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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

Commission file number: 1-3368

THE EMPIRE DISTRICT ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)

Registrant's telephone number: (417) 625-5100

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. / /

        As of February 1, 2002, 19,778,408 shares of common stock were outstanding. Based upon the closing price on the New York Stock Exchange on February 1, 2002, the aggregate market value of the common stock of the Company held by nonaffiliates was approximately $405,457,364.

        The following documents have been incorporated by reference into the parts of the Form 10-K as indicated:

TABLE OF CONTENTS

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FORWARD LOOKING STATEMENTS

        Certain matters discussed in this annual report are "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, competition, litigation, our construction program, rate and other regulatory matters, liquidity and capital resources and accounting matters. Factors that could cause actual results to differ materially from those currently anticipated in such statements include: the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs; electric utility restructuring, including ongoing state and federal activities; weather, business and economic conditions, and other factors which may impact customer growth; operation of our generation facilities; legislation; regulation, including rate relief and environmental regulation (such as NOx regulation); competition, including the impact of deregulation on off-system sales; changes in accounting requirements; other circumstances affecting anticipated rates, revenues and costs; the revision of our construction plans and cost estimates; the performance of projects undertaken by our non-regulated businesses and the success of efforts to invest in and develop new opportunities; and costs and effect of legal and administrative proceedings, settlements, investigations and claims. All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

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PART I

ITEM 1. BUSINESS

General

        The Empire District Electric 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. We also provide water service to three towns in Missouri. In 2001, 99.6% of our gross operating revenues were provided from the sale of electricity and 0.4% from the sale of water.

        The territory served by our electric operations embraces an area of about 10,000 square miles with a population of over 360,000. 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 light industry, agriculture and tourism. Of our total 2001 retail electric revenues, approximately 88% came from Missouri customers, 6% from Kansas customers, 3% from Oklahoma customers and 3% from Arkansas customers.

        We supply electric service at retail to 119 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 we serve is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 157,000. We operate under franchises having original terms of twenty years or longer in virtually all of the incorporated communities. Approximately 51% of our electric operating revenues in 2001 were derived from incorporated communities with franchises having at least ten years remaining and approximately 18% were derived from incorporated communities in which our franchises have remaining terms of ten years or less. Although our franchises contain no renewal provisions, in recent years we have obtained renewals of all of our expiring electric franchises prior to the expiration dates.

        Our electric operating revenues in 2001 were derived as follows: residential 42%, commercial 31%, industrial 17%, wholesale 6% and other 4%. Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2001 accounted for approximately 3% of electric revenues. No single retail customer accounted for more than 1% of electric revenues in 2001.

        We made an investment of approximately $0.8 million in 2001 and $1.9 million in 2000 in fiber optics cable and equipment which we are using in our own operations and leasing to other entities. We also offer electronic monitored security services, generators, surge suppressors, decorative lighting and other energy services. We created a wholly owned subsidiary in 2001, EDE Holdings, Inc., to hold our non-regulated companies. EDE Holdings is a holding company which owns: a 100% interest in Empire District Industries, Inc., a spinoff for our non-regulated business, a 100% interest in Conversant, Inc., a software company which will market the internet-based customer information system software formerly named Centurion that was developed by Empire employees and a 51% interest in transaeris, a start-up wireless internet provider.

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Electric Generating Facilities and Capacity

        At December 31, 2001, our generating plants consisted of:

        We completed construction and commenced commercial operations in June 2001 of a 350 megawatt expansion at the State Line Power Plant resulting in a 500 megawatt combined-cycle unit (the "Combined Cycle Unit") of which we own 60%. This expansion entitles us to 150 megawatts of additional generating capacity and was a joint effort with Westar Generating, Inc. (WGI), a subsidiary of Western Resources, Inc. On October 25, 2001, we entered into an agreement with P2 Energy to purchase two Twin Pac aero units to be installed at the Empire Energy Center with generating capacity of 50 megawatts each. The first unit is to be delivered in October 2002 and is expected to be operational by April 2003. The second unit is scheduled to be delivered in October 2003 and is expected to be operational by April 2004. See Item 2, "Properties—Electric Facilities" for further information about these plants.

        We are a member of the Southwest Power Pool (SPP), a regional division of the North American Electric Reliability Council, and have been participating with other utility members in an effort to restructure the SPP to make it a regional transmission organization (RTO). On October 19, 2001, the SPP and Midwest Independent Transmission System Operator, Inc. (MISO) announced an agreement for the consolidation of the two organizations. In December 2001, the FERC approved the MISO as the first RTO. The agreement between the SPP and MISO to consolidate was completed in February 2002. The new organization will operate an interconnected transmission system encompassing over 120,000 megawatts of generation capacity. We intend to file with the FERC and the utility commissions in the four states in which we operate to transfer control over the operation of our transmission facilities to MISO. We cannot predict what effect, if any, this will have on our off-system sales and revenues. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Competition."

        We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and NERC rules. We have contracted with Western Resources for the purchase of capacity and energy through May 31, 2010. We also have a short-term contract for the purchase of firm energy with American Electric Power from January 2002 through May 31, 2002. Similar agreements for such purchases with Western Resources and Southwestern Public Service Company, (a subsidiary of XCEL Energy) terminated on May 31, 2001. The amount of capacity purchased under these contracts supplements our on-system capacity and contributes to meeting our current expectations of future power needs. The following chart sets forth our purchase commitments and our anticipated owned capacity (in megawatts) during the indicated contract years (which run from

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June 1 to May 31 of the following year). We currently expect to purchase additional capacity to meet reserve margins in 2005 and 2006 of 10 to 50 megawatts per year based on the current forecast of load.

*

Includes five-month AEP contract from January 2002 through May 31, 2002 for replacement energy during a 10-week planned maintenance outage at the Iatan Plant during the first quarter of 2002.

**

Includes capacity from the two Twin Pac aero units scheduled for completion in 2003 and 2004.

        The charges for capacity purchases under the contracts referred to above during calendar year 2001 amounted to approximately $20.4 million. Minimum charges for capacity purchases under such contracts total approximately $80.9 million for the period June 1, 2001, through May 31, 2006.

        The maximum hourly demand on our system reached a new record high of 1001 megawatts on August 9, 2001. Our previous record peak of 993 megawatts was established in August 2000. Our maximum hourly winter demand of 941 megawatts was set on December 19, 2000.

Construction Program

        Total gross property additions (including construction work in progress) for the three years ended December 31, 2001, amounted to $273.8 million, and retirements during the same period amounted to $34.6 million. Please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" for more information.

