Attached files

file	filename
EX-23 - EXHIBIT 23 - EMPIRE DISTRICT ELECTRIC CO	a2196568zex-23.htm
EX-21 - EXHIBIT 21 - EMPIRE DISTRICT ELECTRIC CO	a2196568zex-21.htm
EX-12 - EXHIBIT 12 - EMPIRE DISTRICT ELECTRIC CO	a2196568zex-12.htm
EX-31.(B) - EXHIBIT 31(B) - EMPIRE DISTRICT ELECTRIC CO	a2196568zex-31_b.htm
EX-31.(A) - EXHIBIT 31(A) - EMPIRE DISTRICT ELECTRIC CO	a2196568zex-31_a.htm
EX-32.(B) - EXHIBIT 32(B) - EMPIRE DISTRICT ELECTRIC CO	a2196568zex-32_b.htm
EX-32.(A) - EXHIBIT 32(A) - EMPIRE DISTRICT ELECTRIC CO	a2196568zex-32_a.htm
EX-24 - EXHIBIT 24 - EMPIRE DISTRICT ELECTRIC CO	a2196568zex-24.htm

        Our all-time peak of 73,271 mcfs was established on January 7, 2010, replacing the previous record of 70,820 mcfs which was set on January 4, 2010.

Construction Program

        Total property additions (including construction work in progress), excluding AFUDC, for the three years ended December 31, 2009, amounted to $527.1 million and retirements during the same period amounted to $39.6 million. Please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources" for more information.

        Our total capital expenditures, excluding AFUDC and expenditures to retire assets, were $140.8 million in 2009 and for the next three years are estimated for planning purposes to be as follows:

        Construction expenditures for new generating facilities and additions to our transmission and distribution systems to meet projected increases in customer demand constitute the majority of the projected capital expenditures for the three-year period listed above.

        A new combustion turbine previously scheduled to be installed by the summer of 2011 is currently delayed until 2015 as our generation regulation needs are being met through a combination of our existing units and the SPP energy imbalance market.

        Estimated capital expenditures are reviewed and adjusted for, among other things, revised estimates of future capacity needs, the cost of funds necessary for construction and the availability and cost of alternative power. Actual capital expenditures may vary significantly from the estimates due to a number of factors including changes in customer requirements, construction delays, changes in equipment delivery schedules, ability to raise capital, environmental matters, the extent to which we receive timely and adequate rate increases, the extent of competition from independent power producers and cogenerators, other changes in business conditions and changes in legislation and regulation, including those relating to the energy industry. See " — Regulation" below and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Competition."

Fuel and Natural Gas Supply

Electric Segment

        In 2009, 55.1% of our total system input, based on kilowatt-hours generated, was supplied by our steam and combustion turbine generation units, 1.3% was supplied by our hydro generation, and we

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purchased the remaining 43.6%. Approximately 69.8% of the total fuel requirements for our generating units in 2009 (based on kilowatt-hours generated) were supplied by coal and approximately 29.8% supplied by natural gas with fuel oil and tire-derived fuel (TDF), which is produced from discarded passenger car tires, providing the remainder. The amount and percentage of electricity generated by natural gas decreased in 2009 as compared to 2008 while the amount of energy we purchased increased, primarily reflecting that it was more economical to purchase power during this period than to produce gas-fired generation and reflecting increased purchases of power under our two contracts with windfarms. We offset the cost of these contracts by purchasing less higher-priced power from other suppliers or by displacing on-system generation.

        Our Asbury Plant is fueled primarily by coal with oil being used as start-up fuel and TDF being used as a supplement fuel. In 2009, Asbury burned a coal blend consisting of approximately 86.8% Western coal (Powder River Basin) and 13.2% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2009, we had sufficient coal on hand to supply anticipated requirements at Asbury for up to 95 days, as compared to 96-97 days as of December 31, 2008, depending on the actual blend ratio within this range.

        Our Riverton Plant fuel requirements are primarily met by coal with the remainder supplied by natural gas, petroleum coke and oil. We installed a Siemens V84.3A2 gas combustion turbine (Unit 12) at our Riverton plant in 2007. Riverton Unit 12 and three other smaller units are fueled by natural gas. During 2009, Riverton Units 7 and 8 burned an estimated blend of approximately 82.1% Western coal (Powder River Basin) and 17.9% petroleum coke on a tonnage basis. Our average coal inventory target at Riverton is approximately 60 days. Riverton Unit 7 requires a minimum amount of blend fuel to operate, while Riverton Unit 8 can burn 100% Western coal or a mix of Western and blend fuel. Based on these assumptions, we had sufficient coal as of December 31, 2009 to run 36 days on both units as compared to 43 days as of December 31, 2008.

        We have secured 98% of our anticipated coal requirements for 2010, 59% for 2011, 28% for 2012 and 30% for 2013 through a combination of contracts and binding proposals. All of the Western coal is shipped to the Asbury Plant by rail, a distance of approximately 800 miles, under a five-year contract with the Burlington Northern and Santa Fe Railway Company (BNSF) and the Kansas City Southern Railway Company which expires on June 29, 2010. We are currently in the process of selecting a vendor to provide future rail service. The overall delivered price of coal is expected to be slightly higher in 2010 than in 2009 due to increased market costs. Riverton receives its Western inventory from the coal transported by train to the Asbury Plant which is then transported by truck to Riverton.

        We currently lease one aluminum unit train on a full time basis and a second set is leased on an interim basis to deliver Western coal to the Asbury Plant. During the third quarter of 2009, we entered into a 15 year lease agreement for 54 railcars for our Plum Point plant, which is scheduled to be completed in the summer of 2010.

        Unit 1 at the Iatan Plant is a coal-fired generating unit which is jointly-owned by KCP&L, a subsidiary of Great Plains Energy, Inc. and us, with our share of ownership being 12%. KCP&L is the operator of this plant and is responsible for arranging its fuel supply. KCP&L has secured contracts for low sulfur Western coal in quantities sufficient to meet 95% of Iatan's requirements for 2010 and approximately 40% for 2011, 40% for 2012, 40% for 2013 and 25% for 2014. The coal is transported by rail under a contract with BNSF Railway, which expires on December 31, 2010.

        Our Energy Center and State Line combustion turbine facilities (not including the State Line Combined Cycle (SLCC) Unit, which is fueled 100% by natural gas) are fueled primarily by natural gas with oil also available for use primarily as backup. Based on kilowatt hours generated during 2009, Energy Center generation was 99.8% natural gas with the remainder being fuel oil, and essentially all of the State Line Unit 1 generation came from natural gas. As of December 31, 2009, oil inventories were sufficient for approximately 2 days of full load operation on Units No. 1, 2, 3 and 4 at the Energy Center and 5 days of

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full load operation for State Line Unit No. 1. As typical oil usage is minimal, these inventories are sufficient for our current requirements. Additional oil will be purchased as needed.

        We have firm transportation agreements with Southern Star Central Pipeline, Inc. with original expiration dates of July 31, 2016, for the transportation of natural gas to the SLCC. This date is adjusted for periods of contract suspension by us during outages of the SLCC. This transportation agreement can also supply natural gas to State Line Unit No.1, the Energy Center or the Riverton Plant, as elected by us on a secondary basis. We also have a precedent agreement with Southern Star, which provides additional transportation capability until 2022. This contract provides firm transport to the sites listed above that previously were only served on a secondary basis. We expect that these transportation agreements will serve nearly all of our natural gas transportation needs for our generating plants over the next several years. Any remaining gas transportation requirements, although small, will be met by utilizing capacity release on other holder contracts, interruptible transport, or delivered to the plants by others. The majority of our physical natural gas supply requirements will be met by short-term forward contracts and spot market purchases. Forward natural gas commodity prices and volumes are hedged several years into the future in accordance with our Risk Management Policy in an attempt to lessen the volatility in our fuel expenditures and gain predictability.

        We have signed an agreement with Southern Star to purchase one million Dths of firm gas storage service capacity for a period of five years beginning in April 2011. The reservation charge for this storage capacity is approximately $1.1 million annually. This storage capacity will enable us to better manage our natural gas commodity and transportation needs for our electric segment.

        The following table sets forth a comparison of the costs, including transportation and other miscellaneous costs, per million Btu of various types of fuels used in our electric facilities:

        Our weighted average cost of fuel burned per kilowatt-hour generated was 3.1698 cents in 2009, 3.1307 cents in 2008 and 3.2197 cents in 2007.

