10-K 1 a2190805z10-k.htm 10-K

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TABLE OF CONTENTS
PART IV

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



FORM 10-K

(Mark One)    

ý

 

Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2008 or

o

 

Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                                to                                 .

Commission file number: 1-3368

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

Kansas
(State of Incorporation)
  44-0236370
(I.R.S. Employer Identification No.)

602 S. Joplin Avenue, Joplin, Missouri
(Address of principal executive offices)

 

64801
(zip code)

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

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

Title of each class   Name of each exchange on which registered
Common Stock ($1 par value)
Preference Stock Purchase Rights
  New York Stock Exchange
New York Stock Exchange

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

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

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

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

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o   Accelerated filer ý   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company o

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

         The aggregate market value of the registrant's voting common stock held by nonaffiliates of the registrant, based on the closing price on the New York Stock Exchange on June 30, 2008, was approximately $627,768,368.

         As of February 6 2009, 34,030,579 shares of common stock were outstanding.

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

The Company's proxy statement, filed pursuant
to Regulation 14A under the Securities Exchange
Act of 1934, for its Annual Meeting of
Stockholders to be held on April 23, 2009
  Part of Item 10 of Part III
All of Item 11 of Part III
Part of Item 12 of Part III
All of Item 13 of Part III
All of Item 14 of Part III


Table of Contents


TABLE OF CONTENTS

 
   
  Page  

 

Forward Looking Statements

    3  

PART I

 

ITEM 1.

 

BUSINESS

    4  

 

General

    4  

 

Electric Generating Facilities and Capacity

    5  

 

Gas Facilities. 

    7  

 

Construction Program

    8  

 

Fuel and Natural Gas Supply

    9  

 

Employees

    11  

 

Electric Operating Statistics

    12  

 

Gas Operating Statistics

    13  

 

Executive Officers and other Officers of Empire

    14  

 

Regulation

    15  

 

Environmental Matters

    16  

 

Conditions Respecting Financing

    20  

 

Our Web Site

    21  

ITEM 1A.

 

RISK FACTORS

    22  

ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

    25  

ITEM 2.

 

PROPERTIES

    26  
 

 

Electric Segment Facilities

    26  
 

 

Gas Segment Facilities

    28  
 

 

Other Segment Businesses

    28  

ITEM 3.

 

LEGAL PROCEEDINGS

    28  

ITEM 4.

 

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

    28  

PART II

 

ITEM 5.

 

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

    29  

ITEM 6.

 

SELECTED FINANCIAL DATA

    31  

ITEM 7.

 

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    32  

 

Executive Summary

    32  

 

Results of Operations

    37  

 

Rate Matters

    49  

 

Competition

    53  

 

Liquidity and Capital Resources

    54  

 

Contractual Obligations

    60  

 

Dividends

    61  

 

Off-Balance Sheet Arrangements

    62  

 

Critical Accounting Policies

    62  

 

Recently Issued Accounting Standards

    66  

ITEM 7A

 

QUANTATATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

    67  

ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

    69  

ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

    139  

ITEM 9A.

 

CONTROLS AND PROCEDURES

    139  

ITEM 9B.

 

OTHER INFORMATION

    139  

PART III

 

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

    140  

ITEM 11.

 

EXECUTIVE COMPENSATION

    140  

ITEM 12.

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

    140  

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

    141  

ITEM 14.

 

PRINCIPAL ACCOUNTANT FEES AND SERVICES

    141  

PART IV

 

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

    142  

 

SIGNATURES

    147  

Table of Contents


FORWARD LOOKING STATEMENTS

        Certain matters discussed in this annual report are "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital expenditures, earnings, pension and other costs, competition, litigation, our construction program, our generation plans, our financing plans, potential acquisitions, rate and other regulatory matters, liquidity and capital resources and accounting matters. Forward-looking statements may contain words like "anticipate", "believe", "expect", "project", "objective" or similar expressions to identify them as forward-looking statements. Factors that could cause actual results to differ materially from those currently anticipated in such statements include:

    the amount, terms and timing of rate relief we seek and related matters;

    the cost and availability of purchased power and fuel, and the results of our activities (such as hedging) to reduce the volatility of such costs;

    volatility in the credit, equity and other financial markets and the resulting impact on our short term debt costs and our ability to issue debt or equity securities, or otherwise secure funds to meet our capital expenditure, dividend and liquidity needs;

    the results of prudency and similar reviews by regulators of costs we incur;

    weather, business and economic conditions and other factors which may impact sales volumes and customer growth

    operation of our electric generation facilities and electric and gas transmission and distribution systems, including the performance of our joint owners;

    the costs and other impacts resulting from natural disasters, such as tornados and ice storms;

    the periodic revision of our construction and capital expenditure plans and cost and timing estimates;

    legislation;

    regulation, including environmental regulation (such as NOx, SO2 and CO2 regulation);

    competition, including the regional SPP energy imbalance market;

    electric utility restructuring, including ongoing federal activities and potential state activities;

    the impact of electric deregulation on off-system sales;

    changes in accounting requirements;

    other circumstances affecting anticipated rates, revenues and costs;

    the timing of accretion estimates, and integration costs relating to completed and contemplated acquisitions and the performance of acquired businesses, which may lead to impairments of goodwill;

    matters such as the effect of changes in credit ratings on the availability and our cost of funds;

    the performance of our pension assets and the resulting impact on our pension funding commitments;

    interruptions or changes in our coal delivery, gas transportation or storage agreements or arrangements;

    the success of efforts to invest in and develop new opportunities;

    costs and effects of legal and administrative proceedings, settlements, investigations and claims; and

    our exposure to the credit risk of our hedging counterparties.

        All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond our control. New factors emerge from time to time and it is not possible for management to predict all such factors or to assess the impact of each such factor on us. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

        We caution you that any forward-looking statements are not guarantees of future performance and involve known and unknown risk, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from the facts, results, performance or achievements we have anticipated in such forward-looking statements.

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PART 1

ITEM 1.    BUSINESS

General

        We operate our businesses as three segments: electric, gas and other. The Empire District Electric Company (EDE), a Kansas corporation organized in 1909, is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity in parts of Missouri, Kansas, Oklahoma and Arkansas. 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 formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. Our other segment consists primarily of our fiber optics business. In 2008, 86.5% of our gross operating revenues were provided from sales from our electric segment (including 0.3% from the sale of water), 12.6% from our gas segment, and 0.9% from our other segment.

        The territory served by our electric operations embraces an area of about 10,000 square miles, located principally in southwestern Missouri, and also includes smaller areas in southeastern Kansas, northeastern Oklahoma and northwestern Arkansas. The principal economic activities of these areas include light industry, agriculture and tourism. Of our total 2008 retail electric revenues, approximately 88.7% came from Missouri customers, 5.4% from Kansas customers, 3.0% from Oklahoma customers and 2.9% from Arkansas customers.

        We supply electric service at retail to 121 incorporated communities and to various unincorporated areas and at wholesale to four municipally owned distribution systems. The largest urban area we serve is the city of Joplin, Missouri, and its immediate vicinity, with a population of approximately 157,000. We operate under franchises having original terms of twenty years or longer in virtually all of the incorporated communities. Approximately 64% of our electric operating revenues in 2008 were derived from incorporated communities with franchises having at least ten years remaining and approximately 6% were derived from incorporated communities in which our franchises have remaining terms of ten years or less. Although our franchises contain no renewal provisions, in recent years we have obtained renewals of all of our expiring electric franchises prior to the expiration dates.

        Our electric operating revenues in 2008 were derived as follows: residential 40.2%, commercial 29.8%, industrial 15.1%, wholesale on-system 4.3%, wholesale off-system 6.6%, miscellaneous sources, primarily public authorities, 2.5% and other electric revenues 1.5%. Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2008 accounted for approximately 3% of electric revenues. No single retail customer accounted for more than 1% of electric revenues in 2008.

        Our gas operations serve customers in northwest, north central and west central Missouri. We provide natural gas distribution to 44 communities and 279 transportation customers as of December 31, 2008. Our gas operating revenues in 2008 were derived as follows: residential 60.6%, commercial 26.6%, industrial 7.7% and other 5.1%. No single retail customer accounted for more than 5% of gas revenues in 2008. The largest urban area we serve is the city of Sedalia with a population of over 20,000. We operate under franchises having original terms of twenty years in virtually all of the incorporated communities. Twenty-seven of the franchises have 10 years or more remaining on their term. Although our franchises contain no renewal provisions, since our acquisition, we have obtained renewals of all our expiring gas franchises prior to the expiration dates.

        Our other segment consists primarily of a 100% interest in Empire District Industries, Inc., a non-regulated subsidiary for our fiber optics business. As of December 31, 2008, we have 84 fiber customers.

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Electric Generating Facilities and Capacity

        At December 31, 2008, our generating plants consisted of:

Plant
  *Capacity
(megawatts)
  Primary Fuel

Asbury

    210   Coal

Riverton

    286   Coal and Natural Gas

Iatan I (12% ownership)

    78 ** Coal

State Line Combined Cycle (60% ownership)

    300 ** Natural Gas

Empire Energy Center

    269   Natural Gas

State Line Unit No. 1

    96   Natural Gas

Ozark Beach

    16   Hydro
         
 

Total

    1,255    
         

*
Based on summer rating conditions as utilized by Southwest Power Pool.

**
The 78 and 300 megawatts of Iatan and State Line Combined Cycle, respectively, reflect our allocated shares of the capacity of these plants.

        See Item 2, "Properties — Electric Segment Facilities" for further information about these plants.

        We, and most other electric utilities with interstate transmission facilities, have placed our facilities under the Federal Energy Regulatory Commission (FERC) regulated open access tariffs that provide all wholesale buyers and sellers of electricity the opportunity to procure transmission services (at the same rates) that the utilities provide themselves. We are a member of the Southwest Power Pool Regional Transmission Organization (SPP RTO). On February 1, 2007, the SPP RTO launched its energy imbalance services market (EIS). With the implementation of the SPP RTO EIS market and transmission expansion plans of the SPP RTO, we anticipate that our continued participation in the SPP will provide long-term benefits to our customers and other stakeholders. Our experience to date in the EIS market indicates that we have received benefits through our participation. In general, the SPP RTO EIS market is providing real time energy for most participating members within the SPP regional footprint. Imbalance energy prices are based on market bids and availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Competition."

        We currently supplement our on-system generating capacity with purchases of capacity and energy from other sources in order to meet the demands of our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council rules. The SPP requires its members to maintain a minimum 12% capacity margin. We have contracted with Westar Energy for the purchase of 162 megawatts of capacity and energy through May 31, 2010 and have contracted to add 50 megawatts of purchased power beginning in 2010 from the Plum Point Energy Station discussed below. The amount of capacity purchased under such contracts supplements our on-system capacity and contributes to meeting our current expectations of future power needs.

        Due to increased customer growth, we installed, at our Riverton facility, a Siemens V84.3A2 combustion turbine, Unit 12, with a summer rated capacity of 150 megawatts to allow us to meet the SPP's 12% minimum capacity margin requirement and increased our Riverton Plant's total generating capacity to 286 megawatts. The total expenditure for Unit 12, which began commercial operation as of April 10, 2007, was $39.5 million, excluding allowance for funds used during construction (AFUDC). In addition, in 2006, we entered into contracts to add 200 megawatts of power to our system. This energy is to

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come from two new plants that are scheduled to be operational in 2010, with 100 megawatts from the new Plum Point Energy Station and 100 megawatts from the new Iatan 2 generating facility, each of which is described below.

        The Plum Point Energy Station is a new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. Construction began in the spring of 2006 with completion scheduled for summer 2010. Initially we will own, through an undivided interest, 50 megawatts of the project's capacity for approximately $88.0 million in direct expenditures, excluding AFUDC. We spent $72.8 million through December 31, 2008 and anticipate spending an additional $9.4 million in 2009 and $5.8 million in 2010 for construction expenses related to our 50 megawatt ownership share of Plum Point Unit 1. All of our estimated construction expenditures exclude AFUDC. We also have a long-term (30 year) purchased power agreement for an additional 50 megawatts of capacity and have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015.

        We have also purchased an undivided ownership interest in the coal-fired Iatan 2 generating facility to be operated by Kansas City Power & Light Company (KCP&L) and located at the site of the existing Iatan Generating Station (Iatan 1) near Weston, Missouri. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. Construction began in the spring of 2006 with completion scheduled for summer 2010. As a requirement for the air permit for Iatan 2, and to help meet requirements of the Clean Air Interstate Rule (CAIR), additional emission control equipment was required for Iatan 1. On May 7, 2008, KCP&L announced an update of their estimated construction figures for the construction of the Iatan 2 plant and for the environmental upgrades at the Iatan 1 plant. Our share of the Iatan 2 construction expenditures is expected to be in a range of approximately $218 million to $230 million. The updated estimate of our share of the expenditures for environmental upgrades at the Iatan 1 plant is a range of approximately $58 million to $60 million. The in-service date for the Iatan 1 project is expected to be late in the first quarter of 2009 to early in the second quarter of 2009.

        Our current capital expenditures budget, discussed below, includes $69.9 million in 2009 and $32.4 million in 2010 for our share of Iatan 2 and $15.6 million in 2009 for Iatan 1 environmental upgrades. At December 31, 2008, we have recorded approximately $132.4 million in construction expenditures on the Iatan 2 project and approximately $43.4 million on the Iatan 1 environmental upgrades. As of January 15, 2009, KCP&L stated it had approximately 92% of the total budgeted direct construction expenditures of Iatan 2 under contract and the project was scheduled to be complete in the summer of 2010. The percentage of total budgeted direct construction expenditures is slightly lower than reported in January 2008 due to the May 2008 updated estimated construction figures for Iatan 2 discussed above.

        The Missouri Public Service Commission (MPSC) issued an order on August 2, 2005 approving a Stipulation and Agreement (Agreement) with an effective date of August 12, 2005 regarding our Experimental Regulatory Plan (Plan). The Agreement contains conditions related to our infrastructure investments, including Iatan 2, environmental investments in Iatan 1, the 150 MW combustion turbine at our Riverton Plant and the installation of Selective Catalytic Reduction (SCR) equipment at the Asbury coal-fired plant. The other parties to the Agreement include the Missouri Department of Natural Resources, the MPSC Staff, two of our industrial customers and the Office of the Public Counsel. We had filed the original application on February 4, 2005 seeking approval of our Plan concerning our participation in a new 800–850 MW coal-fired unit (Iatan 2) or other baseload generation options. Our application also sought a certificate of convenience and necessity to participate in Iatan 2, if necessary, and in connection therewith, obtain approval that is intended to provide adequate assurance to potential investors to make financial options available to us concerning our potential investment in Iatan 2.

        In June 2007, we entered into a purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas. This agreement provides for a 20-year term commencing with the commercial operation date, which was December 15, 2008. Pursuant to the terms of the agreement, we will purchase all of the output from the approximately 105-megawatt Phase 1 Meridian

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Wind Farm located in Cloud County, Kansas. We also have a 20-year contract with Elk River Windfarm, LLC to purchase approximately 550,000 megawatt-hours of energy per year. The windfarm was declared commercial on December 15, 2005. We do not own any portion of either windfarm.

        The following chart sets forth our purchase commitments and our anticipated owned capacity (in megawatts) during the indicated contract years (which run from June 1 to May 31 of the following year). The capacity ratings we use for our generating units are based on summer rating conditions under SPP guidelines. The portion of the purchased power that may be counted as capacity from the Elk River Windfarm, LLC and the Cloud County Windfarm, LLC, with which we have contracted to purchase approximately 900,000 megawatt-hours of energy per year, is included in this chart. Because the wind power is an intermittent, non-firm resource, SPP rating criteria does not allow us to count a substantial amount of the wind power as capacity. See Item 7, "Managements' Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources."

Contract Year*
  Purchased
Power
Commitment***
  Anticipated
Owned
Capacity
  Total
Megawatts
 

    2008

    169     1255     1424  

    2009

    174     1257     1431  

**2010

    62     1407     1469  

**2011

    62     1407     1469  

**2012

    62     1407     1469  

*
Contract years begin June 1 and run through May 31 of the following year.

**
The contract years 2010, 2011 and 2012 assume 50 megawatts of purchased power capacity from Plum Point Unit 1, 50 megawatts of owned capacity from Plum Point Unit 1 and 100 megawatts of owned capacity from Iatan 2.

***
Includes an estimated 7 megawatts for the Elk River Windfarm, LLC and 5 megawatts for the Cloud County Windfarm, LLC.

        The charges for capacity purchases under the Westar contract referred to above during calendar year 2008 amounted to approximately $16.2 million. Minimum charges for capacity purchases under the Westar contract total approximately $32.4 million for the period June 1, 2008 through May 31, 2010.

        The maximum hourly demand on our system reached a record high of 1,173 megawatts on August 15, 2007. Our previous record peak of 1,159 megawatts was established on July 19, 2006. A new maximum hourly winter demand of 1,100 megawatts was set on December 22, 2008. Our previous winter peak of 1,059 megawatts was established on February 16, 2007.


Gas Facilities

        We acquired the Missouri natural gas distribution operations of Aquila, Inc. on June 1, 2006. At December 31, 2008, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,113 miles of distribution mains.

        The following table sets forth the three pipelines that serve our gas customers:

Service Area
  Name of Pipeline
South   Southern Star Central Gas Pipeline
North   Panhandle Eastern Pipe Line Company
Northwest   ANR Pipeline Company

        The maximum daily flow on our system for 2008 was a volume of 66,005 mcfs on December 21, 2008.

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Construction Program

        Total property additions (including construction work in progress), excluding AFUDC, for the three years ended December 31, 2008, amounted to $501.3 million and retirements during the same period amounted to $27.9 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 $198.6 million in 2008 and for the next three years are estimated for planning purposes to be as follows:

 
  Estimated Capital Expenditures (amounts in millions)  
 
  2009   2010   2011   Total  

New electric generating facilities:

                         
 

Iatan 2

  $ 69.9   $ 32.4   $   $ 102.3  
 

Plum Point Energy Station

    9.4     5.8         15.2  

Additions to existing electric generating facilities:

                         
 

Environmental upgrades — Iatan 1

    15.6             15.6  
 

Other

    11.9     11.8     14.9     38.6  

Electric transmission facilities

    13.7     12.6     2.9     29.2  

Electric distribution system additions

    40.9     41.2     46.1     128.2  

Non-regulated additions

    1.5     3.0     1.5     6.0  

General and other additions

    3.8     6.9     9.7     20.4  

Gas system additions

    2.2     2.0     2.0     6.2  
                   
 

Total

  $ 168.9   $ 115.7   $ 77.1   $ 361.7  
                   

        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.

        Iatan 2 and Plum Point Unit 1 are important components of a long-term, least-cost resource plan to add approximately 200 megawatts of new coal-fired generation to our system by the summer of 2010. The plan is driven by the continued growth in our service area and the expiration of a major purchase power contract in 2010.

        A new combustion turbine previously scheduled to be installed by the summer of 2011 is currently delayed until 2014 as our generation regulation needs for our purchased power agreements 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 equipment delivery schedules, changes in customer requirements, construction delays, ability to raise capital, environmental matters, the extent to which we receive timely and adequate rate increases, the extent of competition from independent power producers and 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."

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Fuel and Natural Gas Supply

Electric Segment

        In 2008, 60.0% of our total system input, based on kilowatt-hours generated, was supplied by our steam and combustion turbine generation units, 0.5% was supplied by our hydro generation, and we purchased the remaining 39.5%. Approximately 60.9% of the total fuel requirements for our generating units in 2008 (based on kilowatt-hours generated) were supplied by coal and approximately 38.9% 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 coal increased in 2008 as compared to 2007 primarily as a result of an extended maintenance outage at the Asbury plant in the fourth quarter of 2007. The amount and percentage of electricity generated by natural gas decreased in 2008 as compared to 2007 while the energy we purchased on the spot market to supplement the purchased power from our long-term Westar contract and Elk River Windfarm, LLC contract increased. We have a 20-year contract with Elk River Windfarm, LLC to purchase approximately 550,000 megawatt-hours of energy per year. The windfarm was declared commercial on December 15, 2005. We have a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas to purchase the energy generated at the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas commencing with the commercial operation date, which was December 15, 2008. 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 2008, Asbury burned a coal blend consisting of approximately 89.1% Western coal (Powder River Basin) and 10.9% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 60 days. As of December 31, 2008, we had sufficient coal on hand to supply anticipated requirements at Asbury for 96–97 days, as compared to 104–115 days as of December 31, 2007, 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 2008, Riverton Units 7 and 8 burned an estimated blend of approximately 83.5% Western coal (Powder River Basin) and 16.5% petroleum coke on a tonnage basis. Our average coal inventory target at Riverton is approximately 60 days. As of December 31, 2008, we had approximately 42,526 tons of Western coal and approximately 14,663 tons of blend fuel (petroleum coke and local coal) at Riverton. 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, 2008 to run 43 days on both units as compared to 37 days as of December 31, 2007. Riverton receives its Western inventory from coal transported by train to the Asbury Plant which is then transported by truck to Riverton.

