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

FORM 10-Q

Commission file number: 1-3368

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

        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

        Common stock outstanding as of November 1, 2002: 22,525,592 shares.

THE EMPIRE DISTRICT ELECTRIC COMPANY

INDEX

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PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

See accompanying Notes to Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

See accompanying Notes to Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

See accompanying Notes to Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)

See accompanying Notes to Financial Statements

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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET (UNAUDITED)

See accompanying Notes to Financial Statements.

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THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

See accompanying Notes to Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1—Summary of Significant Accounting Policies

        The accompanying interim financial statements do not include all disclosures included in the annual financial statements and therefore should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

        The information furnished reflects all adjustments, consisting only of normal recurring adjustments, which are in our opinion necessary to present fairly the results for the interim periods presented. Certain reclassifications have been made to prior year information to conform to the current year presentation. In the third quarter of 2002, we began recording our non-regulated revenue in "Non-regulated" under Operating Revenues and including our non-regulated expense in "Other" under the Operating Revenue Deductions section of our income statements rather than netting them under "Other—net" in the Other Income and Deductions section. The corresponding 2001 data has been reclassified to conform to the current year presentation.

Note 2—Retained Earnings

Note 3—Non-regulated Acquisition

        On July 18, 2002 we announced that our subsidiary, EDE Holdings, Inc., had joined with seven other investors in acquiring the assets of the Precision Products Department of Eagle Picher Technologies, LLC. The acquisition was accomplished through the creation of a newly formed limited liability company, Mid-America Precision Products, LLC. Mid-America Precision Products, LLC specializes in close tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries, including components for specialized batteries for Eagle Picher Technologies. EDE Holdings, Inc. acquired a controlling 50 percent interest in Mid-America Precision Products through a cash investment of $0.65 million and is also a guarantor for 50 percent of Mid-America Precision Products, LLC's outstanding loans of $3.2 million. Sales revenue for Mid-America Precision Products, LLC for the third quarter of 2002 was $3.1 million with net income of $0.5 million and did not have a material effect on results of operations for the quarter.

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Note 4—Interim Energy Charge

        The Missouri Commission issued a final order on September 20, 2001, granting us an annual increase in rates for our Missouri electric customers and approving an annual Interim Energy Charge, or IEC, of approximately $19.6 million effective October 1, 2001, subject to refund, and expiring two years later. The related accumulated provision for rate refunds increased $13.8 million during the third quarter of 2002 and amounts to $16.6 million at September 30, 2002. See Item 2, "Management's Discussion and Analysis of Financial Conditions and Results of Operations—Rate Matters" for more information on the IEC.

Note 5—Recently Issued Accounting Standards

        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. We are required to adopt SFAS No. 143 on January 1, 2003. We will continue to evaluate the total impact of the adoption of this Statement on our financial condition and results of operations.

        In April 2002, the Financial Accounting Standards Board issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This statement eliminates the requirement (in both FAS 4 and FAS 64) that gains and losses from the extinguishment of debt be aggregated and, if material, classified as an extraordinary item, net of the related income tax effect. Further, FAS 145 eliminates an inconsistency between the accounting for sale-leaseback transactions and certain lease modifications that have economic effects that are similar to sale-leaseback transactions. FAS 145 also makes several other technical corrections to existing pronouncements that may change accounting practice and is effective for transactions occurring after May 15, 2002. We do not believe that the adoption of this Statement will have a material impact on our financial condition and results of operations.

        On June 28, 2002, the FASB voted in favor of issuing Statement No. 146 (FAS 146), Accounting for Exit or Disposal Activities. FAS 146 addresses significant issues regarding the recognition, measurement, and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance that the Emerging Issues Task Force has set forth. The scope of FAS 146 also includes costs related to terminating a contract that is not a capital lease and termination benefits that employees who are involuntarily terminated receive under the terms of a one-time benefit arrangement that is not an ongoing benefit arrangement or an individual deferred-compensation contract. FAS 146 will be effective for exit or disposal activities that are initiated after December 31, 2002. We will continue to evaluate FAS 146 but do not believe there will be a material impact on our financial condition and results of operations upon the adoption of this Statement.

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FORWARD LOOKING STATEMENTS

        Certain matters discussed in this quarterly 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, our financing plans, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like "anticipate," "believe," "expect," "project," "objective" or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include: the amount and timing of rate relief we are currently seeking and related matters; 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; other factors which may impact customer growth; operation of our generation facilities; legislation; regulation, including environmental regulation (such as NOx regulation); competition; the impact of deregulation on off-system sales and our becoming a participant in a Regional Transmission Organization; changes in accounting requirements; other circumstances affecting anticipated rates, revenues and costs, including our cost of funds; the revision of our construction plans and cost estimates; the performance of projects undertaken by our non-regulated businesses; 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.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

        The following discusses significant changes in the results of operations for the three-month, nine-month and twelve-month periods ended September 30, 2002, compared to the same periods ended September 30, 2001.