Gas Segment

        In June 2007, we acquired 10,000 MMBtus per day of firm transportation from Cheyenne Plains Pipeline Company so that up to 75% of our natural gas purchases going forward could come from the Rocky Mountain gas area. Cheyenne Plains interconnects with all of the interstate pipelines listed below that feed our market area.

        We have agreements with many of the major suppliers in both the Midcontinent and Rocky Mountain regions that provide us with both supply and price diversity. We expanded our supplier base in 2008 and will continue to do so to enhance supply reliability as well as provide for increased price competition.

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        The following table sets forth the current costs, including storage, transportation and other miscellaneous costs, per mcf of gas used in our gas operations:

Employees

        At December 31, 2009, we had 730 full-time employees, including 54 employees of EDG. 328 of the EDE employees are members of Local 1474 of The International Brotherhood of Electrical Workers (IBEW). On May 9, 2007, the Local 1474 IBEW voted to ratify a new five-year agreement effective retroactively to November 1, 2006, the expiration date of the last contract. At December 31, 2008, 26 of the EDG employees were members of Local 814 of the IBEW and 8 EDG employees were members of Local 695 of the IBEW. Effective January 1, 2009, both of these locals were merged into Local 1464 of the IBEW, of which 36 EDG employees were members at December 31, 2009. Local 814 of the IBEW and Local 695 of the IBEW had both previously ratified a three-year contract with EDG which expired on May 31, 2009. In June 2009, Local 1464 of the IBEW ratified a new four-year agreement with EDG effective June 1, 2009.

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ELECTRIC OPERATING STATISTICS⁽¹⁾

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GAS OPERATING STATISTICS⁽¹⁾

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Executive Officers and Other Officers of Empire

        The names of our officers, their ages and years of service with Empire as of December 31, 2009, positions held and effective date of such positions are presented below. All of our officers have been employed by Empire for at least the last five years.

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Regulation

Electric Segment

        General.    As a public utility, our electric segment operations are subject to the jurisdiction of the MPSC, the State Corporation Commission of the State of Kansas (KCC), the Corporation Commission of Oklahoma (OCC) and the Arkansas Public Service Commission (APSC) with respect to services and facilities, rates and charges, regulatory accounting, valuation of property, depreciation and various other matters. Each such Commission has jurisdiction over the creation of liens on property located in its state to secure bonds or other securities. The KCC also has jurisdiction over the issuance of all securities because we are a regulated utility incorporated in Kansas. Our transmission and sale at wholesale of electric energy in interstate commerce and our facilities are also subject to the jurisdiction of the FERC, under the Federal Power Act. FERC jurisdiction extends to, among other things, rates and charges in connection with such transmission and sale; the sale, lease or other disposition of such facilities and accounting matters. See discussion in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Competition."

        During 2009, approximately 90.9% of our electric operating revenues was received from retail customers. Sales subject to FERC jurisdiction represented approximately 8.0% of our electric operating revenues during 2009 with the remaining 1.1% being from miscellaneous sources. The percentage of retail revenues derived from each state follows:

        Rates.    See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Rate Matters" for information concerning recent electric rate proceedings.

        Fuel Adjustment Clauses.    Typical fuel adjustment clauses permit the distribution to customers of changes in fuel costs without the need for a general rate proceeding. Fuel adjustment clauses are presently applicable to our retail electric sales in Missouri (effective September 1, 2008), Oklahoma and Kansas (effective January 1, 2006) and system wholesale kilowatt-hour sales under FERC jurisdiction. We have an Energy Cost Recovery Rider in Arkansas that adjusts for changing fuel and purchased power costs on an annual basis.

Gas Segment

        General.    As a public utility, our gas segment operations are subject to the jurisdiction of the MPSC with respect to services and facilities, rates and charges, regulatory accounting, valuation of property, depreciation and various other matters. The MPSC also has jurisdiction over the creation of liens on property to secure bonds or other securities.

        Purchased Gas Adjustment (PGA).    The PGA clause allows EDG to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, including costs associated with our use of natural gas financial instruments to hedge the purchase price of natural gas and related carrying costs. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.

Environmental Matters

        See Note 11 to the consolidated financial statements for information regarding environmental matters.

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Conditions Respecting Financing

        Our EDE Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the EDE Mortgage), and our Restated Articles of Incorporation (Restated Articles), specify earnings coverage and other conditions which must be complied with in connection with the issuance of additional first mortgage bonds or cumulative preferred stock, or the incurrence of unsecured indebtedness. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage) for any twelve consecutive months within the fifteen months preceding issuance must be two times the annual interest requirements (as defined in the EDE Mortgage) on all first mortgage bonds then outstanding and on the prospective issue of new first mortgage bonds. Our earnings for the year ended December 31, 2009, would permit us to issue approximately $239.9 million of new first mortgage bonds based on this test at an assumed interest rate of 7.0%. In addition to the interest coverage requirement, the EDE Mortgage provides that new bonds must be issued against, among other things, retired bonds or 60% of net property additions. At December 31, 2009, we had retired bonds and net property additions which would enable the issuance of at least $644.8 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2009, we believe we are in compliance with all restrictive covenants of the EDE Mortgage.

        Under our Restated Articles, (a) cumulative preferred stock may be issued only if our net income available for interest and dividends (as defined in our Restated Articles) for a specified twelve-month period is at least 1¹/2 times the sum of the annual interest requirements on all indebtedness and the annual dividend requirements on all cumulative preferred stock to be outstanding immediately after the issuance of such additional shares of cumulative preferred stock, and (b) so long as any preferred stock is outstanding, the amount of unsecured indebtedness outstanding may not exceed 20% of the sum of the outstanding secured indebtedness plus our capital and surplus. We have no outstanding preferred stock. Accordingly, the restriction in our Restated Articles does not currently restrict the amount of unsecured indebtedness that we may have outstanding.

        The EDG Indenture of Mortgage and Deed of Trust, dated as of June 1, 2006, as amended and supplemented (the EDG Mortgage) contains a requirement that for new first mortgage bonds to be issued, the amount of such new first mortgage bonds shall not exceed 75% of the cost of property additions acquired after the date of the Missouri Gas acquisition. The mortgage also contains a limitation on the issuance by EDG of debt (including first mortgage bonds, but excluding short-term debt incurred in the ordinary course under working capital facilities) unless, after giving effect to such issuance, EDG's ratio of EBITDA (defined as net income plus interest, taxes, depreciation, amortization and certain other non-cash charges) to interest charges for the most recent four fiscal quarters is at least 2.0 to 1. As of December 31, 2009, this test would not allow us to issue new first mortgage bonds.

        See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources."

Our Web Site

        We maintain a web site at www.empiredistrict.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on form 8-K and related amendments are available free of charge through our web site as soon as reasonably practicable after such reports are filed with or furnished to the SEC electronically. Our Corporate Governance Guidelines, our Code of Business Conduct and Ethics, our Code of Ethics for the Chief Executive Officer and Senior Financial Officer, the charters for our Audit Committee, Compensation Committee and Nominating/Corporate Governance Committee, our Procedures for Reporting Complaints on Accounting, Internal Accounting Controls and Auditing Matters, our Procedures for Communicating with Non-Management Directors and our Policy and Procedures with Respect to Related Person Transactions can also be found on our web site. All of these documents are available in print to any interested party who requests them. Our web site and the information contained in it and connected to it shall not be deemed incorporated by reference into this Form 10-K.

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ITEM 1A.    RISK FACTORS

        Investors should review carefully the following risk factors and the other information contained in this Form 10-K. The risks we face are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect our financial position, results of operations and liquidity.

        Readers are cautioned that the risks and uncertainties described in this Form 10-K are not the only ones facing Empire. Additional risks and uncertainties that we are not presently aware of, or that we currently consider immaterial, may also affect our business operations. Our business, financial condition or results of operations (including our ability to pay dividends on our common stock) could suffer if the concerns set forth below are realized.

Any reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.

