Back to GetFilings.com

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

FORM 10-Q

(Mark One)

For the quarterly period ended June 30, 2002

or

For the transition period from                              to                             

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

        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 August 1, 2002: 22,445,591 shares.

THE EMPIRE DISTRICT ELECTRIC COMPANY
INDEX

2

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.

3

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

See accompanying Notes to Financial Statements.

4

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

See accompanying Notes to Financial Statements.

5

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

See accompanying Notes to Financial Statements

6

THE EMPIRE DISTRICT ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET (UNAUDITED)

See accompanying Notes to Financial Statements.

7

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

See accompanying Notes to Financial Statements.

8

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 with current year presentation.

Note 2—Retained Earnings

Note 3—Subsequent Event

        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.

Note 4—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.

9

        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.

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.

10

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

RESULTS OF OPERATIONS

        The following discussion analyzes significant changes in the results of operations for the three-month, six-month and twelve-month periods ended June 30, 2002, compared to the same periods ended June 30, 2001.

On-System Transactions

        Of our total electric operating revenues during the second quarter of 2002 (excluding the portion of the Interim Energy Charge (IEC), as discussed below, that may be refundable to customers) approximately 36.3% were from residential customers, 30.3% from commercial customers, 17.6% from industrial customers, 4.2% from wholesale on-system customers, 6.4% from wholesale off-system transactions and 5.2% from miscellaneous sources such as late payment fees and transmission services. 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 portion of the Interim Energy Charge that may be refundable to customers. See discussion below.

        Second Quarter 2002.    Residential Kwh sales were up during the second quarter of 2002 due mainly to cooler temperatures in April 2002 and warmer temperatures in June 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. Commercial Kwh sales were down slightly during the second quarter of 2002 as a result of a negative Kwh adjustment due to metering adjustments in prior periods. Residential and commercial revenues increased during the second quarter of 2002 reflecting the October 2001 Missouri rate increase discussed below.

        During the second quarter of 2002, industrial Kwh sales and related revenue grew due to an increase in April sales as compared to the prior year and to the Missouri rate increase.

        On-system wholesale Kwh sales increased during the second quarter of 2002 reflecting the temperatures discussed above while revenues associated with these sales increased less as a result of the operation of the fuel adjustment clause applicable to these FERC regulated sales. This clause permits the pass through to customers of changes in fuel and purchased power costs.

        Six Months Ended June 30, 2002.    For the six months ended June 30, 2002, Kwh sales to our residential and commercial customers decreased, reflecting milder temperatures during the first quarter of 2002 as compared to unusually cold temperatures during the same period of 2001. Residential and commercial revenues increased during the second quarter of 2002 reflecting the Missouri rate increase. Industrial Kwh sales decreased slightly reflecting a general slowdown in economic activity while related revenues increased due to the positive effect of the Missouri rate increase. On-system wholesale Kwh sales and revenues decreased reflecting the milder temperatures and economic slowdown described

11

above. Revenues associated with these sales decreased more than the corresponding Kwh sales as a result of the operation of the fuel adjustment clause.

        Twelve Months Ended June 30, 2002.    For the twelve months ended June 30, 2002, residential and commercial Kwh sales decreased, reflecting mild temperatures during the third and fourth quarters of 2001 as well as the first quarter of 2002. Residential and commercial revenues increased during this period due to the Missouri rate increase. Industrial sales decreased during the twelve-month period reflecting a general slowdown in economic activity. Revenues increased reflecting the Missouri rate increase. On-system wholesale Kwh sales decreased during the twelve-month period reflecting the mild temperatures and general economic slowdown discussed above. Revenues associated with these sales increased as a result of the operation of the fuel adjustment clause applicable to these FERC regulated 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 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 is being collected subject to refund at the end of the two year period to the extent money is 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 will 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 seeks to recover new operating costs and obligations and reflects the changes in our capital structure since the rate increase in October 2001. A hearing is set to begin on October 28, 2002. Any rate increase approved as a result of the filing would not become effective until early 2003. We cannot predict the amount or timing of any increase that might be granted as a result of this filing.