        We have secured 88% of our anticipated coal requirements for 2009, 75% for 2010 and 29% for 2011 through a combination of contracts and binding proposals with Peabody Coal Sales, Arch Coal Sales, Rio Tinto, Phoenix Coal Sales and Oxbow Carbon and Minerals (petroleum coke). We plan to fulfill our remaining 2009 coal requirements through spot purchases. 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. The overall delivered price of coal is expected to be slightly higher in 2009 than in 2008 due to increased market costs.

        We currently lease one aluminum unit train on a full time basis and a second set is leased on an interim basis. These trains deliver Western coal to the Asbury Plant.

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        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 or 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 substantially all of Iatan's requirements for 2009 and approximately 35% for 2010, 25% for 2011 and 15% for 2012 and 2013. 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 as needed. During 2008, essentially all of the Energy Center generation came from natural gas. Based on kilowatt hours generated, State Line Unit 1 fuel consumption during 2008 was 90.4% natural gas with the remainder being oil. Our targeted oil inventory at the Energy Center facility permits eight days of full load operation on Units No. 1, 2, 3 and 4. As of December 31, 2008, oil inventories were sufficient for approximately 2 days of full load operation for these units at the Energy Center and 5 days of full load operation for State Line Unit No. 1.

        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. In 2002, we signed a precedent agreement with Williams Natural Gas Company (now Southern Star Central), which provides additional transportation capability for 20 years. 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.

        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:

Fuel Type/Facility
  2008   2007   2006  

Coal — Iatan

  $ 1.070   $ 0.978   $ 0.793  

Coal — Asbury

    1.577     1.432     1.402  

Coal — Riverton

    1.724     1.548     1.458  

Natural Gas

    6.909     7.050     7.276  

Oil

    16.721     14.870     6.551  

        Our weighted cost of fuel burned per kilowatt-hour generated was 3.1307 cents in 2008, 3.2197 cents in 2007 and 2.6502 cents in 2006.

Gas Segment

        In June 2007, we acquired 10,000 MMBtus per day of firm transportation from Cheyenne Plains Pipeline Company to enhance our Rocky Mountain supply position so that up to 75% of our natural gas purchases going forward could come from the Rocky Mountain gas area. We were able to fill our storage with Rocky Mountain gas supplies that were significantly less expensive during the summer of 2008 than the gas supplies produced in the mid-continent region. Cheyenne Plains interconnects with all of the interstate pipelines listed below that feed our market area. Through this effort we were able to reduce costs for our gas customers.

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        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 have expanded our supplier base in 2008 and will continue to do so to enhance supply reliability as well as provide for increased price competition.

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

Service Area
  Name of Pipeline   2008   2007   2006  
South   Southern Star Central Gas Pipeline   $ 8.9898   $ 8.2967   $ 8.6513  
North   Panhandle Eastern Pipe Line Company     8.3207     7.9568     8.9693  
Northwest   ANR Pipeline Company     8.0716     7.0551     7.5771  
    Weighted average cost   $ 8.6964   $ 8.0534   $ 8.5857  


Employees

        At December 31, 2008, we had 733 full-time employees, including 53 employees of EDG. 332 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. Local 814 of the IBEW and Local 695 of the IBEW both ratified a three-year contract with EDG which will expire on May 31, 2009. The contract requires at least 60 days notice to amend or cancel. At this time, no notice has been given to amend or cancel the contract by either Empire or Local 814 or Local 695. Effective January 1, 2009, both of these locals were merged into Local 1464 of the IBEW. The terms of the current contract remain the same.

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ELECTRIC OPERATING STATISTICS(1)

 
  2008   2007   2006   2005   2004  

Electric Operating Revenues (000's):

                               
 

Residential

  $ 179,293   $ 174,584   $ 159,381   $ 149,176   $ 124,394  
 

Commercial

    132,888     129,035     115,059     106,093     92,407  
 

Industrial

    67,353     67,712     64,820     59,593     51,861  
 

Public authorities(2)

    10,876     9,933     8,892     8,464     7,441  
 

Wholesale on-system

    19,229     18,444     17,561     16,582     13,614  
 

Miscellaneous

    6,976     5,703     4,605     4,833     6,076  
 

Interdepartmental

    154     123     101     101     92  
                       
   

Total system

    416,769     405,534     370,419     344,842     295,885  
 

Wholesale off-system

    29,697     19,627     12,234     14,139     7,010  
                       
   

Total electric operating revenues(3)

    446,466     425,161     382,653     358,981     302,895  
                       

Electricity generated and purchased (000's of kWh):

                               
 

Steam

    2,228,716     2,074,323     2,589,360     2,446,528     2,409,002  
 

Hydro

    32,601     71,360     22,673     62,325     63,036  
 

Combustion turbine

    1,480,729     1,427,298     955,856     1,453,297     1,009,259  
                       
   

Total generated

    3,742,046     3,572,981     3,567,889     3,962,150     3,481,297  
 

Purchased

    2,440,246     2,373,282     2,065,991     1,684,657     1,726,994  
                       
   

Total generated and purchased

    6,182,292     5,946,263     5,633,880     5,646,807     5,208,291  

Interchange (net)

    (436 )   (940 )   (173 )   (126 )   100  
                       
   

Total system input

    6,181,856     5,945,323     5,633,707     5,646,681     5,208,391  
                       

Maximum hourly system demand (Kw)

    1,152,000     1,173,000     1,159,000     1,087,000     1,014,000  

Owned capacity (end of period) (Kw)

    1,255,000     1,255,000     1,102,000     1,102,000     1,102,000  

Annual load factor (%)

    54.29     53.39     52.50     55.59     55.98  
                       

Electric sales (000's of kWh):

                               
 

Residential

    1,952,869     1,930,493     1,898,846     1,881,441     1,703,858  
 

Commercial

    1,622,048     1,610,814     1,547,077     1,485,034     1,417,307  
 

Industrial

    1,073,250     1,110,328     1,145,490     1,106,700     1,085,380  
 

Public authorities(2)

    122,375     115,109     111,204     111,245     106,416  
 

Wholesale on-system

    344,525     342,347     337,658     328,803     305,711  
                       
   

Total system

    5,115,067     5,109,091     5,040,275     4,913,223     4,618,672  
 

Wholesale off-system

    688,203     459,665     303,493     353,138     236,232  
                       
   

Total Electric Sales

    5,803,270     5,568,756     5,343,768     5,266,361     4,854,904  
                       

Company use (000's of kWh)(4)

    9,209     9,369     9,324     10,263     10,087  

kWh losses (000's of kWh)

    369,377     367,198     280,615     370,157     343,400  
                       
   

Total System Input

    6,181,856     5,945,323     5,633,707     5,646,781     5,208,391  
                       

Customers (average number):

                               
 

Residential

    140,791     139,840     137,689     134,724     132,172  
 

Commercial

    24,532     24,330     24,035     23,684     23,256  
 

Industrial

    361     362     370     365     357  
 

Public authorities(2)

    1,935     1,927     1,907     1,837     1,766  
 

Wholesale on-system

    4     4     4     4     4  
                       
   

Total System

    167,623     166,463     164,005     160,614     157,555  
 

Wholesale off-system

    22     20     20     17     16  
                       
   

Total

    167,645     166,483     164,025     160,631     157,571  
                       

Average annual sales per residential customer (kWh)

    13,871     13,805     13,791     13,965     12,891  

Average annual revenue per residential customer

  $ 1,273   $ 1,248   $ 1,158   $ 1,107   $ 941  

Average residential revenue per kWh

    9.18 ¢   9.04 ¢   8.39 ¢   7.93 ¢   7.30 ¢

Average commercial revenue per kWh

    8.19 ¢   8.01 ¢   7.44 ¢   7.14 ¢   6.52 ¢

Average industrial revenue per kWh

    6.28 ¢   6.10 ¢   5.66 ¢   5.38 ¢   4.78 ¢
                       

(1)
See Item 6, "Selected Financial Data" for additional financial information regarding Empire.

(2)
Includes Public Street & Highway Lighting and Public Authorities.

(3)
Before intercompany eliminations.

(4)
Includes kWh used by Company and Interdepartmental.

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GAS OPERATING STATISTICS(1)

 
  2008   2007   2006(2)  

Gas Operating Revenues (000's):

                   
 

Residential

  $ 39,639   $ 39,205   $ 15,957  
 

Commercial

    17,416     16,588     7,127  
 

Industrial

    5,069     752     356  
 

Public authorities

    416     373     161  
               
   

Total retail sales revenues

    62,540     56,918     23,601  
 

Miscellaneous(3)

    231     206     93  
 

Transportation revenues

    2,667     2,753     1,451  
               
   

Total Gas Operating Revenues

    65,438     59,877     25,145  
               

Maximum Daily Flow (mcf)

    66,005     68,379     60,890  
               

Gas delivered to customers (000's of mcf sales)(4)

                   
 

Residential

    2,949     2,835     1,101  
 

Commercial

    1,397     1,304     559  
 

Industrial

    553     76     32  
 

Public authorities

    35     30     12  
               
   

Total retail sales

    4,934     4,245     1,704  
 

Transportation sales

    4,059     4,300     2,150  
               
   

Total gas operating and transportation sales

    8,993     8,545     3,854  
               
 

Company use(3)

    4     2      
 

Transportation sales (cash outs)

        56     56  
 

Mcf losses

    140     8     (70 )
               
   

Total system sales

    9,137     8,611     3,840  
               

Customers (average number):

                   
 

Residential

    39,159     40,315     40,673  
 

Commercial

    5,119     5,208     5,399  
 

Industrial

    26     24     26  
 

Public authorities

    127     124     128  
               
   

Total retail customers

    44,431     45,671     46,226  
 

Transportation customers

    272     270     252  
               
   

Total gas customers

    44,703     45,941     46,478  
               

(1)
See Item 6, "Selected Financial Data" for additional financial information regarding Empire.

(2)
2006 revenues and mcf sales represent the months of June through December 2006.

(3)
Primarily includes miscellaneous service revenue and late fees.

(4)
Includes mcf used by Company and Interdepartmental mcf

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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, 2008, 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.

Name   Age at
12/31/08
  Positions With the Company   With the Company Since   Officer
Since
 

William L. Gipson

    51  

President and Chief Executive Officer (2002), Executive Vice President and Chief Operating Officer (2001), Vice President — Commercial Operations (1997)

    1981     1997  

Bradley P. Beecher(1)

    43  

Vice President and Chief Operating Officer — Electric (2006), Vice President — Energy Supply (2001), General Manager — Energy Supply (2001)

    2001     2001  

Harold Colgin

    59  

Vice President — Energy Supply (2006), General Manager — Energy Supply (2006), Plant Manager, Asbury Plant (1995)

    1972     2006  

Ronald F. Gatz

    58  

Vice President and Chief Operating Officer — Gas (2006), Vice President — Strategic Development (2002), Vice President — Nonregulated Services (2001), General Manager — Nonregulated Services (2001)

    2001     2001  

Gregory A. Knapp(2)

    57  

Vice President — Finance and Chief Financial Officer (2002), General Manager — Finance (2002)

    2002     2002  

Michael E. Palmer

    52  

Vice President — Commercial Operations (2001), General Manager — Commercial Operations (2001), Director of Commercial Operations (1997)

    1986     2001  

Kelly S. Walters(3)

    43  

Vice President — Regulatory and General Services (2006), General Manager — Regulatory and General Services (2005), Director of Regulatory and Planning (2001)

    2001     2006  

Janet S. Watson

    56  

Secretary — Treasurer (1995)

    1994     1995  

Laurie A. Delano(4)

    53  

Controller, Assistant Secretary and Assistant Treasurer and Principal Accounting Officer (2005), Director of Financial Services (2002)

    2002     2005  

(1)
Bradley P. Beecher was previously with Empire from 1988 to 1999 and held the positions of Director of Production Planning and Administration (1993) and Director of Strategic Planning (1995). During the period from 1999 to 2001, Mr. Beecher served as the Associate Director of Marketing and Strategic Planning for the Energy Engineering and Construction Division of Black & Veatch.

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(2)
Gregory A. Knapp was previously with Empire from 1978 to 2000 and held the position of Controller and Assistant Treasurer (1983). During the period from 2000 to 2002, Mr. Knapp served as Controller for the Missouri Department of Transportation.

(3)
Kelly S. Walters was previously with Empire from 1988 to 1998 and held the position of Director of Internal Auditing (1997-1998). Prior to rejoining Empire, she was Director of Financial Services of Crowder College.

(4)
Laurie A. Delano was previously with Empire from 1979 to 1991 and held the position of Director of Internal Auditing (1983-1991). Immediately prior to rejoining Empire, she was with Lozier Corporation, a store fixture manufacturing company, from 1997 to 2002, where she served as Plant Controller.


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, 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 2008, approximately 87.5% of our electric operating revenues were received from retail customers. Approximately 88.7%, 5.4%, 3.0% and 2.9% of such retail revenues were derived from sales in Missouri, Kansas, Oklahoma and Arkansas, respectively. Sales subject to FERC jurisdiction represented approximately 11.5% of our electric operating revenues during 2008 with the remaining 1.0% being from miscellaneous sources.

        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, 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

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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

        We are subject to various federal, state, and local laws and regulations with respect to air and water quality and with respect to hazardous and toxic materials and wastes, including their identification, transportation, disposal, record-keeping and reporting, as well as other environmental matters. We believe that our operations are in compliance with present laws and regulations.

Electric Segment

        Air.    The 1990 Amendments to the Clean Air Act, referred to as the 1990 Amendments, affect the Asbury, Riverton, State Line and Iatan 1 Power Plants and Units 3 and 4 (the FT8 peaking units) at the Empire Energy Center. The 1990 Amendments require affected plants to meet certain emission standards, including maximum emission levels for sulfur dioxide (SO2) and nitrogen oxides (NOx).

        SO2 Emissions.    Under the 1990 Amendments, the amount of SO2 an affected unit can emit is regulated. Each existing affected unit has been allocated a specific number of emission allowances, each of which allows the holder to emit one ton of SO2. Utilities covered by the 1990 Amendments must have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. The annual reconciliation of allowances, which occurs on a facility wide basis, is held each March 1 for the previous calendar year. Allowances may be traded between plants or utilities or "banked" for future use. A market for the trading of emission allowances exists on the Chicago Board of Trade. The Environmental Protection Agency (EPA) withholds annually a percentage of the emission allowances allocated to each affected unit and sells those emission allowances through a direct auction. We receive compensation from the EPA for the sale of these withheld allowances. During 2008, we received less than $0.1 million from the EPA auction.

        Our Asbury, Riverton and Iatan coal plants collectively receive 11,723 allowances per year. They burn a blend of low sulfur Western coal (Powder River Basin) and higher sulfur blend coal and petroleum coke, or burn 100% low sulfur Western coal. In addition, tire-derived fuel (TDF) is used as a supplemental fuel at the Asbury Plant. The Riverton Plant can also burn natural gas as its primary fuel. The State Line Plant, the Energy Center Units 3 and 4 and Riverton Unit 12 are gas-fired facilities and are allocated zero SO2 allowances. In the near term, annual allowance requirements for the State Line Plant, the Energy Center Units 3 and 4 and Riverton Unit 12, which are not expected to exceed 20 allowances per year, will be transferred from our inventoried bank of allowances. In 2008, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances allocated to us by the EPA. The annual EPA reconciliation of SO2 allowances does not occur until March 1 of the year following the actual SO2 emissions. We project that after the EPA reconciliation of March 1, 2009, we will have approximately 17,600 banked SO2 allowances as compared to 23,800 at March 1, 2008. We project that our 2009 emissions will again exceed the number of allowances allocated by the EPA by an amount approximately equal to the difference during 2008.

        When our SO2 allowance bank is exhausted, we will need to purchase additional SO2 allowances or build a Flue Gas Desulphurization (FGD) scrubber system at our Asbury Plant. Based on current and projected SO2 allowance prices and high-level estimated FGD scrubber construction costs ($81 million in 2010 dollars), we expect it will be more economical for us to purchase SO2 allowances than to build a scrubber at the Asbury Plant. We would expect the costs of SO2 allowances to be fully recoverable in our rates.

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        Effective March 1, 2005, the MPSC approved a Stipulation and Agreement granting us authority to manage our SO2 allowance inventory in accordance with our SO2 Allowance Management Policy (SAMP). The SAMP allows us to exchange banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value. We have not yet exchanged or sold any allowances under the SAMP.

        SO2 emissions will be further regulated as described in the Clean Air Interstate Rule section below.

        NOx Emissions.    The Asbury, Iatan, State Line, Energy Center and Riverton Plants are each in compliance with the NOx limits applicable to them under the 1990 Amendments as currently operated.

        The Asbury Plant received permission from the Missouri Department of Natural Resources (MDNR) to burn TDF at a maximum rate of 2% of total fuel input. During 2008, approximately 2,038 tons of TDF were burned. This is equivalent to 203,800 discarded passenger car tires.

        Under the MDNR's Missouri NOx Rule, our Iatan, Asbury, State Line and Energy Center facilities, like other facilities in western Missouri, are generally subject to a maximum NOx emission rate of 0.35 lbs/MMBtu during the ozone season of May 1 through September 30. Facilities which burn at least 100,000 passenger tire equivalents of TDF per year, including our Asbury Plant, are subject to a higher NOx emission limit of 0.68 lbs/MMBtu. All of our plants currently meet the required emission limits.

        In March 2008, the EPA lowered the National Ambient Air Quality Standard (NAAQS) for ozone from 84 ppb to 75 ppb. Ozone, also called ground level smog, is formed by the mixing of NOx and Volatile Organic Compounds (VOCs) in the presence of sunlight. It is possible that several counties in southwest Missouri will be classified as being in non-attainment of the ozone NAAQS standard by the EPA in 2010 or later. We anticipate that the EPA will classify the Kansas City area, where Iatan 1 is located, as being in non-attainment in 2010. At this time we do not foresee the need for additional pollution controls due to the reduction in the ozone standard. In addition, our units do not emit appreciable VOCs. We do not anticipate that southeast Kansas, where our Riverton Plant is located, will be classified as non-attainment under the new ozone NAAQS.

        NOx emissions will be further regulated as described in the Clean Air Interstate Rule section below.

Clean Air Interstate Rule (CAIR)

        The EPA issued its final CAIR on March 10, 2005. CAIR governed NOx and SO2 emissions from fossil fueled units greater than 25 megawatts in 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Units No. 1 and No. 2 are located and Arkansas where the Plum Point Energy Station is being constructed. Kansas was not included in CAIR and our Riverton Plant was not affected.

        On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAIR Rule and remanded it back to the EPA. On September 24, 2008, the EPA filed a petition for rehearing with the United States Court of Appeals. The court vacated CAIR based on its interpretation that the Clean Air Act did not provide the EPA with the authority needed for CAIR implementation. However, the court stayed its vacatur on December 23, 2008. As a result, CAIR became effective for NOx on January 1, 2009 and will become effective for SO2 on January 1, 2010.

        The CAIR is not directed to specific generation units, but instead, requires the states (including Missouri and Arkansas) to develop State Implementation Plans (SIPs) to comply with specific NOx and SO2 state-wide annual budgets. Missouri and Arkansas finalized their respective regulations and submitted their SIPs to the EPA, which were approved. We have received our full allotment of allowances as published in the Missouri CAIR Rule. Under the Arkansas CAIR rule, we will not receive allowances until approximately six years after Plum Point Unit 1 is operational. In the interim, we will transfer allowances from our Missouri units. Based on SIPs for Missouri and Arkansas, we believe we will have excess annual and ozone season NOx allowances. SO2 allowances must be utilized at a 2:1 ratio for our Missouri units as

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compared to our non-CAIR Kansas units beginning in 2010. As a result, based on current SO2 allowance usage projections, we expect to exhaust our banked allowances by the end of 2010 and will need to purchase additional SO2 allowances or build a scrubber at our Asbury Plant.

