ITEM 1. BUSINESS
General The Empire District Electric Company (the "Company"), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. The Company also provides water service to three towns in Missouri. In 1999, 99.5% of the Company's gross operating revenues were provided from the sale of electricity and 0.5% from the sale of water. The Company and UtiliCorp United, Inc. entered into an Agreement and Plan of Merger, dated as of May 10, 1999, which provides for a merger of the Company with and into UtiliCorp, with UtiliCorp being the surviving corporation. At a special meeting of stockholders held on September 3, 1999, the merger was approved by the Company's stockholders. The merger is conditioned, among other things, upon approvals of various federal and state regulatory agencies. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further information. The territory served by the Company's electric operations embraces an area of about 10,000 square miles with a population of over 330,000. The service territory is located principally in Southwestern Missouri and also includes smaller areas in Southeastern Kansas, Northeastern Oklahoma and Northwestern Arkansas. The principal activities of these areas are industry, agriculture and tourism. Of the Company's total 1999 retail electric revenues, approximately 88% came from Missouri customers, 6% from Kansas customers, 3% from Oklahoma customers and 3% from Arkansas customers. The Company supplies electric service at retail to 121 incorporated communities and to various unincorporated areas and at wholesale to four municipally-owned distribution systems and two rural electric cooperatives. The largest urban area served by the Company is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 135,000. The Company operates under franchises having original terms of twenty years or longer in virtually all of the incorporated communities. Approximately 24% of the Company's electric operating revenues in 1999 were derived from incorporated communities with franchises having at least ten years remaining and approximately 36% were derived from incorporated communities in which the Company's franchises have remaining terms of ten years or less. Although the Company's franchises contain no renewal provisions, in recent years the Company has obtained renewals of all of its expiring electric franchises prior to the expiration dates. The Company's electric operating revenues in 1999 were derived as follows: residential 41%, commercial 31%, industrial 17%, wholesale 7% and other 4%. The Company's largest single on-system
wholesale customer is the city of Monett, Missouri, which in 1999 accounted for approximately 3% of electric revenues. No single retail customer accounted for more than 1% of electric revenues in 1999. The Company made an investment of approximately $0.5 million in 1999 and $3.5 million in 1998 in fiber optics cable and equipment which the Company is using in its own operations and leasing to other entities. The Company also offers electronic monitored security services, generators, surge suppressors, decorative lighting and other energy services.
Electric Generating Facilities and Capacity At December 31, 1999, the Company's generating plants consisted of the Asbury Plant (aggregate generating capacity of 213 megawatts), the Riverton Plant (aggregate generating capacity of 136 megawatts), the Empire Energy Center (aggregate generating capacity of 180 megawatts), the State Line Power Plant (aggregate generating capacity of 253 megawatts) and the Ozark Beach Hydroelectric Plant (aggregate generating capacity of 16 megawatts). The Company also has a 12% ownership interest (80 megawatt capacity) in Unit No. 1 at the Iatan Generating Station. The Company is currently constructing a 350 megawatt expansion at the State Line Power Plant which will result in a 500 megawatt combined-cycle unit (the "State Line Combined Cycle Unit") with commercial operation scheduled for June 2001. This is a joint effort with Westar Generating, Inc. ("WGI"), a subsidiary of Western Resources, Inc., from which the Company will be entitled to approximately 150 megawatts of additional generating capacity. See Item 2, "Properties - Electric Facilities" for further information about these plants. The Company is a member of the Southwest Power Pool ("SPP"), a regional division of the North American Electric Reliability Council ("NERC"). The SPP currently requires its members to maintain a 12% capacity reserve margin and provides for contingency reserve sharing, regional near real-time security assessment 24 hours per day and many other functions. The Company is participating with other utility members in the restructuring of SPP to make it a regional transmission organization ("RTO"). See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Competition." The Company is also a member of the Western Systems Power Pool, a marketing pool that provides agreements that facilitate the purchase and sale of wholesale power among members. Most of the United States electric utilities are now parties to this agreement. The Company currently supplements its on-system generating capacity with purchases of capacity and energy from other utilities in order to meet the demands of its customers and the capacity margins applicable to it under current pooling agreements and NERC rules. The Company has entered into agreements for such purchases with Associated Electric Cooperative, Inc. ("AECI") for periods through the contract year 1999 which ends May 31, 2000, and with Western Resources ("WR") and Southwestern Public Service Company ("SPS" - a subsidiary of New Centuries Energies) for periods through the contract year 2000 which ends May 31, 2001. In addition, the Company has contracted with WR for the purchase of capacity and energy through May 31, 2010. The amount of capacity purchased under these contracts supplements the Company's on-system capacity and contributes to meeting its current expectations of future power needs. The following chart sets forth the Company's purchase commitments and anticipated owned capacity (in megawatts) during the indicated contract years (which run from June 1 to May 31 of the following year). The reduction in purchased power commitments in 2001 is the result of the expiration of all of the contracts described above, except the WR contract, and the installation of additional generation that is expected to be available upon completion of construction of the State Line Project in the summer of 2001. The Company currently expects to purchase additional capacity to meet reserve margins in 2003 and 2004 of 30 to 60 megawatts based on current forecast of load.
The charges for capacity purchases under the contracts referred to above during calendar year 1999 amounted to approximately $15.9 million. Minimum charges for capacity purchases under such contracts total approximately $107.8 million for the period June 1, 2000, through May 31, 2005. The maximum hourly demand on the Company's system reached a new record high of 979 megawatts on August 12, 1999. The Company's previous record peak of 916 megawatts was established in August 1998. The Company's maximum hourly winter demand of 841 megawatts, was set on January 13, 1997.
Construction Program Total gross property additions (including construction work in progress) for the three years ended December 31, 1999, amounted to $176.1 million, and retirements during the same period amounted to $13.4 million. The Company's total construction-related expenditures, including allowance for funds used during construction ("AFUDC"), were $70.1 million in 1999 and for the next three years are estimated for planning purposes to be as follows:
The Company's projected construction plans include expenditures for the 350 megawatt expansion project at the State Line Power Plant to be completed in 2001. Additions to the Company's transmission and distribution systems to meet projected increases in customer demand constitute the majority of the remainder of the projected construction expenditures for the three- year period listed above. Estimated construction expenditures are reviewed and adjusted for, among other things, revised estimates of future capacity needs, the cost of funds necessary for construction and the availability and cost of alternative power. Actual construction expenditures may vary significantly from the estimates due to a number of factors including changes in equipment delivery schedules, changes in customer requirements, construction delays, ability to raise capital, environmental matters, the extent to which the Company receives timely and adequate rate increases, the extent of competition from independent power producers and co- generators, other changes in business conditions and changes in legislation and regulation, including those relating to the energy industry. See "Regulation" below and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Competition."
Fuel Coal supplied approximately 81.8% of the Company's total fuel requirements in 1999 based on kilowatt-hours generated. The remainder was supplied by natural gas (18.0%) with oil generation being insignificant. The Company's Asbury Plant is fueled primarily by coal with oil being used as startup fuel. The Plant is currently burning a coal blend consisting of approximately 90% Western coal (Powder River Basin) and 10% blend coal on a tonnage basis. The Company has increased its target coal inventory at Asbury from approximately 45 days to 60 days. As of December 31, 1999, the Company had sufficient coal on hand to supply anticipated requirements at Asbury for 71 days. The Company's Riverton Plant fuel requirements are primarily met by coal with the remainder supplied by natural gas and oil. The Riverton Plant is currently burning a coal blend consisting of approximately 80% Western coal and 20% blend coal on a tonnage basis. The Company has increased its target coal inventory at Riverton from 45 days to approximately 60 days. As of December 31, 1999, the Company had coal supplies on hand to meet anticipated requirements at the Riverton Plant for 74 days.
The Company has a long-term contract, expiring in 2004, with a subsidiary of Peabody Holding Company, Inc. for the supply of low sulfur Western coal at the Asbury and Riverton Plants during the term of the contract. This Peabody coal is supplied from the Rochelle and North Antelope mines located in Campbell County, Wyoming, and is shipped from there to the Asbury Plant by rail, a distance of approximately 800 miles. The coal is delivered under a transportation contract with Western Railroad Properties, Inc., Union Pacific Railroad Company and The Kansas City Southern Railway Company. The Company is currently leasing one 125-car aluminum unit train, which delivers Peabody coal to the Asbury Plant. The Peabody coal is transported from Asbury to Riverton via truck. Anticipated requirements for blend coal are currently being supplied under spot purchases following the expiration of a coal supply agreement with the Mackie-Clemens Fuel Company on December 31, 1999. The Company's Energy Center and State Line combustion turbine facilities are fueled primarily by natural gas with oil being used as a backup fuel. The Company's policy is to maintain a supply of oil at these facilities which would support full load operation for approximately three days for Energy Center Units 1 and 2 and State Line Unit No. 1. Based on current and projected fuel prices, it is expected that these facilities will continue to be operated primarily on natural gas. The Company has a firm agreement with Williams Natural Gas Company, expiring December 31, 2011, for the transportation of natural gas to the Empire Energy Center, the State Line Power Plant or the Riverton Plant, as elected by the Company. The Company expects that its remaining gas transportation requirements, as well as the majority of its gas supply requirements, will be met by spot purchases. The Company historically has purchased natural gas on a short-term basis. Unit No. 1 at the Iatan Plant is a coal-fired generating unit which is jointly-owned by Kansas City Power & Light ("KCPL") (70%), St. Joseph Light & Power Company ("SJLP") (18%) and the Company (12%). Low sulfur Western coal in quantities sufficient to meet substantially all of Iatan's requirements is supplied under a long- term contract expiring on December 31, 2003, between the joint owners and the Thunder Basin Coal Company. The coal is transported by rail under a contract expiring on December 31, 2000, with Burlington Northern, Kansas City Southern Railway Company and the MO-KAN-TEX railroads. The remainder of Iatan Unit No. 1's requirements for coal are met with spot purchases. The following table sets forth a comparison of the costs, including transportation costs, per million btu of various types of fuels used in the Company's facilities:
The Company's weighted cost of fuel burned per kilowatt-hour generated was 1.561 cents in 1999, 1.570 cents in 1998 and 1.397 cents in 1997.
Employees At December 31, 1999, the Company had 615 full-time employees, of whom 333 were members of Local 1474 of The International Brotherhood of Electrical Workers ("IBEW"). On January 17, 2000, the Company and the IBEW entered into a new three-year labor agreement effective November 1, 1999. The agreement provides, among other things, for a 3.25% increase in wages effective October 25, 1999, with additional minimum increases of 2% effective November 6, 2000 for the second year and effective October 22, 2001 for the third year.
Executive Officers and Other Officers of the Registrant The names of the officers of the Company, their ages and years of service with the Company as of December 31, 1999, positions held and effective date of such positions are presented below. Each of the executive officers of the Company has held executive officer or management positions within the Company for at least the last five years.
Regulation General. The Company, as a public utility, is subject to the jurisdiction of the Missouri Public Service Commission ("Missouri Commission"), the State Corporation Commission of the State of Kansas ("Kansas Commission"), the Corporation Commission of Oklahoma ("Oklahoma Commission") and the Arkansas Public Service Commission ("Arkansas Commission") with respect to services and facilities, rates and charges, accounting, valuation of property, depreciation and various other matters. Each such Commission has jurisdiction over the creation of liens on property located in its state to secure bonds or other securities. The Kansas Commission also has jurisdiction over the issuance of securities. The Company's transmission and sale at wholesale of electric energy in interstate commerce and its facilities are also subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") under the Federal Power Act. FERC jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale; the sale, lease or other disposition of such facilities and accounting matters. See discussion in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Competition." The Company's Ozark Beach Hydroelectric Plant is operated under a license from FERC. See Item 2, "Properties - Electric Facilities." The Company is disputing a Headwater Benefits Determination Report it received from FERC on September 9, 1991. The report calculates an assessment to the Company for headwater benefits received at the Ozark Beach Hydroelectric Plant for the period 1973 through 1990 in the amount of $705,724, and calculates an annual assessment thereafter of $42,914 for the years 1991 through 2011. The Company believes that the methodology used in making the assessment was incorrect and is contesting the determination. As of December 31, 1999, FERC had not responded to the comments filed by the Company on July 31, 1992. The Company is currently accruing an amount monthly equal to what it believes the correct assessment to be. During 1999, approximately 93% of the Company's electric operating revenues were received from retail customers. Approximately 88%, 6%, 3% and 3% of such retail revenues were derived from sales in Missouri, Kansas, Oklahoma and Arkansas, respectively. Sales subject to FERC jurisdiction represented approximately 7% of the Company's electric operating revenues during 1999. Rates. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Operating Revenues and Kilowatt-Hour Sales" for information concerning recent electric rate proceedings. Fuel Adjustment Clauses. Fuel adjustment clauses permit changes in fuel costs to be passed along to customers without the need for a rate proceeding. Fuel adjustment clauses are not permitted under Missouri law. Pursuant to an agreement with the Kansas Commission, entered into in connection with a 1989 rate
proceeding, a fuel adjustment clause is not applicable to the Company's retail electric sales in Kansas. Automatic fuel adjustment clauses are presently applicable to retail electric sales in Oklahoma and system wholesale kilowatt-hour sales under FERC jurisdiction. Arkansas has implemented an Energy Cost Recovery Rider that replaces the previous fuel adjustment clause. This rider is adjusted for changing fuel and purchased power costs on an annual basis rather than the monthly adjustment used by the previous fuel adjustment clause. Any increases in fuel costs may be recovered in Missouri and Kansas only through rate filings made with the appropriate Commissions.
Environmental Matters The Company is subject to various federal, state, and local laws and regulations with respect to air and water quality as well as other environmental matters. The Company believes that its operations are in compliance with present laws and regulations. Air. The 1990 Amendments to the Clean Air Act ("1990 Amendments") affect the Asbury, Riverton, and Iatan Power Plants. The 1990 Amendments require affected plants to meet certain emission standards, including maximum emission levels for sulfur dioxide ("SO2") and nitrogen oxide ("NOx"). When a plant becomes an affected unit for a particular emission, it locks in the then current emission standards. The Asbury Plant became an affected unit under the 1990 Amendments for both SO2 and NOx on January 1, 1995. The Riverton Plant became an affected unit for NOx in November 1996 and for SO2 on January 1, 2000. The Iatan Plant became an affected unit for both SO2 and NOx on January 1, 2000. SO2 Emissions. Under the 1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Each affected unit has been awarded a specific number of emission allowances, each of which allows the holder to emit one ton of SO2. Utilities covered by the 1990 Amendments must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. Allowances may be traded between plants, utilities or "banked" for future use. A market for the trading of emission allowances exists on the Chicago Board of Trade. The Environmental Protection Agency (the "EPA"), withholds annually a percentage of the emission allowances awarded to each affected unit and sells those emission allowances through a direct auction. The Company receives compensation from the EPA for the sale of these allowances. In 1999, the Asbury Plant used approximately 51% of its available SO2 emission allowances. In the year 2000, the number of SO2 emission allowances that the Asbury Plant will receive each year is expected to decline by approximately one-half (before EPA withholding). The Company anticipates (based on current operations) that the Asbury Plant will use slightly more allowances than the number available to it on an annual basis with the deficit coming from the Company's inventoried bank of allowances. The Company currently has 36,000 banked allowances. With respect to the Riverton Plant, the Company is presently burning a combination of Western coals that will allow the plant to use approximately the amount of allowances that it receives annually from the EPA. If the plant requires more allowances than it has received, the Company will transfer allowances from the Asbury Plant to the Riverton Plant. The Iatan Unit is expected to be deficient in allowances by a margin of approximately 20% based on current operating conditions. Any needed allowances will be supplied by the respective owners from present inventories or by open-market purchases. NOx Emissions. The EPA revised its regulations to require cyclone units (such as the Asbury Plant) to meet more stringent NOx requirements by 2000. The Company installed NOx control modifications in 1999 that have reduced NOx emissions at the Asbury Plant. The Asbury Plant is in compliance with current NOx requirements The Iatan Plant and the Riverton Plant are each in compliance with the NOx limits applicable to them under the 1990 Amendments as currently operated. In September 1998, the EPA issued its final regulation for a State Implementation Plan ("SIP") call for NOx requiring the District of Columbia and 22 Midwestern and Eastern states to reduce NOx emissions up to 85% below the levels established by the 1990 Amendments. The State of Missouri was included in the final regulation but Kansas, Arkansas and Oklahoma were not. The Asbury, State Line, Energy Center and Iatan Power Plants are affected by this SIP call. If unchanged, this SIP call would require installation of additional NOx control equipment at the Asbury and Iatan Power Plants by May 1, 2003. The Company is proceeding with the development of compliance plans, including preliminary engineering and cost determination. In 1999, the Company joined litigation in the Washington D.C. Circuit Court against the EPA NOx SIP call. One suit has been filed by the Midwest Ozone Group and
another by an alliance of western Missouri utilities. Oral arguments were heard on November 9, 1999 and a ruling is expected during the first quarter of 2000. The NOx SIP call requirement that the Missouri Department of Natural Resources develop its own SIP by September 1999 was stayed by the Washington D.C. Circuit Court until a decision on the NOx SIP call litigation is issued. If the litigation is unsuccessful, the Company will be required to install additional NOx control equipment at the Asbury Power Plant at an estimated capital cost of approximately $17 million. The installation of this equipment would begin in 2002 and its cost is not included in the Company's current construction budget. If the litigation is successful, the Company may still need to install additional NOx control equipment, but the Company cannot estimate the cost or timing thereof. Water. The Company operates under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Water Pollution Control Act Amendments of 1972. The Asbury, Iatan, Riverton, Energy Center and State Line facilities are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required. The Asbury permit has been drafted and is expected to be issued by mid-2000. The Riverton Plant's National Pollution Discharge Elimination System ("NPDES") Permit expires in September 2000. The Company will apply for a renewal in March 2000 and does not expect any changes in the parameters regarding the permit. The State Line Plant is currently in the process of applying for a new NPDES Permit pertaining to the expansion of the plant. This permit is needed by July 2001. Other. Under Title 5 of the 1990 Amendments, the Company must obtain site operating permits for each of its plants from the authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site's total emissions; including emissions from stacks, individual pieces of equipment, road dust, coal dust and steam leaks. The Company has been issued permits for Asbury, State Line and the Energy Center Power Plants. The Riverton Plant has not been issued an operating permit at this time. The Company expects this permit will be issued during 2000.
