UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C.20549

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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, 2007 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 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 registeredCommon 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, 2007, was approximately $681,302,040.

As
of February 15 2008, 33,652,155 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 24, 2008 |  | 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
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ----------------------------------------------------------------------------------------------------------------------------------------



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TABLE OF CONTENTS

|         |  |                                                                                                              |  | Page
|-------- |  | ------------------------------------------------------------------------------------------------------------ |  | ----
|         |  | Forward Looking Statements                                                                                   |  | 3   
|PART I  
|ITEM 1.  |  | BUSINESS                                                                                                     |  | 4   
|         |  | General                                                                                                      |  | 4   
|         |  | Electric Generating Facilities and Capacity                                                                  |  | 5   
|         |  | Gas Facilities                                                                                               |  | 8   
|         |  | 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                                                                                                   |  | 14  
|         |  | Environmental Matters                                                                                        |  | 16  
|         |  | Conditions Respecting Financing                                                                              |  | 20  
|         |  | Our Website                                                                                                  |  | 20  
|ITEM 1A. |  | RISK FACTORS                                                                                                 |  | 21  
|ITEM 1B. |  | UNRESOLVED STAFF COMMENTS                                                                                    |  | 23  
|ITEM 2.  |  | PROPERTIES                                                                                                   |  | 24  
|         |  | Electric Segment Facilities                                                                                  |  | 24  
|         |  | Gas Segment Facilities                                                                                       |  | 26  
|         |  | Other Segment Businesses                                                                                     |  | 26  
|ITEM 3.  |  | LEGAL PROCEEDINGS                                                                                            |  | 26  
|ITEM 4.  |  | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                                          |  | 26  
|PART II 
|ITEM 5.  |  | MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |  | 27  
|ITEM 6.  |  | SELECTED FINANCIAL DATA                                                                                      |  | 29  
|ITEM 7.  |  | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS                        |  | 30  
|         |  | Executive Summary                                                                                            |  | 30  
|         |  | Results of Operations                                                                                        |  | 35  
|         |  | Rate Matters                                                                                                 |  | 44  
|         |  | Competition                                                                                                  |  | 47  
|         |  | Liquidity and Capital Resources                                                                              |  | 49  
|         |  | Contractual Obligations                                                                                      |  | 54  
|         |  | Dividends                                                                                                    |  | 55  
|         |  | Off-Balance Sheet Arrangements                                                                               |  | 56  
|         |  | Critical Accounting Policies                                                                                 |  | 56  
|         |  | Recently Issued Accounting Standards                                                                         |  | 59  
|ITEM 7A  |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                                   |  | 60  
|ITEM 8.  |  | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                                                  |  | 62  
|ITEM 9.  |  | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE                         |  | 128 
|ITEM 9A. |  | CONTROLS AND PROCEDURES                                                                                      |  | 128 
|ITEM 9B. |  | OTHER INFORMATION                                                                                            |  | 128 
|PART III
|ITEM 10. |  | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE COVERNANCE                                                       |  | 129 
|ITEM 11. |  | EXECUTIVE COMPENSATION                                                                                       |  | 129 
|ITEM 12. |  | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS               |  | 129 
|ITEM 13. |  | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE                                    |  | 130 
|ITEM 14. |  | PRINCIPAL ACCOUNTANT FEES AND SERVICES                                                                       |  | 130 
|PART IV 
|ITEM 15. |  | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES                                                                   |  | 131 
|         |  | SIGNATURES                                                                                                   |  | 136 

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FORWARD LOOKING STATEMENTS

Certain matters discussed in this annual report are "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private
Securities Litigation Reform Act of 1995. Such statements address or may address future plans, objectives, expectations and events or conditions concerning various matters such as capital
expenditures, earnings, 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:



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. EDG provides natural gas distribution to communities in northwest, north central and west central Missouri. Our other segment consists of our non-regulated
businesses, primarily our fiber optics business. In 2007, 87.1% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of water), 12.2% from
our gas segment, and 0.7% from our other segment.

The
territory served by our electric operations embraces an area of about 10,000 square miles with a population of over 450,000. The service territory is located principally in
southwestern Missouri and also includes smaller areas in southeastern Kansas, northeastern Oklahoma and northwestern Arkansas. The principal economic activities of these areas include light industry,
agriculture and tourism. Of our total 2007 retail electric revenues, approximately 89.0% came from Missouri customers, 5.5% from Kansas customers, 2.8% from Oklahoma customers and 2.7% 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 2007 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 2007 were derived as follows: residential 41.1%, commercial 30.4%, industrial 15.9%, wholesale on-system 4.3%, wholesale
off-system 4.6% and other 3.7%. Our largest single on-system wholesale customer is the city of Monett, Missouri, which in 2007 accounted for approximately 3% of electric
revenues. No single retail customer accounted for more than 2% of electric revenues in 2007.

Our
gas operations serve customers in northwest, north central and west central Missouri. The principal utility properties consist of approximately 87 miles of transmission mains and
approximately 1,110 miles of distribution mains. We provide natural gas distribution to 44 communities and 269 transportation customers. Our gas operating revenues in 2007 were derived
as follows: residential 65.5%, commercial 27.7%, industrial 1.2% and other 5.6%. No single retail customer accounted for more than 2% of gas revenues in 2007. 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 of our non-regulated businesses, primarily a 100% interest in Empire District Industries, Inc., a subsidiary for our fiber optics business.
We sold our controlling 52% interest in Mid-America Precision Products (MAPP) on August 31, 2006, a company that specialized in close-tolerance custom manufacturing for the
aerospace, electronics, telecommunications and machinery

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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.

Electric Generating Facilities and Capacity

At December 31, 2007, our generating plants consisted of:

|Plant                                     |       | *Capacity
(megawatts) |       | Primary Fuel        
|----------------------------------------- | ----- | --------------------- | ----- | --------------------
|Asbury                                    |       | 210                   |       | Coal                
|Riverton                                  |       | 286                   |       | Coal and Natural Gas
|Iatan (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 |                     
|                                          |       |                       |       |                     

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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. Although our experience to date in the EIS market is limited, we believe we have received benefits through our participation to date. Our active participation and assessment of EIS
market benefits continues.

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 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. 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.

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The
amount of capacity purchased under such contracts supplements our on-system capacity and contributes to meeting our current expectations of future power needs.

On
March 14, 2006, we entered into contracts to add 100 megawatts of power to our system. This power will come from the Plum Point Energy Station, 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 2010. Initially
we will own, through an undivided interest, 50 megawatts of the project's capacity for approximately $86.5 million in direct costs, excluding allowance for funds used during construction
(AFUDC). We also have a long-term (30 year) purchased power agreement for an additional 50 megawatts of capacity and have the option to convert the 50 megawatts
covered by the purchased power agreement into an ownership interest in 2015. We spent $46.4 million through December 31, 2007 and anticipate spending an additional $26.3 million
in 2008, $9.1 million in 2009 and $5.0 million in 2010 for construction expenses (excluding AFUDC) related to our 50 megawatt ownership share of Plum Point Unit 1.

On
February 4, 2005, we filed an application with the Missouri Public Service Commission (MPSC) seeking approval of an Experimental Regulatory Plan (Plan) concerning our possible
participation in a new 800850 MW coal-fired unit (Iatan 2) 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, 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. On July 18, 2005, we filed a Stipulation and Agreement (Agreement) regarding our Plan with the MPSC for its consideration and approval conditioned
upon our participation in Iatan 2. The Agreement contains conditions related to our infrastructure investments, including Iatan 2, environmental investments in Iatan 1, the
150 MW V84.3A2 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. The MPSC issued an order on August 2,
2005 approving the Agreement with an effective date of August 12, 2005.

In
relation to the Plan, we entered into an agreement with KCP&L on June 13, 2006 to purchase an undivided ownership interest in the proposed coal-fired
Iatan 2. We will own 12%, or approximately 100 megawatts, of the 850-megawatt unit. Construction began in the spring of 2006 with completion scheduled for 2010. On
December 12, 2006, KCP&L announced that the total
estimated construction budget for Iatan 2, originally reported to be approximately $1.34 billion, had increased to a range of approximately $1.53 billion to $1.67 billion
due to increases in estimated costs for labor, materials and equipment and also reflecting other market conditions. KCP&L, which will own 54.7% of the unit, announced their expected share of the total
construction costs, originally reported to be approximately $733 million, would actually range from approximately $837 million to $914 million, due to the increase in estimated
costs. Accordingly, our share of the Iatan 2 construction costs will increase from approximately $160.8 million to a range of approximately $183.6 million to
$200.5 million. These estimated construction expenditures exclude AFUDC.

