ITEM 1. BUSINESS
GENERAL
Western Resources, Inc. (formerly The Kansas Power and Light Company, KPL) 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, Missouri and Oklahoma. As used herein, the terms "Company and Western Resources" include its wholly-owned subsidiaries, Astra Resources, Inc., Kansas Gas and Electric Company (KG&E) since March 31, 1992, and KPL Funding Corporation (KFC), unless the context otherwise requires. 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, 1993, the Company had 5,192 employees.
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, were sold for an estimated sale price of $400 million, in cash, based on a calculation as of December 31, 1993. The final sale price will be calculated as of January 31, 1994, within 120 days of closing. Any difference between the estimated and final sale price will be adjusted through a payment to or from the Company.
United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri, for $665,000 in cash.
The operating revenues and operating income (unaudited) related to the Missouri Properties approximated $350 million and $21 million representing approximately 18 percent and seven percent, respectively, of the Company's total for 1993, and $299 million and $11 million representing approximately 19 percent and five percent, respectively, of the Company's total for 1992. Net utility plant (unaudited) for the Missouri Properties, at December 31, 1993, approximated $296 million and $272 million at December 31, 1992. This represents approximately seven percent at December 31, 1993, and six percent at December 31, 1992, of the total Company net utility plant. 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 see Note 13 of the Notes to Consolidated Financial Statements.
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.
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
1993 58% 42% 85% 15% 1992 57% 43% 89% 11% 1991 41% 59% 84% 16% 1990 40% 60% 85% 15% 1989 40% 60% 81% 19%
The difference between the percentage of electric operating revenues in relation to the percentage of electric operating income as compared to the same percentages for gas operations is due to the Company's level of investment in plant and its fuel costs in each of these segments.
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 (Thousands of Dollars)
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 1989 1,092,534 511,733 1,604,267
As a regulated utility, the Company does not have direct competition for retail electric service in its certified service area. However, there is competition, based largely on price, from the generation, or potential generation, of electricity by large commercial and industrial customers, and independent power producers.
Electric utilities have been experiencing problems such as controversy over the safety and use of coal and nuclear power plants, compliance with changing environmental requirements, long construction periods required to complete new generating units resulting in high fixed costs for those facilities, difficulties in obtaining timely and adequate rate relief to recover these high fixed costs, uncertainties in predicting future load requirements, competition from independent power producers and cogenerators, and the effects of changing accounting standards. The problems which most significantly affect the Company are the use, or potential use, of cogeneration or self-generation facilities by large commercial and industrial customers and compliance with environmental requirements. For additional information see Management's Discussion and Analysis and Notes 4 and 5 of the Notes to Consolidated Financial Statements included herein.
Discussion of other factors affecting the Company is set forth in the Notes to Consolidated Financial Statements and Management's Discussion and Analysis included herein.
ELECTRIC OPERATIONS
General. The Company supplies electric energy at retail to approximately 585,000 customers in 462 communities in Kansas. These include Wichita, Topeka, Lawrence, Manhattan, Salina, and Hutchinson. On September 20 1993, the Company completed the purchase of the electric distribution system in DeSoto Kansas. This acquisition added approximately 880 customers to the Company's system. 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):
1993 1992 1991 1990 1989 (Thousands of MWH)
Residential 4,960 3,842 2,556 2,403 2,248 Commercial 5,100 4,473 3,051 2,952 2,814 Industrial 5,301 4,419 1,947 1,954 1,925 Other 4,628 3,119 1,984* 1,820 2,077 Total 19,989 15,853 9,538* 9,129 9,064
* Includes cumulative effect to January 1, 1991, of change in revenue recognition. The cumulative effect of this change increased electric sales by 256,000 MWH.
The Company's electric revenues for the last five years were as follows (includes KG&E since March 31, 1992):
1993 1992 1991 1990 1989 (Thousands of Dollars)
Residential $ 384,618 $296,917 $160,831 $152,509 $142,308 Commercial 319,686 271,303 149,152 146,001 139,567 Industrial 261,898 211,593 78,138 79,225 78,267 Other 138,335 103,072 83,718 85,972 92,201 Total $1,104,537 $882,885 $471,839 $463,707 $452,343
Capacity. The accredited generating capacity of the Company's system is presently 5,184 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, Properties).
The Company's 1993 peak system net load occurred on August 16, 1993 and amounted to 3,821 MW. The Company's net generating capacity together with power available from firm interchange and purchase contracts, provided a capacity margin of approximately 23 percent above system peak responsibility at the time of the peak.
The Company and ten companies in Kansas and western Missouri have agreed to provide capacity (including margin), emergency and economy services for each other. This arrangement is called the MOKAN Power Pool. The pool participants also coordinate the planning of electric generating and transmission facilities.
In January 1994, the Company entered into an agreement with Oklahoma Municipal Power Authority (OMPA), whereby, the Company received a prepayment of approximately $41 million for capacity and transmission charges through the year 2013.
Future Capacity. The Company does not contemplate any significant expenditures in connection with construction of any major generating facilities through the turn of the century (see Management's Discussion and Analysis, Liquidity and Capital Resources). Although the Company's management believes, based on current load-growth projections and load management programs, it will maintain adequate capacity margins through 2000, in view of the lead time required to construct large operating facilities, the Company may be required before 2000 to consider whether to reschedule the construction of Jeffrey Energy Center (JEC) Unit 4 or alternatively either build or acquire other capacity.
Fuel Mix. The Company's coal-fired units comprise 3,186 MW of the total 5,184 MW of generating capacity and the Company's nuclear unit provides 533 MW of capacity. Of the remaining 1,465 MW of generating capacity, units that can burn either natural gas or oil account for 1,373 MW, and the remaining units which burn only oil or diesel account for 92 MW (see Item 2, Properties).
During 1993, low sulfur coal was used to produce 79 percent of the Company's electricity. Nuclear produced 17 percent and the remainder was produced from natural gas, oil, or diesel. Based on the Company's estimate of the availability of fuel, coal will continue to be used to produce approximately 78 percent of the Company's electricity and 18 percent from nuclear.
The Company anticipates the fuel mix to fluctuate with the operation of nuclear powered Wolf Creek which operates on an 18-month refueling and maintenance schedule. The 18-month schedule permits uninterrupted operation every third calendar year. Beginning March 5, 1993, Wolf Creek was taken off- line for its sixth refueling and maintenance outage. The refueling outage took approximately 73 days to complete, during which time electric demand was met primarily by the Company's coal-fired generating units.
Nuclear. The owners of Wolf Creek have on hand or under contract 73 percent of the uranium required for operation of Wolf Creek through the year 2001. The balance is expected to be obtained through spot market and contract purchases.
Contractual arrangements are in place for 100 percent of Wolf Creek's uranium enrichment requirements for 1993-1996, 70 percent for 1997-1998 and 100 percent for 2003-2014. The balance of the 1997-2002 requirements is expected to be obtained through a combination of spot market and contract purchases. The decision not to contract for the full enrichment requirements is one of cost rather than availability of service.
Contractual arrangements are in place for the conversion of uranium to uranium hexafluoride sufficient to meet Wolf Creek's requirements through 1995 as well as the fabrication of fuel assemblies to meet Wolf Creek's requirements through 2012. During 1994, the Company plans to begin securing additional arrangements for uranium conversion for the post 1995 period.
The Nuclear Waste Policy Act of 1982 established schedules, guidelines and responsibilities for the Department of Energy (DOE) to develop and construct repositories for the ultimate disposal of spent fuel and high-level waste. The DOE has not yet constructed a high-level waste disposal site and has announced that a permanent storage facility may not be in operation prior to 2010 although an interim storage facility may be available earlier. Wolf Creek contains an on-site spent fuel storage facility which, under current regulatory guidelines, provides space for the storage of spent fuel through 2006 while still maintaining full core off-load capability. The Company believes adequate additional storage space can be obtained, as necessary.
Coal. The Company has a long-term coal supply contract with Amax Coal West, Inc. (AMAX) a subsidiary of Cyprus Amax Coal Company, to supply low sulfur coal to JEC from AMAX's Eagle Butte Mine or an alternate mine source of AMAX's Belle Ayr Mine, both located in the Powder River Basin in Cambell County, Wyoming. The contract expires December 31, 2020. The contract contains a schedule of minimum annual delivery quantities with deficient mmBTU provisions applicable to deficiencies in the scheduled delivery. The coal to be supplied is surface mined and has an average BTU content of approximately 8,300 BTU per pound and an average sulfur content of .43 lbs/mmBTU (see Environmental Matters). The average delivered cost of coal for JEC was approximately $1.045 per mmBTU or $17.35 per ton during 1993.
Coal is transported from Wyoming under a long-term rail transportation contract with Burlington Northern (BN) and Union Pacific (UP) to JEC through December 31, 2013. Rates are based on net load carrying capabilities of each rail car. The Company provides 770 aluminum rail cars, under a 20 year lease, to transport coal to JEC. During 1994, the Company will provide an additional 120 rail cars under a similar lease.
The two coal fired units at La Cygne generating station have an aggregate generating capacity of 677 MW (KG&E's 50 percent share) (see Item 2.
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, Missouri and Oklahoma (see page 3 with respect to the sale of the Missouri Properties).
During the five years ended December 31, 1993, the Company's gross property additions totalled $852,650,000 and retirements were $125,287,000.
ELECTRIC FACILITIES Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (2)
Abilene Energy Center: Combustion Turbine 1 1973 Gas 67
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 20 3 1951 Gas 31 4 1965 Gas 196 Combustion Turbines 1 1974 Gas 53 2 1974 Gas 51 3 1974 Gas 55 4 1975 Oil 89
Jeffrey Energy Center (84%): Steam Turbines 1 1978 Coal 587 2 1980 Coal 566 3 1983 Coal 588
La Cygne Station (50%): Steam Turbines 1 1973 Coal 342 2 1977 Coal 335
Lawrence Energy Center: Steam Turbines 2 1952 Gas 0 (1) 3 1954 Coal 56 4 1960 Coal 102 5 1971 Coal 380
Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 46 2 1954 Gas--Oil 69 3 1956 Gas--Oil 107 4 1959 Gas--Oil 105
Neosho Energy Center: Steam Turbines 3 1954 Gas--Oil 0 (1)
Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (2)
Tecumseh Energy Center: Steam Turbines 7 1957 Coal 83 8 1962 Coal 147 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 533
Total 5,184
(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, 1993, 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 60 F
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 16,930 MCF per day from this field to meet 1993 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 0.8 BCF to be expanded to 2 BCF. The Company withdrew up to 6,280 MCF per day from this field to meet 1993 winter peaking requirements.
The Company has contracted with Williams Natural Gas Company 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
Information on legal proceedings involving the Company is set forth in Note 15 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 14, 1994, there 45,317 common shareholders of record. For information regarding quarterly common stock price ranges for 1993 and 1992, 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, 1993, 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. Future dividends depend upon future earnings, the financial condition of the Company and other factors. For information regarding quarterly dividend declarations for 1993 and 1992, 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 $2.76 per share of common stock based on 59,294,091 average common shares for 1993, an increase from $2.20 in 1992 on 52,271,932 average common shares. The increase resulted from a return to near normal temperatures compared to unusually mild winter and summer temperatures in 1992, reduced interest costs, and the full twelve month effect of the merger with Kansas Gas and Electric Company (KG&E) on March 31, 1992 (the Merger).
Dividends per common share were $1.94 in 1993, an increase of four cents from 1992. In January 1994, the Board of Directors declared a quarterly dividend of 49 1/2 cents per common share, an increase of one cent over the previous quarter.
The book value per share was $23.08 at December 31, 1993, compared to $21.51 at December 31, 1992. The increase in book value is primarily the result of the issuance of additional common stock and an increase in retained earnings. The 1993 closing stock price of $34 7/8 was 151 percent of book value. There were 61,617,873 common shares outstanding at December 31, 1993.
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 final sale price will be calculated as of January 31, 1994, within 120 days of closing. Any difference between the estimated and final sale price will be adjusted through a payment to or from the Company.
United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri, for $665,000 in cash.
The operating revenues and operating income (unaudited) related to the Missouri Properties approximated $350 million and $21 million representing approximately 18 percent and seven percent, respectively, of the Company's total for 1993, and $299 million and $11 million representing approximately 19 percent and five percent, respectively, of the Company's total for 1992. Net utility plant (unaudited) for the Missouri Properties, at December 31, 1993, approximated $296 million and $272 million at December 31, 1992. This represents approximately seven percent at December 31, 1993, and six percent at December 31, 1992, of the total Company net utility plant. 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.
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 1993, construction expenditures for the Company's electric system were approximately $138 million and nuclear fuel expenditures were approximately $6 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 $94 million during 1993, of which construction expenditures for the Missouri Properties were approximately $39 million.
Capital expenditures for 1994 to 1996 are anticipated to be as follows:
Electric Nuclear Fuel Natural Gas (Dollars in Thousands)
1994 $131,483 $ 20,995 $ 64,608 1995 143,391 21,469 69,482 1996 151,100 9,890 68,747
These expenditures are estimates prepared for planning purposes and are subject to revisions from time to time (see Note 4).
The Company's net cash flow to capital expenditures was 100 percent for 1993 and during the last five years has averaged 87 percent. The Company anticipates net cash flow to capital expenditures to be approximately 100 percent in 1994.
The Company's capital needs through 1998 are approximately $33.6 million for bond maturities and cash sinking fund requirements for bonds and preference stock. This capital as well as capital required for construction will be provided from internal and external sources available under then existing financial conditions.
The Company anticipates using the net proceeds from the sale of the Missouri Properties to reduce the Company's outstanding debt.
The embedded cost of long-term debt was 7.7% at December 31, 1993, a decrease from 7.9% at December 31, 1992. 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 other unsecured lines of credit maintained with banks. At December 31, 1993, short-term borrowings amounted to $441 million, of which $126 million was commercial paper (see Notes 8 and 9).
On September 20, 1993, KG&E terminated a long-term revolving credit agreement which provided for borrowings of up to $150 million. The loan agreement, which was effective through October 1994, was repaid without penalty.
At December 31, 1993, the Company had $200 million of First Mortgage Bonds available to be issued under a shelf registration filed August 24, 1993. Also at December 31, 1993, KG&E had $150 million of First Mortgage Bonds available to be issued under a shelf registration filed on August 24, 1993. On January 20, 1994, KG&E issued $100 million of First Mortgage Bonds, 6.20% Series due January 15, 2006, under the KG&E shelf registration. The net proceeds were used to reduce short-term debt.
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.