Conditions Respecting Financing The Company's Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the "Mortgage"), and its Restated Articles of Incorporation (the "Restated Articles"), specify earnings coverage and other conditions which must be complied with in connection with the issuance of additional first mortgage bonds or cumulative preferred stock, or the incurrence of unsecured indebtedness. The Mortgage generally permits the issuance of additional bonds only if net earnings (as defined) for a specified twelve-month period are at least twice the annual interest requirements on all bonds at the time outstanding, including the additional issue and all indebtedness of prior rank. Under this test, on December 31, 1999, the Company could have issued under the Mortgage approximately $141.8 million principal amount of additional bonds (at an assumed interest rate of 7.50%). In addition to the interest coverage requirement, the Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 1999, the Company had retired bonds and net property additions which would enable the issuance of at least $148.0 million principal amount of bonds. Under the Restated Articles, (a) cumulative preferred stock may be issued only if net income of the Company available for interest and dividends (as defined) for a specified twelve-month period is at least 1-1/2 times the sum of the annual interest requirements on all indebtedness and the annual dividend requirements on all cumulative preferred stock, to be outstanding immediately after the issuance of such additional shares, and (b) so long as any preferred stock is outstanding, the amount of unsecured indebtedness outstanding may not exceed 20% of the sum of the outstanding secured indebtedness plus the capital and surplus of the Company. The Company redeemed all of its outstanding preferred stock on August 2, 1999 and, accordingly, the Articles do not restrict the amount of unsecured indebtedness that the Company may have outstanding.
ITEM 2.
ITEM 2. PROPERTIES
Electric Facilities At December 31, 1999, the Company owned generating facilities (including its interest in Iatan Unit No. 1) with an aggregate generating capacity of 878 megawatts. The principal electric generating plant of the Company is the Asbury Plant with 213 megawatts of generating capacity. The Plant, located near Asbury, Missouri, is a coal-fired generating station
with two steam turbine generating units. The Plant presently accounts for approximately 24% of the Company's owned generating capacity and in 1999 accounted for approximately 44% of the energy generated by the Company and 28% of the total energy sold by the Company. Routine plant maintenance, during which the entire Plant is taken out of service, is scheduled once each year, normally for approximately four weeks in the spring. Every fifth year the spring outage is scheduled to be extended to a total of six weeks to permit inspection of the Unit No. 1 turbine. The last such outage was in 1996 and the next such extended outage will occur in 2001. The Unit No. 2 turbine is inspected approximately every 35,000 hours of operations. The unit can be overhauled without Unit No. 1 having to come off-line. When the Asbury Plant is out of service, the Company typically experiences increased purchased power and fuel costs associated with replacement energy. See Item 1 "Business - Regulation - Fuel Adjustment Clauses," for additional information concerning increased purchased power and fuel costs. The Company's generating plant located at Riverton, Kansas, has two steam-electric generating units with an aggregate generating capacity of 92 megawatts and three gas-fired combustion turbine units with an aggregate generating capacity of 44 megawatts. The steam-electric generating units burn coal as a primary fuel and have the capability of burning natural gas. The last five-year scheduled maintenance outage for the Riverton Plant occurred during the second quarter of 1998. The Company owns a 12% undivided interest in the 670 megawatt coal-fired Unit No. 1 at the Iatan Generating Station located 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. The Company is entitled to 12% of the unit's available capacity and is obligated to pay for that percentage of the operating costs of the Unit. KCPL and SJLP own 70% and 18%, respectively, of the Unit. KCPL operates the unit for the joint owners. See Note 10 of "Notes to Financial Statements" under Item 8. The Company also has two combustion turbine peaking units at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 180 megawatts. These peaking units operate on natural gas as well as oil. The Company's State Line Power Plant, which is located west of Joplin, Missouri, presently consists of two combustion turbine units with an aggregate generating capacity of 253 megawatts. These units burn natural gas as a primary fuel and have the capability of burning oil. Unit No. 1 was placed in service in mid-1995 and Unit No. 2 was placed in service in mid-1997. On July 26, 1999, the Company and Westar Generating, Inc. ("WGI"), a subsidiary of Western Resources, Inc., entered into agreements for the construction, ownership and operation of a 500-megawatt combined- cycle unit at the State Line Power Plant (the "State Line Combined Cycle Unit"). This State Line Combined Cycle Unit will consist of an additional combustion turbine, two heat recovery steam generators and a steam turbine and auxiliary equipment with an already existing combustion turbine. Work has begun and the State Line Combined Cycle Unit is projected to be operational by June 2001. The Company will own an undivided 60% interest in the State Line Combined Cycle Unit with WGI owning the remainder. The Company is entitled to 60% of the capacity of the State Line Combined Cycle Unit. The Company will contribute its existing 152- megawatt State Line Unit No. 2 combustion turbine to the State Line Combined Cycle Unit, and as a result, upon commercial operation, the State Line Combined Cycle Unit will provide the Company with approximately 150 megawatts of additional capacity. The total cost of this construction expansion project is estimated to be $185 million. The Company's share of this amount, after the transfer to WGI of an undivided 40% joint ownership interest in the existing State Line Unit No. 2 and certain other property at book value as described below, is expected to be approximately $100 million. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." The Company's hydroelectric generating plant, located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts, subject to availability of water. The Company has a long-term license from FERC to operate this plant which forms Lake Taneycomo in Southwestern Missouri. At December 31, 1999, the Company's transmission system consisted of approximately 22 miles of 345 kV lines, 412 miles of 161 kV lines, 756 miles of 69 kV lines and 81 miles of 34.5 kV lines. Its distribution system consisted of approximately 6,204 miles of line. The electric generation stations owned by the Company are located on land owned in fee. The Company owns a 3% undivided interest as tenant in common with KCPL and SJLP in the land for the Iatan Generating Station. The Company will own a similar interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all the electric transmission and distribution
facilities of the Company are located either (1) on property leased or owned in fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over private property by virtue of easements obtained from the record holders of title. Substantially all property, plant and equipment of the Company are subject to the Mortgage.
Water Facilities The Company also owns and operates water pumping facilities and distribution systems consisting of a total of approximately 79 miles of water mains in three communities in Missouri.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
No legal proceedings required to be disclosed by this Item are pending.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed on the New York Stock Exchange. On March 1, 2000, there were 8,384 record holders of its common stock. The high and low sale prices for its common stock reported in The Wall Street Journal as New York Stock Exchange composite transactions, and the amount per share of quarterly dividends declared and paid on the common stock for each quarter of 1999 and 1998 were as follows:
Holders of the Company's common stock are entitled to dividends if, as, and when declared by the Board of Directors of the Company, out of funds legally available therefor, subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. The Mortgage and the Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the Mortgage, which provides that the Company may not declare or pay any dividends (other than dividends payable in shares of its common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, its common stock if the cumulative aggregate amount thereof after August 31, 1944, (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the earned surplus (as defined) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to the rights and liabilities of the Company by a merger or consolidation. The Company, with the requisite consents of the holders of bonds issued under the Mortgage, has entered into a supplemental indenture which amends this dividend restriction so
that a successor corporation would only need to look to earned surplus accumulated subsequent to August 31, 1944 instead of the date of succession. This supplemental indenture will not be effective, however, until the merger with UtiliCorp is completed. As of December 31, 1999, said dividend restriction did not affect any of the retained earnings of the Company. The Company's Dividend Reinvestment and Stock Purchase Plan (the "Reinvestment Plan") allows common and preferred stockholders to reinvest dividends of the Company into newly issued shares of the Company's common stock at 95% of a market price average calculated pursuant to the Reinvestment Plan. Stockholders may also purchase, for cash and within specified limits, additional stock at 100% of such market price average. The Company may elect to make shares purchased in the open market rather than newly issued shares available for purchase under the Reinvestment Plan. If the Company so elects, the purchase price to be paid by Reinvestment Plan participants will be 100% of the cost to the Company of such shares. Participants in the Reinvestment Plan do not pay commissions or service charges in connection with purchases under the Reinvestment Plan. The Company has a shareholders rights plan which expires July 25, 2000, under which each of its common stockholders has one-half a Preference Stock Purchase Right ("Right") for each share of common stock owned. One Right enables the holder to acquire one one- hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one-hundredth of a share, subject to adjustment. The rights (other than those held by an acquiring person or group ("Acquiring Person")) will be exercisable only if an Acquiring Person acquires 10% or more of the Company's common stock or if certain other events occur. This provision was amended on May 10, 1999 to exclude the pending merger with UtiliCorp. See Note 5 of "Notes to Financial Statements" under Item 8 for further information. The By-laws of the Company provide that K.S.A. Sections 17- 1286 through 17-1298, the Kansas Control Share Acquisitions Act, will not apply to control share acquisitions of the Company's capital stock. See Note 4 of "Notes to Financial Statements" under Item 8 for additional information regarding the Company's common stock.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MERGER WITH UTILICORP
The Company and UtiliCorp United Inc., a Delaware corporation ("UtiliCorp"), have entered into an Agreement and Plan of Merger, dated as of May 10, 1999 (the "Merger Agreement"), which provides for a merger of the Company with and into UtiliCorp, with UtiliCorp being the surviving corporation (the "Merger"). Under the terms of the Merger Agreement, UtiliCorp will pay $29.50 for each share of common stock of the Company, payable in UtiliCorp common stock or cash. The Merger Agreement contains a collar provision under which the value of the merger consideration per share will decrease if UtiliCorp's common stock is below $22 per share preceding the closing and will increase if UtiliCorp's common stock is above $26 per share preceding the closing. The average trading price of UtiliCorp's common stock price will be used to determine the merger consideration and will be calculated based on the closing prices on the NYSE during the 20 trading days ending on the third trading day prior to the closing date of the Merger. If the average trading price is below $22, UtiliCorp will pay 1.342 times the average trading price for each share of Company common stock and if the average trading price is above $26, UtiliCorp will pay 1.135 times the average trading price for each share of Company common stock. For example, if the Merger had closed on March 6, 2000, the average trading price for UtiliCorp's common stock would have been $17.5656 per share, resulting in the payment of $23.5513 for each share of the Company's common stock. Stockholders of the Company may elect to take cash or stock, but total cash paid to stockholders will be limited to no more than 50% of the total Merger consideration, and the number of shares of UtiliCorp common stock that may be issued in the Merger is limited to 19.9% of the number of then outstanding shares of common stock of UtiliCorp. UtiliCorp also will become liable for all of the Company's existing debt, including its first mortgage bonds. See Note 2 of "Notes to Financial Statements" under Item 8 for further information. The Merger, which was unanimously approved by the Boards of Directors of the constituent companies, is expected to close after all of the conditions to the consummation of the Merger are met or waived. The Merger is conditioned, among other things, upon approvals of federal regulatory agencies and approvals of state regulatory authorities in states where the combined company will operate. At a special meeting of stockholders held on September 3, 1999, the Merger was approved with 76.3% of the Company's outstanding shares voting in favor of the proposal. UtiliCorp is not required to obtain its stockholders' approval of the Merger. The Company and UtiliCorp filed joint applications with the FERC on November 23, 1999 and the Missouri Commission on December 14, 1999 requesting approval of the merger. Applications to merge were filed with the Arkansas Public Service Commission on January 28, 2000 and with the Kansas Corporation Commission and Oklahoma Corporation Commission on January 31, 2000. The applications set forth a proposed Regulatory Plan (the "Plan") which would result in a five-year rate moratorium following the conclusion of a rate case the Company plans to file in the second half of 2000. This rate case is designed to recover the costs associated with the Company's State Line Project anticipated to be operational by June 2001. The Plan also calls for UtiliCorp to keep any savings generated by the Merger to offset the acquisition premium. UtiliCorp may file a rate case at the end of the five-year rate moratorium allowing UtiliCorp to include one half of any unamortized acquisition premium in the rate base, thus allowing it to be recovered in rates. The Missouri Commission has scheduled hearing dates for the Merger proposal for September 11-15, 2000 in Jefferson City, Missouri, which means a ruling could be issued by that Commission before the end of this year. UtiliCorp is a multinational energy and energy services company headquartered in Kansas City, Missouri. It has regulated utility operations in eight states and energy operations in New Zealand, Australia, the United Kingdom and Canada. It also owns non-utility subsidiaries involved in energy trading; natural gas gathering, processing and transportation; energy efficiency services and various other energy-related businesses. For more information on the Merger, see the Company's proxy statement for its special meeting of stockholders held on September 3, 1999, which is dated August 2, 1999.
RESULTS OF OPERATIONS The following discussion analyzes significant changes in the results of operations for the year ended December 31, 1999, compared to the year ended December 31, 1998, and for the year ended December 31, 1998, compared to the year ended December 31, 1997.
Operating Revenues and Kilowatt-Hour Sales Of the Company's total electric operating revenues during 1999, approximately 41% were from residential customers, 31% from commercial customers, 17% from industrial customers, 4% from wholesale on-system customers and 3% from wholesale off-system transactions. The remainder of such revenues were derived from miscellaneous sources. The percentage changes from the prior year in kilowatt-hour ("Kwh") sales and revenue by major customer class were as follows:
Kwh sales for the Company's on-system customers increased slightly during 1999 while revenues increased slightly more than the corresponding increase in Kwh sales. Customer growth increased slightly in 1999 over the 1.8% growth rate in 1998. Despite above-average temperatures in July and August, residential Kwh sales decreased 2.6% with revenues decreasing 1.8% as compared to 1998. This decrease was primarily due to unusually mild temperatures during the second quarter of 1999, as well as in September, November and December, and the unusually warm second and third quarters of 1998. Commercial and industrial classes showed an increase in Kwh sales and revenues due to continued increases in business activity throughout the Company's service territory. On-system wholesale Kwh sales were down slightly in 1999, reflecting the mild temperatures discussed above. Revenues associated with these sales decreased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause applicable to such FERC regulated sales. This clause permits the pass through to customers of changes in fuel and purchased power costs. Kwh sales for the Company's on-system customers increased during 1998 primarily due to above-average temperatures during the second and third quarters. Revenues increased more than the corresponding increase in Kwh sales primarily due to increased rates in Missouri and Arkansas as reflected in the table below and the winter/summer differential in rates. This differential results from summer rates being higher than winter rates, so warm summer temperatures that increase summer Kwh usage cause the corresponding annual revenues to increase at a greater rate than the annual Kwhs. Revenues and Kwh sales were also positively impacted by $1.7 million (0.1%),and 32 million Kwhs (0.8%) respectively, as a result of a change in the estimation of periodic loss factors used to calculate unbilled revenues. Customer growth increased slightly to 1.8% in 1998 as compared to 1.7% in 1997. Residential and commercial Kwh sales increased as compared to 1997, primarily due to the above-average temperatures discussed above. Industrial classes, although not particularly weather-sensitive, also showed an increase in Kwh sales and revenues due to continued increases in business activity throughout the Company's service territory. On-system wholesale Kwh sales were up significantly in 1998, reflecting the warm summer temperatures and continued increases in business activity discussed above. Revenues associated with these sales increased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause. The following table sets forth information regarding electric rate increases affecting the revenue comparisons discussed above:
In addition to sales to its own customers, the Company sells power to other utilities as available and provides transmission service through its system for transactions between other energy suppliers. During 1999 revenues from such off-system transactions were approximately $9.6 million as compared to approximately $8.3 million in 1998 and approximately $7.6 million during 1997. The increase in revenues during 1999 was primarily the result of an increase in firm capacity charges as well as an increase in sales resulting from the ability to sell power at market-based rates. Pursuant to orders issued by the FERC and subsequent tariffs filed by the Company and SPP, these off-system sales have been opened up to competition. See "- Competition" below for more information. The Company's future revenues from the sale of electricity will continue to be affected by economic conditions, business activities, competition, weather, regulation, the utilities' change from a regulated to a competitive environment, changes in electric rate levels and changing patterns of electric energy use by customers. Inflation affects the Company's operations in that historical costs rather than current replacement costs are recovered in the Company's rates.
