ITEM 1. BUSINESS
GENERAL
Western Resources, Inc. is a combination electric and natural gas public utility engaged in the generation, transmission, distribution and sale of electric energy in Kansas and the purchase, transmission, distribution, transportation and sale of natural gas in Kansas and Oklahoma. As used herein, the terms "Company and Western Resources" include its wholly-owned subsidiaries, Astra Resources, Inc. (Astra Resources), Kansas Gas and Electric Company (KG&E) since March 31, 1992, KPL Funding Corporation (KFC), and Mid Continent Market Center, Inc. (Market Center). KG&E owns 47 percent of Wolf Creek Nuclear Operating Corporation, the operating company for Wolf Creek Generating Station (Wolf Creek). Corporate headquarters of the Company is located at 818 Kansas Avenue, Topeka, Kansas 66612. At December 31, 1994, the Company had 4,330 employees.
The Company conducts its non-regulated business through Astra Resources. Astra Resources' non-regulated businesses include natural gas compression, marketing, processing and gathering services, and investments in energy and technology related businesses.
To capitalize on opportunities in the non-regulated natural gas industry, the Company, through the Market Center, is establishing a natural gas market center in Kansas. The Market Center will provide natural gas transportation, storage, and gathering services, as well as balancing, and title transfer capability. Upon approval from the Kansas Corporation Commission (KCC), the Company intends to transfer certain natural gas transmission assets having a value of approximately $52.1 million to the Market Center. In addition, the Company intends to extend credit to the Market Center enabling the Market Center to borrow up to an aggregate principal amount of $25 million on a term basis to construct new facilities and $5 million on a revolving credit basis for working capital. The Market Center will provide no notice natural gas transportation and storage services to the Company under a long-term contract. The Company will continue to operate and maintain the Market Center's assets under a separate contract.
On January 31, 1994, the Company sold substantially all of its Missouri natural gas distribution properties and operations to Southern Union Company (Southern Union). The Company sold the remaining Missouri properties to United Cities Gas Company (United Cities) on February 28, 1994. The properties sold to Southern Union and United Cities are referred to herein as the "Missouri Properties." With the sales the Company is no longer operating as a utility in the State of Missouri.
The portion of the Missouri Properties purchased by Southern Union was sold for an estimated sale price of $400 million, in cash, based on a calculation as of December 31, 1993. United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri for $665,000 in cash. As a result of the sales of the Missouri Properties, as described in Note 2 of the Notes to Consolidated Financial Statements, the Company recognized a gain of approximately $19.3 million, net of tax, ($0.31 per share) and ceased recording the results of operations for the Missouri Properties during the first quarter of 1994. Consequently, the Company's results of operations for the twelve months ended December 31, 1994 are not comparable to the results of operations for the same periods ending December 31, 1993 and 1992.
The following table reflects, through the dates of the sales of the Missouri Properties, the approximate operating revenues and operating income for the years ended December 31, 1994, 1993, and 1992, and net utility plant at December 31, 1993 and 1992, related to the Missouri Properties (see Notes 2 and 4 of the Notes to Consolidated Financial Statements included herein):
1994 1993 1992 Percent Percent Percent of Total of Total of Total Amount Company Amount Company Amount Company (Dollars in Thousands, Unaudited) Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2% Operating income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7% Net utility plant . . - - 296,039 6.6% 272,126 6.1%
Separate audited financial information was not kept by the Company for the Missouri Properties. This unaudited financial information is based on assumptions and allocations of expenses of the Company as a whole.
On March 31, 1992, the Company through its wholly-owned subsidiary KCA Corporation (KCA), acquired all of the outstanding common and preferred stock of Kansas Gas and Electric Company for $454 million in cash and 23,479,380 shares of common stock (the Merger). The Company also paid approximately $20 million in costs to complete the Merger. Simultaneously, KCA and Kansas Gas and Electric Company merged and adopted the name of Kansas Gas and Electric Company (KG&E). Additional information relating to the Merger can be found in Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 3 of Notes to Consolidated Financial Statements.
The following information includes the operations of KG&E since March 31, 1992 and excludes the activities related to the Missouri Properties following the sales of those properties in the first quarter of 1994.
The percentages of Total Operating Revenues and Operating Income Before Income Taxes attributable to the Company's electric and natural gas operations for the past five years were as follows:
Total Operating Income Operating Revenues Before Income Taxes Year Electric Natural Gas Electric Natural Gas 1994 69% 31% 97% 3% 1993 58% 42% 85% 15% 1992 57% 43% 89% 11% 1991 41% 59% 84% 16% 1990 40% 60% 85% 15% The difference between the percentage of electric operating revenues to total operating revenues and the percentage of electric operating income to total operating income as compared to the same percentages for natural gas operations is due to the Company's level of investment in plant and its fuel costs in each of these segments. The reduction in the percentages for the natural gas operations in 1994 is due to the sales of the Missouri Properties. The increase in the percentages for the electric operations in 1992 is due to the Merger. The amount of the Company's plant in service (net of accumulated depreciation) at December 31, for each of the past five years was as follows:
Year Electric Natural Gas Total (Dollars in Thousands) 1994 $3,676,347 $496,753 $4,173,100 1993 3,641,154 759,619 4,400,773 1992 3,645,364 696,036 4,341,400 1991 1,080,579 628,751 1,709,330 1990 1,092,548 567,435 1,659,983
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.
ELECTRIC OPERATIONS
General
The Company supplies electric energy at retail to approximately 594,000 customers in 462 communities in Kansas. These include Wichita, Topeka, Lawrence, Manhattan, Salina, and Hutchinson. The Company also supplies electric energy at wholesale to the electric distribution systems of 67 communities and 5 rural electric cooperatives. The Company has contracts for the sale, purchase or exchange of electricity with other utilities. The Company also receives a limited amount of electricity through parallel generation.
The Company's electric sales for the last five years were as follows (includes KG&E since March 31, 1992):
1994 1993 1992 1991 1990 (Thousands of MWH) Residential 5,003 4,960 3,842 2,556 2,403 Commercial 5,368 5,100 4,473 3,051 2,952 Industrial 5,410 5,301 4,419 1,947 1,954 Wholesale and Interchange 3,899 4,525 3,028 1,669 913 Other 106 103 91 315* 907 ------ ------ ------ ----- ----- Total 19,786 19,989 15,853 9,538* 9,129
* Includes cumulative effect to January 1, 1991, of a change in revenue recognition. The cumulative effect of this change increased electric sales by 256,000 MWH for 1991. The Company's electric revenues for the last five years were as follows (includes KG&E since March 31, 1992):
1994 1993 1992 1991 1990 (Dollars in Thousands) Residential $ 388,271 $ 384,618 $296,917 $160,831 $152,509 Commercial 334,059 319,686 271,303 149,152 146,001 Industrial 265,838 261,898 211,593 78,138 79,225 Wholesale and Interchange 106,243 118,401 98,183 70,262 39,585 Other 27,370 19,934 4,889 13,456 46,387 ---------- ---------- -------- -------- -------- Total $1,121,781 $1,104,537 $882,885 $471,839 $463,707
Capacity
The aggregate net generating capacity of the Company's system is presently 5,230 megawatts (MW). The system comprises interests in 22 fossil fueled steam generating units, one nuclear generating unit (47 percent interest), seven combustion peaking turbines and one diesel generator located at eleven generating stations. Two units of the 22 fossil fueled units have been "mothballed" for future use (see Item 2.
ITEM 2. PROPERTIES
The Company owns or leases and operates an electric generation, transmission, and distribution system in Kansas, a natural gas integrated storage, gathering, transmission and distribution system in Kansas, and a natural gas distribution system in Kansas and Oklahoma.
During the five years ended December 31, 1994, the Company's gross property additions totalled $923,801,000 and retirements were $176,678,000.
ELECTRIC FACILITIES Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (2)
Abilene Energy Center: Combustion Turbine 1 1973 Gas 65
Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 150 2 1967 Gas--Oil 367
Hutchinson Energy Center: Steam Turbines 1 1950 Gas 18 2 1950 Gas 17 3 1951 Gas 28 4 1965 Gas 196 Combustion Turbines 1 1974 Gas 51 2 1974 Gas 49 3 1974 Gas 54 4 1975 Oil 89
Jeffrey Energy Center (84%): Steam Turbines 1 1978 Coal 587 2 1980 Coal 600 3 1983 Coal 588
La Cygne Station (50%): Steam Turbines 1 1973 Coal 343 2 1977 Coal 335
Lawrence Energy Center: Steam Turbines 2 1952 Gas 0 (1) 3 1954 Coal 56 4 1960 Coal 113 5 1971 Coal 370
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 105 Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (2)
Neosho Energy Center: Steam Turbines 3 1954 Gas--Oil 0 (1)
Tecumseh Energy Center: Steam Turbines 7 1957 Coal 88 8 1962 Coal 148 Combustion Turbines 1 1972 Gas 19 2 1972 Gas 19
Wichita Plant: Diesel Generator 5 1969 Diesel 3
Wolf Creek Generating Station (47%): Nuclear 1 1985 Uranium 545 ----- Total 5,230
(1) These units have been "mothballed" for future use.
(2) Based on MOKAN rating.
The Company jointly-owns Jeffrey Energy Center (84%), La Cygne Station (50%) and Wolf Creek Generating Station (47%).
NATURAL GAS COMPRESSOR STATIONS AND STORAGE FACILITIES
The Company's transmission and storage facility compressor stations, all located in Kansas, as of December 31, 1994, are as follows: Mfr Ratings of MCF/Hr Capacity at Driving Type of Mfr hp 14.65 Psia Location Units Year Installed Fuel Ratings at 60F
Abilene . . . . . 4 1930 Gas 4,000 5,920 Bison . . . . . . 1 1951 Gas 440 316 Brehm Storage . . 2 1982 Gas 800 486 Calista . . . . . 3 1987 Gas 4,400 7,490 Hope. . . . . . . 1 1970 Electric 600 44 Hutchinson. . . . 2 1989 Gas 1,600 707 Manhattan . . . . 1 1963 Electric 250 313 Marysville. . . . 1 1964 Electric 250 202 McPherson . . . . 1 1972 Electric 3,000 7,040 Minneola. . . . . 5 1952 - 1978 Gas 9,650 14,018 Pratt . . . . . . 3 1963 - 1983 Gas 1,700 3,145 Spivey. . . . . . 4 1957 - 1964 Gas 7,200 1,368 Ulysses . . . . . 12 1949 - 1981 Gas 26,630 15,244 Yaggy Storage . . 3 1993 Electric 7,500 5,000 The Company owns and operates an underground natural gas storage facility, the Brehm field in Pratt County, Kansas. This facility has a working storage capacity of approximately 1.6 BCF. The Company withdrew up to 6,230 MCF per day from this field to meet 1994 winter peaking requirements.
The Company owns and operates an underground natural gas storage field, the Yaggy field in Reno County, Kansas. This facility has a working storage capacity of approximately 2 BCF. The Company withdrew up to 52,700 MCF per day from this field to meet 1994 winter peaking requirements.
The Company has contracted with WNG for additional underground storage in the Alden field in Kansas. The contract, expiring March 31, 1998, enables the Company to supply customers with up to 75 million cubic feet per day of gas supply during winter peak periods. See Item I. Business, Gas Operations for proven recoverable gas reserve information.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In March, 1995, the litigation between the Company and the Bishop Group, Ltd., and other entities affiliated with the Bishop Group, raising breach of certain gas supply contracts as set forth in Note 4 of the Notes to Consolidated Financial Statements, was settled with the realignment of the commercial relationship between the parties. The resolution of this matter is not expected to have a material adverse impact on the Company.
Additional information on legal proceedings involving the Company is set forth in Note 4 of Notes to Consolidated Financial Statements included herein.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted during the fourth quarter of the fiscal year covered by this report to a vote of security holders, through the solicitation of proxies or otherwise.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Stock Trading
Western Resources common stock, which is traded under the ticker symbol WR, is listed on the New York Stock Exchange. As of March 1, 1995, there were 43,454 common shareholders of record. For information regarding quarterly common stock price ranges for 1994 and 1993, see Note 16 of Notes to Consolidated Financial Statements included herein. Dividend Policy
Western Resources common stock is entitled to dividends when and as declared by the Board of Directors. At December 31, 1994, the Company's retained earnings were restricted by $857,600 against the payment of dividends on common stock. However, prior to the payment of common dividends, dividends must be first paid to the holders of preferred stock and second to the holders of preference stock based on the fixed dividend rate for each series.
Dividends have been paid on the Company's common stock throughout the Company's history. Quarterly dividends on common stock normally are paid on or about the first of January, April, July, and October to shareholders of record as of about the third day of the preceding month. Dividends increased four cents per common share in 1994 to $1.98 per share. In January 1995, the Board of Directors declared a quarterly dividend of 50 1/2 cents per common
share, an increase of one cent over the previous quarter. Based on currently projected operating results, the Company does not anticipate a material change in its dividend policy or payout ratio (approximately 70 percent in 1994) in 1995. Future dividends depend upon future earnings, the financial condition of the Company and other factors. For information regarding quarterly dividend declarations for 1994 and 1993, see Note 16 of Notes to Consolidated Financial Statements included herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION
GENERAL: Earnings were $2.82 per share of common stock based on 61,617,873 average common shares for 1994, an increase from $2.76 in 1993 on 59,294,091 average common shares. Net income for 1994 increased to $187.4 million compared to $177.4 million in 1993. The increase in net income and earnings per share is a result of the gain on the sale of the Company's natural gas distribution properties and operations in the State of Missouri, reduced interest expense, and higher electric sales combined with lower fuel costs.
Dividends increased four cents per common share in 1994 to $1.98 per share. In January 1995, the Board of Directors declared a quarterly dividend of 50 1/2 cents per common share, an increase of one cent over the previous quarter. Based on currently projected operating results, the Company does not anticipate a material change in its dividend policy or payout ratio (approximately 70 percent in 1994) in 1995.
The book value per share was $23.93 at December 31, 1994, compared to $23.08 at December 31, 1993. The 1994 closing stock price of $28 5/8 was 120 percent of book value. There were 61,617,873 common shares outstanding at December 31, 1994.
On January 31, 1994, the Company sold substantially all of its Missouri natural gas distribution properties and operations to Southern Union Company (Southern Union). The Company sold the remaining Missouri properties to United Cities Gas Company (United Cities) on February 28, 1994. The properties sold to Southern Union and United Cities are referred to herein as the "Missouri Properties." With the sales the Company is no longer operating as a utility in the State of Missouri.
The portion of the Missouri Properties purchased by Southern Union was sold for an estimated sale price of $400 million, in cash, based on a calculation as of December 31, 1993. United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri, for $665,000 in cash.
As a result of the sales of the Missouri Properties, as described in Note 2 of the Notes to Consolidated Financial Statements, the Company recognized a gain of approximately $19.3 million, net of tax, ($0.31 per share) and ceased recording the results of operations for the Missouri Properties during the first quarter of 1994. Consequently, the Company's results of operations for the twelve months ended December 31, 1994 are not comparable to the results of operations for the same periods ending December 31, 1993 and 1992. The following table reflects, through the dates of the sales of the Missouri Properties, the approximate operating revenues and operating income for the years ended December 31, 1994, 1993, and 1992, and net utility plant at December 31, 1993 and 1992, related to the Missouri Properties (see Note 2):
1994 1993 1992
Percent Percent Percent of Total of Total of Total Amount Company Amount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2% Operating income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7% Net utility plant . . - - 296,039 6.6% 272,126 6.1%
Separate audited financial information was not kept by the Company for the Missouri Properties. This unaudited financial information is based on assumptions and allocations of expenses of the Company as a whole.
For additional information regarding the sales of the Missouri Properties and the pending litigation see Notes 2 and 4 of the Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES: The Company's liquidity is a function of its ongoing construction program, designed to improve facilities which provide electric and natural gas service and meet future customer service requirements.
During 1994, construction expenditures for the Company's electric system were approximately $152 million and nuclear fuel expenditures were approximately $21 million. It is projected that adequate capacity margins will be maintained without the addition of any major generating facilities through the turn of the century. The construction expenditures for improvements on the natural gas system, including the Company's service line replacement program, were approximately $65 million during 1994.
Capital expenditures for 1995 through 1997 are anticipated to be as follows:
Electric Nuclear Fuel Natural Gas (Dollars in Thousands) 1995. . . . . $131,300 $ 21,400 $ 45,700 1996. . . . . 114,500 8,100 58,700 1997. . . . . 108,500 24,000 58,100
These expenditures are estimates prepared for planning purposes and are subject to revisions from time to time (see Note 7).
The Company's net cash flows to capital expenditures was 97 percent for 1994 and during the last five years has averaged 98 percent. The Company anticipates all of its cash requirements for capital expenditures through 1997 will be provided from net cash flows. The Company's capital needs through 1999 for bond maturities and cash sinking fund requirements for bonds and preference stock are approximately $156 million. This capital will be provided from internal and external sources available under then existing financial conditions.
The embedded cost of long-term debt was 7.6% at December 31, 1994, a decrease from 8.1% at December 31, 1993. The decrease was primarily accomplished through refinancing of higher cost debt.
The Company's short-term financing requirements are satisfied, as needed, through the sale of commercial paper, short-term bank loans and borrowings under unsecured lines of credit maintained with banks. At December 31, 1994, short-term borrowings amounted to $308.2 million, of which $157.2 million was commercial paper (see Notes 6 and 11). At December 31, 1994, the Company had bank credit arrangements available of $145 million.
The Company's short-term debt balance at December 31, 1994, decreased approximately $132.7 million from December 31, 1993. The decrease is primarily a result of the use of the proceeds from the sales of the Missouri Properties and the issuance, on January 20, 1994, of $100 million of Kansas Gas and Electric Company (KG&E) first mortgage bonds, 6.20% Series due January 15, 2006.
In January 1994, the Company entered into an agreement with Oklahoma Municipal Power Authority (OMPA). Under the agreement, the Company received a prepayment of approximately $41 million for which the Company will provide capacity and transmission services to OMPA through the year 2013.
On January 31, 1994, the Company redeemed the remaining $2,466,000 principal amount of Gas Service Company 8 1/2% Series First Mortgage Bonds due 1997.
On February 17, 1994, KG&E refinanced the City of La Cygne, Kansas, 5 3/4% Pollution Control Revenue Refunding Bonds Series 1973, $13,980,000 principal amount, with 5.10% Pollution Control Revenue Refunding Bonds Series 1994, $13,982,500 principal amount, due 2023.
On March 4, 1994, the Company retired the following First Mortgage Bonds: $19 million of 7 5/8% Series due April 1, 1999, $30 million of 8 1/8% Series due June 1, 2007, and $50 million of 8 5/8% Series due March 1, 2017.
On April 28, 1994, two series of Market-Adjusted Tax Exempt Securities (MATES) totalling $75.5 million were sold on behalf of the Company and three series of MATES totalling $46.4 million were sold on behalf of KG&E. The rate on these bonds was 2.95% for the initial auction period. The interest rates are being reset periodically via an auction process. As of December 31, 1994, the rates on these bonds ranged from 3.94% to 4.10%. The net proceeds from the new issues, together with available cash, were used to refund five series of pollution control bonds totalling $121.9 million bearing interest rates between 5 7/8% and 6.8%.
On October 5, the Company extended the term of its $350 million revolving credit facility which will now expire on October 5, 1999.
On November 1, 1994, KG&E terminated a long-term agreement which contained provisions for the sale of accounts receivable and unbilled revenues, and phase-in revenues (see Note 11). The Company has a Customer Stock Purchase Plan (CSPP) and a Dividend Reinvestment and Stock Purchase Plan (DRIP). Shares issued under the CSPP and DRIP may be either original issue shares or shares purchased on the open market.
The Company's capital structure at December 31, 1994, was 49 percent common stock equity, 6 percent preferred and preference stock, and 45 percent long-term debt. The capital structure at December 31, 1994, including short-term debt and current maturities of long-term debt, was 45 percent common stock equity, 5 percent preferred and preference stock, and 50 percent debt. As of December 31, 1994, the Company's bonds were rated "A3" by Moody's Investors Service, "A-" by Standard & Poor's Ratings Group, and "A-" by Fitch Investors Service.
RESULTS OF OPERATIONS
The following is an explanation of significant variations from prior year results in revenues, operating expenses, other income and deductions, interest charges and preferred and preference dividend requirements. The results of operations of the Company include the activities of KG&E since the merger on March 31, 1992, and exclude the activities related to the Missouri Properties following the sales of those properties in the first quarter of 1994.
For additional information regarding the sales of the Missouri Properties and the pending litigation, see Notes 2 and 4 of the Notes to Consolidated Financial Statements. Additional information relating to changes between years is provided in the Notes to Consolidated Financial Statements.
REVENUES
The operating revenues of the Company are based on sales volumes and rates authorized by certain state regulatory commissions and the Federal Energy Regulatory Commission (FERC). Rates, charged for the sale and delivery of natural gas and electricity, are designed to recover the cost of service and allow investors a fair rate of return. Future natural gas and electric sales will be affected by weather conditions, competition from other generating sources, competing fuel sources, customer conservation efforts, and the overall economy of the Company's service area.
The Kansas Corporation Commission (KCC) order approving the merger with KG&E on March 31, 1992 (Merger), provided a moratorium on increases, with certain exceptions, in the Company's jurisdictional electric and natural gas rates until August 1995. The KCC ordered refunds totalling $32 million to the combined companies' customers to share with customers the Merger-related cost savings achieved during the moratorium period. Refunds of $8.5 million were made in April 1992 and December 1993 and the remaining refund of $15 million was made in September 1994 (see Note 3).
On March 26, 1992, in connection with the Merger, the KCC approved the elimination of the Energy Cost Adjustment Clause for most Kansas retail electric customers of both the Company and KG&E effective April 1, 1992. The fuel costs are now included in base rates and were established at a level intended by the KCC to equal the projected average cost of fuel through August 1995. Any variance in fuel costs from the projected average will impact the Company's earnings.
Future natural gas revenues will be reduced as a result of the sales of the Missouri Properties. The Consolidated Statements of Income include revenues of $77 million for the portion of the first quarter of 1994 prior to the sales of the Missouri Properties, $350 million for 1993 and $299 million for 1992. Following the sales of the Missouri Properties and during 1995 and beyond, there will be no revenues related to the Missouri Properties (see Note 2).