        In order to meet CAIR requirements and to meet air permit requirements for Iatan 2, pollution control equipment is being installed on Iatan 1 with the in-service date expected to be late in the first quarter to early in the second quarter of 2009. This equipment includes a Selective Catalytic Reduction (SCR) system, an FGD scrubber and a baghouse, with our share of the capital cost estimated to be between $58 million and $60 million, excluding AFUDC. Of this amount, approximately $3.9 million was incurred in 2006, $12.1 million in 2007 and $27.3 million in 2008 with estimated expenditures of approximately $15.6 million in 2009. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC.

        Also to meet CAIR requirements, we constructed an SCR at Asbury that was completed in November 2007 and placed in service in February 2008 at a total cost of approximately $31.0 million (excluding AFUDC). This project was also included as part of our Experimental Regulatory Plan approved by the MPSC and its cost is now in base rates in Missouri.

        Air Permits.    Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site's total air emissions; including emissions from stacks, individual pieces of equipment, road dust, coal dust and other emissions. We have been issued permits for Asbury, Iatan, Riverton, State Line and the Energy Center Plants. We submitted the required renewal applications for the State Line and Energy Center Title V permits in 2003 and the Asbury Title V permit in 2004 and will operate under the existing permits until the Missouri Department of Natural Resources (MDNR) issues the renewed permits. A Compliance Assurance Monitoring (CAM) plan for particulate matter (PM) will be required by the renewed permit for Asbury. We estimate that the capital costs associated with the PM CAM plan will not exceed $2 million. We submitted the renewal application for the Riverton Title V permit in June 2008. A CAM plan for PM will also be required by the renewed permit for Riverton. No additional capital costs are anticipated. It is expected that the Kansas Department of Health and Environment (KDHE) will issue the renewal permit for Riverton in the first quarter of 2009.

        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 Iatan Unit No. 2 currently under construction. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and baghouse are in place and fully operational, currently estimated to be late in the first quarter of 2009 to early in the second quarter of 2009.

        The Clean Air Act required companies to obtain permits and, if necessary, install control equipment to reduce emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in regulated emissions. The Sierra Club and Concerned Citizens of Platte County have claimed that modifications were made to Iatan 1 prior to the Comprehensive Energy Plan project in violation of Clean Air Act regulations. We own 12% of Iatan 1. As operator, KCP&L entered into a Collaboration Agreement with those parties that provide, among other things, for the release of such claims. In May 2008, a grand jury subpoena requesting documents was received by KCP&L. KCP&L continues to produce documents in response to the subpoena. The outcome of these activities cannot presently be determined, nor can the costs and other liabilities that could potentially result from a negative outcome presently be reasonably estimated.

Clean Air Mercury Rule (CAMR)

        On March 15, 2005, the EPA issued the CAMR regulations for mercury emissions by power plants under the requirements of the 1990 Amendments to the Clean Air Act. The new mercury emission limits

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of CAMR Phase 1 were to go into effect January 1, 2010. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia vacated the EPA's CAMR regulations which was appealed to the U.S. Supreme Court on October 17, 2008.

        The EPA has not yet issued guidance to the states regarding the vacated regulation nor recommended future actions. Based on CAMR, we installed a mercury analyzer at Asbury during late 2007 and installed two mercury analyzers at Riverton in 2008 in order to verify our mercury emissions and to meet the compliance date of January 1, 2009 for the Phase 1 mercury emission compliance date of January 1, 2010. We will operate the mercury analyzers at Riverton and Asbury in accordance with the appropriate state environmental regulator's guidance.

        If the CAMR rulemaking is ultimately revoked by the EPA after final adjudication, Maximum Achievable Control Technology (MACT) will re-emerge under current law. No specific MACT rulemakings have yet been adopted in Missouri or Kansas.

CO2 Emissions

        Our coal and gas plants emit carbon dioxide (CO2), a greenhouse gas. Although not currently regulated, increasing public concern and political pressure from local, regional, national and international bodies may result in the passage of new laws mandating limits on greenhouse gas emissions such as CO2. In April 2007, the U.S. Supreme Court issued a decision ruling the EPA improperly declined to address CO2 impacts in a rule-making related to new motor vehicle emissions. While this decision is not directly applicable to power plant emissions, the reasoning of the decision could affect other regulatory programs. The impact on us of any future greenhouse gas regulation will depend in large part on the details of the requirements and the timetable for mandatory compliance. We would expect the cost of complying with any such regulations to be fully recoverable in our rates.

        Water.    We operate under the Kansas and Missouri Water Pollution Plans that were implemented in response to the Federal Water Pollution Control Act Amendments of 1972. The Asbury, Iatan, Riverton, Energy Center and State Line plants are in compliance with applicable regulations and have received discharge permits and subsequent renewals as required.

        The Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act (CWA) Section 316(b) Phase II. The regulations became final on February 16, 2004 and required the submission of a Sampling Report and Comprehensive Demonstration Study with the permit renewal in 2008. Sampling and summary reports, which were completed during the first quarter of 2008 and submitted to the KDHE, indicate that the effect of the cooling water intake structure on Empire Lake's aquatic life is insignificant. The need for a further Demonstration Study is not expected. On January 25, 2007, the United States Court of Appeals for the Second Circuit remanded key sections of these CWA regulations. On July 9, 2007, the EPA suspended the regulation and is expected to revise and re-propose the regulation in 2009. In addition, on April 14, 2008 certiorari was granted by the United States Supreme Court limited to the review as to whether Section 316(b) of the CWA authorized the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impacts at cooling water intake structures. The Supreme Court heard oral arguments on December 2, 2008 and will issue their ruling in the first half of 2009. The permit renewal application was prepared and submitted in June 2008 and the final permit was received on January 1, 2009. Under the initial regulations, we did not expect costs associated with compliance to be material. We will reassess costs after the Supreme Court issues its ruling and the revised rules are complete.

        Ash Ponds.    We own and maintain coal ash ponds located at our Riverton and Asbury Power Plants. Additionally, we own a 12 percent interest in a coal ash pond at the Iatan Generating Station. All of the ash ponds are compliant with state and federal regulations.

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        Renewable Energy.    On November 4, 2008, Missouri voters approved the Clean Energy Initiative. This initiative requires investor-owned utilities in Missouri (such as Empire) to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, at the rate of at least 2% in retail sales by 2011, increasing to at least 15% by 2021. At least 25 other states have adopted renewable portfolio standard (RPS) programs that mandate some form of renewable generation. Some of these RPS programs incorporate a trading system in which utilities are allowed to buy and sell renewable energy certificates (RECs) in order to meet compliance. Additionally, RECs are utilized by many companies in "green" marketing efforts. REC prices are driven by various market forces. We have been selling RECs and plan to continue to sell all or a portion of the RECs associated with our contracts with Elk River Windfarm, LLC and Cloud County Windfarm, LLC. With respect to the energy underlying the RECs that we sell, we may not claim that we are purchasing renewable energy for any purpose, including for purposes of complying with the new Missouri requirements. Over time, we expect to retain some of the renewable attributes associated with these contracts in order to meet the new Missouri requirements. We realized revenues of $1.8 million from REC sales in 2008 and $0.9 million in 2007.

Gas Segment

        The acquisition of Missouri Gas involved the property transfer of two former manufactured gas plant (MGP) sites previously owned by Aquila, Inc. and its predecessors. Site #1 in Chillicothe, Missouri is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. Site #2 in Marshall, Missouri has received a letter of no further action from the MDNR. A Change of Use request and work plan was approved by the MDNR allowing us to expand our existing service center at Site #1 in Chillicothe, Missouri. This project, which was completed in October 2007, included the removal of all excavated soil and the addition of a new concrete surface replacing the existing gravel at a cost of approximately $0.1 million. We estimate further remediation costs at these two sites to be no more than approximately $0.2 million, based on our best estimate at this time. The remaining liability balance of $0.2 million is recorded under noncurrent liabilities and deferred credits. In our agreement with the MPSC approving the acquisition of Missouri Gas, it was agreed that we could reflect a liability and offsetting regulatory asset not to exceed $260,000 for the acquired sites. The MPSC agreed that up to $260,000 of costs related to the clean up of these MGP sites would be allowed for future rate recovery. Accordingly, we concluded that rate recovery was probable and at the acquisition date, a regulatory asset of $260,000 was recorded as part of the purchase price allocation based on our agreement with the MPSC, and in accordance with SFAS No. 71 — "Accounting for the Effects of Certain Types of Regulation" (FAS 71).


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 15 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 twelve months ended December 31, 2008, would permit us to issue approximately $253.5 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, 2008, we had retired bonds and net property additions which would enable the issuance of at least $612.0 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2008, we believe we are in compliance with all restrictive covenants of the EDE Mortgage.

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        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, 2008, these tests would allow us to issue new first mortgage bonds of approximately $3.1 million based on $4.2 million of property additions.

        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 Officers, 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

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:

 
  Fitch   Moody's   Standard & Poor's

Corporate Credit Rating

  n/r*   Baa2   BBB-

EDE First Mortgage Bonds

  BBB+   Baa1   BBB+

EDE First Mortgage Bonds — Pollution Control Series

  AAA   Aaa   AAA

Senior Notes

  BBB   Baa2   BBB-

Trust Preferred Securities

  BBB-   Baa3   BB

Commercial Paper

  F2   P-2   A-3

Outlook

  Negative   Negative   Stable

*
Not rated.

        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.

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

        The recent general market declines resulting in part from the sub-prime mortgage issues have generally reduced access to the capital markets and reduced market returns on investments. We estimate our capital expenditures to be $168.9 million in 2009. Although we believe it is unlikely we will have difficulty accessing the markets for the capital needed to complete these projects, our financing costs will likely be higher when compared to previous years. The market's effect on our pension plan assets resulted in a negative return of 25.1% in 2008. This decline will likely result in increased funding requirements under the Pension Protection Act of 2006.

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 lb 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.

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        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, such as those that occurred in 2005 and 2006, 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 lbs 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 lb 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 lb and market lb. Market lb 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 through our fuel adjustment mechanisms. Credit lb is the lb that the counterparty might fail to fulfill its obligations under contractual terms.

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, 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.

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Operations lbs may adversely affect our business and financial results.

        The operation of our electric generation, and electric and gas transmission and distribution systems involves many lbs, 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 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.

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.

        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 maintenance and repairs expense and 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 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 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 PGA 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

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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 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 generally recover 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.

The cost and schedule of construction projects may materially change.

        We have entered into contracts to purchase an undivided interest in 50 megawatts of the Plum Point Energy Station's new 665-megawatt, coal-fired generating facility which is being built near Osceola, Arkansas. We have also entered into an agreement with 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.

        There are lbs 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 or increased cost of qualified craft labor, the scope and timing of projects may change, and other events beyond our control may occur that may materially affect the schedule, budget and performance of these projects.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

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ITEM 2.    PROPERTIES

Electric Segment Facilities

        At December 31, 2008, we owned generating facilities with an aggregate generating capacity of 1,255 megawatts.

        Our principal electric baseload generating plant is the Asbury Plant with 210 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 17% of our owned generating capacity and in 2008 accounted for approximately 35.0% 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. Our Asbury units went off-line September 21, 2007 and were expected to be back on-line during the last week of November, during which time we expected to tie in the SCR being constructed at Asbury. However, on December 7, 2007, during the reassembly of the generator, the unit failed inspection. On December 9, 2007, it was determined that corrective action would be necessary and that the additional work would require the unit to remain on outage an additional 60 days. Asbury went back online on February 10, 2008. The Unit No. 2 turbine is inspected approximately every 35,000 hours of operations and was last inspected in 2001. As of December 31, 2008, Unit No. 2 has operated approximately 2,745 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 with an aggregate generating capacity of 92 megawatts and four gas-fired combustion turbine units 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. Unit No. 8 was taken out of service on May 5, 2008 for a scheduled maintenance outage which was extended until July 1, 2008 in order to repair turbine blade damage discovered during the routine inspection. 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. The new permit limits Unit No. 1 to a maximum of 6,600 MMBtu per hour of heat input. This heat input limit allows Unit No. 1 to produce a total of 652 net megawatts, and, as a result, our share decreased from 80 megawatts to 78 megawatts. The 6,600 MMBtu per hour heat input limit is in effect until the new SCR, scrubber, and baghouse are in place and fully operational. We are entitled to 12% of the unit's available capacity and are obligated to pay for that percentage of the operating costs of the unit. KCP&L operates the unit for the joint owners.

        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. The outage was scheduled to be complete on December 30, 2008; however, due to unforeseen circumstances related to the economizer upgrade that took place during the outage, the projected return to service date had to be extended to late January 2009. 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. Current estimates have the unit returning to service late in the first quarter to early in the second quarter of 2009.

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        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.

        We have four combustion turbine peaking units, including two FT8 peaking units installed in 2003, at the Empire Energy Center in Jasper County, Missouri, with an aggregate generating capacity of 269 megawatts. These peaking units operate on natural gas, as well as oil. On June 21, 2007, Unit No. 3 was taken out of service due to the failure of an engine bearing. It was returned to service on October 3, 2007.

        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 Appropriations Act has a provision for the Army Corp of Engineers to provide a one time payment to us for lost energy production. 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 Draft Determination in the Federal Register on March 6, 2008. Subsequently, on July 3, 2008, the SWPA published its Proposed Determination in the Federal Register. The SWPA published its Final Determination on January 23, 2009. SWPA's Final Determination Report documents the procedure to be used 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 are 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 results in a present value for the estimated future lifetime replacement costs of the electrical energy and capacity at Ozark Beach of $41,319,400. We expect that the Army Corp of Engineers will not implement the new minimum flow plan until at least 2010, but, at this time, we cannot be sure of the timetable as it is dependent on Congress providing funding for the economic detriment.

        At December 31, 2008, our transmission system consisted of approximately 22 miles of 345 kV lines, 434 miles of 161 kV lines, 744 miles of 69 kV lines and 81 miles of 34.5 kV lines. Our distribution system consisted of approximately 6,857 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.

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        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.


Gas Segment Facilities

        At December 31, 2008, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately 1,113 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 Businesses

        Our other segment consists of our non-regulated businesses, primarily a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business. We use the fiber optics cable and equipment in our own operations and also lease it to other entities. We sold our controlling 52% interest in MAPP on August 31, 2006, a company that specialized in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. In December 2006, we sold our 100% interest in Conversant, Inc., a software company that marketed Customer Watch, an Internet-based customer information system software. On September 28, 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service provider.

ITEM 3.    LEGAL PROCEEDINGS

        See description of legal matters set forth in Note 12 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 6, 2008, there were 5,142 record holders and 28,875 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 2008 and 2007 were as follows:

 
  Price of Common Stock    
   
 
 
  Dividends Paid
Per Share
 
 
  2008   2007  
 
  High   Low   High   Low   2008   2007  

First Quarter

  $ 23.29   $ 19.33   $ 26.11   $ 23.07   $ 0.32   $ 0.32  

Second Quarter

    21.88     18.30     26.13     21.99     0.32     0.32  

Third Quarter

    23.48     18.37     24.29     21.09     0.32     0.32  

Fourth Quarter

    21.60     14.90     24.34     22.22     0.32     0.32  

        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, 2008, our retained earnings balance was $13.6 million (compared to $17.2 million at December 31, 2007) after paying out $43.3 million in dividends during 2008. If we were to reduce our dividend per share, partially or in whole, it could have an adverse effect on our common stock price.

        The EDE Mortgage and the 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 $10.75 million, as described above. As of December 31, 2008, 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, 2008, there were no such restrictions on our ability to pay dividends.

        During 2008, 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

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market price, newly issued common shares with optional cash payments on a weekly basis, subject to certain restrictions. We also offer participants the option of safekeeping for their stock certificates.

        Our shareholders rights plan provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of common stock owned. One Right enables the holder to acquire one one-hundredth of a share of Series A Participating Preference Stock (or, under certain circumstances, other securities) at a price of $75 per one-hundredth of a share, subject to adjustment. The rights (other than those held by an acquiring person or group (Acquiring Person)) will be exercisable only if an Acquiring Person acquires 10% or more of our common stock or if certain other events occur. See Note 6 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 5 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 5 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding our common stock and equity compensation plans.

        The following graph and table indicates the value at the end of the specified years of a $100 investment made on December 31, 2003, 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.

GRAPHIC

Total Return Analysis
  12/31/2003   12/31/2004   12/31/2005   12/31/2006   12/31/2007   12/31/2008  

The Empire District Electric Company

  $ 100.00   $ 109.72   $ 104.09   $ 133.71   $ 130.21   $ 107.26  

S&P Electric Utilities Index

  $ 100.00   $ 126.67   $ 149.53   $ 183.81   $ 226.31   $ 167.84  

S&P 500 Index

  $ 100.00   $ 110.88   $ 116.33   $ 134.70   $ 142.10   $ 89.53  

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

 
  2008   2007   2006(2)   2005   2004  

Operating revenues

  $ 518,163   $ 490,160   $ 412,171   $ 362,720   $ 306,354  

Operating income

  $ 71,012   $ 65,566   $ 69,821   $ 53,920   $ 53,212  

Total allowance for funds used during construction

  $ 12,518   $ 7,665   $ 4,255   $ 561   $ 220  

Income from continuing operations

  $ 39,722   $ 33,181   $ 40,029   $ 24,944   $ 23,542  

Income (loss) from discontinued operations, net of tax

  $   $ 63   $ (749 ) $ (1,176 ) $ (1,694 )

Net income

  $ 39,722   $ 33,244   $ 39,280   $ 23,768   $ 21,848  

Weighted average number of common shares outstanding — basic

    33,821     30,587     28,277     25,898     25,468  

Weighted average number of common shares outstanding — diluted

    33,860     30,610     28,296     25,941     25,521  

Earnings from continuing operations per weighted average share of common stock — basic and diluted

  $ 1.17   $ 1.09   $ 1.42   $ 0.96   $ 0.93  

Loss from discontinued operations per weighted average share of common stock — basic and diluted

  $   $ 0.00   $ (0.03 ) $ (0.04 ) $ (0.07 )

Total earnings per weighted average share of common stock — basic and diluted

  $ 1.17   $ 1.09   $ 1.39   $ 0.92   $ 0.86  

Cash dividends per share

  $ 1.28   $ 1.28   $ 1.28   $ 1.28   $ 1.28  

Common dividends paid as a percentage of net income

    109.0 %   117.2 %   91.8 %   139.5 %   149.3 %

Allowance for funds used during construction as a percentage of net income

    31.5 %   23.1 %   10.8 %   2.4 %   1.0 %

Book value per common share (actual) outstanding at end of year

  $ 15.56   $ 16.04   $ 15.49   $ 15.08   $ 14.76  

Capitalization:

                               
 

Common equity

  $ 528,872   $ 539,176   $ 468,609   $ 393,411   $ 379,180  
 

Long-term debt

  $ 611,567   $ 541,880   $ 462,398   $ 407,786   $ 397,371  

Ratio of earnings to fixed charges

    2.19x     2.08x     2.60x     2.21x     2.12x  

Total assets

  $ 1,713,846   $ 1,473,074   $ 1,319,142   $ 1,122,030   $ 1,027,539  

Plant in service at original cost

  $ 1,580,558   $ 1,500,640   $ 1,374,837   $ 1,282,123   $ 1,247,380  

Capital expenditures (including AFUDC)(3)

  $ 206,405   $ 195,568   $ 120,171   $ 73,232   $ 41,045  

(1)
All years presented 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 formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. It provides natural gas distribution to customers in 44 communities in northwest, north central and west central Missouri. Our other segment consists of our non-regulated businesses, primarily a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business. During the twelve months ended December 31, 2008, 86.5% of our gross operating revenues were provided from sales from our electric segment (including 0.3% from the sale of water), 12.6% from the sale of gas and 0.9% from our non-regulated businesses.