Operating Revenue Deductions During 1999, total operating expenses increased approximately $6.1 million (5.1%) compared to the prior year. Merger related expenses, which are not tax deductible, contributed $5.8 million to this increase. A significant portion of these expenses include payments to the Company's financial advisors for the first and second portions of the agreed upon transaction fee for their financial services in connection with the merger. This agreement calls for payment of 25% of the transaction fee upon execution of the merger agreement, 25% upon stockholder approval of the merger and the remaining 50% upon the consummation of the merger, payable upon closing. Including the final payment to be made under this agreement, remaining merger costs are expected to total approximately $11 million. Total purchased power costs decreased by approximately $2.9 million (6.0%) during 1999, primarily due to increased availability of the Company's generating units. The Asbury Plant set a new continuous run record of 190 days in 1999. Total fuel costs were up approximately $3.4 million (8.1%) during 1999 as compared to the same period in 1998 primarily reflecting the increased generation from the higher-cost gas turbines at the State Line Power Plant. The hot temperatures in July and August resulted in a significant increase in the price of purchased power, making it more economical for the Company to run its gas turbines during those months. In addition, natural gas prices were higher by 1.5% during 1999 as compared to 1998, contributing to the increase. Other operating expenses decreased slightly by approximately $0.1 million (0.4%) during 1999, compared to 1998. Maintenance and repairs expense decreased approximately $1.2 million (6.7%) during 1999 primarily due to decreased maintenance costs at Asbury and Riverton. The Riverton Plant had a five-year scheduled maintenance outage in 1998. These decreases offset maintenance and repairs expense resulting from a New Year's Day ice storm that interrupted service to approximately 35,000 of the Company's Missouri and Kansas customers over a three day period. Depreciation and amortization expense increased approximately $1.4 million (5.6%) during 1999, compared to 1998, due to increased levels of plant and equipment placed in service. Total income taxes decreased approximately $0.3 million (2.0%) during 1999 due primarily to lower taxable income during the current year. See Note 9 of "Notes to Financial Statements" under Item 8 for additional information regarding income taxes. Other taxes were up approximately $1.1 million (8.8%) during the year largely as a result of increased property taxes.
During 1998, total operating expenses increased approximately $7.5 million (6.6%) compared to the prior year. Total fuel costs were up approximately $5.8 million (16.0%) during 1998, due primarily to the increased generation from gas-fired combustion turbine units at both State Line and the Energy Center. This increased generation was due to increased customer demand in the second and third quarters of 1998 resulting from the warmer temperatures. Natural gas prices were lower by 3.0% during 1998 as compared to 1997, helping to offset some of the additional expense. Total purchased power costs increased slightly by approximately $0.4 million (0.9%) during 1998. Other operating expenses increased approximately $1.3 million (4.3%) during 1998, compared to 1997, due primarily to increases in customer accounts expense and administrative and general expense. Approximately $0.7 million of this increase was a one- time charge due to the initiation of the Directors Stock Unit Plan, a stock-based retirement compensation program for the Company's Directors. Maintenance and repairs expense increased approximately $4.7 million (36.4%) during 1998. Scheduled maintenance on combustion turbines at the Energy Center and the State Line Power Plant accounted for approximately $2.8 million of this increase while approximately $1.1 million can be attributed to the first quarter spring maintenance outage at the Asbury Plant and the second quarter five-year scheduled maintenance outage at the Riverton Plant. Transmission and distribution system maintenance contributed $0.8 million to the increase. Depreciation and amortization expense increased approximately $1.6 million (6.8%) during 1998, compared to 1997, due to increased levels of plant and equipment placed in service. Total income taxes increased approximately $3.2 million (24.5%) during 1998 due primarily to higher taxable income during the current year. See Note 9 of "Notes to Financial Statements" under Item 8 for additional information regarding income taxes. Other taxes were up approximately $1.2 million (10.3%) during the year largely as a result of increased property taxes and city taxes.
Nonoperating Items Total allowance for funds used during construction ("AFUDC") amounted to approximately 6.1% of earnings applicable to common stock during 1999, 1.6% during 1998, and 5.7% during 1997. AFUDC increased significantly during 1999 reflecting higher levels of construction work in progress related to the State Line Project. AFUDC decreased significantly during 1998 reflecting lower levels of construction work in progress due mainly to the completion of State Line Unit No. 2 in June 1997. See Note 1 of "Notes to Financial Statements" under Item 8. Interest charges on long-term debt increased in both 1999 and 1998 due to the issuance of $100 million of the Company's unsecured Senior Notes in November 1999 and $50 million of the Company's First Mortgage Bonds in April 1998. The proceeds from the Senior Notes were added to the Company's general funds and were used to repay short-term indebtedness, including approximately $33.1 million in commercial paper incurred in connection with the Company's preferred stock redemption on August 2, 1999, as well as that incurred in connection with the Company's construction program. The proceeds from the Company's First Mortgage Bonds were added to the Company's general funds and were used to repay $23 million of the Company's First Mortgage Bonds due May 1, 1998 and to repay short-term indebtedness, including that incurred in connection with the Company's construction program. Commercial paper interest increased $1.0 million (153.6%) during 1999 due to increased usage of short-term debt for financing purposes, particularly in connection with the Company's preferred stock redemption. Interest income for that year also increased, reflecting the higher balances of cash available for investment.
Earnings Basic and diluted earnings per weighted average share of common stock were $1.13 during 1999 compared to $1.53 in 1998. Earnings per share were down primarily due to the $5.8 million in merger costs incurred during 1999, as well as the $1.3 million in excess consideration paid on redemption of the Company's preferred stock. Earnings for 1999 were also negatively impacted by mild temperatures and increased interest expense. Excluding the $5.8 million in merger costs, earnings per share would have been $1.46. Earnings per share of common stock were $1.53 during 1998 compared to $1.29 in 1997. Increased revenue resulted mainly from the unusually warm second and third quarters of 1998. The 1998 Arkansas rate increase and the 1997 Missouri rate increase also favorably impacted the Company's operating results in 1998, as the
Missouri jurisdiction accounts for approximately 90% of the on- system retail sales of the Company.
Competition
Federal regulation, such as The National Energy Policy Act of 1992 (the "Energy Act") has promoted and is expected to continue to promote competition in the electric utility industry. The Energy Act, among other things, eases restrictions on independent power producers, delegates authority to the FERC to order wholesale wheeling and grants individual states the power to order retail wheeling. At this time, Oklahoma and Arkansas are the only states in which the Company operates that have taken any such action. In Missouri, the Public Service Commission adopted an order in 1997 establishing a docket and creating a task force on retail electric competition. The Commission Task Force, on which the Company was represented, was charged with preparing a comprehensive report for the Commission on how Missouri could implement retail electric competition. The Joint Committee of the Missouri Legislature received testimony during 1997 and 1998. No legislative action was taken in 1999. There are bills pending in the 2000 Missouri Legislature, but no action is expected this year. In Kansas, although different bills have been introduced into the House and Senate, no legislative action has been taken. In Oklahoma, the Electric Restructuring Act of 1997 was passed by the Legislature and signed into law by the Governor. The bill, with a target date of July 1, 2002, was designed to provide for the orderly restructuring of the electric utility industry in the state and move the state toward open competition for electric generation. An Electric Utility Task Force has been studying all issues in Oklahoma and has prepared legislation to provide a more comprehensive framework for the transition to retail open access. That legislation is under consideration by the Oklahoma General Assembly. Approximately 3.1% of the Company's 1999 operating revenue was derived from sales subject to Oklahoma regulation. The Arkansas Legislature passed a bill in April 1999 that would deregulate the state's electricity industry as early as January 2002. A special provision, however, applies to utilities with a small portion of Arkansas customers whose majority of customers are from another state. This provision, which applies to the Company, exempts the Company from restructuring in Arkansas until restructuring is enacted in Missouri or until January 1, 2004, whichever comes first. The bill would freeze rates for three years for residential and small business customers of utilities that seek to recover stranded costs, and freeze rates for one year for residential and small business customers of utilities, such as the Company, that do not seek to recover stranded costs. This freeze applies only to rate increases and does not apply to any fuel adjustment clause or energy cost recovery rider approved by the Arkansas Commission, such as the one the Company has to recover its fuel and purchased power costs. The bill also requires the unbundling of services on electric bills by June 2000. The Company is currently engaged in the regulatory proceedings that have commenced as a result of the new law. Approximately 2.6% of the Company's 1999 operating revenue was derived from sales subject to Arkansas regulation. In April 1996, the FERC issued Order No. 888 ("Order 888") which required all electric utilities that own, operate, or control interstate transmission facilities to file open access tariffs that offer all wholesale buyers and sellers of electricity the same transmission services that they provide themselves. The utility would have to take service under those tariffs for its own wholesale power transactions. Order 888 required a functional unbundling of transmission and power marketing services. The Company and the SPP have filed open access transmission tariffs covering these wholesale transmission services. The SPP tariff applies to most of the transmission services for which the Company tariff was designed. Where that is the case, the Company shares revenues received from such transmission services with other members of the SPP based on a megawatt mile method of calculating transmission service charges. There are, however, limited circumstances where the Company tariff still applies and the Company receives 100% of the revenues from the transmission services. The SPP tariff will continue to apply unless and until a new tariff is filed as part of any regional transmission organization ("RTO") which the Company may join as discussed below. On December 15, 1999, the FERC issued Order No. 2000 ("Order 2000"), which encourages the development of RTOs. RTOs are designed to control the wholesale transmission services of the utilities in its region. Order 2000 is intended to continue the process of promoting open and more competitive markets in bulk power sales of electricity that was begun with Order 888. On
December 30, 1999, SPP filed with the FERC for recognition as an Independent System Operator and as an RTO. The Company does not expect the implementation of Order 2000 to have a significantly different impact on its results of operations than the implementation of Order 888 and the operation of the SPP tariff had. Several factors exist which may enhance the Company's ability to compete as deregulation occurs. The Company is able to generate and purchase power relatively inexpensively; during 1999, the Company's retail rates were approximately 21% less than the electric industry average. In addition, less than 5% of the Company's electric operating revenues are derived from sales to on- system wholesale customers, the type of customer for which the FERC is already requiring wheeling. At the same time, the Company could face increased competitive pressure as a result of its reliance on relatively large amounts of purchased power and its extensive interconnections with neighboring utilities. In addition, the Company has continued its investments in non- regulated businesses which it commenced in 1996. The Company now leases capacity on its broadband fiber optics network and provides electronic monitored security, decorative lighting and other energy services.
Year 2000 Costs
The Company experienced no Year 2000-related problems as it passed from 1999 to 2000. The Company's total cost (which includes the costs of a new financial management software package and a new customer information system) to update all of its systems for Year 2000 readiness was approximately $5.7 million, of which approximately $5.1 million was capitalized while $0.6 million was expensed. Of these capitalized costs, $0.5 million was included in the 1998 capital budget and $1.5 million was included in the 1999 capital budget. Costs for specific Year 2000 remediation projects were charged to expense while costs to replace software for business purposes other than addressing Year 2000 issues were capitalized.
LIQUIDITY AND CAPITAL RESOURCES
The information discussed below in this section is presented without giving any effect to the Company's proposed merger with UtiliCorp. The Company's construction-related expenditures totaled approximately $71.9 million, $51.9 million, and $56.7 million in 1999, 1998 and 1997, respectively. A breakdown of the Company's 1999 construction expenditures is as follows:
Approximately 46% of construction expenditures and other funds requirements for 1999 were satisfied internally from operations. The Company estimates that its construction expenditures will total approximately $105.7 million in 2000, $61.1 million in 2001 and $50.9 million in 2002. Of these amounts, the Company anticipates that it will spend $21.4 million, $23.1 million and $24.5 million in 2000, 2001 and 2002, respectively, for additions to the Company's distribution system to meet projected increases in customer demand. These construction expenditure estimates also include approximately $57.8 million, $17.8 million and $3.5 million in 2000, 2001 and 2002 respectively, for the construction of the State Line Combined Cycle Unit.
The total cost of construction at the State Line Combined Cycle Unit is estimated to be $185 million. The Company's share of this amount, after the transfer to WGI of an undivided 40% joint ownership interest in the existing State Line Unit No.2 and certain other property at book value is expected to be approximately $100 million. For more information on the State Line Project see Item 2, "Properties - Electric Facilities." WGI is responsible for 40% of expenditures made by the Company in connection with the construction and operation of the State Line Combined Cycle Unit. In addition, WGI will continue to make monthly prepayments to the Company for the future transfer of its 40% joint ownership interest in the existing State Line Unit No. 2, as well as an interest in certain underlying and surrounding land and other property and equipment now owned by the Company. These prepayments are reflected in State Line advance payments on the balance sheet. See Item 8, "Financial Statements and Supplementary Data." The Company estimates that internally generated funds will provide at least 50% of the funds required in 2000, 2001 and 2002 for estimated construction expenditures. As in the past, the Company intends to utilize short-term debt to finance the additional amounts needed for such construction and repay such borrowings with the proceeds of sales of public offerings of long- term debt or equity securities, including the sale of the Company's common stock pursuant to its Dividend Reinvestment Plan and Employee Stock Purchase Plan and from internally-generated funds. The Company will continue to utilize short-term debt as needed to support normal operations or other temporary requirements and has a $50 million line of credit. See Note 6 of "Notes to Financial Statements" regarding the Company's line of credit. The Company financed its preferred stock redemption on August 2, 1999 with approximately $33.1 million in commercial paper. After redeeming all of its preferred stock, the Company is no longer restricted by its Articles as to the amount of unsecured indebtedness that it may have outstanding at any one time. As a result of the implementation of and transition to the Company's new Centurion customer information system, the Company has experienced some delays in customer billing and cash collection. The Company is working to correct these delays and is continuing to enhance and refine this system. The Company filed a shelf registration statement with the SEC, which became effective on September 30, 1999, registering up to an aggregate of $150 million of its common stock, first mortgage bonds and unsecured debt securities. On November 19, 1999, the Company issued $100 million aggregate principal amount of its unsecured Senior Notes, the net proceeds of which were added to the Company's general funds and were used to repay short- term indebtedness, including indebtedness incurred in connection with the Company's preferred stock redemption and in connection with the Company's construction program. On April 28, 1998, the Company sold to the public in an underwritten offering $50 million aggregate principal amount of its First Mortgage Bonds, 6.50% Series due 2010. The net proceeds from this sale were added to the Company's general funds and were used to repay $23 million of the Company's First Mortgage Bonds, 5.70% Series due May 1, 1998 and to repay short-term indebtedness, including indebtedness incurred in connection with the Company's construction program. Following announcement of the Merger, the ratings for the Company's debt securities (other than the 5.20% Pollution Control Series due 2013 and the 5.30% Pollution Control Series due 2013) were placed on credit watch with downward implication by each of Moody's Investors Service, Standard & Poor's and Duff & Phelps Credit Rating Company. As of December 31, 1999, the Company's ratings for its first mortgage bonds, senior notes and commercial paper were as follows:
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk. The Company is exposed to changes in interest rates as a result of significant financing through its issuance of fixed-rate debt and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate exposure to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. See Notes 6 and 7 of "Notes to Financial Statements" under Item 8 for further information. If market interest rates average 1% more in 2000 than in 1999, the Company's interest expense would increase and income before taxes would decrease by $300,000. This amount has been determined by considering the impact of the hypothetical interest rates on the Company's average daily commercial paper balances for the year ended December 31, 1999. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in the Company's financial structure. Commodity Price Risk. The Company is exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employs established policies and procedures to manage its risks associated with these market fluctuations. At this time none of the Company's commodity purchase or sale contracts meet the definition of financial instruments
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Accountants
To the Board of Directors and Stockholders of The Empire District Electric Company
In our opinion, the financial statements listed in the index appearing under Item 14(a)(1) on page 44 present fairly, in all material respects, the financial position of The Empire District Electric Company at December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 14(a)(2) on page 44 present fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
St. Louis, Missouri February 2, 2000
The accompanying notes are an integral part of these financial statements.
Statement of Cash Flows
1. Summary of Accounting Policies
The Company is subject to regulation by the Missouri Public Service Commission (MoPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). The accounting policies of the Company are in accordance with the rate-making practices of the regulatory authorities and, as such, conform to generally accepted accounting principles as applied to regulated public utilities. The Company's electric revenues in 1999 were derived as follows: residential 41%, commercial 31%, industrial 17%, wholesale 4% and other 7%. Following is a description of the Company's significant accounting policies:
Property and plant The costs of additions to property and plant and replacements for retired property units are capitalized. Costs include labor, material and an allocation of general and administrative costs plus an allowance for funds used during construction. Maintenance expenditures and the renewal of items not considered units of property are charged to income as incurred. The cost of units retired is charged to accumulated depreciation, which is credited with salvage and charged with removal costs.
Depreciation Provisions for depreciation are computed at straight-line rates as approved by regulatory authorities. Such provisions approximated 3.2%, 3.2% and 3.1% of depreciable property for 1999, 1998 and 1997, respectively.
Computations of earnings per share Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of common shares outstanding plus the incremental shares that would have been outstanding under the assumed exercise of dilutive stock options and their equivalents. The weighted average number of common shares outstanding used to compute basic earnings per share for the 1999, 1998 and 1997 periods was 17,237,805, 16,932,704 and 16,599,269, respectively. Dilutive stock options for the 1999, 1998 and 1997 periods were 5,290, 7,775 and 9,844, respectively.
