, if the company wished to recover an increase in fuel costs, it would have to file a request for recovery in a rate filing with the KCC which could be denied in whole or in part. The company's fuel costs represented 24% and 22% of its total operating expenses for the years ended December 31, 1996 and 1995, respectively. Any increase in fuel costs from the projected average which the company did not recover through rates would reduce the company's earnings. The degree of any such impact would be affected by a variety of factors, however, and thus cannot be predicted. 15 1996 Compared to 1995: Total operating revenues for 1996 of $654.6 million increased five percent from 1995 operating revenues of $623.9 million primarily due to higher wholesale and interchange sales as a result of an increase in customers. Increased residential and commercial sales also contributed to the increase as a result of colder winter and warmer spring temperatures experienced during the first six months of 1996 compared to 1995. The company's service territory experienced a 17% increase in heating degree days during the first quarter and cooling degree days more than doubled during the second quarter of 1996 compared to the same periods in 1995. Partially offsetting this increase was abnormally cool summer weather during the third quarter of 1996 compared to 1995 and the $8.7 million electric rate reduction implemented on an interim basis on May 23, 1996 and made permanent on January 15, 1997. For more information related to electric rate decreases, see Note 3. 1995 Compared to 1994: Total operating revenues for 1995 of $623.9 million increased less than one percent from revenues of $619.9 million for 1994 as a result of increased sales in all retail customer classes. The increase is primarily attributable to a higher demand for air conditioning load during the third quarter of 1995 compared to 1994. The company's service territory experienced a 14% increase in the number of cooling degree days during that quarter, as compared to the third quarter of 1994. OPERATING EXPENSES 1996 Compared to 1995: Total operating expenses for 1996 were $513.6 million compared to $477.5 million for 1995, an increase of over seven percent. The increase is primarily due to a full year of amortization of the acquisition adjustment related to the Merger and increased fuel expense, purchased power, and natural gas purchases for electric generating stations due to Wolf Creek having been taken off-line for its eighth refueling and maintenance outage during the first quarter of 1996. Also contributing to the increases in fuel and purchased power expenses was the increase in net generation due to increased interchange sales. 1995 Compared to 1994: Total operating expenses for 1995 were $477.5 million compared to $470.9 million for 1994, an increase of over one percent. The increase is a result of increased depreciation and amortization expense as a result of the amortization of the acquisition premium attributable to the Merger which began in August 1995 as discussed in Merger Implementation below. OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of taxes, decreased for the twelve months ended December 31, 1996 compared to 1995 primarily as a result of the gain from the sale of utility plant recorded in the first quarter of 1995. Other income and deductions, net of taxes, increased for the twelve months ended December 31, 1995 compared to 1994 as a result of the additional interest expense on increased corporate-owned life insurance (COLI) borrowings. Partially offsetting this increase was the recognition of income from death benefit proceeds under COLI contracts during the fourth quarter of 1995. INTEREST CHARGES: Total interest charges increased 14% for the twelve months ended December 31, 1996 as compared to 1995 due to increased interest expense on higher short-term debt balances. Interest charges decreased 4% in 1995 compared to 1994 due to an increased AFUDC credit in 1995 compared to 1994 and decreased interest charges on long-term debt. 16 MERGER IMPLEMENTATION: In accordance with the KCC merger order, amortization of the acquisition adjustment commenced August 1995. The amortization will amount to approximately $20 million (pre-tax) per year for 40 years. Western Resources and the company (combined companies) are recovering the amortization of the acquisition adjustment through cost savings under a sharing mechanism approved by the KCC. 16 Based on the order issued by the KCC, with regard to the recovery of the acquisition premium, the combined companies must achieve a level of savings on an annual basis (considering sharing provisions) of approximately $27 million in order to recover the entire acquisition premium. On January 15, 1997, the KCC fixed the annual merger savings level at $40 million which provides complete recovery of the acquisition premium amortization expense and a return on the acquisition premium. See Note 3 for further information relating to rate matters and regulation. As Western Resources' management presently expects to continue this level of savings, the amount is expected to be sufficient to allow for the full recovery of the acquisition premium. OTHER INFORMATION INFLATION: Under the ratemaking procedures prescribed by the regulatory commissions to which the company is subject, only the original cost of plant is recoverable in rates charged to customers. Therefore, because of inflation, present and future depreciation provisions are inadequate for purposes of maintaining the purchasing power invested by common shareholders and the related cash flows are inadequate for replacing property. The impact of this ratemaking process on common shareholders is mitigated to the extent depreciable property is financed with debt that can be repaid with dollars of less purchasing power. While the company has experienced relatively low inflation in the recent past, the cumulative effect of inflation on operating costs may require the company to seek regulatory rate relief to recover these higher costs. ENVIRONMENTAL: The company has taken a proactive position with respect to the potential environmental liability associated with former manufactured gas sites and has an agreement with the Kansas Department of Health and Environment to systematically evaluate these sites in Kansas. The company is one of numerous potentially responsible parties at a groundwater contamination site in Wichita, Kansas which is listed by the Environmental Protection Agency (EPA) as a Superfund site. The nitrogen oxides (NOx) and toxic limits, which were not set in the law, were proposed by the EPA in January 1996. The company is currently evaluating the steps it will need to take in order to comply with the proposed new rules. The company will have three years from the date the limits were proposed to comply with the new NOx rules. See Note 2 for more information regarding environmental matters. 17 DECOMMISSIONING: The staff of the SEC has questioned certain current accounting practices used by nuclear electric generating station owners regarding the recognition, measurement, and classification of decommissioning costs for nuclear electric generating stations. In response to these questions, the Financial Accounting Standards Board is expected to issue new accounting standards for closure and removal costs, including decommissioning, in 1997. The company is not able to predict what effect such changes would have on results of operations, financial position, or related regulatory practices until the final issuance of revised accounting guidance, but such effect could be material. Refer to Note 2 for additional information relating to new accounting standards for decommissioning. On August 30, 1996, WCNOC submitted the 1996 Decommissioning Cost Study to the KCC for approval. Approval of this study was received from the KCC on February 28, 1997. Based on the study, the company's share of these decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $624 million during the period 2025 through 2033, or approximately $192 million in 1996 dollars. These costs were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1996 of 29 years. Refer to Note 2 for additional information relating to the 1996 Decommissioning Cost Study. COMPETITION AND ENHANCED BUSINESS OPPORTUNITIES: The electric utility industry in the United States is rapidly evolving from an historically regulated monopolistic market to a dynamic and competitive integrated marketplace. The 1992 Energy Policy Act (Act) began the process of deregulation of the electricity industry by permitting the FERC to order electric utilities to allow third parties to sell electric power to wholesale customers over their transmission systems. As part of the KGE merger, the company agreed to open access of its transmission system for wholesale transactions. During 1996, wholesale