Our
current capital expenditures budget, discussed below, includes $72.4 million in 2008, $43.8 million in 2009 and $33.1 million in 2010 for our share of
Iatan 2, excluding AFUDC. At December 31, 2007, we have recorded approximately $54.6 million in construction expenditures on this project. As of January 10, 2008, KCP&L
stated it had approximately 94% of the total budgeted direct construction cost of Iatan 2 under firm contract and the project was on schedule to meet its targeted completion in 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 is required for
Iatan 1. According to KCP&L, approximately 97% of the total budgeted direct construction costs for the Iatan 1 environmental upgrades are under firm contract as of January 10,
2008. Our share of the environmental upgrade costs at

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Iatan 1
is estimated at $46 million, excluding AFUDC, and will be expended between 2006 and fourth quarter 2009. At December 31, 2007, we have spent approximately
$16.0 million on this project.

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 cost for Unit 12, which began
commercial operation as of April 10, 2007, was $39.5 million, excluding AFUDC.

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 is expected to be during December 2008. We will begin taking delivery of the energy at that time. Under the agreement, we
will purchase all of the output from the approximately 105-megawatt Phase 1 Meridian Wind Farm to be located in Cloud County, Kansas.

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
|-------------- |  | -------------------------- | --- | -------------------------- |  | ---------------
|2007           |  | 162                        |     | 1255                       |  | 1417           
|2008           |  | 169                        | *** | 1255                       |  | 1424           
|2009           |  | 174                        | *** | 1257                       |  | 1431           
|**2010         |  | 62                         | *** | 1407                       |  | 1469           
|**2011         |  | 62                         | *** | 1407                       |  | 1469           

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The
charges for capacity purchases under the Westar contract referred to above during calendar year 2007 amounted to approximately $16.2 million. Minimum charges for capacity
purchases under the Westar contract total approximately $48.6 million for the period June 1, 2007 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 1,059 megawatts was set on February 16, 2007. Our previous winter peak of 1,034 megawatts was established on
January 31, 2007.

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Gas Facilities

We acquired the Missouri natural gas distribution operations of Aquila, Inc. on June 1, 2006. At December 31, 2007, our principal gas utility
properties consisted of approximately 87 miles of transmission mains and approximately 1,110 miles of distribution mains.

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

Service Area

Name of PipelineSouth

Southern Star Central Gas PipelineNorth

Panhandle Eastern Pipe Line CompanyNorthwest

ANR Pipeline Company


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 2007 than the gas supplies produced in the mid-continent region. Cheyenne Plains interconnects with all of the interstate pipelines listed above that feed
our market area. Through this effort we were able to reduce costs for our gas customers.

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 2007 and will continue to do so to enhance supply reliability as well as provide for increased price competition.

The
maximum daily flow on our system for 2007 was a volume of 68,381 mcfs on February 15, 2007.

Construction Program

Total property additions (including construction work in progress), excluding AFUDC, for the three years ended December 31, 2007, amounted to
$376.5 million and retirements during the same period amounted to $30.4 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 $187.6 million in 2007 and for the next three years are estimated for planning purposes to
be as follows:

|                                                      |                                       | Estimated Capital Expenditures (amounts in millions)
|----------------------------------------------------- | ------------------------------------- | ----------------------------------------------------
|
|New electric generating facilities:                   |                                       |                                                     
|                                                      | Iatan 2                               |                                                     
|                                                      | Plum Point Energy Station             |                                                     
|                                                      | Other  combustion turbine  2011     |                                                     
|Additions to existing electric generating facilities: |                                       |                                                     
|                                                      | Environmental upgrades  Asbury Plant |                                                     
|                                                      | Environmental upgrades  Iatan 1      |                                                     
|                                                      | Other                                 |                                                     
|Electric transmission facilities                      |                                       |                                                     
|Electric distribution system additions                |                                       |                                                     
|Non-regulated additions                               |                                       |                                                     
|General and other additions                           |                                       |                                                     
|Gas system additions                                  |                                       |                                                     
|                                                      |                                       |                                                     
|                                                      | Total                                 |                                                     
|                                                      |                                       |                                                     

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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. The primary costs included in new electric generating facilities are for
Iatan 2, the Plum Point Energy Station and a new combustion turbine scheduled to be in service in 2011 at a still-to-be-determined site. The primary costs
included in additions to existing electric generating facilities include environmental upgrades at Iatan 1.

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 mid-2010. The plan is driven by the continued growth in our service area and the expiration of a major purchase power contract in 2010.

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."

Fuel and Natural Gas Supply

Electric Segment

In 2007, 58.9% of our total system input, based on kilowatt-hours generated, was supplied by our steam and combustion turbine generation units, 1.2% was supplied
by our hydro generation, and we purchased the remaining 39.9%. Coal supplied approximately 58.6% of the total fuel requirements for our generating units in 2007 based on kilowatt-hours generated. The
remainder was supplied by natural gas (41.1%), tire-derived fuel (TDF) (0.2%), which is produced from discarded passenger car tires, and fuel oil (0.1%). The amount and percentage of
electricity generated by coal decreased in 2007 as compared to 2006 primarily due to an extended maintenance outage at the Asbury plant in the fourth quarter of 2007. The amount and percentage of
electricity generated by natural gas increased in 2007 as compared to 2006 as did 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. 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 offset the cost of this contract by purchasing less higher-priced power from other suppliers or by displacing on-system
generation. We sell the renewable energy credits to third parties to further reduce our costs.

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 2007, Asbury burned a coal blend consisting of
approximately 84.1% Western coal (Powder River Basin) and 15.9% blend coal on a tonnage basis. Our average coal inventory target at Asbury is approximately 45 days. As of December 31,
2007, we had sufficient coal on hand to supply anticipated requirements at Asbury for 104115 days, as compared to 7983 days as of December 31, 2006,
depending on the actual blend ratio within this range. This increase in inventory is due to Asbury being on an extended outage beginning on September 21, 2007 and extending to
February 10, 2008. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations  Executive Summary  2007
Activities."

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.

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During
2007, Riverton Units 7 and 8 burned an estimated blend of approximately 78.8% Western coal (Powder River Basin) and 21.2% petroleum coke on a tonnage basis. Our average coal inventory
target at Riverton is approximately 45 days. As of December 31, 2007, we had approximately 37,280 tons of Western coal and approximately 11,265 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, 2007 to run 37 days on both units as compared to 36 days as of December 31, 2006. Riverton receives its Western
inventory from coal transported by train to the Asbury Plant which is then transported by truck to Riverton. Therefore, the lower inventory at Riverton as of December 31, 2007, is offset by the
larger inventory at the Asbury Plant which we expect to realign throughout the course of 2008.

We
have secured 93% of our anticipated coal requirements for 2008, 61% for 2009 and 48% for 2010 through a combination of contracts with Peabody Coal Sales, Peabody Coal Trade, Arch Coal
Sales, Rio Tinto, Oxbow Carbon and Minerals (petroleum coke) and coal stored in inventory. We plan to fulfill the remaining 7% of our 2008 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 2008 than in 2007 as oil prices and other
market factors increase the cost of mining. Due to the extended Asbury maintenance outage, we have issued force majeure notices to our Western coal suppliers and to the railroads suspending Western
coal shipments during the outage. This relieves us of our contractual obligations to receive shipments of coal to the extent caused by the Asbury outage.

In
2007, we sold our steel unit train set, which we had previously leased to another utility. 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.

Unit
No. 1 at the Iatan Plant is a coal-fired generating unit which is jointly-owned by KCP&L (70%), Aquila (18%) and us (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 2008 and
approximately 40% for 2009 and 2010. The coal is transported by rail under a contract with BNSF, 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 2007, essentially all of the Energy Center generation
came from natural gas. Based on kilowatt hours generated, State Line Unit 1 fuel consumption during 2007 was 97.8% 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, 2007, we have oil inventories 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

10

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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 expense 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

2007

2006

2005Coal  Iatan

$
0.978

$
0.793

$
0.786Coal  Asbury


1.432


1.402


1.322Coal  Riverton


1.548


1.458


1.391Natural Gas


7.050


7.276


7.208Oil


14.870


6.551


5.893


Our weighted cost of fuel burned per kilowatt-hour generated was 3.2197 cents in 2007, 2.6502 cents in 2006 and 2.8912 cents in
2005.

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 2007 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.

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 2007 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 transportation and other miscellaneous costs, per mcf of gas used in our gas operations:

Service Area

Name of Pipeline

2007

2006South

Southern Star Central Gas Pipeline

$
8.2967

$
8.6513North

Panhandle Eastern Pipe Line Company


7.9568


8.9693Northwest

ANR Pipeline Company


7.0551


7.5771Weighted average cost

$
8.0534

$
8.5857


Employees

At December 31, 2007, we had 733 full-time employees, including 55 employees of EDG. 334 of the EDE employees are members of Local 1474 of The
International Brotherhood of Electrical Workers (IBEW), while 28 of the EDG employees are members of Local 814 of the IBEW and 8 EDG employees are members of Local 695 of the IBEW. Locals 814 and 695
of the IBEW both ratified a new three-year contract with EDG effective at the June 1, 2006 closing. 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.