1994 Compared to 1993: Electric revenues increased two percent during 1994 primarily as a result of a four percent increase in commercial and industrial electric sales. Residential electric sales increased one percent despite four percent cooler temperatures during the primary air conditioning load months of June, July, and August. Partially offsetting these increases in electric revenues was a fourteen percent decrease in wholesale and interchange sales as a result of higher than normal sales in 1993 to other utilities while their generating units were down due to the flooding of 1993.
Natural gas revenues and sales decreased significantly in 1994 as a result of the sales of the Missouri Properties in the first quarter of 1994 (see Note 2). Also contributing to the decrease in natural gas revenues were reduced natural gas sales for space heating as a result of much warmer temperatures during the winter season of 1994 compared to 1993.
1993 Compared to 1992: Electric revenues increased significantly in 1993 as a result of the Merger. Also contributing to the increase was increased electric sales for space heating, resulting from colder winter temperatures in the first quarter of 1993, and increased sales for cooling load, resulting from warmer temperatures in the second and third quarters of 1993. KG&E electric revenues of $617 million have been included in the Company's 1993 electric revenues. This compares to KG&E revenues of $424 million, from April 1, 1992, through December 31, 1992, included in the Company's 1992 electric revenues. Partially offsetting these increases in electric revenues was the amortization of the Merger-related customer refund.
Electric revenues for 1993 compared to pro forma revenues for 1992, giving effect to the Merger as if it had occurred at January 1, 1992, would have increased as a result of the warmer summer and colder winter temperatures in 1993. Retail sales of kilowatt hours on a pro forma comparative basis increased from approximately 14.6 billion for 1992 to approximately 15.5 billion for 1993, or six percent.
Natural gas revenues for 1993 increased approximately 20 percent as a result of increased sales caused by colder winter temperatures, the full impact of increased retail natural gas rates (see Note 5), and an 11 percent increase in the unit cost of gas passed on to customers through the purchased gas adjustment clauses (PGA). The colder winter temperatures are reflected in a 17 percent increase in natural gas sales to residential customers.
OPERATING EXPENSES
1994 Compared to 1993: Total operating expenses decreased 17 percent during 1994 primarily as a result of the sales of the Missouri Properties (Note 2). Also contributing to the decrease were lower fuel costs for electric generation and reduced natural gas purchases as a result of lower sales caused by milder winter temperatures in 1994 compared to 1993.
Partially offsetting the decreases in operating expenses was higher income tax expense. As of December 31, 1993, KG&E had fully amortized its deferred income tax reserves related to the allowance for borrowed funds used during construction capitalized for Wolf Creek Generating Station. The completion of the amortization of these deferred income tax reserves increased income tax expense and thereby reduced net income by approximately $12 million in 1994, and in the future will reduce net income by this same amount each year.
1993 Compared to 1992: Operating expenses increased for 1993 primarily as a result of the Merger. KG&E operating expenses of $470 million have been included in the Company's operating expenses for the year ended December 31, 1993. This compares to KG&E operating expenses of $316 million, from April 1, 1992, through December 31, 1992, included in the Company's 1992 operating expenses.
Other factors, excluding the Merger, contributing to the increase in operating expenses were higher fuel and purchased power expenses caused by increased electric sales to meet cooling load and increased natural gas purchases caused by a 16 percent increase in natural gas sales and an 11 percent higher unit cost of gas which is passed on to customers through the PGA.
Also contributing to the increase were higher general taxes due to increases in plant, the property tax assessment ratio, and higher mill levies. A constitutional amendment in Kansas changed the assessment on utility property from 30 to 33 percent. As a result of this change the Company had an increased property tax expense of approximately $6.1 million in 1993.
Partially offsetting the increases were savings as a result of the Merger and reduced net lease expense for La Cygne 2 resulting from refinancing of secured facility bonds (see Note 10).
OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of taxes, was higher for the twelve months ended December 31, 1994 compared to 1993 due to the recognition of the gain on the sales of the Missouri Properties of approximately $19.3 million, net of tax, (see Note 2). Partially offsetting this increase was increased interest expense on corporate-owned life insurance (COLI) borrowings. Also partially offsetting the increase was the recognition of income in 1993 from death proceeds from COLI policies.
Other income and deductions, net of taxes, increased $1.3 million in 1993 compared to 1992. KG&E other income and deductions, net of taxes, of $19 million have been included in the Company's total for 1993 compared to $17 million in 1992 from April 1, through December 31, 1992. Income from KG&E's COLI totalled $8 million in 1993. INTEREST CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS: Total interest charges decreased 17 percent for the twelve months ended December 31, 1994, as a result of lower debt balances and the refinancing of higher cost debt, as well as increased COLI borrowings which interest is reflected in Other Income and Deductions, on the Consolidated Statements of Income. The Company's embedded cost of long-term debt decreased to 7.6% at December 31, 1994, compared to 8.1% and 8.2% at December 31, 1993 and 1992, respectively, primarily as a result of the refinancing of higher cost debt.
Partially offsetting these decreases in interest expense were higher interest rates on short-term borrowings.
Interest charges for 1993 were higher than 1992 as a result of the Merger. KG&E interest charges of $59 million for 1993 were included in the Company's total interest charges compared to $53 million for the nine months ended December 31, 1992. The full twelve month effect of interest on debt to acquire KG&E also contributed to the increase in total interest charges. The increased interest charges were partially offset through lower debt balances and reduced interest charges from refinancing higher cost long-term debt and lower interest rates on variable-rate debt.
MERGER IMPLEMENTATION: In accordance with the KCC Merger order, amortization of the acquisition adjustment will commence August 1995. The amortization will amount to approximately $20 million (pre-tax) per year for 40 years. The Company can recover the amortization of the acquisition adjustment through cost savings under a sharing mechanism approved by the KCC as described in Note 3 of the Notes to the Consolidated Financial Statements. While the Company has achieved savings from the Merger, there is no assurance that the savings achieved will be sufficient to, or the cost savings sharing mechanism will operate as to, fully offset the amortization of the acquisition adjustment.
OTHER INFORMATION
INFLATION: Under the ratemaking procedures prescribed by the regulatory commissions to which the Company is subject, only the original cost of plant is recoverable in revenues as depreciation. Therefore, because of inflation, present and future depreciation provisions are inadequate for purposes of maintaining the purchasing power invested by common shareholders and the related cash flows are inadequate for replacing property. The impact of this ratemaking process on common shareholders is mitigated to the extent depreciable property is financed with debt that can be repaid with dollars of less purchasing power. While the Company has experienced relatively low inflation in the recent past, the cumulative effect of inflation on operating costs may require the Company to seek regulatory rate relief to recover these higher costs.
FERC ORDER NO. 636: In 1992 the FERC issued Order No. 636 (FERC 636) which the FERC intended to complete the deregulation of natural gas production and facilitate competition in the gas transportation industry. FERC 636 has affected the Company in several ways. The rules provide greater protection for pipeline companies by providing for recovery of all fixed costs through contracts with local distribution companies and other customers choosing to transport gas on a firm (non-interruptible) basis. The order also separates the purchase of natural gas from the transportation and storage of natural gas, shifting additional responsibility to distribution companies for the provision (through purchase and/or storage) of long-term gas supply and transportation to distribution points. Under the new rules, distribution companies elect the amount and type of services taken from pipelines. The Company may be liable to one or more of its pipeline suppliers for costs related to the transition from its traditional natural gas sales service to the restructured services required by FERC 636. The Company believes substantially all of these costs will be recovered from its customers and any additional transition costs will be immaterial to the Company's financial position or results of operations. For additional information regarding FERC 636 costs, see Note 5 of the Notes to Consolidated Financial Statements.
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 (see Note 7).
Although the Company currently has no Phase I affected units under the Clean Air Act of 1990, the Company has applied for an early substitution permit to bring the co-owned La Cygne Station under the Phase I guidelines. The oxides of nitrogen (NOx) and air toxic limits, which were not set in law, will be specified in future Environmental Protection Agency (EPA) regulations. The EPA's proposed NOx regulations were ruled invalid by the U.S. Court of Appeals for the District of Columbia Circuit in November, 1994 and until such time as the EPA resubmits new proposed regulations, the Company will be unable to determine its compliance options or related compliance costs (see Note 7).
COMPETITION: As a regulated utility, the Company currently has limited direct competition for retail electric service in its certified service area. However, there is competition, based largely on price, from the generation, or potential generation, of electricity by large commercial and industrial customers, and independent power producers.
The 1992 Energy Policy Act (Act) requires increased efficiency of energy usage and has affected the way electricity is marketed. The Act also provides for increased competition in the wholesale electric market by permitting the FERC to order third party access to utilities' transmission systems and by liberalizing the rules for ownership of generating facilities. As part of the Merger, the Company agreed to open access of its transmission system for wholesale transactions. During 1994, wholesale electric revenues represented less than ten percent of the Company's total electric revenues.
Operating in this competitive environment could place pressure on utility profit margins and credit quality. Wholesale and industrial customers may threaten to pursue cogeneration, self-generation, retail wheeling, municipalization or relocation to other service territories in an attempt to obtain reduced energy costs. Increasing competition has resulted in credit rating agencies applying more stringent guidelines when making utility credit rating determinations.
The Company is providing reduced electric rates for industrial expansion projects and economic development projects in an effort to maintain and increase electric load. In 1994, The Boeing Company announced it would develop its 777 jetliner in Wichita and Cessna Aircraft Company announced it would build a production plant in Independence, Kansas along with expanding its Wichita facilities, with an addition of 2,000 jobs.
In order to retain its current electric load, the Company has and will continue to negotiate with some of its larger industrial customers, who are able to develop cogeneration facilities, for long-term contracts although some negotiated rates may result in reduced margins for the Company. During 1996, the Company will lose a major industrial customer to cogeneration resulting in a reduction to pre-tax earnings of approximately $7 to $8 million or 7 to 8 cents per share. This customer's decision to develop its own cogeneration project was based partially on factors other than energy cost.
To capitalize on opportunities in the non-regulated natural gas industry, the Company, through its wholly-owned subsidiary Mid Continent Market Center, Inc. (Market Center), is establishing a natural gas market center in Kansas. The Market Center will provide natural gas transportation, storage, and gathering services, as well as balancing, and title transfer capability. Upon approval from the KCC, the Company intends to transfer certain natural gas transmission assets having a value of approximately $52.1 million to the Market Center. In addition, the Company intends to extend credit to the Market Center enabling the Market Center to borrow up to an aggregate principal amount of $25 million on a term basis to construct new facilities and $5 million on a revolving credit basis for working capital. The Market Center will provide no notice natural gas transportation and storage services to the Company under a long-term contract. The Company will continue to operate and maintain the Market Center's assets under a separate contract.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 35
Financial Statements:
Consolidated Balance Sheets, December 31, 1994 and 1993 36 Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992 37 Consolidated Statements of Cash Flows for the years ended 1994, 1993 and 1992 38 Consolidated Statements of Taxes for the years ended December 31, 1994, 1993 and 1992 39 Consolidated Statements of Capitalization, December 31, 1994 and 1993 40 Consolidated Statements of Common Stock Equity for the years ended December 31, 1994, 1993 and 1992 41 Notes to Consolidated Financial Statements 42
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented:
I, II, III, IV, and V. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Western Resources, Inc.:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Western Resources, Inc., and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, cash flows, taxes and common stock equity for each of the three years in the period ended December 31, 1994. 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 did not audit the financial statements of Kansas Gas and Electric Company, a wholly- owned subsidiary of Western Resources, Inc., as of and for the year ended December 31, 1992, which statements reflect assets and revenues of 61 percent and 27 percent, respectively, of the consolidated totals for 1992. Those statements were audited by other auditors whose report has been furnished to us and our opinion, insofar as it relates to the amounts included for that entity, is based solely on the report of other auditors.
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 and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the financial position of Western Resources, Inc., and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As explained in Note 13 to the consolidated financial statements, effective January 1, 1992, the Company changed its method of accounting for income taxes. As explained in Note 8 to the consolidated financial statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits. As explained in Note 8 to the consolidated financial statements, effective January 1, 1994, the Company changed its method of accounting for postemployment benefits.
ARTHUR ANDERSEN LLP Kansas City, Missouri, January 25, 1995
WESTERN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: The Consolidated Financial Statements of Western Resources, Inc. (the Company, Western Resources), include the accounts of its wholly-owned subsidiaries, Astra Resources, Inc. (Astra), Kansas Gas and Electric Company (KG&E) since March 31, 1992 (see Note 3), KPL Funding Corporation (KFC), and Mid Continent Market Center, Inc. (Market Center). KG&E owns 47 percent of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). The Company records its proportionate share of all transactions of WCNOC as it does other jointly-owned facilities. All significant intercompany transactions have been eliminated. The operations of Astra, KFC, and Market Center were not material to the Company's results of operations. The Company is conducting its utility business as KPL, Gas Service, and through its wholly-owned subsidiary, KG&E. The Company is conducting its non-utility business through Astra.
The accounting policies of the Company are in accordance with generally accepted accounting principles as applied to regulated public utilities. The accounting and rates of the Company are subject to requirements of the Kansas Corporation Commission (KCC), the Oklahoma Corporation Commission (OCC), and the Federal Energy Regulatory Commission (FERC).
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 4.08% in 1994, 4.10% in 1993, and 5.99% in 1992. The cost of additions to utility plant and replacement units of property is capitalized. Maintenance costs and replacement of minor items of property are charged to expense as incurred. When units of depreciable property are retired, they are removed from the plant accounts and the original cost plus removal charges less salvage are charged to accumulated depreciation.
Depreciation: Depreciation is provided on the straight-line method based on estimated useful lives of property. Composite provisions for book depreciation approximated 2.87% during 1994, 3.02% during 1993, and 3.03% during 1992 of the average original cost of depreciable property.
Consolidated Statements of Cash Flows: For purposes of the Consolidated 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.
Cash paid for interest and income taxes for each of the three years ended December 31, are as follows: 1994 1993 1992 (Dollars in Thousands) Interest on financing activities (net of amount capitalized). . . . . . . . . . . $134,785 $171,734 $128,505 Income taxes . . . . . . . . . . . . . . . 90,229 49,108 24,966 Income Taxes: Income tax expense includes provisions for income taxes currently payable and deferred income taxes calculated in conformance with income tax laws, regulatory orders, and Statement of Financial Accounting Standards No. 109 (SFAS 109) (see Note 13).
Investment tax credits previously deferred are being amortized to income over the life of the property which gave rise to the credits.
Revenues: The Company accrues estimated unbilled electric and natural gas revenues. This method of recognizing revenues best matches revenues with costs of services provided to customers and also conforms the Company's accounting treatment of unbilled revenues with the tax treatment of such 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 $61 million and $99 million are recorded as a component of accounts receivable and unbilled revenues (net) on the Consolidated Balance Sheets as of December 31, 1994 and 1993, respectively.
The Company had reserves for doubtful accounts receivable of $3.4 million and $4.3 million at December 31, 1994 and 1993, respectively.
Fuel Costs: The cost of nuclear fuel in process of refinement, conversion, enrichment, and fabrication is recorded as an asset at original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor at December 31, 1994 and 1993, was $13.6 million and $17.4 million, respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts related to corporate-owned life insurance contracts (COLI), primarily with one highly rated major insurance company, are recorded in Corporate-owned Life Insurance (net) on the Consolidated Balance Sheets:
1994 1993 (Dollars in Millions) Cash surrender value of contracts. . . $ 408.9 $ 326.3 Borrowings against contracts . . . . . (391.9) (321.6) ------- ------- COLI (net). . . . . . . . . . $ 17.0 $ 4.7 ======= =======
The COLI borrowings will be repaid upon receipt of proceeds from death benefits under contracts. The Company recognizes increases in the cash surrender value of contracts, resulting from premiums and investment earnings on a tax free basis, and the tax deductible interest on the COLI borrowings in Corporate-owned Life Insurance (net) on the Consolidated Statements of Income. Interest expense related to KG&E's COLI for 1994, 1993, and the nine months ended December 31, 1992, was $21.0 million, $11.9 million, and $5.3 million, respectively.
As approved by the KCC, the Company is using a portion of the net income stream generated by COLI policies purchased in 1993 and 1992 by the Company (see Note 8) to offset Statement of Financial Accounting Standards No. 106 (SFAS 106) and Statement of Financial Accounting Standards No. 112 (SFAS 112) expenses.
Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
2. SALES OF MISSOURI NATURAL GAS DISTRIBUTION PROPERTIES
On January 31, 1994, the Company sold substantially all of its Missouri natural gas distribution properties and operations to Southern Union Company (Southern Union). The Company sold the remaining Missouri properties to United Cities Gas Company (United Cities) on February 28, 1994. The properties sold to Southern Union and United Cities are referred to herein as the "Missouri Properties." With the sales the Company is no longer operating as a utility in the State of Missouri.
The portion of the Missouri Properties purchased by Southern Union was sold for an estimated sale price of $400 million, in cash, based on a calculation as of December 31, 1993. The sale agreement provided for estimated amounts in the sale price calculation to be adjusted to actual as of January 31, 1994, within 120 days of closing. Disputes with respect to proposed adjustments based upon differences between estimates and actuals were to be resolved within 60 days of submission of the disputes by Southern Union or submitted to arbitration by an accounting firm to be agreed to by both parties. Southern Union proposed a number of adjustments to the purchase price, some of which the Company has disputed. The Company maintains the disputed adjustments are not permitted under the sale agreement. In the opinion of the Company's management, the resolution of these purchase price adjustments will not have a material impact on the Company's financial position or results of operations. For information regarding litigation in connection with the sale of the Missouri Properties to Southern Union, see Note 4.
United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri for $665,000 in cash.
During the first quarter of 1994, the Company recognized a gain of approximately $19.3 million, net of tax, on the sales of the Missouri Properties. As of the respective dates of the sales of the Missouri Properties, the Company ceased recording the results of operations, and removed the assets and liabilities from the Consolidated Balance Sheet related to the Missouri Properties. The gain is reflected in Other Income and Deductions, on the Consolidated Statements of Income.
The following table reflects the approximate operating revenues and operating income for the years ended December 31, 1994, 1993, and 1992, and net utility plant at December 31, 1993 and 1992, related to the Missouri Properties:
1994 1993 1992 Percent Percent Percent of Total of Total of Total Amount Company Amount Company Amount Company (Dollars in Thousands, Unaudited) Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2% Operating income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7% Net utility plant . . - - 296,039 6.6% 272,126 6.1%
Separate audited financial information was not kept by the Company for the Missouri Properties. This unaudited financial information is based on assumptions and allocations of expenses of the Company as a whole.
3. ACQUISITION AND MERGER
On March 31, 1992, the Company, through its wholly-owned subsidiary KCA Corporation (KCA), acquired all of the outstanding common and preferred stock of Kansas Gas and Electric Company for $454 million in cash and 23,479,380 shares of common stock (the Merger). The Company also paid $20 million in costs to complete the Merger. Simultaneously, KCA and Kansas Gas and Electric Company merged and adopted the name of Kansas Gas and Electric Company (KG&E). The Merger was accounted for as a purchase. For income tax purposes the tax basis of the KG&E assets was not changed by the Merger.
As the Company acquired 100 percent of the common and preferred stock of KG&E, the Company recorded an acquisition premium of $490 million on the Consolidated Balance Sheet for the difference in purchase price and book value. This acquisition premium and related income tax requirement of $311 million under SFAS 109 have been classified as plant acquisition adjustment in Electric Plant in Service on the Consolidated Balance Sheets. Under the provisions of orders of the KCC, the acquisition premium is recorded as an acquisition adjustment and not allocated to the other assets and liabilities of KG&E.
In the November 1991 KCC order approving the Merger, a mechanism was approved to share equally between the shareholders and ratepayers the cost savings generated by the Merger in excess of the revenue requirement needed to allow recovery of the amortization of a portion of the acquisition adjustment, including income tax, calculated on the basis of a purchase price of KG&E's common stock at $29.50 per share. The order provides an amortization period for the acquisition adjustment of 40 years commencing in August 1995, at which time the full amount of cost savings is expected to have been implemented. Merger savings will be measured by application of an inflation index to certain pre-merger operating and maintenance costs at the time of the next Kansas rate case. While the Company has achieved savings from the Merger, there is no assurance that the savings achieved will be sufficient to, or the cost savings sharing mechanism will operate as to, fully offset the amortization of the acquisition adjustment. The order further provides a moratorium on increases, with certain exceptions, in the Company's Kansas electric and natural gas rates until August 1995. The KCC ordered refunds totalling $32 million to the combined companies' customers to share with customers the Merger-related cost savings achieved during the moratorium period. Refunds of $8.5 million were made in April 1992 and December 1993 and the remaining refund of $15 million was made in September 1994.
The KCC order approving the Merger required the legal reorganization of KG&E so that it was no longer held as a separate subsidiary after January 1, 1995, unless good cause was shown why such separate existence should be maintained. The Securities and Exchange Commission (SEC) order relating to the Merger granted the Company an exemption under the Public Utility Holding Company Act (PUHCA) until January 1, 1995. The Company has been granted regulatory approval from the KCC which eliminates the requirement for a combination. As a result of the sales of the Missouri Properties, the Company is now exempt from regulation as a holding company under Section 3(a)(1) of the PUHCA.
As the Merger did not occur until March 31, 1992, the twelve months ended December 31, 1992, results of operations for the Company reported in its statements of income, cash flows, and common stock equity reflect KG&E's results of operations for only the nine months ended December 31, 1992. Pro forma revenues of $1.7 billion, operating income of $269 million, net income of $132 million and earnings per share of $2.03 for the year ended December 31, 1992 give effect to the Merger as if it had occurred at January 1, 1992. This pro forma information is not necessarily indicative of the results of operations that would have occurred had the Merger been consummated on January 1, 1992, nor is it necessarily indicative of future operating results.
4. LEGAL PROCEEDINGS
On June 1, 1994, Southern Union filed an action against the Company, The Bishop Group, Ltd., and other entities affiliated with The Bishop Group, in the Federal District Court for the Western District of Missouri (the Court) (Southern Union Company v. Western Resources, Inc. et al., Case No. 94-509-CV- W-1) alleging, among other things, breach of the Missouri Properties sale agreement relating to certain gas supply contracts between the Company and various Bishop entities that Southern Union assumed, and requesting unspecified monetary damages as well as declaratory relief. On August 1, 1994, the Company filed its answer and counterclaim denying all claims asserted against it by Southern Union and requesting declaratory judgment with respect to certain adjustments in the purchase price for the Missouri Properties proposed by Southern Union and disputed by the Company. On August 24, 1994, Southern Union filed claims against the Company for alleged purchase price adjustments totalling $19 million. The Company subsequently agreed that approximately $4 million of the purchase price adjustments were subject to arbitration. On January 18, 1995, the Court held the remaining $15 million of proposed adjustments to the purchase price were subject to arbitration under the sale agreement. In the opinion of the Company's management, the disputed adjustments are not proper adjustments to the purchase price. For additional information regarding the sales of the Missouri Properties see Note 2.