KG&E has a long-term agreement that expires in 1995 which contains provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables are accounted for as sales while those related to phase-in revenues are accounted for as collateralized borrowings. At December 31, 1993, KG&E had receivables amounting to $56.8 million which were considered sold.
The issuance and retirement of long-term debt, borrowings against the cash surrender value of corporate-owned life insurance policies (COLI), and the issuance of common stock during 1993 are summarized in the table below.
- ------------------------------------------------------------------------------ | Date Issued Retired | | (Dollars in Millions) | |Long-term debt | |----------------------------------------------------------------------------| |7 3/8% due 2002 - KG&E | 11/22/93 | | $ 25.0| |8 3/8% due 2006 - KG&E | | | 25.0| |8 1/2% due 2007 - KG&E | | | 25.0| |----------------------------------------------------------------------------| |9.35% due 1998 | 10/15/93 | | 75.0| |----------------------------------------------------------------------------| |6 1/2% due 2005 - KG&E | 08/12/93 | $ 65.0| | |8 1/8% due 2001 - KG&E | 08/20/93 | | 35.0| |8 7/8% due 2008 - KG&E | | | 30.0| |----------------------------------------------------------------------------| |7.65% due 2023 | 04/27/93 | 100.0| | |8 3/4% due 2000 | 05/12/93 | | 20.0| |8 5/8% due 2005 | | | 35.0| |8 3/4% due 2008 | | | 35.0| |----------------------------------------------------------------------------| |6% Pollution Control Revenue Refunding | | | | | Bonds due 2033 | 02/09/93 | 58.5| | |9 5/8% Pollution Control Refunding and | | | | | Improvement Revenue Bonds due 2013 | | | 58.5| |----------------------------------------------------------------------------| |Bank term loan | 01/26/93 | | 230.0| |----------------------------------------------------------------------------| |Revolving credit agreements (net) | various | | 35.0| |----------------------------------------------------------------------------| |Other long-term debt and sinking funds | various | 4.1| | |----------------------------------------------------------------------------| |COLI borrowings (net) (1) | various | 183.3| | |----------------------------------------------------------------------------| |Common stock | | | | | 3,425,000 shares (2) | 08/25/93 | 124.2| | | 147,323 shares (3) | various | 5.3| | |----------------------------------------------------------------------------| (1) The COLI borrowings will be repaid upon receipt of proceeds from death benefits under the contracts. See Note 1 of Notes to Consolidated Financial Statements for additional information on the accumulated cash surrender value of COLI policies. (2) Issued in public offering for net proceeds of $121 million. (3) Issued under the Dividend Reinvestment and Stock Purchase Plan (DRIP). The net proceeds from these issues of approximately $5.3 million were added to the general corporate funds of the Company. Shares issued under the DRIP may either be original issue shares or shares purchased on the open market.
The Company has a Customer Stock Purchase Plan (CSPP) under which retail electric and natural gas customers and employees of the Company may purchase common stock through monthly installments. The initial installment period runs from September 1993, through June 1994, with monthly installments plus accumulated interest converted to shares in August 1994. Shares issued under the CSPP may either be original issue shares or shares purchased on the open market. Approximately $14.7 million has been pledged for this installment period.
The capital structure at December 31, 1993, was 45 percent common stock equity, 6 percent preferred and preference stock, and 49 percent long-term debt. The capital structure at December 31, 1993, including short-term debt and current maturities of long-term debt and preference stock, was 40 percent common stock equity, 5 percent preferred and preference stock, and 55 percent debt.
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. 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 FERC, charged for the sale and delivery of natural gas and electricity. Rates are designed to recover the cost of service and allow investors a fair rate of return. Future natural gas and electric sales will continue to be affected by weather conditions, competing fuel sources, customer conservation efforts, and the overall economy of the Company's service area.
The Kansas Corporation Commission (KCC) order approving the 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. The first refund of $8.5 million was made in April 1992. A refund of the same amount was made in December 1993, and an additional refund of $15 million will be 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 increase or decrease in fuel costs from the projected average will be absorbed by the Company.
Future natural gas revenues will be reduced as a result of the sale of the Missouri Properties by approximately $350 million annually based on Missouri revenues recorded in 1993 (see Note 2).
1993 COMPARED TO 1992: Electric revenues increased significantly in 1993 as a result of the Merger. Also contributing to the increase were 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 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 eleven 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.
1992 COMPARED TO 1991: Electric revenues increased significantly in 1992 as a result of the Merger. KG&E electric revenues for the nine months ended December 31, 1992, of $424 million have been included in the Company's electric revenues. Partially offsetting this increase in revenues were reduced retail electric sales as a result of the abnormally mild summer temperatures in 1992 and the amortization of the Merger-related customer refund.
Electric revenues for 1992 compared to pro forma revenues for 1991, giving effect to the Merger as if it had occurred at January 1, 1991, also would have been lower as a result of the mild summer and winter temperatures in 1992. Retail sales of kilowatthours on a pro forma comparative basis decreased from approximately 15.1 billion for 1991 to approximately 14.6 billion for 1992, or four percent.
Natural gas revenues decreased over two percent due to a nine percent decrease in natural gas deliveries, excluding sales related to the cumulative effect of the unbilled revenue adjustment in 1991. Also contributing to the decrease was an approximately four percent decrease in the unit cost of natural gas which is passed on to customers through the PGA. The decrease in sales can be attributed to mild winter temperatures in 1992. Partially offsetting the decreased sales were increased retail rates in Kansas and Missouri beginning early in 1992.
Operating Expenses: 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 (see Note 10).
At December 31, 1993, KG&E completed the accelerated amortization of deferred income tax reserves related to the allowance for borrowed funds used during construction capitalized for Wolf Creek Generating Station. The amortization of these deferred income tax reserves amounted to approximately $12 million in 1993. In accordance with the provisions of the Merger order (see Note 3), the Company is precluded from recovering the $12 million annual amortization in rates until the next rate filing. Therefore the Company's earnings will be impacted negatively until these income taxes are recovered in future rates.
1992 COMPARED TO 1991: Operating expenses increased significantly for 1992 as a result of the Merger. KG&E operating expenses for the nine months ended December 31, 1992, of $316 million have been included in the Company's operating expenses.
Other factors, excluding the Merger, contributing to increased operating expenses were a one-time charge for the Company's portion of the early retirement plan and voluntary separation program of approximately $11 million; higher depreciation and amortization expense caused by increased plant investment and the beginning of the amortization of previously deferred safety-related expenditures in Kansas; and increased property taxes due to increases in plant and tax mill levies.
Partially offsetting those increases in operating expenses was the commencement of savings as a result of the Merger. The Company also changed the depreciable life of Jeffrey Energy Center, for book purposes, to 40 years, resulting in a reduction to depreciation expense of approximately $5.4 million annually. Lower natural gas purchases as a result of the mild temperatures and a reduced unit cost also partially offset the increase in operating expenses.
As permitted under the La Cygne 2 generating station lease agreement, KG&E requested the Trustee Lessor to refinance $341,127,000 of secured facility bonds of the Trustee and owner of La Cygne 2. The transaction was requested to reduce the Company's recurring future net lease expense. To accomplish this transaction, a one-time payment of approximately $27 million was made which will be amortized over the remaining life of the lease and will be included in operating expense as part of the future lower lease expense. On September 29, 1992, the Trustee Lessor refinanced bonds with a coupon rate of approximately 11.7% with bonds having a coupon rate of approximately 7.7%.
Other Income and Deductions: 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.
Other income and deductions, net of taxes, was significantly higher in 1992 compared to 1991 as a result of the Merger. KG&E contributed, for the nine months ended December 31, 1992, $17 million to other income and deductions, net of taxes. Significant items of other income include approximately $9 million from KG&E's COLI and KG&E's recognition of the recovery of approximately $4.2 million of a previously written-off investment in commercial paper.
Interest Charges and Preferred and Preference Dividend Requirements: Interest charges for 1993 were higher as a result of the Merger. KG&E interest charges of $59 million for 1993 have been 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 have been 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. The Company's embedded cost of long-term debt decreased to 7.7% at December 31, 1993, compared to 7.9% and 8.6% at December 31, 1992 and 1991, respectively, primarily as a result of the refinancing of higher cost debt.
Total interest charges increased significantly for 1992 compared to 1991 as a result of the Merger. Partially offsetting this increase were lower short-term and long-term interest rates.
Preferred and preference dividend requirements increased six percent in 1993 and significantly in 1992 compared to 1991 as a result of the issuance of $50 million of 7.58% preference stock in the second quarter of 1992.
Merger Implementation: In accordance with the KCC Merger order, amortization of the acquisition adjustment will commence August 1995. The amortization will amount to approximately $19.6 million 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.
In 1992 the Company completed the consolidation of certain operations of the Company and KG&E. In conjunction with these efforts the Company incurred costs of consolidating facilities, transferring certain employees, and other costs associated with completing the Merger. Certain of these costs related to KG&E have been considered in purchase accounting for the Merger. Other costs, including costs of the early retirement incentive programs and other employee severance compensation programs for former Kansas Power and Light Company employees were charged to expense in 1992. See Note 6 of Notes to Consolidated Financial Statements for a discussion regarding the early retirement and Merger severance plans.
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 requires the Company to seek regulatory rate relief to recover these higher costs.
FERC Order No. 636: On April 8, 1992, the FERC issued Order No. 636 which the FERC intended to complete the deregulation of natural gas production and facilitate competition in the gas transportation industry. Order No. 636 is expected to affect 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 sales service to the restructured services required by Order No. 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.
The Company was an active participant in pipeline restructuring negotiations and does not anticipate any material difficulty in obtaining the pipeline services the Company needs to meet the requirements of its gas operations.
Environmental: The Company has recognized the importance of environmental responsibility and has taken a proactive position with respect to the potential environmental liability associated with former manufactured gas sites. The Company has an agreement with the Kansas Department of Health and Environment to systematically evaluate these sites in Kansas (see Note 4).
The Company currently has no Phase I affected units under the Clean Air Act of 1990. Until such time that additional regulations become final the Company will be unable to determine its compliance options or related compliance costs (see Note 4).
Energy Policy Act: The 1992 Energy Policy Act (Act) requires increased efficiency of energy usage and will potentially change the way electricity is marketed. The Act also provides for increased competition in the wholesale electric market by permitting the FERC to order third party access to utilities' transmission systems and by liberalizing the rules for ownership of generating facilities. As part of the Merger, the Company agreed to open access to its transmission system. Another part of the Act requires a special assessment to be collected from utilities for a uranium enrichment, decontamination, and decommissioning fund. KG&E's portion of the assessment for Wolf Creek is approximately $7 million, payable over 15 years. Management expects such costs to be recovered through the ratemaking process.
Statement of Financial Accounting Standards No. 106 (SFAS 106) and No. 112 (SFAS 112): For discussion regarding the effect of SFAS 106 and SFAS 112 on the Company see Note 6 of Notes to the Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Independent Auditors' Report 33
Financial Statements:
Consolidated Balance Sheets, December 31, 1993 and 1992 34 Consolidated Statements of Income for the years ended December 31, 1993, 1992 and 1991 35 Consolidated Statements of Cash Flows for the years ended 1993, 1992 and 1991 36 Consolidated Statements of Taxes for the years ended December 31, 1993, 1992 and 1991 37 Consolidated Statements of Capitalization, December 31, 1993 and 1992 38 Consolidated Statements of Common Stock Equity for the years ended December 31, 1993, 1992 and 1991 39 Notes to Consolidated Financial Statements 40
Financial Statement Schedules:
V- Utility Plant for the years ended December 31, 1993, 1992 and 1991 67 VI- Accumulated Depreciation of Utility Plant for the years ended December 31, 1993, 1992 and 1991 70
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented: I, II, III, IV, VII, VIII, IX, X, XI, XII and XIII.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the 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, 1993 and 1992, 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, 1993. 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audit 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, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As explained in Note 1 to the consolidated financial statements, effective January 1, 1991, the Company changed to a preferred method of accounting for revenue recognition. As explained in Note 12 to the consolidated financial statements, effective January 1, 1992, the Company changed its method of accounting for income taxes. As explained in Note 6 to the consolidated financial statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedules listed in the table of contents on page 32 are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not a part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion and the opinion of other auditors, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Kansas City, Missouri, ARTHUR ANDERSEN & CO. January 28, 1994
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., Kansas Gas and Electric Company (KG&E) since March 31, 1992 (see Note 3), and KPL Funding Corporation (KFC). 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 Resources, Inc., and KFC are not material to the Company's results of operations. 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 certain state regulatory commissions and the Federal Energy Regulatory Commission (FERC). The Company is doing business as KPL, Gas Service, and, through its wholly-owned subsidiary, KG&E.
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 4.10% in 1993, 5.99% in 1992, and 6.25% in 1991. The cost of additions to utility plant and replacement units of property is capitalized. Maintenance costs and replacement of minor items of property are charged to expense as incurred. When units of depreciable property are retired, they are removed from the plant accounts and the original cost plus removal charges less salvage are charged to accumulated depreciation.
Depreciation: Depreciation is provided on the straight-line method based on estimated useful lives of property. Composite provisions for book depreciation approximated 3.02% during 1993, 3.03% during 1992, and 3.34% during 1991 of the average original cost of depreciable property.
Cash and Cash Equivalents: For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand and highly liquid collateralized debt instruments purchased with maturities of three months or less.
Income Taxes: Income tax expense includes provisions for income taxes currently payable and deferred income taxes calculated in conformance with income tax laws, regulatory orders, and Statement of Financial Accounting Standards No. 109 (SFAS 109) (see Note 12).
Investment tax credits are deferred as realized and amortized to income over the life of the property which gave rise to the credits.
Revenues: Effective January 1, 1991, the Company changed its method of accounting for recognizing electric and natural gas revenues to provide for the accrual of estimated unbilled revenues. The accounting change provides a better matching of revenues with costs of services provided to customers and also serves to conform 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. Meters are read and services are billed on a cycle basis and, prior to the accounting change, revenues were recognized in the accounting period during which services were billed.
The after-tax effect of the change in accounting method for the year ended December 31, 1991, was an increase in net income of $15.9 million or $0.46 per share. This increase was a combination of an increase of $17.3 million or $0.50 per share, attributable to the cumulative effect of the accounting change prior to January 1, 1991, and a decrease of $1.4 million or $0.04 per share in the 1991 income before cumulative effect of a change in accounting principle. Unbilled revenues of $99 and $86 million are recorded as a component of accounts receivable on the consolidated balance sheets as of December 31, 1993 and 1992, respectively. Certain amounts of unbilled revenues have been sold (see Note 8).