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. Weather affects the demand for electricity. 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 1.6% over the next several years. Our electric customer growth for the twelve months ended December 31, 2008 was 0.4%. 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 latest 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 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

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relief and file for such relief when necessary. However, as part of the unanimous stipulation and agreement filed with the MPSC on March 1, 2006 and approved on April 18, 2006, we have agreed to not file a rate increase request for non-gas costs prior to June 1, 2009. A PGA clause is included in our gas rates, which allows us to 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 twelve months ended December 31, 2008 was 1.5%, which we believe was due to higher gas prices and general economic conditions. The rate of gas customer contraction is expected to level out during the next two years and to remain relatively flat after 2010. 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 twelve months ended December 31, 2008, basic and diluted earnings per weighted average share of common stock were $1.17 compared to $1.09 for the twelve months ended December 31, 2007. As reflected in the table below, the primary positive drivers were increased electric and gas revenues while the primary negative drivers were increased fuel and purchased power costs.

        The following reconciliation of basic earnings per share between 2007 and 2008 is a non-GAAP presentation. We believe this information is useful in understanding the fluctuation in earnings per share between the prior and current years. The reconciliation presents the after tax impact of significant items and components of the income statement on a per share basis before the impact of additional stock issuances which is presented separately. Earnings per share for the years ended December 31, 2007 and 2008 shown in the reconciliation are presented on a GAAP basis and are the same as the amounts included

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in the statements of operations. This reconciliation may not be comparable to other companies or more useful than the GAAP presentation included in the statements of operations.

Earnings Per Share — 2007

  $ 1.09  

Revenues

       
 

Electric on-system

  $ 0.22  
 

Electric off-system and other

    0.26  
 

Gas

    0.12  
 

Water

     
 

Other

    0.03  

Expenses

       
 

Electric fuel and purchased power

    (0.29 )
 

Cost of natural gas sold and transported

    (0.11 )
 

Regulated — electric segment

    (0.02 )
 

Regulated — gas segment

    0.01  
 

Other segment

    (0.01 )
 

Maintenance and repairs

    0.08  
 

Depreciation and amortization

    (0.02 )
 

Other taxes

    (0.01 )
 

Interest charges

    (0.09 )
 

AFUDC

    0.11  
 

Gain on sale of assets

    (0.03 )
 

Change in effective income tax rates

    (0.04 )
 

Other income and deductions

    (0.02 )
 

Dilutive effect of additional shares issued

    (0.11 )
       

Earnings Per Share — 2008

  $ 1.17  
       

Fourth Quarter Results

        Earnings for the fourth quarter of 2008, were $7.7 million, or $0.23 per share, as compared to a net loss of $0.4 million, or ($0.01) per share, in the fourth quarter 2007. Total revenues increased approximately $16.5 million (14.4%) for the fourth quarter of 2008 as compared to the fourth quarter of 2007 primarily due to the Missouri rate increase. Total electric revenues were $11.5 million higher, primarily as a result of the rate increase, which had an estimated $5.3 million impact, weather, which had a positive impact of an estimated $2.3 million and an increase in off-system sales of $3.0 million. Increased revenues from our gas segment were $4.8 million. Electric fuel and purchased power costs were $2.8 million less this quarter versus last year, primarily due to lower natural gas prices and our regulatory adjustment of $1.7 million. Our fourth quarter electric fuel and purchased power expenditures were higher than the base cost in our Missouri rates. Therefore, $1.7 million was transferred from fuel costs to a regulatory asset. Costs of natural gas sold and transported for our gas segment increased $4.6 million. Other impacts to the quarter included increased income taxes (approximately $5.7 million) and maintenance and repairs expense (approximately $0.7 million).

2008 Activities

Recent Capital Market Events

        We have monitored recent market events that could have potential business and accounting issues associated with our operations.

        We evaluated our credit exposure with trading counterparties and we do not at this time believe that counterparty default is likely, although, according to published reports, certain of our counterparties

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continue to be adversely impacted by the current credit crisis. In the event that the counterparties to our hedging arrangements were no longer probable of performance, we would discontinue the use of cash flow hedge treatment for these contracts. However, the fuel adjustment clause authorized in the recent Missouri rate case allows us to record any gains or losses associated with our hedging arrangements as a regulatory asset or liability. Accordingly, we believe any counterparty defaults we may experience should not substantially impact our earnings.

        Similar to many companies, we are exposed to the risk of credit rating downgrades from rating agencies; however, we have not received any downgrades of our securities.

        The general market decline has negatively impacted the performance of our pension assets through December 31, 2008. Our net pension liability increased $53.2 million and our net liability for other postretirement benefits increased $15.5 million. These increases were recorded as increases in regulatory assets as we believe they are probable of recovery through customer rates based on rate orders received in our jurisdictions. We expect future pension funding commitments to increase. The expected minimum funding for 2009 is estimated to be between $0 million and $4 million. For 2010 it is estimated to be between $9 million and $15 million. The actual minimum funding requirements will be determined based on the results of the actuarial valuations, and, in the case of 2010, the performance of our pension assets during 2009.

        Historically, we have met most of our short-term cash flow needs through the issuance of commercial paper. However, due to recent market events, we have generally been unable to issue commercial paper at rates below what we can borrow the funds at under our unsecured revolving credit facility. As a result, we have borrowed under this credit facility to meet short-term cash flow needs. See "Liquidity and Capital Resources" below for further discussion.

Financing

        On May 16, 2008, we issued $90 million principal amount of first mortgage bonds. The net proceeds of approximately $89.4 million, less $0.4 million of legal and other financing fees, were added to our general funds and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

        We have a $400 million shelf registration statement with the SEC, which became effective on August 15, 2008, covering our common stock, unsecured debt securities, preference stock, first mortgage bonds and trust preferred securities. We have received regulatory approval in all four of our state jurisdictions. Of the $400 million, $250 million is available for first mortgage bonds. We plan to use a portion of the proceeds from issuances under this shelf to fund a portion of the capital expenditures for our new generation projects.

Regulatory Matters

        On October 1, 2007, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $34.7 million, or 10.11%. The MPSC issued an order on July 30, 2008, granting 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 order contains two components. The first component provides an addition to base rates of approximately $27.7 million. This increase in base rates was partially offset by a $5.7 million reduction to regulatory amortization, which is the second component of the overall change in revenue authorized by the MPSC. Regulatory amortization provides us additional cash through rates to support certain credit metrics during the current construction cycle. This construction, which is part of our long-range plan to ensure reliability, includes the facilities at the Riverton Power Plant and Iatan 2 Power Plant, as well as

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environmental improvements at the Asbury Power Plant and at Iatan 1. The regulatory amortization is now approximately $4.5 million annually and is recorded as depreciation expense.

        The MPSC also authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base cost 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 prudently incurred above or below the base cost. Off-system sales margins are also part of the recovery of fuel and purchased power costs. As a result, the off-system sales margin flows back to the customer. Rates related to the fuel adjustment clause will be modified twice a year subject to the review and approval by the MPSC. In accordance with FAS 71, 95% of the difference between the actual cost of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or a regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered or refunded to our customers when the fuel adjustment clause is modified. At December 31, 2008, Missouri fuel and purchased power costs were over recovered $0.2 million, which is reflected as a regulatory liability.

        The MPSC order approved a Stipulation and Agreement providing for the recovery of deferred expenses of approximately $14.2 million over a five year period for the 2007 ice storms. In addition, the MPSC order required the implementation of a two-way tracking mechanism for recovery of the costs relating to the new MPSC rules on infrastructure inspection and vegetation management. The mechanism authorized by the MPSC creates a regulatory liability in any year we spend less than the target amount, which has been set at $8.6 million for our Missouri jurisdiction, and a regulatory asset if we spend more than the target amount. Any regulatory asset and liability amounts created using the tracking mechanism will then be netted against each other and taken into account in our next rate case. The MPSC also approved Stipulations and Agreements providing for the continuation of the pension and other post-retirement employee benefits tracking mechanism established in our 2007 and 2008 Missouri rate orders. (When we refer to rate orders dates, we are referring to the date the order was effective). See Note 1 of "Notes to Consolidated Financial Statements" under Item 8 for discussion regarding the treatment of the pension and other post-retirement employee benefits tracked.

        The MPSC issued its Report and Order on July 30, 2008, effective August 9, 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.

        For additional information, see "Rate Matters" below.

        Renewable Energy.    On November 4, 2008, Missouri voters approved the Clean Energy Initiative. This initiative requires investor-owned utilities in Missouri (such as Empire) to generate or purchase electricity from renewable energy sources, such as solar, wind, biomass and hydro power, at the rate of at least 2% in retail sales by 2011, increasing to at least 15% by 2021. At least 25 other states have adopted renewable portfolio standard (RPS) programs that mandate some form of renewable generation. Some of these RPS programs incorporate a trading system in which utilities are allowed to buy and sell renewable energy certificates (RECs) in order to meet compliance. Additionally, RECs are utilized by many companies in "green" marketing efforts. REC prices are driven by various market forces. We have been selling RECs

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and plan to continue to sell all or a portion of the RECs associated with our contracts with Elk River Windfarm, LLC and Cloud County Windfarm, LLC. With respect to the energy underlying the RECs that we sell, we may not claim that we are purchasing renewable energy for any purpose, including for purposes of complying with the new Missouri requirements. Over time, we expect to retain some of the renewable attributes associated with these contracts in order to meet the new Missouri requirements. We realized revenues of $1.8 million from REC sales in 2008 and $0.9 million in 2007.

Amendment of EDE Mortgage

        On March 11, 2008, we amended the Indenture of Mortgage and Deed of Trust of The Empire District Electric Company (EDE Mortgage) in order to provide us with additional flexibility to pay dividends to our shareholders by increasing the basket available to pay dividends by $10.75 million. The amendment followed the successful completion of a solicitation of consents from the holders of our First Mortgage Bonds outstanding under the EDE Mortgage. We received consents from holders of 94.46% in aggregate principal amount of the outstanding bonds and paid fees of approximately $1.6 million to the consenting bondholders. See " — Dividends" below.

Energy Supply

        In June 2007, we entered into a purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy, Houston, Texas. This agreement provides for a 20-year term commencing with the commercial operation date, which was December 15, 2008. Pursuant to the terms of the agreement, we will purchase all of the output from the approximately 105-megawatt Phase 1 Meridian Wind Farm located in Cloud County, Kansas. We do not own any portion of the windfarm.

Asbury SCR and Maintenance Outage

        We constructed an SCR at Asbury that was completed in November 2007 and placed in service in February 2008. The total cost of the SCR project was approximately $31.0 million (excluding AFUDC), of which $28.1 million was expended through December 31, 2007 with the remainder expended in 2008. This project was also included as part of our Experimental Regulatory Plan approved by the MPSC and its cost is now in base rates in Missouri. We combined this project with our five year Asbury maintenance outage.

        Our Asbury units went off-line September 21, 2007 and were expected to be back on-line during the last week of November, during which time we expected to tie in the SCR. However, on December 7, 2007, during the reassembly of the generator, the unit failed inspection. On December 9, 2007 it was determined that corrective action would be necessary and that additional work would require the unit to remain on outage an additional 60 days. The unit was returned to service on February 10, 2008. We replaced the energy that would have been generated by our coal-fired units at the Asbury plant with energy generated at our gas plants and with purchased power. After assessing the actual cost of the incremental purchased power and gas-fired generation, we estimate the original planned outage added incremental expenses of approximately $8.7 million for the fourth quarter of 2007. We estimate the extended outage increased expenses an additional $3.5 million in the fourth quarter of 2007 (December 8-December 31, 2007) and an additional $5.8 million in the first quarter of 2008 (January 1-February 10, 2008).


RESULTS OF OPERATIONS

        The following discussion analyzes significant changes in the results of operations for the years 2008, 2007 and 2006.

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

(in millions)
  2008   2007   2006  

Income from continuing operations:

                   
 

Electric

  $ 37.4   $ 31.8   $ 40.9  
 

Gas

    1.7     1.0     (1.0 )
 

Other

    0.6     0.4     0.1  
               

Income from continuing operations

  $ 39.7   $ 33.2   $ 40.0  

Income (loss) from discontinued operations

            (0.7 )
               

Net income

  $ 39.7   $ 33.2   $ 39.3  
               

Differences could occur due to rounding.

Electric Segment

Overview

        Our electric segment income from continuing operations for 2008 was $37.4 million as compared to $31.8 million for 2007.

        Electric operating revenues comprised approximately 86.5% of our total operating revenues during 2008. Of these total electric operating revenues, approximately 40.2% were from residential customers, 29.8% from commercial customers, 15.1% from industrial customers 4.3% from wholesale on-system customers, 6.6% from wholesale off-system transactions, 2.5% from miscellaneous sources, primarily public authorities and 1.5% from other electric revenues. The percentage of revenues provided from our wholesale off-system transactions has increased during 2008 as compared to 2007 primarily due to sales facilitated by the EIS market that began on February 1, 2007.

        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:

 
  kWh Sales
(in millions)
 
Customer Class
  2008   2007   % Change*   2007   2006   % Change*  

Residential

    1,952.9     1,930.5     1.2 %   1,930.5     1,898.8     1.7 %

Commercial

    1,622.0     1,610.8     0.7     1,610.8     1,547.1     4.1  

Industrial

    1,073.3     1,110.3     (3.3 )   1,110.3     1,145.5     (3.1 )

Wholesale on-system

    344.5     342.3     0.6     342.3     337.7     1.4  

Other**

    123.8     116.8     6.0     116.8     112.7     3.6  
                               
 

Total on-system sales

    5,116.5     5,110.7     0.1     5,110.7     5,041.8     1.4  

Off-system

    688.2     459.7     49.7     459.7     303.5     51.5  
                               

Total KWh Sales

    5,804.7     5,570.4     4.2     5,570.4     5,345.3     4.2  

*
Percentage changes are based on actual kWh sales and may not agree to the rounded amounts shown above.

**
Other kWh sales include street lighting, other public authorities and interdepartmental usage.

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  Electric Segment Operating Revenues
(in millions)
 
Customer Class
  2008   2007   % Change*   2007   2006   % Change*  

Residential

  $ 179.3   $ 174.6     2.7 % $ 174.6   $ 159.4     9.5 %

Commercial

    132.9     129.0     3.0     129.0     115.0     12.1  

Industrial

    67.4     67.7     (0.5 )   67.7     64.8     4.5  

Wholesale on-system

    19.2     18.4     4.3     18.4     17.6     5.0  

Other**

    11.0     10.1     9.7     10.1     9.0     11.8  
                               
 

Total on-system revenues

    409.8     399.8     2.5     399.8     365.8     9.3  

Off-system

    29.7     19.6     51.3     19.6     12.2     60.4  
                               

Total Revenues from KWh Sales

    439.5     419.4     4.8     419.4     378.0     11.0  

Miscellaneous Revenues***

    7.0     5.7     22.3     5.7     4.6     23.8  
                               

Total Operating Revenues

  $ 446.5   $ 425.1     5.0   $ 425.1   $ 382.6     11.1  

Water Revenues

    1.7     1.9     (5.1 )   1.9     1.8     2.0  
                               

Total Electric Segment Operating Revenues

  $ 448.2   $ 427.0     5.0   $ 427.0   $ 384.4     11.1  

*
Percentage changes are based on actual revenues and may not agree to the rounded amounts shown above.

**
Other operating revenues include street lighting, other public authorities and interdepartmental usage.

***
Miscellaneous revenues include transmission service revenues, late payment fees, rent, etc.

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. We expect our annual customer growth to range from approximately 1.1% to 1.6% over the next several years.

        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. Revenues associated with these FERC-regulated sales increased more than the kWh sales as a result of the fuel adjustment clause applicable to such sales. This clause permits the distribution to customers of changes in fuel and purchased power costs.

Off-System Electric Transactions

        In addition to sales to our own customers, we also sell power to other utilities as available and provide transmission service through our system for transactions between other energy suppliers (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 get recorded as fuel

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and purchased power expense. The following table sets forth information regarding these sales and related expenses for the years ended December 31:

(in millions)
  2008   2007  

EIS revenues

  $ 13.1   $ 8.8  

Other revenues

    16.6     10.8  
           
 

Subtotal off-system revenues

    29.7     19.6  

Transmission service revenues

    2.4     2.5  
           
 

Total off-system revenues

    32.1     22.1  

EIS expenses

   
9.3
   
6.2
 

Other expenses

    12.2     7.8  
           
 

Subtotal off-system expenses

    21.5     14.0  

Transmission service costs

    1.9     1.8  
           
 

Total off-system expenses

    23.4     15.8  

Net

 
$

8.7
 
$

6.3
 

        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.

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 expense 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 income statement for 2008. The regulatory adjustments shown below reduced fuel and purchased power expense by $0.3 million in 2008 and increased fuel and purchased power $0.2 million in 2007.

(in millions)
  2008   2007  

Actual fuel and purchased power expenditures

  $ 204.1   $ 191.0  

Kansas regulatory adjustments*

    (0.5 )   0.2  

Missouri regulatory adjustments*

    0.2      

Unrealized loss on derivatives

    0.3      
           
 

Total fuel and purchased power expense per income statement

  $ 204.1   $ 191.2  

      *
      A negative amount indicates costs have been under recovered from customers and a positive amount indicates costs have been over recovered from customers.

        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.

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        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.

(in millions)
  2008  

Purchased power (cost per mWh)

  $ 9.6  

Purchased power spot purchase volume

    0.4  

Coal (cost per mWh)

    4.0  

Coal generation volume

    2.5  

Natural gas (cost per mWh)

    (1.3 )

Natural gas generation volume

    (0.2 )

Natural gas — gain on unwind of positions

    (2.1 )

Other (including fuel adjustments)

    (0.1 )
       
 

TOTAL

  $ 12.8  

        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.

        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 steel 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.

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2007 Compared to 2006

Operating Revenues and Kilowatt-Hour Sales

        KWh sales for our on-system customers increased approximately 1.4% during 2007 as compared to 2006 primarily due to continued sales growth. Revenues for our on-system customers increased approximately $34.0 million, or 9.3%. The January 2007 Missouri rate increase (discussed below) contributed an estimated $38.3 million in revenues in 2007 while continued sales growth contributed an estimated $8.0 million. Weather and other factors contributed an estimated $2.2 million. These increases were partially offset by the $5.9 million revision to our estimate of unbilled revenues in the third quarter of 2006 and $8.6 million of interim energy charge (IEC) collected in 2006, neither of which reoccurred in 2007.

        Residential and commercial kWh sales and associated revenues increased in 2007 primarily due to sales growth while the associated revenues also increased due to the January 2007 Missouri rate increase. Industrial kWh sales decreased 3.1% primarily due to a pipeline customer running at minimum output during the first quarter of 2007 as well as the revision to our estimate of unbilled revenues in the third quarter of 2006 while the associated revenues increased 4.5%, reflecting the aforementioned 2007 rate increase. On-system wholesale kWh sales increased reflecting the continued sales growth discussed above. Revenues associated with these FERC-regulated sales increased more than the kWh sales as a result of the fuel adjustment clause applicable to such sales.

Off-System Electric Transactions

        In addition to sales to our own customers, we also sell power to other utilities as available and provide transmission service through our system for transactions between other energy suppliers (including through the SPP EIS market). See "— Competition" below. The following table sets forth information regarding these sales and related expenses for the years ended December 31:

(in millions)
  2007   2006  

EIS revenues

  $ 8.8   $  

Other revenues

    10.8     12.2  
           
 

Subtotal off-system revenues

    19.6     12.2  

Transmission service revenues

    2.5     2.2  
           
 

Total off-system revenues

    22.1     14.4  

EIS expenses

   
6.2
   
 

Other expenses

    7.8     8.8  
           
 

Subtotal off-system expenses

    14.0     8.8  

Transmission service costs

    1.8     1.6  
           
 

Total off-system expenses

    15.8     10.4  

Net

 
$

6.3
 
$

4.0
 

        Revenues less expenses increased during 2007 as compared to 2006 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.

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Operating Revenue Deductions

        During 2007, total electric segment operating expenses increased approximately $50.3 million (15.9%) compared to 2006.

        Total fuel and purchased power expense increased approximately $30.9 million (19.3%) during 2007 as compared to 2006. This increase included the effect of increased costs for off-system sales of $5.4 million and the effect of replacement power for the Asbury and Riverton 8 outages in 2007. Our gas-fired generation increased primarily from the extended outage at the Asbury plant during the fourth quarter of 2007, the Iatan plant outage during the second quarter of 2007 and the fact that we increased on-system and off-system sales in 2007. The availability of Riverton 12 in the spring of 2007 added additional gas-fired capability that allowed us to sell power into the SPP energy imbalance services market. After assessing the actual cost of the incremental purchased power and gas-fired generation, we estimate the planned Asbury outage added incremental expenses for the fourth quarter in 2007 of approximately $8.7 million and the extended outage (December 8-December 31, 2007) 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 2006. This table incorporates all the changes mentioned above. As shown below, the largest impact on fuel and purchased power costs was increased volumes for both natural gas generation and purchased power offset by decreased coal generation volume mainly due to the Asbury outage.