        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 previous permanent rate case (Case No. ER-2001-299). 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 Case No. ER-2001-299 and an Immediate Reduction of the Interim Energy Charge with the Missouri Commission on May 14, 2002. This agreement was approved by the Missouri Commission on June 4, 2002 and provides for a $7 million annual reduction in the IEC. In addition, this agreement sets out a framework for the recovery of off-system sales exposure in the IEC, which will provide the opportunity for us to recover the $3,562,983 million in off-system sales expenses previously omitted from our prior rate case. As a result of the stipulation, we are able to recognize as revenue amounts formerly required to be reserved for refund.

        At June 30, 2002, we had recorded a liability of approximately $12.1 million of the IEC collected in the fourth quarter of 2001 and the first and second quarters of 2002 as a provision for rate refunds and are not recognizing that revenue in total electric operating revenue. In an effort to manage our fuel costs, we utilize forward physical contracts and financial instruments to manage our gas commodity market risk. As of July 29, 2002, 100% of our anticipated volume of natural gas usage for the

12

remainder of year 2002 is hedged at an average price of $2.54 per Dekatherm (Dth), down from the $2.93 per Dth reported in our Annual Report on Form 10-K for the year ended December 31, 2001 under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Operating Revenues and Kilowatt-Hour Sales." This change in our average hedged price was partially due to lower average hedged prices for the last six months of 2002 than during the first six months of 2002 and partially due to term purchases of firm energy that displaced our generation, causing us to be overbought on natural gas. As a result, we sold futures contracts at relatively high market prices, which helped lower our financial position. In addition, approximately 68% of our anticipated volume of natural gas usage for the year 2003 is hedged at an average price of $3.32 per Dth.

        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 excludes 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 is the first requested increase in rates for our water customers since 1994. We had previously announced plans to sell our water facilities but have discontinued efforts to do so.

13

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 second quarter of 2002, revenues from such off-system transactions were approximately $5.7 million as compared to approximately $1.7 million in the second quarter of 2001. Off-system revenues were approximately $9.7 million for the six-month period ended June 30, 2002 as compared to approximately $3.7 million for the six-month period ended June 30, 2001. For the twelve months ended June 30, 2002, revenues from such off-system transactions were approximately $13.5 million as compared to $10.0 million for the twelve months ended June 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 and second quarters 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, and 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; however, conditions of the consolidation may not be met. 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. Effective September 1, 2002, we will begin 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 will require us to pay the SPP all expenses associated with transporting our power from our generating stations. The SPP will then pay us for distributing power to our retail customers and these payments will be reflected in electric operating revenues. 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, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Competition" for further information.

Operating Revenue Deductions

        Second Quarter 2002.    During the second quarter of 2002, total operating expenses increased approximately $1.8 million (4.9%) compared with the same period last year.

        Total fuel costs decreased approximately $0.5 million (3.9%) during the second quarter of 2002 as compared to the same period in 2001 while purchased power costs increased approximately $0.3 million (1.9%) during the period. The decrease in fuel costs reflects significantly lower natural gas prices in 2002. Although availability of our coal-fired units was restricted during the second quarter of 2002 due to a three-week outage at the Asbury Plant to replace the main transformer, our gas-fired units were able to produce more economical power than in the previous year due to natural gas prices being 59% lower than the same period in 2001. The increase in purchased power costs reflects increased demand in the second quarter of 2002 and the term purchases of firm energy previously discussed.