Allowance for funds used during construction As provided in the regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds (preferred and common stockholders' equity) applicable to the Company's construction program are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials. AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation.
In accordance with the methodology prescribed by FERC, the Company utilized aggregate rates of 5.4% for 1999, 5.9% for 1998 and 6.4% for 1997 (on a before-tax basis) compounded semiannually.
Income taxes Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes, measured using statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate.
Unamortized debt discount, premium and expense Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues.
Accrued unbilled revenue The Company accrues on its books estimated, but unbilled, revenue and also a liability for the related taxes.
Accumulated provision for uncollectible accounts The accumulated provision for uncollectible accounts was $372,000 at December 31, 1999 and $276,000 at December 31, 1998.
Franchise taxes Franchise taxes are collected for and remitted to their respective cities. Operating revenues include franchise taxes of $4,400,000, $4,400,000 and $3,900,000 for each of the years ended December 31, 1999, 1998 and 1997, respectively.
Liability insurance The Company carries excess liability insurance for workers' compensation and public liability claims. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on loss experience of the Company.
State Line advance payments The Company is currently receiving advance payments from Westar Generating, Inc. (WGI) for WGI's share of the existing State Line facility (See Note 10).
Use of estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Actual amounts could differ from those estimates.
2. Merger Agreement
The Company and UtiliCorp United, Inc., a Delaware corporation ("UtiliCorp"), have entered into an Agreement and Plan of Merger, dated as of May 10, 1999 (the "Merger Agreement"), which provides for a merger of the Company with and into UtiliCorp, with UtiliCorp being the surviving corporation (the "Merger"). Under the terms of the Merger Agreement, UtiliCorp is offering $29.50 for each share of common stock of the Company, payable in UtiliCorp common stock or cash. The Merger Agreement contains a collar provision under which the value of the Merger consideration per share will decrease if UtiliCorp's common stock is below $22 per share preceding the closing and will increase if UtiliCorp's common stock is above $26 per share preceding the closing. Stockholders of the Company may elect to take cash or stock, but total cash paid to stockholders will be limited to no more than 50% of the total Merger consideration, and the UtiliCorp common stock that may be issued in the Merger is limited to 19.9% of the then outstanding common stock of UtiliCorp. UtiliCorp also will become liable for all of the Company's existing debt, including its first mortgage bonds.
The Merger, which was unanimously approved by the Boards of Directors of the constituent companies, is expected to close after all of the conditions to the consummation of the Merger are met or waived. The Merger is conditioned, among other things, upon approval of stockholders of the Company, approvals of federal regulatory agencies and approvals of state regulatory authorities in states where the combined company will operate. Other conditions in the Merger Agreement require the Company to redeem all of its outstanding preferred stock according to its terms prior to the closing and to obtain the consent of holders of its outstanding first mortgage bonds to a modification of a dividend limitation provision relating to successor corporations which is contained in the Company's indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the "Mortgage"), pursuant to which its first mortgage bonds are issued.
The Company has received the requisite consents to amend the dividend limitation in its Mortgage and has entered into a supplemental indenture in order to implement that amendment. The supplemental indenture will not become effective and no consent fee will be paid, however, until the Merger is completed. On August 2, 1999, the Company redeemed all of its outstanding preferred stock for approximately $34,200,000. In addition, the Company called a special meeting of stockholders on September 3, 1999, for the purpose of voting on the proposed Merger with UtiliCorp. The Merger proposal passed with 76.3% of the Company's outstanding shares being voted in favor of the proposal. UtiliCorp is not required to obtain its stockholders' approval of the Merger.
3. Regulatory Matters
During the three years ending December 31, 1999, the following rate changes were requested or in effect:
Arkansas On February 19, 1998, the Company filed a request with the Arkansas Public Service Commission to increase rates in Arkansas by $618,000 annually. An agreement was reached to stipulate an increase of $359,000 on June 16, 1998, and the Company received an order from the Arkansas Commission on July 21, 1998 approving the stipulated rate increase.
Missouri On August 30, 1996, the Company filed a request with the Missouri Public Service Commission for a general annual increase in rates for its Missouri electric customers of approximately $23,400,000, or 13.8%. A stipulated agreement was filed by the parties for approximately $13,950,000, and on July 17, 1997, the Missouri Commission issued an order approving an annual increase in rates in the amount of approximately $10,600,000, or 6.43% effective July 28, 1997. The amount did not include the Company's investment in Unit No. 2 at the Company's State Line Plant because the Commission deemed that Unit No. 2 did not meet all the specified in-service criteria. On July 25, 1997, the Company filed an Application for Rehearing regarding the status of Unit No. 2, seeking to recover the remaining $3,350,000 of the stipulated agreement. On September 11, 1997, the Missouri Commission issued an order approving an additional annual increase in rates in the amount of $3,000,000, or 1.7% effective September 19, 1997, making the total increase in annual revenue from this proceeding approximately $13,600,000, or 8.25%.
Effects of Regulation In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), the Company's financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over the Company (the MoPSC, the KCC, the OCC, the APSC and the FERC).
Certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to customers. As such, the Company has recorded the following regulatory assets which are expected to result in future revenues as these costs are recovered through the ratemaking process. Historically, all costs of this nature which are determined by the Company's regulators to have been prudently incurred have been recoverable through rates in the course of normal ratemaking procedures and the Company believes that the items detailed below will be afforded similar treatment.
The Company recorded the following regulatory assets and regulatory liability which are being amortized over periods of up to 25 years:
The Company continually assesses the recoverability of its regulatory assets. Under current accounting standards, regulatory assets and liabilities are eliminated through a charge or credit, respectively, to earnings if and when it is no longer probable that such amounts will be recovered through future revenues.
Deregulation If and when retail electric competition legislation is passed in the states the Company serves, the Company may determine that it no longer meets the criteria set forth in SFAS 71 with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require the Company to discontinue application of SFAS 71 based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on the Company's financial condition and results of operations.
In Missouri, the Public Service Commission adopted an order in 1997 establishing a docket and creating a task force on retail electric competition. The Commission Task Force, on which the Company was represented, was charged with preparing a comprehensive report for the Commission on how Missouri could implement retail electric competition. The Joint Committee of the Missouri legislature received testimony during 1997 and 1998. No legislative action was taken in 1999. There is a bill pending in the 2000 Missouri legislature, but no action is expected until 2001. In Kansas, although different bills were introduced into the House and Senate during 1997, no legislative action has been taken.
In Oklahoma, the Electric Restructuring Act of 1997 was passed by the Legislature and signed into law by the Governor. The bill, with a target date of July 1, 2002, was designed to provide for the orderly restructuring of the electric utility industry in the state and move the state toward open competition for electric generation. None of the Company's plant investment or regulatory assets were considered impaired as a result of the bill.
The Arkansas Legislature passed a bill in April 1999 that would deregulate the state's electricity industry as early as January 2002. A special provision however, applies to utilities with a small portion of Arkansas revenues whose majority of revenues are from another state. This provision which applies to the Company exempts the Company from restructuring in Arkansas until restructuring is enacted in Missouri or until January 1, 2004, whichever comes first. The bill would freeze rates for three years for residential and small business customers of utilities, such as the Company, that do not seek to recover stranded costs. This freeze applies only to rate increases and does not apply to any fuel adjustment clause or energy cost recovery rider approved by the Arkansas Commission, such as the one the Company has to recover its fuel and purchased power costs. The bill also requires the unbundling of services on electric bills by June 2000. The Company is currently engaged in the regulatory proceedings that have commenced as a result of the new law. None of the Company's plant investment or regulatory assets were considered impaired as a result of the bill.
4. Common Stock
On August 1, 1998, the Company implemented a new stock unit plan for directors (the Director Retirement Plan) to provide directors the opportunity to accumulate retirement benefits in the form of common stock units in lieu of cash which was how benefits accumulated under the previous cash retirement plan for directors. The new Director Retirement Plan also provided directors the opportunity to convert previously earned cash retirement benefits to common stock units.
100,000 shares are authorized under this new plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for one share of common stock upon retirement by the director. The number of units granted annually is computed by dividing the director's retainer fee by the fair market value of the Company's common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of the Company's stock on the dividend's record date. During 1999, 3,442 units were granted under the Director Retirement Plan and 2,154 units were granted pursuant to the stock incentive plan described below.
The Company's Dividend Reinvestment and Stock Purchase Plan (the Reinvestment Plan) allows common and preferred stockholders to reinvest dividends paid by the Company into newly issued shares of the Company's common stock at 95% of the market price average. Stockholders may also purchase, for cash and within specified limits, additional stock at 100% of the market price average. The Company may elect to make shares purchased in the open market rather than newly issued shares available for purchase under the Reinvestment Plan. If the Company so elects, the purchase price to be paid by Reinvestment Plan participants will be 100% of the cost to the Company of such shares. Participants in the Reinvestment Plan do not pay commissions or service charges in connection with purchases under the Reinvestment Plan.
The Company's Employee Stock Purchase Plan, which terminates on May 31, 2000, permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. Contingent employee stock purchase subscriptions outstanding and the maximum prices per share were 63,985 shares at $23.35, 50,368 shares at $18.34 and 58,972 shares at $15.53 on December 31, 1999, 1998 and 1997, respectively. Shares were issued at $18.34 per share in 1999, $15.53 per share in 1998, and $15.64 per share in 1997. The Company is in the process of amending the Employee Stock Purchase Plan in order to extend the termination date to May 31, 2003.
The Company's 1996 Incentive Plan (the Stock Incentive Plan) provides for the grant of up to 650,000 shares of common stock through January 2006. The terms and conditions of any option or stock grant are determined by the Board of Directors' Compensation Committee, within the provisions of the Stock Incentive Plan. The Stock Incentive Plan permits grants of stock options and restricted stock to qualified employees and permits Directors to receive common stock in lieu of cash compensation for service as a Director.
During February 1999 and January 1998 and 1997, grants for 1,144, 1,535 and 1,414 shares, respectively, of restricted stock were made to qualified employees under the Stock Incentive Plan. For grants made to date, the restrictions typically lapse and the shares are issuable to employees who continue service with the Company three years from the date of grant. For employees whose service is terminated by death, retirement, disability, or under certain circumstances following a change in control of the Company prior to the restrictions lapsing, the shares are issuable immediately. For other terminations, the grant is forfeited. During 1999, 1998 and 1997, 3,300, 2,641 and 3,983 shares, respectively, were issued under the Stock Incentive Plan. No options have been granted under the Stock Incentive Plan. In 1996, the Company adopted the disclosure-only method under SFAS 123, "Accounting for Stock-Based Compensation." If the fair value based accounting method under this statement had been used to account for stock-based compensation costs, the effect on 1999 and 1998 net income and earnings per share would have been immaterial.
The Company's Employee 401(k) Retirement Plan (the 401(k) Plan) allows participating employees to defer up to 15% of their annual compensation up to a specified limit. The Company matches 50% of each employee's deferrals by contributing shares of the Company's common stock, such matching contributions not to exceed 3% of the employee's
annual compensation. The Company contributed 30,919, 32,274 and 36,978 shares of common stock in 1999, 1998 and 1997, respectively, valued at market prices on the dates of contributions. The stock issuances to effect the contributions were not cash transactions and are not reflected as a source of cash in the Statement of Cash Flows.
At December 31, 1999, 1,294,062 shares remain available for issuance under the foregoing plans.
5. Preferred Stock
The Company has 2,500,000 shares of preference stock authorized, including 500,000 shares of Series A Participating Preference Stock, none of which have been issued.
The Company has 5,000,000 shares of $10.00 par value cumulative preferred stock authorized. Of this amount, preferred stock without mandatory redemption provisions issued and outstanding at December 31, 1999 and 1998 is as follows:
On August 2, 1999 the Company redeemed all outstanding 5%, 4 3/4%, and 8 1/8% series of cumulative preferred stock. Holders were paid the following amounts per share plus accumulated and unpaid dividends: 5% cumulative - $10.50 (aggregate amount $4,009,110); 4 3/4% cumulative - $10.20 (aggregate amount $4,080,000); and 8 1/8 cumulative - $10 (aggregate amount $24,809,980).
Preference Stock Purchase Rights The Company had 8,663,648 and 8,535,918 Preference Stock Purchase Rights (Rights) outstanding at December 31, 1999 and 1998, respectively. Each Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one one-hundredth share, subject to adjustment. Each share of common stock currently has one-half of one Right. The Rights (other than those held by an acquiring person or group (Acquiring Person)), which expire July 25, 2000, will be exercisable only if an Acquiring Person acquires 10% or more of the Company's common stock or announces an intention to make a tender offer or exchange offer which would result in the Acquiring Person owning 10% or more of the common stock. The Rights may be redeemed by the Company in whole, but not in part, for $0.01 per Right, prior to 10 days after the first public announcement of the acquisition of 10% or more of the Company's common stock by an Acquiring Person.
In addition, upon the occurrence of a merger or other business combination, or an event of the type described in the preceding paragraph, holders of the Rights, other than an Acquiring Person, will be entitled, upon exercise of a Right, to receive either common stock of the Company or common stock of the Acquiring Person having a value equal to two times the exercise price of the Right. Any time after an Acquiring Person acquires 10% or more (but less than 50%) of the
Company's outstanding common stock, the Board of Directors may, at its option, exchange part or all of the Rights (other than Rights held by the Acquiring Person) for common stock of the Company on a one-for-two basis. The provisions of the Rights were amended in 1999 to exclude the pending merger with UtiliCorp United, Inc.
6. Long-term Debt
The principal amount of all series of first mortgage bonds outstanding at any one time is limited by terms of the mortgage to $1,000,000,000. Substantially all property, plant and equipment is subject to the lien of the mortgage. At December 31, 1999 the long-term debt outstanding was as follows:
(1) Holders of this series have the right to require the Company to repurchase all or any portion of the bonds at a price of 100% of the principal amount plus accrued interest, if any, on November 1, 2001.
The carrying amount of the Company's long-term debt was $346,566,000 and $246,676,000 at December 31, 1999 and 1998, respectively, and its fair market value was estimated to be approximately $329,118,000 and $252,155,000, respectively. This estimate was based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturation. The estimated fair market value may not represent the actual value that could have been realized as of year-end or that will be realizable in the future.
At December 31, 1999, the Company had a $50,000,000 unsecured line of credit. Borrowings are at the bank's prime commercial rate and are due 370 days from the date of each loan. The Company also had a $25,000,000 unsecured line of credit at December 31, 1999, bearing interest at 30-day LIBOR plus .75%. This unsecured line of credit expired on January 31, 2000. These arrangements do not serve to legally restrict the use of the Company's cash. The lines of credit are also utilized to support the Company's issuance of commercial paper although they are not assigned specifically
to such support. There were no outstanding borrowings under these agreements at December 31, 1999 or 1998.
On November 18, 1999, the Company sold to the public in an underwritten offering $100 million aggregate principal amount of its Senior Notes, 7.70% Series due 2004. The net proceeds of this sale were added to the Company's general funds and were used to repay short-term indebtedness, including indebtedness incurred in connection with the redemption of the Company's preferred stock and the Company's construction program.
On April 28, 1998, the Company sold to the public in an underwritten offering $50 million aggregate principal amount of its First Mortgage Bonds, 6.50% Series due 2010. The net proceeds from this sale were added to the Company's general funds and were used to repay $23 million of the Company's First Mortgage Bonds, 5.70% Series due May 1, 1999 and to repay short-term indebtedness, including indebtedness incurred in connection with the Company's construction program.
7. Short-term Borrowings
Short-term commercial paper outstanding and notes payable averaged $30,796,000 and $11,274,000 daily during 1999 and 1998, respectively, with the highest month-end balances being $65,000,000 and $28,500,000, respectively. The weighted daily average interest rates during 1999, 1998 and 1997 were 5.4%, 5.9% and 5.9%, respectively. The weighted average interest rates of borrowings outstanding at December 31, 1999 and 1998 were, 6.12% and 6.2%, respectively.
8. Retirement Benefits
Pensions In 1998, the Company adopted Statement of Financial Accounting Standards (SFAS) 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," which resulted in revisions to the 1997 information previously reported.
The Company's noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. The benefits are based on years of service and the employee's average annual basic earnings. Annual contributions to the plan are at least equal to the minimum funding requirements of ERISA. Plan assets consist of common stocks, United States government obligations, federal agency bonds, corporate bonds and commingled trust funds.
The following table sets forth the plan's projected benefit obligation, the fair value of the plan's assets and its funded status:
Assumptions used in calculating the projected benefit obligation for 1999 and 1998 include the following:
Net pension benefit for 1999, 1998 and 1997 is comprised of the following components:
Other Postretirement Benefits The Company provides certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service.
Effective January 1, 1993, the Company adopted SFAS 106, which requires recognition of these benefits on an accrual basis during the active service period of the employees. The Company elected to amortize its transition obligation (approximately $21,700,000) related to SFAS 106 over a twenty year period. Prior to adoption of SFAS 106, the Company recognized the cost of such postretirement benefits on a pay- as-you-go (i.e., cash) basis. The states of Missouri, Kansas, Oklahoma, and Arkansas authorize the recovery of SFAS 106 costs through rates.