        Currently, our corporate credit ratings and the ratings for our securities are as follows:

        The ratings indicate the agencies' assessment of our ability to pay interest, distributions and principal on these securities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. In addition, a downgrade in our senior unsecured long-term debt rating would result in an increase in our borrowing costs under our bank credit facility. If any of our ratings fall below investment grade (investment grade is defined as Baa3 or above for Moody's and BBB- or above for Standard & Poor's and Fitch), our ability to issue short-term debt, commercial paper or other securities or to market those securities would be impaired or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on our business, financial condition and results of operations. In addition, any actual downgrade of our commercial paper rating from Moody's or Fitch, may make it difficult for us to issue commercial paper. To the extent we are unable to issue commercial paper, we will need to meet our short-term debt needs through borrowings under our revolving credit facility, which may result in higher costs.

        We cannot assure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.

We are exposed to increases in costs and reductions in revenue which we cannot control and which may adversely affect our business, financial condition and results of operations.

        The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) general economic conditions. Of the factors driving revenues, weather has the greatest short-term effect on the demand for electricity for our regulated business. Mild weather reduces demand and, as a result, our electric operating revenues. In addition, changes in customer demand due to downturns in the economy could reduce our revenues.

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        The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expenses, (2) maintenance and repairs expense, including repairs following severe weather and plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Although we generally recover these expenses through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in future rate cases.

        The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our natural gas service territory and a significant amount of our natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our natural gas operations have historically generated less revenues and income when weather conditions are warmer in the winter.

        The primary driver of our gas operating expense in any period is the price of natural gas.

        Significant increases in electric and gas operating expenses or reductions in electric and gas operating revenues may occur and result in a material adverse effect on our business, financial condition and results of operations.

We are exposed to factors that can increase our fuel and purchased power expenditures, including disruption in deliveries of coal or natural gas, decreased output from our power plants, failure of performance by purchased power counterparties and market risk in our fuel procurement strategy.

        Fuel and purchased power costs are our largest expenditures. Increases in the price of coal, natural gas or the cost of purchased power will result in increased electric operating expenditures.

        We depend upon regular deliveries of coal as fuel for our Riverton, Asbury and Iatan plants, and as fuel for the facility which supplies us with purchased power under our contract with Westar Energy. Substantially all of this coal comes from mines in the Powder River Basin of Wyoming and is delivered to the plants by train. Production problems in these mines, railroad transportation or congestion problems, or unavailability of trains could affect delivery cycle times required to maintain plant inventory levels, causing us to implement coal conservation and supply replacement measures to retain adequate reserve inventories at our facilities. These measures could include some or all of the following: reducing the output of our coal plants, increasing the utilization of our higher-cost gas-fired generation facilities, purchasing power from other suppliers, adding additional leased trains to our supply system and purchasing locally mined coal which can be delivered without using the railroads. Such measures could result in increased fuel and purchased power expenditures.

        With the addition of the Missouri fuel adjustment mechanism effective September 1, 2008, we now have a fuel cost recovery mechanism in all of our jurisdictions, which significantly reduces our net income exposure to the impact of the risks discussed above. However, cash flow could still be impacted by these increased expenditures. We are also subject to prudency reviews which could negatively impact our net income if a regulatory commission would conclude our costs were incurred imprudently.

        We have also established a risk management practice of purchasing contracts for future fuel needs to meet underlying customer needs and manage cost and pricing uncertainty. Within this activity, we may incur losses from these contracts. By using physical and financial instruments, we are exposed to credit risk and market risk. Market risk is the exposure to a change in the value of commodities caused by fluctuations in market variables, such as price. The fair value of derivative financial instruments we hold is adjusted cumulatively on a monthly basis until prescribed determination periods. At the end of each determination period, which is the last day of each calendar month in the period, any realized gain or loss for that period related to the contract will be reclassified to fuel expense and recovered or refunded to the customer

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through our fuel adjustment mechanisms. Credit risk is the risk that the counterparty might fail to fulfill its obligations under contractual terms.

We may be unable to recover increases in the cost of natural gas from our natural gas utility customers, or may lose customers as a result of any price increases.

        In our natural gas utility business, we are permitted to recover the cost of gas directly from our customers through the use of a purchased gas adjustment provision. Our purchased gas adjustment provision is regularly reviewed by the MPSC. In addition to reviewing our adjustments to customer rates, the MPSC reviews our costs for prudency as well. To the extent the MPSC may determine certain costs were not incurred prudently, it could adversely affect our gas segment earnings and cash flows. In addition, increases in natural gas costs affect total prices to our customers and, therefore, the competitive position of gas relative to electricity and other forms of energy. Increases in natural gas costs may also result in lower usage by customers unable to switch to alternate fuels. Such disallowed costs or customer losses could have a material adverse effect on our business, financial condition and results of operations.

We are subject to regulation in the jurisdictions in which we operate.

        We are subject to comprehensive regulation by federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility commissions in the states where we operate regulate many aspects of our utility operations, including the rates that we can charge customers, siting and construction of facilities, pipeline safety and compliance, customer service and our ability to recover increases in our fuel and purchased power costs.

        The FERC has jurisdiction over wholesale rates for electric transmission service and electric energy sold in interstate commerce. Federal, state and local agencies also have jurisdiction over many of our other activities.

        Information concerning recent filings requesting increases in rates and related matters is set forth under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Rate Matters."

        We are unable to predict the impact on our operating results from the regulatory activities of any of these agencies. Despite our requests, these regulatory commissions have sole discretion to leave rates unchanged, grant increases or order decreases in the base rates we charge our utility customers. They have similar authority with respect to our recovery of increases in our fuel and purchased power costs. If our costs increase and we are unable to recover increased costs through base rates or fuel adjustment clauses, or if we are unable to fully recover our investments in new facilities, our results of operations could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have a material adverse effect on our results of operations.

Operations risks may adversely affect our business and financial results.

        The operation of our electric generation, and electric and gas transmission and distribution systems involves many risks, including breakdown or failure of expensive and sophisticated equipment, processes and personnel performance; operating limitations that may be imposed by equipment conditions, environmental or other regulatory requirements; fuel supply or fuel transportation reductions or interruptions; transmission scheduling constraints; and catastrophic events such as fires, explosions, severe weather or other similar occurrences.

        We have implemented training, preventive maintenance and other programs, but there is no assurance that these programs will prevent or minimize future breakdowns, outages or failures of our generation facilities. In those cases, we would need to either produce replacement power from our other facilities or

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purchase power from other suppliers at potentially volatile and higher cost in order to meet our sales obligations.

        These and other operating events may reduce our revenues, increase costs, or both, and may materially affect our results of operations, financial position and cash flows.

Financial market disruptions may increase financing costs, limit access to the credit markets or cause reductions in investment values in our pension plan assets.

        General market declines in 2008 and early 2009, resulting in part from the sub-prime mortgage issues, have generally reduced access to the capital markets. We estimate our capital expenditures to be $110.9 million in 2010. Although we believe it is unlikely we will have difficulty accessing the markets for the capital needed to complete these projects, financing costs could fluctuate. Market conditions in 2008 negatively impacted the return on our pension plan and Other Postretirement Benefits (OPEB) assets in 2008. Our net pension and OPEB liability increased $68.7 million in 2008. The market recovered in 2009, however our costs also increased, resulting in a $0.7 million increase in our 2009 net pension and OPEB liability. We expect to be required to fund approximately $15.2 million in 2010 for pension and OPEB liabilities. Future market declines could result in increased pension and OPEB liabilities and funding obligations.

The cost and schedule of construction projects may materially change.

        We have entered into an agreement to purchase an undivided interest in 50 megawatts (7.5% ownership interest) of the Plum Point Energy Station's new 665-megawatt, coal-fired generating facility, scheduled for completion in the summer of 2010. We have also entered into an agreement with KCP&L to purchase an undivided ownership interest in the coal-fired Iatan 2 generating facility, scheduled for completion in the fall of 2010. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit.

        There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than currently planned, the scope and timing of projects may change, and other events beyond our control, including the failure of one or more of the generation plant co-owners to pay their share of construction, operations and maintenance costs, may occur that may materially affect the schedule, budget, cost and performance of these projects. To the extent the completion of these projects is delayed, we expect that the timing of receipt of increases in base rates reflecting our investment in such projects will be correspondingly delayed. Costs associated with these projects will also be subject to prudency review by regulators as part of future rate case filings.

We are subject to environmental laws and the incurrence of environmental liabilities which may adversely affect our business, financial condition and results of operations.