On August 15, 1994, the Bishop entities filed an answer and claims against Southern Union and the Company alleging, among other things, breach of those certain gas supply contracts. The Bishop entities claimed damages up to $270 million against the Company and Southern Union. The Company's management believes that through the sale agreement, Southern Union assumed all liabilities arising out of or related to gas supply contracts associated with the Missouri Properties. The Company's management also believes it is not liable for any claims asserted against it by the Bishop entities and will vigorously defend such claims.
The Company received a civil investigative demand from the U.S. Department of Justice seeking certain information in connection with the department's investigation "to determine whether there is, has been, or may be a violation of the Sherman Act Sec. 1-2" with respect to the natural gas business in Kansas and Missouri. The Company is cooperating with the Department of Justice, but is not aware of any violation of the antitrust laws in connection with its business operations.
The Company and its subsidiaries are involved in various other legal and environmental proceedings. Management believes that adequate provision has been made within the Consolidated Financial Statements for these other matters and accordingly believes their ultimate dispositions will not have a material adverse effect upon the business, financial position, or results of operations of the Company. 5. RATE MATTERS AND REGULATION
The Company, under rate orders from the KCC, OCC and the FERC, recovers increases in fuel and natural gas costs through fuel adjustment clauses for wholesale and certain retail electric customers and various purchased gas adjustment clauses (PGA) for natural gas customers. The KCC and the OCC require the annual difference between actual gas cost incurred and cost recovered through the application of the PGA be deferred and amortized through rates in subsequent periods.
Elimination of the Energy Cost Adjustment Clause (ECA): On March 26, 1992, in connection with the Merger, the KCC approved the elimination of the ECA for most Kansas retail electric customers of both the Company and KG&E effective April 1, 1992. The provisions for fuel costs included in base rates were established at a level intended by the KCC to equal the projected average cost of fuel through August 1995, and to include recovery of costs provided by previously issued orders relating to coal contract settlements. Any variance in fuel costs from the projected average will impact the Company's earnings.
FERC Proceedings: On August 19, 1994, Williams Natural Gas Company (WNG) filed a revised application with the FERC to direct bill approximately $14.7 million of FERC Order No. 636 (FERC 636) transition costs to the Company related to natural gas sales service in Kansas and Oklahoma. These costs are currently being recovered from the Company's current Kansas and Oklahoma customers. The Company believes any future transition costs ultimately will be recovered through charges to its customers, and any unrecovered transition costs will not be material to the Company's financial position or results of operations. For additional information with respect to FERC 636 see Management's Discussion and Analysis.
On October 5, 1994, WNG filed an application with the FERC to direct bill to the Company up to $30.4 million of settlement costs paid to Amoco related to litigation between WNG and Amoco regarding the proper price to be paid for gas purchased by WNG from Amoco. The proposed direct bill is related to natural gas service rendered by the Company in Kansas and Oklahoma. At December 31, 1994, $14.2 million of these costs have been billed to the Company. The Company believes substantially all of these costs and any future settlement costs ultimately will be recovered through charges to its Kansas and Oklahoma customers, and any unrecovered settlement costs will not be material to the Company's financial position or results of operations.
KCC Proceedings: On December 22, 1994, the Company, in conjunction with the Market Center, filed an application with the KCC to form a natural gas market center in Kansas. The Market Center will provide natural gas transportation, storage, and gathering services, as well as balancing, and title transfer capability. Upon approval from the KCC, the Company intends to transfer certain natural gas transmission assets having a value of approximately $52.1 million to the Market Center. In addition, the Company intends to extend credit to the Market Center enabling the Market Center to borrow up to an aggregate principal amount of $25 million on a term basis to construct new facilities and $5 million on a revolving credit basis for working capital. The Market Center will provide no notice natural gas transportation and storage services to the Company under a long-term contract. The Company will continue to operate and maintain the Market Center's assets under a separate contract. On January 24, 1992, the KCC issued an order allowing the Company to continue the deferral of service line replacement program costs incurred since January 1, 1992, including depreciation, property taxes, and carrying costs for recovery in the next general rate case. At December 31, 1994, approximately $7.2 million of these deferrals have been included in Deferred Charges and Other Assets, Other, on the Consolidated Balance Sheet.
On December 30, 1991, the KCC approved a permanent natural gas rate increase of $39 million annually and the Company discontinued the deferral of accelerated line survey costs on January 1, 1992. Approximately $3.1 million of these deferred costs remain in Deferred Charges and Other Assets, Other, on the Consolidated Balance Sheet at December 31, 1994, with the balance being included in rates and amortized to expense during a 43-month period, commencing January 1, 1992.
Tight Sands: In December 1991 the KCC, and the OCC approved agreements authorizing the Company to refund to customers approximately $40 million of the proceeds of the Tight Sands antitrust litigation settlement to be collected on behalf of Western Resources' natural gas customers. To secure the refund of settlement proceeds, the Commissions authorized the establishment of an independently administered trust to collect and maintain cash receipts received under Tight Sands settlement agreements and provide for the refunds made. The trust has a term of ten years.
Rate Stabilization Plan: In 1988, the KCC issued an order requiring the accrual of phase-in revenues be discontinued by KG&E effective December 31, 1988. Effective January 1, 1989, KG&E began amortizing the phase-in revenue asset on a straight-line basis over 9 1/2 years. At December 31, 1994, approximately $61 million of deferred phase-in revenues remained on the Consolidated Balance Sheet.
Coal Contract Settlements: In March 1990, the KCC issued an order allowing KG&E to defer its share of a 1989 coal contract settlement with the Pittsburg and Midway Coal Mining Company amounting to $22.5 million. This amount was recorded as a deferred charge and is included in Deferred Charges and Other Assets on the Consolidated Balance Sheet. The settlement resulted in the termination of a long-term coal contract. The KCC permitted KG&E to recover this settlement as follows: 76 percent of the settlement plus a return over the remaining term of the terminated contract (through 2002) and 24 percent to be amortized to expense with a deferred return equivalent to the carrying cost of the asset.
In February 1991, KG&E paid $8.5 million to settle a coal contract lawsuit with AMAX Coal Company and recorded the payment as a deferred charge in Deferred Charges and Other Assets on the Consolidated Balance Sheet. The KCC approved the recovery of the settlement plus a return, equivalent to the carrying cost of the asset, over the remaining term of the terminated contract (through 1996).
FERC Order No. 528: In 1990, the FERC issued Order No. 528 which authorized new methods for the allocation and recovery of take-or-pay settlement costs by natural gas pipelines from their customers. Settlements were reached between the Company's two largest gas pipelines and their customers in FERC proceedings related to take-or-pay issues. The settlements address the allocation of take-or-pay settlement costs between the pipelines and their customers. However, the amount which one of the pipelines will be allowed to recover is yet to be determined. Litigation continues between the Company and a former upstream pipeline supplier to one of the Company's pipeline suppliers concerning the amount of such costs which may ultimately be allocated to the Company's pipeline supplier. The Company's share of any costs allocated to the Company's pipeline supplier will be charged to the Company. Due to the uncertainty concerning the amount to be recovered by the Company's current suppliers and of the outcome of the litigation between the Company and its current pipeline's upstream supplier, the Company is unable to estimate its future liability for take-or-pay settlement costs. However, the KCC has approved mechanisms which are designed to allow the Company to recover these take-or-pay costs from its customers.
6. SHORT-TERM DEBT
The Company's short-term financing requirements are satisfied, through the sale of commercial paper, short-term bank loans and borrowings under unsecured lines of credit maintained with banks. Information concerning these arrangements for the years ended December 31, 1994, 1993, and 1992, is set forth below:
Year Ended December 31, 1994 1993 1992 (Dollars in Thousands) Lines of credit at year end. . . . $145,000(1) $145,000 $250,000(2) Short-term debt out- standing at year end . . . . . . 308,200 440,895 222,225 Weighted average interest rate on debt outstanding at year end (including fees) . . . . . . 6.25% 3.67% 4.70% Maximum amount of short- term debt outstanding during the period. . . .. . . . . . . . $485,395 $443,895 $263,900 Monthly average short-term debt. . 214,180 347,278 179,577 Weighted daily average interest rates during the year (including fees) . . . . . . . . 4.63% 3.44% 4.90%
(1) Decreased to $121 million in January 1995. (2) Decreased to $155 million in January 1993.
In connection with the commitments, the Company has agreed to pay certain fees to the banks. Available lines of credit and the unused portion of the revolving credit facility are utilized to support the Company's outstanding short-term debt.
7. COMMITMENTS AND CONTINGENCIES
As part of its ongoing operations and construction program, the Company has commitments under purchase orders and contracts which have an unexpended balance of approximately $77 million at December 31, 1994. Approximately $32 million is attributable to modifications to upgrade the three turbines at Jeffrey Energy Center to be completed by December 31, 1998. Plans for future construction of utility plant are discussed in the Management's Discussion and Analysis section.
In January 1994, the Company entered into an agreement with Oklahoma Municipal Power Authority (OMPA). Under the agreement, the Company received a prepayment of approximately $41 million for which the Company will provide capacity and transmission services to OMPA through the year 2013.
Manufactured Gas Sites: The Company was previously associated with 20 former manufactured gas sites located in Kansas which may contain coal tar and other potentially harmful materials. These sites were operated decades ago by predecessor companies, and were owned by the Company for a period of time after operations had ceased. The Company and the Kansas Department of Health and Environment (KDHE) conducted preliminary assessments of the sites at a cost of approximately $500,000. The results of the preliminary investigations determined the Company does not have a connection to four of the sites. Of the remaining 16 sites, the site investigation and risk assessment field work of the highest priority site was completed in 1994 at a total cost of approximately $450,000. The Company has not received the final report so as to determine the extent of contamination and the amount of any possible remediation.
The Company and KDHE entered into a consent agreement governing all future work at these sites. The terms of the consent agreement will allow the Company to investigate the 16 sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a 10 year period. The agreement will allow the Company to set mutual objectives with the KDHE in order to expedite effective response activities and to control costs and environmental impact. The Company is aware of other utilities in Region VII of the EPA (Kansas, Missouri, Nebraska, and Iowa) which have incurred remediation costs for manufactured gas sites ranging between $500,000 and $10 million, depending on the site, and that the KCC has issued an accounting order which will permit another Kansas utility to recover its remediation costs through rates. To the extent that such remediation costs are not recovered through rates, the costs could be material to the Company's financial position or results of operations depending on the degree of remediation required and number of years over which the remediation must be completed.
Superfund Sites: The Company has been identified as one of numerous potentially responsible parties in four hazardous waste sites listed by the EPA as Superfund sites. One site is a groundwater contamination site in Wichita, Kansas (Wichita site), two are soil contamination sites in Missouri (Missouri sites), and one site is a solid waste land-fill located in Edwardsville, Kansas (Edwardsville site). Settlement agreements releasing the Company from liability for future response or costs have been entered into at the Edwardsville site and one of the Missouri sites. The Company's obligation at the remaining Missouri site and the Wichita site appears to be limited based on the Company's experience at similar sites given its limited exposure and settlement costs. In the opinion of the Company's management, the resolution of these matters will not have a material impact on the Company's financial position or results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in sulfur dioxide and oxides of nitrogen (NOx) emissions effective in 1995 and 2000 and a probable reduction in toxic emissions. To meet the monitoring and reporting requirements under the acid rain program, the Company installed continuous monitoring and reporting equipment at a total cost of approximately $10 million. The Company does not expect additional equipment to reduce sulfur emissions to be necessary under Phase II. Although the Company currently has no Phase I affected units, the owners have applied for an early substitution permit to bring the co-owned La Cygne Station under the Phase I regulations.
The NOx and air toxic limits, which were not set in the law, will be specified in future EPA regulations. The EPA's proposed NOx regulations were ruled invalid by the U.S. Court of Appeals for the District of Columbia Circuit and until such time as the EPA resubmits new proposed regulations, the Company will be unable to determine its compliance options or related compliance costs.
Other Environmental Matters: As part of the sale of the Company's Missouri Properties to Southern Union, Southern Union assumed responsibility under an agreement for any environmental matters related to the Missouri Properties purchased by Southern Union pending at the date of the sale or that may arise after closing. For any environmental matters pending or discovered within two years of the date of the agreement, and after pursuing several other potential recovery options, the Company may be liable for up to a maximum of $7.5 million under a sharing arrangement with Southern Union provided for in the agreement.
Spent Nuclear Fuel Disposal: Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from nuclear reactors. Under a contract with the DOE for disposal of spent nuclear fuel, the Company pays a quarterly fee to DOE of one mill per kilowatthour on net nuclear generation. These fees are included as part of nuclear fuel expense and amounted to $3.8 million for 1994, $3.5 million for 1993, and $1.6 million for 1992.
The Company along with the other co-owners of Wolf Creek are among 14 companies that filed a lawsuit on June 20, 1994, seeking an interpretation of the DOE's obligation to begin accepting spent nuclear fuel for disposal in 1998. The Federal Nuclear Waste Policy Act requires DOE ultimately to accept and dispose of nuclear utilities' spent fuel. The DOE has filed a motion to have this case dismissed. The issue to be decided in this case is whether DOE must begin accepting spent fuel in 1998 or at a future date. Wolf Creek contains an on-site spent fuel storage facility which, under current regulatory guidelines, provides space for the storage of spent fuel through the year 2006 while still maintaining full core off-load capability. The Company believes adequate additional storage space can be obtained as necessary.
Decommissioning: On June 9, 1994, the KCC issued an order approving the decommissioning costs of the 1993 Wolf Creek Decommissioning Cost Study which estimates the Company's share of Wolf Creek decommissioning costs, under the immediate dismantlement method, to be approximately $595 million primarily during the period 2025 through 2033, or approximately $174 million in 1993 dollars. These costs were calculated using an assumed inflation rate of 3.45% over the remaining service life, in 1993, of 32 years.
Decommissioning costs are being charged to operating expenses in accordance with the KCC order. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts so expensed ($3.5 million in 1994 increasing annually to $5.5 million in 2024) and earnings on trust fund assets are deposited in an external trust fund. The assumed return on trust assets is 5.9%. The Company's investment in the decommissioning fund, including reinvested earnings was $16.9 million and $13.2 million at December 31, 1994 and December 31, 1993, respectively. These amounts are reflected in Decommissioning Trust, and the related liability is included in Deferred Credits and Other Liabilities, Other, on the Consolidated Balance Sheets.
The Company carries $118 million in premature decommissioning insurance. The insurance coverage has several restrictions. One of these is that it can only be used if Wolf Creek incurs an accident exceeding $500 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor station site in accordance with a plan approved by the Nuclear Regulatory Commission (NRC), and to pay for on-site property damages. If the amount designated as decommissioning insurance is needed to implement the NRC- approved plan for stabilization and decontamination, it would not be available for decommissioning purposes.
Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $8.9 billion for a single nuclear incident. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million and the balance is provided by an assessment plan mandated by the NRC. Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $79.3 million ($37.3 million, Company's share) in the event there is a 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 totalling approximately $2.8 billion ($1.3 billion, Company's share). This insurance is provided by a combination of "nuclear insurance pools" ($500 million) and Nuclear Electric Insurance Limited (NEIL) ($2.3 billion). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. The Company's share of any remaining proceeds can be used for property damage up to $1.2 billion (Company's share) and premature decommissioning costs up to $118 million (Company's share) in 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 of approximately $13 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. Federal Income Taxes: During 1991, the Internal Revenue Service (IRS) completed an examination of KG&E's federal income tax returns for the years 1984 through 1988. In April 1992, KG&E received the examination report and upon review filed a written protest in August 1992. In October 1993, KG&E received another examination report for the years 1989 and 1990 covering the same issues identified in the previous examination report. Upon review of this report, KG&E filed a written protest in November 1993. The most significant proposed adjustments reduce the depreciable basis of certain assets and investment tax credits generated. Management believes there are significant questions regarding the theory, computations, and sampling techniques used by the IRS to arrive at its proposed adjustments, and also believes any additional tax expense incurred or loss of investment tax credits will not be material to the Company's financial position and results of operations. Additional income tax payments, if any, are expected to be offset by investment tax credit carryforwards, alternative minimum tax credit carryforwards, or deferred tax provisions.
Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the Company has entered into various commitments to obtain nuclear fuel, coal, and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1994, WCNOC's nuclear fuel commitments (Company's share) were approximately $12.6 million for uranium concentrates expiring at various times through 1997, $122.9 million for enrichment expiring at various times through 2014, and $56.5 million for fabrication through 2012. At December 31, 1994, the Company's coal and natural gas contract commitments in 1994 dollars under the remaining terms of the contracts were approximately $3 billion and $9 million, respectively. The largest coal contract expires in 2020, with the remaining coal contracts expiring at various times through 2013. The majority of natural gas contracts continue through 1995 with automatic one-year extension provisions. In the normal course of business, additional commitments and spot market purchases will be made to obtain adequate fuel supplies.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment, decontamination, and decommissioning fund. The Company's portion of the assessment for Wolf Creek is approximately $7 million, payable over 15 years. Management expects such costs to be recovered through the ratemaking process.
8. EMPLOYEE BENEFIT PLANS
Pension: The Company maintains noncontributory defined benefit pension plans covering substantially all employees. Pension benefits are based on years of service and the employee's compensation during the five highest paid consecutive years out of ten before retirement. The Company's policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code. The following tables provide information on the components of pension cost, funded status, and actuarial assumptions for the Company's pension plans:
Year Ended December 31, 1994 1993 1992 (Dollars in Thousands) Pension Cost: Service cost. . . . . . . . . . $ 10,197 $ 9,778 $ 9,847 Interest cost on projected benefit obligation. . . . . . 29,734 35,688 29,457 (Gain) loss on plan assets. . . 7,351 (64,113) (38,967) Deferred investment gain (loss) (38,457) 29,190 7,705 Net amortization. . . . . . . . 245 (669) (948) Net pension cost. . . . . . $ 9,070 $ 9,874 $ 7,094
December 31, 1994 1993 1992 (Dollars in Thousands) Reconciliation of Funded Status: Actuarial present value of benefit obligations: Vested . . . . . . . . . . . $278,545 $353,023 $316,100 Non-vested . . . . . . . . . 19,132 26,983 19,331 Total. . . . . . . . . . . $297,677 $380,006 $335,431 Plan assets (principally debt and equity securities) at fair value . . . . . . . . . . . $375,521 $490,339 $452,372 Projected benefit obligation . . . 378,146 468,996 424,232 Funded status. . . . . . . . . . . (2,625) 21,343 28,140 Unrecognized transition asset. . . (2,205) (2,756) (3,092) Unrecognized prior service costs . 47,796 64,217 55,886 Unrecognized net gain. . . . . . . (56,079) (108,783) (106,486) Accrued pension costs. . . . . . . $(13,113) $(25,979) $(25,552)
Year Ended December 31, 1994 1993 1992 Actuarial Assumptions: Discount rate. . . . . . . . . . 8.0-8.5% 7.0-7.75% 8.0-8.5% Annual salary increase rate. . . 5.0% 5.0% 6.0% Long-term rate of return . . . . 8.0-8.5% 8.0-8.5% 8.0-8.5%
Retirement and Voluntary Separation Plans: In January 1992, the Board of Directors approved early retirement plans and voluntary separation programs. The voluntary early retirement plans were offered to all vested participants in the Company's defined pension plan who reached the age of 55 with 10 or more years of service on or before May 1, 1992. Certain pension plan improvements were made, including a waiver of the actuarial reduction factors for early retirement and a cash incentive payable as a monthly supplement up to 60 months or as a lump sum payment. Of the 738 employees eligible for the early retirement option, 531, representing ten percent of the combined Company's work force, elected to retire on or before the May 1, 1992, deadline. Seventy-one of those electing to retire were employees of KG&E acquired March 31, 1992 (see Note 3). Another 67 employees, with 10 or more years of service, elected to participate in the voluntary separation program. Of those, 29 were employees of KG&E. In addition, 68 employees received Merger-related severance benefits, including 61 employees of KG&E. The actuarial cost, based on plan provisions for early retirement and voluntary separation programs, and Merger-related severance benefits for the KG&E employees were considered in purchase accounting for the Merger. The actuarial cost of the former Kansas Power and Light Company employees, of approximately $11 million, was expensed in 1992.
Postretirement: The Company adopted the provisions of Statement of Financial Accounting Standards No. 106 (SFAS 106) in the first quarter of 1993. This statement requires the accrual of postretirement benefits other than pensions, primarily medical benefit costs, during the years an employee provides service.
Based on actuarial projections and adoption of the transition method of implementation which allows a 20-year amortization of the accumulated benefit obligation, SFAS 106 expense was approximately $12.4 million and $26.5 million for 1994 and 1993, respectively. The Company's total SFAS 106 obligation was approximately $114.6 million and $166.5 million at December 31, 1994 and 1993 respectively. The reduction in both the 1994 obligation and expense is primarily the result of the sales of the Missouri Properties. To mitigate the impact of SFAS 106 expense, the Company has implemented programs to reduce health care costs. In addition, the Company received an order from the KCC permitting the initial deferral of SFAS 106 expense. To mitigate the impact SFAS 106 expense will have on rate increases, the Company will include in the future computation of cost of service the actual SFAS 106 expense and an income stream generated from COLI. To the extent SFAS 106 expense exceeds income from the COLI program, this excess is being deferred (in accordance with the provisions of the FASB Emerging Issues Task Force Issue No. 92-12) and will be offset by income generated through the deferral period by the COLI program. Should the income stream generated by the COLI program not be sufficient to offset the deferred SFAS 106 expense, the KCC order allows recovery of such deficit through the ratemaking process.
Prior to the adoption of SFAS 106, the Company's policy was to recognize the cost of retiree health care and life insurance benefits as expense when claims and premiums for life insurance policies were paid. The cost of providing health care and life insurance benefits to 2,928 retirees was $8.1 million in 1992.