11

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ELECTRIC OPERATING STATISTICS(1)

|                                                    |                       | 2007                                 |              | 2006      |           | 2005      |           | 2004      |           | 2003      |          
|--------------------------------------------------- | --------------------- | ------------------------------------ | ------------ | --------- | --------- | --------- | --------- | --------- | --------- | --------- | ---------
|Electric Operating Revenues (000's):                |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    | Residential           |                                      | $            | 174,584   |           | $         | 159,381   |           | $         | 149,176   |          
|                                                    | Commercial            |                                      |              | 129,035   |           |           | 115,059   |           |           | 106,093   |          
|                                                    | Industrial            |                                      |              | 67,712    |           |           | 64,820    |           |           | 59,593    |          
|                                                    | Public authorities(2) |                                      |              | 9,933     |           |           | 8,892     |           |           | 8,464     |          
|                                                    | Wholesale on-system   |                                      |              | 18,444    |           |           | 17,561    |           |           | 16,582    |          
|                                                    | Miscellaneous         |                                      |              | 5,826     |           |           | 4,706     |           |           | 4,934     |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       |                                      | Total system |           |           | 405,534   |           |           | 370,419   |           |          
|                                                    | Wholesale off-system  |                                      |              | 19,627    |           |           | 12,234    |           |           | 14,139    |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total electric operating revenues(3) |              |           | 425,161   |           |           | 382,653   |           |           | 358,981  
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|Electricity generated and purchased (000's of kWh): |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    | Steam                 |                                      |              | 2,074,323 |           |           | 2,589,360 |           |           | 2,446,528 |          
|                                                    | Hydro                 |                                      |              | 71,360    |           |           | 22,673    |           |           | 62,325    |          
|                                                    | Combustion turbine    |                                      |              | 1,427,298 |           |           | 955,856   |           |           | 1,453,297 |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total generated                      |              |           | 3,572,981 |           |           | 3,567,889 |           |           | 3,962,150
|                                                    | Purchased             |                                      |              | 2,373,282 |           |           | 2,065,991 |           |           | 1,684,657 |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total generated and purchased        |              |           | 5,946,263 |           |           | 5,633,880 |           |           | 5,646,807
|Interchange (net)                                   |                       |                                      | (940         | )         |           | (173      | )         |           | (126      | )         |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total system input                   |              |           | 5,945,323 |           |           | 5,633,707 |           |           | 5,646,681
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|Maximum hourly system demand (Kw)                   |                       |                                      | 1,173,000    |           |           | 1,159,000 |           |           | 1,087,000 |           |          
|Owned capacity (end of period) (Kw)                 |                       |                                      | 1,255,000    |           |           | 1,102,000 |           |           | 1,102,000 |           |          
|Annual load factor (%)                              |                       |                                      | 53.39        |           |           | 52.50     |           |           | 55.59     |           |          
|Electric sales (000's of kWh):                      |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    | Residential           |                                      |              | 1,930,493 |           |           | 1,898,846 |           |           | 1,881,441 |          
|                                                    | Commercial            |                                      |              | 1,610,814 |           |           | 1,547,077 |           |           | 1,485,034 |          
|                                                    | Industrial            |                                      |              | 1,110,328 |           |           | 1,145,490 |           |           | 1,106,700 |          
|                                                    | Public authorities(2) |                                      |              | 115,109   |           |           | 111,204   |           |           | 111,245   |          
|                                                    | Wholesale on-system   |                                      |              | 342,347   |           |           | 337,658   |           |           | 328,803   |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total system                         |              |           | 5,109,091 |           |           | 5,040,275 |           |           | 4,913,223
|                                                    | Wholesale off-system  |                                      |              | 459,665   |           |           | 303,493   |           |           | 353,138   |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total Electric Sales                 |              |           | 5,568,756 |           |           | 5,343,768 |           |           | 5,266,361
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|Company use (000's of kWh)(4)                       |                       |                                      | 9,369        |           |           | 9,324     |           |           | 10,263    |           |          
|kWh losses (000's of kWh)(5)                        |                       |                                      | 367,198      |           |           | 280,615   |           |           | 370,157   |           |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total System Input                   |              |           | 5,945,323 |           |           | 5,633,707 |           |           | 5,646,781
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|Customers (average number):                         |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    | Residential           |                                      |              | 139,840   |           |           | 137,689   |           |           | 134,724   |          
|                                                    | Commercial            |                                      |              | 24,330    |           |           | 24,035    |           |           | 23,684    |          
|                                                    | Industrial            |                                      |              | 362       |           |           | 370       |           |           | 365       |          
|                                                    | Public authorities(2) |                                      |              | 1,927     |           |           | 1,907     |           |           | 1,837     |          
|                                                    | Wholesale on-system   |                                      |              | 4         |           |           | 4         |           |           | 4         |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total System                         |              |           | 166,463   |           |           | 164,005   |           |           | 160,614  
|                                                    | Wholesale off-system  |                                      |              | 20        |           |           | 20        |           |           | 17        |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|                                                    |                       | Total                                |              |           | 166,483   |           |           | 164,025   |           |           | 160,631  
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          
|Average annual sales per residential customer (kWh) |                       |                                      | 13,805       |           |           | 13,791    |           |           | 13,965    |           |          
|Average annual revenue per residential customer     |                       | $                                    | 1,248        |           | $         | 1,158     |           | $         | 1,107     |           | $        
|Average residential revenue per kWh                 |                       |                                      | 9.04         | ¢         |           | 8.39      | ¢         |           | 7.93      | ¢         |          
|Average commercial revenue per kWh                  |                       |                                      | 8.01         | ¢         |           | 7.44      | ¢         |           | 7.14      | ¢         |          
|Average industrial revenue per kWh                  |                       |                                      | 6.10         | ¢         |           | 5.66      | ¢         |           | 5.38      | ¢         |          
|                                                    |                       |                                      |              |           |           |           |           |           |           |           |          

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12

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GAS OPERATING STATISTICS(1)

|                                                   |                                  | 2007                         |   | 2006(2) |       
|-------------------------------------------------- | -------------------------------- | ---------------------------- | - | ------- | ------
|Gas Operating Revenues (000's):                    |                                  |                              |   |         |       
|                                                   | Residential                      |                              | $ | 39,205  |       
|                                                   | Commercial                       |                              |   | 16,588  |       
|                                                   | Industrial                       |                              |   | 752     |       
|                                                   | Public authorities               |                              |   | 373     |       
|                                                   | Miscellaneous                    |                              |   | 206     |       
|                                                   |                                  |                              |   |         |       
|                                                   |                                  | Total retail sales revenues  |   |         | 57,124
|                                                   | Transportation revenues          |                              |   | 2,753   |       
|                                                   |                                  |                              |   |         |       
|                                                   |                                  | Total Gas Operating Revenues |   |         | 59,877
|                                                   |                                  |                              |   |         |       
|Gas delivered to customers (000's of mcf sales)(3) |                                  |                              |   |         |       
|                                                   | Residential                      |                              |   | 2,835   |       
|                                                   | Commercial                       |                              |   | 1,304   |       
|                                                   | Industrial                       |                              |   | 76      |       
|                                                   | Public authorities               |                              |   | 30      |       
|                                                   |                                  |                              |   |         |       
|                                                   |                                  | Total retail sales           |   |         | 4,245 
|                                                   | Transportation sales (cash outs) |                              |   | 56      |       
|                                                   | Company use(3)                   |                              |   | 2       |       
|                                                   | Mcf losses                       |                              |   | 8       |       
|                                                   |                                  |                              |   |         |       
|                                                   |                                  | Total gas operating sales    |   |         | 4,311 
|                                                   | Transportation volume            |                              |   | 4,297   |       
|                                                   |                                  |                              |   |         |       
|                                                   |                                  | Total system volume          |   |         | 8,608 
|                                                   |                                  |                              |   |         |       
|Customers (average number):                        |                                  |                              |   |         |       
|                                                   | Residential                      |                              |   | 40,315  |       
|                                                   | Commercial                       |                              |   | 5,208   |       
|                                                   | Industrial                       |                              |   | 24      |       
|                                                   | Public authorities               |                              |   | 124     |       
|                                                   |                                  |                              |   |         |       
|                                                   |                                  | Total retail customers       |   |         | 45,671
|                                                   | Transportation customers         |                              |   | 270     |       
|                                                   |                                  |                              |   |         |       
|                                                   |                                  | Total gas customers          |   |         | 45,941
|                                                   |                                  |                              |   |         |       