electric revenues represented approximately 9% of the company's total electric revenues. Since that time, the wholesale electricity market has become increasingly competitive as companies begin to engage in nationwide power brokerage. In addition, various states including California and New York have taken active steps toward allowing retail customers to purchase electric power from third -party providers. In 1996, the KCC initiated a generic docket to study electric restructuring issues. A retail wheeling task force has been created by the Kansas Legislature to study competitive trends in retail electric services. During the 1997 session of the Kansas Legislature, bills have been introduced to increase competition in the electric industry. Among the matters under consideration is the recovery by utilities of costs in excess of competitive cost levels. There can be no assurance at this time that such costs will be recoverable if open competition is initiated in the electric utility market. Operating in this competitive environment will place pressure on utility profit margins and credit quality. Wholesale and industrial customers may threaten to pursue cogeneration, self-generation, retail wheeling, municipalization or relocation to other service territories in an attempt to obtain reduced energy costs. Increasing competition has resulted in credit rating agencies applying more stringent guidelines when making utility credit rating determinations. See discussion of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) in "Regulatory" below. 18 The company is providing competitive electric rates for industrial expansion projects and economic development projects in an effort to maintain and increase electric load. During 1996, the company lost a major industrial customer to cogeneration resulting in a reduction to pre-tax earnings of $8.6 million annually. This customer's decision to develop its own cogeneration project was based largely on factors unique to the customer, other than energy cost. REGULATORY: On April 24, 1996, FERC issued its final rule on Order No. 888, "Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities". The company does not presently expect the order to have a material effect on its operations in large part because it is already operating in substantially the required manner due to its agreement with the KCC during the KGE merger (See discussion above). On May 23, 1996, the company implemented an $8.7 million electric rate reduction to customers on an interim basis. On October 22, 1996, Western Resources, the KCC Staff, the City of Wichita, and the Citizens Utility Ratepayer Board filed an agreement at the KCC whereby the company's retail electric rates would be reduced, subject to approval by the KCC. This agreement was approved by the KCC on January 15, 1997. Under the agreement, on February 1, 1997, the company's rates were reduced by $36.3 million and the May, 1996 interim reduction became permanent. The company's rates will be reduced by another $10 million effective June 1, 1998, and again on June 1, 1999. Two one-time rebates of $5 million will be credited to the customers of Western Resources in January 1998 and 1999. A portion of these rebates will be credited to the company's customers. The agreement also fixed annual savings from the KGE merger at $40 million. This level of merger savings provides for complete recovery of the acquisition premium amortization expense and a return on the acquisition premium. See Note 3 for additional information regarding rate matters. STRANDED COSTS: The company currently applies accounting standards that recognize the economic effects of rate regulation SFAS 71, and, accordingly, has recorded regulatory assets and liabilities related to its generation, transmission and distribution operations. In the event the company determines that it no longer meets the criteria of SFAS 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that would be material. Criteria that give rise to the discontinuance of SFAS 71 include, (1) increasing competition that restricts the company's ability to establish prices to recover specific costs, and (2) a significant change in the manner in which rates are set by regulators from a cost-based regulation to another form of regulation. The company periodically reviews these criteria to ensure the continuing application of SFAS 71 is appropriate. Based on current evaluation of the various factors and conditions that are expected to impact future cost recovery, the company believes that its net regulatory assets are probable of future recovery. Any regulatory changes that would require the company to discontinue SFAS 71 based upon competitive or other events may significantly impact the valuation of the company's net regulatory assets and its utility plant investments, particularly the Wolf Creek facility. At this time, the effect of competition and the amount of regulatory assets which could be recovered in such an environment cannot be predicted. See discussion of "Competition" above for initiatives taken to restructure the electric industry in Kansas. 19 The term "stranded costs" as it relates to capital intensive utilities has been defined as investment in and carrying costs associated with property, plant and equipment and other regulatory assets in excess of the level which can be recovered in the competitive market in which the utility operates. Regulatory changes, including the introduction of competition, could adversely impact the company's ability to recover its costs in these assets. As of December 31, 1996, the company has recorded regulatory assets which are currently subject to recovery in future rates of approximately $287 million. Of this amount, $165 million represents a receivable for income tax benefits flow-through to customers. The remainder of the regulatory assets represent items that may give rise to stranded costs including debt issuance costs and deferred contract settlement costs. Finally, the company's ability to fully recover its utility plant investments in, and decommissioning cost for, generating facilities, particularly Wolf Creek, may be at risk in a competitive environment. Amounts associated with the company's recovery of environmental remediation costs and long-term fuel contract costs cannot be estimated with any certainty, but also represent items that could give rise to "stranded costs" in a competitive environment. In the event that the company was not allowed to recover its investment in these assets, the accounting impact would be a charge to its results of operations that would be material. 20 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS PAGE Report of Independent Public Accountants 21 Financial Statements: Balance Sheets, December 31, 1996 and 1995 22 Statements of Income for the years ended December 31, 1996, 1995 and 1994 23 Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994 24 Statements of Taxes for the years ended December 31, 1996, 1995 and 1994 25 Statements of Capitalization, December 31, 1996 and 1995 26 Statements of Common Stock Equity for the years ended December 31, 1996, 1995 and 1994 27 Notes to Financial Statements 28 SCHEDULES OMITTED The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented: I, II, III, IV, and V. 21 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Kansas Gas and Electric Company: We have audited the accompanying balance sheets and statements of capitalization of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) as of December 31, 1996 and 1995, and the related statements of income, cash flows, taxes, and common stock equity for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kansas Gas and Electric Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Kansas City, Missouri, January 24, 1997 (February 7, 1997 with respect to Note 13 of the Notes to Financial Statements.) 22 KANSAS GAS AND ELECTRIC COMPANY BALANCE SHEETS (Dollars in Thousands)