The following table summarizes the status of the Company's postretirement plans for financial statement purposes and the related amounts included in the Consolidated Balance Sheets:
December 31, 1994 1993 (Dollars in Thousands) Reconciliation of Funded Status: Actuarial present value of postretirement benefit obligations: Retirees. . . . . . . . . . . . . . . . . . . $ 68,570 $ 111,499 Active employees fully eligible . . . . . . . 13,549 11,848 Active employees not fully eligible . . . . . 32,484 43,109 Unrecognized prior service cost . . . . . . . 9,391 18,195 Unrecognized transition obligation. . . . . . (117,967) (160,731) Unrecognized net gain (loss). . . . . . . . . 14,489 (7,100) Balance sheet liability . . . . . . . . . . . . . $ 20,516 $ 16,820
Year Ended December 31, 1994 1993 Assumptions: Discount rate . . . . . . . . . . . . . . . . . 8.0-8.5 % 7.75% Annual compensation increase rate . . . . . . . 5.0 % 5.0 % Expected rate of return . . . . . . . . . . . . 8.5 % 8.5 %
For measurement purposes, an annual health care cost growth rate of 12% was assumed for 1994, decreasing 1% per year to 5% in 2001 and thereafter. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by 1% each year would increase the present value of the accumulated projected benefit obligation by $4.7 million and the aggregate of the service and interest cost components by $0.3 million.
Postemployment: The Company adopted Statement of Financial Accounting Standards No. 112 (SFAS 112) in the first quarter of 1994, which established accounting and reporting standards for postemployment benefits. The statement requires the Company to recognize the liability to provide postemployment benefits when the liability has been incurred. The Company received an order from the KCC permitting the initial deferral of SFAS 112 expense. To mitigate the impact SFAS 112 expense will have on rate increases, the Company will include in the future computation of cost of service the actual SFAS 112 transition costs and expenses and an income stream generated from COLI. The 1994 expense under SFAS 112 was approximately $2.7 million. At December 31, 1994, the Company's SFAS 112 liability recorded on the Consolidated Balance Sheet was approximately $8.4 million.
Savings: The Company maintains savings plans in which substantially all employees participate. The Company matches employees' contributions up to specified maximum limits. The funds of the plans are deposited with a trustee and invested at each employee's option in one or more investment funds, including a Company stock fund. The Company's contributions were $5.1 million, $5.8 million, and $5.4 million for 1994, 1993, and 1992, respectively.
Missouri Property Sale: Effective January 31, 1994, the Company transferred a portion of the assets and liabilities of the Company's pension plan to a pension plan established by Southern Union. The amount of assets transferred equal the projected benefit obligation for employees and retirees associated with Southern Union's portion of the Missouri Properties plus an additional $9 million.
9. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1994 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 152,816 $ 98,124 343 50 Jeffrey 1 (b) Jul 1978 276,689 122,721 587 84 Jeffrey 2 (b) May 1980 285,579 109,743 600 84 Jeffrey 3 (b) May 1983 387,646 134,199 588 84 Wolf Creek (c) Sep 1985 1,376,335 317,311 545 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL) (b) Jointly owned with 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 percent undivided interest in La Cygne 2 (representing 335 MW capacity) sold and leased back to the Company in 1987, are included in operating expenses on the Consolidated Statements of Income. The Company's share of other transactions associated with the plants is included in the appropriate classification in the Company's Consolidated Financial Statements.
10. LEASES
At December 31, 1994, the Company had leases covering various property and equipment. Certain lease agreements meet the criteria, as set forth in Statement of Financial Accounting Standards No. 13, for classification as capital leases.
Rental payments for capital and operating leases and estimated rental commitments are as follows:
Capital Operating Year Ended December 31, Leases Leases (Dollars in Thousands) 1992 $ 2,426 $ 52,701 1993 3,272 55,011 1994 2,987 55,076 Future Commitments: 1995 3,783 48,524 1996 3,627 46,211 1997 1,511 42,851 1998 - 41,464 1999 - 39,955 Thereafter - 753,062 Total $ 8,921 $972,067 Less Interest 784 Net obligation $ 8,137
In 1987, KG&E sold and leased back its 50 percent 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 percent undivided interest. KG&E 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, 1994, approximately $24.8 million of this deferral remained on the Consolidated Balance Sheet.
Future minimum annual lease payments, included in the table above, required under the La Cygne 2 lease agreement are approximately $34.6 million for each year through 1999 and $680 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale of La Cygne 2 has been deferred for financial reporting purposes, and is being amortized ($9.6 million per year) over the initial lease term in proportion to the related lease expense. KG&E's lease expense, net of amortization of the deferred gain and a one-time payment, was approximately $22.5 million for 1994 and 1993, and $20.6 million for the nine months ended December 31, 1992.
11. LONG-TERM DEBT
The amount of first mortgage bonds authorized by the Western Resources Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited. The amount of first mortgage bonds authorized by the KG&E Mortgage and Deed of Trust, 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 each Mortgage.
On January 20, 1994, KG&E issued $100 million of First Mortgage Bonds, 6.20% Series due January 15, 2006.
On January 31, 1994, the Company redeemed the remaining $2,466,000 principal amount of Gas Service Company (GSC) 8 1/2% Series First Mortgage Bonds due 1997. In addition, the Company had the GSC Mortgage and Deed of Trust discharged.
Debt discount and expenses are being amortized over the remaining lives of each issue. The Western Resources and KG&E improvement and maintenance fund requirements for certain first mortgage bond series can be met by bonding additional property. With the retirement of certain Western Resources and KG&E pollution control series bonds, there are no longer any bond sinking fund requirements. During 1995, $80 thousand of bonds will be redeemed, during 1996, $16 million of bonds will mature and $125 million of bonds will mature in 1999.
On November 1, 1994, the Company terminated a long-term agreement which contained provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables were accounted for as sales while those related to phase-in revenues were accounted for as collateralized borrowings. At December 31, 1993, outstanding receivables amounting to $56.8 million were considered sold under the agreement. The weighted average interest rate, including fees, on this agreement was 4.6% for 1994, 3.7% for 1993, and 6.6% for the nine months ended December 31, 1992.
In January 1993, the Company renegotiated its $600 million bank term loan and revolving credit facility used to finance the Merger into a $350 million revolving credit facility, secured by KG&E common stock. On October 5, 1994, the Company extended the term of this facility to expire on October 5, 1999. The unused portion of the revolving credit facility may be used to provide support for outstanding short-term debt. At December 31, 1994, there was no outstanding balance under the facility.
Long-term debt outstanding at December 31, 1994 and 1993, was as follows:
1994 1993 (Dollars in Thousands) Western Resources First mortgage bond series: 7 1/4% due 1999. . . . . . . . . . . . . 125,000 125,000 7 5/8% due 1999. . . . . . . . . . . . . - 19,000 8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000 7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000 8 1/8% due 2007. . . . . . . . . . . . . - 30,000 8 5/8% due 2017. . . . . . . . . . . . . - 50,000 8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000 7.65% due 2023. . . . . . . . . . . . . 100,000 100,000 525,000 624,000 Pollution control bond series: 5.90 % due 2007. . . . . . . . . . . . . - 31,000 6 3/4% due 2009. . . . . . . . . . . . . - 45,000 Variable due 2032 (1). . . . . . . . . . 45,000 - Variable due 2032 (2). . . . . . . . . . 30,500 - 6% due 2033. . . . . . . . . . . . . 58,500 58,500 134,000 134,500 KG&E First mortgage bond series: 5 5/8% due 1996. . . . . . . . . . . . . 16,000 16,000 7.60 % due 2003. . . . . . . . . . . . . 135,000 135,000 6 1/2% due 2005. . . . . . . . . . . . . 65,000 65,000 6.20 % due 2006. . . . . . . . . . . . . 100,000 - 316,000 216,000 Pollution control bond series: 6.80 % due 2004. . . . . . . . . . . . . - 14,500 5 7/8% due 2007. . . . . . . . . . . . . - 21,940 6% due 2007. . . . . . . . . . . . . - 10,000 5.10 % due 2023. . . . . . . . . . . . . 13,982 - Variable due 2027 (3). . . . . . . . . . 21,940 - 7.0 % due 2031. . . . . . . . . . . . . 327,500 327,500 Variable due 2032 (4). . . . . . . . . . 14,500 - Variable due 2032 (5). . . . . . . . . . 10,000 - 387,922 373,940 GSC First mortgage bond series: 8 1/2 % due 1997. . . . . . . . . . . . . - 2,466 - 2,466
Other pollution control obligations. . . . - 13,980 Revolving credit agreement . . . . . . . . - 115,000 Other long-term agreement. . . . . . . . . - 53,913 Less: Unamortized debt discount. . . . . . . . 5,814 6,607 Long-term debt due within one year . . . 80 3,204 $1,357,028 $1,523,988
Rates at December 31, 1994: (1) 3.94%, (2) 4.05%, (3) 4.10%, (4) 4.10% and (5) 4.10% 12. COMMON STOCK AND CUMULATIVE PREFERRED AND PREFERENCE STOCK
The Company's Restated Articles of Incorporation, as amended, provides for 85,000,000 authorized shares of common stock. At December 31, 1994, 61,617,873 shares were outstanding.
The Company has a Customer Stock Purchase Plan (CSPP) and a Dividend Reinvestment and Stock Purchase Plan (DRIP). Shares issued under the CSPP and DRIP may be either original issue shares or shares purchased on the open market. At December 31, 1994, 2,031,794 shares were available under the CSPP registration statement and 1,183,323 shares were available under the DRIP registration statement.
Not subject to mandatory redemption: The cumulative preferred stock is redeemable in whole or in part on 30 to 60 days notice at the option of the Company.
Subject to mandatory redemption: The mandatory sinking fund provisions of the 8.50% Series preference stock require the Company to redeem 50,000 shares annually beginning on July 1, 1997, at $100 per share. The Company may, at its option, redeem up to an additional 50,000 shares on each July 1, at $100 per share. The 8.50% Series also is redeemable in whole or in part, at the option of the Company, subject to certain restrictions on refunding, at a redemption price of $106.80, $106.23 and $105.67 per share beginning July 1, 1994, 1995 and 1996, respectively.
The mandatory sinking fund provisions of the 7.58% Series preference stock require the Company to redeem 25,000 shares annually beginning on April 1, 2002, and each April 1 through 2006 and the remaining shares on April 1, 2007, all at $100 per share. The Company may, at its option, redeem up to an additional 25,000 shares on each April 1 at $100 per share. The 7.58% Series also is redeemable in whole or in part, at the option of the Company, subject to certain restrictions on refunding, at a redemption price of $106.06, $105.31, and $104.55 per share beginning April 1, 1994, 1995, and 1996, respectively.
13. INCOME TAXES
The Company adopted the provisions of SFAS 109 in the first quarter of 1992. KG&E adopted the provisions of SFAS 96 in 1987 and SFAS 109 in 1992. These statements require the Company to establish deferred tax assets and liabilities, as appropriate, for all temporary differences, and to adjust deferred tax balances to reflect changes in tax rates expected to be in effect during the periods the temporary differences reverse.
In accordance with various rate orders received from the KCC and the OCC, the Company has not yet collected through rates the amounts necessary to pay a significant portion of the net deferred income tax liabilities. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers through future rates, it has recorded a deferred asset for these amounts. These assets are also a temporary difference for which deferred income tax liabilities have been provided. Accordingly, the adoption of SFAS 109 did not have a material impact on the Company's results of operations. At December 31, 1994, the Company has alternative minimum tax credits generated prior to April 1, 1992, which carryforward without expiration, of $41.2 million which may be used to offset future regular tax to the extent the regular tax exceeds the alternative minimum tax. These credits have been applied in determining the Company's net deferred income tax liability and corresponding deferred future income taxes at December 31, 1994.
Deferred income taxes result from temporary differences between the financial statement and tax basis of the Company's assets and liabilities. The sources of these differences and their cumulative tax effects are as follows:
December 31, 1994 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (661,433) $ (661,433) Energy and purchased gas adjustment clauses . . . . . . . - (1,441) (1,441) Phase-in revenues. . . . . . . . . - (27,677) (27,677) Natural gas line survey and replacement program. . . . . . . - (4,083) (4,083) Deferred gain on sale-leaseback. . 110,556 - 110,556 Alternative minimum tax credits. . 41,163 - 41,163 Deferred coal contract settlements. . . . . . . . . . . - (12,966) (12,966) Deferred compensation/pension liability. . . . . . . . . . . . 12,284 - 12,284 Acquisition premium. . . . . . . . - (318,190) (318,190) Deferred future income taxes . . . - (101,886) (101,886) Loss on reacquisition of debt. . . - (10,792) (10,792) Prepaid power sale . . . . . . . . 16,878 - 16,878 Other. . . . . . . . . . . . . . . - (13,427) (13,427) Total Deferred Income Taxes. . . . . $ 180,881 $(1,151,895) $ (971,014)
December 31, 1993 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (653,592) $ (653,592) Energy and purchased gas adjustment clauses . . . . . . . 2,452 - 2,452 Phase-in revenues. . . . . . . . . - (35,573) (35,573) Natural gas line survey and replacement program. . . . . . . - (7,721) (7,721) Deferred gain on sale-leaseback. . 116,186 - 116,186 Alternative minimum tax credits. . 39,882 - 39,882 Deferred coal contract settlements. . . . . . . . . . . - (14,980) (14,980) Deferred compensation/pension liability. . . . . . . . . . . . 11,301 - 11,301 Acquisition premium. . . . . . . . - (301,394) (301,394) Deferred future income taxes . . . - (111,159) (111,159) Loss on reacquisition of debt. . . - (9,298) (9,298) Other. . . . . . . . . . . . . . . - (4,741) (4,741) Total Deferred Income Taxes. . . . . $ 169,821 $(1,138,458) $(968,637) 14. SEGMENTS OF BUSINESS
The Company is a public utility engaged in the generation, transmission, distribution, and sale of electricity in Kansas and the transportation, distribution, and sale of natural gas in Kansas and Oklahoma.
Year Ended December 31, 1994(1) 1993 1992(2) (Dollars in Thousands) Operating revenues: Electric. . . . . . . . . . . $1,121,781 $1,104,537 $ 882,885 Natural gas . . . . . . . . . 496,162 804,822 673,363 1,617,943 1,909,359 1,556,248 Operating expenses excluding income taxes: Electric. . . . . . . . . . . 768,317 791,563 632,169 Natural gas . . . . . . . . . 484,458 747,755 642,910 1,252,775 1,539,318 1,275,079 Income taxes: Electric. . . . . . . . . . . 100,078 73,425 41,184 Natural gas . . . . . . . . . (4,456) 4,553 816 95,622 77,978 42,000 Operating income: Electric. . . . . . . . . . . 253,386 239,549 209,532 Natural gas . . . . . . . . . 16,160 52,514 29,637 $ 269,546 $ 292,063 $ 239,169
Identifiable assets at December 31: Electric. . . . . . . . . . . $4,346,312 $4,231,277 $4,390,117 Natural gas . . . . . . . . . 654,483 1,040,513 918,729 Other corporate assets(3) . . 188,823 140,258 130,060 $5,189,618 $5,412,048 $5,438,906 Other Information-- Depreciation and amortization: Electric. . . . . . . . . . . $ 123,696 $ 126,034 $ 105,842 Natural gas . . . . . . . . . 27,934 38,330 38,171 $ 151,630 $ 164,364 $ 144,013 Maintenance: Electric. . . . . . . . . . . $ 88,162 $ 87,696 $ 73,104 Natural gas . . . . . . . . . 25,024 30,147 28,507 $ 113,186 $ 117,843 $ 101,611 Capital expenditures: Electric. . . . . . . . . . . $ 152,384 $ 137,874 $ 95,465 Nuclear fuel. . . . . . . . . 20,590 5,702 15,839 Natural gas . . . . . . . . . 64,722 94,055 91,189 $ 237,696 $ 237,631 $ 202,493
(1)Information reflects the sales of the Missouri Properties (Note 2). (2)Information reflects the merger with KG&E on March 31, 1992 (Note 3). (3)Principally cash, temporary cash investments, non-utility assets, and deferred charges.
The portion of the table above related to the Missouri Properties is as follows:
1994 1993 1992 (Dollars in Thousands, Unaudited) Natural gas revenues. . . . . . . . . $ 77,008 $349,749 $299,202 Operating expenses excluding income taxes. . . . . . . . 69,114 326,329 288,558 Income taxes. . . . . . . . . . . . . 2,897 2,672 (533) Operating income. . . . . . . . . . . 4,997 20,748 11,177 Identifiable assets . . . . . . . . . - 398,464 361,612 Depreciation and amortization . . . . 1,274 12,668 13,172 Maintenance . . . . . . . . . . . . . 1,099 10,504 9,640 Capital expenditures. . . . . . . . . 3,682 38,821 36,669
15. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in Statement of Financial Accounting Standards No. 107:
Cash and Cash Equivalents- The carrying amount approximates the fair value because of the short-term maturity of these investments. Decommissioning Trust- The fair value of the decommissioning trust is based on quoted market prices at December 31, 1994 and 1993. Variable-rate Debt- The carrying amount approximates the fair value because of the short-term variable rates of these debt instruments. Fixed-rate Debt- The fair value of the fixed-rate debt is based on the sum of the estimated value of each issue taking into consideration the interest rate, maturity, and redemption provisions of each issue. Redeemable Preference Stock- The fair value of the redeemable preference stock is based on the sum of the estimated value of each issue taking into consideration the dividend rate, maturity, and redemption provisions of each issue.
The estimated fair values of the Company's financial instruments are as follows:
Carrying Value Fair Value December 31, 1994 1993 1994 1993 (Dollars in Thousands) Cash and cash equivalents. . . . . . . $ 2,715 $ 1,217 $ 2,715 $ 1,217 Decommissioning trust. . . 16,944 13,204 16,633 13,929 Variable-rate debt . . . . 822,045 931,352 822,045 931,352 Fixed-rate debt. . . . . . 1,240,982 1,364,886 1,171,866 1,473,569 Redeemable preference stock. . . . . . . . . . 150,000 150,000 155,375 160,780
The fair value estimates presented herein are based on information available as of December 31, 1994 and 1993. 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.
16. QUARTERLY RESULTS (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.
First Second Third Fourth (Dollars in Thousands, except Per Share Amounts) 1994(1) Operating revenues. . . . . . . $538,372 $341,132 $379,213 $359,226 Operating income. . . . . . . . 73,782 53,899 83,884 57,981 Net income. . . . . . . . . . . 66,133 30,247 57,679 33,388 Earnings applicable to common stock. . . . . . . . . 62,779 26,892 54,324 30,034 Earnings per share. . . . . . . $ 1.02 $ 0.44 $ 0.88 $ 0.48 Dividends per share . . . . . . $ 0.495 $ 0.495 $ 0.495 $ 0.495 Average common shares outstanding . . . . . . . . . 61,618 61,618 61,618 61,618 Common stock price: High. . . . . . . . . . . . . $ 34 7/8 $ 29 3/4 $ 29 5/8 $ 29 1/4 Low . . . . . . . . . . . . . $ 28 1/4 $ 26 1/8 $ 26 3/4 $ 27 3/8
Operating revenues. . . . . . . $579,581 $400,411 $419,018 $510,349 Operating income. . . . . . . . 85,950 60,282 81,225 64,606 Net income. . . . . . . . . . . 54,814 30,723 56,807 35,026 Earnings applicable to common stock. . . . . . . . . 51,468 27,320 53,405 31,671 Earnings per share. . . . . . . $ 0.89 $ 0.47 $ 0.90 $ 0.51 Dividends per share . . . . . . $ 0.485 $ 0.485 $ 0.485 $ 0.485 Average common shares outstanding . . . . . . . . . 58,046 58,046 59,441 61,603 Common stock price: High. . . . . . . . . . . . . $ 35 3/4 $ 36 1/8 $ 37 1/4 $ 37 Low . . . . . . . . . . . . . $ 30 3/8 $ 32 3/4 $ 35 $ 32 3/4
(1) Information reflects the sales of the Missouri Properties (Note 2).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to the Company's Directors required by Item 10 is set forth in the Company's definitive proxy statement for its 1995 Annual Meeting of Shareholders to be filed with the Commission. Such information is incorporated herein by reference to the material appearing under the caption Election of Directors in the proxy statement to be filed by the Company with the Commission. See EXECUTIVE OFFICERS OF THE COMPANY on page 19 for the information relating to the Company's Executive Officers as required by Item 10.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is set forth in the Company's definitive proxy statement for its 1995 Annual Meeting of Shareholders to be filed with the Commission. Such information is incorporated herein by reference to the material appearing under the captions Information Concerning the Board of Directors, Executive Compensation, Compensation Plans, and Human Resources Committee Report in the proxy statement to be filed by the Company with the Commission.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is set forth in the Company's definitive proxy statement for its 1995 Annual Meeting of Shareholders to be filed with the Commission. Such information is incorporated herein by reference to the material appearing under the caption Beneficial Ownership of Voting Securities in the proxy statement to be filed by the Company with the Commission.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None. PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
The following financial statements are included herein.
FINANCIAL STATEMENTS
Report of Independent Public Accountants Consolidated Balance Sheets, December 31, 1994 and 1993 Consolidated Statements of Income, for the years ended December 31, 1994, 1993 and 1992 Consolidated Statements of Cash Flows, for the years ended December 31, 1994, 1993 and 1992 Consolidated Statements of Taxes, for the years ended December 31, 1994, 1993 and 1992 Consolidated Statements of Capitalization, December 31, 1994 and Consolidated Statements of Common Stock Equity, for the years ended December 31, 1994, 1993 and 1992 Notes to Consolidated Financial Statements
SCHEDULES
Schedules omitted as not applicable or not required under the Rules of regulation S-X: I, II, III, IV, and V
REPORTS ON FORM 8-K Form 8-K dated January 25, 1995.