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13

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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, 2007, 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
12/31/07 |  | Positions With the Company                                                                                                                                                                            |  | With the
Company Since |  | Officer
Since
|------------------ |  | --------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ---------------------- |  | -------------
|William L. Gipson  |  | 50              |  | President and Chief Executive Officer (2002), Executive Vice President and Chief Operating Officer (2001), Vice President  Commercial Operations (1997)                                              |  | 1981                   |  | 1997         
|Bradley P. Beecher |  | 42              |  | Vice President and Chief Operating Officer  Electric (2006), Vice President  Energy Supply (2001), General Manager Energy Supply (2001)                                                            |  | 2001                   |  | 2001         
|Harold Colgin      |  | 58              |  | Vice President  Energy Supply (2006), General Manager  Energy Supply (2006), Plant Manager, Asbury Plant (1995)                                                                                     |  | 1972                   |  | 2006         
|Ronald F. Gatz     |  | 57              |  | 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   |  | 56              |  | Vice President  Finance and Chief Financial Officer (2002), General Manager  Finance (2002)                                                                                                         |  | 2002                   |  | 2002         
|Michael E. Palmer  |  | 51              |  | Vice President  Commercial Operations (2001), General Manager  Commercial Operations (2001), Director of Commercial Operations (1997)                                                               |  | 1986                   |  | 2001         
|Kelly S. Walters   |  | 42              |  | 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    |  | 55              |  | Secretary  Treasurer (1995)                                                                                                                                                                          |  | 1994                   |  | 1995         
|Laurie A. Delano   |  | 52              |  | Controller, Assistant Secretary and Assistant Treasurer and Principal Accounting Officer (2005), Director of Financial Services (2002)                                                                |  | 2002                   |  | 2005         

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

14

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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
2007, approximately 90% of our electric operating revenues were received from retail customers. Approximately 89.0%, 5.5%, 2.8% and 2.7% of such retail revenues were derived from
sales in Missouri, Kansas, Oklahoma and Arkansas, respectively. Sales subject to FERC jurisdiction represented approximately 9% of our electric operating revenues during 2007 with the remaining 1%
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 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. On
July 14, 2005, Missouri Governor Blunt signed Bill SB 179 which authorizes the MPSC to grant fuel adjustment clauses for utilities in the State of Missouri. The bill became effective
January 1, 2006. We do not currently have a fuel adjustment clause in Missouri but have requested the implementation of a fuel adjustment clause as part of our current Missouri rate case.

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. 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.

We
calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the
MPSC. PGA factor elements considered include gas purchased, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

Pursuant
to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and
carrying costs associated with the use of financial instruments), are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings.

15

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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 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). The Asbury
Plant became an affected unit under the 1990 Amendments for SO2 on January 1, 1995 and for NOx as a Group 2 cyclone-fired boiler on January 1, 2000. The Iatan Plant became an
affected unit for both SO2 and NOx on January 1, 2000. The Riverton Plant became an affected unit for NOx in November 1996 and for SO2 on January 1, 2000. The State Line Plant became an
affected unit for SO2 and NOx on January 1, 2000. Units 3 and 4 at the Empire Energy Center became affected units for both SO2 and NOx in April 2003. The new Riverton Unit 12
became an affected unit in January 2007.

SO2 Emissions.Under the 1990 Amendments, the amount of SO2 an affected unit can emit is
regulated. Each existing affected unit has been awarded a specific number of emission allowances, each of which allows the holder to emit one ton of SO2. Utilities covered by the 1990 Amendments must
have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. 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 awarded to each affected unit and sells those emission allowances
through a direct auction. We receive compensation from the EPA for the sale of these withheld allowances.

Our
Asbury, Riverton (other than the gas-fired combustion turbines) and Iatan Plants 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 do not receive 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 2007, the combined actual SO2 allowance need for all affected plant facilities exceeded the number of allowances awarded to us by the EPA.
Although the actual reconciliation of SO2 allowances does not occur until March 1 of each year, we had approximately 24,000 banked SO2 allowances at December 31, 2007 as compared to
31,000 at December 31, 2006. We project that our 2008 emissions will again exceed the number of allowances awarded by the EPA. Based on current SO2 allowance usage projections, we expect to
exhaust our banked allowances by the end of 2010.

Once
our SO2 allowance bank is exhausted, we will need to purchase additional SO2 allowances or build a scrubber at our Asbury Plant. Based on current and projected SO2 allowance prices
and high-level estimated 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. In addition, projected engineering and construction timeframes for a new scrubber make it
unfeasible at this time to construct a scrubber by the end of 2010.

On
July 14, 2004, we filed an application with the MPSC seeking an order authorizing us to implement a plan for the management, sale, exchange, transfer or other disposition of
our SO2 emission allowances

16

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issued
by the EPA. On 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 swap banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances outright for monetary value.
The Stipulation and Agreement became effective March 11, 2005, although we have not yet swapped or sold any allowances. Our banked allowances are not assigned a cost value. The allowances are
removed from inventory on a FIFO basis.

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 2007, approximately 2,651
tons of TDF were burned. This is equivalent to 265,100 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. However, 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 and additional NOx controls are not required.

NOx
is further regulated as described in the Clean Air Interstate Rule below.

Clean Air Interstate Rule (CAIR)

The EPA issued its final CAIR on March 10, 2005. CAIR governs NOx and SO2 emissions from fossil fueled units greater than 25 megawatts and will
affect 28 states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Plants are located and Arkansas where the future Plum Point
Energy Station will be located. Kansas is not included in CAIR and our Riverton Plant will not be affected.

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 for approval. The Missouri SIP was approved
and became effective on December 14, 2007. We will receive our full allotment of allowances as published in the Missouri CAIR Rule. The Arkansas CAIR SIP has been approved but not finalized.
Until the Arkansas SIP is finalized by the EPA, we cannot definitively determine the allowed emissions of ozone season NOx for the Plum Point Energy Station in Arkansas. However, based on the SIP for
Missouri and the approved SIP for Arkansas, it appears 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 compared to
our non-CAIR Kansas units beginning in 2010. 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 help meet anticipated CAIR requirements and to meet air permit requirements for Iatan Unit 2, pollution control equipment is being installed on Iatan Unit 1
which will be completed around the end of 2008. This equipment includes a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a baghouse, with our share of the
capital cost estimated at $46 million, excluding AFUDC. Of this amount, approximately $3.9 million was incurred in 2006 and $12.1 million in 2007. Approximately
$26.7 million in 2008, $1.4 million in 2009 and $0.3 million in 2010 are included in our current capital expenditures budget. This project was also included as part of our
Experimental Regulatory Plan approved by the MPSC.

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Also
to help meet anticipated CAIR requirements, we constructed an SCR at Asbury during the fall of 2007 and placed it in service in early 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 also included as part of our
Experimental Regulatory Plan approved by the MPSC.

Additional
pollution control equipment to comply with CAIR may become economically justified at the Asbury Plant sometime prior to 2015 and may include an FGD scrubber to control SO2 and
a baghouse at an estimated capital cost of $100 million.

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 for Phase 1 were scheduled to go into effect January 1, 2010 and remain in effect until January 1, 2018. Beginning January 1, 2018,
more restrictive mercury emission limits were scheduled to go into effect for Phase 2 of CAMR. These regulations were challenged in the U.S. Court of Appeals for the District of Columbia
Circuit by a group of states led by New Jersey. On February 8, 2008, the Court of Appeals issued its opinion and vacated the EPA's CAMR regulations. The EPA is required to reconsider the
regulation of mercury under Section 112 of the CAA. At this point it is too early to determine the effects of this ruling.

The
CAMR was not directed to specific generation units, but instead, required the states (including Missouri, Kansas and Arkansas) to develop SIPs to comply with specific mercury
state-wide annual budgets. Missouri, Kansas and Arkansas have finalized their respective regulations and submitted their SIPs to the EPA. The proposed SIPs for all states include allowance
trading programs for mercury that could allow compliance without additional capital expenditures.

Based
on CAMR, we installed a mercury analyzer at Asbury during late 2007 and scheduled the installation of two mercury analyzers at Riverton during 2008 in order to verify our mercury
emissions and to meet the compliance date of January 1, 2009 for mercury analyzers and the Phase 1 mercury emission compliance date of January 1, 2010.

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. Several bills addressing climate change have been
introduced in the U.S. Congress and, 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. Various proposals in the U.S. Congress
could require us to purchase offsets or allowances for some or all of our CO2 emissions, or otherwise affect us based on the amount of CO2 we generate. 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.

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 State Line permit was renewed in May 2007. The Energy Center permit was renewed in September 2005 and the Asbury Plant permit was
renewed in December 2005.

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The
Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act Section 316(b) Phase II. The regulations became
final on February 16, 2004 and require the submission of a Comprehensive Demonstration Study with the permit renewal in 2008. A Proposal for Information Collection (PIC) has been approved by
the Kansas Department of Health and Environment (KDHE). Aquatic sampling commenced in April 2006 in accordance with the PIC and was completed in August 2007. Analysis of the sampling and a summary
report will be completed during the first half of 2008. On January 25, 2007, the United States Court of Appeals for the Second Circuit remanded key sections of the EPA's February 16,
2004 regulations. On July 9, 2007, the EPA suspended the regulation and is expected to revise and re-propose the regulation by December 2008. If this occurs, we will monitor the EPA
revision process and comment appropriately. Data collection and analysis will continue under the PIC and will be completed as needed to limit increased costs, if any, due to the EPA's suspension and
revision of the regulation. The permit renewal application will be prepared and submitted as scheduled following KDHE guidance. Under the initial 316(b) regulations, we did not expect costs associated
with compliance to be material. We will assess costs under revised rules when they are complete.