In accordance with the above rate orders, the Company established two separate trusts in 1994, one for those retirees who were subject to a collectively bargained agreement and the other for all other retirees, to fund retiree healthcare and life insurance benefits. The Company's funding policy is to contribute annually an amount at least equal to the revenues collected for the amount of postretirement benefits costs allowed in rates. Assets in these trusts amounted to approximately $10,600,000 at December 31, 1999 and $6,800,000 at December 31, 1998. Postretirement benefits, a portion of which have been capitalized and/or deferred, for 1999, 1998 and 1997 included the following components:
The estimated funded status of the Company's obligations under SFAS 106 at December 31, 1999, 1998 and 1997 using a weighted average discount rate of 8.0%, 7.0% and 6.75%, respectively, is as follows:
9. Income Taxes
The provision for income taxes is different from the amount of income tax determined by applying the statutory income tax rate to income before income taxes as a result of the following differences:
Income tax expense components for the years shown are as follows:
Under SFAS 109, temporary differences gave rise to deferred tax assets and deferred tax liabilities at year end 1999 and 1998 as follows:
10. Commonly Owned Facilities
The Company owns a 12% undivided interest in the Iatan Power Plant, a coal-fired 670 megawatt generating unit near Weston, Missouri. The Company is entitled to 12% of the available capacity and is obligated for that percentage of costs which are included in corresponding operating expense classifications in the Statement of Income. At December 31, 1999 and 1998, the Company's property, plant and equipment accounts include the cost of its ownership interest in the unit of $44,656,000 and $44,628,000, respectively, and accumulated depreciation of $28,689,000 and $27,045,000, respectively.
On July 26, 1999, the Company and Westar Generating, Inc. ("WGI"), a subsidiary of Western Resources, Inc., entered into agreements for the construction, ownership and operation of a 500-megawatt combined cycle unit at the State Line Power Plant (the "State Line Combined Cycle Unit"). Work has begun and the State Line Combined Cycle Unit is projected to be operational by June 2001. The Company will own an undivided 60% interest in the State Line Combined Cycle Unit with WGI owning the remainder. The Company is entitled to 60% of the capacity of the State Line Combined Cycle Unit. The Company will contribute its existing 152-megawatt State Line Unit No. 2 combustion turbine to the State Line Combined Cycle Unit, and as a result, upon commercial operation, the State Line Combined Cycle Unit will provide the Company with approximately 150 megawatts of additional capacity. The total cost of the State Line Combined Cycle Unit is estimated to be $185,000,000. The Company's share of this amount,
after the transfer to WGI of an undivided 40% joint ownership interest in the existing State Line Unit No. 2 and certain other property at book value, is expected to be approximately $100,000,000. The Company and WGI are responsible for their own financing of the project and the Company is billing WGI for its share of monthly construction costs as well as advance payments for WGI's share of the existing State Line Unit No. 2 combustion turbine.
11. Commitments and Contingencies
The Company's 2000 construction budget is $105,720,000. The Company's five-year construction program for 2000 through 2004 is estimated to be approximately $319,555,000.
The Company has entered into long-term agreements to purchase capacity and energy, to obtain supplies of coal and to provide natural gas transportation. Under such contracts, the Company incurred purchased power and fuel costs of approximately $50,000,000, $64,000,000 and $55,000,000 in 1999, 1998 and 1997, respectively. Certain of these contracts provide for minimum and maximum annual amounts to be purchased and further provide, in part, for cash settlements to be made when minimum amounts are not purchased. In the event that no purchases of coal, energy and transportation services are made, an event considered unlikely by management, minimum annual cash settlements would approximate $32,000,000 in 2000, $30,000,000 in 2001, $26,000,000 in 2002 and 24,000,000 in 2003 and reducing to lesser amounts thereafter through 2012.
12. Selected Quarterly Information (Unaudited)
A summary of operations for the quarterly periods of 1999 and 1998 is as follows:
The sum of the quarterly earnings per average share of common stock may not equal the earnings per average share of common stock as computed on an annual basis due to rounding.
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 required by this Item with respect to directors and directorships and with respect to Section 16(a) Beneficial Ownership Reporting Compliance may be found in the Company's proxy statement for its Annual Meeting of Stockholders to be held April 27, 2000, which is incorporated herein by reference. Pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, the information required by this Item with respect to executive officers is set forth in Item 1 of Part I of this Form 10-K under "Executive Officers and Other Officers of the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation may be found in the Company's proxy statement for its Annual Meeting of Stockholders to be held April 27, 2000, which is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the number of shares of the Company's equity securities beneficially owned by the directors and certain executive officers of the Company and by the directors and executive officers as a group may be found in the Company's proxy statement for its Annual Meeting of Stockholders to be held April 27, 2000, which is incorporated herein by reference. To the knowledge of the Company, no person is the beneficial owner of 5% or more of any class of the Company's voting securities, and there are no arrangements the operation of which may at a subsequent date result in a change in control of the Company.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item with respect to certain relationships and related transactions may be found in the Company's proxy statement for its Annual Meeting of Stockholders to be held April 27, 2000, which is incorporated herein by reference. PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Index to Financial Statements and Financial Statement Schedule Covered by Report of Independent Auditors
Balance sheets at December 31, 1999 and 1998 24 Statements of income for each of the three years in the period 25 ended December 31, 1999 Statements of common stockholders' equity for each of the three years in the period ended December 31, 26 Statements of cash flows for each of the three years in the 27 period ended December 31, 1999 Notes to financial statements 28 Schedule for the years ended December 31, 1999, 1998 and 1997: Schedule II - Valuation and qualifying accounts 46
All other schedules are omitted as the required information is either not present, is not present in sufficient amounts, or the information required therein is included in the financial statements or notes thereto.
List of Exhibits (2) - Agreement and Plan of Merger, dated as of May 10, 1999, by and between the Company and UtiliCorp United Inc. (Incorporated by reference to Exhibit 2 to Form 10-Q for quarter ended March 31, 1999, File No.1-3368). (3) (a) - The Restated Articles of Incorporation of the Company (Incorporated by reference to Exhibit 4(a) to Form S-3, File No. 33-54539). (b) - By-laws of Company as amended January 23, 1992 (Incorporated by reference to Exhibit 3(f) to Annual Report Form 10-K for year ended December 31, 1991, File No. 1-3368). (4) (a) - Indenture of Mortgage and Deed of Trust dated as of September 1, 1944 and First Supplemental Indenture thereto (Incorporated by reference to Exhibits B(1) and B(2) to Form 10, File No. 1-3368). (b) - Third Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924). (c) - Sixth through Eighth Supplemental Indentures to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924). (d) - Fourteenth Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(f) to Form S-3, File No. 33-56635). (e) - Seventeenth Supplemental Indenture dated as of December 1, 1990 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(j) to Annual Report on Form 10-K for year ended December 31, 1990, File No. 1- 3368). (f) - Eighteenth Supplemental Indenture dated as of July 1, 1992 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended June 30, 1992, File No. 1-3368). (g) - Twentieth Supplemental Indenture dated as of June 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Form S-3, File No. 33-66748). (h) - Twenty-First Supplemental Indenture dated as of October 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended September 30, 1993, File No. 1-3368).
(i) - Twenty-Second Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(k) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1- 3368). (j) - Twenty-Third Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(l) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1- 3368). (k) - Twenty-Fourth Supplemental Indenture dated as of March 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1- 3368). (l) - Twenty-Fifth Supplemental Indenture dated as of November 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(p) to Form S-3, File No. 33-56635). (m) - Twenty-Sixth Supplemental Indenture dated as of April 1, 1995 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1995, File No. 1-3368). (n) - Twenty-Seventh Supplemental Indenture dated as of June 1, 1995 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended June 30, 1995, File No. 1-3368). (o) - Twenty-Eighth Supplemental Indenture dated as of December 1, 1996 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Annual Report on Form 10-K for year ended December 31, 1996, File No. 1- 3368). (p) Twenty-Ninth Supplemental Indenture dated as of April 1, 1998 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1998, File No. 1-3368). (q) Thirtieth Supplemental Indenture dated as of July 1, 1999 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 (a) to Form 10-Q for quarter ended June 30, 1999, File No. 1-3368). (r) - Rights Agreement dated July 26, 1990 (Incorporated by reference to Exhibit 4(a) to Form 8-K, dated July 26, 1990, File No. 1-3368). (s) - Amendment #1 to Rights Agreement dated October 24, 1991 between the Company and Chemical Bank (successor to Manufacturers Hanover Trust Company), as Rights Agent (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended September 30, 1991, File No. 1-3368). (t) - Amendment #2 to Rights Agreement dated May 10, 1999 (Incorporated by reference to Exhibit 4(b) to Form 10-Q for quarter ended June 30, 1999, File No. 1-3368). (10)(a) - 1996 Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to Form S-8, File No. 33-64639). (b) - Management Incentive Plan (A description of this Plan is incorporated by reference to page 5 of the Company's Proxy Statement for its Annual Meeting of Stockholders held April 27, 1989). (c) - Deferred Compensation Plan for Directors (Incorporated by reference to Exhibit 10(d) to Annual Report on Form 10-K for year ended December 31, 1990, File No. 1-3368). (d) - The Empire District Electric Company Change in Control Severance Pay Plan and Forms of Agreement (Incorporated by reference to Exhibit 10 to Form 10-Q for quarter ended September 30, 1991, File No. 1-3368). (e) - Amendment to The Empire District Electric Company Change in Control Severance Pay Plan and revised Forms of Agreement (Incorporated by reference to Exhibit 10 to Form 10-Q for quarter ended June 30, 1996, File No. 1-3368). (f) - The Empire District Electric Company Supplemental Executive Retirement Plan. (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for year ended December 31, 1994, File No. 1-3368). (g) Retirement Plan for Directors as amended August 1, 1998 (Incorporated by reference to Exhibit 10(a) to Form Q for quarter ended September 30, 1998, File No. 1-3368).
(h) Stock Unit Plan for Directors (Incorporated by reference to Exhibit 10(b) to Form Q for quarter ended September 30, 1998, File No. 1-3368).
(12) - Computation of Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements.* (23) - Consent of PricewaterhouseCoopers LLP*
(24) - Powers of Attorney.*
(27) - Financial Data Schedule for December 31, 1999.
This exhibit is a compensatory plan or arrangement as contemplated by Item 14(a)(3) of Form 10-K. *Filed herewith.
Reports on Form 8-K
No reports on Form 8-K were filed during the fourth quarter of 1999.
SCHEDULE II Valuation and Qualifying Accounts
Years ended December 31, 1999, 1998 and 1997 Balance Additions Deductions Balance At Charged to Other Accounts from reserve at Beginning close of of Charged to period period Income Description Amount Description Amount
Year ended December 31, 1999: Reserve deducted Recovery of from assets: amounts Accumulated previously Accounts provision for written written Uncollectible $ 275,876 $ 580,873 off $ 372,955 off $ 857,758 $ 371,946 accounts Reserve not shown separately in balance sheet: Property, plant Injuries and & equipment and Claims damages Reserve clearing accounts and (Note A) $1,314,461 $407,163 $ 407,163 expenses $1,128,787 $1,000,000
Year ended December 31, 1998: Reserve deducted Recovery of from assets: amounts Accumulated previously Accounts provision for written written Uncollectible $ 278,741 $586,000 off $ 448,718 off $1,037,583 $ 275,876 accounts Reserve not shown separately in balance sheet: Property, plant Claims Injuries and & equipment and and damages Reserve clearing accounts expenses (Note A) $1,311,995 $580,832 $ 530,011 $1,108,377 $1,314,461
Year ended December 31, 1997: Reserve deducted Recovery of from assets: amounts Accumulated previously Accounts provision for written written Uncollectibl $ 265,390 $486,000 off $332,632 off $ 805,281 $ 278,741 accounts Reserve not shown separately in Balance sheet: Property, plant Claims Injuries and & equipment and and damages Reserve clearing accounts expenses (Note A) $1,300,917 $484,541 $472,107 $ 945,570 $1,311,995
NOTE A: This reserve is provided for workers' compensation, certain postemployment benefits and public liability damages. The Company at December 31, 1999 carried insurance for workers' compensation claims in excess of $250,000 and for public liability claims in excess of $300,000. The injuries and damages reserve is included on the Balance Sheet in the section "Noncurrent liabilities and deferred credits" in the category "Other".
SIGNATURES
Pursuant to the requirements of Section 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.
THE EMPIRE DISTRICT ELECTRIC COMPANY
M. W. MCKINNEY By.............................
M.W. McKinney, President
Date: March 21, 2000
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 date indicated.
Date
M. W. MCKINNEY
M. W. McKinney, President and Director (Principal Executive Officer)
R. B. FANCHER
R. B. Fancher, Vice President-Finance (Principal Financial Officer)
G. A. KNAPP
G. A. Knapp, Controller and Assistant Treasurer (Principal Accounting Officer)
V. E. BRILL
V. E. Brill, Vice President-Energy Supply and Director
M. F. CHUBB, JR.*
M. F. Chubb, Jr., Director
R. D. HAMMONS*
R. D. Hammons, Director
March 21, 2000 R. C. HARTLEY*
R. C. Hartley, Director
J. R. HERSCHEND*
J. R. Herschend, Director
F. E. JEFFRIES*
F. E. Jeffries, Director
R. E. MAYES*
R. E. Mayes, Director
R. L. LAMB*
R. L. Lamb, Director
M. M. POSNER*
M. M. Posner, Director
R. B. FANCHER *By (R. B. Fancher, As attorney in fact for each of the persons indicated)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MERGER WITH UTILICORP
The Company and UtiliCorp United Inc., a Delaware corporation ("UtiliCorp"), have entered into an Agreement and Plan of Merger, dated as of May 10, 1999 (the "Merger Agreement"), which provides for a merger of the Company with and into UtiliCorp, with UtiliCorp being the surviving corporation (the "Merger"). Under the terms of the Merger Agreement, UtiliCorp will pay $29.50 for each share of common stock of the Company, payable in UtiliCorp common stock or cash. The Merger Agreement contains a collar provision under which the value of the merger consideration per share will decrease if UtiliCorp's common stock is below $22 per share preceding the closing and will increase if UtiliCorp's common stock is above $26 per share preceding the closing. The average trading price of UtiliCorp's common stock price will be used to determine the merger consideration and will be calculated based on the closing prices on the NYSE during the 20 trading days ending on the third trading day prior to the closing date of the Merger. If the average trading price is below $22, UtiliCorp will pay 1.342 times the average trading price for each share of Company common stock and if the average trading price is above $26, UtiliCorp will pay 1.135 times the average trading price for each share of Company common stock. For example, if the Merger had closed on March 6, 2000, the average trading price for UtiliCorp's common stock would have been $17.5656 per share, resulting in the payment of $23.5513 for each share of the Company's common stock. Stockholders of the Company may elect to take cash or stock, but total cash paid to stockholders will be limited to no more than 50% of the total Merger consideration, and the number of shares of UtiliCorp common stock that may be issued in the Merger is limited to 19.9% of the number of then outstanding shares of common stock of UtiliCorp. UtiliCorp also will become liable for all of the Company's existing debt, including its first mortgage bonds. See Note 2 of "Notes to Financial Statements" under Item 8 for further information. The Merger, which was unanimously approved by the Boards of Directors of the constituent companies, is expected to close after all of the conditions to the consummation of the Merger are met or waived. The Merger is conditioned, among other things, upon approvals of federal regulatory agencies and approvals of state regulatory authorities in states where the combined company will operate. At a special meeting of stockholders held on September 3, 1999, the Merger was approved with 76.3% of the Company's outstanding shares voting in favor of the proposal. UtiliCorp is not required to obtain its stockholders' approval of the Merger. The Company and UtiliCorp filed joint applications with the FERC on November 23, 1999 and the Missouri Commission on December 14, 1999 requesting approval of the merger. Applications to merge were filed with the Arkansas Public Service Commission on January 28, 2000 and with the Kansas Corporation Commission and Oklahoma Corporation Commission on January 31, 2000. The applications set forth a proposed Regulatory Plan (the "Plan") which would result in a five-year rate moratorium following the conclusion of a rate case the Company plans to file in the second half of 2000. This rate case is designed to recover the costs associated with the Company's State Line Project anticipated to be operational by June 2001. The Plan also calls for UtiliCorp to keep any savings generated by the Merger to offset the acquisition premium. UtiliCorp may file a rate case at the end of the five-year rate moratorium allowing UtiliCorp to include one half of any unamortized acquisition premium in the rate base, thus allowing it to be recovered in rates. The Missouri Commission has scheduled hearing dates for the Merger proposal for September 11-15, 2000 in Jefferson City, Missouri, which means a ruling could be issued by that Commission before the end of this year. UtiliCorp is a multinational energy and energy services company headquartered in Kansas City, Missouri. It has regulated utility operations in eight states and energy operations in New Zealand, Australia, the United Kingdom and Canada. It also owns non-utility subsidiaries involved in energy trading; natural gas gathering, processing and transportation; energy efficiency services and various other energy-related businesses. For more information on the Merger, see the Company's proxy statement for its special meeting of stockholders held on September 3, 1999, which is dated August 2, 1999.