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) -Restated Articles of Incorporation of the Company, as amended I May 25, 1988. (filed as Exhibit 4 to Registration Statement No. 33-23022) 3(b) -Certificate of Correction to Restated Articles of Incorporation. I (filed as Exhibit 3(b) to the December 1991 Form 10-K) 3(c) -Amendment to the Restated Articles of Incorporation, as amended May 5, 1992 (filed electronically) 3(d) -Amendments to the Restated Articles of Incorporation of the I Company (filed as Exhibit 3 to the June 1994 Form 10-Q) 3(e) -By-laws of the Company, as amended July 15, 1987. (filed as I Exhibit 3(d) to the December 1987 Form 10-K) 3(f) -Certificate of Designation of Preference Stock, 8.50% Series, I without par value. (filed as Exhibit 3(d) to the December 1993 Form 10-K) 3(g) -Certificate of Designation of Preference Stock, 7.58% Series, I without par value. (filed as Exhibit 3(e) to the December 1993 Form 10-K) 4(a) -Mortgage and Deed of Trust dated July 1, 1939 between the Company I and Harris Trust and Savings Bank, Trustee. (filed as Exhibit 4(a) to Registration Statement No. 33-21739) 4(b) -First through Fifteenth Supplemental Indentures dated July 1, I 1939, April 1, 1949, July 20, 1949, October 1, 1949, December 1, 1949, October 4, 1951, December 1, 1951, May 1, 1952, October 1, 1954, September 1, 1961, April 1, 1969, September 1, 1970, February 1, 1975, May 1, 1976 and April 1, 1977, respectively. (filed as Exhibit 4(b) to Registration Statement No. 33-21739) 4(c) -Sixteenth Supplemental Indenture dated June 1, 1977. (filed as I Exhibit 2-D to Registration Statement No. 2-60207) 4(d) -Seventeenth Supplemental Indenture dated February 1, 1978. I (filed as Exhibit 2-E to Registration Statement No. 2-61310) 4(e) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I as Exhibit (b) (1)-9 to Registration Statement No. 2-64231) 4(f) -Nineteenth Supplemental Indenture dated May 1, 1980. (filed as I Exhibit 4(f) to Registration Statement No. 33-21739) 4(g) -Twentieth Supplemental Indenture dated November 1, 1981. (filed I as Exhibit 4(g) to Registration Statement No. 33-21739) 4(h) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I as Exhibit 4(h) to Registration Statement No. 33-21739) 4(i) -Twenty-Second Supplemental Indenture dated February 1, 1983. I (filed as Exhibit 4(i) to Registration Statement No. 33-21739) 4(j) -Twenty-Third Supplemental Indenture dated July 2, 1986. (filed I as Exhibit 4(j) to Registration Statement No. 33-12054) 4(k) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. (filed I as Exhibit 4(k) to Registration Statement No. 33-21739) 4(l) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I (filed as Exhibit 4 to the September 1988 Form 10-Q) 4(m) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I (filed as Exhibit 4(m) to the December 1989 Form 10-K) Description
4(n) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I (filed as exhibit 4(n) to the December 1991 Form 10-K) 4(o) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I (filed as exhibit 4(o) to the December 1992 Form 10-K) 4(p) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I (filed as exhibit 4(p) to the December 1992 Form 10-K) 4(q) -Thirtieth Supplemental Indenture dated February 1, 1993. I (filed as exhibit 4(q) to the December 1992 Form 10-K) 4(r) -Thirty-First Supplemental Indenture dated April 15, 1993. I (filed as exhibit 4(r) to Form S-3, Registration Statement No. 33-50069) 4(s) -Thirty-Second Supplemental Indenture dated April 15, 1994, (filed electronically)
Instruments defining the rights of holders of other long-term debt not required to be filed as exhibits will be furnished to the Commission upon request.
10(a) -A Rail Transportation Agreement among Burlington Northern I Railroad Company, the Union Pacific Railroad Company and the Company (filed as Exhibit 10 to the June 1994 Form 10-Q) 10(b) -Agreement between the Company and AMAX Coal West Inc. I effective March 31, 1993. (filed as Exhibit 10(a) to the December 1993 Form 10-K) 10(c) -Agreement between the Company and Williams Natural Gas Company I dated October 1, 1993. (filed as Exhibit 10(b) to the December 1993 Form 10-K) 10(d) -Agreement between the Company and Williams Natural Gas Company I dated October 1, 1993. (filed as Exhibit 10(c) to the December 1993 Form 10-K) 10(e) -Agreement between the Company and Williams Natural Gas Company I dated October 1, 1993. (filed as Exhibit 10(d) to the December 1993 Form 10-K) 10(f) -Executive Salary Continuation Plan of The Kansas Power and Light I Company, as revised, effective May 3, 1988. (filed as Exhibit 10(b) to the September 1988 Form 10-Q) 10(g) -Letter of Agreement between The Kansas Power and Light Company I and John E. Hayes, Jr., dated November 20, 1989. (filed as Exhibit 10(w) to the December 1989 Form 10-K) 10(h) -Amended Agreement and Plan of Merger by and among The Kansas I Power and Light Company, KCA Corporation, and Kansas Gas and Electric Company, dated as of October 28, 1990, as amended by Amendment No. 1 thereto, dated as of January 18, 1991. (filed as Annex A to Registration Statement No. 33-38967) 10(i) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I December 1993 Form 10-K) 10(j) -Long-term Incentive Plan (filed as Exhibit 10(j) to the I December 1993 Form 10-K) 10(k) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I December 1993 Form 10-K) 10(l) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I 10(l) to the December 1993 Form 10-K) Description
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges. (filed electronically) 16 -Letter re Change in Certifying Accountant. (filed as Exhibit 16 I to the Current Report on Form 8-K dated March 8, 1993) 21 -Subsidiaries of the Registrant. (filed electronically) 23(a) -Consent of Independent Public Accountants, Arthur Andersen LLP (filed electronically) 23(b) -Consent of Independent Public Accountants, Deloitte & Touche LLP (filed electronically) 27 -Financial Data Schedules (filed electronically) 99 -Kansas Gas and Electric Company's Annual Report on Form 10-K for the year ended December 31, 1994 (filed electronically)
SIGNATURE
Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WESTERN RESOURCES, INC.
March 29, 1995 By JOHN E. HAYES, JR. John E. Hayes, Jr., Chairman of the Board, President, and Chief Executive Officer
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Signature Title Date
Chairman of the Board, President, JOHN E. HAYES, JR. and Chief Executive Officer March 29, 1995 (John E. Hayes, Jr.) (Principal Executive Officer)
Executive Vice President and S. L. KITCHEN Chief Financial Officer March 29, 1995 (S. L. Kitchen) (Principal Financial and Accounting Officer)
FRANK J. BECKER (Frank J. Becker)
GENE A. BUDIG (Gene A. Budig)
C. Q. CHANDLER (C. Q. Chandler)
THOMAS R. CLEVENGER (Thomas R. Clevenger)
JOHN C. DICUS Directors March 29, 1995 (John C. Dicus)
DAVID H. HUGHES (David H. Hughes)
RUSSELL W. MEYER, JR. (Russell W. Meyer, Jr.)
JOHN H. ROBINSON (John H. Robinson)
MARJORIE I. SETTER (Marjorie I. Setter)
LOUIS W. SMITH (Louis W. Smith)
KENNETH J. WAGNON (Kenneth J. Wagnon)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION
GENERAL: Earnings were $2.82 per share of common stock based on 61,617,873 average common shares for 1994, an increase from $2.76 in 1993 on 59,294,091 average common shares. Net income for 1994 increased to $187.4 million compared to $177.4 million in 1993. The increase in net income and earnings per share is a result of the gain on the sale of the Company's natural gas distribution properties and operations in the State of Missouri, reduced interest expense, and higher electric sales combined with lower fuel costs.
Dividends increased four cents per common share in 1994 to $1.98 per share. In January 1995, the Board of Directors declared a quarterly dividend of 50 1/2 cents per common share, an increase of one cent over the previous quarter. Based on currently projected operating results, the Company does not anticipate a material change in its dividend policy or payout ratio (approximately 70 percent in 1994) in 1995.
The book value per share was $23.93 at December 31, 1994, compared to $23.08 at December 31, 1993. The 1994 closing stock price of $28 5/8 was 120 percent of book value. There were 61,617,873 common shares outstanding at December 31, 1994.
On January 31, 1994, the Company sold substantially all of its Missouri natural gas distribution properties and operations to Southern Union Company (Southern Union). The Company sold the remaining Missouri properties to United Cities Gas Company (United Cities) on February 28, 1994. The properties sold to Southern Union and United Cities are referred to herein as the "Missouri Properties." With the sales the Company is no longer operating as a utility in the State of Missouri.
The portion of the Missouri Properties purchased by Southern Union was sold for an estimated sale price of $400 million, in cash, based on a calculation as of December 31, 1993. United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri, for $665,000 in cash.
As a result of the sales of the Missouri Properties, as described in Note 2 of the Notes to Consolidated Financial Statements, the Company recognized a gain of approximately $19.3 million, net of tax, ($0.31 per share) and ceased recording the results of operations for the Missouri Properties during the first quarter of 1994. Consequently, the Company's results of operations for the twelve months ended December 31, 1994 are not comparable to the results of operations for the same periods ending December 31, 1993 and 1992. The following table reflects, through the dates of the sales of the Missouri Properties, the approximate operating revenues and operating income for the years ended December 31, 1994, 1993, and 1992, and net utility plant at December 31, 1993 and 1992, related to the Missouri Properties (see Note 2):
1994 1993 1992
Percent Percent Percent of Total of Total of Total Amount Company Amount Company Amount Company
(Dollars in Thousands, Unaudited)
Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2% Operating income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7% Net utility plant . . - - 296,039 6.6% 272,126 6.1%
Separate audited financial information was not kept by the Company for the Missouri Properties. This unaudited financial information is based on assumptions and allocations of expenses of the Company as a whole.
For additional information regarding the sales of the Missouri Properties and the pending litigation see Notes 2 and 4 of the Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES: The Company's liquidity is a function of its ongoing construction program, designed to improve facilities which provide electric and natural gas service and meet future customer service requirements.
During 1994, construction expenditures for the Company's electric system were approximately $152 million and nuclear fuel expenditures were approximately $21 million. It is projected that adequate capacity margins will be maintained without the addition of any major generating facilities through the turn of the century. The construction expenditures for improvements on the natural gas system, including the Company's service line replacement program, were approximately $65 million during 1994.
Capital expenditures for 1995 through 1997 are anticipated to be as follows:
Electric Nuclear Fuel Natural Gas (Dollars in Thousands) 1995. . . . . $131,300 $ 21,400 $ 45,700 1996. . . . . 114,500 8,100 58,700 1997. . . . . 108,500 24,000 58,100
These expenditures are estimates prepared for planning purposes and are subject to revisions from time to time (see Note 7).
The Company's net cash flows to capital expenditures was 97 percent for 1994 and during the last five years has averaged 98 percent. The Company anticipates all of its cash requirements for capital expenditures through 1997 will be provided from net cash flows. The Company's capital needs through 1999 for bond maturities and cash sinking fund requirements for bonds and preference stock are approximately $156 million. This capital will be provided from internal and external sources available under then existing financial conditions.
The embedded cost of long-term debt was 7.6% at December 31, 1994, a decrease from 8.1% at December 31, 1993. The decrease was primarily accomplished through refinancing of higher cost debt.
The Company's short-term financing requirements are satisfied, as needed, through the sale of commercial paper, short-term bank loans and borrowings under unsecured lines of credit maintained with banks. At December 31, 1994, short-term borrowings amounted to $308.2 million, of which $157.2 million was commercial paper (see Notes 6 and 11). At December 31, 1994, the Company had bank credit arrangements available of $145 million.
The Company's short-term debt balance at December 31, 1994, decreased approximately $132.7 million from December 31, 1993. The decrease is primarily a result of the use of the proceeds from the sales of the Missouri Properties and the issuance, on January 20, 1994, of $100 million of Kansas Gas and Electric Company (KG&E) first mortgage bonds, 6.20% Series due January 15, 2006.
In January 1994, the Company entered into an agreement with Oklahoma Municipal Power Authority (OMPA). Under the agreement, the Company received a prepayment of approximately $41 million for which the Company will provide capacity and transmission services to OMPA through the year 2013.
On January 31, 1994, the Company redeemed the remaining $2,466,000 principal amount of Gas Service Company 8 1/2% Series First Mortgage Bonds due 1997.
On February 17, 1994, KG&E refinanced the City of La Cygne, Kansas, 5 3/4% Pollution Control Revenue Refunding Bonds Series 1973, $13,980,000 principal amount, with 5.10% Pollution Control Revenue Refunding Bonds Series 1994, $13,982,500 principal amount, due 2023.
On March 4, 1994, the Company retired the following First Mortgage Bonds: $19 million of 7 5/8% Series due April 1, 1999, $30 million of 8 1/8% Series due June 1, 2007, and $50 million of 8 5/8% Series due March 1, 2017.
On April 28, 1994, two series of Market-Adjusted Tax Exempt Securities (MATES) totalling $75.5 million were sold on behalf of the Company and three series of MATES totalling $46.4 million were sold on behalf of KG&E. The rate on these bonds was 2.95% for the initial auction period. The interest rates are being reset periodically via an auction process. As of December 31, 1994, the rates on these bonds ranged from 3.94% to 4.10%. The net proceeds from the new issues, together with available cash, were used to refund five series of pollution control bonds totalling $121.9 million bearing interest rates between 5 7/8% and 6.8%.
On October 5, the Company extended the term of its $350 million revolving credit facility which will now expire on October 5, 1999.
On November 1, 1994, KG&E terminated a long-term agreement which contained provisions for the sale of accounts receivable and unbilled revenues, and phase-in revenues (see Note 11). The Company has a Customer Stock Purchase Plan (CSPP) and a Dividend Reinvestment and Stock Purchase Plan (DRIP). Shares issued under the CSPP and DRIP may be either original issue shares or shares purchased on the open market.
The Company's capital structure at December 31, 1994, was 49 percent common stock equity, 6 percent preferred and preference stock, and 45 percent long-term debt. The capital structure at December 31, 1994, including short-term debt and current maturities of long-term debt, was 45 percent common stock equity, 5 percent preferred and preference stock, and 50 percent debt. As of December 31, 1994, the Company's bonds were rated "A3" by Moody's Investors Service, "A-" by Standard & Poor's Ratings Group, and "A-" by Fitch Investors Service.
RESULTS OF OPERATIONS
The following is an explanation of significant variations from prior year results in revenues, operating expenses, other income and deductions, interest charges and preferred and preference dividend requirements. The results of operations of the Company include the activities of KG&E since the merger on March 31, 1992, and exclude the activities related to the Missouri Properties following the sales of those properties in the first quarter of 1994.
For additional information regarding the sales of the Missouri Properties and the pending litigation, see Notes 2 and 4 of the Notes to Consolidated Financial Statements. Additional information relating to changes between years is provided in the Notes to Consolidated Financial Statements.
REVENUES
The operating revenues of the Company are based on sales volumes and rates authorized by certain state regulatory commissions and the Federal Energy Regulatory Commission (FERC). Rates, charged for the sale and delivery of natural gas and electricity, are designed to recover the cost of service and allow investors a fair rate of return. Future natural gas and electric sales will be affected by weather conditions, competition from other generating sources, competing fuel sources, customer conservation efforts, and the overall economy of the Company's service area.
The Kansas Corporation Commission (KCC) order approving the merger with KG&E on March 31, 1992 (Merger), provided a moratorium on increases, with certain exceptions, in the Company's jurisdictional electric and natural gas rates until August 1995. The KCC ordered refunds totalling $32 million to the combined companies' customers to share with customers the Merger-related cost savings achieved during the moratorium period. Refunds of $8.5 million were made in April 1992 and December 1993 and the remaining refund of $15 million was made in September 1994 (see Note 3).
On March 26, 1992, in connection with the Merger, the KCC approved the elimination of the Energy Cost Adjustment Clause for most Kansas retail electric customers of both the Company and KG&E effective April 1, 1992. The fuel costs are now included in base rates and were established at a level intended by the KCC to equal the projected average cost of fuel through August 1995. Any variance in fuel costs from the projected average will impact the Company's earnings.
Future natural gas revenues will be reduced as a result of the sales of the Missouri Properties. The Consolidated Statements of Income include revenues of $77 million for the portion of the first quarter of 1994 prior to the sales of the Missouri Properties, $350 million for 1993 and $299 million for 1992. Following the sales of the Missouri Properties and during 1995 and beyond, there will be no revenues related to the Missouri Properties (see Note 2).
1994 Compared to 1993: Electric revenues increased two percent during 1994 primarily as a result of a four percent increase in commercial and industrial electric sales. Residential electric sales increased one percent despite four percent cooler temperatures during the primary air conditioning load months of June, July, and August. Partially offsetting these increases in electric revenues was a fourteen percent decrease in wholesale and interchange sales as a result of higher than normal sales in 1993 to other utilities while their generating units were down due to the flooding of 1993.
Natural gas revenues and sales decreased significantly in 1994 as a result of the sales of the Missouri Properties in the first quarter of 1994 (see Note 2). Also contributing to the decrease in natural gas revenues were reduced natural gas sales for space heating as a result of much warmer temperatures during the winter season of 1994 compared to 1993.
1993 Compared to 1992: Electric revenues increased significantly in 1993 as a result of the Merger. Also contributing to the increase was increased electric sales for space heating, resulting from colder winter temperatures in the first quarter of 1993, and increased sales for cooling load, resulting from warmer temperatures in the second and third quarters of 1993. KG&E electric revenues of $617 million have been included in the Company's 1993 electric revenues. This compares to KG&E revenues of $424 million, from April 1, 1992, through December 31, 1992, included in the Company's 1992 electric revenues. Partially offsetting these increases in electric revenues was the amortization of the Merger-related customer refund.
Electric revenues for 1993 compared to pro forma revenues for 1992, giving effect to the Merger as if it had occurred at January 1, 1992, would have increased as a result of the warmer summer and colder winter temperatures in 1993. Retail sales of kilowatt hours on a pro forma comparative basis increased from approximately 14.6 billion for 1992 to approximately 15.5 billion for 1993, or six percent.
Natural gas revenues for 1993 increased approximately 20 percent as a result of increased sales caused by colder winter temperatures, the full impact of increased retail natural gas rates (see Note 5), and an 11 percent increase in the unit cost of gas passed on to customers through the purchased gas adjustment clauses (PGA). The colder winter temperatures are reflected in a 17 percent increase in natural gas sales to residential customers.
OPERATING EXPENSES
1994 Compared to 1993: Total operating expenses decreased 17 percent during 1994 primarily as a result of the sales of the Missouri Properties (Note 2). Also contributing to the decrease were lower fuel costs for electric generation and reduced natural gas purchases as a result of lower sales caused by milder winter temperatures in 1994 compared to 1993.
Partially offsetting the decreases in operating expenses was higher income tax expense. As of December 31, 1993, KG&E had fully amortized its deferred income tax reserves related to the allowance for borrowed funds used during construction capitalized for Wolf Creek Generating Station. The completion of the amortization of these deferred income tax reserves increased income tax expense and thereby reduced net income by approximately $12 million in 1994, and in the future will reduce net income by this same amount each year.
1993 Compared to 1992: Operating expenses increased for 1993 primarily as a result of the Merger. KG&E operating expenses of $470 million have been included in the Company's operating expenses for the year ended December 31, 1993. This compares to KG&E operating expenses of $316 million, from April 1, 1992, through December 31, 1992, included in the Company's 1992 operating expenses.
Other factors, excluding the Merger, contributing to the increase in operating expenses were higher fuel and purchased power expenses caused by increased electric sales to meet cooling load and increased natural gas purchases caused by a 16 percent increase in natural gas sales and an 11 percent higher unit cost of gas which is passed on to customers through the PGA.
Also contributing to the increase were higher general taxes due to increases in plant, the property tax assessment ratio, and higher mill levies. A constitutional amendment in Kansas changed the assessment on utility property from 30 to 33 percent. As a result of this change the Company had an increased property tax expense of approximately $6.1 million in 1993.
Partially offsetting the increases were savings as a result of the Merger and reduced net lease expense for La Cygne 2 resulting from refinancing of secured facility bonds (see Note 10).
OTHER INCOME AND DEDUCTIONS: Other income and deductions, net of taxes, was higher for the twelve months ended December 31, 1994 compared to 1993 due to the recognition of the gain on the sales of the Missouri Properties of approximately $19.3 million, net of tax, (see Note 2). Partially offsetting this increase was increased interest expense on corporate-owned life insurance (COLI) borrowings. Also partially offsetting the increase was the recognition of income in 1993 from death proceeds from COLI policies.
Other income and deductions, net of taxes, increased $1.3 million in 1993 compared to 1992. KG&E other income and deductions, net of taxes, of $19 million have been included in the Company's total for 1993 compared to $17 million in 1992 from April 1, through December 31, 1992. Income from KG&E's COLI totalled $8 million in 1993. INTEREST CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS: Total interest charges decreased 17 percent for the twelve months ended December 31, 1994, as a result of lower debt balances and the refinancing of higher cost debt, as well as increased COLI borrowings which interest is reflected in Other Income and Deductions, on the Consolidated Statements of Income. The Company's embedded cost of long-term debt decreased to 7.6% at December 31, 1994, compared to 8.1% and 8.2% at December 31, 1993 and 1992, respectively, primarily as a result of the refinancing of higher cost debt.
Partially offsetting these decreases in interest expense were higher interest rates on short-term borrowings.
Interest charges for 1993 were higher than 1992 as a result of the Merger. KG&E interest charges of $59 million for 1993 were included in the Company's total interest charges compared to $53 million for the nine months ended December 31, 1992. The full twelve month effect of interest on debt to acquire KG&E also contributed to the increase in total interest charges. The increased interest charges were partially offset through lower debt balances and reduced interest charges from refinancing higher cost long-term debt and lower interest rates on variable-rate debt.
MERGER IMPLEMENTATION: In accordance with the KCC Merger order, amortization of the acquisition adjustment will commence August 1995. The amortization will amount to approximately $20 million (pre-tax) per year for 40 years. The Company can recover the amortization of the acquisition adjustment through cost savings under a sharing mechanism approved by the KCC as described in Note 3 of the Notes to the Consolidated Financial Statements. While the Company has achieved savings from the Merger, there is no assurance that the savings achieved will be sufficient to, or the cost savings sharing mechanism will operate as to, fully offset the amortization of the acquisition adjustment.
OTHER INFORMATION
INFLATION: Under the ratemaking procedures prescribed by the regulatory commissions to which the Company is subject, only the original cost of plant is recoverable in revenues as depreciation. Therefore, because of inflation, present and future depreciation provisions are inadequate for purposes of maintaining the purchasing power invested by common shareholders and the related cash flows are inadequate for replacing property. The impact of this ratemaking process on common shareholders is mitigated to the extent depreciable property is financed with debt that can be repaid with dollars of less purchasing power. While the Company has experienced relatively low inflation in the recent past, the cumulative effect of inflation on operating costs may require the Company to seek regulatory rate relief to recover these higher costs.