December 31, 1996 1995 ASSETS UTILITY PLANT: Electric plant in service (Notes 1 and 11). . . . . . . . $3,574,980 $3,427,928 Less - Accumulated depreciation . . . . . . . . . . . . . 1,062,218 893,728 2,512,762 2,534,200 Construction work in progress . . . . . . . . . . . . . . 33,197 40,810 Nuclear fuel (net). . . . . . . . . . . . . . . . . . . . 38,461 53,942 Net utility plant . . . . . . . . . . . . . . . . . . . 2,584,420 2,628,952 INVESTMENTS AND OTHER PROPERTY: Decommissioning trust (Note 2). . . . . . . . . . . . . . 33,041 25,070 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 9,093 7,885 42,134 32,955 CURRENT ASSETS: Cash and cash equivalents (Note 1). . . . . . . . . . . . 44 53 Accounts receivable and unbilled revenues (net)(Note 1) . 75,671 76,490 Advances to parent company (Note 12). . . . . . . . . . . 250,733 34,948 Fossil fuel, at average cost, . . . . . . . . . . . . . . 13,459 17,522 Materials and supplies, at average cost . . . . . . . . . 30,187 31,458 Prepayments and other current assets. . . . . . . . . . . 16,991 17,128 387,085 177,599 DEFERRED CHARGES AND OTHER ASSETS: Deferred future income taxes (Note 7) . . . . . . . . . . 164,520 208,367 Corporate-owned life insurance (net) (Note 1). . . .. . . 10,341 7,279 Regulatory assets (Note 3). . . . . . . . . . . . . . . . 122,388 146,116 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 7,999 2,146 305,248 363,908 TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $3,318,887 $3,203,414 CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Statements): Common stock equity . . . . . . . . . . . . . . . . . . . $1,182,351 $1,186,077 Long-term debt (net). . . . . . . . . . . . . . . . . . . 684,068 684,082 1,866,419 1,870,159 CURRENT LIABILITIES: Short-term debt (Note 4). . . . . . . . . . . . . . . . . 222,300 50,000 Long-term debt due within one year (Note 5) . . . . . . . - 16,000 Accounts payable. . . . . . . . . . . . . . . . . . . . . 48,819 50,783 Accrued taxes . . . . . . . . . . . . . . . . . . . . . . 35,358 17,766 Accrued interest. . . . . . . . . . . . . . . . . . . . . 9,445 7,903 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,726 6,608 322,648 149,060 DEFERRED CREDITS AND OTHER LIABILITIES: Deferred income taxes (Note 7). . . . . . . . . . . . . . 753,511 800,934 Deferred investment tax credits (Note 7). . . . . . . . . 69,722 72,970 Deferred gain from sale-leaseback (Note 6). . . . . . . . 233,060 242,700 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 73,527 67,591 1,129,820 1,184,195 COMMITMENTS AND CONTINGENCIES (Notes 2 and 8) TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . $3,318,887 $3,203,414 The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
23 KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (Dollars in Thousands)
Year Ended December 31, 1996 1995 1994 OPERATING REVENUES (Notes 1 and 3). . . . . . . . . . . $ 654,570 $ 623,868 $ 619,880 OPERATING EXPENSES: Fuel used for generation: Fossil fuel . . . . . . . . . . . . . . . . . . . . 91,824 80,592 90,383 Nuclear fuel. . . . . . . . . . . . . . . . . . . . 19,962 19,425 13,562 Power purchased . . . . . . . . . . . . . . . . . . . 11,483 4,577 7,144 Other operations. . . . . . . . . . . . . . . . . . . 134,720 117,876 115,060 Maintenance . . . . . . . . . . . . . . . . . . . . . 48,943 48,056 47,988 Depreciation and amortization . . . . . . . . . . . . 96,309 79,679 71,457 Amortization of phase-in revenues . . . . . . . . . . 17,544 17,545 17,544 Taxes (See Statements): Federal income. . . . . . . . . . . . . . . . . . . 36,156 50,513 50,212 State income . . . . . . . . . . . . . . . . . . . 10,455 13,037 12,427 General . . . . . . . . . . . . . . . . . . . . . . 46,183 46,241 45,092 Total operating expenses. . . . . . . . . . . . . 513,579 477,541 470,869 OPERATING INCOME. . . . . . . . . . . . . . . . . . . . 140,991 146,327 149,011 OTHER INCOME AND DEDUCTIONS: Corporate-owned life insurance (net). . . . . . . . . (2,249) (2,668) (5,354) Miscellaneous (net) . . . . . . . . . . . . . . . . . 3,397 4,884 5,079 Income taxes (net) (See Statements) . . . . . . . . . 10,353 11,763 7,290 Total other income and deductions . . . . . . . . 11,501 13,979 7,015 INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . 152,492 160,306 156,026 INTEREST CHARGES: Long-term debt. . . . . . . . . . . . . . . . . . . . 46,304 47,073 47,827 Other . . . . . . . . . . . . . . . . . . . . . . . . 11,758 5,190 5,183 Allowance for borrowed funds used during construction (credit). . . . . . . . . . . . (1,844) (2,830) (1,510) Total interest charges. . . . . . . . . . . . . . 56,218 49,433 51,500 NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 96,274 $ 110,873 $ 104,526 The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
24 KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year Ended December 31, 1996 1995 1994 CASH FLOWS FROM OPERATING ACTIVITIES: Net income. . . . . . . . . . . . . . . . . . . . . . . . $ 96,274 $ 110,873 $ 104,526 Depreciation and amortization . . . . . . . . . . . . . . 96,309 79,679 71,457 Amortization of nuclear fuel. . . . . . . . . . . . . . . 15,685 14,703 10,437 Gain on sales of utility plant (net of tax) . . . . . . . - (951) - Amortization of phase-in revenues . . . . . . . . . . . . 17,544 17,545 17,544 Corporate-owned life insurance. . . . . . . . . . . . . . (29,713) (28,548) (17,246) Amortization of gain from sale-leaseback. . . . . . . . . (9,640) (9,640) (9,640) Changes in working capital items: Accounts receivable and unbilled revenues (net) (Note 1) . . . . . . . . . . . . . . . 819 (8,657) (56,721) Fossil fuel . . . . . . . . . . . . . . . . . . . . . . 4,063 (3,770) (6,158) Accounts payable. . . . . . . . . . . . . . . . . . . . (1,964) 1,690 (2,002) Interest and taxes accrued. . . . . . . . . . . . . . . 19,134 967 4,508 Other . . . . . . . . . . . . . . . . . . . . . . . . . 4,421 (1,980) (922) Changes in other assets and liabilities . . . . . . . . . (9,772) 18,866 14,636 Net cash flows from operating activities. . . . . . . 203,160 190,777 130,419 CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to utility plant. . . . . . . . . . . . . . . . 68,632 93,938 89,880 Sales of utility plant. . . . . . . . . . . . . . . . . . - (1,723) - Corporate-owned life insurance policies . . . . . . . . . 25,647 30,347 26,418 Death proceeds of corporate-owned life insurance. . . . . (9,445) (10,583) - Net cash flows used in investing activities . . . . . 84,834 111,979 116,298 CASH FLOWS FROM FINANCING ACTIVITIES: Short-term debt (net) . . . . . . . . . . . . . . . . . . 172,300 - (105,800) Advances to parent company (net). . . . . . . . . . . . . (215,785) 29,445 128,399 Bonds issued. . . . . . . . . . . . . . . . . . . . . . . - - 160,422 Bonds retired . . . . . . . . . . . . . . . . . . . . . . (16,135) (25) (46,440) Other long-term debt retired. . . . . . . . . . . . . . . - - (67,893) Borrowings against life insurance policies. . . . . . . . 45,978 47,046 42,175 Repayment of borrowings against life insurance policies . (4,693) (5,258) - Revolving credit agreement (net). . . . . . . . . . . . . - - Dividends to parent company . . . . . . . . . . . . . . . (100,000) (150,000) (125,000) Net cash flows (used in) financing activities. . . . . (118,335) (78,792) (14,137) NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . . . (9) 6 (16) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . . . 53 47 63 CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . . . $ 44 $ 53 $ 47 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION CASH PAID FOR: Interest on financing activities (net of amount capitalized) . . . . . . . . . . . . . . . . . . . . $ 78,712 $ 71,808 $ 68,544 Income taxes . . . . . . . . . . . . . . . . . . . . . . 32,100 42,100 28,509 The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
25 KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF TAXES (Dollars in Thousands)
Year Ended December 31, 1996 1995 1994 FEDERAL INCOME TAXES: Payable currently . . . . . . . . . . . . . . . . . $ 31,135 $ 34,661 $ 24,427 Deferred (net). . . . . . . . . . . . . . . . . . . (218) 9,528 23,002 Investment tax credit-Deferral. . . . . . . . . . . - - - -Amortization. . . . . . . . . (3,249) (3,314) (3,208) Total Federal income taxes . . . . . . . . . . . 27,668 40,875 44,221 Less: Federal income taxes applicable to non-operating items . . . . . . . . . . . . . (8,488) (9,638) (5,991) Total Federal income taxes charged to operations. . 36,156 50,513 50,212 STATE INCOME TAXES: Payable currently . . . . . . . . . . . . . . . . . 11,948 13,275 5,574 Deferred (net). . . . . . . . . . . . . . . . . . . (3,358) (2,363) 5,554 Total State income taxes . . . . . . . . . . . . 8,590 10,912 11,128 Less: State income taxes applicable to non-operating items . . . . . . . . . . . . . (1,865) (2,125) (1,299) Total State income taxes charged to operations. . . 10,455 13,037 12,427 GENERAL TAXES: Property. . . . . . . . . . . . . . . . . . . . . . 41,331 40,827 40,104 Payroll and other taxes . . . . . . . . . . . . . . 4,852 5,414 4,988 Total general taxes charged to operations. . . . 46,183 46,241 45,092 TOTAL TAXES CHARGED TO OPERATIONS . . . . . . . . . . $ 92,794 $ 109,791 $ 107,731 The effective income tax rates set forth below are computed by dividing total Federal and State income taxes by the sum of such taxes and net income. The difference between the effective rates and the Federal statutory income tax rates are as follows: Year Ended December 31, 1996 1995 1994 EFFECTIVE INCOME TAX RATE . . . . . . . . . . . . . . 27% 32% 35% Effect of: State income taxes. . . . . . . . . . . . . . . . . (4) (4) (5) Amortization of investment tax credits. . . . . . . 2 2 2 Corporate-owned life insurance. . . . . . . . . . . 7 5 4 Flow through and amortization, net. . . . . . . . . 2 - (1) Other differences . . . . . . . . . . . . . . . . . 1 - - STATUTORY FEDERAL INCOME TAX RATE . . . . . . . . . . 35% 35% 35% The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