        Our total construction-related expenditures, including allowance for funds used during construction, referred to as AFUDC, were $71.8 million in 2001 and for the next three years are estimated for planning purposes to be as follows:

*

Excludes AFUDC

        Our projected construction expenditures for new generating facilities include plans for the two Twin Pac aero units to be installed at the Empire Energy Center with generating capacity of 50 megawatts each. The first unit is scheduled to be delivered in October 2002 and is expected to be operational by April 2003. The second unit is scheduled to be delivered in October 2003 and is

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expected to be operational by April 2004. The estimated cost for the purchase, construction and installation of these units will be approximately $18.8 million in 2002, $25.8 million in 2003 and $7.0 million in 2004. Additions to our 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.

        Projected additions to existing generating facilities include $6.4 million in 2003 and $10.3 million in 2004 for the installation of a selective catalytic reduction system at the Asbury Plant to comply with nitrogen oxide emission standards set by the Missouri Department of Natural Resources. See "—Environmental Matters" below for more information.

        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 we receive 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—Results of Operations—Competition."

Fuel

        Coal, generally considered the most cost-effective fuel for base-load generation, supplied approximately 70.2% of our total fuel requirements in 2001 based on kilowatt-hours generated. The remainder was supplied by natural gas (29.3%) with oil generation providing less than 1%. We expect that the amount and percentage of electricity generated by natural gas will increase due to the placing into commercial operation in June 2001 of the new combined cycle unit at the State Line Power Plant and the addition of an additional 50 megawatts of gas-fired generation in each of 2003 and 2004.

        Our 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 85% Western coal (Powder River Basin) and 15% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2001, we had sufficient coal on hand to supply anticipated requirements at Asbury for 100 days. This extra inventory was due to the extended fall outage at the plant and the coal contract commitments to purchase a minimum tonnage for the year.

        Our Riverton Plant fuel requirements are primarily met by coal with the remainder supplied by natural gas and oil. The Riverton Plant is currently burning 100% Western coal (Powder River Basin) on Unit No. 8 and a blend consisting of approximately 78% Western coal (Powder River Basin) and 22% blend coal on Unit No. 7 on a tonnage basis. Our average coal inventory target at Riverton is approximately 60 days. As of December 31, 2001, we had coal supplies on hand to meet anticipated requirements at the Riverton Plant for 60 days.

        We have a long-term contract, expiring in 2004, with a subsidiary of Peabody Holding Company, Inc. for the supply of low sulfur Western coal (Powder River Basin) at the Asbury and Riverton Plants during the term of the contract. This Peabody coal is supplied from the Rochelle/North Antelope mines located in Campbell County, Wyoming, and is shipped to the Asbury Plant by rail, a distance of approximately 800 miles. The coal is delivered under a transportation contract with Union Pacific Railroad Company and The Kansas City Southern Railway Company. We are 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. Asbury blend coal is currently being supplied under a short-term contract, expiring December 31, 2002, with GENWAL Resources, Inc. This coal is supplied

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from the Crandall Canyon mine near Huntington, Utah and is transported by rail by Burlington Northern and Santa Fe Railway Company and The Kansas City Southern Railway Company. This contract expires at the end of 2003. The Riverton Plant blend coal is supplied under a contract expiring December 31, 2002, with Phoenix Coal Sales. The Phoenix coal is transported to Riverton via truck.

        Unit No. 1 at the Iatan Plant is a coal-fired generating unit which is jointly-owned by Kansas City Power & Light (70%), St. Joseph Light & Power (a UtiliCorp subsidiary) (18%) and us (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. Kansas City Power & Light is the operator of this plant and is responsible for arranging its fuel supply. The coal is transported by rail under a contract expiring on December 31, 2010, with the Burlington Northern and Santa Fe Railway Company and The Kansas City Southern Railway Company.

        Since 1995, our Energy Center and State Line combustion turbine facilities have been fueled primarily by natural gas with oil being used as a backup fuel. During 2001, the heat input at the Energy Center was 93% natural gas and 7% oil. The State Line heat input during 2001 was 100% natural gas. Our targeted oil inventory at the Energy Center facility permits eight days of full load operation. We currently have an oil inventory of approximately eight days of full load operation for State Line Unit No. 1.

        We have a firm agreement with Williams Natural Gas Company, expiring May 31, 2016, for the transportation of natural gas to the State Line Power Plant for State Line Unit No. 1 and the jointly-owned Combined Cycle Unit. This transportation agreement can also supply natural gas to the Energy Center or the Riverton Plant, as elected by us on a secondary basis. We expect that our remaining gas transportation requirements, as well as the majority of our natural gas supply requirements, will be met by short-term forward contracts and 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 our facilities:

        Our weighted cost of fuel burned per kilowatt-hour generated was 2.048 cents in 2001, 1.846 cents in 2000 and 1.561 cents in 1999. See "Regulation—Fuel Adjustment Clauses" for information with respect to our recovery of fuel cost increases.

Employees

        At December 31, 2001, we had 616 full-time employees, of whom 328 were members of Local 1474 of The International Brotherhood of Electrical Workers. On January 17, 2000, we and the IBEW entered into a new three-year labor agreement effective November 1, 1999. The agreement provided, among other things, for a 3.25% increase in wages effective October 25, 1999, a 3.5% increase effective November 6, 2000 and an increase of 2.9% effective October 22, 2001. We expect to begin negotiations for a new union contract in late summer of 2002.

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ELECTRIC OPERATING STATISTICS(1)

(1)

See Item 6—Selected Financial Data for additional financial information regarding Empire.

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Executive Officers and Other Officers of Empire

        The names of our officers, their ages and years of service with Empire as of December 31, 2001, positions held and effective date of such positions are presented below. All of our officers, other than G. A. Knapp, B. P. Beecher and R. F. Gatz (whose biographical information is set forth below), have been employed by Empire for at least the last five years.

(1)

M. W. McKinney will retire from his position as President and Chief Executive Officer effective April 30, 2002 but will continue on the Board of Directors as Chairman of the Board.

(2)

W. L. Gipson will become President and Chief Executive Officer effective May 1, 2002 and has been nominated to the Board of Directors.

(3)

C. A. Stark will retire from his position as Vice-President—General Services effective June 30, 2002.

(4)

Effective March 15, 2002.

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(5)

Effective March 15, 2002. G. A. Knapp was previously with Empire from 1978 to 2000 and held the position of Controller and Assistant Treasurer (1983). During the period from 2000 to 2002, Mr. Knapp served as Controller for the Missouri Department of Transportation.

(6)

B. P. Beecher was previously with Empire from 1988 to 1999 and held the positions of Director of Production Planning and Administration (1993) and Director of Strategic Planning (1995). During the period from 1999 to 2001, Mr. Beecher served as the Associate Director of Marketing and Strategic Planning for the Energy Engineering and Construction Division of Black & Veatch.