Other.Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the
authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site's total 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 MDNR issues the renewed permits. A Compliance
Assurance Monitoring (CAM) plan is required by the renewed permit for Asbury. We estimate that the capital costs associated with the CAM plan will not exceed $2 million.

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 completed, currently estimated to be late in the fourth quarter of 2008.

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 is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. Site #2 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. This estimated liability 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 Statement of
Financial Accounting Standards No. 71  "Accounting for the Effects of Certain Types of Regulation" (FAS 71).

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Conditions Respecting Financing

Our EDE Indenture of Mortgage and Deed of Trust, dated as of September 1, 1944, as amended and supplemented (the EDE Mortgage), and our Restated Articles
of Incorporation (Restated Articles), specify earnings coverage and other conditions which must be complied with in connection with the issuance of additional first mortgage bonds or cumulative
preferred stock, or the incurrence of unsecured indebtedness. The EDE Mortgage contains a requirement that for new first mortgage bonds to be issued, our net earnings (as defined in the EDE Mortgage)
for any twelve consecutive months within the 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, 2007, would permit us to issue approximately $247.7 million of
new first mortgage bonds based on this test at an assumed interest rate of 6.5%. 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, 2007, we had retired bonds and net property additions which would enable the issuance of at least
$565.5 million principal amount of bonds if the annual interest requirements are met. As of December 31, 2007, we believe we are in compliance with all restrictive covenants of the EDE
Mortgage.

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

Our
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. At December 31, 2007, we had property additions of $2.5 million. 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, 2007, this test would not allow us to issue any new first mortgage bonds. However, our current financing plan does not contemplate the need for additional
EDG first mortgage bonds.

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     |  | BB+              
|Trust Preferred Securities                          |  | BBB-     |  | Baa3     |  | BB               
|Commercial Paper                                    |  | F2       |  | P-2      |  | A-3              
|Outlook                                             |  | Negative |  | Negative |  | Stable           

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. Currently, our senior unsecured debt rating from Standard & Poor's is BB+ (a non-investment grade rating). In addition, on
February 14, 2008, Moody's placed all of our ratings on review for possible downgrade. This action, as well as any actual downgrade of our commercial paper rating from Moody's, 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
higher-cost revolving credit facility.

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

We are exposed to market risk in our fuel procurement strategy and may incur losses from these activities.

We have established a risk management practice of purchasing contracts for future fuel needs to meet underlying customer needs. Within this activity, we may incur
losses from these contracts. These losses could have a material adverse effect on our results of operations.

By
using physical and financial instruments, we are exposed to credit risk and market risk. Credit risk is the risk that the counterparty might fail to fulfill its obligations under
contractual terms. Market risk is the exposure to a change in the value of commodities caused by fluctuations in market variables, such as price. The fair value of derivative financial instruments we
hold is adjusted cumulatively on a monthly basis until prescribed determination periods. At the end of each determination period, which is the last day of each calendar month in the period, any
realized gain or loss for that period related to the contract will be reclassified to fuel expense.

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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.

A combination of increases in customer demand, decreases in output from our power plants and/or the failure of performance by purchased power contract counterparties could have
a material adverse effect on our results of operations.

If demand for power increases significantly and rapidly (due to weather or other conditions) and either our power plants do not operate as planned or the parties
with which we have contracted to purchase power are not able to, or fail to, deliver that power, we would be forced to purchase power in the spot-market. Those unforeseen costs could have
a material adverse effect on our results of operations. See Item 1, "Business  Fuel and Natural Gas Supply", Item 2, "Properties  Electric Segment
Facilities" and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" for more information.

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. Weather can also impact the revenues of our natural gas utility business. 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 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. Of the factors driving expenses, fuel and
purchased power costs are our largest expense items. Increases in the price of natural gas or the cost of purchased power will result in increases in electric operating expenses. Our

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existing
strategies for mitigating such risks include hedging against changes in natural gas prices and utilizing fuel adjustment mechanisms to recover actual fuel and purchased power expenses.

Such
efforts, however, may not offset or permit us to recover all of such increased costs. Therefore, significant increases in electric operating expenses or reductions in electric
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. However, this provision only permits the recovery of "prudently incurred" costs. To the extent the MPSC determines that any of our costs were not prudently incurred, we would have to repay
any such amounts that we collected from customers as part of an annual reconciliation. 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.

Disruptions in coal deliveries could require us to reduce the output of our coal-fired generating facilities and lead to increases in our fuel and purchased power
costs.

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 increases in our fuel and purchased power costs and
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.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.    PROPERTIES

Electric Segment Facilities

At December 31, 2007, 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 2007 accounted for
approximately 30% 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 during the 2001 outage. As of September 21,
2007, the date the units went off-line to begin the five year maintenance outage, Unit No. 2 had operated approximately 2,489 hours since its last turbine inspection in 2001.
When the Asbury Plant is out of service, we typically experience increased purchased power and fuel costs associated with replacement energy.

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. 7
was taken out of service from October 1, 2005 to November 4, 2005 for its five-year scheduled maintenance outage. Unit No. 8 was taken out of service from
February 14, 2003 to May 14, 2003 for its scheduled five-year maintenance outage as well as to make necessary repairs to a high-pressure cylinder. 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. Iatan 1 underwent a planned maintenance and turbine inspection from January 6, 2007
through February 23, 2007. 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 completed, currently estimated to be late in the fourth quarter of 2008. 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 and Aquila own 70% and 18%, respectively, of the Unit. KCP&L operates the unit for the joint owners. On
June 13, 2006, we 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 new 850-megawatt unit to be operated by KCP&L and located at the site of the existing Iatan Generating Station.

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

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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 January 7, 2004, one of the original combustion turbine peaking units, Unit No. 2,
experienced a rotating blade failure. Upon dismantling and inspecting the unit, we found damage to rotating and stationary components in the turbine, as well as anomalies in the generator. We incurred
$4.1 million of insurable costs to repair this
facility, including a $1 million insurance deductible we expensed in the first quarter of 2004 related to this damage. We received all of the remaining $3.1 million from our insurer as
of June 30, 2005. 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, located on the White River at Ozark Beach, Missouri, has a generating capacity of 16 megawatts. We replaced two of the four water wheels at our
hydroelectric plant in 2003, the third wheel in early 2004 and the fourth and final wheel in March 2005. 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. We expect that the Army Corp of Engineers will not implement the new minimum flow plan until at least 2009, but, at this time, we cannot be sure of the timetable. 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 us, in coordination with our relevant public service
commissions and the Southwest Power Administration (SWPA), to determine our economic detriment. The SWPA published their estimate of our damages in the Federal Register on February 5, 2008 with
comments open until March 6, 2008. We expect the process for reaching agreement on our economic harm to be completed in 2008 or 2009, but cannot predict the outcome at this time.

At
December 31, 2007, 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 6,785 miles of line.

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

We
also own and operate water pumping facilities and distribution systems consisting of a total of approximately 86 miles of water mains in three communities in Missouri.

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Gas Segment Facilities

At December 31, 2007, our principal gas utility properties consisted of approximately 87 miles of transmission mains and approximately
1,110 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.

26

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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 15, 2007, there were 5,298 record holders and 27,830 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 2007 and 2006 were as follows:

|               |  | Price of Common Stock |       |  |   |      
|-------------- |  | --------------------- | ----- |  | - | -----
|
|
|
|First Quarter  |  | $                     | 26.11 |  | $ | 23.07
|Second Quarter |  |                       | 26.13 |  |   | 21.99
|Third Quarter  |  |                       | 24.29 |  |   | 21.09
|Fourth Quarter |  |                       | 24.34 |  |   | 22.22

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, 2007, our retained earnings balance was
$17.2 million (compared to $22.9 million at December 31, 2006) after paying out $39.0 million in dividends during 2007. 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 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. As of December 31, 2007, our level of retained earnings did not prevent us from issuing dividends. Absent an amendment to the EDE Mortgage, we may not have sufficient
earned surplus to pay our next quarterly dividend at the rate of $0.32 per share. As a result, we have commenced a consent solicitation to amend the EDE Mortgage to increase the earned surplus basket
under the EDE Mortgage by $10.75 million. We believe that the consent solicitation, which is scheduled to expire on March 11, 2008, will be successful. However, we can give no assurance
that this will be the case.

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, 2007, there were no
such restrictions on our ability to pay dividends.

27

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During
2007, no purchases of our common stock were made by or on behalf of us.

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

Our
shareholders rights plan 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, 2002, 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.