26 KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, 1996 1995 COMMON STOCK EQUITY (See Statements): Common stock, without par value, authorized and issued 1,000 shares. . . . . . . . . . . . . . . . . . . . . . . $1,065,634 $1,065,634 Retained earnings . . . . . . . . . . . . . . . . . . . . . 116,717 120,443 Total common stock equity . . . . . . . . . . . . . . . . 1,182,351 63% 1,186,077 63%
LONG-TERM DEBT (Note 5): First Mortgage Bonds: Series Due 1996 1995 5-5/8% 1996 $ - $ 16,000 7.6% 2003 135,000 135,000 6-1/2% 2005 65,000 65,000 6.20% 2006 100,000 100,000 300,000 316,000 Pollution Control Bonds: 5.10% 2023 13,822 13,957 Variable (1) 2027 21,940 21,940 7.0% 2031 327,500 327,500 Variable (2) 2032 14,500 14,500 Variable (3) 2032 10,000 10,000 387,762 387,897 Total bonds. . . . . . . . . . . . . . . . . . . . . . 687,762 703,897 Less: Unamortized premium and discount (net). . . . . . . . . . 3,694 3,815 Long-term debt due within one year. . . . . . . . . . . . - 16,000 Total long-term debt . . . . . . . . . . . . . . . . . 684,068 37% 684,082 37% TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . $1,866,419 100% $1,870,159 100% Market-Adjusted Tax Exempt Securities (MATES). The interest rate is reset periodically via an auction process. Rates at December 31, 1996: (1) 3.55%, (2) 3.60%, and (3) 3.52%. The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
27 KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF COMMON STOCK EQUITY (Dollars in Thousands)
Common Retained Stock Earnings BALANCE DECEMBER 31, 1993, 1,000 shares. . . . . . . $1,065,634 $ 180,044 Net income . . . . . . . . . . . . . . . . . . . . . 104,526 Dividend to parent company . . . . . . . . . . . . . (125,000) BALANCE DECEMBER 31, 1994, 1,000 shares. . . . . . . 1,065,634 159,570 Net Income . . . . . . . . . . . . . . . . . . . . . 110,873 Dividend to parent company . . . . . . . . . . . . . (150,000) Balance December 30, 1995, 1,000 shares. . . . . . . 1,065,634 120,443 Net Income . . . . . . . . . . . . . . . . . . . . . 96,274 Dividend to parent company . . . . . . . . . . . . . (100,000) Balance December 31, 1996, 1,000 shares. . . . . . . $1,065,634 $ 116,717 The NOTES TO FINANCIAL STATEMENTS are an integral part of these statements.
28 KANSAS GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General: Kansas Gas and Electric Company (the company, KGE) is a rate- regulated electric utility and wholly-owned subsidiary of Western Resources, Inc. (Western Resources). The company is engaged principally in the production, purchase, transmission, distribution, and sale of electricity. The company serves approximately 277,000 electric customers in southeastern Kansas. At December 31, 1996, the company had no employees. All employees are provided by the company's parent, Western Resources which allocates costs related to the employees to the company. The company owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). The company records its proportionate share of all transactions of WCNOC as it does other jointly-owned facilities. The company prepares its financial statements in conformity with generally accepted accounting principles as applied to regulated public utilities. The accounting and rates of the Company are subject to requirements of the Kansas Corporation Commission (KCC) and the Federal Energy Regulatory Commission (FERC). The financial statements require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, to disclose contingent assets and liabilities at the balance sheet date, and to report amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The company currently applies accounting standards that recognize the economic effects of rate regulation Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation", (SFAS 71) and, accordingly, has recorded regulatory assets and liabilities related to its generation, transmission and distribution operations. In 1996, the KCC initiated a generic docket to study electric restructuring issues. A retail wheeling task force has been created by the Kansas Legislature to study competitive trends in retail electric services. During the 1997 session of the Kansas Legislature, bills have been introduced to increase competition in the electric industry. Among the matters under consideration is the recovery by utilities of costs in excess of competitive cost levels. There can be no assurance at this time that such costs will be recoverable if open competition is initiated in the electric utility market. In the event the company determines that it no longer meets the criteria for SFAS 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that would be material. Criteria that give rise to the discontinuance of SFAS 71 include, (1) increasing competition that restricts the company's ability to establish prices to recover specific costs, and (2) a significant change in the manner in which rates are set by regulators from a cost-based regulation to another form of regulation. The company periodically reviews these criteria to ensure the continuing application of SFAS 71 is appropriate. Based on current evaluation of the various factors and conditions that are expected to impact future cost recovery, the company believes that its net regulatory assets are probable of future recovery. Any regulatory changes that would require the company to discontinue SFAS 71 based upon competitive or other events may significantly impact the valuation of the company's net regulatory assets and its utility plant investments, particularly the Wolf Creek facility. At this time, the effect of competition and the amount of regulatory assets which could be recovered in such an environment cannot be predicted. See Note 3 for further discussion on regulatory assets. 29 In January, 1996, the company adopted Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". This Statement imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. Based on the current regulatory structure in which the company operates, the adoption of this standard did not have a material impact on the financial position or results of operations of the company. This conclusion may change in the future as competitive factors influence wholesale or retail pricing in the electric industry. Utility Plant: Utility plant is stated at cost. For constructed plant, cost includes contracted services, direct labor and materials, indirect charges for engineering, supervision, general and administrative costs, and an allowance for funds used during construction (AFUDC). The AFUDC rate was 5.71% for 1996, 6.39% for 1995, and 4.07% for 1994. The cost of additions to utility plant and replacement units of property is capitalized. Maintenance costs and replacement of minor items of property are charged to expense as incurred. When units of depreciable property are retired, they are removed from the plant accounts and the original cost plus removal charges less salvage are charged to accumulated depreciation. In accordance with regulatory decisions made by the KCC, amortization of the acquisition premium of approximately $801 million resulting from the KGE purchase began in August of 1995. The premium is being amortized over 40 years and has been classified as electric plant in service. Accumulated amortization through December 31, 1996 totaled $27.5 million. See Note 3 for further information concerning the amortization of this premium. Depreciation: Depreciation is provided on the straight-line method based on estimated useful lives of property. Composite provisions for book depreciation approximated 2.81% during 1996, 2.72% during 1995, and 2.7% during 1994 of the average original cost of depreciable property. In the past, the methods and rates have been determined by depreciation studies and approved by the various regulatory bodies. The company periodically evaluates its depreciation rates considering the past and expected future experience in the operation of its facilities. Environmental Remediation: Effective January 1, 1997, the company adopted the provisions of Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities". This statement provides authoritative guidance for recognition, measurement, display, and disclosure of environmental remediation liabilities in financial statements. The company is currently evaluating and in the process of estimating the potential liability associated with environmental remediation. Management does not expect the amount to be significant to the company's results of operations as the company will seek recovery of these costs through rates as has been permitted by the KCC in the case of another Kansas utility. Additionally, the adoption of this statement is not expected to have a material impact on the company's financial position. To the extent that such remediation costs are not recovered through rates, the costs may be material to the company's operating results, depending on the degree of remediation required and number of years over which the remediation must be completed. 