The Company had reserves for doubtful accounts receivable of $4.3 and $3.3 million at December 31, 1993 and 1992, respectively.
Fuel Costs: The cost of nuclear fuel in process of refinement,conversion, enrichment, and fabrication is recorded as an asset at original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor at December 31, 1993 and 1992, was $17.4 million and $26.0 million, respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts related to corporate-owned life insurance contracts (COLI), primarily with one highly rated major insurance company, are recorded on the consolidated balance sheets (millions of dollars):
1993 1992 Cash surrender value of contracts. . . $ 326.3 $ 256.3 Prepaid COLI . . . . . . . . . . . . . 11.9 7.0 Borrowings against contracts . . . . . (321.5) (109.6) COLI (net). . . . . . . . . . $ 16.7 $ 153.7
The decrease in COLI (net) is a result of increased borrowings against the accumulated cash surrender value of the COLI policies. The COLI borrowings will be repaid with proceeds from death benefits. Management expects to realize increases in the cash surrender value of contracts resulting from premiums and investment earnings on a tax free basis upon receipt of proceeds from death benefits under the contracts. Interest expense included in other income and deductions, net of taxes, related to KG&E's COLI for 1993 and the nine months ended December 31, 1992, was $11.9 and $5.3 million, respectively.
As approved by the Kansas Corporation Commission (KCC) and Missouri Public Service Commission (MPSC), 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 6) to offset Statement of Financial Accounting Standards No. 106 (SFAS 106) expenses.
Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
2. SALE 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 final sale price will be calculated as of January 31, 1994, within 120 days of closing. Any difference between the estimated and final sale price will be adjusted through a payment to or from the Company.
United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri, for $665,000 in cash.
The operating revenues and operating income (unaudited) related to the Missouri Properties approximated $350 million and $21 million representing approximately 18 percent and seven percent, respectively, of the Company's total for 1993, and $299 million and$11 million representing approximately 19 percent and five percent, respectively, of the Company's total for 1992. Net utility plant (unaudited) for the Missouri Properties, at December 31, 1993, approximated $296 million and $272 million at December 31, 1992. This represents approximately seven percent at December 31, 1993, and six percent at December 31, 1992, of the total Company net utility plant. 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 $294 million under SFAS 109 have been classified as plant acquisition adjustment in electric plant in service on the consolidated balance sheets. The total cost of the acquisition was $1.066 billion. Under the provisions of orders of the KCC and the MPSC 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. The first refund was made in April 1992 and amounted to $8.5 million. A refund of the same amount was made in December 1993 and an additional refund of $15 million will be made in September 1994.
The KCC order approving the Merger requires the legal reorganization of KG&E so that it is no longer held as a separate subsidiary after January 1, 1995, unless good cause is shown why such separate existence should be maintained. The Securities and Exchange Commission order relating to the Merger granted the Company an exemption under the Public Utilities Holding Company Act until January 1, 1995. In connection with a requested ruling that a merger of KG&E into Western Resources would not adversely affect the tax structure of the merger, KG&E received a response from the Internal Revenue Service that the IRS would not issue the requested ruling. In light of the IRS response, KG&E withdrew its request for a ruling. The Company will consider alternative forms of combination or seek regulatory approvals to waive the requirements for a combination. There is no certainty as to whether a combination will occur or as to the form or timing thereof.
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. The pro forma combined revenues, operating income, net income, and earnings per common share of the Company presented below give effect to the Merger as if it had occurred at January 1, 1991. This pro forma information is not necessarily indicative of the results of operations that would have occurred had the Merger been consummated for the period for which it is being given effect nor is it necessarily indicative of future operating results.
Year Ended December 31, 1992 1991 (Dollars in Thousands, except per share amounts)
Revenues. . . . . . . . . . . . $1,684,885 $1,748,844 Operating Income. . . . . . . . 268,772 279,458 Net Income. . . . . . . . . . . 131,524 110,290(1) Earnings Per Common . . . . . . $ 2.03 $ 1.72(1)
(1) Reflects information before the cumulative effect of the January 1, 1991 change in accounting method of recognizing revenues.
4. 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 $86 million at December 31, 1993. Approximately $36 million is attributable to modifications to upgrade the 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.
Environmental: The Company has been associated with 28 (20 in Kansas and 8 in Missouri) former manufactured gas sites which may contain coal tar and other potentially harmful materials. These sites were operated decades ago by other companies, and were acquired by the Company after they had ceased operation. The Environmental Protection Agency (EPA) has performed preliminary assessments of eleven of these sites (EPA sites), six of which are under site investigation. The Company has not received any indication from the EPA that further action will be taken at the EPA sites, nor does the Company have reason to believe there will be any fines or penalties assessed related to these sites. The Company and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement to conduct separate preliminary assessments of the 20 former manufactured gas sites located in Kansas. The preliminary assessments of these 20 sites have been completed at a total cost of approximately $500,000. The Company plans to initiate site investigation and risk assessments at the two highest priority sites in 1994 at a total cost of approximately $500,000. Until such time that risk assessments are completed at these or the remaining sites, it will be impossible to predict the cost of remediation. However, the Company is aware of other utilities in Region VII of the EPA (Kansas, Missouri, Nebraska, and Iowa) which have incurred remediation costs for such sites ranging between $500,000 and $10 million, depending on the site. The Company is also aware that the KCC has permitted another Kansas utility to recover a portion of the remediation costs through rates. To the extent that such remediation costs are not recovered through rates, the costs could be material to the Company's financial position or results of operations depending on the degree of remediation and number of years over which the remediation must be completed.
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, and one is an oil soil contamination site in Springfield, Missouri. The other two sites are solid waste land fills located in Edwardsville and Hutchinson, Kansas. The Company's obligation at these sites appears to be limited, and it is the opinion of the Company's management that the resolution of these matters will not have a material impact on the Company's financial position or results of operations.
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 now pending or that may arise after closing. For any environmental matters now 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 $3.5 million for 1993 and $1.6 million for 1992.
Decommissioning: The Company's share of Wolf Creek decommissioning costs, currently authorized in rates, was estimated to be approximately $97 million in 1988 dollars. Decommissioning costs are being charged to operating expenses. Amounts so expensed are deposited in an external trust fund and will be used solely for the physical decommissioning of the plant. Electric rates charged to customers provide for recovery of these decommissioning costs over the estimated life of Wolf Creek. At December 31, 1993, and December 31, 1992, $13.2 and $9.3 million, respectively, were on deposit in the decommissioning fund. On September 1, 1993, WCNOC filed an application with the KCC for an order approving a 1993 Wolf Creek Decommissioning Cost Study which estimates the Company's share of Wolf Creek decommissioning costs at approximately $174 million in 1993 dollars. If approved by the KCC, management expects substantially all such cost increases to be recovered through the ratemaking process.
The Company carries $164 million in premature decommissioning insurance in the event of a shortfall in the trust fund. The insurance coverage has several restrictions. One of these is that it can only be used if Wolf Creek incurs an accident exceeding $500 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor station site in accordance with a plan approved by the Nuclear Regulatory Commission (NRC), and to pay for on-site property damages. If the amount designated as decommissioning insurance is needed to implement the NRC-approved plan for stabilization and decontamination, it would not be available for decommissioning purposes.
Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.4 billion for a single nuclear incident. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million and the balance is provided by an assessment plan mandated by the NRC. Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $79.3 million ($37.3 million, Company's share) in the event there is a nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index. There is a limitation of $10 million ($4.7 million, Company's share) in retrospective assessments per incident per year.
The Owners carry decontamination liability, premature decommissioning liability, and property damage insurance for Wolf Creek totalling approximately $2.8 billion ($1.3 billion, Company's share). This insurance is provided by a combination of "nuclear insurance pools" ($1.3 billion) and Nuclear Electric Insurance Limited (NEIL) ($1.5 billion). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. The remaining proceeds from the $2.8 billion insurance coverage ($1.3 billion, Company's share), if any, can be used for property damage up to $1.1 billion (Company's share) and premature decommissioning costs up to $117.5 million (Company's share) in excess of funds previously collected for decommissioning (as discussed under "Decommissioning"), with the remaining $47 million (Company's share) available for either property damage or premature decommissioning costs.
The Owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves, and other NEIL resources, the Company may be subject to retrospective assessments of approximately $9 million per year.
There can be no assurance that all potential losses or liabilities will be insurable or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance, to the extent not recoverable through rates, could have a material adverse effect on the Company's financial condition and results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in sulfur dioxide and nitrous oxide emissions effective in 1995 and 2000 and a probable reduction in toxic emissions. To meet the monitoring and reporting requirements under the acid rain program, the Company is installing continuous monitoring and reporting equipment at a total cost of approximately $10 million. At December 31, 1993, the Company had completed approximately $4 million of these capital expenditures with the remaining $6 million of capital expenditures to be completed in 1994 and 1995. The Company does not expect additional equipment to reduce sulfur emissions to be necessary under Phase II. The Company currently has no Phase I affected units.
The nitrous oxide and toxic limits, which were not set in the law, will be specified in future EPA regulations. The EPA has issued for public comment preliminary nitrous oxide regulations for Phase I group 1 units. Nitrous oxide regulations for Phase II units and Phase I group 2 units are mandated in the Act to be promulgated by January 1, 1997. Although the Company has no Phase I units, the final nitrous oxide regulations for Phase I group 1 may allow for early compliance for Phase II group 1 units. Until such time as the Phase I group 1 nitrous oxide regulations are final, the Company will be unable to determine its compliance options or related compliance costs.
Federal Income Taxes: During 1991, the Internal Revenue Service (IRS) completed an examination of 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, 1993, WCNOC's nuclear fuel commitments (Company's share) were approximately $18.0 million for uranium concentrates expiring at various times through 1997, $123.6 million for enrichment expiring at various times through 2014, and $45.5 million for fabrication through 2012. At December 31, 1993, the Company's coal and natural gas contract commitments in 1993 dollars under the remaining term of the contracts were $2.8 billion and $20.4 million, respectively. The largest coal contract was renegotiated early in 1993 and 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.
5. RATE MATTERS AND REGULATION
The Company, under rate orders from certain state regulatory commissions 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. Certain state regulatory commissions 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 increase or decrease in fuel costs from the projected average will be absorbed by the Company.
MPSC Rate Proceedings: On October 5, 1993, the MPSC approved an agreement among the Company, the MPSC staff, and intervenors to increase natural gas rates $9.75 million annually, effective October 15, 1993. Also on October 15, 1993, the Company discontinued the deferral of service line replacement program costs deferred since July 1, 1991, and began amortizing the balance to expense over twenty years. At December 31, 1993, approximately $8.3 million of these deferrals have been included in other deferred charges on the consolidated balance sheet.
On January 22, 1992, the MPSC issued an order authorizing the Company to increase natural gas rates $7.3 million annually.
KCC Rate Proceedings: 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, 1993, approximately $2.9 million of these deferrals have been included in other deferred charges 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 $8.3 million of deferred costs remain in other deferred charges on the consolidated balance sheet at December 31, 1993, with the balance being included in rates and amortized to expense during a 43-month period, commencing January 1, 1992.
Gas Transportation Charges: On September 12, 1991, the KCC authorized the Company to begin recovering, through the PGA, deferred supplier gas transportation costs of $9.9 million incurred through December 31, 1990, based on a three-year amortization schedule. On December 30, 1991, the KCC authorized the Company to recover deferred transportation costs of approximately $2.8 million incurred subsequent to December 31, 1990, through the PGA over a 32-month period. At December 31, 1993, approximately $4.8 million of these deferrals remain in other deferred charges on the consolidated balance sheet.
Tight Sands: In December 1991, the KCC, MPSC, and Oklahoma Corporation Commission (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 that 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.
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 Pittsburgh and Midway Coal Mining Company amounting to $22.5 million. This amount was recorded as a deferred charge on the consolidated balance sheets. 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 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 have been 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. A portion 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 and MPSC have approved mechanisms which are expected to allow the Company to recover these take-or-pay costs from its customers.
6. 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, 1993 1992 1991 (Dollars in Thousands) Pension Cost: Service cost................... $ 9,778 $ 9,847 $ 6,589 Interest cost on projected benefit obligation........... 35,688 29,457 20,985 Return on plan assets.......... (64,113) (38,967) (59,161) Deferred gain on plan assets... 29,190 7,705 38,015 Net amortization............... (669) (948) (131) Net pension cost........... $ 9,874 $ 7,094 $ 6,297
December 31, 1993 1992 1991 (Dollars in Thousands) Funded Status: Actuarial present value of benefit obligations: Vested . . . . . . . . . . . $353,023 $316,100 $200,435 Non-vested . . . . . . . . . 26,983 19,331 13,935 Total. . . . . . . . . . . $380,006 $335,431 $214,370 Plan assets (principally debt and equity securities) at fair value . . . . . . . . . . . $490,339 $452,372 $324,780 Projected benefit obligation . . . 468,996 424,232 282,062 Plan assets in excess of projected benefit obligation . . 21,343 28,140 42,718 Unrecognized transition asset. . . (2,756) (3,092) (1,253) Unrecognized prior service costs . 64,217 55,886 27,216 Unrecognized net gain. . . . . . . (108,783) (106,486) (69,494) Accrued pension costs. . . . . . . $(25,979) $(25,552) $ (813)
Year Ended December 31, 1993 1992 1991 Actuarial Assumptions: Discount rate. . . . . . . . . . 7.0-7.75% 8.0-8.5% 8.0% Annual salary increase rate. . . 5.0 % 6.0% 6.0% Long-term rate of return . . . . 8.0-8.5 % 8.0-8.5% 8.0%
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, the annual expense under SFAS 106 was approximately $26.5 million in 1993 (as compared to approximately $9.6 million on a cash basis) and the Company's total obligation was approximately $166.5 million at December 31, 1993. To mitigate the impact of SFAS 106 expense, the Company has implemented programs to reduce health care costs. In addition, the Company has received orders from the KCC and MPSC permitting the initial deferral of SFAS 106 expense. To mitigate the impact SFAS 106 expense will have on rate increases, the Company will include in the future computation of cost of service the actual SFAS 106 expense and an income stream generated from corporate-owned life insurance (COLI). To the extent SFAS 106 expense exceeds income from the COLI program, this excess will be deferred (as allowed by the FASB Emerging Issues Task Force Issue No. 92-12) and offset by income generated through the deferral period by the COLI program. The OCC is reviewing the Company's application for similar treatment in Oklahoma. Should the OCC require recognition of postretirement benefit costs for regulatory purposes under a different method than that proposed under the Company's application, the impact on earnings would not be material. Should the income stream generated by the COLI program not be sufficient to offset the deferred SFAS 106 expense, the KCC and MPSC orders allow 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 amount included in the consolidated balance sheet:
December 31, 1993 (Dollars in Thousands) Actuarial present value of postretirement benefit obligations: Retirees. . . . . . . . . . . . . . . . . . . . $ 111,499 Active employees fully eligible . . . . . . . . 11,848 Active employees not fully eligible . . . . . . 43,109 Unrecognized prior service cost . . . . . . . . 18,195 Unrecognized transition obligation. . . . . . . (160,731) Unrecognized net loss . . . . . . . . . . . . . (7,100) Balance sheet liability . . . . . . . . . . . . . . $ 16,820
For measurement purposes, an annual health care cost growth rate of 13% was assumed for 1994, decreasing to 6% by 2002 and thereafter. The accumulated post retirement benefit obligation was calculated using a weighted-average discount rate of 7.75%, a weighted-average compensation increase rate of 5.0%, and a weighted-average expected rate of return of 8.5%. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by 1% each year would increase the present value of the accumulated projected benefit obligation by $11.1 million and the aggregate of the service and interest cost components by $1.5 million.