(in millions)
  2007  

Purchased power (cost per mWh)

  $ 2.3  

Purchased power spot purchase volume

    8.2  

Coal (cost per mWh)

    1.6  

Coal generation volume

    (7.3 )

Natural gas (cost per mWh)

    (3.6 )

Natural gas generation volume

    28.7  

Other

    1.0  
       
 

TOTAL

  $ 30.9  

        Regulated operating expenses for our electric segment increased approximately $7.0 million (12.8%) during 2007 as compared to 2006 primarily due to increases of $2.1 million in employee pension expense, $1.3 million in uncollectible accounts, $1.1 million in transmission and distribution expense, $0.6 million in labor and other costs, $0.6 million in customer accounts expense, $0.4 million in regulatory commission expense, $0.4 million in other steam power expense, $0.4 million in injuries and damages and $0.2 million in other power supply expense, partially offset by a $0.2 million decrease in professional services. The increase in pension costs is primarily due to the effects of regulatory accounting. We defer or record pension and other postretirement benefit costs (other than EDG other postretirement benefit costs) if they are more or less, respectively, than those allowed in rates for the Missouri and Kansas portion of pension costs. See Note 4 of "Notes to Consolidated Financial Statements" under Item 8 for further discussion regarding the regulatory treatment of our pension and post-retirement benefit plans.

        Maintenance and repairs expense increased approximately $8.5 million (38.7%) during 2007 as compared to 2006 primarily reflecting increases of approximately $7.7 million in distribution maintenance costs, including $3.9 million of incremental costs (and the $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, $0.8 million in transmission distribution maintenance costs and $0.9 million in maintenance costs for our coal-fired units, partially offset by a decrease of approximately $0.8 million in maintenance costs for our gas-fired units. The $0.9 million

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increase in maintenance costs for our coal-fired units consisted mainly of a $0.5 million increase in maintenance costs at our Iatan Plant related to the 2007 first quarter inspection, a $0.2 million increase in maintenance costs at our Riverton Plant and a $0.1 million increase in maintenance costs at our Asbury Plant. The $0.8 million decrease in maintenance for our gas-fired units consisted mainly of a $0.8 million decrease in maintenance for our SLCC Plant as compared to 2006 expenses related to the spring 2006 SLCC maintenance outage and a $0.4 million decrease in maintenance at our State Line Unit 1 Plant, which had its first major inspection from September 7, 2006 until December 20, 2006, partially offset by a $0.4 million increase in maintenance during 2007 at the Empire Energy Center related to Unit #3 being repaired in the third quarter of 2007. Maintenance expense associated with our five year Asbury maintenance project is not expensed but is deferred as a regulatory asset and amortized over a five year period. A minor true up in December 2007 reclassified some of the January 2007 ice storm costs from maintenance expense to a regulatory asset. See Note 4 of "Notes to Consolidated Financial Statements" under Item 8 for further information regarding our regulatory assets and liabilities.

        We recognized a $1.2 million gain in the fourth quarter of 2007 from the sale of our steel unit train set.

        Depreciation and amortization expense increased approximately $13.2 million (36.2%) during 2007 primarily due to $10.4 million of regulatory amortization related to the 2007 Missouri rate order that has been recorded as depreciation expense as well as increased plant in service. Other taxes increased approximately $1.5 million due to increased property taxes reflecting our additions to plant in service and increased municipal franchise taxes.

Gas Segment

2008 Compared to 2007

Operating Revenues, Sales and Cost of Gas Sold

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

Total Gas Delivered to Customers

 
  bcf sales
2008
  bcf sales
2007
  % Change  

Residential

    2.95     2.83     4.0 %

Commercial

    1.40     1.30     7.2  

Industrial*

    0.55     0.08     628.3  

Other**

    0.03     0.03     20.5  
                 

Total retail sales

    4.93     4.24     16.3  

Transportation sales**

    4.06     4.30     (5.6)  
                 

Total gas operating sales

    8.99     8.54     5.3  

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Operating Revenues and Cost of Gas Sold

($ in millions)
  2008   2007   % Change  

Residential

  $ 39.6   $ 39.2     1.1 %

Commercial

    17.4     16.6     5.0  

Industrial*

    5.1     0.7     574.4  

Other**

    0.4     0.4     17.6  
                 

Total retail revenues

  $ 62.5   $ 56.9     9.9  

Other revenues

    0.2     0.2     0.5  

Transportation revenues*

    2.7     2.8     (3.1)  
                 

Total gas operating revenues

  $ 65.4   $ 59.9     9.3  

Cost of gas sold

    42.6     37.6     13.3  
                 

Gas operating revenues over cost of gas in rates

  $ 22.8   $ 22.3     2.5  

*
Percentage change reflects the transfer of a customer from transportation sales to industrial.

**
Other includes other public authorities and interdepartmental usage.

        Gas retail sales increased 16.3%, primarily due to an increase in industrial sales as compared to 2007 and colder weather. The winter months are high sales months for the natural gas business, whose heating season runs from November to March of each year. Residential and commercial sales increased during 2008 as compared to 2007 primarily due to colder weather. Heating degree days were 13.5% higher than 2007. Industrial sales increased during 2008 due to the transfer of two large volume interruptible customers from transportation to sales service and the addition of a new large volume interruptible customer. These increases offset the effect of our gas segment customer contraction of 1.5% in 2008. We believe this contraction was due to higher gas prices and general economic conditions. The rate of gas customer contraction is expected to level out during the next two years and to remain relatively flat after 2010.

        During 2008, gas segment revenues were approximately $65.4 million as compared to $59.9 million in 2007, an increase of 9.3%, reflecting the higher sales. During 2008, our PGA revenue (which represents the cost of gas recovered from our customers) was approximately $42.6 million as compared to $37.6 million in 2007, an increase of approximately $5.0 million. This increase was largely driven by the increase in the industrial sales and the effect of higher sales due to weather.

        Our PGA clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, transportation and storage, including costs associated with the use of financial instruments to hedge the purchase price of natural gas. Pursuant to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a regulatory asset or regulatory liability until the balance is recovered from or credited to customers. As of December 31, 2008, we had unrecovered purchased gas costs of $5.6 million recorded as a regulatory asset.

Operating Revenue Deductions

        Total other operating expenses were $10.0 million during 2008 as compared to $10.2 million in 2007, a decrease of $0.2 million. This decrease was mainly due to a $0.8 million decrease in uncollectible accounts, and a $0.6 million decrease in administrative and general expenses, partially offset by a $0.9 million increase in customer accounts expense and a $0.2 million increase in distribution expense.

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2007 Compared to 2006

Operating Revenues, Sales and Cost of Gas Sold

        During 2007, our total natural gas revenues were approximately $59.9 million. Our total natural gas revenues were approximately $25.1 million during 2006 (June 1, 2006 — December 31, 2006).

Total Gas Delivered to Customers

 
  bcf sales
2007
  bcf sales
2006*
 

Residential

    2.83     1.10  

Commercial

    1.30     0.56  

Industrial

    0.08     0.03  

Other**

    0.03     0.01  
           

Total retail sales

    4.24     1.70  

Transportation sales

    4.30     2.23  
           

Total gas operating sales

    8.54     3.93  

Operating Revenues and Cost of Gas Sold

($ in millions)
  2007   2006*  

Residential

  $ 39.2   $ 15.9  

Commercial

    16.6     7.1  

Industrial

    0.7     0.4  

Other**

    0.4     0.2  
           

Total retail revenues

  $ 56.9   $ 23.6  

Other revenues

    0.2     0.1  

Transportation revenues

    2.8     1.5  
           

Total gas operating revenues

  $ 59.9   $ 25.2  

Cost of gas sold

    37.6     15.3  
           

Gas operating revenues over cost of gas in rates

  $ 22.3   $ 9.9  

*
2006 revenues and bcf sales represent the months of June through December 2006.

**
Other includes other public authorities and interdepartmental usage.

        During 2007, EDG's cost of natural gas sold and transported was approximately $37.6 million. The cost of natural gas sold and transported during 2006 (June 1, 2006 — December 31, 2006) was approximately $15.3 million.

Operating Revenue Deductions

        Total other operating expenses were approximately $10.2 million during 2007, primarily consisting of approximately $5.7 million of administrative and general expenses, approximately $2.5 million of customer accounts expense (including $1.7 million of uncollectible accounts) and approximately $1.7 million of distribution expense. Total other operating expenses were approximately $5.9 million during 2006 (June 1, 2006 — December 31, 2006) primarily consisting of approximately $4.0 million of administrative and general expenses, approximately $1.0 million of distribution expense and approximately $0.8 million of customer accounts expense (including $0.4 million of uncollectible accounts). EDG had net income of $1.0 million during 2007 and a net loss of $1.0 million during 2006. Approximately $1.2 million in transition costs were paid in 2006 for billing and other transition services. These services ended when they were transitioned to us by November 1, 2006.

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Other Segment

        Our other segment consists of our non-regulated business, primarily the leasing of fiber optics cable and equipment (which we are also using in our own utility operations). See Note 13 of "Notes to Consolidated Financial Statements". The following table represents our results of continuing operations for our other segment for the applicable periods ended December 31:

(in millions)
  2008   2007   2006  

Revenues

  $ 5.0   $ 3.7   $ 2.9  

Expenses

    4.4     3.3     2.8  
               

Net income from continuing operations

  $ 0.6   $ 0.4   $ 0.1  
               

Consolidated Company

Income Taxes

        Our consolidated provision for income taxes increased approximately $4.7 million during 2008 as compared to 2007. Our consolidated effective federal and state income tax rate for 2008 was 32.5% as compared to 30.3% for 2007. The rate in 2008 is higher primarily due to lower tax benefits received from cost of plant retirement expenditures. Our cost of retirement expenditures was unusually high in 2007 due to the ice storms we experienced. This reduced benefit in 2008 was partially offset by an increase in the tax effects of equity AFUDC compared to 2007.

        Our consolidated provision for income taxes decreased approximately $7.5 million during 2007 as compared to 2006. Our consolidated effective federal and state income tax rate for 2007 was 30.3% as compared to 35.3% for 2006. The decrease in the effective tax rate for 2007 as compared to 2006 was mainly due to an increase in equity AFUDC, Medicare Part D tax benefits and increased tax benefits received from cost of plant retirement expenditures resulting from the January 2007 and December 2007 ice storms.

        See Note 10 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding income taxes.

Nonoperating Items

        Total allowance for funds used during construction (AFUDC) increased $4.9 million in 2008 as compared to 2007. Total AFUDC increased $3.4 million in 2007 as compared to 2006. See Note 1 of "Notes to Consolidated Financial Statements" under Item 8.

        Total interest charges on long-term debt increased $4.9 million (15.8%) in 2008 as compared to 2007 reflecting the interest on the $90 million principal amount of first mortgage bonds we issued on May 16, 2008. The increase also reflects a full year of interest on the $80 million principal amount of first mortgage bonds we issued on March 26, 2007. The proceeds of both bond issuances were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

        Total interest charges on long-term debt increased $5.2 million (19.9%) in 2007 as compared to 2006 reflecting interest on the $80 million principal amount of first mortgage bonds issued March 26, 2007 by EDE. This increase also reflects interest on the first mortgage bonds issued June 1, 2006 by EDG to fund a portion of our acquisition of the Missouri natural gas distribution operations. See "— Liquidity and Capital Resources" for further information.

        Short-term debt interest decreased $1.1 million during 2008 as compared to 2007, reflecting lower cost of borrowing in 2008. Short-term debt interest increased $0.7 million during 2007 as compared to 2006, reflecting increased usage of short-term debt in 2007.

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        Gains or losses from discontinued operations were zero in 2008 compared to a slight gain from discontinued operations in 2007 of less than $0.1 million. Losses from discontinued operations were approximately $0.7 million in 2006. These transactions reflect the sales of Fast Freedom in 2007 and MAPP and Conversant in 2006.

Other Comprehensive Income

        The change in the fair value of the effective portion of our open gas contracts designated as cashflow hedges entered into prior to September 1, 2008 for our electric business and our interest rate derivative contracts and the gains and losses on contracts settled during the periods being reported, including the tax effect of these items, are reflected in our Consolidated Statement of Comprehensive Income. The fair value of open electric segment derivative contracts decreased $17.4 million in 2008, reflecting falling natural gas prices. This net change is recorded as accumulated other comprehensive income in the capitalization section of our balance sheet and does not affect net income or earnings per share. All of these contracts have been designated as cash flow hedges. The unrealized gains and losses accumulated in other comprehensive income are reclassified to fuel and purchased power, or interest expense, in the periods in which the hedged transaction is actually realized or no longer qualifies for hedge accounting. Effective September 1, 2008, in conjunction with the implementation of the Missouri fuel adjustment clause in the 2008 MPSC rate order, the unrealized losses or gains from new cash flow hedges for our electric business, will be recorded in regulatory assets or liabilities. This is in accordance with FAS 71, given that those regulatory assets and liabilities are probable of recovery through our fuel adjustment mechanism. Unrealized gains and losses from cash flow hedges existing at September 1, 2008 will continue to be recorded through other comprehensive income. Once any contracts are settled, the realized gain or loss will be recorded as fuel expense and be subject to the fuel adjustment clause. No interest rate derivative contracts were open or settled during the periods shown below.

        The following table sets forth the pre-tax gains/(losses) of our natural gas contracts for our electric segment that have settled and been reclassified, the pre-tax change in the fair market value (FMV) of our open contracts and the tax effect in Other Comprehensive Income for the presented periods ended December 31:

Change in Other Comprehensive Income

(in millions)
  2008   2007   2006  

Natural gas contracts settled(1)

  $ (3.9 ) $ (1.6 ) $ (1.3 )

Change in FMV of open contracts for natural gas

  $ (17.4 ) $ 5.2   $ (13.6 )

Taxes

  $ 8.1   $ (1.4 ) $ 5.7  
               

Total change in OCI — net of tax

  $ (13.2 ) $ 2.2   $ (9.2 )
               

(1)
Reflected in fuel expense

        Our average cost for our open financial natural gas hedges was $6.033/Dth at December 31, 2008, $5.460/Dth at December 31, 2007 and $4.805/Dth at December 31, 2006 for our electric segment.

        As of June 30, 2007, we elected to change our valuation of natural gas derivatives (financial hedges) for financial reporting purposes to a new methodology which is more closely related to an independent market valuation. For accounting purposes, this change is considered a change in estimate. To reflect the change, an increase of approximately $6 million was recorded to the fair value of derivatives and $3.7 million, net of tax, was recorded to other comprehensive income at June 30, 2007. This change had no impact on the income statement.

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        We had no interest rate derivative contracts in 2008, 2007 or 2006. On February 15, 2008, we unwound 992,000 Dths of physical gas contracts originally scheduled for delivery in July and August of 2010 and 2011. This transaction resulted in a non-recurring gain of approximately $1.3 million after taxes, which was recorded in the Statement of Income in the first quarter of 2008.

        See Note 15 of "Notes to Consolidated Financial Statements" under Item 8 for additional discussion regarding our hedged commodity transactions.


RATE MATTERS

        We continually assess the need for rate relief in all of the jurisdictions we serve and file for such relief when necessary.

Electric Segment

        The following table sets forth information regarding electric and water rate increases since January 1, 2006:

Jurisdiction
  Date
Requested
  Annual
Increase
Granted
  Percent
Increase
Granted
  Date
Effective
 

Missouri — Electric

    October 1, 2007   $ 22,040,395     6.70 %   August 23, 2008  

Missouri — Electric

    February 1, 2006   $ 29,369,397     9.96 %   January 1, 2007  

Missouri — Water

    June 24, 2005   $ 469,000     35.90 %   February 4, 2006  

Kansas — Electric

    April 29, 2005   $ 2,150,000     12.67 %   January 4, 2006  

Missouri

2007 Rate Case

        On October 1, 2007, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $34.7 million, or 10.11%. We requested recovery of our investment in the new 150-megawatt combustion turbine, Unit 12, at our Riverton plant, capital expenditures associated with the construction of a selective catalytic reduction system at our Asbury Plant, capital expenditures and expenses related to the January and December 2007 ice storms and other changes in our underlying costs. We also requested implementation of a fuel adjustment clause in Missouri which would permit the distribution to Missouri customers of changes in fuel and purchased power costs.

        The MPSC issued an order on July 30, 2008, granting 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 order contains two components. The first component provides an addition to base rates of approximately $27.7 million. This increase in base rates was partially offset by a $5.7 million reduction to regulatory amortization, which is the second component to support certain credit metrics of the overall change in revenue authorized by the MPSC. Regulatory amortization provides us additional cash through rates during the current construction cycle. This construction, which is part of our long-range plan to ensure reliability, includes the facilities at the Riverton Power Plant and Iatan 2 Power Plant, as well as environmental improvements at the Asbury Power Plant and at Iatan 1. The regulatory amortization is now approximately $4.5 million annually and is recorded as depreciation expense.

        The MPSC also authorized a fuel adjustment clause for our Missouri customers effective September 1, 2008. The MPSC established a base cost 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 cost. Off-system sales margins are also part of the

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recovery of fuel and purchased power costs. As a result, the off-system sales margin flows back to the customer. Rates related to the recovery of fuel and purchased power costs will be modified twice a year subject to the review and approval by the MPSC. In accordance with FAS 71, 95% of the difference between the actual cost of fuel and purchased power and the base cost of fuel and purchased power recovered from our customers is recorded as an adjustment to fuel and purchased power expense with a corresponding regulatory asset or a regulatory liability. If the actual fuel and purchased power costs are higher or lower than the base fuel and purchased power costs billed to customers, 95% of these amounts will be recovered or refunded to our customers when the fuel adjustment clause is modified. At December 31, 2008, Missouri fuel and purchased power costs were over-recovered $0.2 million, which is reflected as a regulatory liability.

        The MPSC order approved a Stipulation and Agreement providing for the recovery of deferred expenses of approximately $14.2 million over a five year period for the 2007 ice storms. In addition, the MPSC order required the implementation of a two-way tracking mechanism for recovery of the costs relating to the new MPSC rules on infrastructure inspection and vegetation management. The mechanism authorized by the MPSC creates a regulatory liability in any year we spend less than the target amount, which has been set at $8.6 million for our Missouri jurisdiction, and a regulatory asset if we spend more than the target amount. Any regulatory asset and liability amounts created using the tracking mechanism will then be netted against each other and taken into account in our next rate case. The MPSC also approved Stipulations and Agreements providing for the continuation of the pension and other post-retirement employee benefits tracking mechanism established in our 2006 and 2007 Missouri rate orders.

        The MPSC issued its Report and Order on July 30, 2008, effective August 9, 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, and briefs are currently being filed with the Cole County Circuit Court.

2006 Rate Case

        On February 1, 2006, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $29.5 million, or 9.63%. We also requested transition from the interim energy charge (IEC) from an earlier case to Missouri's new fuel adjustment mechanism. The MPSC issued an order May 2, 2006 ruling that while we may have the option of requesting that the IEC be terminated, we may not request the implementation of an energy cost recovery mechanism while the current IEC is effective. The MPSC issued an order on December 21, 2006 granting us an annual increase of $29.4 million, or 9.96%, with an effective date of January 1, 2007 and eliminating the IEC. Pursuant to this order, the collected IEC revenue was not refunded. The increase included an authorized return on equity of 10.9% and included our fuel and energy costs as a component of base electric rates. This order also allowed deferral of any other postretirement benefits that are different from those allowed recovery in this rate case. This treatment is similar to treatment afforded pension costs in our 2005 rate case. This order also approved regulatory treatment of additional liabilities arising from the adoption of FAS 158. We also agreed to write off $1 million of the construction cost associated with our Energy Center Units 3 and 4. The Missouri jurisdictional portion of this agreement resulted in a pre-tax write-off of $0.8 million in the fourth quarter of 2006.