(7)

R. F. Gatz was previously with Hook Up, Inc. from 1999 to 2001 as Chief Administrative Officer and with Mercantile Bank in Joplin from 1985 to 1999 and held the positions of Executive Vice President, Senior Credit Officer, and Chief Financial Officer.

Regulation

        General.    As a public utility, we are subject to the jurisdiction of the Missouri Public Service Commission, the State Corporation Commission of the State of Kansas, the Corporation Commission of Oklahoma and the Arkansas Public Service 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. Our transmission and sale at wholesale of electric energy in interstate commerce and our facilities are also subject to the jurisdiction of the Federal Energy Regulatory Commission, referred to as 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—Results of Operations—Competition."

        Our Ozark Beach Hydroelectric Plant is operated under a license from FERC. See Item 2, "Properties—Electric Facilities." We are disputing a Headwater Benefits Determination Report we received from FERC on September 9, 1991. The report calculates an assessment to us 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. We believe that the methodology used in making the assessment was incorrect and are contesting the determination. As of December 31, 2001, FERC had not responded to the comments filed by us on July 31, 1992. We are currently accruing an amount monthly equal to what we believe the correct assessment to be.

        During 2001, approximately 92% of our 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 6% of our electric operating revenues during 2001.

        Rates.    See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—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. Although fuel adjustment clauses are not permitted under Missouri law, our recent Missouri rate order approved an annual Interim Energy Charge effective October 1, 2001 and expiring two years later. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Operating Revenues and Kilowatt-Hour Sales" for more information. 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 our retail electric sales in Kansas. However, in our current rate case in Kansas, we requested reinstatement of this fuel adjustment clause. Automatic fuel adjustment clauses are presently

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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 adjusts for changing fuel and purchased power costs on an annual basis rather than the monthly adjustment used by our previous fuel adjustment clause.

Environmental Matters

        We are subject to various federal, state, and local laws and regulations with respect to air and water quality as well as other environmental matters. We believe that our operations are in compliance with present laws and regulations.

        Air.    The 1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect the Asbury, Riverton, State Line 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 Iatan Plant became an affected unit for both SO2 and NOx on January 1, 2000. The Riverton Plant became an affected unit for NOx in November 1996 and for SO2 on January 1, 2000. The State Line Plant became an affected unit for 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 ("EPA") withholds annually a percentage of the emission allowances awarded to each affected unit and sells those emission allowances through a direct auction. We receive compensation from the EPA for the sale of these allowances.

        Our Asbury, Riverton and Iatan plants currently burn a blend of low sulfur Western coal (Powder River Basin) and higher sulfur local coal or burn 100% low sulfur Western coal. The State Line Plant is a gas-fired facility and does not receive SO2 allowances. However, annual allowance requirements for the State Line Plant, which are not expected to exceed 20 allowances per year, will be transferred from our inventoried bank of allowances. We anticipate, based on current operations, that the combined actual SO2 allowance need for all affected plant facilities will not exceed the number of allowances awarded to us annually by the EPA. The excess annual SO2 allowances will be transferred to our inventoried bank of allowances. We currently have 40,000 banked allowances.

        NOx Emissions.    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 April 2000 the Missouri Department of Natural Resources promulgated a final rule addressing the ozone moderate non-attainment classification of the St. Louis area. The final regulation set a maximum NOx emission rate of 0.25 lbs/mmBtu for Eastern Missouri and a maximum NOx emission rate of 0.351bs/mmBtu for Western Missouri. The Iatan, Asbury, State Line and Energy Center facilities are affected by this regulation. The compliance date is set for May 1, 2003. The Iatan, State Line and Energy Center units presently meet this emission limit. The Asbury Plant does not. The regulation provides for a NOx emission trading program and for the generation of Early Reduction Credits during the years 2000, 2001 and 2002. Early Reduction Credits may be used for compliance during 2003 and 2004. We are evaluating our options at this time. In order to comply with the emission

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rate at Asbury, installation of a selective catalytic reduction system appears to be the most viable option and we have included funds for that system in our construction program as described under "Business—Construction Program." However, NOx trading and the purchase of Early Reduction Credits may permit the delay of the installation until 2004 or 2005.

        We have construction and operating permits for our State Line Power Plant and have continuously operated in compliance with those permits since they went into operation on May 30, 1995 for Unit No. 1 and June 18, 1997 for Unit No. 2. In July 2000, we received a request for information from the EPA regarding the State Line Power Plant. The information request indicated that the State Line Power Plant units should have an Acid Rain Permit under Title IV of the 1990 Amendments to the Clean Air Act in addition to the construction and operating permits previously issued to us by the Missouri Department of Natural Resources. In response, in August 2000, we applied for the required Acid Rain Permit with the Missouri Department of Natural Resources and subsequently received the required permit. The EPA notified us in June 2001 that we were subject to being fined approximately $173,000 because of the lack of the permit but had the right to request a hearing or a settlement conference. We had a settlement conference with the EPA in July 2001. The EPA offered to settle if we agreed to a $35,000 fine and to undertake a supplemental environmental project with a cost approximating $128,500. We have reached consensus with the EPA and expect to conclude the supplemental environmental project and a mutually agreeable end to this matter during the fourth quarter of 2002.

        Water.    We operate 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 Riverton and State Line Power Plants' National Pollution Discharge Elimination System Permits were issued in 2001.

        Other.    Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our 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. We have 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 State of Kansas requested that we draft the Title V Permit and submit it to the state. The permit has been drafted and submitted. We expect this permit will be issued during 2002.

Conditions Respecting Financing

        Our Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the "Mortgage"), and our 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 contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the Mortgage) for any twelve consecutive months within the 15 months preceding issuance must be two times the annual interest requirements (as defined in the Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. The Mortgage provides an exception from this earnings requirement in certain instances relating to the issuance of new first mortgage bonds against first mortgage bonds which have been, or are to be, retired. Our earnings for the twelve months ended December 31, 2001, do not permit us to issue new first mortgage bonds based on this test. We have not financed with first mortgage bonds since 1998. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Nonoperating Items." 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, 2001, we had retired bonds

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and net property additions which would enable the issuance of at least $236 million principal amount of bonds if the annual interest requirements are met.

        Under the Restated Articles, (a) cumulative preferred stock may be issued only if our net income available for interest and dividends (as defined in the Restated Articles) for a specified twelve-month period is at least 1¹/2 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 of cumulative preferred stock, 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 our capital and surplus. We redeemed all of our outstanding preferred stock on August 2, 1999. Accordingly, the restriction in our restated Articles does not currently restrict the amount of unsecured indebtedness that we may have outstanding.

ITEM 2. PROPERTIES

Electric Facilities

        At December 31, 2001, we owned generating facilities (including our interest in Iatan Unit No. 1) with an aggregate generating capacity of 1007 megawatts.