On-System Transactions

        Of our total electric operating revenues during the third quarter of 2002 (excluding the Interim Energy Charge (IEC), as discussed below, which was refundable to customers as of September 30, 2002) approximately 42% were from residential customers, 30% from commercial customers, 15% from industrial customers, 4% from wholesale on-system customers, 6% from wholesale off-system transactions and 3% from miscellaneous sources such as late payment fees and transmission services.

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The percentage changes from the prior periods in kilowatt-hour ("Kwh") sales and operating revenues by major customer class were as follows:

*

Revenues excluding the Interim Energy Charge which was refundable to customers as of September 30, 2002. See discussion below.

        Third Quarter 2002.    Residential and commercial Kwh sales increased during the third quarter of 2002 compared to the third quarter of 2001 due mainly to warmer temperatures in September 2002. Residential and commercial Kwh revenues increased as a result of the increased sales and the October 2001 Missouri rate increase and, to a lesser extent, the July 2002 Kansas rate increase discussed below.

        Industrial Kwh sales and related revenues increased during the third quarter of 2002 due to stronger sales in August and September as compared to the same period last year, the October 2001 Missouri rate increase and, to a lesser extent, the July 2002 Kansas rate increase.

        On-system wholesale Kwh sales increased during the third quarter of 2002 due mainly to the warmer temperatures in September 2002. Revenues associated with these FERC-regulated sales decreased as a result of the fuel adjustment clause applicable to such sales. This clause permits the pass through to customers of changes in fuel and purchased power costs. Natural gas prices were significantly lower during the third quarter of 2002 as compared to the same period a year earlier, causing the decrease in revenues associated with the increased Kwh sales.

        Nine Months Ended September 30, 2002.    For the nine months ended September 30, 2002, Kwh sales to our residential and commercial customers increased slightly, primarily reflecting the cooler temperatures in April 2002 and the warmer temperatures in June and September of 2002 as compared to the same periods in 2001. Lower temperatures during the heating season (September through May) and higher temperatures during the air-conditioning season (May through September) generally result in increased Kwh sales. Residential and commercial revenues increased during the nine months ended September 30, 2002 reflecting increased Kwh sales as well as the October 2001 Missouri rate increase. Industrial Kwh sales and related revenues increased during the nine months ended September 30, 2002, reflecting increased sales in April, August and September as compared to the same period in 2001 and also reflecting the October 2001 Missouri rate increase. On-system wholesale Kwh sales decreased slightly for the nine months ended September 30, 2002. Revenues associated with these FERC-regulated sales decreased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause applicable to such sales.

        Twelve Months Ended September 30, 2002.    For the twelve months ended September 30, 2002, Kwh sales to our residential and commercial customers decreased, reflecting mild temperatures during the fourth quarter of 2001 and first quarter of 2002. Residential and commercial revenues increased during the twelve months ended September 30, 2002 reflecting the October 2001 Missouri rate increase. Industrial sales decreased slightly during the twelve-month period reflecting a general slowdown in economic activity during the fourth quarter of 2001 and the first quarter of 2002 while related revenues increased reflecting the October 2001 Missouri rate increase. On-system wholesale Kwh sales decreased

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slightly for the twelve months ended September 30, 2002, reflecting the mild weather and general economic slowdown. Revenues associated with these FERC-regulated sales decreased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause applicable to such sales.

Rate Matters

        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%. The Missouri Commission issued a final order on September 20, 2001 granting 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, or IEC, of approximately $19.6 million effective October 1, 2001 and expiring two years later. This IEC was $0.0054 per kilowatt hour of customer usage before being reconfigured (see below) and was being collected subject to refund at the end of the two year period to the extent money was collected from customers above the greater of the actual and prudently incurred costs or the base cost of fuel and purchased power set in rates. Any excess money collected would be refunded to customers with interest equal to the current prime rate at that time.

        On March 8, 2002, we filed a request with the Missouri Public Service Commission for an annual increase in base rates for our Missouri electric customers in the amount of $19,779,916 and also asked to have the IEC that was granted in the last rate case reconfigured to reflect a decrease of $9,994,888 in the amount billed to customers. The reconfigured IEC would remain subject to refund with interest. This request sought to recover new operating costs and obligations and reflect the changes in our capital structure since the rate increase in October 2001. Also on March 8, 2002, we filed an interim rate case for an annual increase in base rates of $3,562,983, the amount that was erroneously omitted from the increase granted in our 2001 rate case. The Missouri Commission rejected the interim request. After extensive negotiations with the Missouri Commission staff, Office of Public Counsel and other intervening parties, we filed a Unanimous Stipulation and Agreement Regarding "Error" in the 2001 rate case and an Immediate Reduction of the IEC with the Missouri Commission on May 14, 2002. This agreement was approved by the Missouri Commission on June 4, 2002 and provided for a $7 million annual reduction in the IEC. In addition, this agreement set out a framework for the recovery of off-system sales exposure in the IEC, which provided the opportunity for us to recover the $3,562,983 in off-system sales expenses previously omitted from our prior rate case.