FERC ORDER NO. 636: In 1992 the FERC issued Order No. 636 (FERC 636) which the FERC intended to complete the deregulation of natural gas production and facilitate competition in the gas transportation industry. FERC 636 has affected the Company in several ways. The rules provide greater protection for pipeline companies by providing for recovery of all fixed costs through contracts with local distribution companies and other customers choosing to transport gas on a firm (non-interruptible) basis. The order also separates the purchase of natural gas from the transportation and storage of natural gas, shifting additional responsibility to distribution companies for the provision (through purchase and/or storage) of long-term gas supply and transportation to distribution points. Under the new rules, distribution companies elect the amount and type of services taken from pipelines. The Company may be liable to one or more of its pipeline suppliers for costs related to the transition from its traditional natural gas sales service to the restructured services required by FERC 636. The Company believes substantially all of these costs will be recovered from its customers and any additional transition costs will be immaterial to the Company's financial position or results of operations. For additional information regarding FERC 636 costs, see Note 5 of the Notes to Consolidated Financial Statements.
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 (see Note 7).
Although the Company currently has no Phase I affected units under the Clean Air Act of 1990, the Company has applied for an early substitution permit to bring the co-owned La Cygne Station under the Phase I guidelines. The oxides of nitrogen (NOx) and air toxic limits, which were not set in law, will be specified in future Environmental Protection Agency (EPA) regulations. The EPA's proposed NOx regulations were ruled invalid by the U.S. Court of Appeals for the District of Columbia Circuit in November, 1994 and until such time as the EPA resubmits new proposed regulations, the Company will be unable to determine its compliance options or related compliance costs (see Note 7).
COMPETITION: As a regulated utility, the Company currently has limited direct competition for retail electric service in its certified service area. However, there is competition, based largely on price, from the generation, or potential generation, of electricity by large commercial and industrial customers, and independent power producers.
The 1992 Energy Policy Act (Act) requires increased efficiency of energy usage and has affected the way electricity is marketed. The Act also provides for increased competition in the wholesale electric market by permitting the FERC to order third party access to utilities' transmission systems and by liberalizing the rules for ownership of generating facilities. As part of the Merger, the Company agreed to open access of its transmission system for wholesale transactions. During 1994, wholesale electric revenues represented less than ten percent of the Company's total electric revenues.
Operating in this competitive environment could place pressure on utility profit margins and credit quality. Wholesale and industrial customers may threaten to pursue cogeneration, self-generation, retail wheeling, municipalization or relocation to other service territories in an attempt to obtain reduced energy costs. Increasing competition has resulted in credit rating agencies applying more stringent guidelines when making utility credit rating determinations.
The Company is providing reduced electric rates for industrial expansion projects and economic development projects in an effort to maintain and increase electric load. In 1994, The Boeing Company announced it would develop its 777 jetliner in Wichita and Cessna Aircraft Company announced it would build a production plant in Independence, Kansas along with expanding its Wichita facilities, with an addition of 2,000 jobs.
In order to retain its current electric load, the Company has and will continue to negotiate with some of its larger industrial customers, who are able to develop cogeneration facilities, for long-term contracts although some negotiated rates may result in reduced margins for the Company. During 1996, the Company will lose a major industrial customer to cogeneration resulting in a reduction to pre-tax earnings of approximately $7 to $8 million or 7 to 8 cents per share. This customer's decision to develop its own cogeneration project was based partially on factors other than energy cost.
To capitalize on opportunities in the non-regulated natural gas industry, the Company, through its wholly-owned subsidiary Mid Continent Market Center, Inc. (Market Center), is establishing a natural gas market center in Kansas. The Market Center will provide natural gas transportation, storage, and gathering services, as well as balancing, and title transfer capability. Upon approval from the KCC, the Company intends to transfer certain natural gas transmission assets having a value of approximately $52.1 million to the Market Center. In addition, the Company intends to extend credit to the Market Center enabling the Market Center to borrow up to an aggregate principal amount of $25 million on a term basis to construct new facilities and $5 million on a revolving credit basis for working capital. The Market Center will provide no notice natural gas transportation and storage services to the Company under a long-term contract. The Company will continue to operate and maintain the Market Center's assets under a separate contract.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Report of Independent Public Accountants 35
Financial Statements:
Consolidated Balance Sheets, December 31, 1994 and 1993 36 Consolidated Statements of Income for the years ended December 31, 1994, 1993 and 1992 37 Consolidated Statements of Cash Flows for the years ended 1994, 1993 and 1992 38 Consolidated Statements of Taxes for the years ended December 31, 1994, 1993 and 1992 39 Consolidated Statements of Capitalization, December 31, 1994 and 1993 40 Consolidated Statements of Common Stock Equity for the years ended December 31, 1994, 1993 and 1992 41 Notes to Consolidated Financial Statements 42
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented:
I, II, III, IV, and V. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Western Resources, Inc.:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Western Resources, Inc., and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, cash flows, taxes and common stock equity for each of the three years in the period ended December 31, 1994. 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 did not audit the financial statements of Kansas Gas and Electric Company, a wholly- owned subsidiary of Western Resources, Inc., as of and for the year ended December 31, 1992, which statements reflect assets and revenues of 61 percent and 27 percent, respectively, of the consolidated totals for 1992. Those statements were audited by other auditors whose report has been furnished to us and our opinion, insofar as it relates to the amounts included for that entity, is based solely on the report of other auditors.
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 and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the financial position of Western Resources, Inc., and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As explained in Note 13 to the consolidated financial statements, effective January 1, 1992, the Company changed its method of accounting for income taxes. As explained in Note 8 to the consolidated financial statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits. As explained in Note 8 to the consolidated financial statements, effective January 1, 1994, the Company changed its method of accounting for postemployment benefits.
ARTHUR ANDERSEN LLP Kansas City, Missouri, January 25, 1995
WESTERN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: The Consolidated Financial Statements of Western Resources, Inc. (the Company, Western Resources), include the accounts of its wholly-owned subsidiaries, Astra Resources, Inc. (Astra), Kansas Gas and Electric Company (KG&E) since March 31, 1992 (see Note 3), KPL Funding Corporation (KFC), and Mid Continent Market Center, Inc. (Market Center). KG&E owns 47 percent of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). The Company records its proportionate share of all transactions of WCNOC as it does other jointly-owned facilities. All significant intercompany transactions have been eliminated. The operations of Astra, KFC, and Market Center were not material to the Company's results of operations. The Company is conducting its utility business as KPL, Gas Service, and through its wholly-owned subsidiary, KG&E. The Company is conducting its non-utility business through Astra.
The accounting policies of the Company are in accordance with generally accepted accounting principles as applied to regulated public utilities. The accounting and rates of the Company are subject to requirements of the Kansas Corporation Commission (KCC), the Oklahoma Corporation Commission (OCC), and the Federal Energy Regulatory Commission (FERC).
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 4.08% in 1994, 4.10% in 1993, and 5.99% in 1992. The cost of additions to utility plant and replacement units of property is capitalized. Maintenance costs and replacement of minor items of property are charged to expense as incurred. When units of depreciable property are retired, they are removed from the plant accounts and the original cost plus removal charges less salvage are charged to accumulated depreciation.
Depreciation: Depreciation is provided on the straight-line method based on estimated useful lives of property. Composite provisions for book depreciation approximated 2.87% during 1994, 3.02% during 1993, and 3.03% during 1992 of the average original cost of depreciable property.
Consolidated Statements of Cash Flows: For purposes of the Consolidated 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.
Cash paid for interest and income taxes for each of the three years ended December 31, are as follows: 1994 1993 1992 (Dollars in Thousands) Interest on financing activities (net of amount capitalized). . . . . . . . . . . $134,785 $171,734 $128,505 Income taxes . . . . . . . . . . . . . . . 90,229 49,108 24,966 Income Taxes: Income tax expense includes provisions for income taxes currently payable and deferred income taxes calculated in conformance with income tax laws, regulatory orders, and Statement of Financial Accounting Standards No. 109 (SFAS 109) (see Note 13).
Investment tax credits previously deferred are being amortized to income over the life of the property which gave rise to the credits.
Revenues: The Company accrues estimated unbilled electric and natural gas revenues. This method of recognizing revenues best matches revenues with costs of services provided to customers and also conforms the Company's accounting treatment of unbilled revenues with the tax treatment of such 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 $61 million and $99 million are recorded as a component of accounts receivable and unbilled revenues (net) on the Consolidated Balance Sheets as of December 31, 1994 and 1993, respectively.
The Company had reserves for doubtful accounts receivable of $3.4 million and $4.3 million at December 31, 1994 and 1993, respectively.
Fuel Costs: The cost of nuclear fuel in process of refinement, conversion, enrichment, and fabrication is recorded as an asset at original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor at December 31, 1994 and 1993, was $13.6 million and $17.4 million, respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts related to corporate-owned life insurance contracts (COLI), primarily with one highly rated major insurance company, are recorded in Corporate-owned Life Insurance (net) on the Consolidated Balance Sheets:
1994 1993 (Dollars in Millions) Cash surrender value of contracts. . . $ 408.9 $ 326.3 Borrowings against contracts . . . . . (391.9) (321.6) ------- ------- COLI (net). . . . . . . . . . $ 17.0 $ 4.7 ======= =======
The COLI borrowings will be repaid upon receipt of proceeds from death benefits under contracts. The Company recognizes increases in the cash surrender value of contracts, resulting from premiums and investment earnings on a tax free basis, and the tax deductible interest on the COLI borrowings in Corporate-owned Life Insurance (net) on the Consolidated Statements of Income. Interest expense related to KG&E's COLI for 1994, 1993, and the nine months ended December 31, 1992, was $21.0 million, $11.9 million, and $5.3 million, respectively.
As approved by the KCC, the Company is using a portion of the net income stream generated by COLI policies purchased in 1993 and 1992 by the Company (see Note 8) to offset Statement of Financial Accounting Standards No. 106 (SFAS 106) and Statement of Financial Accounting Standards No. 112 (SFAS 112) expenses.
Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
2. SALES OF MISSOURI NATURAL GAS DISTRIBUTION PROPERTIES
On January 31, 1994, the Company sold substantially all of its Missouri natural gas distribution properties and operations to Southern Union Company (Southern Union). The Company sold the remaining Missouri properties to United Cities Gas Company (United Cities) on February 28, 1994. The properties sold to Southern Union and United Cities are referred to herein as the "Missouri Properties." With the sales the Company is no longer operating as a utility in the State of Missouri.
The portion of the Missouri Properties purchased by Southern Union was sold for an estimated sale price of $400 million, in cash, based on a calculation as of December 31, 1993. The sale agreement provided for estimated amounts in the sale price calculation to be adjusted to actual as of January 31, 1994, within 120 days of closing. Disputes with respect to proposed adjustments based upon differences between estimates and actuals were to be resolved within 60 days of submission of the disputes by Southern Union or submitted to arbitration by an accounting firm to be agreed to by both parties. Southern Union proposed a number of adjustments to the purchase price, some of which the Company has disputed. The Company maintains the disputed adjustments are not permitted under the sale agreement. In the opinion of the Company's management, the resolution of these purchase price adjustments will not have a material impact on the Company's financial position or results of operations. For information regarding litigation in connection with the sale of the Missouri Properties to Southern Union, see Note 4.
United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri for $665,000 in cash.
During the first quarter of 1994, the Company recognized a gain of approximately $19.3 million, net of tax, on the sales of the Missouri Properties. As of the respective dates of the sales of the Missouri Properties, the Company ceased recording the results of operations, and removed the assets and liabilities from the Consolidated Balance Sheet related to the Missouri Properties. The gain is reflected in Other Income and Deductions, on the Consolidated Statements of Income.
The following table reflects the approximate operating revenues and operating income for the years ended December 31, 1994, 1993, and 1992, and net utility plant at December 31, 1993 and 1992, related to the Missouri Properties:
1994 1993 1992 Percent Percent Percent of Total of Total of Total Amount Company Amount Company Amount Company (Dollars in Thousands, Unaudited) Operating revenues. .$ 77,008 4.8% $349,749 18.3% $299,202 19.2% Operating income. . . 4,997 1.9% 20,748 7.1% 11,177 4.7% Net utility plant . . - - 296,039 6.6% 272,126 6.1%
Separate audited financial information was not kept by the Company for the Missouri Properties. This unaudited financial information is based on assumptions and allocations of expenses of the Company as a whole.
3. ACQUISITION AND MERGER
On March 31, 1992, the Company, through its wholly-owned subsidiary KCA Corporation (KCA), acquired all of the outstanding common and preferred stock of Kansas Gas and Electric Company for $454 million in cash and 23,479,380 shares of common stock (the Merger). The Company also paid $20 million in costs to complete the Merger. Simultaneously, KCA and Kansas Gas and Electric Company merged and adopted the name of Kansas Gas and Electric Company (KG&E). The Merger was accounted for as a purchase. For income tax purposes the tax basis of the KG&E assets was not changed by the Merger.
As the Company acquired 100 percent of the common and preferred stock of KG&E, the Company recorded an acquisition premium of $490 million on the Consolidated Balance Sheet for the difference in purchase price and book value. This acquisition premium and related income tax requirement of $311 million under SFAS 109 have been classified as plant acquisition adjustment in Electric Plant in Service on the Consolidated Balance Sheets. Under the provisions of orders of the KCC, the acquisition premium is recorded as an acquisition adjustment and not allocated to the other assets and liabilities of KG&E.
In the November 1991 KCC order approving the Merger, a mechanism was approved to share equally between the shareholders and ratepayers the cost savings generated by the Merger in excess of the revenue requirement needed to allow recovery of the amortization of a portion of the acquisition adjustment, including income tax, calculated on the basis of a purchase price of KG&E's common stock at $29.50 per share. The order provides an amortization period for the acquisition adjustment of 40 years commencing in August 1995, at which time the full amount of cost savings is expected to have been implemented. Merger savings will be measured by application of an inflation index to certain pre-merger operating and maintenance costs at the time of the next Kansas rate case. While the Company has achieved savings from the Merger, there is no assurance that the savings achieved will be sufficient to, or the cost savings sharing mechanism will operate as to, fully offset the amortization of the acquisition adjustment. The order further provides a moratorium on increases, with certain exceptions, in the Company's Kansas electric and natural gas rates until August 1995. The KCC ordered refunds totalling $32 million to the combined companies' customers to share with customers the Merger-related cost savings achieved during the moratorium period. Refunds of $8.5 million were made in April 1992 and December 1993 and the remaining refund of $15 million was made in September 1994.
The KCC order approving the Merger required the legal reorganization of KG&E so that it was no longer held as a separate subsidiary after January 1, 1995, unless good cause was shown why such separate existence should be maintained. The Securities and Exchange Commission (SEC) order relating to the Merger granted the Company an exemption under the Public Utility Holding Company Act (PUHCA) until January 1, 1995. The Company has been granted regulatory approval from the KCC which eliminates the requirement for a combination. As a result of the sales of the Missouri Properties, the Company is now exempt from regulation as a holding company under Section 3(a)(1) of the PUHCA.
As the Merger did not occur until March 31, 1992, the twelve months ended December 31, 1992, results of operations for the Company reported in its statements of income, cash flows, and common stock equity reflect KG&E's results of operations for only the nine months ended December 31, 1992. Pro forma revenues of $1.7 billion, operating income of $269 million, net income of $132 million and earnings per share of $2.03 for the year ended December 31, 1992 give effect to the Merger as if it had occurred at January 1, 1992. This pro forma information is not necessarily indicative of the results of operations that would have occurred had the Merger been consummated on January 1, 1992, nor is it necessarily indicative of future operating results.
4. LEGAL PROCEEDINGS
On June 1, 1994, Southern Union filed an action against the Company, The Bishop Group, Ltd., and other entities affiliated with The Bishop Group, in the Federal District Court for the Western District of Missouri (the Court) (Southern Union Company v. Western Resources, Inc. et al., Case No. 94-509-CV- W-1) alleging, among other things, breach of the Missouri Properties sale agreement relating to certain gas supply contracts between the Company and various Bishop entities that Southern Union assumed, and requesting unspecified monetary damages as well as declaratory relief. On August 1, 1994, the Company filed its answer and counterclaim denying all claims asserted against it by Southern Union and requesting declaratory judgment with respect to certain adjustments in the purchase price for the Missouri Properties proposed by Southern Union and disputed by the Company. On August 24, 1994, Southern Union filed claims against the Company for alleged purchase price adjustments totalling $19 million. The Company subsequently agreed that approximately $4 million of the purchase price adjustments were subject to arbitration. On January 18, 1995, the Court held the remaining $15 million of proposed adjustments to the purchase price were subject to arbitration under the sale agreement. In the opinion of the Company's management, the disputed adjustments are not proper adjustments to the purchase price. For additional information regarding the sales of the Missouri Properties see Note 2.
On August 15, 1994, the Bishop entities filed an answer and claims against Southern Union and the Company alleging, among other things, breach of those certain gas supply contracts. The Bishop entities claimed damages up to $270 million against the Company and Southern Union. The Company's management believes that through the sale agreement, Southern Union assumed all liabilities arising out of or related to gas supply contracts associated with the Missouri Properties. The Company's management also believes it is not liable for any claims asserted against it by the Bishop entities and will vigorously defend such claims.
The Company received a civil investigative demand from the U.S. Department of Justice seeking certain information in connection with the department's investigation "to determine whether there is, has been, or may be a violation of the Sherman Act Sec. 1-2" with respect to the natural gas business in Kansas and Missouri. The Company is cooperating with the Department of Justice, but is not aware of any violation of the antitrust laws in connection with its business operations.
The Company and its subsidiaries are involved in various other legal and environmental proceedings. Management believes that adequate provision has been made within the Consolidated Financial Statements for these other matters and accordingly believes their ultimate dispositions will not have a material adverse effect upon the business, financial position, or results of operations of the Company. 5. RATE MATTERS AND REGULATION
The Company, under rate orders from the KCC, OCC and the FERC, recovers increases in fuel and natural gas costs through fuel adjustment clauses for wholesale and certain retail electric customers and various purchased gas adjustment clauses (PGA) for natural gas customers. The KCC and the OCC require the annual difference between actual gas cost incurred and cost recovered through the application of the PGA be deferred and amortized through rates in subsequent periods.
Elimination of the Energy Cost Adjustment Clause (ECA): On March 26, 1992, in connection with the Merger, the KCC approved the elimination of the ECA for most Kansas retail electric customers of both the Company and KG&E effective April 1, 1992. The provisions for fuel costs included in base rates were established at a level intended by the KCC to equal the projected average cost of fuel through August 1995, and to include recovery of costs provided by previously issued orders relating to coal contract settlements. Any variance in fuel costs from the projected average will impact the Company's earnings.
FERC Proceedings: On August 19, 1994, Williams Natural Gas Company (WNG) filed a revised application with the FERC to direct bill approximately $14.7 million of FERC Order No. 636 (FERC 636) transition costs to the Company related to natural gas sales service in Kansas and Oklahoma. These costs are currently being recovered from the Company's current Kansas and Oklahoma customers. The Company believes any future transition costs ultimately will be recovered through charges to its customers, and any unrecovered transition costs will not be material to the Company's financial position or results of operations. For additional information with respect to FERC 636 see Management's Discussion and Analysis.
On October 5, 1994, WNG filed an application with the FERC to direct bill to the Company up to $30.4 million of settlement costs paid to Amoco related to litigation between WNG and Amoco regarding the proper price to be paid for gas purchased by WNG from Amoco. The proposed direct bill is related to natural gas service rendered by the Company in Kansas and Oklahoma. At December 31, 1994, $14.2 million of these costs have been billed to the Company. The Company believes substantially all of these costs and any future settlement costs ultimately will be recovered through charges to its Kansas and Oklahoma customers, and any unrecovered settlement costs will not be material to the Company's financial position or results of operations.
KCC Proceedings: On December 22, 1994, the Company, in conjunction with the Market Center, filed an application with the KCC to form a natural gas market center in Kansas. The Market Center will provide natural gas transportation, storage, and gathering services, as well as balancing, and title transfer capability. Upon approval from the KCC, the Company intends to transfer certain natural gas transmission assets having a value of approximately $52.1 million to the Market Center. In addition, the Company intends to extend credit to the Market Center enabling the Market Center to borrow up to an aggregate principal amount of $25 million on a term basis to construct new facilities and $5 million on a revolving credit basis for working capital. The Market Center will provide no notice natural gas transportation and storage services to the Company under a long-term contract. The Company will continue to operate and maintain the Market Center's assets under a separate contract. On January 24, 1992, the KCC issued an order allowing the Company to continue the deferral of service line replacement program costs incurred since January 1, 1992, including depreciation, property taxes, and carrying costs for recovery in the next general rate case. At December 31, 1994, approximately $7.2 million of these deferrals have been included in Deferred Charges and Other Assets, Other, on the Consolidated Balance Sheet.
On December 30, 1991, the KCC approved a permanent natural gas rate increase of $39 million annually and the Company discontinued the deferral of accelerated line survey costs on January 1, 1992. Approximately $3.1 million of these deferred costs remain in Deferred Charges and Other Assets, Other, on the Consolidated Balance Sheet at December 31, 1994, with the balance being included in rates and amortized to expense during a 43-month period, commencing January 1, 1992.
Tight Sands: In December 1991 the KCC, and the OCC approved agreements authorizing the Company to refund to customers approximately $40 million of the proceeds of the Tight Sands antitrust litigation settlement to be collected on behalf of Western Resources' natural gas customers. To secure the refund of settlement proceeds, the Commissions authorized the establishment of an independently administered trust to collect and maintain cash receipts received under Tight Sands settlement agreements and provide for the refunds made. The trust has a term of ten years.
Rate Stabilization Plan: In 1988, the KCC issued an order requiring the accrual of phase-in revenues be discontinued by KG&E effective December 31, 1988. Effective January 1, 1989, KG&E began amortizing the phase-in revenue asset on a straight-line basis over 9 1/2 years. At December 31, 1994, approximately $61 million of deferred phase-in revenues remained on the Consolidated Balance Sheet.
Coal Contract Settlements: In March 1990, the KCC issued an order allowing KG&E to defer its share of a 1989 coal contract settlement with the Pittsburg and Midway Coal Mining Company amounting to $22.5 million. This amount was recorded as a deferred charge and is included in Deferred Charges and Other Assets on the Consolidated Balance Sheet. The settlement resulted in the termination of a long-term coal contract. The KCC permitted KG&E to recover this settlement as follows: 76 percent of the settlement plus a return over the remaining term of the terminated contract (through 2002) and 24 percent to be amortized to expense with a deferred return equivalent to the carrying cost of the asset.
In February 1991, KG&E paid $8.5 million to settle a coal contract lawsuit with AMAX Coal Company and recorded the payment as a deferred charge in Deferred Charges and Other Assets on the Consolidated Balance Sheet. The KCC approved the recovery of the settlement plus a return, equivalent to the carrying cost of the asset, over the remaining term of the terminated contract (through 1996).