30 Cash and Cash Equivalents: For purposes of the Statements of Cash Flows, the company considers highly liquid collateralized debt instruments purchased with a maturity of three months or less to be cash equivalents. Income Taxes: The company accounts for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" (SFAS 109). Under SFAS 109, deferred tax assets and liabilities are recognized based on temporary differences in amounts recorded for financial reporting purposes and their respective tax bases. Investment tax credits previously deferred are being amortized to income over the life of the property which gave rise to the credits (See Note 7). Revenues: Operating revenues include amounts actually billed for services rendered and an accrual of estimated unbilled revenues. Unbilled revenues represent the estimated amount customers will be billed for service provided from the time meters were last read to the end of the accounting period. Unbilled revenues of $23.5 million and $21.8 million are recorded as a component of accounts receivable and unbilled revenue (net) on the balance sheets as of December 31, 1996 and 1995, respectively. The company's recorded reserves for doubtful accounts receivable totaled $1.9 million and $2.7 million at December 31, 1996 and 1995, respectively. Debt Issuance and Reacquisition Expense: Debt premium, discount and issuance expenses are amortized over the life of each issue. Under regulatory procedures, debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt. See Note 3 for more information regarding regulatory assets. Fuel Costs: The cost of nuclear fuel in process of refinement, conversion, enrichment, and fabrication is recorded as an asset at original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor at December 31, 1996 and 1995, was $25.3 and $28.5 million, respectively. Cash Surrender Value of Life Insurance Contracts: The following amounts related to corporate-owned life insurance contracts (COLI) are recorded in Corporate-owned Life Insurance (net) on the balance sheets: 1996 1995 (Dollars in Millions) Cash surrender value of contracts.(1). $404.6 $360.3 Borrowings against contracts . . . . . (394.3) (353.0) COLI (net) . . . . . . . . . . . . $ 10.3 $ 7.3 (1) Cash surrender value of contracts as presented represents the value of the policies as of the end of the respective policy years and not as of December 31, 1996 and 1995. Income is recorded for increases in cash surrender value and net death proceeds. Interest expense is recognized for COLI borrowings. The net income generated from COLI contracts, including the tax benefit of the interest deductions and premium expenses, are recorded as Corporate-owned Life Insurance (net) on the Statements of Income. The income from increases in cash surrender value and net death proceeds was $25.4 million for 1996, $22.7 million for 1995, and $15.6 million for 1994. The interest expense deduction taken was $27.6 million for 1996, $25.4 million for 1995, and $21.0 million for 1994. 31 On August 2, 1996, Congress passed legislation that will phase out tax benefits associated with certain COLI policies. The legislation had minimal impact on the company's COLI policies as all policies entered into prior to July 1, 1986 were grandfathered under the legislation. Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation. 2. COMMITMENTS AND CONTINGENCIES Manufactured Gas Sites: The company has been associated with three former manufactured gas sites which may contain coal tar and other potentially harmful materials. The company and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement governing all future work at the three sites. The terms of the consent agreement will allow the company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analyses. The prioritized sites will be investigated over a ten year period. The agreement will allow the company to set mutual objectives with the KDHE in order to expedite effective response activities and to control costs and environmental impact. The costs incurred for site investigation and risk assessment in 1996 and 1995 were minimal. To the extent that such remediation costs are not recovered through rates, the costs could be material to the company's financial position or results of operations depending on the degree of remediation and number of years over which the remediation must be completed. Decommissioning: The company accrues decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund. On August 30, 1996, WCNOC submitted the 1996 Decommissioning Cost Study to the KCC for approval. Approval of this study was received from the KCC on February 28, 1997. Based on the study, the company's share of these decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $624 million during the period 2025 through 2033, or approximately $192 million in 1996 dollars. These costs were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1996 of 29 years. Decommissioning costs are currently being charged to operating expenses in accordance with the prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated $3.7 million in 1996 and will increase annually to $5.6 million in 2024. These expenses are deposited in an external trust fund. The average after tax expected return on trust assets is 5.7%. Approval of this funding schedule is still pending with the KCC. 32 The company's investment in the decommissioning fund, including reinvested earnings approximated $33.0 million and $25.1 million at December 31, 1996 and December 31, 1995, respectively. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability. These amounts are reflected in Investments and Other Property, Decommissioning trust, and the related liability is included in Deferred Credits and Other Liabilities, Other, on the Balance Sheets. The staff of the SEC has questioned certain current accounting practices used by nuclear electric generating station owners regarding the recognition, measurement, and classification of decommissioning costs for nuclear electric generating stations. In response to these questions, the Financial Accounting Standards Board is expected to issue new accounting standards for removal costs, including decommissioning, in 1997. If current electric utility industry accounting practices for such decommissioning costs are changed: (1) annual decommissioning expenses could increase, (2) the estimated present value of decommissioning costs could be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. When revised accounting guidance is issued, the company will also have to evaluate its effect on accounting for removal costs of other long-lived assets. The company is not able to predict what effect such changes would have on results of operations, financial position, or related regulatory practices until the final issuance of revised accounting guidance, but such effect could be material. The company carries premature decommissioning insurance which has several restrictions. One of these is that it can only be used if Wolf Creek incurs an accident exceeding $500 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor station site in accordance with a plan approved by the NRC, and to pay for on-site property damages. This decommissioning insurance will only be available if the insurance funds are not needed to implement the NRC-approved plan for stabilization and decontamination. Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $8.9 billion for a single nuclear incident. If this liability limitation is insufficient, the U.S. Congress will consider taking whatever action is necessary to compensate the public for valid claims. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million and the balance is provided by an assessment plan mandated by the NRC. Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $79.3 million ($37.3 million, company's share) in the event there is a major nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million ($4.7 million, company's share) in retrospective assessments per incident, per year. The Owners carry decontamination liability, premature decommissioning liability, and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion, company's share). This insurance is provided by a combination of "nuclear insurance pools" ($500 million) and Nuclear Electric Insurance Limited (NEIL) ($2.3 billion). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. The company's share of any remaining proceeds can be used 33 for property damage or premature decommissioning costs up to $1.3 billion (company's share). Premature decommissioning insurance cost recovery is the excess of funds previously collected for decommissioning (as discussed under "Decommissioning"). The Owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves, and other NEIL resources, the company may be subject to retrospective assessments under the current policies of approximately $8 million per year. Although the company maintains various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, the company's insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on the company's financial condition and results of operations. Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in certain emissions. To meet the monitoring and reporting requirements under the acid rain program, the company has installed continuous monitoring and reporting equipment at a total cost of approximately $2.3 million as of December 31, 1996. The company does not expect material expenditures to be needed to meet Phase II sulfur dioxide requirements. The nitrogen oxides (NOx) and toxic limits, which were not set in the law, were proposed by the EPA in January 1996. The company is currently evaluating the steps it would need to take in order to comply with the proposed new rules. The company will have three years from the date the limits were proposed to comply with the new NOx rules. Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the company has entered into various commitments to obtain nuclear fuel and coal. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1996, WCNOC's nuclear fuel commitments (company's share) were approximately $15.4 million for uranium concentrates expiring at various times through 2001, $59.4 million for enrichment expiring at various times through 2003, and $70.3 million for fabrication through 2025. At December 31, 1996, the company's coal contract commitments in 1996 dollars under the remaining terms of the contracts were approximately $671 million. The largest coal contract expires in 2020, with the remaining coal contracts expiring at various times through 2013. Energy Act: As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment decontamination and decommissioning fund. The company's portion of the assessment for Wolf Creek is approximately $7 million, payable over 15 years. Management expects such costs to be recovered through the ratemaking process. 3. RATE MATTERS AND REGULATION Utility expenses and credits recognized as regulatory assets and liabilities on the Consolidated Balance Sheets are recognized in income as the related amounts are included in service rates and recovered from or refunded 34 to customers in utility revenues. The company expects to recover the following regulatory assets in rates: December 31, 1996 1995 (Dollars in Thousands) Coal contract settlement costs $ 11,655 $ 14,612 Deferred plant costs 31,272 31,539 Phase-in revenues 26,317 43,861 Debt issuance costs (See Note 1 and 6) 45,989 49,279 Other regulatory assets 7,155 6,825 Total regulatory assets $122,388 $146,116 Coal Contract Settlements: In March 1990, the KCC issued an order allowing the company to defer its share of a 1989 coal contract settlement with the Pittsburg and Midway Coal Mining Company amounting to $22.5 million. This amount was recorded as a deferred charge and is included in Deferred Charges and Other Assets, Regulatory Assets, on the balance sheet. The settlement resulted in the termination of a long-term coal contract. The KCC permitted the company to recover this settlement as follows: 76% of the settlement plus a return over the remaining term of the terminated contract (through 2002) and 24% to be amortized to expense with a deferred return equivalent to the carrying cost of the asset. Deferred Plant Costs: In 1986, the company recognized the effects of Wolf Creek related disallowances in accordance with Statement of Financial Accounting Standard No. 90 "Regulated Enterprises - Accounting for Abandonments and Disallowances of Plant Costs". Phase-in Revenues: In 1988, the KCC ordered the accrual of phase-in revenues to be discontinued effective December 31, 1988. The company began amortizing the phase-in revenue asset on a straight-line basis over 9-1/2 years beginning January 1, 1989. At December 31, 1996, approximately $26 million of deferred phase-in revenues remain to be recovered. KCC Rate Proceedings: On August 17, 1995, the company filed with the KCC a request to more rapidly recover its investment in its assets of Wolf Creek over the next seven years by increasing depreciation by $50 million each year and reduce annual depreciation expense by approximately $3 million for electric transmission, distribution and certain generating plant assets to reflect the useful lives of these properties more accurately. The company sought to reduce electric rates for its customers by approximately $8.7 million annually in each of the seven years of accelerated Wolf Creek depreciation. On May 23, 1996, the company implemented an $8.7 million electric rate reduction on an interim basis. On October 22, 1996, Western Resources, the company, the KCC Staff, the City of Wichita, and the Citizens Utility Ratepayer Board filed an agreement with the KCC whereby the company's retail electric rates would be reduced, subject to approval by the KCC. This agreement was approved on January 15, 1997. Under the agreement, on February 1, 1997, the company's rates were reduced by $36.3 million, and in addition, the May 1996 interim reduction became permanent. The company's rates will be reduced by another $10 million effective June 1, 1998, and again on June 1, 1999. Two one-time rebates of $5 million will be credited to customers of Western Resources in January 1998 and 1999. A portion of these rebates will be credited to the company's customers. The agreement also fixed annual savings from the 1992 merger with Western Resources at $40 million. This level of merger savings provides for complete recovery of and a return on the acquisition premium. 35 4. SHORT-TERM BORROWINGS The company's short-term financing requirements are satisfied through short-term bank loans and uncommitted loan participation agreements. The company has arrangements with certain banks to provide unsecured short-term lines of credit on a committed basis totaling $200 million. The agreements provide the company with the ability to borrow at different market-based interest rates. The company pays commitment or facility fees in support of these lines of credit. Under the terms of the agreements, the company is required, among other restrictions, to maintain a total debt to total capitalization ratio of not greater than 65% at all times. The unused portion of these lines of credit are used to provide support for commercial paper. Information regarding the company's short-term borrowings, comprised of borrowings under the credit agreements and bank loans, is as follows: Year ended December 31, 1996 1995 1994 (Dollars in Thousands) Borrowings outstanding at year end: Lines of credit $200,000 $ - $ - Bank loans 22,300 50,000 50,000 Total $222,300 $ 50,000 $ 50,000 Weighted average interest rate on debt outstanding at year end (including fees) 5.93% 6.03% 6.26% Weighted average short-term debt outstanding during the year $147,556 $ 32,296 $ 47,566 Weighted daily average interest rates during the year (including fees) 5.83% 6.10% 4.50% 5. LONG-TERM DEBT The amount of KGE's first mortgage bonds authorized by the KGE Mortgage and Deed of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion. Amounts of additional bonds which may be issued are subject to property, earnings, and certain restrictive provisions of the Mortgage. Electric plant is subject to the lien of the Mortgage except for transportation equipment. Debt discount and expenses are being amortized over the remaining lives of each issue. The improvement and maintenance fund requirements for certain first mortgage bond series can be met by bonding additional property. With the retirement of certain Company pollution control series bonds, there are no longer any bond sinking fund requirements. No bonds will mature during 1997. 