RESULTS OF OPERATIONS The following discussion analyzes significant changes in the results of operations for the year ended December 31, 1999, compared to the year ended December 31, 1998, and for the year ended December 31, 1998, compared to the year ended December 31, 1997.
Operating Revenues and Kilowatt-Hour Sales Of the Company's total electric operating revenues during 1999, approximately 41% were from residential customers, 31% from commercial customers, 17% from industrial customers, 4% from wholesale on-system customers and 3% from wholesale off-system transactions. The remainder of such revenues were derived from miscellaneous sources. The percentage changes from the prior year in kilowatt-hour ("Kwh") sales and revenue by major customer class were as follows:
Kwh sales for the Company's on-system customers increased slightly during 1999 while revenues increased slightly more than the corresponding increase in Kwh sales. Customer growth increased slightly in 1999 over the 1.8% growth rate in 1998. Despite above-average temperatures in July and August, residential Kwh sales decreased 2.6% with revenues decreasing 1.8% as compared to 1998. This decrease was primarily due to unusually mild temperatures during the second quarter of 1999, as well as in September, November and December, and the unusually warm second and third quarters of 1998. Commercial and industrial classes showed an increase in Kwh sales and revenues due to continued increases in business activity throughout the Company's service territory. On-system wholesale Kwh sales were down slightly in 1999, reflecting the mild temperatures discussed above. Revenues associated with these sales decreased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause applicable to such FERC regulated sales. This clause permits the pass through to customers of changes in fuel and purchased power costs. Kwh sales for the Company's on-system customers increased during 1998 primarily due to above-average temperatures during the second and third quarters. Revenues increased more than the corresponding increase in Kwh sales primarily due to increased rates in Missouri and Arkansas as reflected in the table below and the winter/summer differential in rates. This differential results from summer rates being higher than winter rates, so warm summer temperatures that increase summer Kwh usage cause the corresponding annual revenues to increase at a greater rate than the annual Kwhs. Revenues and Kwh sales were also positively impacted by $1.7 million (0.1%),and 32 million Kwhs (0.8%) respectively, as a result of a change in the estimation of periodic loss factors used to calculate unbilled revenues. Customer growth increased slightly to 1.8% in 1998 as compared to 1.7% in 1997. Residential and commercial Kwh sales increased as compared to 1997, primarily due to the above-average temperatures discussed above. Industrial classes, although not particularly weather-sensitive, also showed an increase in Kwh sales and revenues due to continued increases in business activity throughout the Company's service territory. On-system wholesale Kwh sales were up significantly in 1998, reflecting the warm summer temperatures and continued increases in business activity discussed above. Revenues associated with these sales increased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause. The following table sets forth information regarding electric rate increases affecting the revenue comparisons discussed above:
In addition to sales to its own customers, the Company sells power to other utilities as available and provides transmission service through its system for transactions between other energy suppliers. During 1999 revenues from such off-system transactions were approximately $9.6 million as compared to approximately $8.3 million in 1998 and approximately $7.6 million during 1997. The increase in revenues during 1999 was primarily the result of an increase in firm capacity charges as well as an increase in sales resulting from the ability to sell power at market-based rates. Pursuant to orders issued by the FERC and subsequent tariffs filed by the Company and SPP, these off-system sales have been opened up to competition. See "- Competition" below for more information. The Company's future revenues from the sale of electricity will continue to be affected by economic conditions, business activities, competition, weather, regulation, the utilities' change from a regulated to a competitive environment, changes in electric rate levels and changing patterns of electric energy use by customers. Inflation affects the Company's operations in that historical costs rather than current replacement costs are recovered in the Company's rates.
Operating Revenue Deductions During 1999, total operating expenses increased approximately $6.1 million (5.1%) compared to the prior year. Merger related expenses, which are not tax deductible, contributed $5.8 million to this increase. A significant portion of these expenses include payments to the Company's financial advisors for the first and second portions of the agreed upon transaction fee for their financial services in connection with the merger. This agreement calls for payment of 25% of the transaction fee upon execution of the merger agreement, 25% upon stockholder approval of the merger and the remaining 50% upon the consummation of the merger, payable upon closing. Including the final payment to be made under this agreement, remaining merger costs are expected to total approximately $11 million. Total purchased power costs decreased by approximately $2.9 million (6.0%) during 1999, primarily due to increased availability of the Company's generating units. The Asbury Plant set a new continuous run record of 190 days in 1999. Total fuel costs were up approximately $3.4 million (8.1%) during 1999 as compared to the same period in 1998 primarily reflecting the increased generation from the higher-cost gas turbines at the State Line Power Plant. The hot temperatures in July and August resulted in a significant increase in the price of purchased power, making it more economical for the Company to run its gas turbines during those months. In addition, natural gas prices were higher by 1.5% during 1999 as compared to 1998, contributing to the increase. Other operating expenses decreased slightly by approximately $0.1 million (0.4%) during 1999, compared to 1998. Maintenance and repairs expense decreased approximately $1.2 million (6.7%) during 1999 primarily due to decreased maintenance costs at Asbury and Riverton. The Riverton Plant had a five-year scheduled maintenance outage in 1998. These decreases offset maintenance and repairs expense resulting from a New Year's Day ice storm that interrupted service to approximately 35,000 of the Company's Missouri and Kansas customers over a three day period. Depreciation and amortization expense increased approximately $1.4 million (5.6%) during 1999, compared to 1998, due to increased levels of plant and equipment placed in service. Total income taxes decreased approximately $0.3 million (2.0%) during 1999 due primarily to lower taxable income during the current year. See Note 9 of "Notes to Financial Statements" under Item 8 for additional information regarding income taxes. Other taxes were up approximately $1.1 million (8.8%) during the year largely as a result of increased property taxes.
During 1998, total operating expenses increased approximately $7.5 million (6.6%) compared to the prior year. Total fuel costs were up approximately $5.8 million (16.0%) during 1998, due primarily to the increased generation from gas-fired combustion turbine units at both State Line and the Energy Center. This increased generation was due to increased customer demand in the second and third quarters of 1998 resulting from the warmer temperatures. Natural gas prices were lower by 3.0% during 1998 as compared to 1997, helping to offset some of the additional expense. Total purchased power costs increased slightly by approximately $0.4 million (0.9%) during 1998. Other operating expenses increased approximately $1.3 million (4.3%) during 1998, compared to 1997, due primarily to increases in customer accounts expense and administrative and general expense. Approximately $0.7 million of this increase was a one- time charge due to the initiation of the Directors Stock Unit Plan, a stock-based retirement compensation program for the Company's Directors. Maintenance and repairs expense increased approximately $4.7 million (36.4%) during 1998. Scheduled maintenance on combustion turbines at the Energy Center and the State Line Power Plant accounted for approximately $2.8 million of this increase while approximately $1.1 million can be attributed to the first quarter spring maintenance outage at the Asbury Plant and the second quarter five-year scheduled maintenance outage at the Riverton Plant. Transmission and distribution system maintenance contributed $0.8 million to the increase. Depreciation and amortization expense increased approximately $1.6 million (6.8%) during 1998, compared to 1997, due to increased levels of plant and equipment placed in service. Total income taxes increased approximately $3.2 million (24.5%) during 1998 due primarily to higher taxable income during the current year. See Note 9 of "Notes to Financial Statements" under Item 8 for additional information regarding income taxes. Other taxes were up approximately $1.2 million (10.3%) during the year largely as a result of increased property taxes and city taxes.
Nonoperating Items Total allowance for funds used during construction ("AFUDC") amounted to approximately 6.1% of earnings applicable to common stock during 1999, 1.6% during 1998, and 5.7% during 1997. AFUDC increased significantly during 1999 reflecting higher levels of construction work in progress related to the State Line Project. AFUDC decreased significantly during 1998 reflecting lower levels of construction work in progress due mainly to the completion of State Line Unit No. 2 in June 1997. See Note 1 of "Notes to Financial Statements" under Item 8. Interest charges on long-term debt increased in both 1999 and 1998 due to the issuance of $100 million of the Company's unsecured Senior Notes in November 1999 and $50 million of the Company's First Mortgage Bonds in April 1998. The proceeds from the Senior Notes were added to the Company's general funds and were used to repay short-term indebtedness, including approximately $33.1 million in commercial paper incurred in connection with the Company's preferred stock redemption on August 2, 1999, as well as that incurred in connection with the Company's construction program. The proceeds from the Company's First Mortgage Bonds were added to the Company's general funds and were used to repay $23 million of the Company's First Mortgage Bonds due May 1, 1998 and to repay short-term indebtedness, including that incurred in connection with the Company's construction program. Commercial paper interest increased $1.0 million (153.6%) during 1999 due to increased usage of short-term debt for financing purposes, particularly in connection with the Company's preferred stock redemption. Interest income for that year also increased, reflecting the higher balances of cash available for investment.
Earnings Basic and diluted earnings per weighted average share of common stock were $1.13 during 1999 compared to $1.53 in 1998. Earnings per share were down primarily due to the $5.8 million in merger costs incurred during 1999, as well as the $1.3 million in excess consideration paid on redemption of the Company's preferred stock. Earnings for 1999 were also negatively impacted by mild temperatures and increased interest expense. Excluding the $5.8 million in merger costs, earnings per share would have been $1.46. Earnings per share of common stock were $1.53 during 1998 compared to $1.29 in 1997. Increased revenue resulted mainly from the unusually warm second and third quarters of 1998. The 1998 Arkansas rate increase and the 1997 Missouri rate increase also favorably impacted the Company's operating results in 1998, as the
Missouri jurisdiction accounts for approximately 90% of the on- system retail sales of the Company.
Competition
Federal regulation, such as The National Energy Policy Act of 1992 (the "Energy Act") has promoted and is expected to continue to promote competition in the electric utility industry. The Energy Act, among other things, eases restrictions on independent power producers, delegates authority to the FERC to order wholesale wheeling and grants individual states the power to order retail wheeling. At this time, Oklahoma and Arkansas are the only states in which the Company operates that have taken any such action. In Missouri, the Public Service Commission adopted an order in 1997 establishing a docket and creating a task force on retail electric competition. The Commission Task Force, on which the Company was represented, was charged with preparing a comprehensive report for the Commission on how Missouri could implement retail electric competition. The Joint Committee of the Missouri Legislature received testimony during 1997 and 1998. No legislative action was taken in 1999. There are bills pending in the 2000 Missouri Legislature, but no action is expected this year. In Kansas, although different bills have been introduced into the House and Senate, no legislative action has been taken. In Oklahoma, the Electric Restructuring Act of 1997 was passed by the Legislature and signed into law by the Governor. The bill, with a target date of July 1, 2002, was designed to provide for the orderly restructuring of the electric utility industry in the state and move the state toward open competition for electric generation. An Electric Utility Task Force has been studying all issues in Oklahoma and has prepared legislation to provide a more comprehensive framework for the transition to retail open access. That legislation is under consideration by the Oklahoma General Assembly. Approximately 3.1% of the Company's 1999 operating revenue was derived from sales subject to Oklahoma regulation. The Arkansas Legislature passed a bill in April 1999 that would deregulate the state's electricity industry as early as January 2002. A special provision, however, applies to utilities with a small portion of Arkansas customers whose majority of customers are from another state. This provision, which applies to the Company, exempts the Company from restructuring in Arkansas until restructuring is enacted in Missouri or until January 1, 2004, whichever comes first. The bill would freeze rates for three years for residential and small business customers of utilities that seek to recover stranded costs, and freeze rates for one year for residential and small business customers of utilities, such as the Company, that do not seek to recover stranded costs. This freeze applies only to rate increases and does not apply to any fuel adjustment clause or energy cost recovery rider approved by the Arkansas Commission, such as the one the Company has to recover its fuel and purchased power costs. The bill also requires the unbundling of services on electric bills by June 2000. The Company is currently engaged in the regulatory proceedings that have commenced as a result of the new law. Approximately 2.6% of the Company's 1999 operating revenue was derived from sales subject to Arkansas regulation. In April 1996, the FERC issued Order No. 888 ("Order 888") which required all electric utilities that own, operate, or control interstate transmission facilities to file open access tariffs that offer all wholesale buyers and sellers of electricity the same transmission services that they provide themselves. The utility would have to take service under those tariffs for its own wholesale power transactions. Order 888 required a functional unbundling of transmission and power marketing services. The Company and the SPP have filed open access transmission tariffs covering these wholesale transmission services. The SPP tariff applies to most of the transmission services for which the Company tariff was designed. Where that is the case, the Company shares revenues received from such transmission services with other members of the SPP based on a megawatt mile method of calculating transmission service charges. There are, however, limited circumstances where the Company tariff still applies and the Company receives 100% of the revenues from the transmission services. The SPP tariff will continue to apply unless and until a new tariff is filed as part of any regional transmission organization ("RTO") which the Company may join as discussed below. On December 15, 1999, the FERC issued Order No. 2000 ("Order 2000"), which encourages the development of RTOs. RTOs are designed to control the wholesale transmission services of the utilities in its region. Order 2000 is intended to continue the process of promoting open and more competitive markets in bulk power sales of electricity that was begun with Order 888. On
December 30, 1999, SPP filed with the FERC for recognition as an Independent System Operator and as an RTO. The Company does not expect the implementation of Order 2000 to have a significantly different impact on its results of operations than the implementation of Order 888 and the operation of the SPP tariff had. Several factors exist which may enhance the Company's ability to compete as deregulation occurs. The Company is able to generate and purchase power relatively inexpensively; during 1999, the Company's retail rates were approximately 21% less than the electric industry average. In addition, less than 5% of the Company's electric operating revenues are derived from sales to on- system wholesale customers, the type of customer for which the FERC is already requiring wheeling. At the same time, the Company could face increased competitive pressure as a result of its reliance on relatively large amounts of purchased power and its extensive interconnections with neighboring utilities. In addition, the Company has continued its investments in non- regulated businesses which it commenced in 1996. The Company now leases capacity on its broadband fiber optics network and provides electronic monitored security, decorative lighting and other energy services.
Year 2000 Costs
The Company experienced no Year 2000-related problems as it passed from 1999 to 2000. The Company's total cost (which includes the costs of a new financial management software package and a new customer information system) to update all of its systems for Year 2000 readiness was approximately $5.7 million, of which approximately $5.1 million was capitalized while $0.6 million was expensed. Of these capitalized costs, $0.5 million was included in the 1998 capital budget and $1.5 million was included in the 1999 capital budget. Costs for specific Year 2000 remediation projects were charged to expense while costs to replace software for business purposes other than addressing Year 2000 issues were capitalized.
LIQUIDITY AND CAPITAL RESOURCES
The information discussed below in this section is presented without giving any effect to the Company's proposed merger with UtiliCorp. The Company's construction-related expenditures totaled approximately $71.9 million, $51.9 million, and $56.7 million in 1999, 1998 and 1997, respectively. A breakdown of the Company's 1999 construction expenditures is as follows:
Approximately 46% of construction expenditures and other funds requirements for 1999 were satisfied internally from operations. The Company estimates that its construction expenditures will total approximately $105.7 million in 2000, $61.1 million in 2001 and $50.9 million in 2002. Of these amounts, the Company anticipates that it will spend $21.4 million, $23.1 million and $24.5 million in 2000, 2001 and 2002, respectively, for additions to the Company's distribution system to meet projected increases in customer demand. These construction expenditure estimates also include approximately $57.8 million, $17.8 million and $3.5 million in 2000, 2001 and 2002 respectively, for the construction of the State Line Combined Cycle Unit.