        Other operating expenses increased $2.0 million (21.4%) during the period as a result of increased transmission expense due to the delivery of purchased energy to our system, administrative and general expense and other power operation expenses related to the State Line Combined Cycle Unit, which operated during the second quarter of 2002 but was operational only during the last week of the second quarter of 2001. Maintenance and repair expense increased approximately $2.1 million (49.6%) during the quarter, primarily due to new expenditures for maintenance contracts, which serve to

14

levelize maintenance costs over time, entered into in July 2001 for the State Line Combined Cycle Unit, the Energy Center and State Line Unit No. 1. Maintenance costs associated with the Asbury outage also contributed to this increase.

        Depreciation and amortization expense decreased approximately $0.9 million (12.8%) during the quarter due to lower depreciation rates in effect during the fourth quarter of 2001 as a result of the October 2001 Missouri rate increase. The provision for income taxes increased $2.0 million (816.7%) during the second quarter of 2002 due to an increase in taxable income. Other taxes increased approximately $0.5 million (14.1%) during the second quarter of 2002 due mainly to increased property taxes.

        Six Months Ended June 30, 2002.    For the six months ended June 30, 2002, total operating expenses were up approximately $1.6 million (2.1%). Merger related expenses (which include expenses related to severance benefits during the first quarter of 2002) increased approximately $0.3 million (23.3%). Purchased power costs decreased $6.5 million (18.0%) due mainly to decreased demand resulting from milder temperatures in the first quarter of 2002 as well as increased generation due to the availability of the State Line Combined Cycle Unit beginning June 30, 2001. Total fuel costs increased $4.6 million (21.3%) for the six-month period ending June 30, 2002 because of increased generation and the need to use our higher-cost gas-fired turbines as a replacement for our lower-cost coal units during the period. The Asbury plant had a three-week outage to replace the main transformer during the second quarter of 2002. During the first quarter of 2002, Iatan had a 10-week planned boiler overhaul outage and generation from the Asbury Plant was limited to only 70-80% of budgeted kilowatt hours in order to comply with opacity regulations. Other operating expenses increased $3.2 million (17.8%) primarily as a result of increased transmission expense due to the delivery of purchased energy to our system, administrative and general expense as well as other power operation expenses related to the State Line Combined Cycle Unit.

        Maintenance and repair expense increased $5.1 million (68.4%) for the six months ended June 30, 2002 compared to the same period in 2001 primarily due to the maintenance contracts entered into in July 2001. Depreciation and amortization expense decreased approximately $1.8 million (12.2%) during the six-month period due to the lower depreciation rates put into effect during the fourth quarter of 2001. Total provisions for income taxes increased $4.3 million (201.7%) due to an increase in taxable income in the second quarter of 2002 and to the benefit created by the deductibility of approximately $6.1 million in merger related expenses taken in the first quarter of 2001. Other taxes increased approximately $0.8 million (11.8%) for the six months ended June 30, 2002 due mainly to increased property taxes.

        Twelve Months Ended June 30, 2002.    During the twelve months ended June 30, 2002, total operating expenses decreased approximately $1.5 million (0.9%) compared to the same period in 2001. Total purchased power costs decreased by approximately $16.2 million (22.5%) primarily due to decreased demand in the third and fourth quarters 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. Total fuel costs increased approximately $9.5 million (18.3%) during the twelve-month period because of increased generation and the need to use our higher-cost gas-fired turbines as a replacement for our lower-cost coal units during the 13 week outage at the Asbury plant during the fourth quarter of 2001, the 10-week outage at the Iatan plant in the first quarter of 2002 and the three-week outage at the Asbury plant in the second quarter of 2002. Merger related expenses increased $0.1 million (5.2%) during the twelve months ended June 2002 as compared to the same period in 2001 due to expenses related to severance benefits during the first quarter of 2002.