        On October 29, 2002, we filed a Unanimous Stipulation and Agreement, agreed to by the Missouri Commission staff, Office of Public Counsel and other intervening parties, with the Missouri Commission. This Agreement, if approved by the Missouri Commission, would settle all matters covered by our March 2002 filings, provide us with an annual increase in rates of approximately $11.0 million, or 4.97%, effective December 1, 2002 and eliminate the IEC as of that date. The Agreement also calls for us to rebate all funds collected by the IEC, with interest, by March 15, 2003.

        At September 30, 2002, we had recorded a liability of approximately $16.6 million for the IEC since its inception as a provision for rate refunds and have not recognized that revenue in total electric operating revenue. The refunds will not have a material impact on our earnings per share. Refunds would be listed as a credit on current customer bills and checks would be mailed to former customers who are no longer on service. The Agreement also provides for a change to the summer/winter rate differential for our residential customers with the new rates reflecting a smaller differential between summer and winter rates for usage above 600 kilowatt hours. Each of the parties have also agreed not to file a new request for a general rate increase or decrease before September 1, 2003, barring any unforeseen, extraordinary occurrences. This stipulation must be approved by the Missouri Public Service Commission.

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        On December 28, 2001, we filed a request with the Kansas Corporation Commission (KCC) for an annual increase in base rates for our Kansas electric customers in the amount of $3,239,744, or 22.81%. This request sought 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 our transmission and distribution systems and operating cost increases which had occurred since our last rate increase in September 1994. We also requested reinstatement of a fuel adjustment clause for our Kansas rates. We filed a Unanimous Stipulation and Agreement, agreed to by the KCC staff and all intervening parties, with the KCC on June 7, 2002. The agreement stipulates that we will not file for general rate relief before November 1, 2003 barring any unforeseen, extraordinary occurrences. This agreement was approved by the KCC on June 27, 2002 providing us an annual increase in rates of approximately $2,539,000, or 17.87%, effective July 1, 2002 and does not provide for the reinstatement of a fuel adjustment clause.

        On May 15, 2002, we filed a request with the Missouri Public Service Commission for an annual increase in base rates for our Missouri water customers in the amount of approximately $361,000, or 33.9%. This was the first requested increase in rates for our water customers since 1994. On November 7, 2002, we filed an Agreement Regarding Disposition of a Small Company Rate Increase Request, agreed to by the Missouri Commission staff, with the Missouri Commission. This agreement, if approved by the Missouri Commission, would provide us with an annual increase in rates of approximately $358,000, or 33.7%.

Off-System Transactions

        In addition to sales to our own customers, we also sell power to other utilities as available and also provide transmission service through our system for transactions between other energy suppliers. During the third quarter of 2002, revenues from such off-system transactions were approximately $6.7 million as compared to $1.9 million for the same period ended September 30, 2001. Off-system revenues were approximately $16.4 million for the nine-month period ended September 30, 2002 as compared to $5.6 million for the same period in 2001. For the twelve months ended September 30, 2002, revenues from such off-system transactions were approximately $18.3 million as compared to $8.2 million for the twelve months ended September 30, 2001. The increase in revenues for all periods resulted primarily from the availability of competitively priced power from our recently completed State Line Combined Cycle Unit and term purchases of firm energy during the first nine months of 2002 which, if not required to meet our own customers' needs, could be sold in the wholesale market. These term purchases will continue throughout the remainder of 2002.

        We are a member of the Southwest Power Pool (SPP), a regional division of the North American Electric Reliability Council. Effective September 1, 2002, we began taking Network Integration Transmission Service under the SPP's Open Access Transmission Tariff. This provides a cost-effective way for us to participate in a broader market of generation resources with the possibility of lower transmission costs. This tariff provides for a zonal rate structure, whereby transmission customers pay a pro-rata share, in the form of a reservation charge, for the use of the facilities for each transmission owner that serves them. Currently, all revenues collected within a zone are allocated back to the transmission owner serving the zone. Since we are a transmission provider for our zone and are currently the only transmission customer taking service from that zone, we are currently being assessed 100 per cent of the zonal costs and receiving it back as revenue. To the extent that we are incurring these revenues and charges to serve our on-system wholesale and retail power customers, the associated costs are netted against the revenues collected and only the difference, if any, is recorded. In the event that other transmission customers take Network Integration Transmission Service in our zone, the revenues received will be reflected in electric operating revenues and the related charges will be expensed. Reference is made to our Annual Report on Form 10-K for the year ended December 31, 2001 under Item 1, "Business—Electric Generating Facilities and Capacity" and under Item 7,

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"Management's Discussion and Analysis of Financial Condition and Results of Operations—Competition" for further information.