Postemployment: The FASB has issued Statement of Financial Accounting Standards No. 112 (SFAS 112), which establishes accounting and reporting standards for postemployment benefits. The new statement will require the Company to recognize the liability to provide postemployment benefits when the liability has been incurred. The Company adopted SFAS 112 effective January 1, 1994. To mitigate the impact adopting SFAS 112 will have on rate increases, the Company will file applications with the KCC and OCC for orders permitting the initial deferral of SFAS 112 transition costs and expenses and its inclusion in the future computation of cost of service net of an income stream generated from COLI. However, if the state regulatory commissions were to recognize postemployment benefit costs under a different method, 1994 earnings could be impacted negatively. At December 31, 1993, the Company estimates SFAS 112 liability to total approximately $11 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 $5.4, $5.4, and $3.3 million for 1993, 1992, and 1991, 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.
7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in Statement of Financial Accounting Standards No. 107:
Cash and Cash Equivalents- The carrying amount approximates the fair value because of the short-term maturity of these investments. Decommissioning Trust- The fair value of the decommissioning trust is based on quoted market prices at December 31, 1993 and 1992. Variable-rate Debt- The carrying amount approximates the fair value because of the short-term variable rates of these debt instruments. Fixed-rate Debt- The fair value of the fixed-rate debt is based on the sum of the estimated value of each issue taking into consideration the 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, 1993 1992 1993 1992 (Dollars in Thousands) Cash and cash equivalents. . . . . . . $ 1,217 $ 875 $ 1,217 $ 875 Decommissioning trust. . . 13,204 9,272 13,929 9,500 Variable-rate debt . . . . 931,352 758,449 931,352 758,449 Fixed-rate debt. . . . . . 1,364,886 1,508,077 1,473,569 1,563,375 Redeemable preference stock. . . . . . . . . . 150,000 152,733 160,780 161,733
8. 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 took measures to have 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. The sinking fund requirements for certain Western Resources and KG&E pollution control series bonds can be met only through the acquisition and retirement of outstanding bonds. Bonds maturing and acquisition and retirement of bonds for sinking fund requirements for the five years subsequent to December 31, 1993, are as follows:
Maturing Retiring Year Bonds Bonds (Dollars in Thousands)
1994. . . . . $ 2,466 $ 738 1995. . . . . - 753 1996. . . . . 16,000 770 1997. . . . . - 1,333 1998. . . . . - 1,550
Long-term debt outstanding at December 31, 1993 and 1992, was as follows:
1993 1992 (Dollars in Thousands) Western Resources First mortgage bond series: 9.35 % due 1998. . . . . . . . . . . . . $ - $ 75,000 7 1/4% due 1999. . . . . . . . . . . . . 125,000 125,000 7 5/8% due 1999. . . . . . . . . . . . . 19,000 19,000 8 3/4% due 2000. . . . . . . . . . . . . - 20,000 8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000 7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000 8 5/8% due 2005. . . . . . . . . . . . . - 35,000 8 1/8% due 2007. . . . . . . . . . . . . 30,000 30,000 8 3/4% due 2008. . . . . . . . . . . . . - 35,000 8 5/8% due 2017. . . . . . . . . . . . . 50,000 50,000 8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000 7.65% due 2023. . . . . . . . . . . . . 100,000 - 624,000 689,000 Pollution control bond series: 5.90 % due 2007. . . . . . . . . . . . . 31,000 31,500 6 3/4% due 2009. . . . . . . . . . . . . 45,000 45,000 9 5/8% due 2013. . . . . . . . . . . . . - 58,500 6% due 2033. . . . . . . . . . . . . 58,500 - 134,500 135,000 KG&E First mortgage bond series: 5 5/8% due 1996. . . . . . . . . . . . . 16,000 16,000 8 1/8% due 2001. . . . . . . . . . . . . - 35,000 7 3/8% due 2002. . . . . . . . . . . . . - 25,000 7.60% due 2003. . . . . . . . . . . . . 135,000 135,000 6 1/2% due 2005. . . . . . . . . . . . . 65,000 - 8 3/8% due 2006. . . . . . . . . . . . . - 25,000 8 1/2% due 2007. . . . . . . . . . . . . - 25,000 8 7/8% due 2008. . . . . . . . . . . . . - 30,000 216,000 291,000 Pollution control bond series: 6.80% due 2004. . . . . . . . . . . . . 14,500 14,500 5 7/8% due 2007. . . . . . . . . . . . . 21,940 21,940 6% due 2007. . . . . . . . . . . . . 10,000 10,000 7.0% due 2031. . . . . . . . . . . . . 327,500 327,500 373,940 373,940 GSC First mortgage bond series: 8 1/2% due 1997. . . . . . . . . . . . . 2,466 4,932 2,466 4,932
Bank term loan . . . . . . . . . . . . . . - 230,000 Other pollution control obligations. . . . 13,980 14,205 Revolving credit agreement . . . . . . . . 115,000 150,000 Other long term agreement. . . . . . . . . 53,913 46,640 Less: Unamortized debt discount. . . . . . . . 6,607 6,730 Long-term debt due within one year . . . 3,204 1,961 $1,523,988 $1,926,026
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. The revolver has an initial term of three years with options to renew for an additional two years with the consent of the banks. The unused portion of the revolving credit facility may be used to provide support for outstanding short-term debt. At December 31, 1993, $115 million was outstanding under the facility.
On September 20, 1993, KG&E terminated a long-term revolving credit agreement which provided for borrowings of up to $150 million. The loan agreement, which was effective through October 1994, was repaid without penalty.
KG&E has a long-term agreement, expiring in 1995, which contains provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables are accounted for as sales while those related to phase-in revenues are accounted for as collateralized borrowings. Additional receivables are continually sold to replace those collected. At December 31, 1993 and 1992, outstanding receivables amounting to $56.8 and $47.7 million, respectively, were considered sold under the agreement. The credit risk associated with the sale of customer accounts receivable is considered minimal. The weighted average interest rate, including fees, was 3.7% for the year ended December 31, 1993, and 6.6% for the nine months ended December 31, 1992. At December 31, 1993, an additional $16.4 million was available under the agreement.
9. SHORT-TERM 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 other unsecured lines of credit maintained with banks. Information concerning these arrangements for the years ended December 31, 1993, 1992, and 1991, is set forth below:
Year Ended December 31, 1993 1992 1991 (Dollars in Thousands) Lines of credit at year end. . . . $145,000 $250,000(1) $185,000(2) Short-term debt out- standing at year end . . . . . . 440,895 222,225 135,800 Weighted average interest rate on debt outstanding at year end (including fees) . . . . . . 3.67% 4.70% 5.07% Maximum amount of short- term debt outstanding during the period. . . .. . . . . . . . $443,895 $263,900 $175,000 Monthly average short-term debt. . 347,278 179,577 125,968 Weighted daily average interest rates during the year (including fees) . . . . . . . . 3.44% 4.90% 6.69%
(1) Decreased to $155 million in January 1993. (2) Increased to $200 million in January 1992.
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.
10. LEASES
At December 31, 1993, 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 Ending December 31, Leases Leases (Dollars in Thousands) 1991 $ 1,217 $21,501 1992 2,426 52,701 1993 3,272 55,011 Future Commitments: 1994 $ 4,002 $47,729 1995 3,752 45,825 1996 3,627 44,176 1997 1,209 41,644 1998 - 41,019 Thereafter - 771,157 Total $12,590 $ 991,550 Less Interest 1,466 Net obligation $11,124
In 1987, KG&E sold and leased back its 50 percent undivided interest in La Cygne 2. The 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 lease agreement, the Company in 1992 requested the Trustee Lessor to refinance $341.1 million of secured facility bonds of the Trustee and owner of La Cygne 2. The transaction was requested to reduce recurring future net lease expense. In connection with the refinancing on September 29, 1992, a one-time payment of approximately $27 million was made by the Company which has been deferred and is being amortized over the remaining life of the lease and included in operating expense as part of the future lease expense.
Future minimum annual lease payments, included in the table above, required under the lease agreement are approximately $34.6 million for each year through 1998 and $715 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale has been deferred for financial reporting purposes, and is being amortized over the initial lease term in proportion to the related lease expense. KG&E's lease expense, net of amortization of the deferred gain and a one-time payment, was approximately $22.5 million for the year ended December 31, 1993, and $20.6 million for the nine months ended December 31, 1992.
11. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1993 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 150,265 $ 91,175 342 50 Jeffrey 1 (b) Jul 1978 277,087 116,526 587 84 Jeffrey 2 (b) May 1980 274,018 106,301 566 84 Jeffrey 3 (b) May 1983 386,925 124,158 588 84 Wolf Creek (c) Sep 1985 1,366,387 281,819 533 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL) (b) Jointly owned with UtiliCorp United Inc. and a third party (c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity represent the Company's share. The Company's share of operating expenses of the plants in service above, as well as such expenses for a 50 percent undivided interest in La Cygne 2 (representing 335 MW capacity) sold and leased back to the Company in 1987, are included in operating expenses in the statements of income. The Company's share of other transactions associated with the plants is included in the appropriate classification in the Company's consolidated financial statements.
12. 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, the MPSC, 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, 1993, KG&E has unused investment tax credits of approximately $7.1 million available for carryforward which, if not utilized, will expire in the years 2000 through 2002. In addition, the Company has alternative minimum tax credits generated prior to April 1, 1992, which carryforward without expiration, of $57.2 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, 1993.
Deferred income taxes result from temporary differences between the financial statement and tax basis of the Company's assets and liabilities. The sources of these differences and their cumulative tax effects are as follows:
December 31, 1993 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (647,202) $ (647,202) 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 . . . - (117,549) (117,549) Other. . . . . . . . . . . . . . . - (14,039) (14,039) Total Deferred Income Taxes. . . . . $ 169,821 $(1,138,458) $ (968,637)
December 31, 1992 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (607,303) $ (607,303) Energy and purchased gas adjustment clauses . . . . . . . - (7,717) (7,717) Phase-in revenues. . . . . . . . . - (37,564) (37,564) Natural gas line survey and replacement program. . . . . . . - (7,473) (7,473) Deferred gain on sale-leaseback. . 104,573 - 104,573 Alternative minimum tax credits. . 39,882 - 39,882 Deferred coal contract settlements. . . . . . . . . . . - (9,318) (9,318) Deferred compensation/pension liability. . . . . . . . . . . . 8,488 - 8,488 Acquisition premium. . . . . . . . - (314,241) (314,241) Deferred future income taxes . . . - (158,102) (158,102) Other. . . . . . . . . . . . . . . - (1,380) (1,380) Total Deferred Income Taxes. . . . . $ 152,943 $(1,143,098) $ (990,155)
13. 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, Missouri, and Oklahoma.
Year Ended December 31, 1993 1992(1) 1991 (Dollars in Thousands) Operating revenues: Electric. . . . . . . . . . . $1,104,537 $ 882,885 $ 471,839 Natural gas . . . . . . . . . 804,822 673,363 690,339 1,909,359 1,556,248 1,162,178
Operating expenses excluding income taxes: Electric. . . . . . . . . . . 791,563 632,169 337,150 Natural gas . . . . . . . . . 747,755 642,910 664,825 1,539,318 1,275,079 1,001,975
Income taxes: Electric. . . . . . . . . . . 73,425 41,184 32,239 Natural gas . . . . . . . . . 4,553 816 (1,657) 77,978 42,000 30,582
Operating income: Electric. . . . . . . . . . . 239,549 209,532 102,450 Natural gas . . . . . . . . . 52,514 29,637 27,171 $ 292,063 $ 239,169 $ 129,621
Identifiable assets at December 31: Electric. . . . . . . . . . . $4,231,277 $4,390,117 $1,196,023 Natural gas . . . . . . . . . 1,040,513 918,729 840,692 Other corporate assets(2) . . 140,258 130,060 75,798 $5,412,048 $5,438,906 $2,112,513
Other Information-- Depreciation and amortization: Electric. . . . . . . . . . . $ 126,034 $ 105,842 $ 53,632 Natural gas . . . . . . . . . 38,330 38,171 32,103 $ 164,364 $ 144,013 $ 85,735
Maintenance: Electric. . . . . . . . . . . $ 87,696 $ 73,104 $ 34,240 Natural gas . . . . . . . . . 30,147 28,507 26,275 $ 117,843 $ 101,611 $ 60,515
Capital expenditures: Electric. . . . . . . . . . . $ 137,874 $ 95,465 $ 43,714 Nuclear fuel. . . . . . . . . 5,702 15,839 - Natural gas . . . . . . . . . 94,055 91,189 81,961 $ 237,631 $ 202,493 $ 125,675
(1)Information reflects the merger with KG&E on March 31, 1992. (2)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 (unaudited):
(Dollars in Thousands) Natural gas revenues. . . . . . . . . . $ 349,749 Operating expenses excluding income taxes. . . . . . . . . 326,329 Income taxes. . . . . . . . . . . . . . 2,672 Operating income. . . . . . . . . . . . 20,748 Identifiable assets . . . . . . . . . . 398,464 Depreciation and amortization . . . . . 12,668 Maintenance . . . . . . . . . . . . . . 10,504 Capital expenditures. . . . . . . . . . 38,821
14. 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. During 1993, the Company issued 3,572,323 shares of common stock and at December 31, 1993, 61,617,873 shares were outstanding.