The total cost of construction at the State Line Combined Cycle Unit is estimated to be $185 million. The Company's share of this amount, after the transfer to WGI of an undivided 40% joint ownership interest in the existing State Line Unit No.2 and certain other property at book value is expected to be approximately $100 million. For more information on the State Line Project see Item 2, "Properties - Electric Facilities." WGI is responsible for 40% of expenditures made by the Company in connection with the construction and operation of the State Line Combined Cycle Unit. In addition, WGI will continue to make monthly prepayments to the Company for the future transfer of its 40% joint ownership interest in the existing State Line Unit No. 2, as well as an interest in certain underlying and surrounding land and other property and equipment now owned by the Company. These prepayments are reflected in State Line advance payments on the balance sheet. See Item 8, "Financial Statements and Supplementary Data." The Company estimates that internally generated funds will provide at least 50% of the funds required in 2000, 2001 and 2002 for estimated construction expenditures. As in the past, the Company intends to utilize short-term debt to finance the additional amounts needed for such construction and repay such borrowings with the proceeds of sales of public offerings of long- term debt or equity securities, including the sale of the Company's common stock pursuant to its Dividend Reinvestment Plan and Employee Stock Purchase Plan and from internally-generated funds. The Company will continue to utilize short-term debt as needed to support normal operations or other temporary requirements and has a $50 million line of credit. See Note 6 of "Notes to Financial Statements" regarding the Company's line of credit. The Company financed its preferred stock redemption on August 2, 1999 with approximately $33.1 million in commercial paper. After redeeming all of its preferred stock, the Company is no longer restricted by its Articles as to the amount of unsecured indebtedness that it may have outstanding at any one time. As a result of the implementation of and transition to the Company's new Centurion customer information system, the Company has experienced some delays in customer billing and cash collection. The Company is working to correct these delays and is continuing to enhance and refine this system. The Company filed a shelf registration statement with the SEC, which became effective on September 30, 1999, registering up to an aggregate of $150 million of its common stock, first mortgage bonds and unsecured debt securities. On November 19, 1999, the Company issued $100 million aggregate principal amount of its unsecured Senior Notes, the net proceeds of which were added to the Company's general funds and were used to repay short- term indebtedness, including indebtedness incurred in connection with the Company's preferred stock redemption and in connection with the Company's construction program. On April 28, 1998, the Company sold to the public in an underwritten offering $50 million aggregate principal amount of its First Mortgage Bonds, 6.50% Series due 2010. The net proceeds from this sale were added to the Company's general funds and were used to repay $23 million of the Company's First Mortgage Bonds, 5.70% Series due May 1, 1998 and to repay short-term indebtedness, including indebtedness incurred in connection with the Company's construction program. Following announcement of the Merger, the ratings for the Company's debt securities (other than the 5.20% Pollution Control Series due 2013 and the 5.30% Pollution Control Series due 2013) were placed on credit watch with downward implication by each of Moody's Investors Service, Standard & Poor's and Duff & Phelps Credit Rating Company. As of December 31, 1999, the Company's ratings for its first mortgage bonds, senior notes and commercial paper were as follows:
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk. The Company is exposed to changes in interest rates as a result of significant financing through its issuance of fixed-rate debt and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate exposure to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. See Notes 6 and 7 of "Notes to Financial Statements" under Item 8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Accountants
To the Board of Directors and Stockholders of The Empire District Electric Company
In our opinion, the financial statements listed in the index appearing under Item 14(a)(1) on page 44 present fairly, in all material respects, the financial position of The Empire District Electric Company at December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 14(a)(2) on page 44 present fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
St. Louis, Missouri February 2, 2000
The accompanying notes are an integral part of these financial statements.
Statement of Cash Flows
1. Summary of Accounting Policies
The Company is subject to regulation by the Missouri Public Service Commission (MoPSC), the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). The accounting policies of the Company are in accordance with the rate-making practices of the regulatory authorities and, as such, conform to generally accepted accounting principles as applied to regulated public utilities. The Company's electric revenues in 1999 were derived as follows: residential 41%, commercial 31%, industrial 17%, wholesale 4% and other 7%. Following is a description of the Company's significant accounting policies:
Property and plant The costs of additions to property and plant and replacements for retired property units are capitalized. Costs include labor, material and an allocation of general and administrative costs plus an allowance for funds used during construction. Maintenance expenditures and the renewal of items not considered units of property are charged to income as incurred. The cost of units retired is charged to accumulated depreciation, which is credited with salvage and charged with removal costs.
Depreciation Provisions for depreciation are computed at straight-line rates as approved by regulatory authorities. Such provisions approximated 3.2%, 3.2% and 3.1% of depreciable property for 1999, 1998 and 1997, respectively.
Computations of earnings per share Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of common shares outstanding plus the incremental shares that would have been outstanding under the assumed exercise of dilutive stock options and their equivalents. The weighted average number of common shares outstanding used to compute basic earnings per share for the 1999, 1998 and 1997 periods was 17,237,805, 16,932,704 and 16,599,269, respectively. Dilutive stock options for the 1999, 1998 and 1997 periods were 5,290, 7,775 and 9,844, respectively.
Allowance for funds used during construction As provided in the regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction (AFUDC) when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds (preferred and common stockholders' equity) applicable to the Company's construction program are capitalized as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials. AFUDC does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are permitted as a component of rate base and the provision for depreciation.
In accordance with the methodology prescribed by FERC, the Company utilized aggregate rates of 5.4% for 1999, 5.9% for 1998 and 6.4% for 1997 (on a before-tax basis) compounded semiannually.
Income taxes Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes, measured using statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate.
Unamortized debt discount, premium and expense Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses, related to refunded long-term debt are amortized over the lives of the related new debt issues.
Accrued unbilled revenue The Company accrues on its books estimated, but unbilled, revenue and also a liability for the related taxes.
Accumulated provision for uncollectible accounts The accumulated provision for uncollectible accounts was $372,000 at December 31, 1999 and $276,000 at December 31, 1998.
Franchise taxes Franchise taxes are collected for and remitted to their respective cities. Operating revenues include franchise taxes of $4,400,000, $4,400,000 and $3,900,000 for each of the years ended December 31, 1999, 1998 and 1997, respectively.
Liability insurance The Company carries excess liability insurance for workers' compensation and public liability claims. In order to provide for the cost of losses not covered by insurance, an allowance for injuries and damages is maintained based on loss experience of the Company.
State Line advance payments The Company is currently receiving advance payments from Westar Generating, Inc. (WGI) for WGI's share of the existing State Line facility (See Note 10).
Use of estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of revenues and expenses during the period. Actual amounts could differ from those estimates.
2. Merger Agreement
The Company and UtiliCorp United, Inc., a Delaware corporation ("UtiliCorp"), have entered into an Agreement and Plan of Merger, dated as of May 10, 1999 (the "Merger Agreement"), which provides for a merger of the Company with and into UtiliCorp, with UtiliCorp being the surviving corporation (the "Merger"). Under the terms of the Merger Agreement, UtiliCorp is offering $29.50 for each share of common stock of the Company, payable in UtiliCorp common stock or cash. The Merger Agreement contains a collar provision under which the value of the Merger consideration per share will decrease if UtiliCorp's common stock is below $22 per share preceding the closing and will increase if UtiliCorp's common stock is above $26 per share preceding the closing. Stockholders of the Company may elect to take cash or stock, but total cash paid to stockholders will be limited to no more than 50% of the total Merger consideration, and the UtiliCorp common stock that may be issued in the Merger is limited to 19.9% of the then outstanding common stock of UtiliCorp. UtiliCorp also will become liable for all of the Company's existing debt, including its first mortgage bonds.
The Merger, which was unanimously approved by the Boards of Directors of the constituent companies, is expected to close after all of the conditions to the consummation of the Merger are met or waived. The Merger is conditioned, among other things, upon approval of stockholders of the Company, approvals of federal regulatory agencies and approvals of state regulatory authorities in states where the combined company will operate. Other conditions in the Merger Agreement require the Company to redeem all of its outstanding preferred stock according to its terms prior to the closing and to obtain the consent of holders of its outstanding first mortgage bonds to a modification of a dividend limitation provision relating to successor corporations which is contained in the Company's indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the "Mortgage"), pursuant to which its first mortgage bonds are issued.
The Company has received the requisite consents to amend the dividend limitation in its Mortgage and has entered into a supplemental indenture in order to implement that amendment. The supplemental indenture will not become effective and no consent fee will be paid, however, until the Merger is completed. On August 2, 1999, the Company redeemed all of its outstanding preferred stock for approximately $34,200,000. In addition, the Company called a special meeting of stockholders on September 3, 1999, for the purpose of voting on the proposed Merger with UtiliCorp. The Merger proposal passed with 76.3% of the Company's outstanding shares being voted in favor of the proposal. UtiliCorp is not required to obtain its stockholders' approval of the Merger.
3. Regulatory Matters
During the three years ending December 31, 1999, the following rate changes were requested or in effect:
Arkansas On February 19, 1998, the Company filed a request with the Arkansas Public Service Commission to increase rates in Arkansas by $618,000 annually. An agreement was reached to stipulate an increase of $359,000 on June 16, 1998, and the Company received an order from the Arkansas Commission on July 21, 1998 approving the stipulated rate increase.
Missouri On August 30, 1996, the Company filed a request with the Missouri Public Service Commission for a general annual increase in rates for its Missouri electric customers of approximately $23,400,000, or 13.8%. A stipulated agreement was filed by the parties for approximately $13,950,000, and on July 17, 1997, the Missouri Commission issued an order approving an annual increase in rates in the amount of approximately $10,600,000, or 6.43% effective July 28, 1997. The amount did not include the Company's investment in Unit No. 2 at the Company's State Line Plant because the Commission deemed that Unit No. 2 did not meet all the specified in-service criteria. On July 25, 1997, the Company filed an Application for Rehearing regarding the status of Unit No. 2, seeking to recover the remaining $3,350,000 of the stipulated agreement. On September 11, 1997, the Missouri Commission issued an order approving an additional annual increase in rates in the amount of $3,000,000, or 1.7% effective September 19, 1997, making the total increase in annual revenue from this proceeding approximately $13,600,000, or 8.25%.
Effects of Regulation In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), the Company's financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over the Company (the MoPSC, the KCC, the OCC, the APSC and the FERC).
Certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to customers. As such, the Company has recorded the following regulatory assets which are expected to result in future revenues as these costs are recovered through the ratemaking process. Historically, all costs of this nature which are determined by the Company's regulators to have been prudently incurred have been recoverable through rates in the course of normal ratemaking procedures and the Company believes that the items detailed below will be afforded similar treatment.
The Company recorded the following regulatory assets and regulatory liability which are being amortized over periods of up to 25 years:
The Company continually assesses the recoverability of its regulatory assets. Under current accounting standards, regulatory assets and liabilities are eliminated through a charge or credit, respectively, to earnings if and when it is no longer probable that such amounts will be recovered through future revenues.
Deregulation If and when retail electric competition legislation is passed in the states the Company serves, the Company may determine that it no longer meets the criteria set forth in SFAS 71 with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require the Company to discontinue application of SFAS 71 based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on the Company's financial condition and results of operations.
In Missouri, the Public Service Commission adopted an order in 1997 establishing a docket and creating a task force on retail electric competition. The Commission Task Force, on which the Company was represented, was charged with preparing a comprehensive report for the Commission on how Missouri could implement retail electric competition. The Joint Committee of the Missouri legislature received testimony during 1997 and 1998. No legislative action was taken in 1999. There is a bill pending in the 2000 Missouri legislature, but no action is expected until 2001. In Kansas, although different bills were introduced into the House and Senate during 1997, no legislative action has been taken.
In Oklahoma, the Electric Restructuring Act of 1997 was passed by the Legislature and signed into law by the Governor. The bill, with a target date of July 1, 2002, was designed to provide for the orderly restructuring of the electric utility industry in the state and move the state toward open competition for electric generation. None of the Company's plant investment or regulatory assets were considered impaired as a result of the bill.
The Arkansas Legislature passed a bill in April 1999 that would deregulate the state's electricity industry as early as January 2002. A special provision however, applies to utilities with a small portion of Arkansas revenues whose majority of revenues are from another state. This provision which applies to the Company exempts the Company from restructuring in Arkansas until restructuring is enacted in Missouri or until January 1, 2004, whichever comes first. The bill would freeze rates for three years for residential and small business customers of utilities, such as the Company, that do not seek to recover stranded costs. This freeze applies only to rate increases and does not apply to any fuel adjustment clause or energy cost recovery rider approved by the Arkansas Commission, such as the one the Company has to recover its fuel and purchased power costs. The bill also requires the unbundling of services on electric bills by June 2000. The Company is currently engaged in the regulatory proceedings that have commenced as a result of the new law. None of the Company's plant investment or regulatory assets were considered impaired as a result of the bill.
4. Common Stock
On August 1, 1998, the Company implemented a new stock unit plan for directors (the Director Retirement Plan) to provide directors the opportunity to accumulate retirement benefits in the form of common stock units in lieu of cash which was how benefits accumulated under the previous cash retirement plan for directors. The new Director Retirement Plan also provided directors the opportunity to convert previously earned cash retirement benefits to common stock units.
100,000 shares are authorized under this new plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for one share of common stock upon retirement by the director. The number of units granted annually is computed by dividing the director's retainer fee by the fair market value of the Company's common stock on January 1 of the year the units are granted. Common stock unit dividends are computed based on the fair market value of the Company's stock on the dividend's record date. During 1999, 3,442 units were granted under the Director Retirement Plan and 2,154 units were granted pursuant to the stock incentive plan described below.
The Company's Dividend Reinvestment and Stock Purchase Plan (the Reinvestment Plan) allows common and preferred stockholders to reinvest dividends paid by the Company into newly issued shares of the Company's common stock at 95% of the market price average. Stockholders may also purchase, for cash and within specified limits, additional stock at 100% of the market price average. The Company may elect to make shares purchased in the open market rather than newly issued shares available for purchase under the Reinvestment Plan. If the Company so elects, the purchase price to be paid by Reinvestment Plan participants will be 100% of the cost to the Company of such shares. Participants in the Reinvestment Plan do not pay commissions or service charges in connection with purchases under the Reinvestment Plan.
The Company's Employee Stock Purchase Plan, which terminates on May 31, 2000, permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of grant or at date of exercise. Contingent employee stock purchase subscriptions outstanding and the maximum prices per share were 63,985 shares at $23.35, 50,368 shares at $18.34 and 58,972 shares at $15.53 on December 31, 1999, 1998 and 1997, respectively. Shares were issued at $18.34 per share in 1999, $15.53 per share in 1998, and $15.64 per share in 1997. The Company is in the process of amending the Employee Stock Purchase Plan in order to extend the termination date to May 31, 2003.
The Company's 1996 Incentive Plan (the Stock Incentive Plan) provides for the grant of up to 650,000 shares of common stock through January 2006. The terms and conditions of any option or stock grant are determined by the Board of Directors' Compensation Committee, within the provisions of the Stock Incentive Plan. The Stock Incentive Plan permits grants of stock options and restricted stock to qualified employees and permits Directors to receive common stock in lieu of cash compensation for service as a Director.
During February 1999 and January 1998 and 1997, grants for 1,144, 1,535 and 1,414 shares, respectively, of restricted stock were made to qualified employees under the Stock Incentive Plan. For grants made to date, the restrictions typically lapse and the shares are issuable to employees who continue service with the Company three years from the date of grant. For employees whose service is terminated by death, retirement, disability, or under certain circumstances following a change in control of the Company prior to the restrictions lapsing, the shares are issuable immediately. For other terminations, the grant is forfeited. During 1999, 1998 and 1997, 3,300, 2,641 and 3,983 shares, respectively, were issued under the Stock Incentive Plan. No options have been granted under the Stock Incentive Plan. In 1996, the Company adopted the disclosure-only method under SFAS 123, "Accounting for Stock-Based Compensation." If the fair value based accounting method under this statement had been used to account for stock-based compensation costs, the effect on 1999 and 1998 net income and earnings per share would have been immaterial.
The Company's Employee 401(k) Retirement Plan (the 401(k) Plan) allows participating employees to defer up to 15% of their annual compensation up to a specified limit. The Company matches 50% of each employee's deferrals by contributing shares of the Company's common stock, such matching contributions not to exceed 3% of the employee's
annual compensation. The Company contributed 30,919, 32,274 and 36,978 shares of common stock in 1999, 1998 and 1997, respectively, valued at market prices on the dates of contributions. The stock issuances to effect the contributions were not cash transactions and are not reflected as a source of cash in the Statement of Cash Flows.
At December 31, 1999, 1,294,062 shares remain available for issuance under the foregoing plans.
5. Preferred Stock
The Company has 2,500,000 shares of preference stock authorized, including 500,000 shares of Series A Participating Preference Stock, none of which have been issued.
The Company has 5,000,000 shares of $10.00 par value cumulative preferred stock authorized. Of this amount, preferred stock without mandatory redemption provisions issued and outstanding at December 31, 1999 and 1998 is as follows:
On August 2, 1999 the Company redeemed all outstanding 5%, 4 3/4%, and 8 1/8% series of cumulative preferred stock. Holders were paid the following amounts per share plus accumulated and unpaid dividends: 5% cumulative - $10.50 (aggregate amount $4,009,110); 4 3/4% cumulative - $10.20 (aggregate amount $4,080,000); and 8 1/8 cumulative - $10 (aggregate amount $24,809,980).
Preference Stock Purchase Rights The Company had 8,663,648 and 8,535,918 Preference Stock Purchase Rights (Rights) outstanding at December 31, 1999 and 1998, respectively. Each Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one one-hundredth share, subject to adjustment. Each share of common stock currently has one-half of one Right. The Rights (other than those held by an acquiring person or group (Acquiring Person)), which expire July 25, 2000, will be exercisable only if an Acquiring Person acquires 10% or more of the Company's common stock or announces an intention to make a tender offer or exchange offer which would result in the Acquiring Person owning 10% or more of the common stock. The Rights may be redeemed by the Company in whole, but not in part, for $0.01 per Right, prior to 10 days after the first public announcement of the acquisition of 10% or more of the Company's common stock by an Acquiring Person.
In addition, upon the occurrence of a merger or other business combination, or an event of the type described in the preceding paragraph, holders of the Rights, other than an Acquiring Person, will be entitled, upon exercise of a Right, to receive either common stock of the Company or common stock of the Acquiring Person having a value equal to two times the exercise price of the Right. Any time after an Acquiring Person acquires 10% or more (but less than 50%) of the
Company's outstanding common stock, the Board of Directors may, at its option, exchange part or all of the Rights (other than Rights held by the Acquiring Person) for common stock of the Company on a one-for-two basis. The provisions of the Rights were amended in 1999 to exclude the pending merger with UtiliCorp United, Inc.