        We have been participating with other utility members in an effort to restructure the SPP to make it a regional transmission organization (RTO). After the FERC rejected several attempts by the SPP to seek RTO status, the SPP and the Midwest Independent Transmission System Operator, Inc. (MISO), agreed in October 2001 to consolidate and form an RTO. The consolidation was scheduled to close at the end of the third quarter this year but is still in progress. If the consolidation does not occur, we will continue to operate our system as part of the SPP while continuing to search for an RTO to join. MISO and SPP filed a combined tariff for the new resulting company on November 1, 2002 as directed by the FERC. This new tariff would eliminate rate pancaking for transactions that occur between MISO and SPP customers, preserve the zonal rate structure under the current MISO and SPP tariffs, preserve the existing rates for certain long-term firm SPP service agreements, preserve the grandfathered contract provisions under both organizations' tariffs and continue the stated rates currently on file under the SPP tariff.

Operating Revenue Deductions

        Third Quarter 2002.    During the third quarter of 2002, total operating expenses increased approximately $2.2 million (5.0%) compared with the same period last year. Total fuel costs decreased approximately $5.6 million (25.2%) during the third quarter of 2002 as compared to the same period in 2001, reflecting significantly lower natural gas prices in 2002 as well as less generation by our gas-fired units primarily due to the term purchases of firm energy previously discussed. Purchased power costs increased approximately $2.8 million (21.7%) during the period reflecting increased demand in the third quarter of 2002 and the term purchases of firm energy. Other operating expenses increased approximately $5.1 million (53.3%) during the third quarter primarily due to increases in expense for our non-regulated businesses and administrative and general expense.

        Maintenance and repairs expense increased approximately $1.6 million (37.0%) during the third quarter mainly due to a payment, per contract terms, to Westar Generating, Inc. (WGI) for maintenance expense related to our usage of the existing Unit No. 2 turbine prior to WGI's 40% joint ownership of the State Line Combined Cycle Unit and to expenditures for maintenance contracts. These contracts were entered into in July 2001 for the State Line Combined Cycle Unit, the Energy Center and State Line Unit No. 1 and serve to levelize maintenance costs over time. Payments on the Energy Center and State Line Unit No. 1 contracts began in January 2002.

        Depreciation and amortization expenses decreased approximately $1.8 million (21.5%) during the quarter due to lower depreciation rates put into effect during the fourth quarter of 2001 as a result of the October 2001 Missouri rate increase. Total income taxes increased approximately $5.7 million (140.4%) due primarily to an increase in taxable income. Other taxes increased $0.5 million (11.3%) during the period as a result of increased property taxes primarily due to a reduction in capitalized property taxes related to the State Line Combined Cycle Unit being placed in service in June 2001.

        Nine Months Ended September 30, 2002.    For the nine months ended September 30, 2002, total operating expenses increased approximately $5.2 million (4.3%). Merger related expenses (which include expenses related to severance benefits incurred in the first quarter of both 2002 and 2001) accounted for approximately $0.2 million of this increase. Purchased power costs decreased $3.7 million (7.6%) primarily due to lower purchased power prices and increased generation due to the availability of the State Line Combined Cycle Unit beginning June 30, 2001. Total fuel costs decreased $1.0 million (2.3%) primarily reflecting significantly lower natural gas prices in 2002. Other operating expenses increased $9.6 million (34.4%), primarily due to increases in expense for our non-regulated businesses, administrative and general expense, transmission expense due to the delivery of purchased energy to our system and other power operation expenses related to the State Line Combined Cycle Unit.

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        Maintenance and repairs expense increased $6.7 million (56.8%) for the nine months ended September 30, 2002 primarily due to the maintenance contracts discussed above. Maintenance costs associated with a three-week outage to replace the main transformer at the Asbury Plant during the second quarter of 2002 also contributed to this increase. Depreciation and amortization expense decreased approximately $3.5 million (15.2%) during the nine-month period due to the lower depreciation rates put into effect during the fourth quarter of 2001. Total provisions for income taxes increased $9.6 million (491.6%) for the nine months ended September 30, 2002 due primarily to an increase in taxable income and to the benefit created by the deductibility of approximately $6.1 million in merger related expenses in the first quarter of 2001. Other taxes increased $1.3 million (11.8%) during the period primarily due to the increase in property taxes discussed above.