        Our principal electric generating plant 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 21% of our owned generating capacity and in 2001 accounted for approximately 34% of the energy generated by us. 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 took place from September 15, 2001 to December 17, 2001, a total of thirteen weeks. The 2001 five-year major generator turbine inspection was extended to allow for expanded boiler maintenance and the replacement of the control system. The Unit No. 2 turbine is inspected approximately every 35,000 hours of operations and was also inspected during the recent outage. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel costs associated with replacement energy. This year's outage was moved to the fall when the new State Line Combined Cycle Unit would be operational to help decrease the need for purchased power.

        Our 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 1998 for Unit No. 8 and in 2000 for Unit No. 7.

        We own 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. We are entitled to 12% of the unit's available capacity and are obligated to pay for that percentage of the operating costs of the Unit. Kansas City Power & Light and UtiliCorp own 70% and 18%, respectively, of the Unit. Kansas City Power & Light operates the unit for the joint owners. See Note 10 of "Notes to Financial Statements" under Item 8.

        We also have two combustion turbine peaking units at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 170 megawatts. These peaking units operate on natural gas as well as oil. On October 25, 2001, we entered into an agreement to purchase two Twin Pac aero units to be installed at the Empire Energy Center with generating capacity of 50 megawatts each. The first unit is scheduled to be delivered in October 2002 and is expected to be operational by April 2003. The second unit is scheduled to be delivered in October 2003 and is expected to be

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operational by April 2004. Contracts with other vendors will be entered into for construction and installation of the units.

        Our State Line Power Plant, which is located west of Joplin, Missouri, presently consists of Unit No. 1, a combustion turbine unit with generating capacity of 92 megawatts and a Combined Cycle Unit with generating capacity of 500 megawatts of which we are entitled to 60%, or 300 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines (including our former State Line Unit No. 2), two heat recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with WGI, a subsidiary of Western Resources, Inc. which owns the remaining 40% of the unit. We are the operator of this Unit. These units burn natural gas as a primary fuel with Unit No. 1 having the capability of burning oil.

        Our hydroelectric generating plant, located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts, subject to river flow. We are currently replacing the water wheels at our hydroelectric plant over a two-year period. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in Southwestern Missouri.

        At December 31, 2001, our transmission system consisted of approximately 22 miles of 345 kV lines, 430 miles of 161 kV lines, 744 miles of 69 kV lines and 81 miles of 34.5 kV lines. Our distribution system consisted of approximately 6,387 miles of line.

        Our electric generation stations are located on land owned in fee. We own a 3% undivided interest as tenant in common with Kansas City Power & Light and UtiliCorp in the land for the Iatan Generating Station. We own a similar interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all of our electric transmission and distribution facilities 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 of our property, plant and equipment are subject to the Mortgage.

Water Facilities

        We also own and operate water pumping facilities and distribution systems consisting of a total of approximately 81 miles of water mains in three communities in Missouri. We are considering selling our water facilities.

Other

        We also have investments in non-regulated businesses which we commenced in 1996. We now lease capacity on our broadband fiber optics network and provide electronic monitored security, decorative lighting and other energy services through our wholly owned subsidiary, EDE Holdings, Inc. We created this subsidiary in 2001 to hold our non-regulated companies. EDE Holdings is a holding company which owns: a 100% interest in Empire District Industries, Inc., a spinoff for our non-regulated business, a 100% interest in Conversant, Inc., a software company which markets the internet-based customer information system software formerly named Centurion that was developed by Empire employees and a 51% interest in transaeris, a start-up wireless internet provider.

ITEM 3. LEGAL PROCEEDINGS

        No legal proceedings required to be disclosed by this Item are pending except for those disclosed in "Environmental Matters" above.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        None

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PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

        Our common stock is listed on the New York Stock Exchange. On February 1, 2002, there were 6,796 record holders of our common stock. The high and low sale prices for our common stock as reported by the New York Stock Exchange for composite transactions, and the amount per share of quarterly dividends declared and paid on the common stock for each quarter of 2001 and 2000 were as follows:

        Holders of our common stock are entitled to dividends if, as, and when declared by the Board of Directors, out of funds legally available therefore, 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 we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our 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 in the Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. As of December 31, 2001, this dividend restriction did not affect any of our retained earnings.

        Participants in our Dividend Reinvestment and Stock Purchase Plan may acquire, at a 3% discount, newly issued common shares with reinvested dividends. Participants may also purchase, at an averaged market price, newly issued common shares with optional cash payments on a weekly basis, subject to certain restrictions. We also offer participants the option of safekeeping for their stock certificates.

        Our shareholders rights plan provides each of the common stockholders one 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 our common stock or if certain other events occur. See Note 5 of "Notes to Financial Statements" under Item 8 for additional information.

        Our By-laws 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 our capital stock.

        See Note 4 of "Notes to Financial Statements" under Item 8 for additional information regarding our common stock.

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ITEM 6. SELECTED FINANCIAL DATA
(Dollars in thousands, except per share amounts)

*

Does not include $0.8 million in non-utility property in 2001.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

TERMINATED MERGER WITH UTILICORP

        Empire and UtiliCorp United Inc. entered into an Agreement and Plan of Merger, dated as of May 10, 1999 which provided for a merger of our company with and into UtiliCorp, with UtiliCorp being the surviving corporation. The merger was conditioned, among other things, upon approvals of various federal and state regulatory agencies, with either company having the right to terminate the merger agreement if all regulatory approvals were not obtained by December 31, 2000. All approvals were not received by this date and UtiliCorp notified us on January 2, 2001, that it was exercising its right to terminate the merger agreement.

        As a result of the termination of the merger by UtiliCorp, approximately $6.1 million in merger related expenses that were not tax deductible when incurred by us, became deductible. This deduction was taken in January 2001, decreasing income tax expense and increasing operating income for the first quarter of 2001 by approximately $2.3 million.

RESULTS OF OPERATIONS

        The following discussion analyzes significant changes in the results of operations for the year ended December 31, 2001, compared to the year ended December 31, 2000, and for the year ended December 31, 2000, compared to the year ended December 31, 1999.

Operating Revenues and Kilowatt-Hour Sales

        Of our total electric operating revenues during 2001, approximately 42% were from residential customers, 31% from commercial customers, 17% from industrial customers, 5% from wholesale on-system customers, 1.5% from wholesale off-system transactions and 3.5% from miscellaneous sources such as late payment fees and transmission services. The percentage changes from the prior year in kilowatt-hour ("Kwh") sales and revenue by major electric customer class were as follows:

*

Revenues excluding portion of the Interim Energy Charge that may be refundable to customers. See discussion below.