TOTAL RETURN TO STOCKHOLDERS
(Assumes $100 investment on 12/31/02)

GRAPHIC

|Total Return Analysis                |  | 12/31/2002 |        | 12/31/2003 |   | 12/31/2004 |  | 12/31/2005 |        | 12/31/2006 |   | 12/31/2007
|------------------------------------ |  | ---------- | ------ | ---------- | - | ---------- |  | ---------- | ------ | ---------- | - | ----------
|The Empire District Electric Company |  | $          | 100.00 |            | $ | 128.30     |  | $          | 140.81 |            | $ | 133.60    
|S&P Electric Utilities Index         |  | $          | 100.00 |            | $ | 123.81     |  | $          | 156.57 |            | $ | 184.16    
|S&P 500 Index                        |  | $          | 100.00 |            | $ | 128.63     |  | $          | 142.59 |            | $ | 149.58    

28

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

|                                                                                                   |                | 2007 |           | 2006(2) |   | 2005      |         | 2004 |           | 2003    |  
|-------------------------------------------------------------------------------------------------- | -------------- | ---- | --------- | ------- | - | --------- | ------- | ---- | --------- | ------- | -
|Operating revenues                                                                                 |                | $    | 490,160   |         | $ | 412,171   |         | $    | 362,720   |         | $
|Operating income                                                                                   |                | $    | 65,566    |         | $ | 69,821    |         | $    | 53,920    |         | $
|Total allowance for funds used during construction                                                 |                | $    | 7,665     |         | $ | 4,255     |         | $    | 561       |         | $
|Income from continuing operations                                                                  |                | $    | 33,181    |         | $ | 40,029    |         | $    | 24,944    |         | $
|Income (loss) from discontinued operations, net of tax                                             |                | $    | 63        |         | $ | (749      | )       | $    | (1,176    | )       | $
|Net income                                                                                         |                | $    | 33,244    |         | $ | 39,280    |         | $    | 23,768    |         | $
|Weighted average number of common shares outstanding  basic                                       |                |      | 30,587    |         |   | 28,277    |         |      | 25,898    |         |  
|Weighted average number of common shares outstanding  diluted                                     |                |      | 30,610    |         |   | 28,296    |         |      | 25,941    |         |  
|Earnings from continuing operations per weighted average share of common stock  basic and diluted |                | $    | 1.09      |         | $ | 1.42      |         | $    | 0.96      |         | $
|Loss from discontinued operations per weighted average share of common stock  basic and diluted   |                | $    | 0.00      |         | $ | (0.03     | )       | $    | (0.04     | )       | $
|Total earnings per weighted average share of common stock  basic and diluted                      |                | $    | 1.09      |         | $ | 1.39      |         | $    | 0.92      |         | $
|Cash dividends per share                                                                           |                | $    | 1.28      |         | $ | 1.28      |         | $    | 1.28      |         | $
|Common dividends paid as a percentage of net income                                                |                |      | 117.2     | %       |   | 91.8      | %       |      | 139.5     | %       |  
|Allowance for funds used during construction as a percentage of net income                         |                |      | 23.1      | %       |   | 10.8      | %       |      | 2.4       | %       |  
|Book value per common share (actual) outstanding at end of year                                    |                | $    | 16.04     |         | $ | 15.49     |         | $    | 15.08     |         | $
|Capitalization:                                                                                    |                |      |           |         |   |           |         |      |           |         |  
|                                                                                                   | Common equity  |      | $         | 539,176 |   | $         | 468,609 |      | $         | 393,411 |  
|                                                                                                   | Long-term debt |      | $         | 541,880 |   | $         | 462,398 |      | $         | 407,786 |  
|Ratio of earnings to fixed charges                                                                 |                |      | 1.98x     |         |   | 2.60x     |         |      | 2.21x     |         |  
|Total assets(3)                                                                                    |                | $    | 1,471,750 |         | $ | 1,319,142 |         | $    | 1,122,030 |         | $
|Plant in service at original cost                                                                  |                | $    | 1,500,640 |         | $ | 1,374,837 |         | $    | 1,282,123 |         | $
|Capital expenditures (including AFUDC)(4)                                                          |                | $    | 195,568   |         | $ | 120,171   |         | $    | 73,232    |         | $

---

29

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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
our fiber optics business. During the twelve months ended December 31, 2007, 87.1% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the
sale of water), 12.2% from the sale of gas and 0.7% from our non-regulated businesses.

In
August 2006, we sold our controlling 52% interest in Mid-America Precision Products (MAPP), which specialized in close-tolerance custom manufacturing. 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. For financial reporting purposes, MAPP, Conversant and Fast Freedom, all of which were formerly within our other segment, have
been classified as discontinued operations and are not included in our segment information.

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 1.4% to 1.6% over the next several years. Our electric customer growth for the twelve months ended December 31, 2007 was 1.1%. 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. Fuel and purchased power costs are our largest
expense items. Several factors affect these costs, including fuel and purchased power prices, plant outages and weather, which drives customer demand. In order to control the price we pay for fuel for
electric generation and purchased power, we have entered into long and short-term agreements to purchase power (including wind energy) and coal and natural gas for our energy supply. We
currently engage in hedging activities in an effort to minimize our risk from volatile natural gas prices.

30

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Gas Segment

The primary drivers of our gas operating revenues in any period are: (1) rates we can charge our customers, (2) weather, (3) customer growth,
(4) the cost of natural gas and interstate pipeline transportation charges and (5) general economic conditions. The MPSC sets the rates which we can charge our customers. In order to
offset expenses, we depend on our ability to receive adequate and timely recovery of our costs (primarily commodity natural gas) and/or rate relief. We assess the need for rate relief and file for
such relief when necessary. 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, 2007 was (2.2)%, which we
believe was due to higher gas prices and general economic conditions. We expect our annual gas customer growth to be up to 1% over the next several years. 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 causes customers to reduce usage.

Earnings

For the twelve months ended December 31, 2007, basic and diluted earnings per weighted average share of common stock were $1.09 compared to $1.39 for the
twelve months ended December 31, 2006. As reflected in the table below, the primary positive drivers were increased electric and gas revenues. This was offset, however, by higher fuel and
purchased power costs resulting primarily from the Asbury outage and from higher maintenance and repairs expense resulting from the ice storms discussed below.

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The
following reconciliation of basic earnings per share between 2006 and 2007 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, 2006 and 2007 shown in the reconciliation are presented on a
GAAP basis and are the same as the amounts included 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  2006*

$
1.39RevenuesElectric on-system

$
0.77Electric off-system and other


0.19Gas


0.78Water


Non-regulated


0.02ExpensesElectric fuel


(0.44
)Purchased power


(0.26
)Cost of natural gas sold and transported


(0.50
)Regulated  electric segment


(0.16
)Regulated  gas segment


(0.10
)Non-regulated


(0.01
)Maintenance and repairs


(0.20
)Depreciation and amortization


(0.32
)Other taxes


(0.09
)Interest charges


(0.13
)AFUDC


0.08Discontinued operations


0.03Loss on plant disallowance


0.02Gain on sale of assets


0.03Change in effective income tax rates


0.08Other income and deductions


(0.02
)Dilutive effect of additional shares issued


(0.07
)Earnings Per Share  2007

$
1.09




Fourth Quarter Results

In the fourth quarter of 2007, we experienced a net loss of $0.4 million, or ($0.01) per share compared to fourth quarter 2006 earnings of
$8.2 million, or $0.27 per share. Total revenues increased approximately $8.5 million (8.0%) for the fourth quarter of 2007 as compared to the fourth quarter of 2006 primarily due to the
Missouri rate increase. However, this was offset by increased operating expenses, including increased fuel and purchased power costs (approximately $17.5 million) primarily relating to the
Asbury outage, depreciation expense (approximately $3.5 million) and other operating and maintenance costs (approximately $3.0 million, of which $1.5 million consisted of December
ice storm expense).

32

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2007 Activities

Asbury SCR and Maintenance Outage

In order to help meet CAIR requirements, we constructed an SCR at Asbury during the fall of 2007 and placed it in service in early February 2008. This was
combined with our five year Asbury maintenance project. 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 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. In addition, as a result of the extended outage at Asbury into the first quarter of 2008, we expect that our earnings for the first
quarter will be negatively impacted compared to earnings in the first quarter of 2007. We had to replace 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. We had originally estimated that this would increase our expenses approximately $79 million in the fourth
quarter of 2007 as compared to the fourth quarter of 2006 due to the original extended outage. We then estimated that during the additional 60 day outage we would incur approximately
$810 million in additional replacement energy costs. After assessing the actual cost of the incremental purchased power and gas-fired generation, we estimate the
planned outage added incremental expenses for the fourth quarter of approximately $8.7 million. We estimate the extended outage (December 8December 31, 2007)
increased expenses an additional $3.5 million.

2007 Ice Storms

A major winter storm system that brought sleet and freezing rain to a large portion of our service area December 911, 2007 left approximately
65,000 (40%) of our electric customers without power. Costs associated with the restoration effort due to this ice storm were approximately $18.6 million, of which approximately
$9.2 million was capitalized as additions to our utility plant, approximately $1.5 million was recorded as maintenance expense and approximately $7.9 million was deferred as a
regulatory asset, as we believe it is probable that these costs will be recoverable in future electric rate cases.