        We are subject to extensive federal, state and local regulation with regard to air and other environmental matters. Failure to comply with these laws and regulations could have a material adverse effect on our results of operations and financial position. In addition, new environmental laws and regulations, and new interpretations of existing environmental laws and regulations, have been adopted and may in the future be adopted which may substantially increase our future environmental expenditures for both new facilities and our existing facilities. Compliance with current and future air emission standards (such as those limiting emission levels of sulfur dioxide (SO2) and nitrogen oxide (NOx) and, potentially, carbon dioxide (CO2)) has required, and may in the future require, significant environmental expenditures. Although we have historically recovered such costs through our rates, there can be no assurance that we will recover all, or any part of, such increased costs in future rate cases. The incurrence of additional material environmental costs which are not recovered in our rates may result in a material adverse effect on our business, financial condition and results of operations.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

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ITEM 2.    PROPERTIES

Electric Segment Facilities

        At December 31, 2009, we owned generating facilities with an aggregate generating capacity of 1,257 megawatts.

        Our principal electric baseload generating plant is the Asbury Plant with 207 megawatts of generating capacity. The plant, located near Asbury, Missouri, is a coal-fired generating station with two steam turbine generating units. The plant presently accounts for approximately 16% of our owned generating capacity and in 2009 accounted for approximately 41.2% of the energy generated by us. Routine plant maintenance, during which the entire plant is taken out of service, is scheduled once each year, normally for approximately four weeks in the spring. Approximately every fifth year, the maintenance outage is scheduled to be extended to a total of six weeks to permit inspection of the Unit No. 1 turbine. The last such outage took place in the fall of 2007. The Unit No. 2 turbine is inspected approximately every 35,000 hours of operations and was last inspected in 2001. As of December 31, 2009, Unit No. 2 has operated approximately 2,862 hours since its last turbine inspection in 2001. When the Asbury Plant is out of service, we typically experience increased purchased power and fuel expenditures associated with replacement energy, which is now likely to be recovered through our fuel adjustment clauses.

        Our generating plant located at Riverton, Kansas, has two steam-electric generating units (Units 7 and 8) with an aggregate generating capacity of 92 megawatts and four gas-fired combustion turbine units (Units 9, 10, 11 and 12) with an aggregate generating capacity of 194 megawatts. The steam-electric generating units burn coal as a primary fuel and have the capability of burning natural gas. We installed a Siemens V84.3A2 combustion turbine (Unit 12) at our Riverton plant in 2007 with a summer rated capacity of 150 megawatts. It began commercial operation on April 10, 2007.

        We own a 12% undivided interest in the coal-fired Unit No. 1 at the Iatan Generating Station located near Weston, Missouri, 35 miles northwest of Kansas City, Missouri, as well as a 3% interest in the site and a 12% interest in certain common facilities. A new air permit was issued for the Iatan Generating Station on January 31, 2006. The new permit covers the entire Iatan Generating Station and includes the existing Unit No. 1 and Unit No. 2, currently under construction. Iatan 1 began a planned major maintenance outage on October 18, 2008 which included activities ranging from a turbine upgrade and generator rewind to the tie-in of the new air quality control systems. Once all the outage work was complete, start-up and commissioning activities began in late January. In early February, vibration issues with the upgraded high pressure turbine were encountered requiring the turbine to be shipped off-site for repairs, delaying the unit's return to service until the second quarter of 2009. KCP&L reported the emission control equipment had met regulatory in-service criteria as of April 19, 2009 and it is currently in service. We are entitled to 12% of the unit's available capacity, currently 85 megawatts, and are obligated to pay for that percentage of the operating costs of the unit. KCP&L operates the unit for the joint owners.

        Our State Line Power Plant, which is located west of Joplin, Missouri, consists of Unit No. 1, a combustion turbine unit with generating capacity of 96 megawatts and a Combined Cycle Unit with generating capacity of 500 megawatts of which we are entitled to 60%, or 300 megawatts. The Combined Cycle Unit consists of the combination of two combustion turbines, two heat recovery steam generators, a steam turbine and auxiliary equipment. The Combined Cycle Unit is jointly owned with Westar Generating Inc., a subsidiary of Westar Energy, Inc., which owns the remaining 40% of the unit. Westar reimburses us for a percentage of the operating costs per our joint ownership agreement stipulations. We are the operator of the Combined Cycle Unit. All units at our State Line Power Plant burn natural gas as a primary fuel with Unit No. 1 having the additional capability of burning oil. Unit No. 1 had its first major inspection from September 7, 2006 until December 20, 2006.

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        We have four combustion turbine peaking units at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 267 megawatts. These peaking units operate on natural gas, as well as oil.

        Our hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. As part of the Energy and Water Development Appropriations Act of 2006 (the Appropriations Act), a new minimum flow was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this, the level of Bull Shoals Lake will be increased an average of 5 feet. The increase at Bull Shoals will decrease the head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our electrical output. We estimate the lost production to be up to 16% of our average annual energy production for this unit. The loss in this facility would require us to replace it with additional generation from our gas-fired and coal-fired units or with purchased power. The Appropriations Act requires the Southwest Power Administration (SWPA), in coordination with us and our relevant public service commissions, to determine our economic detriment.

        The SWPA published its Final Determination Report on January 23, 2009 documenting the procedure they intended to use to calculate the present value of the future lifetime replacement cost of the electrical energy and capacity lost due to the White River Minimum Flows project at Ozark Beach. The actual hydropower compensation values were to be calculated using the method presented in the Final Determination and current values for the specified parameters based on the official implementation date. Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and November 2008 values for the specified parameters, the SWPA's determination at that time resulted in a present value for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach of $41.3 million. On June 8, 2009, the SWPA published a draft addendum to its January 2009 Final Determination Report documenting proposed changes to the SWPA's methodology, including the inclusion of an additional discount rate source to be used by the SWPA in determination of the present value of the losses. Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and current values for the specified parameters, the SWPA's Draft Addendum to its Final Determination results in a present value of $22.3 million for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach. We and the MPSC have provided comments on the new methodology included in the draft addendum but cannot predict the final outcome. Originally, the Appropriations Act had a provision for the Army Corp of Engineers to provide a one time payment to us for lost energy production. This provision was revised in October 2009 to allow the SWPA to pay for damages through a special disbursement account. Under the revised law, payments must be made annually by SWPA in an amount of at least $5 million until the total damages are reimbursed.

        At December 31, 2009, our transmission system consisted of approximately 22 miles of 345 kV lines, 434 miles of 161 kV lines, 745 miles of 69 kV lines and 81 miles of 34.5 kV lines. Our distribution system consisted of approximately 6,905 miles of line.

        Our electric generation stations are located on land owned in fee. We own a 3% undivided interest as tenant in common in the land for the Iatan Generating Station. We own a similar interest in 60% of the land used for the State Line Combined Cycle Unit. Substantially all of our electric transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) over streets, alleys, highways and other public places, under franchises or other rights; or (3) over private property by virtue of easements obtained from the record holders of title. Substantially all of our electric segment property, plant and equipment are subject to the EDE Mortgage.

        We also own and operate water pumping facilities and distribution systems consisting of a total of approximately 87 miles of water mains in three communities in Missouri.

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Gas Segment Facilities

        At December 31, 2009, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,118 miles of distribution mains.

        Substantially all of our gas transmission and distribution facilities are located either (1) on property leased or owned in fee; (2) under streets, alleys, highways and other public places, under franchises or other rights; or (3) under private property by virtue of easements obtained from the record holders of title. Substantially all of our gas segment property, plant and equipment are subject to the EDG Mortgage.

Other Segment

        Our other segment consists of our non-regulated business, the leasing of fiber optics cable and equipment (which we also use in our own utility operations).

ITEM 3.    LEGAL PROCEEDINGS

        See Note 11 of "Notes to Consolidated Financial Statements" under Item 8, which description is incorporated herein by reference.

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

        None.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

        Our common stock is listed on the New York Stock Exchange. On February 5, 2010, there were 5,044 record holders and 31,905 individual participants in security position listings. The high and low sale prices for our common stock as reported by the New York Stock Exchange for composite transactions, and the amount per share of quarterly dividends declared and paid on the common stock for each quarter of 2009 and 2008 were as follows:

        Holders of our common stock are entitled to dividends, if, as, and when declared by the Board of Directors, out of funds legally available therefore subject to the prior rights of holders of any outstanding cumulative preferred stock and preference stock. Payment of dividends is determined by our Board of Directors after considering all relevant factors, including the amount of our retained earnings, which is essentially our accumulated net income less dividend payouts. As of December 31, 2009, our retained earnings balance was $10.1 million (compared to $13.6 million at December 31, 2008) after paying out $44.8 million in dividends during 2009. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price. On February 4, 2010, the Board of Directors declared a quarterly dividend of $0.32 per share on common stock payable March 15, 2010 to holders of record as of March 1, 2010.