        Kwh sales and revenues for our on-system customers increased during 2001 primarily due to unseasonably cold temperatures in the first quarter and warmer temperatures during the second quarter, offset by milder temperatures in the last two quarters of 2001. Customer growth was 1.13% in 2001.

        Residential Kwh sales increased 1.2% with revenues increasing 0.7% as compared to 2000 primarily due to these weather conditions. Commercial Kwh sales increased 3.2% with revenues increasing 4.4% due to these weather conditions as well as continued increases in business activity throughout our service territory. Industrial classes showed a 1.1% decrease in Kwh sales due to decreased consumption by the manufacturing sector in our service territory during the third and fourth quarters of 2001. Revenues in these classes were favorably impacted by the increased Missouri rates.

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        On-system wholesale Kwh sales increased 4.1% in 2001, reflecting the weather conditions discussed above. Revenues associated with these sales increased more than the corresponding Kwh sales as a result of the operation of our 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 and revenues for our on-system customers increased during 2000 primarily due to above-average temperatures in August and September of 2000 as well as unseasonably cold temperatures in November and December of 2000. Customer growth in 2000 remained at the same rate as experienced in 1999. Residential Kwh sales increased 10.1% with revenues increasing 9.9% as compared to 1999 primarily due to these weather conditions. Commercial Kwh sales increased 5.8% with revenues increasing 5.2% due to these weather conditions as well as increases in business activity throughout our service territory. Industrial classes also showed an increase in Kwh sales and revenues because of the increased business activity.

        On-system wholesale Kwh sales increased 4.0% in 2000, reflecting these weather conditions. Revenues associated with these sales increased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause mentioned above.

        On November 3, 2000, we filed a request with the Missouri Public Service Commission for a general annual increase in rates for our Missouri electric customers in the amount of $41,467,926, or 19.36%. This request sought recovery of expenses resulting from significantly higher natural gas prices than the levels contemplated by our existing rates as well as our investment in the Combined Cycle Unit which was under construction at the State Line Power Plant and other plant additions which had occurred since our last rate increase in September 1997. We also filed a request for interim rate relief in February 2001, which was denied in March.

        The Missouri Commission issued a final order on September 20, 2001. The order granted us an annual increase in rates of approximately $17.1 million, or 8.4%, effective October 2, 2001. In addition, the order approved an annual Interim Energy Charge (IEC) of approximately $19.6 million effective October 1, 2001 and expiring two years later. This IEC is $0.0054 per kilowatt hour of customer usage. The recent extraordinarily high natural gas prices and extreme volatility of natural gas led the Missouri Commission to allow forecasted fuel costs to be used rather than the traditional historical costs in determining the fuel portion of the rate increase. At the end of the two year period, the excess money collected from customers, if any, above the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates, will be refunded to the customers with interest equal to the current prime rate at that time. At December 31, 2001, we had recorded a liability of approximately $2.8 million of the IEC collected in the fourth quarter of 2001 as a provision for rate refunds and are not recognizing that revenue in total electric operating revenue. As of February 18, 2002, approximately 90% of our anticipated volume of natural gas usage for the year 2002 is hedged at an average price of $2.93 per Dekatherm (Dth) while approximately 59% of our anticipated volume of natural gas usage for the year 2003 is hedged at an average price of $3.20 per Dth.

        On October 26, 2001, we filed a request with the Missouri Public Service Commission for an additional increase in rates for our Missouri electric customers in the amount of $3,562,983 annually to rectify a regulatory clerical error omitting the cost of off-system sales in the recent rate order. The Missouri Commission, after various proceedings, denied our requests for relief. We are currently evaluating our options for recovering the previously overlooked expenses as well as other capital investments and increased operating expenses which have occurred since our last rate increase.

        On December 28, 2001, we filed a request with the Kansas Corporation Commission for a general annual increase in rates for our Kansas electric customers in the amount of $3,239,744, or 22.81%. This request seeks to recover costs associated with our investment in State Line Unit No. 1, State Line Unit No. 2 and the State Line Combined Cycle Unit as well as significant additions to the transmission and distribution systems and operating cost increases which have occurred since our last rate increase in

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September 1994. A hearing is scheduled for June 27-28, 2002. Any rate increase approved as a result of the filing would not become effective until August 2002. We cannot predict the amount of any increase which might be granted as a result of this filing.

        In addition to sales to our own customers, we sell power to other utilities as available and provide transmission service through our system for transactions between other energy suppliers. During 2001 revenues from such off-system transactions were approximately $7.5 million as compared to approximately $10.6 million in 2000 and approximately $9.6 million during 1999. This fluctuation in revenues is primarily the result of our ability to sell power at market-based rates with the decrease in revenues during 2001 resulting primarily from our peak hour market-based rates being substantially lower this summer than in 2000, milder regional weather conditions in the fourth quarter affecting demand and less power available for sale from the State Line Plant due to the construction of the Combined Cycle Unit during the first half of the year. See "—Competition" below for more information on open-access tariffs.

        Our future revenues from the sale of electricity will continue to be affected by economic conditions, business activities, competition, weather, fuel costs, regulation, the change from a regulated to a competitive environment, changes in electric rate levels, and changes in patterns of electric energy use by customers and our ability to receive adequate and timely rate relief.

Operating Revenue Deductions

        During 2001, total operating expenses increased approximately $10.0 million (6.8%) compared to the prior year. Total purchased power costs decreased by approximately $2.9 million (4.4%) during 2001 reflecting both the decreased demand in the third and fourth quarters of 2001 resulting from milder temperatures and the increased generating capability due to the completion of the State Line Combined Cycle Unit. Total fuel costs were up approximately $7.6 million (15.6%) during 2001 as compared to 2000 primarily reflecting the higher cost of natural gas, increased generation from the new Combined Cycle Unit in the third and fourth quarters and less coal generation due to our Asbury Plant being out of service for scheduled and unscheduled repairs and maintenance during 13 weeks late in the year. Natural gas prices were higher by 35.9% during 2001 as compared to 2000.

        Merger related expenses were $1.4 million during 2001 as compared to $0.3 million in 2000. Merger related expenses in 2001 were primarily the result of expenses related to severance benefits incurred under our Change in Control Severance Pay Plan in the first quarter of 2001. Other operating expenses increased approximately $4.2 million (12.8%) during 2001 primarily due to an actuarially determined adjustment to our fully-funded pension benefit expense in the first quarter of 2001, decreased income of approximately $2.5 million from the pension fund caused by a decline in the value of invested funds during 2001 and additions to the bad debt reserve of approximately $0.7 million during 2001. Maintenance and repairs expense increased approximately $4.3 million (29.1%) during 2001 primarily due to payments under our new maintenance contracts entered into in July 2001 for the combustion turbines at the Energy Center and State Line Power Plants.