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        The $29.4 million authorized increase in annual revenues included $19 million in base rate revenue and $10.4 million in "regulatory amortization." The regulatory amortization, which is treated as additional book depreciation for rate-making purposes and is so reflected in the financial statements, was granted to provide additional cash flow to enhance the financial support for our current generation expansion plan. This regulatory amortization is related to our investment in Iatan 2 and also includes our Riverton V84-3A2 combustion turbine (Unit 12) and the environmental improvements and upgrades at Asbury and Iatan 1, all of which are part of the Experimental Regulatory Plan approved by the MPSC subject to a subsequent prudence review of actual expenditures. Amounts granted as regulatory amortization will reduce our rate base used in determining our base rates in subsequent rate cases.

        On March 19, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Supreme Court regarding the MPSC's order approving our tariffs issued on December 29, 2006. On October 30, 2007, the Missouri Supreme Court issued an opinion directing the MPSC to vacate its order approving tariffs and allow the OPC a reasonable amount of time to prepare and file an application for rehearing. The Court did not examine the lawfulness or reasonableness of the substance of the MPSC's order approving tariffs, and considered only the timing of the issuance of the order. The Court also did not consider the underlying tariff rates.

        Acting upon the opinion of the Missouri Supreme Court, the MPSC issued an order on December 4, 2007, effective December 14, 2007, vacating the December 29, 2006 order and re-approving the tariffs and the same resulting increase in rates. The OPC and intervenors Praxair, Inc. and Explorer Pipeline Company, filed applications for rehearing with the MPSC regarding this order.

        On March 26, 2008, the MPSC issued its Order Granting Reconsideration of Report and Order, effective April 5, 2008, and its Report and Order Upon Reconsideration, effective April 5, 2008, in which the MPSC made additional findings and reaffirmed the rate increase originally authorized in December of 2006. In this order, the MPSC made two adjustments, and an increase in the return on rate base was offset by a decrease in the regulatory amortization from $10.4 million to $10.2 million. The OPC and intervenors Praxair and Explorer Pipeline filed applications for rehearing regarding this Report and Order Upon Reconsideration, raising objections to many of the issues addressed in the order, including but not limited to issues relating to return on equity and fuel and purchased power expense.

        On March 18, 2008, the OPC filed a second Petition for Writ of Mandamus with the Missouri Supreme Court regarding the MPSC's order approving our tariffs issued on December 29, 2006 and the MPSC's vacation order issued on December 4, 2007. On October 14, 2008, the Missouri Supreme Court issued a ruling directing the MPSC to comply with the Court's previous mandate and opinion. The Court took no position on the effect such action has on any tariffs the MPSC had approved. It is our position that the opinion and mandate do not impact the monies collected under the filed tariffs. On November 14, 2008, the MPSC issued an order in compliance with the Court's mandate.

        All pending applications for rehearing in the 2006 rate case were denied by the MPSC on November 20, 2008. On December 15, 2008, the 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.

Kansas

        On April 29, 2005, we filed a request with the Kansas Corporation Commission (KCC) for an increase in base rates for our Kansas electric customers in the amount of $4.2 million, or 24.64%. On October 4, 2005, we and the KCC Staff filed a Motion to Approve Joint Stipulated Settlement Agreement (Agreement) with the KCC. The Agreement called for an annual increase in base rates (which includes historical fuel costs) for our Kansas electric customers of approximately $2,150,000, or 12.67%, the implementation of an Energy Cost Adjustment Clause (ECA), a fuel rider that will collect or refund fuel

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costs in the future that are above or below the fuel costs included in the base rates and the adoption of the same depreciation rates approved by the MPSC in our 2005 Missouri rate case. In addition, we were allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above or below the amount included in this rate case as a regulatory asset or liability. The KCC approved the Agreement on December 9, 2005 effective January 4, 2006. Pursuant to the Agreement, we sought KCC approval of an explicit natural gas hedging program in a separate docket by March 1, 2006. We requested and received an extension until April 1, 2006 and made this filing on March 30, 2006, which was denied in a February 4, 2008 order by the KCC. As a result, all gains or losses related to the financial instruments used to fix the future price of natural gas will be excluded from the Energy Cost Adjustment clause implemented in the last Kansas rate case and future base electric rates in Kansas.

Ice Storm Recovery

        We filed applications for Accounting Authority Orders in Oklahoma and Kansas and filed a request for storm recovery in Arkansas respecting costs incurred due to two major ice storms in 2007. On May 23, 2008, the Arkansas Public Service Commission issued an Order allowing us to defer approximately $0.4 million of extraordinary incremental expenses incurred as a result of the 2007 ice storms as a regulatory asset and amortize such costs over a 5 year period beginning with the first full month following the storms. On June 24, 2008, the KCC issued an Order approving our application for an accounting order to accumulate and defer for recovery in future rate case proceedings, approximately $1.1 million of 2007 ice storm costs as a regulatory asset to be amortized over a 10 year period. On June 25, 2008, the Corporation Commission of Oklahoma issued a Final Order approving a Joint Stipulation and Settlement Agreement permitting deferral and recording of approximately $0.5 million of 2007 ice storm costs as a regulatory asset and authorizing recovery of the regulatory asset over a five year period, via a rider effective July 1, 2008. We were granted rate recovery of the Missouri ice storm costs as part of the order issued by the MPSC on July 30, 2008 as discussed above.

Gas Segment

        On June 1, 2006, The Empire District Gas Company acquired the Missouri natural gas distribution operations of Aquila, Inc. (Missouri Gas). The Missouri Gas properties consist of 44 Missouri communities in northwest, north central and west central Missouri. The rates, excluding the cost of gas, are the same as had been in effect at Aquila, Inc. We agreed in the unanimous stipulation and agreement filed with the MPSC on March 1, 2006 and approved on April 18, 2006, to not file a rate increase request for non-gas costs for a period of 36 months following the closing date of the acquisition. We expect to file a gas rate case in 2009 as the 36 month limitation expires on June 1, 2009. We have also agreed to use Aquila Inc.'s current depreciation rates and were allowed to adopt the pension cost recovery methodology approved in our electric 2005 Missouri Rate Case.

        A PGA clause is included in our gas rates which allows for the over recovery or under recovery of actual gas costs compared to the cost of gas in the PGA rate. This PGA clause allows us to make rate changes periodically (up to four times) throughout the year in response to weather conditions, natural gas prices and supply demands, rather than in one possibly extreme change per year. The Actual Cost Adjustment (ACA) is a scheduled yearly filing with the MPSC filed between October 15 and November 4 each year. This filing establishes the amount to be recovered from customers for the over/under recovered yearly amounts. A PGA is included in the ACA filing. An optional PGA filing without the ACA can be filed up to three times each year, provided a filing does not occur within 60 days of a previous filing. On October 28, 2008, we filed a new ACA and PGA with the MPSC that was effective November 12, 2008.

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COMPETITION

Electric Segment

SPP-RTO

        On February 1, 2007, the Southwest Power Pool (SPP) regional transmission organization (RTO) launched its energy imbalance services market (EIS). With the implementation of the SPP RTO EIS market and transmission expansion plans of the SPP RTO, we anticipate that our continued participation in the SPP will provide long-term benefits to our customers and other stakeholders. Our experience to date in the EIS market indicates that we have received benefits through our participation.

        In general, the SPP RTO EIS market is providing real time energy for most participating members within the SPP regional footprint. Imbalance energy prices are based on market bids and status/availability of dispatchable generation and transmission within the SPP market footprint. In addition to energy imbalance service, the SPP RTO performs a real time security-constrained economic dispatch of all generation voluntarily offered into the EIS market to the market participants to also serve the native load.

        We will continue to actively engage with the SPP RTO, other members of the SPP and staffs of our state commissions to evaluate the impact and value of EIS market participation.

        On August 15, 2008 the SPP filed with the FERC proposed revisions to its open access transmission pro forma tariff (OATT) to establish a process for including a "balanced portfolio" of economic transmission upgrades in the annual SPP Transmission Expansion Plan. The cost of such upgrades will be recovered through a regional rate allocated to SPP members based on their load ratio share within SPP's market area of the balanced portfolio's cost. On October 16, 2008, the FERC accepted the balanced portfolio approach, which sets forth the selection process of a group of projects and regional cost allocation rules based on projected benefits and allocated costs over a ten year period. The plan will be balanced if the portfolio is cost beneficial for each zone, including ours, within the SPP. A balanced portfolio could include projects below the 345 kv level (which is the bright line voltage level for projects to be included in the portfolio) to increase benefits to a particular zone to achieve balance of benefits and costs over the ten year study period. We continue our involvment in the discussions regarding the proposed projects, estimated benefits, and costs regarding SPP's first balanced portfolio. However, we are uncertain, at this time, what the benefits and costs of the first balanced portfolio will be for us. It is anticipated that the SPP Regional State Committee (composed of commissioners from the state commissions within the SPP footprint) will endorse, and the SPP Board of Directors will approve, the first SPP RTO balanced portfolio of economic transmission projects sometime in 2009.

FERC Market Power Order

        On March 3, 2005, the FERC issued an order commencing an investigation to determine if we had market power within our control area based on our failure to meet one of the FERC's wholesale market share screens. We filed responses to that order in May and June 2005 and in early January 2006. On August 15, 2006, the FERC issued its order accepting Empire's proposed mitigation to become effective May 16, 2005, subject to a further compliance filing as directed in the order. Relying on a series of orders issued since March 17, 2006 in other proceedings, the FERC rejected our tariff language and directed us to file revisions to our market-based tariff to provide that service under the tariff applies only to sales outside our control area. The FERC directed us to make refunds, with interest, by September 15, 2006, which we initially estimated to be approximately $0.6 million (excluding interest) covering over 1,000 hourly energy sales since May 16, 2005 to numerous counterparties external to our system for wholesale sales made at market prices above the cost based prices permitted under the mitigation proposal accepted by the FERC. The refund obligation applied to certain wholesale power sales made "inside" our service area at market based rates, even though consumption of the energy occurred outside our service area. In response to the order, we filed a Motion For Extension of time and expedited treatment regarding the refund and

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requested that such refund be delayed until 15 days after the FERC's order on our rehearing request. On September 5, 2006, the FERC granted the Motion For Extension, as requested.

        On September 14, 2006, we filed a Request For Rehearing of the FERC's August 15, 2006 order regarding the refund and market power mitigation we had proposed. We requested a rehearing and a waiver of the refund requirement in its entirety. On April 25, 2008, the FERC issued an Order that rejected our Request For Rehearing, required a Compliance Filing of our market based rate tariff and ordered refunds with interest. We made our Compliance Filing and issued refunds totaling $340,608, including interest, on May 27, 2008. We were also required to file an informational refund report with the FERC on June 26, 2008.

        As a result of the FERC's requirement for us to issue the aforementioned refunds and our belief that the FERC erred in its orders, on June 30, 2008 we initiated a Petition For Review of the FERC's orders on our market based rate refunds in the United States Court of Appeals for the District of Columbia Circuit (DC Circuit). We requested and received approval for a consolidation of our Petition with a similar petition by Westar Energy. If a decision is reached in our favor, the DC Circuit will likely remand the FERC's orders back to the FERC for reconsideration. It is expected that the judicial review of the Petitions will take several months.

Other FERC Rulemaking

        On June 21, 2007, the FERC issued an Advance Notice of Proposed Rulemaking (ANOPR) on potential reforms to improve operations in organized wholesale power markets, such as the SPP RTO in which we participate. On October 16, 2008, the FERC issued its Final Order on Wholesale Competition in Regions with Organized Electric Markets. The Final Order will affect us as it directly affects the SPP RTO. The Final Order addresses four key areas for amending its regulations in Wholesale Competition for RTOs and Independent System Operators (ISOs): (1) demand response and market pricing during periods of operating reserve shortage; (2) long-term power contracting; (3) market monitoring policies; and (4) the responsiveness of RTOs and ISOs to stakeholders and customers. We will be involved in the SPP RTOs discussions on compliance of these new rules.

        On January 28, 2008, we filed with the FERC certain non-rate and ministerial revisions to our currently effective wholesale Open Access Transmission Tariff (OATT), which included the elimination of certain tariff sections that have become moot in light of our membership in the SPP, as well as correction of the formatting of our OATT for consistency with a previous FERC order, Order No. 614.

        On April 2, 2008, the FERC accepted our revised OATT, as filed, with an effective date of January 29, 2008.

Gas Segment

        Non-residential gas customers whose annual usage exceeds certain amounts may purchase natural gas from a source other than EDG. EDG does not have a non-regulated energy marketing service that sells natural gas in competition with outside sources. EDG continues to receive non-gas related revenues for distribution and other services if natural gas is purchased from another source by our eligible customers.


LIQUIDITY AND CAPITAL RESOURCES

        We used approximately $211.3 million of cash for regulated capital expenditures during 2008. Our primary sources of cash flow for these expenditures during 2008 were $93.0 million in internally generated funds from continuing operations and $117.5 million in proceeds from financing activities.

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        Our short-term debt at December 31, 2008 was $102.0 million, compared to $33.0 million at December 31, 2007. Our current short-term debt is at a high level on a historical basis, primarily as a result of funding our ongoing construction program. This high short-term debt balance is also the primary driver of our negative working capital. We intend to issue equity and long-term debt in the near future to repay all or a portion of our short-term debt and to provide liquidity to fund our ongoing construction program and operations. In addition, we expect to seek an increase in our unsecured revolving credit facility commitments (either within the same facility or through an additional facility) to help meet short-term liquidity needs. We believe it is unlikely we will have difficulty accessing the markets for needed capital. However, as a result of recent market conditions, we believe the costs of these financing activities will be significantly higher than our historical financing costs.

Summary of Cash Flows

 
  Fiscal Year  
(in millions)
  2008   2007   2006  

Cash provided by (used in):

                   
 

Operating activities

  $ 93.0   $ 103.5   $ 69.2  
 

Investing activities

    (211.8 )   (178.9 )   (217.3 )
 

Financing activities

    117.5     67.0     143.1  
               

Net change in cash and cash equivalents from continuing operations

    (1.3 )   (8.4 )   (5.0 )

Discontinued operations

        0.1     1.4  
               

Net change in cash and cash equivalents

  $ (1.3 ) $ (8.3 ) $ (3.6 )

Operating Activities

        Our net cash flows provided by continuing operating activities were $93.0 million during 2008 as compared to $103.5 million during 2007. The $6.5 million increase in net income added to cash flows, but was offset by other activities. First, the effect of adjustments to net income to reconcile to cash flows had a $10.0 million negative impact when compared to last year, primarily due to changes in deferred taxes. In 2007, our tax payments decreased as a result of taking tax deductions associated with the 2007 ice storms. In 2008, an increase in deferred taxes also positively contributed to cash flows through the use of bonus depreciation, however, the effect was less when compared to 2007.

        Changes in working capital and other balance sheet items also negatively impacted cash flows in 2008 compared to 2007. Expenditures for the December 2007 ice storm were primarily paid in January 2008. This use of cash in 2008 was offset by the effects of changes in our prepaid expenses and deferred charges. In 2007, $15.5 million in cash outlays from both the January and December ice storms are reflected in the increase in deferred charges. Cash also decreased in 2008 due to the change in deferred assets but the effect is much smaller than the effect from the ice storms in 2007.

        Our net cash flows provided by continuing operating activities were $103.5 million during 2007 as compared to $69.2 during 2006. Net income decreased $6.0 million in 2007 but was offset by a $36.1 million positive impact from the effect of adjustments to net income to reconcile to cash flows. This resulted from the positive effects of increased depreciation and amortization, including $10.4 million in regulatory amortization and an increase in deferred taxes primarily resulting from tax deductions allowed as a result of the 2007 ice storms. In addition, cash flows were positively impacted in 2007 as compared to 2006 because of the increase in accounts payable in 2007 compared to the decrease in 2006. Payables associated with fuel costs increased $6.6 million in 2007 while fuel payables decreased by $11.6 million in 2006. Payables also increased due to the expenditures incurred for the December 2007 ice storm. The change in prepaid expense and deferred charges resulted in a $9.6 million decrease in cash this year versus 2006. The negative cash flow impact of $15.5 million in cash outlays as a result of the 2007 ice storms, included in deferred charges, that have been deferred as regulatory assets are offset by the net effect of decreases to

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our regulatory asset accounts. These decreases reflect the recovery of deferred gas costs during the year, as well as changes in our pension and OPEB liabilities. An increase in accounts receivable compared to 2006 had a negative impact on cash flow. This resulted from an increase in unbilled accounts receivable of $6.0 million for our electric segment at December 31, 2007 and an increase in various miscellaneous accounts receivable items.

Capital Requirements and Investing Activities

        Our net cash flows used in investing activities increased $32.8 million during 2008 as compared to 2007, primarily reflecting our construction expenditures for Plum Point Unit 1 and Iatan 2.

        Our net cash flows used in investing activities decreased $38.4 million during 2007 as compared to 2006, primarily reflecting our acquisition of Missouri Gas in 2006. Partially offsetting this decrease in 2007 were additions to our transmission and distribution systems, construction costs for Plum Point Unit 1 and Iatan 2, capital costs related to the January and December 2007 ice storms and capital costs related to the new SCR at the Asbury Plant. Proceeds from the sale of the unit train added $1.2 million.

        Our capital costs incurred for continuing operations total approximately $206.4 million, $195.5 million, and $120.2 million in 2008, 2007 and 2006, respectively (excluding the acquisition of Missouri Gas in 2006). These capital costs include AFUDC, capital costs to retire assets and benefits from salvage.

        A breakdown of these capital costs (including AFUDC) for 2008, 2007 and 2006 is as follows:

 
  Capital Expenditures  
(in millions)
  2008   2007   2006  

Distribution and transmission system additions

  $ 46.8   $ 43.5   $ 44.1  

New generation — Riverton combustion turbine

        3.9     14.0  

New generation — Plum Point Energy Station

    30.9     29.8     19.6  

New generation — Iatan 2

    82.6     44.0     12.4  

Storms(1)

    4.3     26.9     1.2  

Additions and replacements — Asbury

    6.0     21.7     14.6  

Additions and replacements — Iatan 1

    32.3     14.2     5.1  

Additions and replacements — State Line Combined Cycle Unit,
Riverton, Energy Center, State Line Unit 1 and Ozark Beach

    1.9     2.1     2.0  

Gas segment additions and replacements

    1.9     1.8     0.9  

Transportation

    1.2     0.8     1.9  

Other (including retirements and salvage — net)(1)(2)

    (3.6 )   1.8     1.8  
               

Subtotal

  $ 204.3   $ 190.5   $ 117.6  

Non-regulated capital expenditures (primarily fiber optics)

    2.1     5.0     2.6  
               

Subtotal capital expenditures incurred(3)

  $ 206.4   $ 195.5   $ 120.2  
               

Less capital expenditures payable(4)

    (6.9 )   12.1     5.0  
               

Total cash outlay

  $ 213.3   $ 183.4   $ 115.2  
               

(1)
For 2007, storm costs of $17.8 million and Other of $1.4 million, which relate to the cost of removal, are specifically related to capital expenditures associated with the January 2007 ice storm. $9.2 million of capitalized storm costs are related to the December 2007 ice storm.

(2)
Other includes equity AFUDC of $(5.9) million, $(2.9) million and $(1.4) million for 2008, 2007 and 2006, respectively. 2008 also includes proceeds from sale of property of $1.5 million.

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(3)
Expenditures incurred represent the total cost for work completed for the projects during the year. Discussion of capital expenditures throughout the 10-K is presented on this basis.

(4)
The amount of expenditures unpaid at the end of the year and not reflected in the Investing Activities section of the Statement of Cash Flows.

        Approximately 23%, 36% and 30% of our cash requirements for capital expenditures for 2008, 2007 (excluding the acquisition of Missouri Gas) and 2006, respectively, were satisfied with internally generated funds (funds provided by operating activities less dividends paid). The remaining amounts of such requirements were satisfied from short-term borrowings and proceeds from our sales of common stock and debt securities discussed below.

        In order to help meet anticipated CAIR requirements and the existing Missouri NOx Rule, we constructed an SCR at Asbury that was completed in November 2007 and placed in service in February 2008 at a total cost of approximately $31.0 million (excluding AFUDC), of which $28.1 million was expended through December 31, 2007 with the remainder expended in 2008. This project was included as part of our Experimental Regulatory Plan approved by the MPSC and its cost is now in base rates in Missouri. For additional information, see Item 1, "Business — Environmental Matters."