        Under Kansas corporate law, our Board of Directors may only declare and pay dividends out of our surplus or, if there is no surplus, out of our net profits for the fiscal year in which the dividend is declared or the preceding fiscal year, or both. Our surplus, under Kansas law, is equal to our retained earnings plus accumulated other comprehensive income/(loss), net of income tax. However, Kansas law does permit, under certain circumstances, our Board of Directors to transfer amounts from capital in excess of par value to surplus. In addition, Section 305(a) of the Federal Power Act (FPA) prohibits the payment by a utility of dividends from any funds "properly included in capital account". There are no additional rules or regulations issued by the FERC under the FPA clarifying the meaning of this limitation. However, several decisions by the FERC on specific dividend proposals suggest that any determination would be based on a fact-intensive analysis of the specific facts and circumstances surrounding the utility and the dividend in question, with particular focus on the impact of the proposed dividend on the liquidity and financial condition of the utility.

        In addition, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive of these is contained in the EDE Mortgage, which provides that we may not declare or pay any dividends (other than dividends payable in shares of our common stock) or make any other distribution on, or purchase (other than with the proceeds of additional common stock financing) any shares of, our common stock if the cumulative aggregate amount thereof after August 31, 1944 (exclusive of the first quarterly dividend of $98,000 paid after said date) would exceed the sum of $10.75 million and the earned surplus (as defined in the EDE Mortgage) accumulated subsequent to August 31, 1944, or the date of succession in the event that another corporation succeeds to our rights and liabilities by a merger or consolidation. On March 11, 2008, we amended the EDE Mortgage in order to provide us with more flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by

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$10.75 million, as described above. As of December 31, 2009, this restriction did not prevent us from issuing dividends.

        In addition, under certain circumstances, our Junior Subordinated Debentures, 8¹/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust I, an unconsolidated securitization trust subsidiary, may also restrict our ability to pay dividends on our common stock. These restrictions apply if: (1) we have knowledge that an event has occurred that would constitute an event of default under the indenture governing these junior subordinated debentures and we have not taken reasonable steps to cure the event, (2) we are in default with respect to payment of any obligations under our guarantee relating to the underlying preferred securities, or (3) we have deferred interest payments on the Junior Subordinated Debentures, 8¹/2% Series due 2031 or given notice of a deferral of interest payments. As of December 31, 2009, there were no such restrictions on our ability to pay dividends.

        During 2009, no purchases of our common stock were made by or on behalf of us.

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

        Our shareholders rights plan, which expires July 25, 2010, provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of common stock owned. One Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one-hundredth of a share, subject to adjustment. The rights (other than those held by an acquiring person or group (Acquiring Person)) will be exercisable only if an Acquiring Person acquires 10% or more of our common stock or if certain other events occur. See Note 5 of "Notes to Consolidated Financial Statements" under Item 8 for additional information. In addition, we have stock based compensation programs which are described in Note 4 of "Notes to Consolidated Financial Statements" under Item 8.

        Our By-laws provide that K.S.A. Sections 17-1286 through 17-1298, the Kansas Control Share Acquisitions Act, will not apply to control share acquisitions of our capital stock.

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

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        The following graph and table indicates the value at the end of the specified years of a $100 investment made on December 31, 2004, in our common stock and similar investments made in the securities of the companies in the Standard & Poor's 500 Composite Index (S&P 500 Index) and the Standard & Poor's Electric Utilities Index (S&P Electric Utility). The graph and table assume that dividends were reinvested when received.

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ITEM 6.    SELECTED FINANCIAL DATA
(in thousands, except per share amounts)⁽¹⁾

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(1)

2006 through 2005 have been adjusted to show continuing operations, reflecting the sale of MAPP and Conversant in 2006 and Fast Freedom in 2007.

(2)

Includes EDG data for the months of June through December 2006.

(3)

2006 capital expenditures do not include $103.2 million for the acquisition of the Missouri Gas operations.

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

EXECUTIVE SUMMARY

        We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE) is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of our electric segment, we also provide water service to three towns in Missouri. The Empire District Gas Company (EDG) is our wholly owned subsidiary. It provides natural gas distribution to customers in 44 communities in northwest, north central and west central Missouri. Our other segment consists of our fiber optics business. During the year ended December 31, 2009, 87.5% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of water), 11.5% from the sale of gas and 1.0% from our other segment.

Electric Segment

        The primary drivers of our electric operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth and (4) general economic conditions. The utility commissions in the states in which we operate, as well as the Federal Energy Regulatory Commission (FERC), set the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily fuel and purchased power) and/or rate relief. We assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary. Of the factors driving revenues, weather has the greatest short-term effect on the demand for electricity for our regulated business. Very hot summers and very cold winters increase electric demand, while mild weather reduces demand. Residential and commercial sales are impacted more by weather than industrial sales, which are mostly affected by business needs for electricity and by general economic conditions. Customer growth, which is the growth in the number of customers, contributes to the demand for electricity. We expect our annual electric customer growth to range from approximately 1.1% to 1.5% over the next several years. Our electric customer growth for the year ended December 31, 2009 was 0.3%. We define electric sales growth to be growth in kWh sales period over period excluding the impact of weather. The primary drivers of electric sales growth are customer growth and general economic conditions.

        The primary drivers of our electric operating expenses in any period are: (1) fuel and purchased power expense, (2) maintenance and repairs expense, including repairs following severe weather and plant outages, (3) taxes and (4) non-cash items such as depreciation and amortization expense. Historically, fuel and purchased power costs were the expense items that had the most significant impact on our net income. In our 2007 rate case, the Missouri Public Service Commission (MPSC) authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base rate for the recovery of fuel and purchased power expenses used to supply energy. The clause permits the distribution to customers of 95% of the changes in fuel and purchased power costs above or below the base. With the addition of the Missouri fuel adjustment mechanism, we now have a fuel cost recovery mechanism in all of our jurisdictions, which will significantly reduce the impact of fluctuating fuel and purchased power costs on our net income.

Gas Segment

        The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth, (4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge our customers. In order to offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for rate relief and file for such relief when necessary. A PGA clause is included in our gas rates, which allows us to

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recover our actual cost of natural gas from customers through rate changes, which are made periodically (up to four times) throughout the year in response to weather conditions, natural gas costs and supply demands. Weather affects the demand for natural gas. Very cold winters increase demand for gas, while mild weather reduces demand. Due to the seasonal nature of the gas business, revenues and earnings are typically concentrated in the November through March period, which generally corresponds with the heating season. Customer growth, which is the growth in the number of customers, contributes to the demand for gas. Our gas segment customer contraction for the year ended December 31, 2009 was 1.3%, which we believe was due to depressed economic conditions. The rate of gas customer contraction is expected to level out during the next three years and begin modest growth after 2012. We define gas sales growth to be growth in mcf sales excluding the impact of weather. The primary drivers of gas sales growth are customer growth and general economic conditions.

        The primary driver of our gas operating expense in any period is the price of natural gas. However, because gas purchase costs for our gas utility operations are normally recovered from our customers, any change in gas prices does not have a corresponding impact on income unless such costs are deemed imprudent or cause customers to reduce usage.

Earnings

        For the year ended December 31, 2009, basic and diluted earnings per weighted average share of common stock were $1.18 compared to $1.17 for the year ended December 31, 2008. Third quarter 2009 weather was the coolest summer in the past 30 years, which affected both customer demand and generation needs. The resulting lower revenues were the primary driver for lower earnings in 2009 as compared to 2008. Lower fuel and purchased power costs, however, mostly offset the decrease in revenues.

        The table below sets forth a reconciliation of basic and diluted earnings per share between 2008 and 2009, which reconciliation is a non-GAAP presentation. The economic substance behind our non-GAAP earnings per share (EPS) measure is to present the after tax impact of significant items and components of the statement of operations on a per share basis before the impact of additional stock issuances.

        We believe this presentation is useful to investors because the statement of operations does not readily show the EPS impact of the various components, including the effect of new stock issuances. This could limit the readers' understanding of the reasons for the EPS change from previous years. This information is useful to management, and we believe this information is useful to investors, to better understand the reasons for the fluctuation in EPS between the prior and current years on a per share basis.