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: On October 1, 1993, the Company redeemed the remaining 22,000 shares of the 8.70% Series preference stock.
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 $107.37, $106.80, and $106.23 per share beginning July 1, 1993, 1994, and 1995, 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 $106.82, $106.06, and $105.31 per share beginning April 1, 1993, 1994, and 1995, respectively.
15. LEGAL PROCEEDINGS
The Company and its subsidiaries are involved in various legal and environmental proceedings. Management believes that adequate provision has been made within the consolidated financial statements for these 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.
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) 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
1992(1) Operating revenues. . . . . . . $373,620 $341,715 $380,745 $460,168 Operating income. . . . . . . . 42,684 45,830 77,010 73,645 Net income. . . . . . . . . . . 27,984 18,434 42,185 39,281 Earnings applicable to common stock. . . . . . . . . 25,472 15,113 38,726 35,822 Earnings per share. . . . . . . $ 0.74 $ 0.26 $ 0.67 $ 0.62 Dividends per share . . . . . . $ 0.475 $ 0.475 $ 0.475 $ 0.475 Average common shares outstanding . . . . . . . . . 34,566 58,046 58,046 58,046 Common stock price: High. . . . . . . . . . . . . $ 29 1/2 $ 26 7/8 $ 30 1/2 $ 32 5/8 Low . . . . . . . . . . . . . $ 25 3/8 $ 25 1/4 $ 26 3/4 $ 28 1/2
(1) Information reflects the merger with KG&E on March 31, 1992.
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 1994 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 18 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 1994 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 1994 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
The information required by Item 13 is set forth in the Company's definitive proxy statement for its 1994 Annual Meeting of Shareholders to be filed with the Commission. Such information is incorporated herein by reference to the material appearing under the caption Transactions with Management in the proxy statement to be filed by the Company with the Commission.
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, 1993 and 1992 Consolidated Statements of Income - years ended December 31, 1993, 1992 and 1991 Consolidated Statements of Cash Flows - years ended December 31, 1993, 1992 and 1991 Consolidated Statements of Taxes - years ended December 31, 1993, 1992 and 1991 Consolidated Statements of Capitalization - December 31, 1993 and Consolidated Statements of Common Stock Equity - years ended December 31, 1993, 1992 and 1991 Notes to Consolidated Financial Statements
The following supplemental schedules are included herein.
SCHEDULES
Schedule V - Utility Plant - years ended December 31, 1993, 1992 and 1991 Schedule VI - Accumulated Depreciation of Utility Plant - years ended December 31, 1993, 1992 and 1991
Schedules omitted as not applicable or not required under the Rules of regulation S-X: I, II, III, IV, VII, VIII, IX, X, XI, XII, and XIII
REPORTS ON FORM 8-K
Form 8-K dated February 2, 1994
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) -By-laws of the Company, as amended July 15, 1987. (filed as I Exhibit 3(d) to the December 1987 Form 10-K) 3(d) -Certificate of Designation of Preference Stock, 8.50% Series, without par value. (filed electronically) 3(e) -Certificate of Designation of Preference Stock, 7.58% Series, without par value. (filed electronically) 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) 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)
Description
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)
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) -Agreement between the Company and AMAX Coal West Inc. effective March 31, 1993. (filed electronically) 10(b) -Agreement between the Company and Williams Natural Gas Company dated October 1, 1993. (filed electronically) 10(c) -Agreement between the Company and Williams Natural Gas Company dated October 1, 1993. (filed electronically) 10(d) -Agreement between the Company and Williams Natural Gas Company dated October 1, 1993. (filed electronically) 10(e) -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(f) -Letter of Agreement between The Kansas Power and Light Company and I John E. Hayes, Jr., dated November 20, 1989. (filed as Exhibit 10(w) to the December 1989 Form 10-K) 10(g) -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(h) -Deferred Compensation Plan 10(i) -Long-term Incentive Plan 10(j) -Short-term Incentive Plan 10(k) -Outside Directors' Deferred Compensation Plan 12 -Computation of Ratio of Consolidated Earnings to Fixed Charges. (filed electronically) 16 -Letter re Change in Certifying Accountant. (filed as Exhibit 16 I to the Current Report on Form 8-K dated March 8, 1993) 21 -Subsidiaries of the Registrant. (filed as Exhibit 22 to the I December 1992 Form 10-K) 23(a) -Consent of Independent Public Accountants, Arthur Andersen & Co. (filed electronically) 23(b) -Consent of Independent Public Accountants, Deloitte & Touche (filed electronically)) 23(c) -Consent of K&A Energy Consultants, Inc. (filed as Exhibit 24(b) I to the December 1988 Form 10-K) 99(a) -Kansas Gas and Electric Company's Annual Report on Form 10-K for the year ended December 31, 1993 (filed electronically) 99(b) -Report of K&A Energy Consultants, Inc. (filed as Exhibit 28 to I the December 1988 Form 10-K)
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 18, 1994 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 18, 1994 (John E. Hayes, Jr.) (Principal Executive Officer)
Executive Vice President and S. L. KITCHEN Chief Financial Officer March 18, 1994 (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 18, 1994 (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 $2.76 per share of common stock based on 59,294,091 average common shares for 1993, an increase from $2.20 in 1992 on 52,271,932 average common shares. The increase resulted from a return to near normal temperatures compared to unusually mild winter and summer temperatures in 1992, reduced interest costs, and the full twelve month effect of the merger with Kansas Gas and Electric Company (KG&E) on March 31, 1992 (the Merger).
Dividends per common share were $1.94 in 1993, an increase of four cents from 1992. In January 1994, the Board of Directors declared a quarterly dividend of 49 1/2 cents per common share, an increase of one cent over the previous quarter.
The book value per share was $23.08 at December 31, 1993, compared to $21.51 at December 31, 1992. The increase in book value is primarily the result of the issuance of additional common stock and an increase in retained earnings. The 1993 closing stock price of $34 7/8 was 151 percent of book value. There were 61,617,873 common shares outstanding at December 31, 1993.
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 final sale price will be calculated as of January 31, 1994, within 120 days of closing. Any difference between the estimated and final sale price will be adjusted through a payment to or from the Company.
United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri, for $665,000 in cash.
The operating revenues and operating income (unaudited) related to the Missouri Properties approximated $350 million and $21 million representing approximately 18 percent and seven percent, respectively, of the Company's total for 1993, and $299 million and $11 million representing approximately 19 percent and five percent, respectively, of the Company's total for 1992. Net utility plant (unaudited) for the Missouri Properties, at December 31, 1993, approximated $296 million and $272 million at December 31, 1992. This represents approximately seven percent at December 31, 1993, and six percent at December 31, 1992, of the total Company net utility plant. 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.
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 1993, construction expenditures for the Company's electric system were approximately $138 million and nuclear fuel expenditures were approximately $6 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 $94 million during 1993, of which construction expenditures for the Missouri Properties were approximately $39 million.
Capital expenditures for 1994 to 1996 are anticipated to be as follows:
Electric Nuclear Fuel Natural Gas (Dollars in Thousands)
1994 $131,483 $ 20,995 $ 64,608 1995 143,391 21,469 69,482 1996 151,100 9,890 68,747
These expenditures are estimates prepared for planning purposes and are subject to revisions from time to time (see Note 4).
The Company's net cash flow to capital expenditures was 100 percent for 1993 and during the last five years has averaged 87 percent. The Company anticipates net cash flow to capital expenditures to be approximately 100 percent in 1994.
The Company's capital needs through 1998 are approximately $33.6 million for bond maturities and cash sinking fund requirements for bonds and preference stock. This capital as well as capital required for construction will be provided from internal and external sources available under then existing financial conditions.
The Company anticipates using the net proceeds from the sale of the Missouri Properties to reduce the Company's outstanding debt.
The embedded cost of long-term debt was 7.7% at December 31, 1993, a decrease from 7.9% at December 31, 1992. 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 other unsecured lines of credit maintained with banks. At December 31, 1993, short-term borrowings amounted to $441 million, of which $126 million was commercial paper (see Notes 8 and 9).
On September 20, 1993, KG&E terminated a long-term revolving credit agreement which provided for borrowings of up to $150 million. The loan agreement, which was effective through October 1994, was repaid without penalty.
At December 31, 1993, the Company had $200 million of First Mortgage Bonds available to be issued under a shelf registration filed August 24, 1993. Also at December 31, 1993, KG&E had $150 million of First Mortgage Bonds available to be issued under a shelf registration filed on August 24, 1993. On January 20, 1994, KG&E issued $100 million of First Mortgage Bonds, 6.20% Series due January 15, 2006, under the KG&E shelf registration. The net proceeds were used to reduce short-term debt.
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.
KG&E has a long-term agreement that expires in 1995 which contains provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables are accounted for as sales while those related to phase-in revenues are accounted for as collateralized borrowings. At December 31, 1993, KG&E had receivables amounting to $56.8 million which were considered sold.
The issuance and retirement of long-term debt, borrowings against the cash surrender value of corporate-owned life insurance policies (COLI), and the issuance of common stock during 1993 are summarized in the table below.
- ------------------------------------------------------------------------------ | Date Issued Retired | | (Dollars in Millions) | |Long-term debt | |----------------------------------------------------------------------------| |7 3/8% due 2002 - KG&E | 11/22/93 | | $ 25.0| |8 3/8% due 2006 - KG&E | | | 25.0| |8 1/2% due 2007 - KG&E | | | 25.0| |----------------------------------------------------------------------------| |9.35% due 1998 | 10/15/93 | | 75.0| |----------------------------------------------------------------------------| |6 1/2% due 2005 - KG&E | 08/12/93 | $ 65.0| | |8 1/8% due 2001 - KG&E | 08/20/93 | | 35.0| |8 7/8% due 2008 - KG&E | | | 30.0| |----------------------------------------------------------------------------| |7.65% due 2023 | 04/27/93 | 100.0| | |8 3/4% due 2000 | 05/12/93 | | 20.0| |8 5/8% due 2005 | | | 35.0| |8 3/4% due 2008 | | | 35.0| |----------------------------------------------------------------------------| |6% Pollution Control Revenue Refunding | | | | | Bonds due 2033 | 02/09/93 | 58.5| | |9 5/8% Pollution Control Refunding and | | | | | Improvement Revenue Bonds due 2013 | | | 58.5| |----------------------------------------------------------------------------| |Bank term loan | 01/26/93 | | 230.0| |----------------------------------------------------------------------------| |Revolving credit agreements (net) | various | | 35.0| |----------------------------------------------------------------------------| |Other long-term debt and sinking funds | various | 4.1| | |----------------------------------------------------------------------------| |COLI borrowings (net) (1) | various | 183.3| | |----------------------------------------------------------------------------| |Common stock | | | | | 3,425,000 shares (2) | 08/25/93 | 124.2| | | 147,323 shares (3) | various | 5.3| | |----------------------------------------------------------------------------| (1) The COLI borrowings will be repaid upon receipt of proceeds from death benefits under the contracts. See Note 1 of Notes to Consolidated Financial Statements for additional information on the accumulated cash surrender value of COLI policies. (2) Issued in public offering for net proceeds of $121 million. (3) Issued under the Dividend Reinvestment and Stock Purchase Plan (DRIP). The net proceeds from these issues of approximately $5.3 million were added to the general corporate funds of the Company. Shares issued under the DRIP may either be original issue shares or shares purchased on the open market.
The Company has a Customer Stock Purchase Plan (CSPP) under which retail electric and natural gas customers and employees of the Company may purchase common stock through monthly installments. The initial installment period runs from September 1993, through June 1994, with monthly installments plus accumulated interest converted to shares in August 1994. Shares issued under the CSPP may either be original issue shares or shares purchased on the open market. Approximately $14.7 million has been pledged for this installment period.
The capital structure at December 31, 1993, was 45 percent common stock equity, 6 percent preferred and preference stock, and 49 percent long-term debt. The capital structure at December 31, 1993, including short-term debt and current maturities of long-term debt and preference stock, was 40 percent common stock equity, 5 percent preferred and preference stock, and 55 percent debt.
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. 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 FERC, charged for the sale and delivery of natural gas and electricity. Rates are designed to recover the cost of service and allow investors a fair rate of return. Future natural gas and electric sales will continue to be affected by weather conditions, competing fuel sources, customer conservation efforts, and the overall economy of the Company's service area.
The Kansas Corporation Commission (KCC) order approving the 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. The first refund of $8.5 million was made in April 1992. A refund of the same amount was made in December 1993, and an additional refund of $15 million will be 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 increase or decrease in fuel costs from the projected average will be absorbed by the Company.
Future natural gas revenues will be reduced as a result of the sale of the Missouri Properties by approximately $350 million annually based on Missouri revenues recorded in 1993 (see Note 2).
1993 COMPARED TO 1992: Electric revenues increased significantly in 1993 as a result of the Merger. Also contributing to the increase were 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 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 eleven 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.
1992 COMPARED TO 1991: Electric revenues increased significantly in 1992 as a result of the Merger. KG&E electric revenues for the nine months ended December 31, 1992, of $424 million have been included in the Company's electric revenues. Partially offsetting this increase in revenues were reduced retail electric sales as a result of the abnormally mild summer temperatures in 1992 and the amortization of the Merger-related customer refund.
Electric revenues for 1992 compared to pro forma revenues for 1991, giving effect to the Merger as if it had occurred at January 1, 1991, also would have been lower as a result of the mild summer and winter temperatures in 1992. Retail sales of kilowatthours on a pro forma comparative basis decreased from approximately 15.1 billion for 1991 to approximately 14.6 billion for 1992, or four percent.
Natural gas revenues decreased over two percent due to a nine percent decrease in natural gas deliveries, excluding sales related to the cumulative effect of the unbilled revenue adjustment in 1991. Also contributing to the decrease was an approximately four percent decrease in the unit cost of natural gas which is passed on to customers through the PGA. The decrease in sales can be attributed to mild winter temperatures in 1992. Partially offsetting the decreased sales were increased retail rates in Kansas and Missouri beginning early in 1992.
Operating Expenses: 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 (see Note 10).
At December 31, 1993, KG&E completed the accelerated amortization of deferred income tax reserves related to the allowance for borrowed funds used during construction capitalized for Wolf Creek Generating Station. The amortization of these deferred income tax reserves amounted to approximately $12 million in 1993. In accordance with the provisions of the Merger order (see Note 3), the Company is precluded from recovering the $12 million annual amortization in rates until the next rate filing. Therefore the Company's earnings will be impacted negatively until these income taxes are recovered in future rates.