36 6. SALE-LEASEBACK OF LA CYGNE 2 In 1987, the company sold and leased back its 50% undivided interest in the La Cygne 2 generating unit. The La Cygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. The company remains responsible for its share of operation and maintenance costs and other related operating costs of La Cygne 2. The lease is an operating lease for financial reporting purposes. As permitted under the La Cygne 2 lease agreement, the company in 1992 requested the Trustee Lessor to refinance $341.1 million of secured facility bonds of the Trustee and owner of La Cygne 2. The transaction was requested to reduce recurring future net lease expense. In connection with the refinancing on September 29, 1992, a one-time payment of approximately $27 million was made by the company which has been deferred and is being amortized over the remaining life of the lease and included in operating expense as part of the future lease expense. At December 31, 1996, approximately $22.5 million of this deferral remained in Deferred Charges and Other Assets, Regulatory Assets, on the balance sheet. Future minimum annual lease payments required under the La Cygne 2 lease agreement are approximately $34.6 million for each year through 2001 and $611 million over the remainder of the lease. The gain realized at the date of the sale of La Cygne 2 has been deferred for financial reporting purposes, and is being amortized ($9.7 million per year) over the initial lease term in proportion to the related lease expense. The company's lease expense, net of amortization of the deferred gain and a one-time payment, was approximately $22.5 million for 1996, 1995, and 1994. 37 7. INCOME TAXES Under SFAS 109, temporary differences gave rise to deferred tax assets and deferred tax liabilities at December 31, 1996 and 1995, respectively, as follows: 1996 1995 (Dollars in Thousands) Deferred Tax Assets: Deferred gain on sale-leaseback. . . . . $ 99,466 $ 105,007 Alternative minimum tax carry forwards . 250 18,740 Other. . . . . . . . . . . . . . . . . . 11,246 10,870 Total Deferred Tax Assets. . . . . . . $ 110,962 $ 134,617 Deferred Tax Liabilities: Accelerated depreciation & other . . . . $ 363,647 $ 375,079 Acquisition premium. . . . . . . . . . . 306,662 314,933 Deferred future income taxes . . . . . . 164,520 208,367 Other. . . . . . . . . . . . . . . . . . 29,644 37,172 Total Deferred Tax Liabilities . . . . $ 864,473 $ 935,551 Accumulated Deferred Income Taxes, Net $ 753,511 $ 800,934 In accordance with various rate orders received from the KCC, the company has not yet collected through rates the amounts necessary to pay a significant portion of the net deferred income tax liabilities. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers, it has recorded a deferred asset for these amounts. These assets are also a temporary difference for which deferred income tax liabilities have been provided. 8. LEGAL PROCEEDINGS The company is involved in various legal and environmental proceedings. Management believes that adequate provision has been made within the financial statements for these matters and accordingly believes their ultimate dispositions will not have a material adverse effect upon the financial position or results of operations of the company. 9. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in Statement of Financial Accounting Standards No. 107 "Disclosures About Fair Value of Financial Instruments": Cash and cash equivalents, short-term borrowings and variable-rate debt are carried at cost which approximates fair value. The decommissioning trust is recorded at fair value and is based on the quoted market prices at December 31, 1996 and 1995. The fair value of long-term debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. 38 The estimated fair values of the company's financial instruments are as follows: Carrying Value Fair Value December 31, 1996 1995 1996 1995 (Dollars in Thousands) Decommissioning trust. . . $ 33,041 $ 25,070 $ 33,041 $ 25,070 Fixed-rate debt. . . . . . 641,322 657,457 665,300 675,471 The recorded amount of accounts receivable and other current financial instruments approximate fair value. The fair value estimates presented herein are based on information available as of December 31, 1996 and 1995. These fair value estimates have not been comprehensively revalued for the purpose of these financial statements since that date, and current estimates of fair value may differ significantly from the amounts presented herein. Because the company's operations are regulated, the company believes that any gains or losses related to the retirement of debt would not have a material effect on the company's financial position or results of operations. 10. JOINT OWNERSHIP OF UTILITY PLANTS Company's Ownership at December 31, 1996 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 160,541 $ 105,043 343 50 Jeffrey 1 (b) Jul 1978 69,043 27,962 147 20 Jeffrey 2 (b) May 1980 67,896 28,125 147 20 Jeffrey 3 (b) May 1983 95,844 38,487 141 20 Wolf Creek (c) Sep 1985 1,382,000 369,182 547 47 (a) Jointly owned with Kansas City Power & Light Company (KCPL) (b) Jointly owned with Western Resources and UtiliCorp United Inc. (c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc. Amounts and capacity represent the company's share. The company's share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in La Cygne 2 (representing 335 MW capacity) sold and leased back to the company in 1987, are included in operating expenses on the Statements of Income. The company's share of other transactions associated with the plants is included in the appropriate classification in the company's financial statements. 39 11. QUARTERLY FINANCIAL STATISTICS (Unaudited) The amounts in the table are unaudited but, in the opinion of management, contain all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results of such periods. The business of the company is seasonal in nature and, in the opinion of management, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations. 1996 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. (Dollars in Thousands) Operating revenues. . . . . $153,300 $193,198 $163,038 $145,034 Operating income. . . . . . 35,066 49,432 27,439 29,054 Net income. . . . . . . . . 22,585 40,736 17,253 15,700 1995 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr. (Dollars in Thousands) Operating revenues. . . . . $138,182 $202,382 $144,747 $138,557 Operating income. . . . . . 25,021 61,960 30,779 28,567 Net income. . . . . . . . . 21,598 51,836 19,567 17,872 12. RELATED PARTY TRANSACTIONS The cash management function, including cash receipts and disbursements, for the company is performed by Western Resources. An intercompany account is used to record net receipts and disbursements handled by Western Resources. The net amount advanced by the company to Western Resources approximated $251 million and $35 million at December 31, 1996 and 1995, respectively. These amounts are recorded as advances to parent company in Current Assets on the balance sheet. Certain operating expenses have been allocated to the company from Western Resources. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers, and/or other appropriate allocators. Management believes such allocation procedures are reasonable. During 1996, the company declared a dividend to Western Resources of $100 million. 13. WESTERN RESOURCES AND KANSAS CITY POWER & LIGHT COMPANY MERGER AGREEMENT On February 7, 1997, KCPL and the Western Resources entered into an agreement whereby KCPL would be merged with and into Western Resources (KCPL Merger). The merger agreement provides for a tax-free, stock-for-stock transaction valued at approximately $2 billion. Under the terms of the agreement, KCPL shareholders will receive $32 of Western Resources common stock per KCPL share, subject to an exchange ratio collar of not less than 0.917 to no more than 1.100 common shares. Consummation of the KCPL Merger is subject to customary conditions including obtaining the approval of KCPL's and the Western Resources' shareholders and various regulatory agencies. Western Resources expects to be able to close the KCPL Merger in the first half of 1998. 40 KCPL is a public utility company engaged in the generation, transmission, distribution, and sale of electricity to approximately 430,000 customers in western Missouri and eastern Kansas. KCPL, Western Resources, and the company have joint interests in certain electric generating assets, including Wolf Creek. 41 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There were no disagreements with accountants on accounting and financial disclosure. 