        This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations. We also note that this presentation does not purport to be an alternative to earnings per share determined in accordance with GAAP as a measure of operating performance or any other measure of financial performance presented in accordance with GAAP. Management compensates for the limitations of using non-GAAP financial measures by using them to

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supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone.

Fourth Quarter Results

        Earnings for the fourth quarter of 2009 were $7.9 million, or $0.22 per share, as compared to $7.7 million, or $0.23 per share, in the fourth quarter 2008. Total revenues decreased approximately $10.4 million (7.9%) for the fourth quarter of 2009 as compared to the fourth quarter of 2008 primarily due to milder weather in October and November of 2009 as compared to 2008. Mostly offsetting the decrease in revenues were decreased fuel and purchased power costs and decreased natural gas costs.

2009 Activities

Regulatory Matters

        On November 4, 2009, 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 $5.2 million, or 24.6%. This request is primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 completed in 2009 and at our Asbury plant completed in 2008 and our investment in new generating units at Iatan 2, the Plum Point Generating Station and our Riverton 12 unit that went on line in 2007. We anticipate new rates will go into effect in July 2010.

        On October 29, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%. This request is primarily to allow us to recover capital expenditures associated with environmental upgrades at Iatan 1 and our investment in new generating units at Iatan 2 and the Plum Point Generating Station. We are currently in discussions about procedures to be used in this case, including the timing of the consideration and rate recovery of our investments in the three generating facilities and other expenditures. Due to the expected in-service delay of Iatan 2, however, we do not anticipate recovering Iatan 2 costs in this Missouri rate case. We anticipate filing a rate case at the conclusion of this case to recover the Iatan 2 costs.

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        On June 5, 2009, we filed a request with the MPSC for an annual increase in base rates for our Missouri gas customers in the amount of $2.9 million, or 4.9%. In this filing, we requested recovery of the ongoing cost of operating and maintaining our 1,200-mile gas distribution system and a return on equity of 11.3%. We have entered into a Stipulated Agreement, which was approved by the MPSC, for an increase of $2.6 million. Pursuant to the Agreement, new rates will go into effect on April 1, 2010.

        All pending applications for rehearing in our 2006 Missouri electric rate case were denied by the MPSC on November 20, 2008. On December 15, 2008, the Office of the Public Counsel (OPC) filed a Petition for Writ of Review with the Cole County Circuit Court regarding the MPSC's decisions in our 2006 rate case. Praxair and Explorer Pipeline filed a Petition for Writ of Review on December 19, 2008. These actions were consolidated into one proceeding. Briefs were filed by all parties and oral arguments were held on June 2, 2009. The Cole County Circuit Court issued a ruling on December 8, 2009, affirming the MPSC's order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

        On May 13, 2009, the OPC filed a petition in the Jasper County Circuit Court seeking refunds with regard to utility rates for electric service paid by our customers during the period of January 1, 2007 to December 13, 2007. During this period, we charged the rates set forth in the tariffs which were approved by, and are on file with, the MPSC. We filed a motion to dismiss, or, in the alternative, motion for more definitive statement. On September 3, 2009, the Jasper County Circuit Court dismissed the petition with prejudice. On October 7, 2009, the OPC appealed the Jasper County Circuit Court decision to the Missouri Court of Appeals — Southern District. The initial brief was filed by the OPC on January 11, 2010. We filed a responsive brief on February 5, 2010.

        The MPSC issued an order on July 30, 2008 in response to a request filed with the MPSC on October 1, 2007 for an annual increase in base rates for our Missouri electric customers. This order granted an annual increase in revenues for our Missouri electric customers in the amount of $22.0 million, or 6.7%, based on a 10.8% return on equity. The new rates went into effect August 23, 2008. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed applications for rehearing with the MPSC regarding this order. On August 12, 2008, the MPSC issued its Order Granting Expedited Treatment and Approving Compliance Tariff Sheets, effective August 23, 2008, in which the MPSC approved our tariff sheets containing our base rates for service rendered on and after August 23, 2008, and approved our fuel adjustment clause tariff sheets effective September 1, 2008. On September 3, 2008, the MPSC denied all pending applications for rehearing.

        On October 2, 2008, the OPC and intervenors Praxair, Inc. and Explorer Pipeline Company filed Petitions for Writ of Review with the Cole County Circuit Court. These actions were consolidated into one proceeding, briefs were filed and the Cole County Circuit Court heard oral arguments on September 29, 2009. The Cole County Circuit Court issued a ruling on December 31, 2009, affirming the Commission's Report and Order. OPC, Praxair and Explorer Pipeline have filed appeals with the Western District Court of Appeals.

        For additional information, see "Rate Matters" below.

Financings

        During the fourth quarter of 2009, we issued and sold 2,115,149 shares of our common stock, pursuant to our equity distribution agreement with UBS Securities LLC (UBS), at an average price per share of $18.51, resulting in proceeds to us of approximately $37.9 million (after payment of approximately $1.2 million in commissions to the sales agent). Since inception of the program, in the aggregate, we have issued and sold 3,767,909 shares pursuant to the program, resulting in net proceeds to us of approximately $66.7 million. Sales of the shares pursuant to the equity distribution agreement will be made at market prices or as otherwise agreed with UBS. Under the terms of the program agreement, we may also sell shares to UBS as principal for UBS' own account at a price agreed upon at the time of sale. On

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October 22, 2009, we amended the equity distribution agreement to increase the aggregate offering amount under the program from $60 million to $120 million.

        On March 27, 2009, we issued $75 million principal amount of 7% first mortgage bonds due April 1, 2024. The net proceeds (after payment of expenses) of approximately $72.6 million, were used to repay short-term debt incurred, in part, to fund our current construction program.

        On January 26, 2010, we entered into the Second Amended and Restated Unsecured Credit Agreement (Credit Agreement) which amends and restates our Amended and Restated Unsecured Credit Agreement dated March 14, 2006. This agreement extends the termination date of the revolving credit facility from July 15, 2010 to January 26, 2013. In addition, the pricing and fees under the Credit Agreement were amended. Interest on borrowings under the Credit Agreement accrues at a rate equal to, at our option, (i) the highest of (A) the bank's prime commercial rate, (B) the federal funds effective rate plus 0.5% or (C) one month LIBOR plus 1.0%, plus a margin or (ii) one month, two month or three month LIBOR, in each case, plus a margin. Each margin is based on our current credit ratings and the pricing schedule in the Credit Agreement. As of the date hereof, and based on our current credit ratings, the LIBOR margin under the facility increased from 0.80% to 2.70%. A facility fee is payable quarterly on the full amount of the commitments under the Credit Agreement and a usage fee is payable on the full amount of the commitments under the Credit Agreement for any period in which we have drawn less than 33% of the total revolving commitments under the Credit Agreement, in each case based on our current credit ratings. In addition, upon entering into the Credit Agreement, we paid an upfront fee to the revolving credit banks of $900,000 in the aggregate. The aggregate amount of the revolving commitments remained unchanged at $150 million and there were no other material changes to the terms of the Credit Agreement.

        On March 11, 2009, we entered into a $50 million unsecured credit agreement. This agreement provides for $50 million of revolving loans to be available to us for working capital, general corporate purposes and to back-up our use of commercial paper and terminates on July 15, 2010. This credit agreement is in addition to, and has substantially identical covenants and terms as (other than pricing), our Second Amended and Restated Unsecured Credit Agreement dated January 26, 2010. There were no borrowings under the new agreement at December 31, 2009.

Regulatory Plan

        On April 19, 2009, we began recording deferred carrying charges associated with environmental upgrades recently completed at our Iatan 1 facility in accordance with our regulatory plan. We deferred $2.7 million in 2009. Construction accounting, for purposes of the regulatory plan, allows us to defer certain charges as regulatory assets, including depreciation and carrying costs, related to operation of the facilities until the facilities are ultimately included in our rate base. The amounts deferred, which began at the in-service date for Iatan 1 and will also be deferred for Iatan 2 at its in-service date, will then be amortized over the life of the plants once they are in our rate base. The regulatory plan covers the 150 megawatt V84.3A2 combustion turbine (Unit 12) that began commercial operation on April 10, 2007 at our Riverton plant, the environmental upgrades at Asbury, which were completed in 2008, environmental upgrades at Iatan 1 and the construction of the Iatan 2 facilities. See Note 3 of "Notes to Consolidated Financial Statements".