1992 COMPARED TO 1991: Operating expenses increased significantly for 1992 as a result of the Merger. KG&E operating expenses for the nine months ended December 31, 1992, of $316 million have been included in the Company's operating expenses.
Other factors, excluding the Merger, contributing to increased operating expenses were a one-time charge for the Company's portion of the early retirement plan and voluntary separation program of approximately $11 million; higher depreciation and amortization expense caused by increased plant investment and the beginning of the amortization of previously deferred safety-related expenditures in Kansas; and increased property taxes due to increases in plant and tax mill levies.
Partially offsetting those increases in operating expenses was the commencement of savings as a result of the Merger. The Company also changed the depreciable life of Jeffrey Energy Center, for book purposes, to 40 years, resulting in a reduction to depreciation expense of approximately $5.4 million annually. Lower natural gas purchases as a result of the mild temperatures and a reduced unit cost also partially offset the increase in operating expenses.
As permitted under the La Cygne 2 generating station lease agreement, KG&E requested the Trustee Lessor to refinance $341,127,000 of secured facility bonds of the Trustee and owner of La Cygne 2. The transaction was requested to reduce the Company's recurring future net lease expense. To accomplish this transaction, a one-time payment of approximately $27 million was made which will be amortized over the remaining life of the lease and will be included in operating expense as part of the future lower lease expense. On September 29, 1992, the Trustee Lessor refinanced bonds with a coupon rate of approximately 11.7% with bonds having a coupon rate of approximately 7.7%.
Other Income and Deductions: 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.
Other income and deductions, net of taxes, was significantly higher in 1992 compared to 1991 as a result of the Merger. KG&E contributed, for the nine months ended December 31, 1992, $17 million to other income and deductions, net of taxes. Significant items of other income include approximately $9 million from KG&E's COLI and KG&E's recognition of the recovery of approximately $4.2 million of a previously written-off investment in commercial paper.
Interest Charges and Preferred and Preference Dividend Requirements: Interest charges for 1993 were higher as a result of the Merger. KG&E interest charges of $59 million for 1993 have been 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 have been 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. The Company's embedded cost of long-term debt decreased to 7.7% at December 31, 1993, compared to 7.9% and 8.6% at December 31, 1992 and 1991, respectively, primarily as a result of the refinancing of higher cost debt.
Total interest charges increased significantly for 1992 compared to 1991 as a result of the Merger. Partially offsetting this increase were lower short-term and long-term interest rates.
Preferred and preference dividend requirements increased six percent in 1993 and significantly in 1992 compared to 1991 as a result of the issuance of $50 million of 7.58% preference stock in the second quarter of 1992.
Merger Implementation: In accordance with the KCC Merger order, amortization of the acquisition adjustment will commence August 1995. The amortization will amount to approximately $19.6 million 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.
In 1992 the Company completed the consolidation of certain operations of the Company and KG&E. In conjunction with these efforts the Company incurred costs of consolidating facilities, transferring certain employees, and other costs associated with completing the Merger. Certain of these costs related to KG&E have been considered in purchase accounting for the Merger. Other costs, including costs of the early retirement incentive programs and other employee severance compensation programs for former Kansas Power and Light Company employees were charged to expense in 1992. See Note 6 of Notes to Consolidated Financial Statements for a discussion regarding the early retirement and Merger severance plans.
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 requires the Company to seek regulatory rate relief to recover these higher costs.
FERC Order No. 636: On April 8, 1992, the FERC issued Order No. 636 which the FERC intended to complete the deregulation of natural gas production and facilitate competition in the gas transportation industry. Order No. 636 is expected to affect 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 sales service to the restructured services required by Order No. 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.
The Company was an active participant in pipeline restructuring negotiations and does not anticipate any material difficulty in obtaining the pipeline services the Company needs to meet the requirements of its gas operations.
Environmental: The Company has recognized the importance of environmental responsibility and has taken a proactive position with respect to the potential environmental liability associated with former manufactured gas sites. The Company has an agreement with the Kansas Department of Health and Environment to systematically evaluate these sites in Kansas (see Note 4).
The Company currently has no Phase I affected units under the Clean Air Act of 1990. Until such time that additional regulations become final the Company will be unable to determine its compliance options or related compliance costs (see Note 4).
Energy Policy Act: The 1992 Energy Policy Act (Act) requires increased efficiency of energy usage and will potentially change the way electricity is marketed. The Act also provides for increased competition in the wholesale electric market by permitting the FERC to order third party access to utilities' transmission systems and by liberalizing the rules for ownership of generating facilities. As part of the Merger, the Company agreed to open access to its transmission system. Another part of the Act requires a special assessment to be collected from utilities for a uranium enrichment, decontamination, and decommissioning fund. KG&E's portion of the assessment for Wolf Creek is approximately $7 million, payable over 15 years. Management expects such costs to be recovered through the ratemaking process.
Statement of Financial Accounting Standards No. 106 (SFAS 106) and No. 112 (SFAS 112): For discussion regarding the effect of SFAS 106 and SFAS 112 on the Company see Note 6 of Notes to the Consolidated Financial Statements.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS PAGE
Independent Auditors' Report 33
Financial Statements:
Consolidated Balance Sheets, December 31, 1993 and 1992 34 Consolidated Statements of Income for the years ended December 31, 1993, 1992 and 1991 35 Consolidated Statements of Cash Flows for the years ended 1993, 1992 and 1991 36 Consolidated Statements of Taxes for the years ended December 31, 1993, 1992 and 1991 37 Consolidated Statements of Capitalization, December 31, 1993 and 1992 38 Consolidated Statements of Common Stock Equity for the years ended December 31, 1993, 1992 and 1991 39 Notes to Consolidated Financial Statements 40
Financial Statement Schedules:
V- Utility Plant for the years ended December 31, 1993, 1992 and 1991 67 VI- Accumulated Depreciation of Utility Plant for the years ended December 31, 1993, 1992 and 1991 70
SCHEDULES OMITTED
The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented: I, II, III, IV, VII, VIII, IX, X, XI, XII and XIII.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the 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, 1993 and 1992, 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, 1993. 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audit 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, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As explained in Note 1 to the consolidated financial statements, effective January 1, 1991, the Company changed to a preferred method of accounting for revenue recognition. As explained in Note 12 to the consolidated financial statements, effective January 1, 1992, the Company changed its method of accounting for income taxes. As explained in Note 6 to the consolidated financial statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedules listed in the table of contents on page 32 are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not a part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion and the opinion of other auditors, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Kansas City, Missouri, ARTHUR ANDERSEN & CO. January 28, 1994
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., Kansas Gas and Electric Company (KG&E) since March 31, 1992 (see Note 3), and KPL Funding Corporation (KFC). 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 Resources, Inc., and KFC are not material to the Company's results of operations. 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 certain state regulatory commissions and the Federal Energy Regulatory Commission (FERC). The Company is doing business as KPL, Gas Service, and, through its wholly-owned subsidiary, KG&E.
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 4.10% in 1993, 5.99% in 1992, and 6.25% in 1991. The cost of additions to utility plant and replacement units of property is capitalized. Maintenance costs and replacement of minor items of property are charged to expense as incurred. When units of depreciable property are retired, they are removed from the plant accounts and the original cost plus removal charges less salvage are charged to accumulated depreciation.
Depreciation: Depreciation is provided on the straight-line method based on estimated useful lives of property. Composite provisions for book depreciation approximated 3.02% during 1993, 3.03% during 1992, and 3.34% during 1991 of the average original cost of depreciable property.
Cash and Cash Equivalents: For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand and highly liquid collateralized debt instruments purchased with maturities of three months or less.
Income Taxes: Income tax expense includes provisions for income taxes currently payable and deferred income taxes calculated in conformance with income tax laws, regulatory orders, and Statement of Financial Accounting Standards No. 109 (SFAS 109) (see Note 12).
Investment tax credits are deferred as realized and amortized to income over the life of the property which gave rise to the credits.
Revenues: Effective January 1, 1991, the Company changed its method of accounting for recognizing electric and natural gas revenues to provide for the accrual of estimated unbilled revenues. The accounting change provides a better matching of revenues with costs of services provided to customers and also serves to conform 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. Meters are read and services are billed on a cycle basis and, prior to the accounting change, revenues were recognized in the accounting period during which services were billed.
The after-tax effect of the change in accounting method for the year ended December 31, 1991, was an increase in net income of $15.9 million or $0.46 per share. This increase was a combination of an increase of $17.3 million or $0.50 per share, attributable to the cumulative effect of the accounting change prior to January 1, 1991, and a decrease of $1.4 million or $0.04 per share in the 1991 income before cumulative effect of a change in accounting principle. Unbilled revenues of $99 and $86 million are recorded as a component of accounts receivable on the consolidated balance sheets as of December 31, 1993 and 1992, respectively. Certain amounts of unbilled revenues have been sold (see Note 8).
The Company had reserves for doubtful accounts receivable of $4.3 and $3.3 million at December 31, 1993 and 1992, respectively.
Fuel Costs: The cost of nuclear fuel in process of refinement,conversion, enrichment, and fabrication is recorded as an asset at original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor at December 31, 1993 and 1992, was $17.4 million and $26.0 million, respectively.
Cash Surrender Value of Life Insurance Contracts: The following amounts related to corporate-owned life insurance contracts (COLI), primarily with one highly rated major insurance company, are recorded on the consolidated balance sheets (millions of dollars):
1993 1992 Cash surrender value of contracts. . . $ 326.3 $ 256.3 Prepaid COLI . . . . . . . . . . . . . 11.9 7.0 Borrowings against contracts . . . . . (321.5) (109.6) COLI (net). . . . . . . . . . $ 16.7 $ 153.7
The decrease in COLI (net) is a result of increased borrowings against the accumulated cash surrender value of the COLI policies. The COLI borrowings will be repaid with proceeds from death benefits. Management expects to realize increases in the cash surrender value of contracts resulting from premiums and investment earnings on a tax free basis upon receipt of proceeds from death benefits under the contracts. Interest expense included in other income and deductions, net of taxes, related to KG&E's COLI for 1993 and the nine months ended December 31, 1992, was $11.9 and $5.3 million, respectively.
As approved by the Kansas Corporation Commission (KCC) and Missouri Public Service Commission (MPSC), 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 6) to offset Statement of Financial Accounting Standards No. 106 (SFAS 106) expenses.
Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation.
2. SALE 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 final sale price will be calculated as of January 31, 1994, within 120 days of closing. Any difference between the estimated and final sale price will be adjusted through a payment to or from the Company.
United Cities purchased the Company's natural gas distribution system in and around the City of Palmyra, Missouri, for $665,000 in cash.
The operating revenues and operating income (unaudited) related to the Missouri Properties approximated $350 million and $21 million representing approximately 18 percent and seven percent, respectively, of the Company's total for 1993, and $299 million and$11 million representing approximately 19 percent and five percent, respectively, of the Company's total for 1992. Net utility plant (unaudited) for the Missouri Properties, at December 31, 1993, approximated $296 million and $272 million at December 31, 1992. This represents approximately seven percent at December 31, 1993, and six percent at December 31, 1992, of the total Company net utility plant. 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 $294 million under SFAS 109 have been classified as plant acquisition adjustment in electric plant in service on the consolidated balance sheets. The total cost of the acquisition was $1.066 billion. Under the provisions of orders of the KCC and the MPSC 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. The first refund was made in April 1992 and amounted to $8.5 million. A refund of the same amount was made in December 1993 and an additional refund of $15 million will be made in September 1994.
The KCC order approving the Merger requires the legal reorganization of KG&E so that it is no longer held as a separate subsidiary after January 1, 1995, unless good cause is shown why such separate existence should be maintained. The Securities and Exchange Commission order relating to the Merger granted the Company an exemption under the Public Utilities Holding Company Act until January 1, 1995. In connection with a requested ruling that a merger of KG&E into Western Resources would not adversely affect the tax structure of the merger, KG&E received a response from the Internal Revenue Service that the IRS would not issue the requested ruling. In light of the IRS response, KG&E withdrew its request for a ruling. The Company will consider alternative forms of combination or seek regulatory approvals to waive the requirements for a combination. There is no certainty as to whether a combination will occur or as to the form or timing thereof.
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. The pro forma combined revenues, operating income, net income, and earnings per common share of the Company presented below give effect to the Merger as if it had occurred at January 1, 1991. This pro forma information is not necessarily indicative of the results of operations that would have occurred had the Merger been consummated for the period for which it is being given effect nor is it necessarily indicative of future operating results.
Year Ended December 31, 1992 1991 (Dollars in Thousands, except per share amounts)
Revenues. . . . . . . . . . . . $1,684,885 $1,748,844 Operating Income. . . . . . . . 268,772 279,458 Net Income. . . . . . . . . . . 131,524 110,290(1) Earnings Per Common . . . . . . $ 2.03 $ 1.72(1)
(1) Reflects information before the cumulative effect of the January 1, 1991 change in accounting method of recognizing revenues.
4. 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 $86 million at December 31, 1993. Approximately $36 million is attributable to modifications to upgrade the 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.
Environmental: The Company has been associated with 28 (20 in Kansas and 8 in Missouri) former manufactured gas sites which may contain coal tar and other potentially harmful materials. These sites were operated decades ago by other companies, and were acquired by the Company after they had ceased operation. The Environmental Protection Agency (EPA) has performed preliminary assessments of eleven of these sites (EPA sites), six of which are under site investigation. The Company has not received any indication from the EPA that further action will be taken at the EPA sites, nor does the Company have reason to believe there will be any fines or penalties assessed related to these sites. The Company and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement to conduct separate preliminary assessments of the 20 former manufactured gas sites located in Kansas. The preliminary assessments of these 20 sites have been completed at a total cost of approximately $500,000. The Company plans to initiate site investigation and risk assessments at the two highest priority sites in 1994 at a total cost of approximately $500,000. Until such time that risk assessments are completed at these or the remaining sites, it will be impossible to predict the cost of remediation. However, the Company is aware of other utilities in Region VII of the EPA (Kansas, Missouri, Nebraska, and Iowa) which have incurred remediation costs for such sites ranging between $500,000 and $10 million, depending on the site. The Company is also aware that the KCC has permitted another Kansas utility to recover a portion of the remediation costs through rates. To the extent that such remediation costs are not recovered through rates, the costs could be material to the Company's financial position or results of operations depending on the degree of remediation and number of years over which the remediation must be completed.
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, and one is an oil soil contamination site in Springfield, Missouri. The other two sites are solid waste land fills located in Edwardsville and Hutchinson, Kansas. The Company's obligation at these sites appears to be limited, and it is the opinion of the Company's management that the resolution of these matters will not have a material impact on the Company's financial position or results of operations.