        We estimate that our capital expenditures will total approximately $168.9 million in 2009, $115.7 million in 2010 and $77.1 million in 2011 (excluding AFUDC). See Item 1, "Business — Construction Program." Of these budgeted amounts, we anticipate that we will spend the following amounts over the next three years for the following projects:

Project
  2009   2010   2011  

Iatan 2

  $ 69.9   $ 32.4   $  

Plum Point Energy Station

    9.4     5.8      

Electric distribution system additions

    40.9     41.2     46.1  

Electric transmission facilities additions

    13.7     12.6     2.9  

Environmental upgrades — Iatan 1

    15.6          

Other

    19.4     23.7     28.1  
               
 

Total

  $ 168.9   $ 115.7   $ 77.1  

        Construction on the Plum Point Energy Station began in the spring of 2006 with completion scheduled for 2010. Initially we will own, through an undivided interest, 50 megawatts of the project's capacity. We also have a long term purchased power agreement (30 years) for an additional 50 megawatts of the project's capacity and have the option to purchase an undivided ownership interest in the 50 megawatts covered by the purchased power agreement in 2015. A new combustion turbine previously scheduled to be installed by the summer of 2011 will be delayed until 2014 as our generation regulation needs for our purchased power agreements are being met through a combination of our existing units and the SPP EIS market. See Note 12 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding commitments.

        We estimate that internally generated funds will provide approximately 40% of the funds required in 2009 for our budgeted capital expenditures. We intend to utilize a combination of short-term debt, the proceeds of sales of long-term debt and/or common stock (including common stock sold under our Employee Stock Purchase Plan, our Dividend Reinvestment and Stock Purchase Plan, and our 401(k) Plan and ESOP) to finance additional amounts needed beyond those provided by operating activities for such capital expenditures. We will continue to utilize short-term debt as needed to support normal operations or other temporary requirements. The estimates herein may be changed because of changes we make in our construction program, unforeseen construction costs, our ability to obtain financing, regulation and for other reasons. See further discussion under "Financing Activities" below.

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Financing Activities

        Our net cash flows from continuing operations provided by financing activities increased $50.4 million to $117.5 million during 2008 as compared to $67.0 million in 2007, primarily due to the issuance of first mortgage bonds and increased usage of short-term borrowings in 2008.

        Our net cash flows from continuing operations provided by financing activities decreased $76.1 million to $67.0 million during 2007 as compared to $143.1 million in 2006, primarily due to increased repayments of short-term borrowings in 2007.

        On May 16, 2008, we issued $90 million principal amount of first mortgage bonds. The net proceeds of approximately $89.4 million, less $0.4 million of legal and other financing fees, were added to our general funds and used primarily to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

        On December 12, 2007, we sold 3,000,000 shares of our common stock in an underwritten public offering for $23.00 per share. The sale resulted in net proceeds of approximately $65.8 million ($69.0 million less issuance costs of $3.2 million). The proceeds were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

        On March 26, 2007, we issued $80 million principal amount of first mortgage bonds. The net proceeds of approximately $79.1 million, less $0.4 million of legal and other financing fees, were added to our general funds and used to pay down short-term indebtedness incurred, in part, as a result of our on-going construction program.

        On June 21, 2006, we sold 3,795,000 shares of our common stock, including an additional 495,000 shares to cover the underwriters' over-allotments, in an underwritten public offering for $20.25 per share. The sale resulted in net proceeds of approximately $73.3 million ($76.8 million less issuance costs of $3.5 million). The proceeds were used to pay down short-term debt, including short-term debt used to fund a portion of our acquisition of Missouri Gas.

        On June 1, 2006, we used $55 million of privately placed 6.82% First Mortgage Bonds due 2036 issued by EDG to fund a portion of our acquisition of Missouri Gas. We used short-term debt to fund the remainder of the acquisition, which was replaced with common equity on June 21, 2006.

        We have a $400 million shelf registration statement with the SEC, which became effective on August 15, 2008, covering our common stock, unsecured debt securities, preference stock, first mortgage bonds and trust preferred securities. We have received regulatory approval in all four of our state jurisdictions. Of the $400 million, $250 million is available for first mortgage bonds. We plan to use a portion of the proceeds from issuances under this shelf to fund a portion of the capital expenditures for our new generation projects.

        On July 15, 2005, we entered into a $150 million unsecured revolving credit facility until July 15, 2010. Borrowings (other than through commercial paper) are at the bank's prime commercial rate or LIBOR plus 100 basis points based on our current credit ratings and the pricing schedule in the line of credit facility. On March 14, 2006, we entered into the First Amended and Restated Unsecured Credit Agreement which amends and restates the $150 million unsecured revolving credit facility. The principal amount of the credit facility was increased to $226 million, with the additional $76 million allocated to support a letter of credit issued in connection with our participation in the Plum Point Energy Station project. This extra $76 million of availability reduces over a four year period in line with the amount of construction expenditures we owe for Plum Point Unit 1 and was $19.5 million as of February 1, 2009. The unallocated credit facility is used for working capital, general corporate purposes and to back-up our use of commercial paper. This facility requires our total indebtedness (which does not include our note payable to the securitization trust) to be less than 62.5% of our total capitalization at the end of each fiscal quarter and our EBITDA (defined as net income plus interest, taxes, depreciation and amortization) to be at least

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two times our interest charges (which includes interest on the note payable to the securitization trust) for the trailing four fiscal quarters at the end of each fiscal quarter. Failure to maintain these ratios will result in an event of default under the credit facility and will prohibit us from borrowing funds thereunder. As of December 31, 2008, we are in compliance with these ratios. This credit facility is also subject to cross-default if we default on in excess of $10 million in the aggregate on our other indebtedness. This arrangement does not serve to legally restrict the use of our cash in the normal course of operations. There were $93.0 million of outstanding borrowings under this agreement at December 31, 2008. In addition, $9.0 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

        The principal amount of all series of first mortgage bonds outstanding at any one time under the EDE Mortgage is limited by terms of the mortgage to $1 billion. Substantially all of the property, plant and equipment of The Empire District Electric Company (but not its subsidiaries) is subject to the lien of the EDE Mortgage. Restrictions in the EDE mortgage bond indenture could affect our liquidity. 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 twelve months ended December 31, 2008 would permit us to issue approximately $253.5 million of new first mortgage bonds based on this test with 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, 2008, we had retired bonds and net property additions which would enable the issuance of at least $612.0 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2008, we are in compliance with all restrictive covenants of the EDE Mortgage.

        The principal amount of all series of first mortgage bonds outstanding at any one time under the EDG Mortgage is limited by terms of the mortgage to $300 million. Substantially all of the property, plant and equipment of The Empire District Gas Company is subject to the lien of the EDG Mortgage. 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, 2008, these tests would allow us to issue new first mortgage bonds of approximately $3.1 million based on $4.2 million of property additions.

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

 
  Fitch   Moody's   Standard & Poor's

Corporate Credit Rating

  n/r*   Baa2   BBB-

First Mortgage Bonds

  BBB+   Baa1   BBB+

First Mortgage Bonds — Pollution Control Series

  AAA   Aaa   AAA

Senior Notes

  BBB   Baa2   BBB-

Trust Preferred Securities

  BBB-   Baa3   BB

Commercial Paper

  F2   P-2   A-3

Outlook

  Negative   Negative   Stable

*
Not rated

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        On May 17, 2006, S&P lowered our long-term corporate credit rating to BBB- from BBB, senior secured debt to BBB+ from A-, senior unsecured debt rating to BB+ from BBB- and affirmed our short-term rating of A-3. S&P's downgrade reflected their view that our financial measures will be constrained over the next several years by fuel and power costs that continue to exceed the level recoverable in rates, and by our higher-than-historical level of capital spending, including the acquisition of Missouri Gas. S&P affirmed our ratings on June 8, 2007 and again on June 12, 2008 with a stable outlook. On November 5, 2008, Standard & Poor's raised our senior unsecured debt rating from BB+ (a non-investment grade rating) to BBB- as a result of a reevaluation of the application of their notching criteria for U. S. investment-grade investor-owned utility operating company unsecured debt to better reflect the relatively strong recovery prospects of creditors in this sector. As a result, the senior unsecured debt of most utilities will now be rated the same as the corporate credit rating almost uniformly, even when a considerable amount of secured debt is outstanding.

        On January 24, 2007, Moody's affirmed our ratings but changed their rating outlook on us from stable to negative. The change to a negative rating outlook reflects Moody's view on the longer-term prospects for our ratings given the sizable capital spending program we have committed to through 2010 and the potential for further weakness in our credit metrics that could develop during this time. On February 14, 2008, Moody's placed all of our ratings on review for possible downgrade. Moody's announced that the review would consider the cumulative impact that certain negative events, including severe weather and operational disruptions in 2007 and 2008, have had on our cash flow and overall financial flexibility at the current rating level as well as consider the potential for elevated costs related to our capital spending plan in 2008. On May 12, 2008, Moody's affirmed our ratings with a negative outlook.

        On December 19, 2005, Fitch Ratings initiated coverage and assigned ratings (see table above) with a stable rating outlook. Fitch announced that their ratings reflect our low business risk position as a regulated electric utility, a stable service territory and a seemingly improving regulatory environment in Missouri where we receive approximately 89% of our electric revenues. On January 25, 2008, Fitch affirmed our ratings but revised their rating outlook to negative. At the time of the change, the negative rating outlook reflected uncertainty surrounding the outcome of our Missouri rate filing and weakness in our projected financial measures relative to Fitch guidelines. Events leading to the revision were storm damage incurred in December 2007 and the extended Asbury coal plant outage we experienced last winter.


CONTRACTUAL OBLIGATIONS

        Set forth below is information summarizing our contractual obligations as of December 31, 2008. Not included in these amounts are expected obligations associated with our share of the Iatan 2 construction and Iatan 1 environmental construction additions for which we have not yet been billed. Other postretirement benefit plans are funded on an ongoing basis to match their corresponding costs, per regulatory requirements and have been estimated for 2009-2013 as noted below. In light of the credit crisis and resulting market turmoil that occurred in the second half of the year, we expect future pension funding commitments to increase. The expected minimum funding for 2009 is estimated to be between $0 million and $4 million. For 2010 it is estimated to be between $9 million and $15 million. The actual minimum

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funding requirements will be determined based on the results of the actuarial valuations and, in the case of 2010, the performance of our pension assets during 2009.

 
  Payments Due By Period
(in millions)
 
Contractual Obligations(1)
  Total   Less Than
1 Year
  1-3 Years   3-5 Years   More Than
5 Years
 

Long-term debt (w/o discount)

  $ 582.3   $ 20.0   $ 50.0     111.2   $ 401.1  

Note payable to securitization trust

    50.0                 50.0  

Interest on long-term debt

    581.7     34.0     59.5     56.6     431.6  

Short-term debt

    102.0     102.0              

Capital lease obligations

    0.5     0.3     0.2          

Operating lease obligations(2)

    3.1     1.1     1.0     0.5     0.5  

Electric purchase obligations(3)

    282.1     66.5     83.0     52.4     80.2  

Gas purchase obligations(4)

    64.6     9.2     14.3     14.8     26.3  

Open purchase orders

    51.5     24.1     27.4          

Plum Point

    14.6     9.3     5.3          

SPP transmission system upgrades

    4.6     4.6              

Postretirement benefit obligation funding

    15.8     3.0     6.3     6.5      

Other long-term liabilities(5)

    3.8     0.1     0.3     0.3     3.1  
                       

TOTAL CONTRACTUAL OBLIGATIONS(6)

  $ 1,756.6   $ 274.2   $ 247.3   $ 242.3   $ 992.8  
                       

(1)
Some of our contractual obligations have price escalations based on economic indices, but we do not anticipate these escalations to be significant.

(2)
Excludes payments under our Elk River Wind Farm, LLC and Cloud County Wind Farm, LLC agreements, as payments are contingent upon output of the facilities. Payments under the Elk River Wind Farm, LLC agreement can run from zero up to a maximum of approximately $16.9 million per year based on a 20 year average cost and an annual output of 550,000 megawatt hours. Payments under the Meridian Way Wind Farm agreement can range from zero to a maximum of approximately $14.6 million per year based on a 20-year average cost.

(3)
Includes a water usage contract for our SLCC facility, fuel and purchased power contracts and associated transportation costs, as well as purchased power for 2010 through 2015 for Plum Point.

(4)
Represents fuel contracts and associated transportation costs of our gas segment.

(5)
Other long-term liabilities primarily represent electric facilities charges owed to City Utilities of Springfield, Missouri of $11,000 per month over 30 years.

(6)
Our estimate of uncertain tax liabilities as required by FIN 48 totaled $2.2 million at December 31, 2008. Due to the uncertainties surrounding this estimate, we cannot reasonably estimate the timing of potential payments, if any, and have not included any in the table above.


DIVIDENDS

        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, 2008, our retained earnings balance was $13.6 million, compared to $17.2 million as of December 31, 2007, after paying out $43.3 million in dividends during 2008. A reduction of our dividend per share, partially or in whole, could have an adverse effect on our common stock price.

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        Our diluted earnings per share were $1.17 for the year ended December 31, 2008 and were $1.09 and $1.39 for the years ended December 31, 2007 and 2006, respectively. Dividends paid per share were $1.28 for the year ended December 31, 2008 and for each of the years ended December 31, 2007 and 2006.

        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 $10.75 million, as described above. As of December 31, 2008, 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, 2008, there were no such restrictions on our ability to pay dividends.


OFF-BALANCE SHEET ARRANGEMENTS

        We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources, other than operating leases entered into in the normal course of business.


CRITICAL ACCOUNTING POLICIES

        Set forth below are certain accounting policies that are considered by management to be critical and that typically require difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain (other accounting policies may also require assumptions that could cause actual results to be different than anticipated results). A change in assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

        Pensions and Other Postretirement Benefits (OPEB).    We recognize expense related to pension and postretirement benefits as earned during the employee's period of service. Related assets and liabilities are established based upon the funded status of the plan compared to the accumulated benefit obligation. Our pension and OPEB expense or benefit includes amortization of previously unrecognized net gains or losses. Additional income or expense may be recognized when our unrecognized gains or losses as of the most recent measurement date exceed 10% of our postretirement benefit obligation or fair value of plan assets, whichever is greater. For pension benefits (effective January 1, 2005) and OPEB benefits (effective January 1, 2007) unrecognized net gains or losses as of the measurement date are amortized into actuarial expense over ten years.

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        In our 2005 electric Missouri Rate Case the MPSC ruled that we would be allowed to recover pension costs consistent with our GAAP policy noted above. In accordance with the rate order, we prospectively calculated the value of plan assets using a market related value method (as allowed by Statement of Financial Accounting Standards No. 87 — "Employers' Accounting for Pensions" (FAS 87)).

        The MPSC ruling also allowed us to record the Missouri portion of any costs above or below the amount included in rates as a regulatory asset or liability, respectively. Therefore, the deferral of these costs began in the second quarter of 2005. In our 2006 Kansas Rate Case, the KCC also ruled that we would be allowed to change our recognition of pension costs, deferring the Kansas portion of any costs above or below the amount included in our rate case as a regulatory asset or liability. In our agreement with the MPSC regarding the purchase of Missouri Gas by EDG, we were allowed to adopt this pension cost recovery methodology for EDG, as well. Also, it was agreed that the effects of purchase accounting entries related to pension and other post-retirement benefits would be recoverable in future rate proceedings. Thus the fair value adjustment acquisition entries have been recorded as regulatory assets, as we believe these amounts are probable of recovery in future rates. The regulatory asset will be reduced by an amount equal to the difference between the regulatory costs and the estimated FAS 87 costs. The difference between this total and the costs being recovered from customers will be deferred as a regulatory asset or liability in accordance with FAS 71, and recovered over a period of 5 years. We now expect future pension expense or benefits are probable of full recovery in rates charged to our Missouri and Kansas customers, thus lowering our sensitivity to accounting risks and uncertainties.

        Our 2006 Missouri rate case order allows us to defer any OPEB cost that is different from those allowed recovery in this rate case. This treatment is similar to treatment afforded pension costs in our March 2005 rate case. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into expense over ten years and the recognition of regulatory assets and liabilities as described in the immediately preceding paragraph.

        On December 31, 2006, we adopted FASB No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106 and 132R" (FAS 158). FAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. We adopted FAS 158 for the fiscal year ended December 31, 2006. Based on the regulatory treatment of pension and OPEB recovery afforded in our jurisdictions, we have concluded that the amount of unfunded defined benefit pension and postretirement plan obligations will be recorded as regulatory assets on our balance sheet rather than as reductions of equity through comprehensive income.

        Our 2008 Missouri rate case order approved Stipulations providing for the continuation of the pension and other post-retirement employee benefits tracking mechanism established in our 2006 and 2007 Missouri rate cases. Due to the downturn of the financial markets in the second half of 2008, at December 31, 2008, our net liability for pension and OPEB increased $53.2 million and $15.5 million, respectively. These increases were recorded as increases to regulatory assets as we believe they are probable of recovery through customer rates based on rate orders received in our jurisdictions. (See Note 9 of "Notes to Consolidated Financial Statements" under Item 8).

        Risks and uncertainties affecting the application of our pension accounting policy include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount rates), demographic assumptions (i.e. mortality and retirement rates) and employee compensation trend rates. Factors that could result in additional pension expense and/or funding include: a lower discount rate than estimated, higher compensation rate increases, lower return on plan assets, and longer retirement periods.

        Risks and uncertainties affecting the application of our OPEB accounting policy and related funding include: future rate of return on plan assets, interest rates used in valuing benefit obligations (i.e. discount

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rates), healthcare cost trend rates, Medicare prescription drug costs and demographic assumptions (i.e. mortality and retirement rates). See Note 1 and Note 9 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        Hedging Activities.    We currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices. We enter into contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to a range of predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expense and gain predictability. We recognize that if risk is not timely and adequately balanced or if counterparties fail to perform contractual obligations, actual results could differ materially from intended results. All derivative instruments are recognized at fair value on the balance sheet with gains and losses from effective instruments deferred in other comprehensive income (in stockholders' equity) or a regulatory asset or liability for instruments entered into after September 1, 2008, while gains and losses from ineffective (overhedged) instruments are recognized as the fair value of the derivative instrument changes. 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 the impact of fluctuating fuel costs on our net income.

        Risks and uncertainties affecting the application of this accounting policy include: market conditions in the energy industry, especially the effects of price volatility, regulatory and global political environments and requirements, fair value estimations on longer term contracts, the effectiveness of the derivative instrument in hedging the change in fair value of the hedged item, estimating underlying fuel demand and counterparty ability to perform. If we estimate that we have overhedged forecasted demand, the gain or loss on the overhedged portion will be recognized immediately in our Consolidated Statement of Income. See Note 15 of "Notes to Consolidated Financial Statements" under Item 8 for detailed information regarding our hedging information.

        As of February 6, 2009, approximately 78% of our anticipated volume of natural gas usage for our electric operations for the year 2009 is hedged, either through physical or financial contracts, at an average price of $6.274 per Dekatherm (Dth). In addition, the following volumes and percentages of our anticipated volume of natural gas usage for our electric operations for the next four years are hedged at the following average prices per Dth:

Year
  % Hedged   Dth Hedged   Average Price  

2010

    64 %   5,715,000   $ 6.538  

2011

    37 %   3,200,000   $ 5.561  

2012

    14 %   1,200,000   $ 7.295  

2013

    12 %   1,200,000   $ 7.295  

        We attempt to mitigate our natural gas price risk for our gas segment by a combination of (1) injecting natural gas into storage during the off-heating season months, (2) purchasing physical forward contracts and (3) purchasing financial derivative contracts. As of February 6, 2009, we have 100% of our expected remaining winter heating season usage (through March 2009) hedged with physical storage, physical forward contracts and financial derivative contracts. The average price of these hedges is $7.49 per Dth. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of February 6, 2009, we had 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 36% of our storage capacity. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of current year, up to 50% of second year and up to 20% of third year expected gas usage by the beginning of the Actual Cost Adjustment (ACA) year at September 1. A PGA clause is included in our rates for our gas segment operations, therefore, we mark to market any unrealized gains or losses and

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any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

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

        In accordance with FAS 71, we record a regulatory asset for all or part of an incurred cost that would otherwise be charged to expense in accordance with FAS 71 paragraphs 9a and b which requires that an asset be recorded if it is probable that future revenue in an amount at least equal to the capitalized cost will be allowable for costs for rate making purposes and the current available evidence indicates that future revenue will be provided to permit recovery of the cost. Additionally, we follow FAS 71 paragraph 11 which says that a liability should be recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the future. We follow this guidance for incurred costs or credits that are subject to future recovery from or refund to our customers in accordance with the orders of our regulators.