Iatan 2

        On June 13, 2006, we announced we had entered into an agreement with Kansas City Power & Light (KCP&L) to purchase an undivided ownership interest in the coal-fired Iatan 2 generating facility. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. Early in the third quarter of 2009, KCP&L announced its efforts to produce a cost and schedule reforecast primarily to address on-going productivity issues that were negatively impacting the original schedule and reported the anticipated

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in-service date for Iatan 2 to be late summer of 2010. Based on a late summer in-service date, we expected base rates reflecting our investment to be in effect in late 2010 as we filed a request with the MPSC on October 29, 2009, for an annual increase in base rates for our Missouri electric customers in the amount of $68.2 million, or 19.6%, as discussed above. However, on January 13, 2010, KCP&L announced that, due to construction delays and unusually cold weather, it currently anticipates that the in-service date of Iatan 2 will shift approximately two months into the fall of 2010. KCP&L also announced that, as the Iatan 2 project moves into the startup phase, it has commenced a cost and schedule reforecast process for Iatan 2. KCP&L notes that the results will be disclosed when the process is completed, which it currently projects to be in the second half of the first quarter of 2010. Additionally, KCP&L also stated that it presently believes there will be no material increase in the estimated construction cost range of Iatan 2. As a result of this delay in the project, we expect that the timing of receipt of the increase in base rates associated with Iatan 2 will be delayed.

SLCC Generator Failure

        On July 3, 2009, the generator on State Line Unit 2-1, one of the combustion turbines at SLCC, failed during operation. Unit 2-1 represents about 150 megawatts of the 500 megawatts rated output of SLCC, of which we are entitled to 60%, or 300 megawatts. The remainder of SLCC was undamaged and continued to operate as normal. The cost to replace the turbine was in excess of the $1.5 million insurance deductible on the unit. We expect to recover all the costs from insurance proceeds in excess of the $1.5 million deductible. The unplanned outage did not have a material financial impact. Unit 2-1 returned to service in October 2009.

Energy Center Engine Failure

        On September 28, 2009, we experienced a failure on Energy Center Unit 3, Engine A. The unit returned to 100% operation on December 23, 2009. This unplanned outage did not have a material financial impact, as almost all of the expenditures were capital replacements and our insurance covered all costs greater than our $500,000 deductible.

2009 Storm Damage

        A major wind storm caused substantial damage to our electric service territory on May 8, 2009. Approximately 83,000 of our electric customers were without power at the height of the storm. Incremental costs associated with the restoration effort due to the wind storm were approximately $6.0 million, of which $5.3 million was capitalized as additions to our utility plant and approximately $0.7 million was maintenance expense that was deferred as a regulatory asset as we believe it is probable that these costs will be recoverable in future electric rate cases.

Ozark Beach Plant

        Our hydroelectric generating plant (FERC Project No. 2221), located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We have a long-term license from FERC to operate this plant which forms Lake Taneycomo in southwestern Missouri. As part of the Energy and Water Development Appropriations Act of 2006 (the Appropriations Act), a new minimum flow was established with the intent of increasing minimum flows on recreational streams in Arkansas. To accomplish this, the level of Bull Shoals Lake will be increased an average of 5 feet. The increase at Bull Shoals will decrease the head waters available for generation at Ozark Beach by 5 feet and, thus, reduce our electrical output. We estimate the lost production to be up to 16% of our average annual energy production for this unit. The loss in this facility would require us to replace it with additional generation from our gas-fired and coal-fired units or with purchased power. The Appropriations Act requires the Southwest Power Administration (SWPA), in coordination with us and our relevant public service commissions, to determine our economic detriment.

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        The SWPA published its Final Determination Report on January 23, 2009 documenting the procedure they intended to use to calculate the present value of the future lifetime replacement cost of the electrical energy and capacity lost due to the White River Minimum Flows project at Ozark Beach. The actual hydropower compensation values were to be calculated using the method presented in the Final Determination and current values for the specified parameters based on the official implementation date. Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and November 2008 values for the specified parameters, the SWPA's determination at that time resulted in a present value for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach of $41.3 million. On June 8, 2009, the SWPA published a draft addendum to its January 2009 Final Determination Report documenting proposed changes to the SWPA's methodology, including the inclusion of an additional discount rate source to be used by the SWPA in determination of the present value of the losses. Assuming a January 1, 2011 date of implementation for the White River Minimum Flows project and current values for the specified parameters, the SWPA's Draft Addendum to its Final Determination results in a present value of $22.3 million for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach. We and the MPSC have provided comments on the new methodology included in the draft addendum but cannot predict the final outcome. Originally, the Appropriations Act had a provision for the Army Corp of Engineers to provide a one time payment to us for lost energy production. This provision was revised in October 2009 to allow the SWPA to pay for damages through a special disbursement account. Under the revised law, payments must be made annually by SWPA in an amount of at least $5 million until the total damages are reimbursed.

Gas Storage Contract

        We have signed an agreement with Southern Star to purchase one million Dths of firm gas storage service capacity for a period of five years beginning in April 2011. The reservation charge for this storage capacity is approximately $1.1 million annually. This storage capacity will enable us to better manage our natural gas commodity and transportation needs for our electric segment

Iatan 2 Coal Investment Tax Credits

        We are currently working with KCP&L to enter into an agreement with the IRS to receive our share of the $125 million in advanced coal investment tax credits granted Iatan 2, of which our share amounts to approximately $17.7 million. We cannot predict the timing of the receipt of the credit. However, it would have no significant income statement impact as the credit, which would reduce our tax payments, would flow to our customers over the life of the plant.

RESULTS OF OPERATIONS

        The following discussion analyzes significant changes in the results of operations for the years 2009, 2008 and 2007.

        The following table represents our results of operations by operating segment for the applicable periods ended December 31:

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Electric Segment

Overview

        Our electric segment income for 2009 was $39.1 million as compared to $37.4 million for 2008.

        Electric operating revenues comprised approximately 87.5% of our total operating revenues during 2009. Of these total electric operating revenues, approximately 41.6% were from residential customers, 31.4% from commercial customers, 15.2% from industrial customers, 4.2% from wholesale on-system customers, 3.3% from wholesale off-system transactions, 2.7% from miscellaneous sources, primarily public authorities and 1.6% from other electric revenues. The percentage of revenues provided from our wholesale off-system transactions has decreased during 2009 as compared to 2008 primarily due to decreased market demand resulting from milder weather in 2009 and general economic conditions.

        The amounts and percentage changes from the prior periods in kilowatt-hour ("kWh") sales and electric segment operating revenues by major customer class for on-system and off-system sales were as follows:

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        The following table sets forth revenues and expenses relating to off-system transactions (including through the Southwest Power Pool (SPP) energy imbalance services (EIS) market) for the years ended December 31:

2009 Compared to 2008

On-System Operating Revenues and Kilowatt-Hour Sales

        KWh sales for our on-system customers decreased approximately 4.3% during 2009 as compared to 2008 with the associated revenues increasing approximately $2.2 million (0.5%). Weather and other related factors decreased revenues an estimated $20.3 million. Total cooling degree days (the cumulative number of degrees that the average temperature for each day during that period was above 65° F) for 2009 were 12.3% less than 2008 and 18.7% less than the 30-year average. Total heating degree days (the sum of the number of degrees that the daily average temperature for each day during that period was below 65° F) for 2009 were 4.0% less than 2008 and 0.5% less than the 30-year average. Rate changes, primarily the August 2008 Missouri rate increase (discussed below), contributed an estimated $21.9 million to revenues while continued sales growth contributed an estimated $0.6 million. We expect our annual customer growth to range from approximately 1.1% to 1.5% over the next several years.

        Residential and commercial kWh sales decreased in 2009 primarily due to mild weather during the year. The related revenues increased during 2009 primarily due to the August 2008 Missouri rate increase and continued sales growth. Industrial kWh sales decreased 7.6% mainly due to a slowdown created by economic uncertainty while the associated revenues decreased 2.0%, reflecting the economic conditions, partially offset by the Missouri rate increase. On-system wholesale kWh sales and revenues decreased reflecting the general economic conditions and mild weather.