        Other operating expenses increased approximately $5.2 million (15.0%) during the twelve months ended June 30, 2002, compared to the same period last year due to increased transmission expense

15

resulting from the delivery of purchased energy to our system, administrative and general expense, 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 repair expenses increased approximately $9.7 million (67.3%) during the twelve months ended June 30, 2002 compared to the prior period primarily due to the maintenance contracts entered into in July 2001 as well as maintenance costs associated with the Asbury outages. Depreciation and amortization expense decreased approximately $0.8 million (2.8%) due to the lower depreciation rates put into effect during the fourth quarter of 2001. Total provision for income taxes decreased $0.7 million (10.5%) due to lower taxable income during the current period. Other taxes increased approximately $1.0 million (7.5%) due mainly to increased property taxes.

Nonoperating Items

        Total allowance for funds used during construction (AFUDC) decreased significantly during each of the periods presented, reflecting the completion of the State Line Combined Cycle Unit in June 2001.

        Other-net deductions decreased slightly in the second quarter of 2002 but increased $0.6 million during the six months ended June 30, 2002 and $1.1 million during the twelve months ended June 30, 2002 primarily due to non-utility operations. A $0.4 million loss in the third quarter 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 also contributed to the increase for the twelve-month period. 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 disallowed costs were part of a stipulated agreement approved by the Missouri Public Service Commission in connection with our recent rate case and will not be recovered in rates. The net effect on twelve months ended June 30, 2002 earnings after considering the tax effect on this write-down was $2.5 million.

        Interest charges on long-term debt were virtually the same for the second quarter of 2002 as compared to the same period last year. Interest charges on long-term debt increased $0.7 million for the six months ended June 30, 2002 and $2.8 million for the twelve months ended period when compared to the same periods last year due to the interest related to our Trust Preferred Securities issued on March 1, 2001. Commercial paper interest decreased $0.2 million during the second quarter, $1.2 million for the six months ended June 30, 2002 and $1.6 million for the twelve months ended June 30, 2002, as compared to the same periods ended in 2001. These decreases in commercial paper interest reflect the completion of the State Line Combined Cycle Unit in June 2001, which we financed in part on an interim basis using short-term debt, as well as lower interest rates.

Earnings

        For the second quarter of 2002, earnings per share of common stock were $0.19 compared to $0.04 during the second quarter of 2001. Earnings per share were up primarily as a result of increased demand resulting from favorable weather conditions and the October 2001 Missouri rate increase.

        Earnings per share for the six months ended June 30, 2002, were $0.17 compared to $0.17 for the six months ended a year earlier. Although revenues increased in the first six months of 2002 due to the October 2001 increase in Missouri rates, earnings per share remained flat primarily due to comparatively milder temperatures during the first quarter of 2002, significantly lower AFUDC due to the completion of the State Line Combined Cycle Unit and increased maintenance costs. Earnings in

16

the first quarter of 2001 were also positively impacted by a one-time $2.3 million income tax benefit resulting from the $6.1 million in merger costs that became tax deductible upon termination of the merger in the first quarter of 2001. Excluding $1.5 million in merger costs for the first six months of 2002 and $1.2 million for the first six months of 2001 and the one-time income tax benefit, earnings per share would have been $0.25 for the six months ended June 30, 2002 and $0.11 for the six months ended June 30, 2001.

        For the twelve months ended June 30, 2002, earnings per share of common stock were $0.57 compared to $1.17 for the twelve months ended a year earlier. Although revenues increased during the twelve months ended June 30, 2002 due to the October 2001 increase in Missouri rates, earnings per share decreased primarily due to mild temperatures during the third and fourth quarters of 2001 and the first quarter of 2002, significantly lower AFUDC due to the completion of the State Line Combined Cycle Unit and increased maintenance costs. 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 in the third quarter of 2001 also contributed to the decrease. Excluding $1.7 million in merger costs for the twelve months ended June 2002 and $1.6 million in merger costs for the twelve months ended June 2001, the $2.5 million one-time write-down of construction expenditures and the tax benefit from merger expenses that became deductible in the first quarter of 2001, earnings per share would have been $0.79 and $1.13 respectively.