        Twelve Months Ended September 30, 2002.    During the twelve months ended September 30, 2002, total operating expenses increased approximately $1.6 million (0.1%) compared to the same period in 2001. Merger related expenses discussed above increased approximately $0.1 million (5.3%) compared to the year ago period. Total purchased power costs decreased approximately $9.8 million (14.4%) while total fuel costs were virtually the same for the twelve-month periods. Purchased power costs decreased primarily due to decreased demand in the fourth quarter of 2001 and the first quarter of 2002 resulting from milder temperatures as well as increased generating capability due to the availability of competitively priced power from the new State Line Combined Cycle Unit.

        Other operating expenses increased approximately $11.3 million (31.1%) during the twelve months ended September 30, 2002, compared to the same period in 2001 primarily due to increases in expense for our non-regulated businesses, administrative and general expense, transmission expense due to the delivery of purchased energy to our system, other power operation expenses related to the operation of the State Line Combined Cycle Unit, decreased income from the pension fund caused by a decline in the value of invested funds and additions to our bad debt reserve during the fourth quarter of 2001.

        Maintenance and repairs expense increased approximately $10.2 million (65.5%) during the twelve months ended September 30, 2002 compared to the same period in 2001 primarily due to our new maintenance contracts and to the Asbury outage in the second quarter of 2002. Depreciation and amortization expense decreased approximately $3.8 million (12.6%) due to the lower depreciation rates put into effect during the fourth quarter of 2001. Total provision for income taxes increased $9.1 million (440.4%) due to higher taxable income during the current period and to the benefit created by the deductibility of approximately $6.1 million in merger related expenses in the first quarter of 2001. Other taxes increased approximately $1.5 million (11.0%) primarily due to the increase in property taxes discussed above.

Non-regulated Items

        In the third quarter of 2002, we began recording our non-regulated revenue in "Non-regulated" under Operating Revenues and including our non-regulated expense in "Other" under the Operating Revenue Deductions section of our income statements rather than netting them under "Other—net" in the Other Income and Deductions section, as we had done in prior periods. Additionally, as previously mentioned, we have reclassified the non-regulated revenues and expenses within prior periods to conform to the new presentation. Prior period amounts reclassified are not material to the results of operations for those periods. During the third quarter of 2002, total non-regulated operating revenue increased approximately $3.4 million while total non-regulated operating expense increased approximately $3.3 million compared with the same period in 2001. Total non-regulated operating revenue increased approximately $3.6 million for the nine months ended September 30, 2002 while total non-regulated operating expense increased approximately $4.5 million as compared to the year ago period. During the twelve months ended September 30, 2002, total non-regulated operating revenue increased approximately $3.7 million while total non-regulated operating expense increased approximately $4.2 million when compared to the same period in 2001. The increase in revenues and

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expenses for all three periods was primarily due to the acquisition of Mid-America Precision Products, LLC in July 2002. The increase in expense for all three periods was also due to the activities of our wholly owned subsidiary, Conversant, Inc., a software company that began business in early 2002. Conversant markets the internet-based customer information system software formerly named Centurion that was developed by Empire employees.

Nonoperating Items

        Total allowance for funds used during construction (AFUDC) was virtually the same during the third quarters of 2002 and 2001. AFUDC decreased significantly during both the nine-months ended and the twelve-months ended September 30, 2002 periods reflecting the completion of the State Line Combined Cycle Unit in June 2001.

        Other-net deductions increased $0.2 million for the third quarter of 2002 mainly due to an unrealized loss on derivatives in July 2002. Other-net deductions decreased $0.4 million for the nine-months ended September 30, 2002 and $0.3 million for the twelve-month ended period reflecting losses in June, July and August of 2001 caused by the marking to market of option contracts relating to our procurement of natural gas and entered into in connection with our hedging activities that did not qualify for hedge accounting. See "Liquidity and Capital Resources—Critical Accounting Policies" below for more information on hedging activities. Interest income decreased for all periods, reflecting lower investments.

        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 costs were disallowed as part of the stipulated agreement approved by the Missouri Public Service Commission in connection with our 2001 rate case and will not be recovered in rates. The net effect on earnings after considering the tax effect on this write-down was $2.5 million for each of the three-month, nine-month and twelve-month periods ended September 30, 2001.

        Total interest charges decreased $0.9 million (11.4%) during the third quarter of 2002 mainly due to the maturing of $37.5 million of our first mortgage bonds in July 2002. Total interest charges increased $1.9 million (9.0%) for the nine months ended September 30, 2002 and $4.6 million (16.9%) for the twelve months ended period when compared to the same periods last year due to the interest related to our Trust Preferred Securities which were issued on March 1, 2001. Commercial paper interest decreased $0.3 million during the third quarter, $1.5 million for the nine months ended September 30, 2002 and $1.9 million for the twelve months ended September 30, 2002, as compared to the same periods ended in 2001. These decreases in commercial paper interest reflect decreased usage of short-term debt as well as lower interest rates.