        Historically, all costs of this nature, which are determined by our regulators to have been prudently incurred, have been recoverable through rates in the course of normal ratemaking procedures. Regulatory assets and liabilities are ratably eliminated through a charge or credit, respectively, to earnings while being recovered in revenues and fully recognized if and when it is no longer probable that such amounts will be recovered through future revenues. We continually assess the recoverability of our regulatory assets. Although we believe it unlikely, should retail electric competition legislation be passed in the states we serve, we may determine that we no longer meet the criteria set forth in FAS 71 with respect to continued recognition of some or all of the regulatory assets and liabilities. Any regulatory changes that would require us to discontinue application of FAS 71 based upon competitive or other events may also impact the valuation of certain utility plant investments. Impairment of regulatory assets or utility plant investments could have a material adverse effect on our financial condition and results of operations.

        As of December 31, 2008, we have recorded $164.1 million in regulatory assets and $66.6 million as regulatory liabilities. See Note 4 of "Notes to Consolidated Financial Statements" under Item 8 for detailed information regarding our regulatory assets and liabilities.

        Risks and uncertainties affecting the application of this accounting policy include: regulatory environment, external regulatory decisions and requirements, anticipated future regulatory decisions and their impact of deregulation and competition on ratemaking process, possible changes in accounting standards and the ability to recover costs.

        Unbilled Revenue.    At the end of each period we estimate, based on expected usage, the amount of revenue to record for energy and natural gas that has been provided to customers but not billed. Risks and uncertainties affecting the application of this accounting policy include: projecting customer energy usage, estimating the impact of weather and other factors that affect usage (such as line losses) for the unbilled period and estimating loss of energy during transmission and delivery.

        Contingent Liabilities.    We are a party to various claims and legal proceedings arising in the ordinary course of our business. We regularly assess our insurance deductibles, analyze litigation information with our attorneys and evaluate our loss experience. Based on our evaluation as of the end of 2008, we believe that we have accrued liabilities in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, "Accounting for Contingencies" (FAS 5) sufficient to meet potential liabilities that could result from these claims. This liability at December 31, 2008 and 2007 was $3.5 million and $2.0 million, respectively.

        Risks and uncertainties affecting these assumptions include: changes in estimates on potential outcomes of litigation and potential litigation yet unidentified in which we might be named as a defendant.

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        Goodwill.    We recorded goodwill of $39.5 million upon the completion of the 2006 Missouri Gas acquisition. Goodwill represents the excess of the cost of the acquisition over the fair value of the related net assets at the date of acquisition. In accordance with Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," (FAS 142) goodwill is required to be tested for impairment on an annual basis or whenever events or circumstances indicate possible impairment. In performing impairment tests, we utilize valuation techniques which estimate the discounted future cash flows of operations. Our procedures include developing a baseline test and performing sensitivity analysis to calculate a reasonable valuation range. The sensitivities are derived from altering those assumptions which are subjective in nature and inherent to a discounted cash flows valuation technique. Other qualitative factors and comparisons to industry peers are also used to further support the assumptions and ultimately the overall evaluation. A significant qualitative factor considered in our evaluation is the impact of regulation, including rate regulation and cost recovery for our gas segment. Some of the more significant quantitative assumptions included in our tests involve: regulatory rate design and results; the discount rate; the growth rate; capital spending rates and terminal value calculations. Risks and uncertainties affecting these assumptions include: management's identification of impairment indicators, changes in business, industry, laws, technology or economic and market conditions. While management believes the assumptions utilized in our analysis were reasonable, significant adverse developments in the gas segment in future periods or changes in the assumptions could negatively impact goodwill impairment considerations, which could adversely impact earnings. We performed our annual goodwill impairment test as of November 30, 2008 and concluded our goodwill was not impaired.

        Use of Management's Estimates.    The preparation of our consolidated financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to unbilled utility revenues, collectibility of accounts receivable, depreciable lives, asset impairment and goodwill evaluations, employee benefit obligations, contingent liabilities, asset retirement obligations, the fair value of stock based compensation and tax provisions. Actual amounts could differ from those estimates.


RECENTLY ISSUED ACCOUNTING STANDARDS

        See Recently Issued and Proposed Accounting Standards under Note 1 of "Notes to Consolidated Financial Statements" under Item 8.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Market risk is the exposure to a change in the value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates or commodity prices. We handle our commodity market risk in accordance with our established Energy Risk Management Policy, which typically includes entering into various derivative transactions. We utilize derivatives to manage our gas commodity market risk and to help manage our exposure resulting from purchasing most of our natural gas on the volatile spot market for the generation of power for our native-load customers. See Note 15 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        Interest Rate Risk.    We are exposed to changes in interest rates as a result of financing through our issuance of commercial paper and other short-term debt. We manage our interest rate exposure by limiting our variable-rate exposure (applicable to commercial paper and borrowings under our unsecured credit agreement) to a certain percentage of total capitalization, as set by policy, and by monitoring the effects of market changes in interest rates. See Notes 7 and 8 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        If market interest rates average 1% more in 2009 than in 2008, our interest expense would increase, and income before taxes would decrease by less than $0.8 million. This amount has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2008. These analyses do not consider the effects of the reduced level of overall economic activity that could exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.

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

        We satisfied 60.9% of our 2008 generation fuel supply need through coal. Approximately 90% of our 2008 coal supply was Western coal. We have contracts and binding proposals to supply fuel for our coal plants through 2011. These contracts and binding proposals satisfy approximately 88% of our anticipated fuel requirements for 2009, 75% for 2010 and 29% for our 2011 requirements for our Asbury and Riverton coal plants. In order to manage our exposure to fuel prices, future coal supplies will be acquired using a combination of short-term and long-term contracts.

        We are exposed to changes in market prices for natural gas we must purchase to run our combustion turbine generators. Our natural gas procurement program is designed to manage our costs to avoid volatile natural gas prices. We enter into physical forward and financial derivative contracts with counterparties relating to our future natural gas requirements that lock in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in our fuel expenditures and improve predictability. As of February 6, 2009, 78%, or 5.3 million Dths's, of our anticipated volume of natural gas usage for our electric operations for 2010 is hedged. See Note 15 of "Notes to Consolidated Financial Statements" under Item 8 for further information.

        Based on our expected natural gas purchases for our electric operations for 2009, if average natural gas prices should increase 10% more in 2009 than the price at December 31, 2008, our natural gas expenditures would increase by approximately $2.4 million based on our December 31, 2008 total hedged positions for the next twelve months. However, this is probable of recovery through fuel adjustment mechanisms. 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 the impact of fluctuating fuel costs.

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        We attempt to mitigate a portion of our natural gas price risk associated with our gas segment using physical forward purchase agreements, storage and derivative contracts. As of February 6, 2009, we have 100% of our expected remaining winter heating season usage (through March 2009) hedged with physical storage, physical forward contracts and financial derivative contracts. The average price of these hedges is $7.49 per Dth. We target to have 95% of our storage capacity full by November 1 for the upcoming winter heating season. As the winter progresses, gas is withdrawn from storage to serve our customers. As of February 6, 2009, we have 0.7 million Dths in storage on the three pipelines that serve our customers. This represents 36% of our storage capacity. Our long-term hedge strategy is to mitigate price volatility for our customers by hedging a minimum of 50% of the current year, up to 50% of the second year and up to 20% of third year expected gas usage by the beginning of the ACA year at September 1. However, due to purchased natural gas cost recovery mechanisms for our retail customers, fluctuations in the cost of natural gas have little effect on income.

        Credit Risk.    Credit risk is the risk of financial loss to the Company if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, certain counterparties make available collateral in the form of cash held as margin deposits as a result of exceeding agreed-upon credit exposure thresholds or may be required to prepay the transaction. Conversely, we are required to post collateral with counterparties at certain thresholds, which is typically the result of changes in commodity prices. Amounts reported as margin deposit liabilities represent funds we hold that result from various trading counterparties exceeding agreed-upon credit exposure thresholds. Amounts reported as margin deposit assets represent funds held on deposit by various trading counterparties that resulted from us exceeding agreed-upon credit limits established by the counterparties. The following table depicts our margin deposit assets and margin deposit liabilities recorded on our balance sheet at December 31:

(in millions)
  2008   2007  

Margin deposit assets

  $ 10.7   $ 6.3  

Margin deposit liabilities

  $   $  

        On September 30, 2008, we converted a $6.5 million letter of credit from a counterparty to cash. This amount has since been returned to the counterparty due to the decline in natural gas prices.

        Our exposure to credit risk is concentrated primarily within our fuel procurement process, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. At February 6, 2009, net credit exposure related to these transactions totaled ($13.6) million reflecting that our counterparties are exposed to Empire for the net unrealized mark-to-market losses for physical forward and financial natural gas contracts carried at fair value. This ($13.6) million consists of ($7.2) million of net unrealized mark-to-market losses for physical forward natural gas contracts and ($6.4) million of net unrealized mark-to-market losses for financial natural gas contracts. Included in the ($6.4) million net unrealized mark-to-market losses for financial natural gas contracts, we have exposure with a single counterparty of $6.2 million of unrealized mark-to-market gains. We are holding no collateral from this counterparty since we are below the $10 million mark-to-market collateral threshold in our agreement with this counterparty. As noted above, we have $10.7 million on deposit covering NYMEX exposure to Empire.

        We sell electricity and gas and provide distribution and transmission services to a diverse group of customers, including residential, commercial and industrial customers. Credit risk associated with trade accounts receivable from energy customers is limited due to the large number of customers. In addition, we enter into contracts with various companies in the energy industry for purchases of energy-related commodities, including natural gas in our fuel procurement process.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

        In our opinion, the consolidated financial statements listed in the index appearing under Item 15 present fairly, in all material respects, the financial position of The Empire District Electric Company and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits (which were integrated audits in 2008 and 2007). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP
St. Louis, Missouri
February 20, 2009

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

 
  December 31,  
 
  2008   2007  
 
  ($-000's)
 

Assets

             

Plant and property, at original cost:

             
 

Electric

  $ 1,485,235   $ 1,409,217  
 

Natural gas

    56,282     54,715  
 

Water

    10,560     10,353  
 

Non-regulated

    28,481     26,355  
 

Construction work in progress

    289,460     167,049  
           

    1,870,018     1,667,689  

Accumulated depreciation and amortization

    527,245     488,816  
           

    1,342,773     1,178,873  
           

Current assets:

             
 

Cash and cash equivalents

    2,754     4,043  
 

Accounts receivable — trade, net of allowance of $1,265 and $1,140 respectively

    39,487     38,011  
 

Accrued unbilled revenues

    25,170     20,886  
 

Accounts receivable — other

    19,353     15,465  
 

Fuel, material and supplies

    54,202     49,482  
 

Unrealized gain in fair value of derivative contracts

    2,395     2,499  
 

Prepaid expenses and other

    5,675     3,308  
 

Regulatory assets

    2,033      
           

    151,069     133,694  
           

Noncurrent assets and deferred charges:

             
 

Regulatory assets

    162,026     92,785  
 

Goodwill

    39,492     39,492  
 

Unamortized debt issuance costs

    9,133     6,662  
 

Unrealized gain in fair value of derivative contracts

    6,434     17,520  
 

Other

    2,919     4,048  
           

    220,004     160,507  
           

Total assets

  $ 1,713,846   $ 1,473,074  
           

(Continued)

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

 
  December 31,  
 
  2008   2007  
 
  ($-000's)
 

Capitalization and liabilities

             

Common stock, $1 par value, 100,000,000 shares authorized, 33,981,579 and 33,605,871 shares issued and outstanding, respectively

 
$

33,982
 
$

33,606
 

Capital in excess of par value

    483,443     477,385  

Retained earnings

    13,579     17,153  

Accumulated comprehensive income/(loss), net of income tax

    (2,132 )   11,032  
           
   

Total common stockholders' equity

    528,872     539,176  

Long-term debt (net of current portion)

             
 

Note payable to securitization trust

    50,000     50,000  
 

Obligations under capital lease

    174     349  
 

First mortgage bonds and secured debt

    312,953     242,959  
 

Unsecured debt

    248,440     248,572  
           
   

Total long-term debt

    611,567     541,880  
           
   

Total long-term debt and common stockholders' equity

    1,140,439     1,081,056  
           

Current liabilities:

             
 

Accounts payable and accrued liabilities

    69,502     79,282  
 

Current maturities of long-term debt

    20,160     150  
 

Short-term debt

    102,000     33,040  
 

Customer deposits

    9,577     8,414  
 

Interest accrued

    5,921     5,147  
 

Unrealized loss in fair value of derivative contracts

    12,276     1,611  
 

Taxes accrued

    3,174     2,931  
 

Other current liabilities

        328  
           

    222,610     130,903  
           

Commitments and contingencies (Note 12)

             

Noncurrent liabilities and deferred credits:

             
 

Regulatory liabilities

    66,585     58,107  
 

Deferred income taxes

    173,511     165,989  
 

Unamortized investment tax credits

    2,917     3,441  
 

Pension and other postretirement benefit obligations

    83,151     14,115  
 

Unrealized loss in fair value of derivative contracts

    3,302     698  
 

Other

    21,331     18,765  
           

    350,797     261,115  
           
   

Total capitalization and liabilities

  $ 1,713,846   $ 1,473,074  
           

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

 
  Year Ended December 31,  
 
  2008   2007   2006  
 
  ($-000's, except per share amounts)
 

Operating revenues:

                   
 

Electric

  $ 446,466   $ 425,161   $ 382,653  
 

Gas

    65,438     59,877     25,145  
 

Water

    1,782     1,879     1,843  
 

Other

    4,477     3,243     2,530  
               

    518,163     490,160     412,171  
               

Operating revenue deductions:

                   
 

Fuel and purchased power

    204,058     191,230     160,294  
 

Cost of natural gas sold and transported

    42,630     37,626     15,285  
 

Regulated operating expenses

    71,918     71,367     60,092  
 

Other operating expenses

    1,889     1,611     1,335  
 

Maintenance and repairs

    28,549     32,059     23,150  
 

Loss on plant disallowance

            828  
 

Gain on sale of assets

        (1,241 )    
 

Depreciation and amortization

    53,562     52,599     38,392  
 

Provision for income taxes

    19,128     14,416     21,947  
 

Other taxes

    25,417     24,927     21,027  
               

    447,151     424,594     342,350  
               

Operating income

    71,012     65,566     69,821  

Other income and (deductions):

                   
 

Allowance for equity funds used during construction

    5,929     2,923     1,405  
 

Interest income

    1,057     326     389  
 

Benefit/(provision) for other income taxes

    2     (28 )   16  
 

Other — non-operating expense, net

    (1,569 )   (969 )   (962 )
               

    5,419     2,252     848  
               

Interest charges:

                   
 

Long-term debt

    36,041     31,120     25,947  
 

Note payable to securitization trust

    4,250     4,250     4,250  
 

Short-term debt

    1,854     2,940     2,276  
 

Allowance for borrowed funds used during construction

    (6,589 )   (4,742 )   (2,850 )
 

Other

    1,153     1,069     1,017  
               

    36,709     34,637     30,640  
               

Income from continuing operations

    39,722     33,181     40,029  
 

Income (loss) from discontinued operations, net of tax

        63     (749 )
               

Net income

  $ 39,722   $ 33,244   $ 39,280  
               

Weighted average number of common shares outstanding — basic

    33,821     30,587     28,277  
               

Weighted average number of common shares outstanding — diluted

    33,860     30,610     28,296  
               

Earnings from continuing operations per weighted average share of common stock — basic and diluted

  $ 1.17   $ 1.09   $ 1.42  
               

Gain (loss) from discontinued operations per weighted average share of common stock — basic and diluted

        0.00     (0.03 )
               

Total earnings per weighted average share of common stock — basic and diluted

  $ 1.17   $ 1.09   $ 1.39  
               

Dividends declared per share of common stock

  $ 1.28   $ 1.28   $ 1.28  
               

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
  Year Ended December 31,  
 
  2008   2007   2006  
 
  ($-000's)
 

Net income

  $ 39,722   $ 33,244   $ 39,280  
               

Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability

    (3,872 )   (1,610 )   (1,320 )

Net change in fair market value of open derivative contracts for period

    (17,394 )   5,229     (13,604 )

Income taxes

    8,102     (1,379 )   5,686  
               

Comprehensive income

  $ 26,558   $ 35,484   $ 30,042  
               

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

 
  December 31,  
 
  2008   2007   2006  
 
  ($-000's)
 

Common stock, $1 par value:

                   
 

Balance, beginning of year

  $ 33,606   $ 30,251   $ 26,084  
 

Stock/stock units issued through:

                   
   

Public offering

        3,000     3,795  
   

Stock purchase and reinvestment plans

    376     355     372  
               
     

Balance, end of year

  $ 33,982   $ 33,606   $ 30,251  
               

Capital in excess of par value:

                   
 

Balance, beginning of year

  $ 477,385   $ 406,650   $ 329,605  
 

Excess of net proceeds over par value of stock issued:

                   
   

Public offering

        62,779     69,519  
   

Stock purchase and reinvestment plans

    6,058     7,956     7,526  
               
     

Balance, end of year

  $ 483,443   $ 477,385   $ 406,650  
               

Retained earnings:

                   
 

Balance, beginning of year

  $ 17,153   $ 22,916   $ 19,692  
 

Cumulative effect of adopting a change in accounting

        (54 )    
 

Net income

    39,722     33,244     39,280  
               

    56,875     56,106     58,972  
 

Less common stock dividends declared

    43,296     38,953     36,056  
               
     

Balance, end of year

  $ 13,579   $ 17,153   $ 22,916  
               

Accumulated comprehensive income/(loss):

                   
 

Balance, beginning of year

  $ 11,032   $ 8,792   $ 18,030  
 

Reclassification adjustment for gains included in net income

    (3,872 )   (1,610 )   (1,320 )
 

Change in fair value of open derivative contracts for period

    (17,394 )   5,229     (13,604 )
 

Income taxes

    8,102     (1,379 )   5,686  
               
     

Balance, end of year

  $ (2,132 ) $ 11,032   $ 8,792  
               

Total Common Stockholders' Equity, end of year

  $ 528,872   $ 539,176   $ 468,609  
               

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

 
  Year Ended December 31,  
 
  2008   2007   2006  
 
  ($-000's)
 

Operating activities:

                   
 

Net income

  $ 39,722   $ 33,244   $ 39,280  

Adjustments to reconcile net income to cash flows:

                   
 

Depreciation and amortization

    59,066     57,317     42,969  
 

Pension and other postretirement benefit costs

    8,282     9,490     5,689  
 

Deferred income taxes and unamortized investment tax credit, net

    8,580     18,681     845  
 

Allowance for equity funds used during construction

    (5,929 )   (2,923 )   (1,405 )
 

Stock compensation expense

    2,169     2,394     1,887  
 

Loss on plant disallowance

            828  
 

Non cash gain on derivatives

    (39 )   (893 )   (3,380 )
 

Gain on the sale of assets

        (1,241 )    
 

Gain on the sale of other segment businesses

        (161 )   (827 )
 

Impairment of other non-operating investment

    556          

Cash flows impacted by changes in:

                   
 

Accounts receivable and accrued unbilled revenues

    (10,938 )   (10,216 )   (1,648 )
 

Fuel, materials and supplies

    (4,720 )   (2,869 )   (5,378 )
 

Prepaid expenses, other current assets and deferred charges

    (2,683 )   (13,057 )   (3,506 )
 

Accounts payable and accrued liabilities

    (4,905 )   11,970     (8,235 )
 

Interest, taxes accrued and customer deposits

    2,234     2,532     1,314  
 

Other liabilities and other deferred credits

    1,597     (811 )   742  
               

Net cash provided by operating activities of continuing operations

    92,992     103,457     69,175  

Net cash provided by operating activities of discontinued operations

        208     2,197  
               

Total net cash provided by operating activities

    92,992     103,665     71,372  
               

(Continued)

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

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

 
  Year Ended December 31,  
 
  2008   2007   2006  
 
  ($-000's)
 

Investing activities:

                   
 

Capital expenditures — regulated

    (211,311 ) $ (178,469 ) $ (112,577 )
 

Acquisition of gas operations, net of cash acquired

            (103,195 )
 

Capital expenditures and other investments — non-regulated

    (1,969 )   (4,924 )   (2,632 )
 

Proceeds from the sale of property, plant and equipment

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