        Depreciation and amortization expense increased approximately $1.7 million (6.0%) during 2001 due to increased levels of plant and equipment placed in service. The increase in depreciation and amortization expense caused by increased levels of plant and equipment was partially offset by lower depreciation rates put into effect during the fourth quarter of 2001 as a result of the October rate order issued by the Missouri Commission. Total provision for income taxes decreased approximately $9.7 million (85.3%) during 2001 due primarily to lower taxable income and by the deductibility of approximately $6.1 million in merger related expenses discussed above. See Note 9 of "Notes to Financial Statements" under Item 8 for additional information regarding income taxes. Other taxes increased approximately $0.4 million (3.4%) during the year.

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        During 2000, total operating expenses increased approximately $19.5 million (15.3%) compared to the prior year. Total purchased power costs increased by approximately $20.5 million (46.0%) during 2000 reflecting increased demand in the third and fourth quarters of 2000. Decreased availability of some of our generating units during the third quarter of 2000 and escalating natural gas prices (which at times made it more economical to purchase power than to run our gas-fired units, particularly in September) added to the increase in purchased power. The Riverton Plant's coal-fired Unit No. 7 was out of service for its scheduled fall outage from September 15 to November 9 and Unit No. 8, also coal-fired, was out of service for its scheduled fall outage from September 29 to October 16. The State Line Plant's Unit No. 2 was taken out of service on September 12, 2000 to begin construction of the Combined Cycle Unit that was placed into commercial operation in June 2001.

        Total fuel costs were up approximately $3.6 million (8.1%) during 2000 primarily reflecting increased generation by our gas generation facilities in the fourth quarter of 2000. The extremely cold temperatures in December resulted in a significant increase in the price of purchased power, making it more economical for us to run our gas-fired turbines. Natural gas prices were higher by 31.3% during 2000 as compared to 1999.

        Merger related expenses, which were not tax deductible when they were incurred, were $5.4 million (94.3%) less during 2000 as compared to 1999. Other operating expenses increased approximately $0.7 million (2.3%) during 2000, compared to 1999, mainly due to a $0.5 million addition to the bad debt reserve in the third quarter. Maintenance and repairs expense decreased approximately $1.6 million (9.5%) during 2000 primarily due to decreased maintenance on the combustion turbines at Energy Center as well as decreased levels of distribution maintenance.

        Depreciation and amortization expense increased approximately $1.4 million (5.4%) during 2000, compared to 1999, due to increased levels of plant and equipment placed in service. Total provision for income taxes decreased approximately $4.5 million (28.3%) during 2000 due primarily to lower taxable income. Other taxes decreased approximately $0.3 million (2.6%) during the year.

Nonoperating Items

        Total allowance for funds used during construction ("AFUDC") amounted to approximately 34.7% of earnings applicable to common stock during 2001, 24.5% during 2000, and 6.1% during 1999. Although the percentage of AFUDC compared to earnings applicable to common stock increased in 2001 as compared to 2000, this reflected decreased net income in 2001 rather than increased AFUDC. The amount of AFUDC actually decreased $2.2 million (37.5%) in 2001 reflecting the completion of the State Line Combined Cycle Unit in June. AFUDC increased significantly in 2000 primarily due to the construction of the State Line Combined Cycle. See Note 1 of "Notes to Financial Statements" under Item 8.

        Other-net deductions increased $0.6 million (92.3%) during 2001 as compared to 2000 primarily reflecting a loss in the second and third quarters of 2001 caused by the marking to market, required by Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) of option contracts entered into in connection with our hedging activities that did not qualify for hedge accounting. As a result of our use of derivatives to manage our gas commodity risk and our exposure to gas and purchased power cost volatility (including hedging) and the use of mark-to-market accounting, revenues and earnings may fluctuate. Although our purpose is to minimize our risk from volatile natural gas prices and protect earnings, we recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

        A one-time write-down of $4.1 million was taken in the third quarter of 2001 for disallowed capital costs related to the construction of the State Line Combined Cycle Unit. These disallowed costs were part of a stipulated agreement between us and the Missouri Commission in connection with our

21

October rate order. The net effect on earnings after considering the tax effect on this write-down is $2.5 million.

        Interest charges on long-term debt were virtually the same for 2001 as for 2000. Interest charges on long-term debt increased $7.0 million (35.8%) during 2000 as compared to 1999 due to the issuance of $100 million of our unsecured Senior Notes in November 1999. Commercial paper interest increased $1.0 million (78.7%) during 2001 due to increased usage of short-term debt for financing our construction program. Interest related to our Trust Preferred Securities issued on March 1, 2001 added $3.5 million to total interest charges during 2001. Interest income decreased $0.4 million (68.9%), reflecting lower balances of cash available for investment.

Earnings

        Basic and diluted earnings per weighted average share of common stock were $0.59 during 2001 compared to $1.35 in 2000. Earnings per share for 2001 were negatively impacted by the mild weather in the third and fourth quarters, increased natural gas prices and greater use of gas than in the prior year and the one-time non-cash charge of $2.5 million, net of related income taxes, from the write-down of the State Line construction expenditures. Positively impacting earnings in 2001 was the one-time tax benefit of approximately $2.3 million from previously incurred merger related costs and favorable weather conditions in the first and second quarters of 2001. Excluding $1.4 million in merger costs for 2001, the one-time write-down of construction expenditures and the tax benefit from merger expenses, earnings per share would have been $0.68. Excluding merger related expenses of $0.3 million, earnings per share would have been $1.37 during 2000.

        Basic and diluted earnings per weighted average share of common stock were $1.35 during 2000 compared to $1.13 in 1999. Excluding merger related expenses, earnings per share would have been $1.37 during 2000 compared to $1.46 in 1999. Earnings per share, although higher because of favorable weather conditions, increased AFUDC and decreased merger expenses, were negatively impacted by significantly increased natural gas prices and purchased power costs.

        Earnings for the first quarter of 2002 will reflect an aggregate of $1.5 million of merger expenses related to severance benefits accrued under our Change in Control Severance Pay Plan.

Competition

        Federal regulation has promoted and is expected to continue to promote competition in the electric utility industry. Oklahoma and Arkansas, however, are the only states in which we operate that have taken action with respect to promoting competition.

        Legislation in Oklahoma originally provided for open competition by July 2002. However, the Oklahoma Legislature overwhelmingly approved legislation in June 2001 that indefinitely delays electric restructuring in the state. Approximately 3.19% of our retail electric revenue for 2001 was derived from sales subject to Oklahoma regulation.