Earnings

        For the third quarter of 2002, earnings per share of common stock were $0.82 compared to $0.42 during the third quarter of 2001. Earnings per share were positively impacted by the warmer temperatures in September of 2002, the October 2001 Missouri rate increase, lower fuel and purchased power costs, an increase in off-system sales, and decreased interest expense and depreciation expense. Earnings per share in the third quarter of 2002 were negatively impacted by planned increased maintenance costs for our combustion turbine and combined cycle units. Earnings per share in the third quarter of 2001 were negatively impacted by the one-time non-cash charge of $2.5 million, net of related income taxes, from the write-down of the disallowed State Line construction expenditures. Excluding this net one-time non-cash charge, earnings per share would have been $0.56 for the third quarter of 2001.

        Earnings per share for the nine months ended September 30, 2002, were $1.04 compared to $0.58 for the nine months ended a year earlier. Earnings per share were positively impacted by the cooler

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temperatures in April 2002 and the warmer temperatures in June and September of 2002, the October 2001 Missouri rate increase, lower fuel and purchased power costs, an increase in off-system sales, and decreased depreciation expense. Earnings per share for the nine months ended September 30, 2002, were negatively impacted by $1.5 million in merger related expenses as well as planned increased maintenance costs for our combustion turbine and combined cycle units. Earnings per share for the nine months ended September 30, 2001, were negatively impacted by the one-time write-down of construction expenditures as well as $1.3 million in merger related costs. Positively impacting earnings for the nine months ended September 30, 2001 was a one-time tax benefit of $2.3 million from previously incurred merger-related costs that became deductible for income tax purposes in the first quarter of 2001. Excluding $1.5 million in merger costs for the first nine months of 2002 and $1.3 million for the first nine months of 2001, the one-time write-down of construction expenditures and the tax benefit from merger expenses that became deductible in 2001, earnings per share would have been $1.11 for the nine months ended September 30, 2002 and $0.67 for the nine months ended September 30, 2001.

        For the twelve months ended September 30, 2002, earnings per share of common stock were $1.08 compared to $0.77 for the year earlier period. This increase in earnings per share was primarily due to the October 2001 Missouri rate increase, an increase in off-system sales and decreased depreciation expense. Earnings per share for the twelve months ended September 30, 2002, were negatively impacted by $1.6 million in merger related expenses as well as planned increased maintenance costs for our combustion turbine and combined cycle units. Earnings for the twelve months ended September 30, 2001 were negatively impacted by $1.6 million in merger related expenses as well as the one-time write-down of construction expenditures and positively impacted by the one-time tax benefit from merger expenses in 2001. Excluding $1.6 million in merger costs for the twelve months ended September 2002 and $1.6 million in merger costs for the twelve months ended September 2001, the one-time write-down of construction expenditures and the tax benefit from merger expenses that became deductible in 2001, earnings per share would have been $1.16 for the twelve months ended September 30, 2002 and $0.87 for the twelve months ended September 30, 2001.

        Earnings per share for all three periods ended September 30, 2002 were diluted, as compared to the year earlier periods, by the issuance of 2.0 million shares of our common stock in December 2001 and 2.5 million shares in May 2002.

Environmental

        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, we applied for the required Acid Rain Permit with the Missouri Department of Natural Resources in August 2000 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 reached consensus with the EPA and paid the fine in the fourth quarter of 2001. The supplemental environmental project was physically completed in October 2002 and final documentation to conclude this matter is scheduled for transmittal to the EPA in November 2002.

LIQUIDITY AND CAPITAL RESOURCES

        Our construction-related expenditures totaled $23.4 million during the third quarter of 2002, compared to $10.4 million for the same period in 2001. For the nine months ended September 30,

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2002, construction-related expenditures totaled $58.1 million compared to $56.8 million for the same period in 2001. Approximately $7.5 million of the construction expenditures during the third quarter of 2002 and $18.6 million during the first nine months of 2002 were related to additions to our transmission and distribution systems. Approximately $9.2 million of the third quarter expenditures and $20.8 million for the first nine months of 2002 were related to the Energy Center aero units discussed below. Approximately $0.7 million during the third quarter of 2002 and $2.6 million during the first nine months of 2002 were related to work at the Asbury Plant, including the replacement of the main transformer during the second quarter. Approximately $0.9 million during the third quarter of 2002 and $1.8 million during the first nine months of 2002 were related to Computer Services projects, including a system-wide mapping project for work force optimization and outage management. Approximately $0.5 million during the third quarter of 2002 and $1.3 million during the first nine months of 2002 were related to miscellaneous plant additions for the State Line Combined Cycle Unit while $0.4 million during the third quarter of 2002 and $1.8 million during the first nine months of 2002 were related to our investment in fiber optics cable and equipment. During the third quarter of 2002, 100% of our construction expenditures were paid with funds provided internally from operations while 74% of our construction expenditures for the first nine months of 2002 were satisfied internally from operations. The remainder was satisfied from short-term borrowings and from the proceeds of our sales of common stock in underwritten public offerings on December 10, 2001 and May 22, 2002.