LIQUIDITY AND CAPITAL RESOURCES

        Our construction-related expenditures totaled $19.5 million during the second quarter of 2002 compared to $23.0 million for the same period in 2001. For the six months ended June 30, 2002, construction-related expenditures totaled $34.7 million compared to $46.7 million for the same period in 2001. Approximately $6.2 million of these expenditures during the second quarter of 2002 and $11.2 million during the first six months of 2002 were related to additions to our distribution and transmission systems. Approximately $7.6 million during the second quarter of 2002 and $11.6 million during the first six months of 2002 were related to the Energy Center aero units discussed below. Approximately $1.5 million during the second quarter of 2002 and $1.9 million during the first six months of 2002 were related to work at the Asbury Plant, including the replacement of the main transformer during the second quarter. Approximately $0.7 million during the second quarter of 2002 and $0.8 million during the first six months of 2002 were related to miscellaneous plant additions for the State Line Combined Cycle Unit while $0.4 million during the second quarter of 2002 and $1.4 million during the first six months of 2002 were related to our investment in fiber optics cable and equipment. During the second quarter of 2002, less than 1% of our construction expenditures were paid with funds provided internally from operations while 19% of our construction expenditures for the first six 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 are scheduled to be delivered in October 2002 and to be operational by mid-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. In addition, we estimate that our construction expenditures for 2003, 2004 and 2005 will

17

be approximately $71, $67 and $76 million respectively (including AFUDC). These amounts have changed from our previous estimates primarily due to an accelerated schedule for installation of the two Twin Pac aero units to be installed at the Empire Energy Center as 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.

        We currently expect that internally generated funds will provide approximately 68-77% 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 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 proceeds of approximately $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 and issuance costs of approximately $2.4 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 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 will be 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).

        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. 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 June 30, 2002 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.

18

        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.

Contractual Obligations

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

        *We also have guaranteed $1.6 million in outstanding loans as a result of our acquisition of Mid-America Precision Products, LLC on July 18, 2002. $0.35 million of these loans are required to be paid within one year with the remainder to be paid over a five-year period. Reference is made to Note 3—Subsequent Event under Notes to Consolidated Financial Statements (Unaudited).

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 (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.

        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, will be refunded to

19

the customers with interest equal to the current prime rate at that time. At June 30, 2002, we had recorded a liability of approximately $12.1 million of the IEC collected in the fourth quarter of 2001 and the first and second quarters of 2002 as a provision for rate refunds and are not recognizing that revenue in total electric operating revenue.

        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 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.

20

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 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.

21

PART II.    OTHER INFORMATION

Item 4.    Submission of Matters to a Vote of Security Holders.

(a)

The annual meeting of our common stockholders was held on April 25, 2002.



(b)

The following persons were re-elected Directors of Empire to serve until the 2005 Annual Meeting of Stockholders:

M. F. Chubb (16,766,306 votes for; 322,699 withheld authority).
R. L. Lamb (16,620,893 votes for; 468,112 withheld authority).

The following person was elected Director of Empire to serve until the 2005 Annual Meeting of Stockholders:

W. L. Gipson (16,833,038 votes for; 255,967 withheld authority).

The term of office as Director of the following other Directors continued after the meeting: F. E. Jeffries, J. S. Leon, R. D. Hammons, R. C. Hartley, J. R. Herschend, M. W. McKinney and M. M. Posner.

Item 5.    Other Information.

        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.

        At June 30, 2002, the Company's ratio of earnings to fixed charges was 1.46x. See Exhibit (12) hereto.

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.

(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 May 15, 2002, Empire filed, under Item 5. "Other Events," a press release relating to Empire's rate increase for its Missouri water customers, a press release relating to a unanimous stipulation and agreement Empire filed with the Missouri Public Service Commission and the unanimous stipulation and agreement.



(2)

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.

22

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.

23

QuickLinks

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.
Item 5. Other Information.
Item 6. Exhibits and Reports on Form 8-K.