        The Arkansas Legislature passed a bill in April 1999 that called for deregulation of the state's electricity industry as early as January 2002. A bill was enacted in February 2001, however, delaying implementation of deregulation until October 2003 and giving the Arkansas Public Service Commission (APSC) authority to set further delays in one-year increments until October 2005. The APSC, after conducting hearings, issued a report in December 2001 recommending that the legislature suspend deregulation beyond 2003 or repeal the law mandating deregulation. Approximately 3.13% of our retail electric revenue for 2001 was derived from sales subject to Arkansas regulation.

        We, and all other electric utilities with interstate transmission facilities, operate under FERC regulated open access tariffs that offer all wholesale buyers and sellers of electricity the same transmission services (at the same rates) that the utilities provide themselves. We and the Southwestern

22

Power Pool (SPP) have filed these open access transmission tariffs covering wholesale transmission services. Under these tariffs, we share revenues received from most of our transmission services with other members of the SPP. There are, however, limited circumstances where our own tariff still applies and we receive 100% of the revenues from the transmission services. We will continue to operate under the SPP tariff until a new tariff is filed as part of the Midwest Independent Transmission System Operator, Inc. (MISO), the regional transmission organization, or RTO, which we intend to join.

        In December 1999, the FERC issued Order No. 2000 which encourages the development of RTOs. RTOs are designed to control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive markets in bulk power. After the FERC rejected several attempts by the SPP to seek RTO status, the SPP and MISO agreed in October 2001 to consolidate and form an RTO. In December 2001 the FERC approved this newly formed MISO as the first RTO. The agreement to consolidate was completed in February 2002. This new organization will operate our system as part of an interconnected transmission system encompassing over 120,000 megawatts of generation capacity located in 20 states. MISO will collect revenues attributable to the use of each member's transmission system and each member will be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire MISO system. Although each member will have priority over the use of its own transmission facilities for selling power to its wholesale customers or others, each member will be charged the same uniform transmission rate as other energy suppliers who are able to sell power to them. We intend to file with the FERC and the utility commissions in the four states in which we operate to transfer control over the operation of our transmission facilities to MISO.

        We cannot predict what effect, if any, this will have on our off-system sales and revenues but it could be material. Even though we have historically been able to generate power relatively inexpensively, other suppliers may be able to offer power at more favorable rates and transmit that power along our system at the same price we pay. Approximately 5% of our electric operating revenues are derived from sales to on-system wholesale customers, the type of customer for which the FERC is already requiring wheeling.

Nonregulated Business

        We are continuing our investments in nonregulated businesses which we commenced in 1996. We now lease capacity on our broadband fiber optics network and provide electronic monitored security, decorative lighting and other energy services through our wholly owned subsidiary, EDE Holdings, Inc. See Item 1, "Business—General" for further information about these nonregulated businesses.

LIQUIDITY AND CAPITAL RESOURCES

        Our construction-related expenditures totaled approximately $71.8 million, $133.9 million, and $71.9 million in 2001, 2000 and 1999, respectively.

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        A breakdown of our 2001 construction expenditures is as follows:

        The amounts in the table do not include $9.2 million of capitalized spare parts for the State Line Combined Cycle Plant, ($1.3) million of plant retirements and ($0.3) million in capital leases and utility land transferred to land held for future use.

        Approximately 20% of construction expenditures and other funds requirements for 2001 were satisfied internally from operations. The other 80% of such requirements were satisfied from short-term borrowings and proceeds from our sale of common stock in an underwritten public offering on December 10, 2001.

        We estimate that our construction expenditures will total approximately $72.2 million in 2002, $85.8 million in 2003 and $66.1 million in 2004. Of these amounts, we anticipate that we will spend $18.8 million, $22.3 million and $21.8 million in 2002, 2003 and 2004, respectively, for additions to our distribution system to meet projected increases in customer demand. These construction expenditure estimates also include approximately $19.2 million, $25.8 million and $7.0 million in 2002, 2003 and 2004, respectively, for two Twin Pac aero units at the Empire Energy Center.

        On October 25, 2001, we entered into an agreement to purchase two Twin Pac aero units with generating capacity of 50 megawatts each to be installed at the Empire Energy Center. An initial payment of $3.4 million was made at that time. The first unit is scheduled to be delivered in October 2002 and is expected to be operational by April 2003. The second unit is scheduled to be delivered in October 2003 and is expected to be operational by April 2004. Contracts with other vendors will be entered into for construction and installation of the units.

        We estimate that internally generated funds will provide at least 55% of the borrowing funds required in 2002 for construction expenditures. As in the past, we intend 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 common stock, including common stock pursuant to our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan and from internally-generated funds. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements.

        As of December 31, 2001, we had lines of credit aggregating $75 million. Our lines of credit each currently contain certain contingencies which affected our rights and obligations thereunder. In the event that the credit rating on our first mortgage bonds falls below BBB (Standard & Poor's) or Baa3 (Moody's) for a $55 million line of credit or Baa2 for a $20 million line of credit, our obligations under our lines of credit either could become immediately due and payable or are no longer available to us. Our credit ratings are discussed below. Further, one of our lines of credit contains a restriction on availability in the event that we fail to maintain Total Funded Debt to Capital (where Capital is defined as Total Funded Debt plus Equity Capital (including our $50,000,000 of Trust Preferred Securities)) less

24

than 67.5%. We are currently in compliance with this ratio. This line of credit is also subject to cross-default with our other indebtedness (in excess of $10,000,000 in the aggregate). We are currently in the process of seeking to amend and/or replace these lines of credit so as to remove the credit rating conditions. See Note 7 of "Notes to Financial Statements" regarding our lines of credit.

        In addition, restrictions in our mortgage bond indenture could also affect our liquidity. The Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. The Mortgage provides an exception from this earnings requirement in certain instances, relating to the issuance of new first mortgage bonds against first mortgage bonds which have been, or are to be, retired. Our earnings for the twelve months ended December 31, 2001 do not permit us to issue new first mortgage bonds based on this test. However, we have not financed with bonds since 1998 and have used unsecured long-term debt rather than first mortgage bonds. See Note 6 to "Notes to Financial Statements" for more information on the mortgage bond indenture.

        In February 2001, the SEC declared effective our $80 million shelf registration statement covering our unsecured debt securities and preferred securities of two newly created trusts of which $30 million remains available for issuance. On March 1, 2001, we sold two million 8¹/2% Trust Preferred Securities (liquidation amount $25 per preferred security) in a public underwritten offering. This issuance generated proceeds of $50.0 million and issuance costs of $1.8 million. Holders of the trust preferred securities are entitled to receive distributions at an annual rate of 8¹/2% of the $25 liquidation amount. Quarterly payments of dividends by the trust, as well as payments of principal, are made from cash received from corresponding payments made by us on the $50.0 million aggregate principal amount of 8.5% Junior Subordinated Debentures due March 1, 2031, issued by us to the trust, and held by the trust, as assets. Our interest payments on the debentures are tax deductible by us. We have effectively guaranteed the payments due on the outstanding trust preferred securities. The net proceeds of this offering were added to our general funds and were used to repay short-term indebtedness.