FERC Order No. 528: In 1990, the FERC issued Order No. 528 which authorized new methods for the allocation and recovery of take-or-pay settlement costs by natural gas pipelines from their customers. Settlements were reached between the Company's two largest gas pipelines and their customers in FERC proceedings related to take-or-pay issues. The settlements address the allocation of take-or-pay settlement costs between the pipelines and their customers. However, the amount which one of the pipelines will be allowed to recover is yet to be determined. Litigation continues between the Company and a former upstream pipeline supplier to one of the Company's pipeline suppliers concerning the amount of such costs which may ultimately be allocated to the Company's pipeline supplier. The Company's share of any costs allocated to the Company's pipeline supplier will be charged to the Company. Due to the uncertainty concerning the amount to be recovered by the Company's current suppliers and of the outcome of the litigation between the Company and its current pipeline's upstream supplier, the Company is unable to estimate its future liability for take-or-pay settlement costs. However, the KCC has approved mechanisms which are designed to allow the Company to recover these take-or-pay costs from its customers.
6. SHORT-TERM DEBT
The Company's short-term financing requirements are satisfied, through the sale of commercial paper, short-term bank loans and borrowings under unsecured lines of credit maintained with banks. Information concerning these arrangements for the years ended December 31, 1994, 1993, and 1992, is set forth below:
Year Ended December 31, 1994 1993 1992 (Dollars in Thousands) Lines of credit at year end. . . . $145,000(1) $145,000 $250,000(2) Short-term debt out- standing at year end . . . . . . 308,200 440,895 222,225 Weighted average interest rate on debt outstanding at year end (including fees) . . . . . . 6.25% 3.67% 4.70% Maximum amount of short- term debt outstanding during the period. . . .. . . . . . . . $485,395 $443,895 $263,900 Monthly average short-term debt. . 214,180 347,278 179,577 Weighted daily average interest rates during the year (including fees) . . . . . . . . 4.63% 3.44% 4.90%
(1) Decreased to $121 million in January 1995. (2) Decreased to $155 million in January 1993.
In connection with the commitments, the Company has agreed to pay certain fees to the banks. Available lines of credit and the unused portion of the revolving credit facility are utilized to support the Company's outstanding short-term debt.
7. COMMITMENTS AND CONTINGENCIES
As part of its ongoing operations and construction program, the Company has commitments under purchase orders and contracts which have an unexpended balance of approximately $77 million at December 31, 1994. Approximately $32 million is attributable to modifications to upgrade the three turbines at Jeffrey Energy Center to be completed by December 31, 1998. Plans for future construction of utility plant are discussed in the Management's Discussion and Analysis section.
In January 1994, the Company entered into an agreement with Oklahoma Municipal Power Authority (OMPA). Under the agreement, the Company received a prepayment of approximately $41 million for which the Company will provide capacity and transmission services to OMPA through the year 2013.
Manufactured Gas Sites: The Company was previously associated with 20 former manufactured gas sites located in Kansas which may contain coal tar and other potentially harmful materials. These sites were operated decades ago by predecessor companies, and were owned by the Company for a period of time after operations had ceased. The Company and the Kansas Department of Health and Environment (KDHE) conducted preliminary assessments of the sites at a cost of approximately $500,000. The results of the preliminary investigations determined the Company does not have a connection to four of the sites. Of the remaining 16 sites, the site investigation and risk assessment field work of the highest priority site was completed in 1994 at a total cost of approximately $450,000. The Company has not received the final report so as to determine the extent of contamination and the amount of any possible remediation.
The Company and KDHE entered into a consent agreement governing all future work at these sites. The terms of the consent agreement will allow the Company to investigate the 16 sites and set remediation priorities based upon the results of the investigations and risk analysis. The prioritized sites will be investigated over a 10 year period. The agreement will allow the Company to set mutual objectives with the KDHE in order to expedite effective response activities and to control costs and environmental impact. The Company is aware of other utilities in Region VII of the EPA (Kansas, Missouri, Nebraska, and Iowa) which have incurred remediation costs for manufactured gas sites ranging between $500,000 and $10 million, depending on the site, and that the KCC has issued an accounting order which will permit another Kansas utility to recover its remediation costs through rates. To the extent that such remediation costs are not recovered through rates, the costs could be material to the Company's financial position or results of operations depending on the degree of remediation required and number of years over which the remediation must be completed.
Superfund Sites: The Company has been identified as one of numerous potentially responsible parties in four hazardous waste sites listed by the EPA as Superfund sites. One site is a groundwater contamination site in Wichita, Kansas (Wichita site), two are soil contamination sites in Missouri (Missouri sites), and one site is a solid waste land-fill located in Edwardsville, Kansas (Edwardsville site). Settlement agreements releasing the Company from liability for future response or costs have been entered into at the Edwardsville site and one of the Missouri sites. The Company's obligation at the remaining Missouri site and the Wichita site appears to be limited based on the Company's experience at similar sites given its limited exposure and settlement costs. In the opinion of the Company's management, the resolution of these matters will not have a material impact on the Company's financial position or results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in sulfur dioxide and oxides of nitrogen (NOx) emissions effective in 1995 and 2000 and a probable reduction in toxic emissions. To meet the monitoring and reporting requirements under the acid rain program, the Company installed continuous monitoring and reporting equipment at a total cost of approximately $10 million. The Company does not expect additional equipment to reduce sulfur emissions to be necessary under Phase II. Although the Company currently has no Phase I affected units, the owners have applied for an early substitution permit to bring the co-owned La Cygne Station under the Phase I regulations.
The NOx and air toxic limits, which were not set in the law, will be specified in future EPA regulations. The EPA's proposed NOx regulations were ruled invalid by the U.S. Court of Appeals for the District of Columbia Circuit and until such time as the EPA resubmits new proposed regulations, the Company will be unable to determine its compliance options or related compliance costs.
Other Environmental Matters: As part of the sale of the Company's Missouri Properties to Southern Union, Southern Union assumed responsibility under an agreement for any environmental matters related to the Missouri Properties purchased by Southern Union pending at the date of the sale or that may arise after closing. For any environmental matters pending or discovered within two years of the date of the agreement, and after pursuing several other potential recovery options, the Company may be liable for up to a maximum of $7.5 million under a sharing arrangement with Southern Union provided for in the agreement.
Spent Nuclear Fuel Disposal: Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the ultimate storage and disposal of spent nuclear fuel removed from nuclear reactors. Under a contract with the DOE for disposal of spent nuclear fuel, the Company pays a quarterly fee to DOE of one mill per kilowatthour on net nuclear generation. These fees are included as part of nuclear fuel expense and amounted to $3.8 million for 1994, $3.5 million for 1993, and $1.6 million for 1992.
The Company along with the other co-owners of Wolf Creek are among 14 companies that filed a lawsuit on June 20, 1994, seeking an interpretation of the DOE's obligation to begin accepting spent nuclear fuel for disposal in 1998. The Federal Nuclear Waste Policy Act requires DOE ultimately to accept and dispose of nuclear utilities' spent fuel. The DOE has filed a motion to have this case dismissed. The issue to be decided in this case is whether DOE must begin accepting spent fuel in 1998 or at a future date. Wolf Creek contains an on-site spent fuel storage facility which, under current regulatory guidelines, provides space for the storage of spent fuel through the year 2006 while still maintaining full core off-load capability. The Company believes adequate additional storage space can be obtained as necessary.
Decommissioning: On June 9, 1994, the KCC issued an order approving the decommissioning costs of the 1993 Wolf Creek Decommissioning Cost Study which estimates the Company's share of Wolf Creek decommissioning costs, under the immediate dismantlement method, to be approximately $595 million primarily during the period 2025 through 2033, or approximately $174 million in 1993 dollars. These costs were calculated using an assumed inflation rate of 3.45% over the remaining service life, in 1993, of 32 years.
Decommissioning costs are being charged to operating expenses in accordance with the KCC order. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts so expensed ($3.5 million in 1994 increasing annually to $5.5 million in 2024) and earnings on trust fund assets are deposited in an external trust fund. The assumed return on trust assets is 5.9%. The Company's investment in the decommissioning fund, including reinvested earnings was $16.9 million and $13.2 million at December 31, 1994 and December 31, 1993, respectively. These amounts are reflected in Decommissioning Trust, and the related liability is included in Deferred Credits and Other Liabilities, Other, on the Consolidated Balance Sheets.
The Company carries $118 million in premature decommissioning insurance. The insurance coverage has several restrictions. One of these is that it can only be used if Wolf Creek incurs an accident exceeding $500 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor station site in accordance with a plan approved by the Nuclear Regulatory Commission (NRC), and to pay for on-site property damages. If the amount designated as decommissioning insurance is needed to implement the NRC- approved plan for stabilization and decontamination, it would not be available for decommissioning purposes.
Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $8.9 billion for a single nuclear incident. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million and the balance is provided by an assessment plan mandated by the NRC. Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $79.3 million ($37.3 million, Company's share) in the event there is a 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 totalling approximately $2.8 billion ($1.3 billion, Company's share). This insurance is provided by a combination of "nuclear insurance pools" ($500 million) and Nuclear Electric Insurance Limited (NEIL) ($2.3 billion). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. The Company's share of any remaining proceeds can be used for property damage up to $1.2 billion (Company's share) and premature decommissioning costs up to $118 million (Company's share) in 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 of approximately $13 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. Federal Income Taxes: During 1991, the Internal Revenue Service (IRS) completed an examination of KG&E's federal income tax returns for the years 1984 through 1988. In April 1992, KG&E received the examination report and upon review filed a written protest in August 1992. In October 1993, KG&E received another examination report for the years 1989 and 1990 covering the same issues identified in the previous examination report. Upon review of this report, KG&E filed a written protest in November 1993. The most significant proposed adjustments reduce the depreciable basis of certain assets and investment tax credits generated. Management believes there are significant questions regarding the theory, computations, and sampling techniques used by the IRS to arrive at its proposed adjustments, and also believes any additional tax expense incurred or loss of investment tax credits will not be material to the Company's financial position and results of operations. Additional income tax payments, if any, are expected to be offset by investment tax credit carryforwards, alternative minimum tax credit carryforwards, or deferred tax provisions.
Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the Company has entered into various commitments to obtain nuclear fuel, coal, and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1994, WCNOC's nuclear fuel commitments (Company's share) were approximately $12.6 million for uranium concentrates expiring at various times through 1997, $122.9 million for enrichment expiring at various times through 2014, and $56.5 million for fabrication through 2012. At December 31, 1994, the Company's coal and natural gas contract commitments in 1994 dollars under the remaining terms of the contracts were approximately $3 billion and $9 million, respectively. The largest coal contract expires in 2020, with the remaining coal contracts expiring at various times through 2013. The majority of natural gas contracts continue through 1995 with automatic one-year extension provisions. In the normal course of business, additional commitments and spot market purchases will be made to obtain adequate fuel supplies.
Energy Act: As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment, decontamination, and decommissioning fund. The Company's portion of the assessment for Wolf Creek is approximately $7 million, payable over 15 years. Management expects such costs to be recovered through the ratemaking process.
8. EMPLOYEE BENEFIT PLANS
Pension: The Company maintains noncontributory defined benefit pension plans covering substantially all employees. Pension benefits are based on years of service and the employee's compensation during the five highest paid consecutive years out of ten before retirement. The Company's policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code. The following tables provide information on the components of pension cost, funded status, and actuarial assumptions for the Company's pension plans:
Year Ended December 31, 1994 1993 1992 (Dollars in Thousands) Pension Cost: Service cost. . . . . . . . . . $ 10,197 $ 9,778 $ 9,847 Interest cost on projected benefit obligation. . . . . . 29,734 35,688 29,457 (Gain) loss on plan assets. . . 7,351 (64,113) (38,967) Deferred investment gain (loss) (38,457) 29,190 7,705 Net amortization. . . . . . . . 245 (669) (948) Net pension cost. . . . . . $ 9,070 $ 9,874 $ 7,094
December 31, 1994 1993 1992 (Dollars in Thousands) Reconciliation of Funded Status: Actuarial present value of benefit obligations: Vested . . . . . . . . . . . $278,545 $353,023 $316,100 Non-vested . . . . . . . . . 19,132 26,983 19,331 Total. . . . . . . . . . . $297,677 $380,006 $335,431 Plan assets (principally debt and equity securities) at fair value . . . . . . . . . . . $375,521 $490,339 $452,372 Projected benefit obligation . . . 378,146 468,996 424,232 Funded status. . . . . . . . . . . (2,625) 21,343 28,140 Unrecognized transition asset. . . (2,205) (2,756) (3,092) Unrecognized prior service costs . 47,796 64,217 55,886 Unrecognized net gain. . . . . . . (56,079) (108,783) (106,486) Accrued pension costs. . . . . . . $(13,113) $(25,979) $(25,552)
Year Ended December 31, 1994 1993 1992 Actuarial Assumptions: Discount rate. . . . . . . . . . 8.0-8.5% 7.0-7.75% 8.0-8.5% Annual salary increase rate. . . 5.0% 5.0% 6.0% Long-term rate of return . . . . 8.0-8.5% 8.0-8.5% 8.0-8.5%
Retirement and Voluntary Separation Plans: In January 1992, the Board of Directors approved early retirement plans and voluntary separation programs. The voluntary early retirement plans were offered to all vested participants in the Company's defined pension plan who reached the age of 55 with 10 or more years of service on or before May 1, 1992. Certain pension plan improvements were made, including a waiver of the actuarial reduction factors for early retirement and a cash incentive payable as a monthly supplement up to 60 months or as a lump sum payment. Of the 738 employees eligible for the early retirement option, 531, representing ten percent of the combined Company's work force, elected to retire on or before the May 1, 1992, deadline. Seventy-one of those electing to retire were employees of KG&E acquired March 31, 1992 (see Note 3). Another 67 employees, with 10 or more years of service, elected to participate in the voluntary separation program. Of those, 29 were employees of KG&E. In addition, 68 employees received Merger-related severance benefits, including 61 employees of KG&E. The actuarial cost, based on plan provisions for early retirement and voluntary separation programs, and Merger-related severance benefits for the KG&E employees were considered in purchase accounting for the Merger. The actuarial cost of the former Kansas Power and Light Company employees, of approximately $11 million, was expensed in 1992.
Postretirement: The Company adopted the provisions of Statement of Financial Accounting Standards No. 106 (SFAS 106) in the first quarter of 1993. This statement requires the accrual of postretirement benefits other than pensions, primarily medical benefit costs, during the years an employee provides service.
Based on actuarial projections and adoption of the transition method of implementation which allows a 20-year amortization of the accumulated benefit obligation, SFAS 106 expense was approximately $12.4 million and $26.5 million for 1994 and 1993, respectively. The Company's total SFAS 106 obligation was approximately $114.6 million and $166.5 million at December 31, 1994 and 1993 respectively. The reduction in both the 1994 obligation and expense is primarily the result of the sales of the Missouri Properties. To mitigate the impact of SFAS 106 expense, the Company has implemented programs to reduce health care costs. In addition, the Company received an order from the KCC permitting the initial deferral of SFAS 106 expense. To mitigate the impact SFAS 106 expense will have on rate increases, the Company will include in the future computation of cost of service the actual SFAS 106 expense and an income stream generated from COLI. To the extent SFAS 106 expense exceeds income from the COLI program, this excess is being deferred (in accordance with the provisions of the FASB Emerging Issues Task Force Issue No. 92-12) and will be offset by income generated through the deferral period by the COLI program. Should the income stream generated by the COLI program not be sufficient to offset the deferred SFAS 106 expense, the KCC order allows recovery of such deficit through the ratemaking process.
Prior to the adoption of SFAS 106, the Company's policy was to recognize the cost of retiree health care and life insurance benefits as expense when claims and premiums for life insurance policies were paid. The cost of providing health care and life insurance benefits to 2,928 retirees was $8.1 million in 1992.
The following table summarizes the status of the Company's postretirement plans for financial statement purposes and the related amounts included in the Consolidated Balance Sheets:
December 31, 1994 1993 (Dollars in Thousands) Reconciliation of Funded Status: Actuarial present value of postretirement benefit obligations: Retirees. . . . . . . . . . . . . . . . . . . $ 68,570 $ 111,499 Active employees fully eligible . . . . . . . 13,549 11,848 Active employees not fully eligible . . . . . 32,484 43,109 Unrecognized prior service cost . . . . . . . 9,391 18,195 Unrecognized transition obligation. . . . . . (117,967) (160,731) Unrecognized net gain (loss). . . . . . . . . 14,489 (7,100) Balance sheet liability . . . . . . . . . . . . . $ 20,516 $ 16,820
Year Ended December 31, 1994 1993 Assumptions: Discount rate . . . . . . . . . . . . . . . . . 8.0-8.5 % 7.75% Annual compensation increase rate . . . . . . . 5.0 % 5.0 % Expected rate of return . . . . . . . . . . . . 8.5 % 8.5 %
For measurement purposes, an annual health care cost growth rate of 12% was assumed for 1994, decreasing 1% per year to 5% in 2001 and thereafter. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by 1% each year would increase the present value of the accumulated projected benefit obligation by $4.7 million and the aggregate of the service and interest cost components by $0.3 million.
Postemployment: The Company adopted Statement of Financial Accounting Standards No. 112 (SFAS 112) in the first quarter of 1994, which established accounting and reporting standards for postemployment benefits. The statement requires the Company to recognize the liability to provide postemployment benefits when the liability has been incurred. The Company received an order from the KCC permitting the initial deferral of SFAS 112 expense. To mitigate the impact SFAS 112 expense will have on rate increases, the Company will include in the future computation of cost of service the actual SFAS 112 transition costs and expenses and an income stream generated from COLI. The 1994 expense under SFAS 112 was approximately $2.7 million. At December 31, 1994, the Company's SFAS 112 liability recorded on the Consolidated Balance Sheet was approximately $8.4 million.
Savings: The Company maintains savings plans in which substantially all employees participate. The Company matches employees' contributions up to specified maximum limits. The funds of the plans are deposited with a trustee and invested at each employee's option in one or more investment funds, including a Company stock fund. The Company's contributions were $5.1 million, $5.8 million, and $5.4 million for 1994, 1993, and 1992, respectively.
Missouri Property Sale: Effective January 31, 1994, the Company transferred a portion of the assets and liabilities of the Company's pension plan to a pension plan established by Southern Union. The amount of assets transferred equal the projected benefit obligation for employees and retirees associated with Southern Union's portion of the Missouri Properties plus an additional $9 million.
9. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1994 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 152,816 $ 98,124 343 50 Jeffrey 1 (b) Jul 1978 276,689 122,721 587 84 Jeffrey 2 (b) May 1980 285,579 109,743 600 84 Jeffrey 3 (b) May 1983 387,646 134,199 588 84 Wolf Creek (c) Sep 1985 1,376,335 317,311 545 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL) (b) Jointly owned with 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 percent undivided interest in La Cygne 2 (representing 335 MW capacity) sold and leased back to the Company in 1987, are included in operating expenses on the Consolidated Statements of Income. The Company's share of other transactions associated with the plants is included in the appropriate classification in the Company's Consolidated Financial Statements.
10. LEASES
At December 31, 1994, the Company had leases covering various property and equipment. Certain lease agreements meet the criteria, as set forth in Statement of Financial Accounting Standards No. 13, for classification as capital leases.
Rental payments for capital and operating leases and estimated rental commitments are as follows:
Capital Operating Year Ended December 31, Leases Leases (Dollars in Thousands) 1992 $ 2,426 $ 52,701 1993 3,272 55,011 1994 2,987 55,076 Future Commitments: 1995 3,783 48,524 1996 3,627 46,211 1997 1,511 42,851 1998 - 41,464 1999 - 39,955 Thereafter - 753,062 Total $ 8,921 $972,067 Less Interest 784 Net obligation $ 8,137
In 1987, KG&E sold and leased back its 50 percent 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 percent undivided interest. KG&E 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, 1994, approximately $24.8 million of this deferral remained on the Consolidated Balance Sheet.
Future minimum annual lease payments, included in the table above, required under the La Cygne 2 lease agreement are approximately $34.6 million for each year through 1999 and $680 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale of La Cygne 2 has been deferred for financial reporting purposes, and is being amortized ($9.6 million per year) over the initial lease term in proportion to the related lease expense. KG&E's lease expense, net of amortization of the deferred gain and a one-time payment, was approximately $22.5 million for 1994 and 1993, and $20.6 million for the nine months ended December 31, 1992.
11. LONG-TERM DEBT
The amount of first mortgage bonds authorized by the Western Resources Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited. The amount of first mortgage bonds authorized by the KG&E Mortgage and Deed of Trust, 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 each Mortgage.
On January 20, 1994, KG&E issued $100 million of First Mortgage Bonds, 6.20% Series due January 15, 2006.
On January 31, 1994, the Company redeemed the remaining $2,466,000 principal amount of Gas Service Company (GSC) 8 1/2% Series First Mortgage Bonds due 1997. In addition, the Company had the GSC Mortgage and Deed of Trust discharged.
Debt discount and expenses are being amortized over the remaining lives of each issue. The Western Resources and KG&E improvement and maintenance fund requirements for certain first mortgage bond series can be met by bonding additional property. With the retirement of certain Western Resources and KG&E pollution control series bonds, there are no longer any bond sinking fund requirements. During 1995, $80 thousand of bonds will be redeemed, during 1996, $16 million of bonds will mature and $125 million of bonds will mature in 1999.
On November 1, 1994, the Company terminated a long-term agreement which contained provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables were accounted for as sales while those related to phase-in revenues were accounted for as collateralized borrowings. At December 31, 1993, outstanding receivables amounting to $56.8 million were considered sold under the agreement. The weighted average interest rate, including fees, on this agreement was 4.6% for 1994, 3.7% for 1993, and 6.6% for the nine months ended December 31, 1992.
In January 1993, the Company renegotiated its $600 million bank term loan and revolving credit facility used to finance the Merger into a $350 million revolving credit facility, secured by KG&E common stock. On October 5, 1994, the Company extended the term of this facility to expire on October 5, 1999. The unused portion of the revolving credit facility may be used to provide support for outstanding short-term debt. At December 31, 1994, there was no outstanding balance under the facility.