6. Long-term Debt
The principal amount of all series of first mortgage bonds outstanding at any one time is limited by terms of the mortgage to $1,000,000,000. Substantially all property, plant and equipment is subject to the lien of the mortgage. At December 31, 1999 the long-term debt outstanding was as follows:
(1) Holders of this series have the right to require the Company to repurchase all or any portion of the bonds at a price of 100% of the principal amount plus accrued interest, if any, on November 1, 2001.
The carrying amount of the Company's long-term debt was $346,566,000 and $246,676,000 at December 31, 1999 and 1998, respectively, and its fair market value was estimated to be approximately $329,118,000 and $252,155,000, respectively. This estimate was based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturation. The estimated fair market value may not represent the actual value that could have been realized as of year-end or that will be realizable in the future.
At December 31, 1999, the Company had a $50,000,000 unsecured line of credit. Borrowings are at the bank's prime commercial rate and are due 370 days from the date of each loan. The Company also had a $25,000,000 unsecured line of credit at December 31, 1999, bearing interest at 30-day LIBOR plus .75%. This unsecured line of credit expired on January 31, 2000. These arrangements do not serve to legally restrict the use of the Company's cash. The lines of credit are also utilized to support the Company's issuance of commercial paper although they are not assigned specifically
to such support. There were no outstanding borrowings under these agreements at December 31, 1999 or 1998.
On November 18, 1999, the Company sold to the public in an underwritten offering $100 million aggregate principal amount of its Senior Notes, 7.70% Series due 2004. The net proceeds of this sale were added to the Company's general funds and were used to repay short-term indebtedness, including indebtedness incurred in connection with the redemption of the Company's preferred stock and the Company's construction program.
On April 28, 1998, the Company sold to the public in an underwritten offering $50 million aggregate principal amount of its First Mortgage Bonds, 6.50% Series due 2010. The net proceeds from this sale were added to the Company's general funds and were used to repay $23 million of the Company's First Mortgage Bonds, 5.70% Series due May 1, 1999 and to repay short-term indebtedness, including indebtedness incurred in connection with the Company's construction program.
7. Short-term Borrowings
Short-term commercial paper outstanding and notes payable averaged $30,796,000 and $11,274,000 daily during 1999 and 1998, respectively, with the highest month-end balances being $65,000,000 and $28,500,000, respectively. The weighted daily average interest rates during 1999, 1998 and 1997 were 5.4%, 5.9% and 5.9%, respectively. The weighted average interest rates of borrowings outstanding at December 31, 1999 and 1998 were, 6.12% and 6.2%, respectively.
8. Retirement Benefits
Pensions In 1998, the Company adopted Statement of Financial Accounting Standards (SFAS) 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits," which resulted in revisions to the 1997 information previously reported.
The Company's noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. The benefits are based on years of service and the employee's average annual basic earnings. Annual contributions to the plan are at least equal to the minimum funding requirements of ERISA. Plan assets consist of common stocks, United States government obligations, federal agency bonds, corporate bonds and commingled trust funds.
The following table sets forth the plan's projected benefit obligation, the fair value of the plan's assets and its funded status:
Assumptions used in calculating the projected benefit obligation for 1999 and 1998 include the following:
Net pension benefit for 1999, 1998 and 1997 is comprised of the following components:
Other Postretirement Benefits The Company provides certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors. Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service.
Effective January 1, 1993, the Company adopted SFAS 106, which requires recognition of these benefits on an accrual basis during the active service period of the employees. The Company elected to amortize its transition obligation (approximately $21,700,000) related to SFAS 106 over a twenty year period. Prior to adoption of SFAS 106, the Company recognized the cost of such postretirement benefits on a pay- as-you-go (i.e., cash) basis. The states of Missouri, Kansas, Oklahoma, and Arkansas authorize the recovery of SFAS 106 costs through rates.
In accordance with the above rate orders, the Company established two separate trusts in 1994, one for those retirees who were subject to a collectively bargained agreement and the other for all other retirees, to fund retiree healthcare and life insurance benefits. The Company's funding policy is to contribute annually an amount at least equal to the revenues collected for the amount of postretirement benefits costs allowed in rates. Assets in these trusts amounted to approximately $10,600,000 at December 31, 1999 and $6,800,000 at December 31, 1998. Postretirement benefits, a portion of which have been capitalized and/or deferred, for 1999, 1998 and 1997 included the following components:
The estimated funded status of the Company's obligations under SFAS 106 at December 31, 1999, 1998 and 1997 using a weighted average discount rate of 8.0%, 7.0% and 6.75%, respectively, is as follows:
9. Income Taxes
The provision for income taxes is different from the amount of income tax determined by applying the statutory income tax rate to income before income taxes as a result of the following differences:
Income tax expense components for the years shown are as follows:
Under SFAS 109, temporary differences gave rise to deferred tax assets and deferred tax liabilities at year end 1999 and 1998 as follows:
10. Commonly Owned Facilities
The Company owns a 12% undivided interest in the Iatan Power Plant, a coal-fired 670 megawatt generating unit near Weston, Missouri. The Company is entitled to 12% of the available capacity and is obligated for that percentage of costs which are included in corresponding operating expense classifications in the Statement of Income. At December 31, 1999 and 1998, the Company's property, plant and equipment accounts include the cost of its ownership interest in the unit of $44,656,000 and $44,628,000, respectively, and accumulated depreciation of $28,689,000 and $27,045,000, respectively.
On July 26, 1999, the Company and Westar Generating, Inc. ("WGI"), a subsidiary of Western Resources, Inc., entered into agreements for the construction, ownership and operation of a 500-megawatt combined cycle unit at the State Line Power Plant (the "State Line Combined Cycle Unit"). Work has begun and the State Line Combined Cycle Unit is projected to be operational by June 2001. The Company will own an undivided 60% interest in the State Line Combined Cycle Unit with WGI owning the remainder. The Company is entitled to 60% of the capacity of the State Line Combined Cycle Unit. The Company will contribute its existing 152-megawatt State Line Unit No. 2 combustion turbine to the State Line Combined Cycle Unit, and as a result, upon commercial operation, the State Line Combined Cycle Unit will provide the Company with approximately 150 megawatts of additional capacity. The total cost of the State Line Combined Cycle Unit is estimated to be $185,000,000. The Company's share of this amount,
after the transfer to WGI of an undivided 40% joint ownership interest in the existing State Line Unit No. 2 and certain other property at book value, is expected to be approximately $100,000,000. The Company and WGI are responsible for their own financing of the project and the Company is billing WGI for its share of monthly construction costs as well as advance payments for WGI's share of the existing State Line Unit No. 2 combustion turbine.
11. Commitments and Contingencies
The Company's 2000 construction budget is $105,720,000. The Company's five-year construction program for 2000 through 2004 is estimated to be approximately $319,555,000.
The Company has entered into long-term agreements to purchase capacity and energy, to obtain supplies of coal and to provide natural gas transportation. Under such contracts, the Company incurred purchased power and fuel costs of approximately $50,000,000, $64,000,000 and $55,000,000 in 1999, 1998 and 1997, respectively. Certain of these contracts provide for minimum and maximum annual amounts to be purchased and further provide, in part, for cash settlements to be made when minimum amounts are not purchased. In the event that no purchases of coal, energy and transportation services are made, an event considered unlikely by management, minimum annual cash settlements would approximate $32,000,000 in 2000, $30,000,000 in 2001, $26,000,000 in 2002 and 24,000,000 in 2003 and reducing to lesser amounts thereafter through 2012.
12. Selected Quarterly Information (Unaudited)
A summary of operations for the quarterly periods of 1999 and 1998 is as follows:
The sum of the quarterly earnings per average share of common stock may not equal the earnings per average share of common stock as computed on an annual basis due to rounding.
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 required by this Item with respect to directors and directorships and with respect to Section 16(a) Beneficial Ownership Reporting Compliance may be found in the Company's proxy statement for its Annual Meeting of Stockholders to be held April 27, 2000, which is incorporated herein by reference. Pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, the information required by this Item with respect to executive officers is set forth in Item 1 of Part I of this Form 10-K under "Executive Officers and Other Officers of the Registrant."
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation may be found in the Company's proxy statement for its Annual Meeting of Stockholders to be held April 27, 2000, which is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the number of shares of the Company's equity securities beneficially owned by the directors and certain executive officers of the Company and by the directors and executive officers as a group may be found in the Company's proxy statement for its Annual Meeting of Stockholders to be held April 27, 2000, which is incorporated herein by reference. To the knowledge of the Company, no person is the beneficial owner of 5% or more of any class of the Company's voting securities, and there are no arrangements the operation of which may at a subsequent date result in a change in control of the Company.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item with respect to certain relationships and related transactions may be found in the Company's proxy statement for its Annual Meeting of Stockholders to be held April 27, 2000, which is incorporated herein by reference. PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Index to Financial Statements and Financial Statement Schedule Covered by Report of Independent Auditors
Balance sheets at December 31, 1999 and 1998 24 Statements of income for each of the three years in the period 25 ended December 31, 1999 Statements of common stockholders' equity for each of the three years in the period ended December 31, 26 Statements of cash flows for each of the three years in the 27 period ended December 31, 1999 Notes to financial statements 28 Schedule for the years ended December 31, 1999, 1998 and 1997: Schedule II - Valuation and qualifying accounts 46
All other schedules are omitted as the required information is either not present, is not present in sufficient amounts, or the information required therein is included in the financial statements or notes thereto.
List of Exhibits (2) - Agreement and Plan of Merger, dated as of May 10, 1999, by and between the Company and UtiliCorp United Inc. (Incorporated by reference to Exhibit 2 to Form 10-Q for quarter ended March 31, 1999, File No.1-3368). (3) (a) - The Restated Articles of Incorporation of the Company (Incorporated by reference to Exhibit 4(a) to Form S-3, File No. 33-54539). (b) - By-laws of Company as amended January 23, 1992 (Incorporated by reference to Exhibit 3(f) to Annual Report Form 10-K for year ended December 31, 1991, File No. 1-3368). (4) (a) - Indenture of Mortgage and Deed of Trust dated as of September 1, 1944 and First Supplemental Indenture thereto (Incorporated by reference to Exhibits B(1) and B(2) to Form 10, File No. 1-3368). (b) - Third Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924). (c) - Sixth through Eighth Supplemental Indentures to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924). (d) - Fourteenth Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(f) to Form S-3, File No. 33-56635). (e) - Seventeenth Supplemental Indenture dated as of December 1, 1990 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(j) to Annual Report on Form 10-K for year ended December 31, 1990, File No. 1- 3368). (f) - Eighteenth Supplemental Indenture dated as of July 1, 1992 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended June 30, 1992, File No. 1-3368). (g) - Twentieth Supplemental Indenture dated as of June 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Form S-3, File No. 33-66748). (h) - Twenty-First Supplemental Indenture dated as of October 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended September 30, 1993, File No. 1-3368).
(i) - Twenty-Second Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(k) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1- 3368). (j) - Twenty-Third Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(l) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1- 3368). (k) - Twenty-Fourth Supplemental Indenture dated as of March 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Annual Report on Form 10-K for year ended December 31, 1993, File No. 1- 3368). (l) - Twenty-Fifth Supplemental Indenture dated as of November 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(p) to Form S-3, File No. 33-56635). (m) - Twenty-Sixth Supplemental Indenture dated as of April 1, 1995 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1995, File No. 1-3368). (n) - Twenty-Seventh Supplemental Indenture dated as of June 1, 1995 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended June 30, 1995, File No. 1-3368). (o) - Twenty-Eighth Supplemental Indenture dated as of December 1, 1996 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Annual Report on Form 10-K for year ended December 31, 1996, File No. 1- 3368). (p) Twenty-Ninth Supplemental Indenture dated as of April 1, 1998 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1998, File No. 1-3368). (q) Thirtieth Supplemental Indenture dated as of July 1, 1999 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 (a) to Form 10-Q for quarter ended June 30, 1999, File No. 1-3368). (r) - Rights Agreement dated July 26, 1990 (Incorporated by reference to Exhibit 4(a) to Form 8-K, dated July 26, 1990, File No. 1-3368). (s) - Amendment #1 to Rights Agreement dated October 24, 1991 between the Company and Chemical Bank (successor to Manufacturers Hanover Trust Company), as Rights Agent (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended September 30, 1991, File No. 1-3368). (t) - Amendment #2 to Rights Agreement dated May 10, 1999 (Incorporated by reference to Exhibit 4(b) to Form 10-Q for quarter ended June 30, 1999, File No. 1-3368). (10)(a) - 1996 Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to Form S-8, File No. 33-64639). (b) - Management Incentive Plan (A description of this Plan is incorporated by reference to page 5 of the Company's Proxy Statement for its Annual Meeting of Stockholders held April 27, 1989). (c) - Deferred Compensation Plan for Directors (Incorporated by reference to Exhibit 10(d) to Annual Report on Form 10-K for year ended December 31, 1990, File No. 1-3368). (d) - The Empire District Electric Company Change in Control Severance Pay Plan and Forms of Agreement (Incorporated by reference to Exhibit 10 to Form 10-Q for quarter ended September 30, 1991, File No. 1-3368). (e) - Amendment to The Empire District Electric Company Change in Control Severance Pay Plan and revised Forms of Agreement (Incorporated by reference to Exhibit 10 to Form 10-Q for quarter ended June 30, 1996, File No. 1-3368). (f) - The Empire District Electric Company Supplemental Executive Retirement Plan. (Incorporated by reference to Exhibit 10(e) to Annual Report on Form 10-K for year ended December 31, 1994, File No. 1-3368). (g) Retirement Plan for Directors as amended August 1, 1998 (Incorporated by reference to Exhibit 10(a) to Form Q for quarter ended September 30, 1998, File No. 1-3368).
(h) Stock Unit Plan for Directors (Incorporated by reference to Exhibit 10(b) to Form Q for quarter ended September 30, 1998, File No. 1-3368).
(12) - Computation of Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements.* (23) - Consent of PricewaterhouseCoopers LLP*
(24) - Powers of Attorney.*
(27) - Financial Data Schedule for December 31, 1999.
This exhibit is a compensatory plan or arrangement as contemplated by Item 14(a)(3) of Form 10-K. *Filed herewith.
Reports on Form 8-K
No reports on Form 8-K were filed during the fourth quarter of 1999.
SCHEDULE II Valuation and Qualifying Accounts
Years ended December 31, 1999, 1998 and 1997 Balance Additions Deductions Balance At Charged to Other Accounts from reserve at Beginning close of of Charged to period period Income Description Amount Description Amount
Year ended December 31, 1999: Reserve deducted Recovery of from assets: amounts Accumulated previously Accounts provision for written written Uncollectible $ 275,876 $ 580,873 off $ 372,955 off $ 857,758 $ 371,946 accounts Reserve not shown separately in balance sheet: Property, plant Injuries and & equipment and Claims damages Reserve clearing accounts and (Note A) $1,314,461 $407,163 $ 407,163 expenses $1,128,787 $1,000,000
Year ended December 31, 1998: Reserve deducted Recovery of from assets: amounts Accumulated previously Accounts provision for written written Uncollectible $ 278,741 $586,000 off $ 448,718 off $1,037,583 $ 275,876 accounts Reserve not shown separately in balance sheet: Property, plant Claims Injuries and & equipment and and damages Reserve clearing accounts expenses (Note A) $1,311,995 $580,832 $ 530,011 $1,108,377 $1,314,461
Year ended December 31, 1997: Reserve deducted Recovery of from assets: amounts Accumulated previously Accounts provision for written written Uncollectibl $ 265,390 $486,000 off $332,632 off $ 805,281 $ 278,741 accounts Reserve not shown separately in Balance sheet: Property, plant Claims Injuries and & equipment and and damages Reserve clearing accounts expenses (Note A) $1,300,917 $484,541 $472,107 $ 945,570 $1,311,995
NOTE A: This reserve is provided for workers' compensation, certain postemployment benefits and public liability damages. The Company at December 31, 1999 carried insurance for workers' compensation claims in excess of $250,000 and for public liability claims in excess of $300,000. The injuries and damages reserve is included on the Balance Sheet in the section "Noncurrent liabilities and deferred credits" in the category "Other".
SIGNATURES
Pursuant to the requirements of Section 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.
THE EMPIRE DISTRICT ELECTRIC COMPANY
M. W. MCKINNEY By.............................
M.W. McKinney, President
Date: March 21, 2000
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 date indicated.
Date
M. W. MCKINNEY
M. W. McKinney, President and Director (Principal Executive Officer)
R. B. FANCHER
R. B. Fancher, Vice President-Finance (Principal Financial Officer)
G. A. KNAPP
G. A. Knapp, Controller and Assistant Treasurer (Principal Accounting Officer)
V. E. BRILL
V. E. Brill, Vice President-Energy Supply and Director
M. F. CHUBB, JR.*
M. F. Chubb, Jr., Director
R. D. HAMMONS*
R. D. Hammons, Director
March 21, 2000 R. C. HARTLEY*
R. C. Hartley, Director
J. R. HERSCHEND*
J. R. Herschend, Director
F. E. JEFFRIES*
F. E. Jeffries, Director
R. E. MAYES*
R. E. Mayes, Director
R. L. LAMB*
R. L. Lamb, Director
M. M. POSNER*
M. M. Posner, Director
R. B. FANCHER *By (R. B. Fancher, As attorney in fact for each of the persons indicated)