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 now pending or that may arise after closing. For any environmental matters now 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 $3.5 million for 1993 and $1.6 million for 1992.
Decommissioning: The Company's share of Wolf Creek decommissioning costs, currently authorized in rates, was estimated to be approximately $97 million in 1988 dollars. Decommissioning costs are being charged to operating expenses. Amounts so expensed are deposited in an external trust fund and will be used solely for the physical decommissioning of the plant. Electric rates charged to customers provide for recovery of these decommissioning costs over the estimated life of Wolf Creek. At December 31, 1993, and December 31, 1992, $13.2 and $9.3 million, respectively, were on deposit in the decommissioning fund. On September 1, 1993, WCNOC filed an application with the KCC for an order approving a 1993 Wolf Creek Decommissioning Cost Study which estimates the Company's share of Wolf Creek decommissioning costs at approximately $174 million in 1993 dollars. If approved by the KCC, management expects substantially all such cost increases to be recovered through the ratemaking process.
The Company carries $164 million in premature decommissioning insurance in the event of a shortfall in the trust fund. The insurance coverage has several restrictions. One of these is that it can only be used if Wolf Creek incurs an accident exceeding $500 million in expenses to safely stabilize the reactor, to decontaminate the reactor and reactor station site in accordance with a plan approved by the Nuclear Regulatory Commission (NRC), and to pay for on-site property damages. If the amount designated as decommissioning insurance is needed to implement the NRC-approved plan for stabilization and decontamination, it would not be available for decommissioning purposes.
Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.4 billion for a single nuclear incident. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million and the balance is provided by an assessment plan mandated by the NRC. Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $79.3 million ($37.3 million, Company's share) in the event there is a nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index. There is a limitation of $10 million ($4.7 million, Company's share) in retrospective assessments per incident per year.
The Owners carry decontamination liability, premature decommissioning liability, and property damage insurance for Wolf Creek totalling approximately $2.8 billion ($1.3 billion, Company's share). This insurance is provided by a combination of "nuclear insurance pools" ($1.3 billion) and Nuclear Electric Insurance Limited (NEIL) ($1.5 billion). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. The remaining proceeds from the $2.8 billion insurance coverage ($1.3 billion, Company's share), if any, can be used for property damage up to $1.1 billion (Company's share) and premature decommissioning costs up to $117.5 million (Company's share) in excess of funds previously collected for decommissioning (as discussed under "Decommissioning"), with the remaining $47 million (Company's share) available for either property damage or premature decommissioning costs.
The Owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves, and other NEIL resources, the Company may be subject to retrospective assessments of approximately $9 million per year.
There can be no assurance that all potential losses or liabilities will be insurable or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance, to the extent not recoverable through rates, could have a material adverse effect on the Company's financial condition and results of operations.
Clean Air Act: The Clean Air Act Amendments of 1990 (the Act) require a two-phase reduction in sulfur dioxide and nitrous oxide emissions effective in 1995 and 2000 and a probable reduction in toxic emissions. To meet the monitoring and reporting requirements under the acid rain program, the Company is installing continuous monitoring and reporting equipment at a total cost of approximately $10 million. At December 31, 1993, the Company had completed approximately $4 million of these capital expenditures with the remaining $6 million of capital expenditures to be completed in 1994 and 1995. The Company does not expect additional equipment to reduce sulfur emissions to be necessary under Phase II. The Company currently has no Phase I affected units.
The nitrous oxide and toxic limits, which were not set in the law, will be specified in future EPA regulations. The EPA has issued for public comment preliminary nitrous oxide regulations for Phase I group 1 units. Nitrous oxide regulations for Phase II units and Phase I group 2 units are mandated in the Act to be promulgated by January 1, 1997. Although the Company has no Phase I units, the final nitrous oxide regulations for Phase I group 1 may allow for early compliance for Phase II group 1 units. Until such time as the Phase I group 1 nitrous oxide regulations are final, the Company will be unable to determine its compliance options or related compliance costs.
Federal Income Taxes: During 1991, the Internal Revenue Service (IRS) completed an examination of 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, 1993, WCNOC's nuclear fuel commitments (Company's share) were approximately $18.0 million for uranium concentrates expiring at various times through 1997, $123.6 million for enrichment expiring at various times through 2014, and $45.5 million for fabrication through 2012. At December 31, 1993, the Company's coal and natural gas contract commitments in 1993 dollars under the remaining term of the contracts were $2.8 billion and $20.4 million, respectively. The largest coal contract was renegotiated early in 1993 and 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.
5. RATE MATTERS AND REGULATION
The Company, under rate orders from certain state regulatory commissions 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. Certain state regulatory commissions 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 increase or decrease in fuel costs from the projected average will be absorbed by the Company.
MPSC Rate Proceedings: On October 5, 1993, the MPSC approved an agreement among the Company, the MPSC staff, and intervenors to increase natural gas rates $9.75 million annually, effective October 15, 1993. Also on October 15, 1993, the Company discontinued the deferral of service line replacement program costs deferred since July 1, 1991, and began amortizing the balance to expense over twenty years. At December 31, 1993, approximately $8.3 million of these deferrals have been included in other deferred charges on the consolidated balance sheet.
On January 22, 1992, the MPSC issued an order authorizing the Company to increase natural gas rates $7.3 million annually.
KCC Rate Proceedings: 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, 1993, approximately $2.9 million of these deferrals have been included in other deferred charges 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 $8.3 million of deferred costs remain in other deferred charges on the consolidated balance sheet at December 31, 1993, with the balance being included in rates and amortized to expense during a 43-month period, commencing January 1, 1992.
Gas Transportation Charges: On September 12, 1991, the KCC authorized the Company to begin recovering, through the PGA, deferred supplier gas transportation costs of $9.9 million incurred through December 31, 1990, based on a three-year amortization schedule. On December 30, 1991, the KCC authorized the Company to recover deferred transportation costs of approximately $2.8 million incurred subsequent to December 31, 1990, through the PGA over a 32-month period. At December 31, 1993, approximately $4.8 million of these deferrals remain in other deferred charges on the consolidated balance sheet.
Tight Sands: In December 1991, the KCC, MPSC, and Oklahoma Corporation Commission (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 that 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.
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 Pittsburgh and Midway Coal Mining Company amounting to $22.5 million. This amount was recorded as a deferred charge on the consolidated balance sheets. 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 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 have been 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. A portion 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 and MPSC have approved mechanisms which are expected to allow the Company to recover these take-or-pay costs from its customers.
6. 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, 1993 1992 1991 (Dollars in Thousands) Pension Cost: Service cost................... $ 9,778 $ 9,847 $ 6,589 Interest cost on projected benefit obligation........... 35,688 29,457 20,985 Return on plan assets.......... (64,113) (38,967) (59,161) Deferred gain on plan assets... 29,190 7,705 38,015 Net amortization............... (669) (948) (131) Net pension cost........... $ 9,874 $ 7,094 $ 6,297
December 31, 1993 1992 1991 (Dollars in Thousands) Funded Status: Actuarial present value of benefit obligations: Vested . . . . . . . . . . . $353,023 $316,100 $200,435 Non-vested . . . . . . . . . 26,983 19,331 13,935 Total. . . . . . . . . . . $380,006 $335,431 $214,370 Plan assets (principally debt and equity securities) at fair value . . . . . . . . . . . $490,339 $452,372 $324,780 Projected benefit obligation . . . 468,996 424,232 282,062 Plan assets in excess of projected benefit obligation . . 21,343 28,140 42,718 Unrecognized transition asset. . . (2,756) (3,092) (1,253) Unrecognized prior service costs . 64,217 55,886 27,216 Unrecognized net gain. . . . . . . (108,783) (106,486) (69,494) Accrued pension costs. . . . . . . $(25,979) $(25,552) $ (813)
Year Ended December 31, 1993 1992 1991 Actuarial Assumptions: Discount rate. . . . . . . . . . 7.0-7.75% 8.0-8.5% 8.0% Annual salary increase rate. . . 5.0 % 6.0% 6.0% Long-term rate of return . . . . 8.0-8.5 % 8.0-8.5% 8.0%
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, the annual expense under SFAS 106 was approximately $26.5 million in 1993 (as compared to approximately $9.6 million on a cash basis) and the Company's total obligation was approximately $166.5 million at December 31, 1993. To mitigate the impact of SFAS 106 expense, the Company has implemented programs to reduce health care costs. In addition, the Company has received orders from the KCC and MPSC permitting the initial deferral of SFAS 106 expense. To mitigate the impact SFAS 106 expense will have on rate increases, the Company will include in the future computation of cost of service the actual SFAS 106 expense and an income stream generated from corporate-owned life insurance (COLI). To the extent SFAS 106 expense exceeds income from the COLI program, this excess will be deferred (as allowed by the FASB Emerging Issues Task Force Issue No. 92-12) and offset by income generated through the deferral period by the COLI program. The OCC is reviewing the Company's application for similar treatment in Oklahoma. Should the OCC require recognition of postretirement benefit costs for regulatory purposes under a different method than that proposed under the Company's application, the impact on earnings would not be material. Should the income stream generated by the COLI program not be sufficient to offset the deferred SFAS 106 expense, the KCC and MPSC orders allow 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 amount included in the consolidated balance sheet:
December 31, 1993 (Dollars in Thousands) Actuarial present value of postretirement benefit obligations: Retirees. . . . . . . . . . . . . . . . . . . . $ 111,499 Active employees fully eligible . . . . . . . . 11,848 Active employees not fully eligible . . . . . . 43,109 Unrecognized prior service cost . . . . . . . . 18,195 Unrecognized transition obligation. . . . . . . (160,731) Unrecognized net loss . . . . . . . . . . . . . (7,100) Balance sheet liability . . . . . . . . . . . . . . $ 16,820
For measurement purposes, an annual health care cost growth rate of 13% was assumed for 1994, decreasing to 6% by 2002 and thereafter. The accumulated post retirement benefit obligation was calculated using a weighted-average discount rate of 7.75%, a weighted-average compensation increase rate of 5.0%, and a weighted-average expected rate of return of 8.5%. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by 1% each year would increase the present value of the accumulated projected benefit obligation by $11.1 million and the aggregate of the service and interest cost components by $1.5 million.
Postemployment: The FASB has issued Statement of Financial Accounting Standards No. 112 (SFAS 112), which establishes accounting and reporting standards for postemployment benefits. The new statement will require the Company to recognize the liability to provide postemployment benefits when the liability has been incurred. The Company adopted SFAS 112 effective January 1, 1994. To mitigate the impact adopting SFAS 112 will have on rate increases, the Company will file applications with the KCC and OCC for orders permitting the initial deferral of SFAS 112 transition costs and expenses and its inclusion in the future computation of cost of service net of an income stream generated from COLI. However, if the state regulatory commissions were to recognize postemployment benefit costs under a different method, 1994 earnings could be impacted negatively. At December 31, 1993, the Company estimates SFAS 112 liability to total approximately $11 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 $5.4, $5.4, and $3.3 million for 1993, 1992, and 1991, 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.
7. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in Statement of Financial Accounting Standards No. 107:
Cash and Cash Equivalents- The carrying amount approximates the fair value because of the short-term maturity of these investments. Decommissioning Trust- The fair value of the decommissioning trust is based on quoted market prices at December 31, 1993 and 1992. Variable-rate Debt- The carrying amount approximates the fair value because of the short-term variable rates of these debt instruments. Fixed-rate Debt- The fair value of the fixed-rate debt is based on the sum of the estimated value of each issue taking into consideration the 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, 1993 1992 1993 1992 (Dollars in Thousands) Cash and cash equivalents. . . . . . . $ 1,217 $ 875 $ 1,217 $ 875 Decommissioning trust. . . 13,204 9,272 13,929 9,500 Variable-rate debt . . . . 931,352 758,449 931,352 758,449 Fixed-rate debt. . . . . . 1,364,886 1,508,077 1,473,569 1,563,375 Redeemable preference stock. . . . . . . . . . 150,000 152,733 160,780 161,733
8. 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 took measures to have 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. The sinking fund requirements for certain Western Resources and KG&E pollution control series bonds can be met only through the acquisition and retirement of outstanding bonds. Bonds maturing and acquisition and retirement of bonds for sinking fund requirements for the five years subsequent to December 31, 1993, are as follows:
Maturing Retiring Year Bonds Bonds (Dollars in Thousands)
1994. . . . . $ 2,466 $ 738 1995. . . . . - 753 1996. . . . . 16,000 770 1997. . . . . - 1,333 1998. . . . . - 1,550
Long-term debt outstanding at December 31, 1993 and 1992, was as follows:
1993 1992 (Dollars in Thousands) Western Resources First mortgage bond series: 9.35 % due 1998. . . . . . . . . . . . . $ - $ 75,000 7 1/4% due 1999. . . . . . . . . . . . . 125,000 125,000 7 5/8% due 1999. . . . . . . . . . . . . 19,000 19,000 8 3/4% due 2000. . . . . . . . . . . . . - 20,000 8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000 7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000 8 5/8% due 2005. . . . . . . . . . . . . - 35,000 8 1/8% due 2007. . . . . . . . . . . . . 30,000 30,000 8 3/4% due 2008. . . . . . . . . . . . . - 35,000 8 5/8% due 2017. . . . . . . . . . . . . 50,000 50,000 8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000 7.65% due 2023. . . . . . . . . . . . . 100,000 - 624,000 689,000 Pollution control bond series: 5.90 % due 2007. . . . . . . . . . . . . 31,000 31,500 6 3/4% due 2009. . . . . . . . . . . . . 45,000 45,000 9 5/8% due 2013. . . . . . . . . . . . . - 58,500 6% due 2033. . . . . . . . . . . . . 58,500 - 134,500 135,000 KG&E First mortgage bond series: 5 5/8% due 1996. . . . . . . . . . . . . 16,000 16,000 8 1/8% due 2001. . . . . . . . . . . . . - 35,000 7 3/8% due 2002. . . . . . . . . . . . . - 25,000 7.60% due 2003. . . . . . . . . . . . . 135,000 135,000 6 1/2% due 2005. . . . . . . . . . . . . 65,000 - 8 3/8% due 2006. . . . . . . . . . . . . - 25,000 8 1/2% due 2007. . . . . . . . . . . . . - 25,000 8 7/8% due 2008. . . . . . . . . . . . . - 30,000 216,000 291,000 Pollution control bond series: 6.80% due 2004. . . . . . . . . . . . . 14,500 14,500 5 7/8% due 2007. . . . . . . . . . . . . 21,940 21,940 6% due 2007. . . . . . . . . . . . . 10,000 10,000 7.0% due 2031. . . . . . . . . . . . . 327,500 327,500 373,940 373,940 GSC First mortgage bond series: 8 1/2% due 1997. . . . . . . . . . . . . 2,466 4,932 2,466 4,932
Bank term loan . . . . . . . . . . . . . . - 230,000 Other pollution control obligations. . . . 13,980 14,205 Revolving credit agreement . . . . . . . . 115,000 150,000 Other long term agreement. . . . . . . . . 53,913 46,640 Less: Unamortized debt discount. . . . . . . . 6,607 6,730 Long-term debt due within one year . . . 3,204 1,961 $1,523,988 $1,926,026
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. The revolver has an initial term of three years with options to renew for an additional two years with the consent of the banks. The unused portion of the revolving credit facility may be used to provide support for outstanding short-term debt. At December 31, 1993, $115 million was outstanding under the facility.