42 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Western Resources, Inc. owns 100% of the Company's outstanding common stock. A Director Business Experience Since 1991 and Other Continuously Name Age Directorships Other Than The Company Since William B. 44 Chairman of the Board and President 1995 Moore (since June 1995), and prior to that Vice President, Finance, Western Resources, Inc. Directorships Intrust Bank Anderson E. 63 President, Jackson Mortuary, 1994 Jackson Wichita, Kansas Directorships The National Business League Donald A. 63 Retired President and Chairman (Emeritus), 1992(b) Johnston Maupintour, Inc. Lawrence, Kansas, (a) Consultant - Commerce Bank, Lawrence, Kansas (since July 1996) Directorships Commerce Bank, Lawrence, Kansas Steven L. 51 Executive Vice President and Chief 1992 Kitchen Financial Officer, Western Resources, Inc. Directorships Central National Bank Marilyn B. 47 President Wichita, NationsBank N.A. 1994 Pauly (Midwest), Wichita, Kansas (since (a) October 1993) and prior to that Executive Vice President, Bank IV, N.A., Wichita, Kansas Directorships Farmers Mutual Alliance Insurance Company Bank IV, Community Development Corporation NationsBank N.A. (Midwest) 43 Richard D. 63 President, Range Oil Company 1993 Smith Directorships NationsBank N.A. (Midwest), (Advisory) HCA Wesley Medical Center, Wichita, Kansas (a) Member of the Audit Committee of which Mr. Johnston is Chairman. The Audit Committee has responsibility for the investigation and review of the financial affairs of the Company and its relations with independent accountants. (b) Mr. Johnston was a director of the former Kansas Gas and Electric Company since 1980. Outside Directors are paid $3,750 per quarter retainer and are paid an attendance fee of $600 for Directors' meetings ($300 if attending by phone). A committee attendance fee of $800 is paid to the outside Director Audit Committee Chairman, and $500 to other outside Committee members. All outside Directors are reimbursed mileage and expenses while attending Directors' and Committee Meetings. During 1996, the Board of Directors met four times and the Audit Committee met once. Each director attended at least 75% of the total number of Board and Committee meetings held while he/she served as a director or a member of the committee. Other information required by Item 10 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. ITEM 11. EXECUTIVE COMPENSATION Information required by Item 11 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required by Item 12 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information required by Item 13 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. 44 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K The following financial statements are included herein under Item 8. FINANCIAL STATEMENTS Balance Sheets, December 31, 1996 and 1995 Statements of Income for the year ended December 31, 1996, 1995 and 1994 Statements of Cash Flows for the year ended December 31, 1996, 1995 and 1994 Statements of Taxes for the year ended December 31, 1996, 1995 and 1994 Statements of Capitalization, December 31, 1996 and 1995 Statements of Common Stock Equity for the year ended December 31, 1996 Notes to Financial Statements REPORTS ON FORM 8-K None 45 EXHIBIT INDEX All exhibits marked "I" are incorporated herein by reference. Description 2(a) Agreement and Plan of Merger (Filed as Exhibit 2 to Form 10-K I for the year ended December 31, 1990, File No. 1-7324) 2(b) Amendment No. 1 to Agreement and Plan of Merger (Filed as I Exhibit 2 to Form 10-K for the year ended December 31, 1990, File No. 1-7324) 3(a) Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K I for the year ended December 31, 1992, File No. 1-7324) 3(b) Certificate of Merger of Kansas Gas and Electric Company into I KCA Corporation (Filed as Exhibit 3(b) to Form 10-K for the year ended December 31, 1992, File No. 1-7324) 3(c) By-laws as amended (Filed as Exhibit 3(c) Form 10-K I for the year ended December 31, 1992, File No. 1-7324) 4(c) Mortgage and Deed of Trust, dated as of April 1, 1940 to I Guaranty Trust Company of New York (now Morgan Guaranty Trust Company of New York) and Henry A. Theis (to whom W. A. Spooner is successor), Trustees, as supplemented by thirty-eight Supplemental Indentures, dated as of June 1, 1942, March 1, 1948, December 1, 1949, June 1, 1952, October 1, 1953, March 1, 1955, February 1, 1956, January 1, 1961, May 1, 1966, March 1, 1970, May 1, 1971, March 1, 1972, May 31, 1973, July 1, 1975, December 1, 1975, September 1, 1976, March 1, 1977, May 1, 1977, August 1, 1977, March 15, 1978, January 1, 1979, April 1, 1980, July 1, 1980, August 1, 1980, June 1, 1981, December 1, 1981, May 1, 1982, March 15, 1984, September 1, 1984 (Twenty-ninth and Thirtieth), February 1, 1985, April 15, 1986, June 1, 1991 March 31, 1992, December 17, 1992, August 24, 1993, January 15, 1994 and March 1, 1994, (Filed, respectively, as Exhibit A-1 to Form U-1, File No. 70-23; Exhibits 7(b) and 7(c), File No. 2-7405; Exhibit 7(d), File No. 2-8242; Exhibit 4(c), File No. 2-9626; Exhibit 4(c), File No. 2-10465; Exhibit 4(c), File No. 2-12228; Exhibit 4(c), File No. 2-15851; Exhibit 2(b)-1, File No. 2-24680; Exhibit 2(c), File No. 2-36170; Exhibits 2(c) and 2(d), File No. 2-39975; Exhibit 2(d), File No. 2-43053; Exhibit 4(c)2 to Form 10-K, for December 31, 1989, File No. 1-7324; Exhibit 2(c), File No. 2-53765; Exhibit 2(e), File No. 2-55488; Exhibit 2(c), File No. 2-57013; Exhibit 2(c), File No. 2-58180; Exhibit 4(c)3 to Form 10-K for December 31, 1989, File No. 1-7324; Exhibit 2(e), File No. 2-60089; Exhibit 2(c), File No. 2-60777; Exhibit 2(g), File No. 2-64521; Exhibit 2(h), File No. 2-66758; Exhibits 2(d) and 2(e), File No. 2-69620; Exhibits 4(d) and 4(e), File No. 2-75634; Exhibit 4(d), File No. 2-78944; Exhibit 4(d), File No. 2-87532; Exhibits 4(c)4, 4(c)5 and 4(c)6 to Form 10-K for December 31, 1989, File No. 1-7324; Exhibits 4(c)2 and 4(c)3 to Form 10-K for 46 Description December 31, 1992, File No. 1-7324; Exhibit 4(b) to Form S-3, File No. 33-50075; Exhibits 4(c)2 and 4(c)3 to Form 10-K for December 31, 1993, File No. 1-7324; Exhibit 4(c)2 to Form 10-K for December 31, 1994, File No. 1-7324) Instruments defining the rights of holders of other long-term debt not required to be filed as exhibits will be furnished to the Commission upon request. 10(a) La Cygne 2 Lease (Filed as Exhibit 10(a) to Form 10-K for the year I ended December 31, 1988, File No. 1-7324) 10(a) Amendment No. 3 to La Cygne 2 Lease Agreement dated as of September I 29, 1992 (Filed as Exhibit 10(b)1 to Form 10-K for the year ended December 31, 1992, File No. 1-7324) 10(b) Outside Directors' Deferred Compensation Plan (Filed as Exhibit I 10(c) to the Form 10-K for the year ended December 31, 1993, File No. 1-7324) 12 Computation of Ratio of Consolidated Earnings to Fixed Charges (Filed electronically) 23 Consent of Independent Public Accountants, Arthur Andersen LLP (Filed electronically) 27 Financial Data Schedule (Filed electronically) 47 SIGNATURE Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. KANSAS GAS AND ELECTRIC COMPANY March 27, 1997 By /s/ William B. Moore William B. Moore, Chairman of the Board and President 48 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: Signature Title Date /s/ WILLIAM B. MOORE Chairman of the Board and (William B. Moore) President (Principal Executive March 27, 1997 Officer) Secretary, Treasurer and General /s/ RICHARD D. TERRILL Counsel (Principal Financial March 27, 1997 (Richard D. Terrill) and Accounting Officer) /s/ ANDERSON E. JACKSON (Anderson E. Jackson) /s/ DONALD A. JOHNSTON (Donald A. Johnston) /s/ S. L. KITCHEN Directors March 27, 1997 (S. L. Kitchen) /s/ MARILYN B. PAULY (Marilyn B. Pauly) /s/ RICHARD D. SMITH (Richard D. Smith)

Exhibit 12 KANSAS GAS AND ELECTRIC COMPANY Computations of Ratio of Earnings to Fixed Charges (Dollars in Thousands)
1996 1995 1994 Net Income. . . . . . . . . . . . . $ 96,274 $110,873 $104,526 Taxes on Income . . . . . . . . . . 36,258 51,787 55,349 Net Income Plus Taxes. . . . . 132,532 162,660 159,875 Fixed Charges: Interest on Long-Term Debt. . . . 46,304 47,073 47,827 Interest on Other Indebtedness. . 11,758 5,190 5,183 Interest on Corporate-owned Life Insurance Borrowings . . . 27,636 25,357 20,990 Interest Applicable to Rentals. . 25,539 25,375 25,096 Total Fixed Charges . . . . . 111,237 102,995 99,096 Earnings (1). . . . . . . . . . . . $243,769 $265,655 $258,971 Ratio of Earnings to Fixed Charges. 2.19 2.58 2.61 1992 Pro Forma April 1 | January 1 1993 1992 (2) to Dec. 31 | to March 31 (Successor) |(Predecessor) Net Income. . . . . . . . . . . . . $108,103 $ 77,981 $ 71,941 | $ 6,040 Taxes on Income . . . . . . . . . . 46,896 20,378 23,551 | (3,173) Net Income Plus Taxes. . . . . 154,999 98,359 95,492 | 2,867 | Fixed Charges: | Interest on Long-Term Debt. . . . 53,908 57,862 42,889 | 14,973 Interest on Other Indebtedness. . 6,075 15,121 11,777 | 3,344 Interest on Corporate-owned | Life Insurance Borrowings . . . 11,865 7,155 5,294 | 1,861 Interest Applicable to Rentals. . 24,967 30,212 22,133 | 8,079 Total Fixed Charges . . . . . 96,815 110,350 82,093 | 28,257 | Earnings (1). . . . . . . . . . . . $251,814 $208,709 $177,585 | $ 31,124 | Ratio of Earnings to Fixed Charges. 2.60 1.89 2.16 | 1.10 (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, January 24, 1997 (February 7, 1997 with respect to Note 13 of the Notes to Consolidated Financial Statements.)

UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE BALANCE SHEET AT DECEMBER 31, 1996 AND THE STATEMENT OF INCOME AND THE STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1996 DEC-31-1996 PER-BOOK 2,584,420 42,134 387,085 305,248 0 3,318,887 1,065,634 0 116,717 1,182,351 0 0 684,068 222,300 0 0 0 0 0 0 1,230,168 3,318,887 654,570 36,258 466,968 513,579 140,991 11,501 152,492 56,218 96,274 0 0 100,000 46,304 203,160 0 0