        In October 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. An initial payment of $3.4 million was made at that time. Both units have been delivered and are scheduled to be operational by the second quarter of 2003. Contracts with other vendors have been entered into for construction and installation of the units. We estimate that the total cost of these installed units will be approximately $55.0 million.

        We originally estimated that our construction expenditures would total approximately $72.2 million in 2002, including approximately $18.8 million for additions to our distribution system and approximately $19.2 million for the two Twin Pac aero units. We have revised our original estimate and now estimate that our total construction expenditures for 2002 will range from approximately $75-80 million. This amount has changed from our previous estimate primarily reflecting the accelerated schedule for installation of the two Twin Pac aero units discussed above. Originally, the first unit was to be delivered in October 2002 and operational by April 2003 with the second unit scheduled to be delivered in October 2003 and operational by April 2004. In addition, due to a number of factors, we have reduced our estimated construction expenditures (including AFUDC) for 2003, 2004 and 2005 from approximately $71, $67 and $76 million, respectively, to approximately $50, $31 and $33 million, respectively. These factors include: (1) a Missouri Commission approved change in policy relating to charging developers for new line construction, which will reduce our costs, (2) an expected change in Missouri's EPA approved plan for nitrogen oxide (NOx) reduction, which will allow us to delay additional environmentally-related construction and (3) a revision of our annual customer growth projections from 1.6% to 1.4% (based on updated historical growth reflecting lowered economic activity) over the next several years, which will allow us to delay construction of additional generation capacity.

        We currently expect that internally generated funds will provide less than 5% of the funds required for the remainder of our 2002 construction expenditures. As in the past, we intend to utilize short-term debt to finance the additional amounts needed for construction and repay such borrowings with the proceeds of sales of long-term debt or common stock (including common stock sold pursuant to our Employee Stock Purchase Plan and our Dividend Reinvestment and Stock Purchase Plan) and from internally-generated funds.

        On March 1, 2001, we sold two million 8¹/2% Trust Preferred Securities in a public underwritten offering. This issuance generated proceeds of $50.0 million and issuance costs of $1.8 million. The net

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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 $41.0 million. The net proceeds of approximately $39.2 million from the sale of the common stock were added to our general funds and used to repay short-term debt.

        On May 22, 2002, we sold to the public in an underwritten offering 2,500,000 shares of newly issued common stock. This issuance generated proceeds of $51.9 million. The net proceeds of approximately $49.4 million were used to repay $37.5 million of our First Mortgage Bonds, 7.50% Series due July 1, 2002 and to repay short-term debt.

        We have an effective shelf registration under which approximately $150 million of common stock and unsecured debt securities remain available for issuance.

        On May 7, 2002 we entered into a new 370-Day $100,000,000 unsecured revolving credit facility. This credit facility replaced all of our existing lines of credit. The facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total Indebtedness (which does not include our Trust Preferred Securities) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to be at least two times our interest charges (which includes distributions on our Trust Preferred Securities) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. We are in compliance with these ratios. This credit facility is also subject to cross-default with our other indebtedness (in excess of $5,000,000 in the aggregate). There are no borrowings outstanding under this revolver as of September 30, 2002. However, $51 million of the facility as of that date was used to back up our commercial paper and was not available to be borrowed.

        In addition, restrictions in our mortgage bond indenture could 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. Our earnings for the twelve months ended September 30, 2002 would permit us to issue approximately $141.8 million of new first mortgage bonds (at an assumed interest rate of 7.5%) based on this test. 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.

        Moody's Investors Service currently rates our first mortgage bonds (other than the pollution control bonds) Baa1 and our senior unsecured debt Baa2. Standard & Poor's downgraded our first mortgage bonds (other than the pollution control bonds) on July 2, 2002 from A- to BBB, our senior unsecured debt from BBB+ to BBB- and our Trust Preferred Securities from BBB to BB+. The outlook, however, was revised from negative to stable. In July 2001, Moody's adjusted the credit rating of our Trust Preferred Securities from Baa1 to Baa3 due to technical changes in Moody's methodology for rating this classification of security.

        These ratings indicate the agencies' 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 (the cutoff for which is Baa3 for Moody's and BBB- for Standard & Poor's) may also impair our ability to issue short-term debt as described above, commercial paper of other securities or make the marketing of such securities more difficult.