On September 20, 1993, KG&E terminated a long-term revolving credit agreement which provided for borrowings of up to $150 million. The loan agreement, which was effective through October 1994, was repaid without penalty.
KG&E has a long-term agreement, expiring in 1995, which contains provisions for the sale of accounts receivable and unbilled revenues (receivables) and phase-in revenues up to a total of $180 million. Amounts related to receivables are accounted for as sales while those related to phase-in revenues are accounted for as collateralized borrowings. Additional receivables are continually sold to replace those collected. At December 31, 1993 and 1992, outstanding receivables amounting to $56.8 and $47.7 million, respectively, were considered sold under the agreement. The credit risk associated with the sale of customer accounts receivable is considered minimal. The weighted average interest rate, including fees, was 3.7% for the year ended December 31, 1993, and 6.6% for the nine months ended December 31, 1992. At December 31, 1993, an additional $16.4 million was available under the agreement.
9. SHORT-TERM 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 other unsecured lines of credit maintained with banks. Information concerning these arrangements for the years ended December 31, 1993, 1992, and 1991, is set forth below:
Year Ended December 31, 1993 1992 1991 (Dollars in Thousands) Lines of credit at year end. . . . $145,000 $250,000(1) $185,000(2) Short-term debt out- standing at year end . . . . . . 440,895 222,225 135,800 Weighted average interest rate on debt outstanding at year end (including fees) . . . . . . 3.67% 4.70% 5.07% Maximum amount of short- term debt outstanding during the period. . . .. . . . . . . . $443,895 $263,900 $175,000 Monthly average short-term debt. . 347,278 179,577 125,968 Weighted daily average interest rates during the year (including fees) . . . . . . . . 3.44% 4.90% 6.69%
(1) Decreased to $155 million in January 1993. (2) Increased to $200 million in January 1992.
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.
10. LEASES
At December 31, 1993, 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 Ending December 31, Leases Leases (Dollars in Thousands) 1991 $ 1,217 $21,501 1992 2,426 52,701 1993 3,272 55,011 Future Commitments: 1994 $ 4,002 $47,729 1995 3,752 45,825 1996 3,627 44,176 1997 1,209 41,644 1998 - 41,019 Thereafter - 771,157 Total $12,590 $ 991,550 Less Interest 1,466 Net obligation $11,124
In 1987, KG&E sold and leased back its 50 percent undivided interest in La Cygne 2. The 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 lease agreement, the Company in 1992 requested the Trustee Lessor to refinance $341.1 million of secured facility bonds of the Trustee and owner of La Cygne 2. The transaction was requested to reduce recurring future net lease expense. In connection with the refinancing on September 29, 1992, a one-time payment of approximately $27 million was made by the Company which has been deferred and is being amortized over the remaining life of the lease and included in operating expense as part of the future lease expense.
Future minimum annual lease payments, included in the table above, required under the lease agreement are approximately $34.6 million for each year through 1998 and $715 million over the remainder of the lease.
The gain of approximately $322 million realized at the date of the sale has been deferred for financial reporting purposes, and is being amortized over the initial lease term in proportion to the related lease expense. KG&E's lease expense, net of amortization of the deferred gain and a one-time payment, was approximately $22.5 million for the year ended December 31, 1993, and $20.6 million for the nine months ended December 31, 1992.
11. JOINT OWNERSHIP OF UTILITY PLANTS
Company's Ownership at December 31, 1993 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 150,265 $ 91,175 342 50 Jeffrey 1 (b) Jul 1978 277,087 116,526 587 84 Jeffrey 2 (b) May 1980 274,018 106,301 566 84 Jeffrey 3 (b) May 1983 386,925 124,158 588 84 Wolf Creek (c) Sep 1985 1,366,387 281,819 533 47
(a) Jointly owned with Kansas City Power & Light Company (KCPL) (b) Jointly owned with UtiliCorp United Inc. and a third party (c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
Amounts and capacity represent the Company's share. The Company's share of operating expenses of the plants in service above, as well as such expenses for a 50 percent undivided interest in La Cygne 2 (representing 335 MW capacity) sold and leased back to the Company in 1987, are included in operating expenses in the statements of income. The Company's share of other transactions associated with the plants is included in the appropriate classification in the Company's consolidated financial statements.
12. 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, the MPSC, 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, 1993, KG&E has unused investment tax credits of approximately $7.1 million available for carryforward which, if not utilized, will expire in the years 2000 through 2002. In addition, the Company has alternative minimum tax credits generated prior to April 1, 1992, which carryforward without expiration, of $57.2 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, 1993.
Deferred income taxes result from temporary differences between the financial statement and tax basis of the Company's assets and liabilities. The sources of these differences and their cumulative tax effects are as follows:
December 31, 1993 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (647,202) $ (647,202) 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 . . . - (117,549) (117,549) Other. . . . . . . . . . . . . . . - (14,039) (14,039) Total Deferred Income Taxes. . . . . $ 169,821 $(1,138,458) $ (968,637)
December 31, 1992 Debits Credits Total (Dollars in Thousands) Sources of Deferred Income Taxes: Accelerated depreciation and other property items . . . . . . $ - $ (607,303) $ (607,303) Energy and purchased gas adjustment clauses . . . . . . . - (7,717) (7,717) Phase-in revenues. . . . . . . . . - (37,564) (37,564) Natural gas line survey and replacement program. . . . . . . - (7,473) (7,473) Deferred gain on sale-leaseback. . 104,573 - 104,573 Alternative minimum tax credits. . 39,882 - 39,882 Deferred coal contract settlements. . . . . . . . . . . - (9,318) (9,318) Deferred compensation/pension liability. . . . . . . . . . . . 8,488 - 8,488 Acquisition premium. . . . . . . . - (314,241) (314,241) Deferred future income taxes . . . - (158,102) (158,102) Other. . . . . . . . . . . . . . . - (1,380) (1,380) Total Deferred Income Taxes. . . . . $ 152,943 $(1,143,098) $ (990,155)
13. 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, Missouri, and Oklahoma.
Year Ended December 31, 1993 1992(1) 1991 (Dollars in Thousands) Operating revenues: Electric. . . . . . . . . . . $1,104,537 $ 882,885 $ 471,839 Natural gas . . . . . . . . . 804,822 673,363 690,339 1,909,359 1,556,248 1,162,178
Operating expenses excluding income taxes: Electric. . . . . . . . . . . 791,563 632,169 337,150 Natural gas . . . . . . . . . 747,755 642,910 664,825 1,539,318 1,275,079 1,001,975
Income taxes: Electric. . . . . . . . . . . 73,425 41,184 32,239 Natural gas . . . . . . . . . 4,553 816 (1,657) 77,978 42,000 30,582
Operating income: Electric. . . . . . . . . . . 239,549 209,532 102,450 Natural gas . . . . . . . . . 52,514 29,637 27,171 $ 292,063 $ 239,169 $ 129,621
Identifiable assets at December 31: Electric. . . . . . . . . . . $4,231,277 $4,390,117 $1,196,023 Natural gas . . . . . . . . . 1,040,513 918,729 840,692 Other corporate assets(2) . . 140,258 130,060 75,798 $5,412,048 $5,438,906 $2,112,513
Other Information-- Depreciation and amortization: Electric. . . . . . . . . . . $ 126,034 $ 105,842 $ 53,632 Natural gas . . . . . . . . . 38,330 38,171 32,103 $ 164,364 $ 144,013 $ 85,735
Maintenance: Electric. . . . . . . . . . . $ 87,696 $ 73,104 $ 34,240 Natural gas . . . . . . . . . 30,147 28,507 26,275 $ 117,843 $ 101,611 $ 60,515
Capital expenditures: Electric. . . . . . . . . . . $ 137,874 $ 95,465 $ 43,714 Nuclear fuel. . . . . . . . . 5,702 15,839 - Natural gas . . . . . . . . . 94,055 91,189 81,961 $ 237,631 $ 202,493 $ 125,675
(1)Information reflects the merger with KG&E on March 31, 1992. (2)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 (unaudited):
(Dollars in Thousands) Natural gas revenues. . . . . . . . . . $ 349,749 Operating expenses excluding income taxes. . . . . . . . . 326,329 Income taxes. . . . . . . . . . . . . . 2,672 Operating income. . . . . . . . . . . . 20,748 Identifiable assets . . . . . . . . . . 398,464 Depreciation and amortization . . . . . 12,668 Maintenance . . . . . . . . . . . . . . 10,504 Capital expenditures. . . . . . . . . . 38,821
14. 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. During 1993, the Company issued 3,572,323 shares of common stock and at December 31, 1993, 61,617,873 shares were outstanding.
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: On October 1, 1993, the Company redeemed the remaining 22,000 shares of the 8.70% Series preference stock.
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 $107.37, $106.80, and $106.23 per share beginning July 1, 1993, 1994, and 1995, 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 $106.82, $106.06, and $105.31 per share beginning April 1, 1993, 1994, and 1995, respectively.
15. LEGAL PROCEEDINGS
The Company and its subsidiaries are involved in various legal and environmental proceedings. Management believes that adequate provision has been made within the consolidated financial statements for these 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.
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) 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
1992(1) Operating revenues. . . . . . . $373,620 $341,715 $380,745 $460,168 Operating income. . . . . . . . 42,684 45,830 77,010 73,645 Net income. . . . . . . . . . . 27,984 18,434 42,185 39,281 Earnings applicable to common stock. . . . . . . . . 25,472 15,113 38,726 35,822 Earnings per share. . . . . . . $ 0.74 $ 0.26 $ 0.67 $ 0.62 Dividends per share . . . . . . $ 0.475 $ 0.475 $ 0.475 $ 0.475 Average common shares outstanding . . . . . . . . . 34,566 58,046 58,046 58,046 Common stock price: High. . . . . . . . . . . . . $ 29 1/2 $ 26 7/8 $ 30 1/2 $ 32 5/8 Low . . . . . . . . . . . . . $ 25 3/8 $ 25 1/4 $ 26 3/4 $ 28 1/2
(1) Information reflects the merger with KG&E on March 31, 1992.
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 1994 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 18 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 1994 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 1994 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
The information required by Item 13 is set forth in the Company's definitive proxy statement for its 1994 Annual Meeting of Shareholders to be filed with the Commission. Such information is incorporated herein by reference to the material appearing under the caption Transactions with Management in the proxy statement to be filed by the Company with the Commission.
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, 1993 and 1992 Consolidated Statements of Income - years ended December 31, 1993, 1992 and 1991 Consolidated Statements of Cash Flows - years ended December 31, 1993, 1992 and 1991 Consolidated Statements of Taxes - years ended December 31, 1993, 1992 and 1991 Consolidated Statements of Capitalization - December 31, 1993 and Consolidated Statements of Common Stock Equity - years ended December 31, 1993, 1992 and 1991 Notes to Consolidated Financial Statements
The following supplemental schedules are included herein.
SCHEDULES
Schedule V - Utility Plant - years ended December 31, 1993, 1992 and 1991 Schedule VI - Accumulated Depreciation of Utility Plant - years ended December 31, 1993, 1992 and 1991
Schedules omitted as not applicable or not required under the Rules of regulation S-X: I, II, III, IV, VII, VIII, IX, X, XI, XII, and XIII
REPORTS ON FORM 8-K
Form 8-K dated February 2, 1994
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) -By-laws of the Company, as amended July 15, 1987. (filed as I Exhibit 3(d) to the December 1987 Form 10-K) 3(d) -Certificate of Designation of Preference Stock, 8.50% Series, without par value. (filed electronically) 3(e) -Certificate of Designation of Preference Stock, 7.58% Series, without par value. (filed electronically) 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) 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)
Description
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)
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) -Agreement between the Company and AMAX Coal West Inc. effective March 31, 1993. (filed electronically) 10(b) -Agreement between the Company and Williams Natural Gas Company dated October 1, 1993. (filed electronically) 10(c) -Agreement between the Company and Williams Natural Gas Company dated October 1, 1993. (filed electronically) 10(d) -Agreement between the Company and Williams Natural Gas Company dated October 1, 1993. (filed electronically) 10(e) -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(f) -Letter of Agreement between The Kansas Power and Light Company and I John E. Hayes, Jr., dated November 20, 1989. (filed as Exhibit 10(w) to the December 1989 Form 10-K) 10(g) -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(h) -Deferred Compensation Plan 10(i) -Long-term Incentive Plan 10(j) -Short-term Incentive Plan 10(k) -Outside Directors' Deferred Compensation Plan 12 -Computation of Ratio of Consolidated Earnings to Fixed Charges. (filed electronically) 16 -Letter re Change in Certifying Accountant. (filed as Exhibit 16 I to the Current Report on Form 8-K dated March 8, 1993) 21 -Subsidiaries of the Registrant. (filed as Exhibit 22 to the I December 1992 Form 10-K) 23(a) -Consent of Independent Public Accountants, Arthur Andersen & Co. (filed electronically) 23(b) -Consent of Independent Public Accountants, Deloitte & Touche (filed electronically)) 23(c) -Consent of K&A Energy Consultants, Inc. (filed as Exhibit 24(b) I to the December 1988 Form 10-K) 99(a) -Kansas Gas and Electric Company's Annual Report on Form 10-K for the year ended December 31, 1993 (filed electronically) 99(b) -Report of K&A Energy Consultants, Inc. (filed as Exhibit 28 to I the December 1988 Form 10-K)
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 18, 1994 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 18, 1994 (John E. Hayes, Jr.) (Principal Executive Officer)
Executive Vice President and S. L. KITCHEN Chief Financial Officer March 18, 1994 (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 18, 1994 (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)