A
major ice storm also struck virtually all areas of our electric service territory January 1214, 2007 causing substantial damage. Approximately 85,000 (52%) of our
electric customers were without power at the height of the storm. Costs associated with the restoration effort due to the ice storm were approximately $30.7 million, of which
$19.2 million has been capitalized as additions to our utility plant, approximately $3.9 million recorded as maintenance expense and approximately $7.6 million was deferred as a
regulatory asset as we believe it is probable that these costs will be recoverable in future electric rate cases.

Financing

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, EDE issued $80 million principal amount of First Mortgage Bonds, 5.875% Series due 2037. The net proceeds of $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.

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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%. This request is to allow us to recover 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 2007 ice storms and other changes in our
underlying costs. We are also requesting implementation of a fuel adjustment clause in Missouri which would permit the distribution to Missouri customers of changes in fuel and purchased power costs.

On
December 29, 2006, the Office of Public Counsel (OPC) and intervenors Praxair, Inc. and Explorer Pipeline Company, filed an application with the MPSC requesting the MPSC
grant a rehearing on most of the issues addressed in the December 2006 Missouri rate case order and many of the procedural issues. On December 29, 2006, we also filed an application with the
MPSC requesting a rehearing on return on equity, capital structure and energy cost recovery. A decision by the MPSC is pending.

Praxair
and Explorer Pipeline filed a Petition for Writ of Review with the Cole County Circuit Court on January 31, 2007. The Circuit Court issued a Writ, but the MPSC moved to
have the Writ set aside on the basis that it was issued prematurely. On March 20, 2007, Praxair and Explorer filed a motion in
the Circuit Court writ proceeding requesting an immediate stay of the effectiveness of our December 2006 Missouri rate case order and the tariffs filed pursuant thereto. Without an order being issued
on the stay motion, pursuant to an agreement of the parties, the Circuit Court set aside the Writ and dismissed the case.

On
January 4, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Court of Appeals, Western District, seeking to have the order approving tariffs issued by the
MPSC on December 29, 2006, set aside. On March 12, 2007, the Court of Appeals issued an order denying the OPC's petition.

On
March 19, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Supreme Court seeking an order requiring the MPSC to vacate and rescind its December 29,
2006 order approving tariffs and directing the MPSC to provide an effective date for any subsequent tariff approval order that allows at least ten days to prepare and file an application for
rehearing. On May 1, 2007, the Missouri Supreme Court issued a preliminary writ directing the MPSC to respond to the OPC's petition. Following briefs and oral argument, on October 30,
2007, the Supreme Court made its preliminary writ peremptory and issued an opinion directing the MPSC to vacate its December 29 order approving tariffs and allow the Public Counsel a reasonable
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 December 29, 2006 order approving tariffs, and
considered only the timing of the issuance of the order. The Court also did not consider the underlying tariffed rates which continue in force and in effect. Acting upon this opinion, 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 an application with the MPSC requesting the MPSC grant a rehearing on the December 4, 2007 order. All
applications for rehearing remain pending before the MPSC.

We
have filed applications for Accounting Authority Orders in Oklahoma and Kansas respecting costs incurred due to the 2007 ice storms.

For
additional information, see "Rate Matters" below.

Energy Supply

On June 25, 2007, we entered into a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy,
Houston, Texas. The agreement provides for a 20-year

34

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term
commencing with the commercial operation date, which is expected to be during December 2008. We will begin taking delivery of the energy at that time. Pursuant to the terms of the agreement, we
will purchase all of the output from the approximately 105-megawatt Phase 1 Meridian Way Wind Farm located in Cloud County, Kansas and owned by Cloud County Windfarm, LLC. We
do not own any portion of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a
20-year average cost.

As
of April 10, 2007, our new Siemens V84.3A2 combustion turbine, Unit 12 at our Riverton plant, began commercial operation. Riverton Unit 12 has a summer rated
capacity of 150 megawatts, increasing our Riverton Plant's total generating capacity to 286 megawatts.

Union Agreement

At April 30, 2007, we had 702 full-time employees, including 54 employees of EDG. 326 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.

BPU Contract

In May 2007, we entered into a contract with Kansas City Kansas Board of Public Utilities (BPU) for the sale of energy and capacity for June through September of
2007 and 2008. Capacity revenue will total approximately $1.3 million each year with the energy portion dependent upon the number of hours the contract is utilized by BPU. 2007 revenues from
the BPU contract were approximately $1.8 million.

Non-Regulated Businesses

On September 28, 2007, we sold our 100% interest in Fast Freedom, Inc., an Internet service provider. For financial reporting purposes, this
business has been classified as a discontinued operation and is not included in our segment information. Our gain on the disposal of Fast Freedom was $0.2 million.

RESULTS OF OPERATIONS

The following discussion analyzes significant changes in the results of operations for the years 2007, 2006 and 2005. The following table represents our results
of operations by operating segment for the applicable periods ended December 31:

|(in millions)                           |          | 2007 |      | 2006 |   | 2005 |     
|--------------------------------------- | -------- | ---- | ---- | ---- | - | ---- | ----
|Income from continuing operations:      |          |      |      |      |   |      |     
|                                        | Electric |      | $    | 31.8 |   | $    | 40.9
|                                        | Gas      |      |      | 1.0  |   |      | (1.0
|                                        | Other    |      |      | 0.4  |   |      | 0.1 
|                                        |          |      |      |      |   |      |     
|Total income from continuing operations |          | $    | 33.2 |      | $ | 40.0 |     
|Loss from discontinued operations       |          |      |     |      |   | (0.7 | )   
|                                        |          |      |      |      |   |      |     
|Net income                              |          | $    | 33.2 |      | $ | 39.3 |     
|                                        |          |      |      |      |   |      |     

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Electric Segment

Overview

Our electric segment income from continuing operations for 2007 was $31.8 million as compared to $40.9 million for 2006.

Electric
operating revenues comprised approximately 86.7% of our total operating revenues during 2007. Of these total electric operating revenues, approximately 41.1% were from
residential customers, 30.4% from commercial customers, 15.9% from industrial customers 4.3% from wholesale on-system customers, 4.6% from wholesale off-system transactions and
3.7% from miscellaneous sources, primarily transmission services. The breakdown of our electric customer classes has not significantly changed from 2006 or 2005.

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

|                    |  | kWh Sales
(in millions) |        
|------------------- |  | ----------------------- | -------
|
|
|Residential         |  |                         | 1,930.5
|Commercial          |  |                         | 1,610.8
|Industrial          |  |                         | 1,110.3
|Wholesale on-system |  |                         | 342.3  
|Other**             |  |                         | 116.8  
|                    |  |                         |        
|Total on-system     |  |                         | 5,110.7
|
|
|Residential         |  | $                       | 174.6  
|Commercial          |  |                         | 129.0  
|Industrial          |  |                         | 67.7   
|Wholesale on-system |  |                         | 18.4   
|Other**             |  |                         | 10.1   
|                    |  |                         |        
|Total on-system     |  | $                       | 399.8  

---

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

36

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2006
and $8.6 million of IEC collected in 2006, neither of which reoccurred in 2007. We expect our annual customer growth to range from approximately 1.4% to 1.6% over the next several years.

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 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. See " Competition" below. The following table sets forth information regarding these sales and related expenses for the years ended
December 31:

(in millions)

2007

2006Revenues

$
22.5

$
14.4Expenses


15.8


10.4Net

$
6.7

$
4.0


Revenues less expenses increased during 2007 as compared to 2006 primarily due to sales facilitated by the SPP Energy Imbalance Services (EIS) market that began
on February 1, 2007. Sales from this market contributed $8.8 million to our off-system electric revenues during 2007 with $6.2 million of related expense. In addition,
sales from the BPU contract contributed approximately $1.8 million to revenues. Total purchase power related expenses are included in our discussion of purchased power costs below.

Operating Revenue Deductions

During 2007, total electric segment operating expenses increased approximately $50.3 million (15.9%) compared to 2006. Total fuel costs increased
approximately $19.6 million (20.9%) during 2007 while purchased power costs increased approximately $11.3 million (17.1%), resulting in a total increase of $30.9 million for fuel
and purchased power. The increase in fuel costs was primarily due to increased generation by our gas fired units during 2007 as compared to 2006 (an estimated $28.7 million). This increase in
gas-fired generation was mainly due to 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. Lower prices for both the hedged and unhedged natural gas that we burned in our gas-fired units in 2007 reduced fuel prices an
estimated $3.6 million. Decreased generation from coal reduced costs approximately $7.3 million (mainly due to the Asbury outage), partially offset by increased coal prices in 2007 which
contributed approximately $1.6 million to fuel expense. The increase in purchased power costs primarily reflected our increased purchases on the spot market for replacement energy in the fourth
quarter due to the extended Asbury outage and in the second quarter due to the Iatan outage. 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 of approximately $8.7 million and the extended outage (December 8December 31,
2007) increased expenses an additional $3.5 million.