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Contractual Obligations

        Set forth below is information summarizing our contractual obligations as of September 30, 2002:

Payments Due by Period
(in millions)

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). A change in assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

        Pensions.    In accordance with Statement of Financial Accounting Standards (SFAS) 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. The result for the current year is an increase of $3,014,394 in pension income.

        Given recent market returns, we could face a position at December 31, 2002 where our accumulated pension benefit obligation exceeds the fair value of our plan assets. If this situation develops, a cash contribution to the plan may be required. We cannot determine at this time if this situation will occur or the magnitude of this contribution. There would be no effect to net income if this contribution is made.

        Provision for Refunds.    The Missouri Commission in its September 2001 rate case order approved an annual IEC of approximately $19.6 million (reconfigured in June 2002 and reduced by $7 million annually) 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, would be refunded to the customers with interest equal to the current prime rate at that time. On October 29, 2002, however, we filed a Unanimous Stipulation and Agreement with the Missouri Commission that, in addition to providing us with an annual increase in rates, would eliminate the IEC effective December 1, 2002. The Agreement also calls for us to rebate all funds collected by the IEC, with interest, by March 15, 2003. At September 30, 2002, we have recorded a liability of approximately $16.6 million of the IEC collected since its inception as a provision for rate refunds and are not recognizing that revenue in total electric operating revenue. The refund will not materially impact our

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earnings per share but will impact our cash flow. This stipulation must still be approved by the Missouri Public Service Commission.

        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. As of November 4, 2002, 99% of our anticipated volume of natural gas usage for the remainder of year 2002 is hedged at an average price of $3.00 per Dekatherm (Dth). In addition, approximately 71% of our anticipated volume of natural gas usage for the year 2003 is hedged at an average price of $3.386 per Dth, approximately 51% of our anticipated volume of natural gas usage for the year 2004 is hedged at an average price of $3.289 per Dth and approximately 13% of our anticipated volume of natural gas usage for the year 2005 is hedged at an average price of $3.763 per Dth.

        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 have recorded totals of $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.

        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.

Item 3. 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. During the second quarter of 2001, we began utilizing derivatives to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers.

        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. 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

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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.

Item 4. Controls and Procedures.

        Within the 90-day period prior to the date of this report, an evaluation was carried out, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC's rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

        There have been no significant changes in our internal controls or in other factors that could significantly affect internal controls subsequent to the date of the evaluation described above.

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PART II. OTHER INFORMATION

Item 5. Other Information.

(a)

At September 30, 2002, the Company's ratio of earnings to fixed charges was 2.04x. See Exhibit (12) hereto.

(b)

Our three-year agreement with the Local 1474 of The International Brotherhood of Electrical Workers ("IBEW") expired on October 31, 2002. Negotiations with the IBEW did not result in a new agreement, however, pursuant to its terms, the contract was automatically renewed for an additional year. We and the IBEW both have the right to submit any unresolved issues to binding arbitration. As of October 20, 2002, 328 of our 633 employees were members of the IBEW.

(c)

On October 31, 2002, we received a letter from Enron North America Corp. asserting that, as a result of the termination of an agreement between Enron and us relating to our purchase of natural gas, we owe Enron approximately $6.1 million. We terminated the agreement effective December 3, 2001 as a result of, among other reasons, the drop in Enron's credit ratings. We believe that, under the terms of the agreement, we have no obligation to make any payment to Enron.

Item 6. Exhibits and Reports on Form 8-K.

(a)

Exhibits.

        (12) Computation of Ratios of Earnings to Fixed Charges.

        (99)(a) Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

*

This certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 or any other provision of the Securities Exchange Act of 1934, as amended.

        (99)(b) Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

(b)

Reports on Form 8-K.

(1)

In a current report dated July 3, 2002, Empire filed, under Item 5. "Other Events," press releases relating to Standard & Poor's downgrade of Empire's credit ratings.

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SIGNATURES

        Pursuant to the requirements 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.

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CERTIFICATIONS

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, William L. Gipson, certify that:

        1.    I have reviewed this quarterly report on Form 10-Q of The Empire District Electric Company;

        2.    Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

        3.    Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

        4.    The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;



b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and



c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

        5.    The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

        6.    The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

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CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002

I, Gregory A. Knapp, certify that:

        1.    I have reviewed this quarterly report on Form 10-Q of The Empire District Electric Company;

        2.    Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

        3.    Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

        4.    The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;



b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and



c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

        5.    The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

        6.    The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

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QuickLinks

Item 1. Consolidated Financial Statements
THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)

THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (UNAUDITED)
THE EMPIRE DISTRICT ELECTRIC COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Item 3. Quantitative and Qualitative Disclosures about Market Risk
Item 4. Controls and Procedures.

PART II. OTHER INFORMATION
Item 5. Other Information.
Item 6. Exhibits and Reports on Form 8-K.