Off-System Electric Transactions

        In addition to sales to our own customers, we also sell power to other utilities as available, including through the Southwest Power Pool (SPP) energy imbalance services (EIS) market. See " — Competition" below. The majority of our off-system sales margins are now included as a component of the fuel adjustment clause in our Missouri, Kansas and Oklahoma jurisdictions and generally adjust the fuel and purchased power expense. As a result, nearly all of the off-system sales margin flows back to the customer and has little effect on net income.

        Revenues and related expenses were less during 2009 as compared to 2008 primarily due to decreased market demand and lower gas prices that made it more economical for utilities to generate their own power rather than purchase it. Total purchased power related expenses are included in our discussion of purchased power costs below.

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Miscellaneous Revenues

        Our miscellaneous revenues were $6.8 million during 2009 as compared to $7.0 million during 2008. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

Operating Revenue Deductions

        During 2009, total electric segment operating expenses decreased approximately $17.3 million (4.5%) compared to 2008.

        Total fuel and purchased power expenses decreased approximately $22.1 million (10.8%) during 2009 as compared to 2008. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statements of income for 2009 and 2008.

        The overall fuel and purchased power expense decrease primarily reflects the effect of decreased market demand resulting from mild weather in 2009, as well as the effects of an extended outage at the Asbury plant lasting from the fourth quarter of 2007 into the first quarter of 2008 during which time we relied on purchased power as well as our gas-fired units to replace our coal-fired generation. The decrease in fuel costs also includes the effect of decreased off-system sales.

        Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power expenses when compared to 2008. This table incorporates all the changes mentioned above. As shown below, the largest impacts on fuel and purchased power costs were lower purchased power and natural gas prices and decreased generation by our gas-fired units.

        Regulated operating expenses increased approximately $1.0 million (1.6%) during 2009 as compared to 2008 primarily due to increases of $1.5 million in professional services, $1.2 million in other steam power expense, $0.8 million in general labor costs and $0.6 million in customer accounts expenses (mainly

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increased banking fees). These increases were partially offset by decreases of $1.3 million in employee health care expense, $1.1 million in injuries and damages expense, $0.4 million in pension expense and $0.3 million in regulatory commission expense. We were able to defer an additional $0.6 million in other steam power expense related to Iatan 1 operating costs in accordance with our agreement with the MPSC that allows deferral of certain costs until the environmental upgrades to Iatan 1 are included in our rate base.

        Maintenance and repairs expense increased approximately $4.5 million (16.4%) during 2009 primarily due to increases of approximately $3.8 million in distribution maintenance costs (including $2.5 million of ice storm related amortization), $1.2 million in maintenance and repairs expense at the Asbury plant, $0.3 million in maintenance and repairs expense to the SLCC mainly due to a maintenance outage in the first quarter of 2009, $0.1 million in maintenance and repairs expense to the Riverton gas units and $0.1 million in maintenance and repairs expense to State Line Unit No. 1. These increases were partially offset by decreases of $0.6 million in maintenance and repairs expense at the Iatan plant which experienced an outage in the fourth quarter of 2008 and $0.4 million in maintenance and repairs expense to the coal units at the Riverton plant.

        Depreciation and amortization expense decreased approximately $2.3 million (4.5%) during 2009 primarily due to reduced regulatory amortization resulting from the Missouri rate case that went into effect August 23, 2008. Other taxes increased approximately $0.8 million due to increased property tax reflecting our additions to plant in service and increased municipal franchise taxes.

2008 Compared to 2007

On-System Operating Revenues and Kilowatt-Hour Sales

        KWh sales for our on-system customers increased approximately 0.1% during 2008 as compared to 2007 primarily due to continued sales growth. Revenues for our on-system customers increased approximately $10.0 million, or 2.5%. Rate changes, primarily the August 2008 Missouri rate increase (discussed below), contributed an estimated $8.9 million to revenues while continued sales growth contributed an estimated $3.9 million. Weather and other related factors decreased revenues an estimated $2.8 million.

        Residential and commercial kWh sales increased in 2008 primarily due to continued sales growth while the associated revenues also increased due to the August 2008 Missouri rate increase. Industrial kWh sales decreased 3.3% mainly due to a slowdown created by economic uncertainty while the associated revenues decreased 0.5%, reflecting the economic conditions, partially offset by the Missouri rate increase. On-system wholesale kWh sales increased reflecting the continued sales growth discussed above.

Off-System Electric Transactions

        Off-system revenues increased during 2008 as compared to 2007 primarily due to sales facilitated by the EIS market that began on February 1, 2007. Total purchased power related expenses are included in our discussion of purchased power costs below.

Miscellaneous Revenues

        Our miscellaneous revenues were $7.0 million during 2008 as compared to $5.7 million during 2007. These revenues are comprised mainly of transmission revenues, late payment fees and renewable energy credit sales.

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Operating Revenue Deductions

        During 2008, total electric segment operating expenses increased approximately $17.0 million (4.6%) compared to 2007.

        Total fuel and purchased power expenses increased approximately $12.8 million (6.7%) during 2008 as compared to 2007. The table below is a reconciliation of our actual fuel and purchased power expenditures (netted with the regulatory adjustments) to the fuel and purchased power expense shown on our statements of income for 2008 and 2007.

        The overall fuel and purchased power increase included the effect of increased costs for off-system sales of $7.6 million and the effect of replacement power for the Asbury and Riverton 8 outages in both years. After assessing the actual cost of the incremental purchased power and gas-fired generation, we estimate the extended outage at Asbury increased our expenses by an additional $5.8 million in the first quarter of 2008 (January 1 – February 10, 2008). This compares to the impact of the 5-year planned maintenance outage in 2007 which we estimated added additional expenses of approximately $8.7 million and the extended outage (December 8 – December 31, 2007) which increased expenses an additional $3.5 million.

        Summarized in the table below are our estimated cost and volume changes in the components of fuel and purchased power costs when compared to 2007. This table incorporates all the changes mentioned above. As shown below, the largest impact on fuel and purchased power costs was increased costs for both purchased power and coal, offset by decreases in natural gas prices and the effect of the unwinding of future physical natural gas positions in February 2008.

        Regulated operating expenses increased approximately $0.8 million (1.4%) during 2008 as compared to 2007 primarily due to increases of $1.4 million in transmission and distribution expense, $0.8 million in other steam power expense, $0.6 million in injuries and damages expense, $0.4 million in other power expense and $0.1 million in director and stockholder expense. These increases were partially offset by decreases of $0.9 million in uncollectible accounts expense, $0.7 million in employee pension expense, $0.7 million in employee health care expense and $0.2 million in professional services.

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        Maintenance and repairs expense decreased approximately $2.9 million (9.6%) during 2008 mainly due to decreases of approximately $4.2 million in distribution maintenance costs as compared to 2007. In 2007 we incurred $3.9 million of incremental costs (and $1.2 million non-incremental tree trimming and labor costs in the first quarter of 2007) related to the January 2007 ice storm and $1.5 million of incremental costs related to the December 2007 ice storm. In 2008 we began amortizing this cost and recognized $1.4 million in maintenance costs. Also contributing to the decrease during 2008 was a $0.5 million decrease in maintenance and repairs expense at the Asbury plant as compared to the same period in 2007 when there was an extended outage during the fourth quarter, and a $0.4 million decrease in maintenance expense at the Energy Center plant compared to 2007 when there was a bearing failure in Unit #3 in the second quarter of 2007. These decreases were partially offset by a $0.7 million increase in maintenance and repairs expense at the SLCC plant due to the extended spring maintenance outage in the second quarter of 2008, a $0.7 million increase in maintenance and repairs expense at the Riverton plant due to the extended outage on Unit 8 to repair damage to high pressure blades discovered during Riverton's scheduled maintenance outage in May 2008, a $0.5 million increase in transmission expense and a $0.1 million increase in maintenance costs for the Riverton gas-fired units.

        We recognized a $1.2 million gain in the fourth quarter of 2007 from the sale of our unit train set. We recognized no corresponding gains in 2008.

        Depreciation and amortization expense increased approximately $0.7 million (1.3%) mainly due to a $2.9 million increase in depreciation expense due to increased plant in service partially offset by a $2.3 million decrease in the amount of regulatory amortization related to the 2008 Missouri electric rate order that is recorded as depreciation expense. Other taxes increased approximately $0.4 million due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

Gas Operating Revenues and Sales

        The following tables detail our natural gas sales and revenues for the periods ended December 31:

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