        On December 10, 2001, we sold to the public in an underwritten offering 2,012,500 newly issued shares of our common stock for approximately $41 million. Proceeds from the sale of the common stock were added to our general funds and used to repay short-term debt, including debt incurred in connection with our construction program.

        On November 19, 1999, we issued $100 million aggregate principal amount of our unsecured Senior Notes, the net proceeds of which were added to our general funds and were used to repay short-term indebtedness, including indebtedness incurred in connection with our preferred stock redemption and in connection with our construction program.

        Following announcement of the merger with UtiliCorp, the credit ratings for our first mortgage bonds (other than the pollution control bonds) were placed on credit watch with downward implications by Moody's Investors Service and Standard & Poor's. Standard & Poor's removed the credit watch but kept the downward implication in January 2001 after the merger was terminated. In May 2001, Moody's Investors Service lowered the credit ratings of our first mortgage bonds (other than the pollution control bonds) to Baa1 from A2, and on our senior unsecured debt to Baa2 from A3. This downgrade was primarily due to the risk to our credit profile associated with our ability to obtain necessary rate relief from the Missouri Public Service Commission to recover our capital expenditures associated with the construction of the Combined Cycle Unit at our State Line Power Plant and our increased

25

operating expenses primarily caused by escalating natural gas prices. As of December 31, 2001, the ratings for our securities were as follows:

        These ratings indicate the agency's assessment of our ability to pay interest, distributions, dividends and principal on these securities. The lower the rating the higher the cost of the securities when they are sold. Ratings below investment grade may also impair our ability to issue short-term debt as described above, commercial paper or other securities or make the marketing of such securities more difficult.

Contractual Obligations

        Set forth below is information summarizing our contractual obligations as of December 31, 2001:

Critical Accounting Policies

        Set forth below are certain accounting policies that are considered by management to be critical and to possibly involve significant risk, which means that they typically require difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain (other accounting policies may also require assumptions that could cause actual results to be different than anticipated results).

        Pensions.    In accordance with Statement of Financial Accounting Standards No. 87, "Employers' Accounting for Pensions", our pension expense includes a calculation of "amortization of unrecognized net (gain)/loss" which was changed in 2001 as a result of the settlement order in our Missouri rate case. Previously the current year calculation of net gains or losses was amortized over five years. The new calculation requires the use of an average of the previous five years gain or loss, which is then amortized over five years. The result for year 2001 was an increase of $317,135 in pension income.

        Provision for Refunds.    As discussed under "Operating Revenues and Kilowatt-Hour Sales" above, the Missouri Commission in its September rate case order approved an annual IEC of approximately $19.6 million effective October 1, 2001 and expiring two years later. At the end of the two year period, the excess money collected from customers under the IEC, if any, above the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates, will be refunded to the customers with interest equal to the current prime rate at that time. At December 31, 2001, we had recorded a liability of approximately $2.8 million of the IEC collected in the fourth quarter of 2001 as a provision for rate refunds and are not recognizing that revenue in total electric operating revenue.

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        Hedging Activities.    We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties for our future natural gas requirements (under a set of predetermined percentages) that lock in prices in an attempt to lessen the volatility in our fuel expense and gain predictability, thus protecting earnings. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results.

        Regulatory Assets.    In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", our financial statements reflect ratemaking policies prescribed by the regulatory commissions having jurisdiction over us (FERC and four states).

        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, we have recorded certain 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 our regulators to have been prudently incurred have been recoverable through rates in the course of normal ratemaking procedures and we believe that the items detailed below will be afforded similar treatment.

        We recorded $37,743,107 in regulatory assets and $12,915,456 in income taxes as a regulatory liability for 2001. These amounts are being amortized over periods of up to 25 years. See Note 3 of "Notes to Financial Statements" under Item 8 for detailed information regarding our regulatory assets and liabilities.

        We continually assess the recoverability of our 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.

RECENTLY ISSUED ACCOUNTING STANDARDS

        In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". These statements eliminate the amortization of purchased goodwill and instead require an annual review of goodwill and intangibles for impairment or when a change or event occurs that indicates goodwill may be impaired. SFAS No. 142 is required to be adopted no later than the first quarter of fiscal 2002. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 and establishes specific criteria for recognition of intangible assets separately from goodwill. We had no recorded goodwill as of December 31, 2001 but will continue to evaluate the total impact of the adoption of these Statements on our financial statements and financial reporting.

        In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Obligations Associated with the Retirement of Long-Lived Assets." This statement establishes standards for accounting and reporting for legal and constructive obligations associated with the retirement of tangible long-lived assets. In August 2001, the Financial Accounting Standards Board issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", establishing new standards for accounting and reporting for the impairment or disposal of long-lived assets. This statement eliminates the requirement under SFAS 121 to allocate goodwill to long-lived assets to be tested for impairment. We adopted SFAS No. 144 on January 1, 2002 and are required to adopt SFAS No. 143 on January 1, 2003. We will continue to evaluate the total impact of the adoption of these Statements on our financial statements and financial reporting.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Market risk is the exposure to a change in the value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates or commodity prices. We handle market risk in accordance with established policies, which may include entering into various derivative transactions. See Note 13 of "Notes to Consolidated Financial Statements" for further information.

        Interest Rate Risk.    We are exposed to changes in interest rates as a result of significant financing through our issuance of commercial paper. We manage our interest rate exposure by limiting our 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 2002 than in 2001, our interest expense would increase, and income before taxes would decrease by approximately $555,000. This amount has been determined by considering the impact of the hypothetical interest rates on our commercial paper balances as of December 31, 2001. 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 our financial structure.

        Commodity Price Risk.    We are exposed to the impact of market fluctuations in the price and transportation costs of coal, natural gas, and electricity and employ established policies and procedures to manage the risks associated with these market fluctuations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPLEMENTARY DATA

Report of Independent Accountants

To the Board of Directors and Stockholders of
The Empire District Electric Company:

        In our opinion, the consolidated financial statements listed in the index appearing under Item 14 on page 54 present fairly, in all material respects, the financial position of The Empire District Electric Company and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14 on page 54 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, 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 our opinion.

PricewaterhouseCoopers LLP

St. Louis, Missouri
January 29, 2002

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Consolidated Balance Sheets

(Continued)

The accompanying notes are an integral part of these consolidated financial statements.

30

Consolidated Balance Sheets (Continued)

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statements of Income

(Continued)