Long-term debt outstanding at December 31, 1994 and 1993, was as follows:
1994 1993 (Dollars in Thousands) Western Resources First mortgage bond series: 7 1/4% due 1999. . . . . . . . . . . . . 125,000 125,000 7 5/8% due 1999. . . . . . . . . . . . . - 19,000 8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000 7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000 8 1/8% due 2007. . . . . . . . . . . . . - 30,000 8 5/8% due 2017. . . . . . . . . . . . . - 50,000 8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000 7.65% due 2023. . . . . . . . . . . . . 100,000 100,000 525,000 624,000 Pollution control bond series: 5.90 % due 2007. . . . . . . . . . . . . - 31,000 6 3/4% due 2009. . . . . . . . . . . . . - 45,000 Variable due 2032 (1). . . . . . . . . . 45,000 - Variable due 2032 (2). . . . . . . . . . 30,500 - 6% due 2033. . . . . . . . . . . . . 58,500 58,500 134,000 134,500 KG&E First mortgage bond series: 5 5/8% due 1996. . . . . . . . . . . . . 16,000 16,000 7.60 % due 2003. . . . . . . . . . . . . 135,000 135,000 6 1/2% due 2005. . . . . . . . . . . . . 65,000 65,000 6.20 % due 2006. . . . . . . . . . . . . 100,000 - 316,000 216,000 Pollution control bond series: 6.80 % due 2004. . . . . . . . . . . . . - 14,500 5 7/8% due 2007. . . . . . . . . . . . . - 21,940 6% due 2007. . . . . . . . . . . . . - 10,000 5.10 % due 2023. . . . . . . . . . . . . 13,982 - Variable due 2027 (3). . . . . . . . . . 21,940 - 7.0 % due 2031. . . . . . . . . . . . . 327,500 327,500 Variable due 2032 (4). . . . . . . . . . 14,500 - Variable due 2032 (5). . . . . . . . . . 10,000 - 387,922 373,940 GSC First mortgage bond series: 8 1/2 % due 1997. . . . . . . . . . . . . - 2,466 - 2,466
Other pollution control obligations. . . . - 13,980 Revolving credit agreement . . . . . . . . - 115,000 Other long-term agreement. . . . . . . . . - 53,913 Less: Unamortized debt discount. . . . . . . . 5,814 6,607 Long-term debt due within one year . . . 80 3,204 $1,357,028 $1,523,988
Rates at December 31, 1994: (1) 3.94%, (2) 4.05%, (3) 4.10%, (4) 4.10% and (5) 4.10% 12. COMMON STOCK AND CUMULATIVE PREFERRED AND PREFERENCE STOCK
The Company's Restated Articles of Incorporation, as amended, provides for 85,000,000 authorized shares of common stock. At December 31, 1994, 61,617,873 shares were outstanding.
The Company has a Customer Stock Purchase Plan (CSPP) and a Dividend Reinvestment and Stock Purchase Plan (DRIP). Shares issued under the CSPP and DRIP may be either original issue shares or shares purchased on the open market. At December 31, 1994, 2,031,794 shares were available under the CSPP registration statement and 1,183,323 shares were available under the DRIP registration statement.
Not subject to mandatory redemption: The cumulative preferred stock is redeemable in whole or in part on 30 to 60 days notice at the option of the Company.
Subject to mandatory redemption: The mandatory sinking fund provisions of the 8.50% Series preference stock require the Company to redeem 50,000 shares annually beginning on July 1, 1997, at $100 per share. The Company may, at its option, redeem up to an additional 50,000 shares on each July 1, at $100 per share. The 8.50% Series also is redeemable in whole or in part, at the option of the Company, subject to certain restrictions on refunding, at a redemption price of $106.80, $106.23 and $105.67 per share beginning July 1, 1994, 1995 and 1996, respectively.
The mandatory sinking fund provisions of the 7.58% Series preference stock require the Company to redeem 25,000 shares annually beginning on April 1, 2002, and each April 1 through 2006 and the remaining shares on April 1, 2007, all at $100 per share. The Company may, at its option, redeem up to an additional 25,000 shares on each April 1 at $100 per share. The 7.58% Series also is redeemable in whole or in part, at the option of the Company, subject to certain restrictions on refunding, at a redemption price of $106.06, $105.31, and $104.55 per share beginning April 1, 1994, 1995, and 1996, respectively.
13. INCOME TAXES
The Company adopted the provisions of SFAS 109 in the first quarter of 1992. KG&E adopted the provisions of SFAS 96 in 1987 and SFAS 109 in 1992. These statements require the Company to establish deferred tax assets and liabilities, as appropriate, for all temporary differences, and to adjust deferred tax balances to reflect changes in tax rates expected to be in effect during the periods the temporary differences reverse.
In accordance with various rate orders received from the KCC and the OCC, the Company has not yet collected through rates the amounts necessary to pay a significant portion of the net deferred income tax liabilities. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers through future rates, it has recorded a deferred asset for these amounts. These assets are also a temporary difference for which deferred income tax liabilities have been provided. Accordingly, the adoption of SFAS 109 did not have a material impact on the Company's results of operations. At December 31, 1994, the Company has alternative minimum tax credits generated prior to April 1, 1992, which carryforward without expiration, of $41.2 million which may be used to offset future regular tax to the extent the regular tax exceeds the alternative minimum tax. These credits have been applied in determining the Company's net deferred income tax liability and corresponding deferred future income taxes at December 31, 1994.
Deferred income taxes result from temporary differences between the financial statement and tax basis of the Company's assets and liabilities. The sources of these differences and their cumulative tax effects are as follows:
December 31, 1994 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (661,433) $ (661,433) Energy and purchased gas adjustment clauses . . . . . . . - (1,441) (1,441) Phase-in revenues. . . . . . . . . - (27,677) (27,677) Natural gas line survey and replacement program. . . . . . . - (4,083) (4,083) Deferred gain on sale-leaseback. . 110,556 - 110,556 Alternative minimum tax credits. . 41,163 - 41,163 Deferred coal contract settlements. . . . . . . . . . . - (12,966) (12,966) Deferred compensation/pension liability. . . . . . . . . . . . 12,284 - 12,284 Acquisition premium. . . . . . . . - (318,190) (318,190) Deferred future income taxes . . . - (101,886) (101,886) Loss on reacquisition of debt. . . - (10,792) (10,792) Prepaid power sale . . . . . . . . 16,878 - 16,878 Other. . . . . . . . . . . . . . . - (13,427) (13,427) Total Deferred Income Taxes. . . . . $ 180,881 $(1,151,895) $ (971,014)
December 31, 1993 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (653,592) $ (653,592) Energy and purchased gas adjustment clauses . . . . . . . 2,452 - 2,452 Phase-in revenues. . . . . . . . . - (35,573) (35,573) Natural gas line survey and replacement program. . . . . . . - (7,721) (7,721) Deferred gain on sale-leaseback. . 116,186 - 116,186 Alternative minimum tax credits. . 39,882 - 39,882 Deferred coal contract settlements. . . . . . . . . . . - (14,980) (14,980) Deferred compensation/pension liability. . . . . . . . . . . . 11,301 - 11,301 Acquisition premium. . . . . . . . - (301,394) (301,394) Deferred future income taxes . . . - (111,159) (111,159) Loss on reacquisition of debt. . . - (9,298) (9,298) Other. . . . . . . . . . . . . . . - (4,741) (4,741) Total Deferred Income Taxes. . . . . $ 169,821 $(1,138,458) $(968,637) 14. SEGMENTS OF BUSINESS
The Company is a public utility engaged in the generation, transmission, distribution, and sale of electricity in Kansas and the transportation, distribution, and sale of natural gas in Kansas and Oklahoma.
Year Ended December 31, 1994(1) 1993 1992(2) (Dollars in Thousands) Operating revenues: Electric. . . . . . . . . . . $1,121,781 $1,104,537 $ 882,885 Natural gas . . . . . . . . . 496,162 804,822 673,363 1,617,943 1,909,359 1,556,248 Operating expenses excluding income taxes: Electric. . . . . . . . . . . 768,317 791,563 632,169 Natural gas . . . . . . . . . 484,458 747,755 642,910 1,252,775 1,539,318 1,275,079 Income taxes: Electric. . . . . . . . . . . 100,078 73,425 41,184 Natural gas . . . . . . . . . (4,456) 4,553 816 95,622 77,978 42,000 Operating income: Electric. . . . . . . . . . . 253,386 239,549 209,532 Natural gas . . . . . . . . . 16,160 52,514 29,637 $ 269,546 $ 292,063 $ 239,169
Identifiable assets at December 31: Electric. . . . . . . . . . . $4,346,312 $4,231,277 $4,390,117 Natural gas . . . . . . . . . 654,483 1,040,513 918,729 Other corporate assets(3) . . 188,823 140,258 130,060 $5,189,618 $5,412,048 $5,438,906 Other Information-- Depreciation and amortization: Electric. . . . . . . . . . . $ 123,696 $ 126,034 $ 105,842 Natural gas . . . . . . . . . 27,934 38,330 38,171 $ 151,630 $ 164,364 $ 144,013 Maintenance: Electric. . . . . . . . . . . $ 88,162 $ 87,696 $ 73,104 Natural gas . . . . . . . . . 25,024 30,147 28,507 $ 113,186 $ 117,843 $ 101,611 Capital expenditures: Electric. . . . . . . . . . . $ 152,384 $ 137,874 $ 95,465 Nuclear fuel. . . . . . . . . 20,590 5,702 15,839 Natural gas . . . . . . . . . 64,722 94,055 91,189 $ 237,696 $ 237,631 $ 202,493
(1)Information reflects the sales of the Missouri Properties (Note 2). (2)Information reflects the merger with KG&E on March 31, 1992 (Note 3). (3)Principally cash, temporary cash investments, non-utility assets, and deferred charges.
The portion of the table above related to the Missouri Properties is as follows:
1994 1993 1992 (Dollars in Thousands, Unaudited) Natural gas revenues. . . . . . . . . $ 77,008 $349,749 $299,202 Operating expenses excluding income taxes. . . . . . . . 69,114 326,329 288,558 Income taxes. . . . . . . . . . . . . 2,897 2,672 (533) Operating income. . . . . . . . . . . 4,997 20,748 11,177 Identifiable assets . . . . . . . . . - 398,464 361,612 Depreciation and amortization . . . . 1,274 12,668 13,172 Maintenance . . . . . . . . . . . . . 1,099 10,504 9,640 Capital expenditures. . . . . . . . . 3,682 38,821 36,669
15. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in Statement of Financial Accounting Standards No. 107:
Cash and Cash Equivalents- The carrying amount approximates the fair value because of the short-term maturity of these investments. Decommissioning Trust- The fair value of the decommissioning trust is based on quoted market prices at December 31, 1994 and 1993. Variable-rate Debt- The carrying amount approximates the fair value because of the short-term variable rates of these debt instruments. Fixed-rate Debt- The fair value of the fixed-rate debt is based on the sum of the estimated value of each issue taking into consideration the interest rate, maturity, and redemption provisions of each issue. Redeemable Preference Stock- The fair value of the redeemable preference stock is based on the sum of the estimated value of each issue taking into consideration the dividend rate, maturity, and redemption provisions of each issue.
The estimated fair values of the Company's financial instruments are as follows:
Carrying Value Fair Value December 31, 1994 1993 1994 1993 (Dollars in Thousands) Cash and cash equivalents. . . . . . . $ 2,715 $ 1,217 $ 2,715 $ 1,217 Decommissioning trust. . . 16,944 13,204 16,633 13,929 Variable-rate debt . . . . 822,045 931,352 822,045 931,352 Fixed-rate debt. . . . . . 1,240,982 1,364,886 1,171,866 1,473,569 Redeemable preference stock. . . . . . . . . . 150,000 150,000 155,375 160,780
The fair value estimates presented herein are based on information available as of December 31, 1994 and 1993. 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.
16. QUARTERLY RESULTS (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.
First Second Third Fourth (Dollars in Thousands, except Per Share Amounts) 1994(1) Operating revenues. . . . . . . $538,372 $341,132 $379,213 $359,226 Operating income. . . . . . . . 73,782 53,899 83,884 57,981 Net income. . . . . . . . . . . 66,133 30,247 57,679 33,388 Earnings applicable to common stock. . . . . . . . . 62,779 26,892 54,324 30,034 Earnings per share. . . . . . . $ 1.02 $ 0.44 $ 0.88 $ 0.48 Dividends per share . . . . . . $ 0.495 $ 0.495 $ 0.495 $ 0.495 Average common shares outstanding . . . . . . . . . 61,618 61,618 61,618 61,618 Common stock price: High. . . . . . . . . . . . . $ 34 7/8 $ 29 3/4 $ 29 5/8 $ 29 1/4 Low . . . . . . . . . . . . . $ 28 1/4 $ 26 1/8 $ 26 3/4 $ 27 3/8
Operating revenues. . . . . . . $579,581 $400,411 $419,018 $510,349 Operating income. . . . . . . . 85,950 60,282 81,225 64,606 Net income. . . . . . . . . . . 54,814 30,723 56,807 35,026 Earnings applicable to common stock. . . . . . . . . 51,468 27,320 53,405 31,671 Earnings per share. . . . . . . $ 0.89 $ 0.47 $ 0.90 $ 0.51 Dividends per share . . . . . . $ 0.485 $ 0.485 $ 0.485 $ 0.485 Average common shares outstanding . . . . . . . . . 58,046 58,046 59,441 61,603 Common stock price: High. . . . . . . . . . . . . $ 35 3/4 $ 36 1/8 $ 37 1/4 $ 37 Low . . . . . . . . . . . . . $ 30 3/8 $ 32 3/4 $ 35 $ 32 3/4
(1) Information reflects the sales of the Missouri Properties (Note 2).
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to the Company's Directors required by Item 10 is set forth in the Company's definitive proxy statement for its 1995 Annual Meeting of Shareholders to be filed with the Commission. Such information is incorporated herein by reference to the material appearing under the caption Election of Directors in the proxy statement to be filed by the Company with the Commission. See EXECUTIVE OFFICERS OF THE COMPANY on page 19 for the information relating to the Company's Executive Officers as required by Item 10.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is set forth in the Company's definitive proxy statement for its 1995 Annual Meeting of Shareholders to be filed with the Commission. Such information is incorporated herein by reference to the material appearing under the captions Information Concerning the Board of Directors, Executive Compensation, Compensation Plans, and Human Resources Committee Report in the proxy statement to be filed by the Company with the Commission.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is set forth in the Company's definitive proxy statement for its 1995 Annual Meeting of Shareholders to be filed with the Commission. Such information is incorporated herein by reference to the material appearing under the caption Beneficial Ownership of Voting Securities in the proxy statement to be filed by the Company with the Commission.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None. PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
The following financial statements are included herein.
FINANCIAL STATEMENTS
Report of Independent Public Accountants Consolidated Balance Sheets, December 31, 1994 and 1993 Consolidated Statements of Income, for the years ended December 31, 1994, 1993 and 1992 Consolidated Statements of Cash Flows, for the years ended December 31, 1994, 1993 and 1992 Consolidated Statements of Taxes, for the years ended December 31, 1994, 1993 and 1992 Consolidated Statements of Capitalization, December 31, 1994 and Consolidated Statements of Common Stock Equity, for the years ended December 31, 1994, 1993 and 1992 Notes to Consolidated Financial Statements
SCHEDULES
Schedules omitted as not applicable or not required under the Rules of regulation S-X: I, II, III, IV, and V
REPORTS ON FORM 8-K Form 8-K dated January 25, 1995.
EXHIBIT INDEX
All exhibits marked "I" are incorporated herein by reference.
Description
3(a) -Restated Articles of Incorporation of the Company, as amended I May 25, 1988. (filed as Exhibit 4 to Registration Statement No. 33-23022) 3(b) -Certificate of Correction to Restated Articles of Incorporation. I (filed as Exhibit 3(b) to the December 1991 Form 10-K) 3(c) -Amendment to the Restated Articles of Incorporation, as amended May 5, 1992 (filed electronically) 3(d) -Amendments to the Restated Articles of Incorporation of the I Company (filed as Exhibit 3 to the June 1994 Form 10-Q) 3(e) -By-laws of the Company, as amended July 15, 1987. (filed as I Exhibit 3(d) to the December 1987 Form 10-K) 3(f) -Certificate of Designation of Preference Stock, 8.50% Series, I without par value. (filed as Exhibit 3(d) to the December 1993 Form 10-K) 3(g) -Certificate of Designation of Preference Stock, 7.58% Series, I without par value. (filed as Exhibit 3(e) to the December 1993 Form 10-K) 4(a) -Mortgage and Deed of Trust dated July 1, 1939 between the Company I and Harris Trust and Savings Bank, Trustee. (filed as Exhibit 4(a) to Registration Statement No. 33-21739) 4(b) -First through Fifteenth Supplemental Indentures dated July 1, I 1939, April 1, 1949, July 20, 1949, October 1, 1949, December 1, 1949, October 4, 1951, December 1, 1951, May 1, 1952, October 1, 1954, September 1, 1961, April 1, 1969, September 1, 1970, February 1, 1975, May 1, 1976 and April 1, 1977, respectively. (filed as Exhibit 4(b) to Registration Statement No. 33-21739) 4(c) -Sixteenth Supplemental Indenture dated June 1, 1977. (filed as I Exhibit 2-D to Registration Statement No. 2-60207) 4(d) -Seventeenth Supplemental Indenture dated February 1, 1978. I (filed as Exhibit 2-E to Registration Statement No. 2-61310) 4(e) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I as Exhibit (b) (1)-9 to Registration Statement No. 2-64231) 4(f) -Nineteenth Supplemental Indenture dated May 1, 1980. (filed as I Exhibit 4(f) to Registration Statement No. 33-21739) 4(g) -Twentieth Supplemental Indenture dated November 1, 1981. (filed I as Exhibit 4(g) to Registration Statement No. 33-21739) 4(h) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I as Exhibit 4(h) to Registration Statement No. 33-21739) 4(i) -Twenty-Second Supplemental Indenture dated February 1, 1983. I (filed as Exhibit 4(i) to Registration Statement No. 33-21739) 4(j) -Twenty-Third Supplemental Indenture dated July 2, 1986. (filed I as Exhibit 4(j) to Registration Statement No. 33-12054) 4(k) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. (filed I as Exhibit 4(k) to Registration Statement No. 33-21739) 4(l) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I (filed as Exhibit 4 to the September 1988 Form 10-Q) 4(m) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I (filed as Exhibit 4(m) to the December 1989 Form 10-K) Description
4(n) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I (filed as exhibit 4(n) to the December 1991 Form 10-K) 4(o) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I (filed as exhibit 4(o) to the December 1992 Form 10-K) 4(p) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I (filed as exhibit 4(p) to the December 1992 Form 10-K) 4(q) -Thirtieth Supplemental Indenture dated February 1, 1993. I (filed as exhibit 4(q) to the December 1992 Form 10-K) 4(r) -Thirty-First Supplemental Indenture dated April 15, 1993. I (filed as exhibit 4(r) to Form S-3, Registration Statement No. 33-50069) 4(s) -Thirty-Second Supplemental Indenture dated April 15, 1994, (filed electronically)
Instruments defining the rights of holders of other long-term debt not required to be filed as exhibits will be furnished to the Commission upon request.
10(a) -A Rail Transportation Agreement among Burlington Northern I Railroad Company, the Union Pacific Railroad Company and the Company (filed as Exhibit 10 to the June 1994 Form 10-Q) 10(b) -Agreement between the Company and AMAX Coal West Inc. I effective March 31, 1993. (filed as Exhibit 10(a) to the December 1993 Form 10-K) 10(c) -Agreement between the Company and Williams Natural Gas Company I dated October 1, 1993. (filed as Exhibit 10(b) to the December 1993 Form 10-K) 10(d) -Agreement between the Company and Williams Natural Gas Company I dated October 1, 1993. (filed as Exhibit 10(c) to the December 1993 Form 10-K) 10(e) -Agreement between the Company and Williams Natural Gas Company I dated October 1, 1993. (filed as Exhibit 10(d) to the December 1993 Form 10-K) 10(f) -Executive Salary Continuation Plan of The Kansas Power and Light I Company, as revised, effective May 3, 1988. (filed as Exhibit 10(b) to the September 1988 Form 10-Q) 10(g) -Letter of Agreement between The Kansas Power and Light Company I and John E. Hayes, Jr., dated November 20, 1989. (filed as Exhibit 10(w) to the December 1989 Form 10-K) 10(h) -Amended Agreement and Plan of Merger by and among The Kansas I Power and Light Company, KCA Corporation, and Kansas Gas and Electric Company, dated as of October 28, 1990, as amended by Amendment No. 1 thereto, dated as of January 18, 1991. (filed as Annex A to Registration Statement No. 33-38967) 10(i) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I December 1993 Form 10-K) 10(j) -Long-term Incentive Plan (filed as Exhibit 10(j) to the I December 1993 Form 10-K) 10(k) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I December 1993 Form 10-K) 10(l) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I 10(l) to the December 1993 Form 10-K) Description
12 -Computation of Ratio of Consolidated Earnings to Fixed Charges. (filed electronically) 16 -Letter re Change in Certifying Accountant. (filed as Exhibit 16 I to the Current Report on Form 8-K dated March 8, 1993) 21 -Subsidiaries of the Registrant. (filed electronically) 23(a) -Consent of Independent Public Accountants, Arthur Andersen LLP (filed electronically) 23(b) -Consent of Independent Public Accountants, Deloitte & Touche LLP (filed electronically) 27 -Financial Data Schedules (filed electronically) 99 -Kansas Gas and Electric Company's Annual Report on Form 10-K for the year ended December 31, 1994 (filed electronically)
SIGNATURE
Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WESTERN RESOURCES, INC.
March 29, 1995 By JOHN E. HAYES, JR. John E. Hayes, Jr., Chairman of the Board, President, and Chief Executive Officer
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Signature Title Date
Chairman of the Board, President, JOHN E. HAYES, JR. and Chief Executive Officer March 29, 1995 (John E. Hayes, Jr.) (Principal Executive Officer)
Executive Vice President and S. L. KITCHEN Chief Financial Officer March 29, 1995 (S. L. Kitchen) (Principal Financial and Accounting Officer)
FRANK J. BECKER (Frank J. Becker)
GENE A. BUDIG (Gene A. Budig)
C. Q. CHANDLER (C. Q. Chandler)
THOMAS R. CLEVENGER (Thomas R. Clevenger)
JOHN C. DICUS Directors March 29, 1995 (John C. Dicus)
DAVID H. HUGHES (David H. Hughes)
RUSSELL W. MEYER, JR. (Russell W. Meyer, Jr.)
JOHN H. ROBINSON (John H. Robinson)
MARJORIE I. SETTER (Marjorie I. Setter)
LOUIS W. SMITH (Louis W. Smith)
KENNETH J. WAGNON (Kenneth J. Wagnon)