37

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Regulated 
other 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 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
January 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.

2006 Compared to 2005

Operating Revenues and Kilowatt-Hour Sales

KWh sales for our on-system customers increased approximately 2.6% during 2006 as compared to 2005 primarily due to continued sales growth. Revenues
for our on-system customers increased approximately $25.8 million, or 7.6%. The January 2006 Kansas rate increase, March 2005 Missouri rate increase and May 2005 Arkansas rate
increase (discussed below) contributed an estimated $13.8 million to revenues in 2006 while continued sales growth contributed an estimated $6.9 million. Additionally, revisions to our
estimate of unbilled revenues contributed $5.9 million to revenues in 2006. Weather and other factors had a negative impact of an estimated $2.8 million despite our setting a new record
summer peak of 1,159 megawatts on July 19, 2006. The collected IEC, which was not refunded pursuant to the

38

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December 21,
2006 order from the MPSC, contributed approximately $2.0 million more during 2006. Our customer growth was 2.1% in 2006 compared to 1.9% in 2005.

Residential
and commercial kWh sales increased in 2006 primarily due to the strong sales growth and the increase from our revisions to our estimate of unbilled revenues while the
associated revenues also increased due to the Missouri, Arkansas and Kansas rate increases. Industrial kWh sales increased 3.5% while revenues increased 8.8%, reflecting the increased sales growth and
the aforementioned rate increases. 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. See
" Competition" below. The following table sets forth information regarding these sales and related expenses for the years ended December 31:

(in millions)

2006

2005Revenues

$
14.4

$
16.9Expenses


10.4


12.0Net

$
4.0

$
4.9


Revenues less expenses decreased during 2006 as compared to 2005 due to decreased market demand resulting from mild weather in the first quarter of 2006 as well
as less market demand for gas-fired energy in the third quarter of 2006 as compared to the third quarter of 2005 when there was a shortage of available coal-fired generation on
the open market. Companies that normally would have coal-fired energy to sell in the market were not doing so due to coal shortages, pushing demand onto the gas-fired units.
The related expenses are included in our discussions of purchased power costs below.

Operating Revenue Deductions

During 2006, total electric segment operating expenses increased approximately $10.1 million (3.3%) compared to 2005. Total fuel costs decreased
approximately $18.8 million (16.7%) during 2006 partially offset by increased purchased power costs of approximately $13.6 million (25.8%), resulting in a net decrease of
$5.2 million for fuel and purchased power. The decrease in fuel costs was primarily due to decreased generation by our gas fired units during 2006 as compared to 2005 (an estimated
$25.6 million), partially offset by higher prices for both hedged and unhedged natural gas that we burned in our gas-fired units in 2006 (an estimated $4.4 million). In
addition, in 2005 we recognized a $5 million one-time pre-tax gain from unwinding part of a physical purchase of natural gas for the 2009 through 2011 period as part of
our fuel management process. This gain was recognized in the third quarter of 2005 as a decrease to fuel expense. Increased coal costs contributed approximately $2.4 million to total fuel costs
in 2006 and increased coal generation added approximately $2.0 million. A decrease in fuel oil generation decreased fuel costs approximately $2.0 million. The increase in purchased power
costs primarily reflected our increased
purchases from the Elk River Windfarm, LLC and also reflected a February 2006 outage at our Asbury Plant.

Regulated 
other operating expenses for our electric segment increased approximately $0.4 million (0.7%) during 2006 as compared to 2005 primarily due to
increases of $0.7 million in professional services expense, $0.6 million in general labor costs and $0.5 million in customer assistance expense, partially offset by a
$1.5 million decrease in employee health care costs. We began deferring a portion of our pension cost into a regulatory asset effective with the second quarter of 2005, as authorized in our
2005 Missouri rate case. We had deferred approximately $2.4 million as of December 31, 2006. See Note 4 of "Notes to

39

---



Consolidated
Financial Statements" under Item 8 for further discussion regarding our regulatory treatment of pension and post-retirement benefit plans.

Maintenance
and repairs expense increased approximately $1.2 million (5.7%) during 2006 as compared to 2005 primarily reflecting increases of approximately $1.5 million in
distribution maintenance costs and $1.4 million in maintenance costs for our gas-fired units, partially offset by a decrease of approximately $1.5 million in maintenance
costs for our coal-fired units. The $1.4 million increase in maintenance for our gas-fired units consisted mainly of a $1.5 million increase in maintenance for
our SLCC Plant related to the spring 2006 maintenance outage and a $0.4 million increase in maintenance at our State Line Unit 1 Plant, which had its first major inspection from
September 7, 2006 until December 20, 2006. These increases were partially offset by a $0.5 million decrease in maintenance during 2006 at the Empire Energy Center related to
generator repairs in the second quarter of 2005. The $1.5 million decrease in maintenance costs for our coal-fired units consisted mainly of a $0.9 million decrease in
maintenance costs at our Riverton Plant and a $0.5 million decrease in maintenance costs at our Iatan Plant related to 2005 outages. In our 2006 Missouri rate case Stipulation and Agreement as
to Certain Issues, approved December 21, 2006, we agreed to a disallowance for regulatory purposes of the Missouri jurisdictional portion of $1 million of our Energy Center
Units 3 and 4 costs recorded in plant in service, which would not be afforded rate recovery in Missouri rates. In accordance with FAS 71, we reduced the capitalized value of our Energy
Center Units 3 and 4 by recording a charge to expense in 2006 for $0.8 million, which represents the Missouri jurisdictional portion of these capitalized costs.

Depreciation
and amortization expense increased approximately $2.6 million (7.6%) during 2006 primarily due to higher depreciation rates that became effective on March 27,
2005 and increased plant in service. Other taxes increased approximately $0.5 million (2.5%) during 2006 due to increased property taxes reflecting our additions to plant in service and
increased municipal franchise taxes.

Gas Segment

Operating Revenues and Sales

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). The winter months are high sales months for the natural gas business, whose heating season runs from November to March of each
year.

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

Total Gas Delivered to Customers  bcf Sales*

|                           |  | 2007 |  | 2006**
|-------------------------- |  | ---- |  | ------
|Residential                |  | 2.83 |  | 1.10  
|Commercial                 |  | 1.30 |  | 0.56  
|Industrial                 |  | 0.08 |  | 0.03  
|Public authorities         |  | 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  

---

40

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Operating Revenues ($ in millions)*

|                             |  | 2007 |      | 2006**
|---------------------------- |  | ---- | ---- | ------
|Residential                  |  | $    | 39.2 |       
|Commercial                   |  |      | 16.6 |       
|Industrial                   |  |      | 0.7  |       
|Public authorities           |  |      | 0.4  |       
|                             |  |      |      |       
|Total retail sales revenues  |  | $    | 56.9 |       
|Transportation revenues      |  |      | 2.8  |       
|                             |  |      |      |       
|Total gas operating revenues |  | $    | 59.7 |       
|                             |  |      |      |       

---

Operating Revenue Deductions

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. The cost of natural gas tends to vary with changing sales requirements and unit cost of
natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on income. Our Purchased Gas
Adjustment (PGA) Clause allows us to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies, including costs, cost reductions, and related carrying costs
associated with the use of financial instruments to hedge the purchase price of natural gas.

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.

Other Segment

Our other segment includes 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 remaining non-regulated businesses for the applicable periods ended
December 31:

(in millions)

2007

2006

2005Revenues

$
3.7

$
2.9

$
2.7Expenses


3.3


2.8


2.6Net income from continuing operations

$
0.4

$
0.1

$
0.1


41

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Consolidated Company

Income Taxes

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 decreased income, as well as an increase
in equity AFUDC, Medicare Part D tax benefits and increased cost of removal resulting from the January 2007 ice storm.

Our
consolidated provision for income taxes increased approximately $9.3 million during 2006 as compared to 2005. Our consolidated effective federal and state income tax rate for
2006 was 35.3% as compared to 33.4% for 2005. The increase in the effective tax rate for 2006 compared to 2005 was mainly due to increased income.

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 $3.4 million in 2007 as compared to 2006 and increased $3.7 million in 2006 as
compared to 2005 due to higher levels of construction in each period. See Note 1 of "Notes to Consolidated Financial Statements" under Item 8.

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, the proceeds of which 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. 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. Total interest charges on long-term debt increased $2.0 million (8.4%) in 2006 as compared to 2005 reflecting interest on the first
mortgage bonds issued June 1, 2006 by EDG. See " Liquidity and Capital Resources" for further information. Short-term
debt interest increased $0.7 million during 2007 as compared to 2006 and increased $2.1 million during 2006 as compared to 2005, reflecting increased usage of short-term debt
in each period.

Losses
from discontinued operations were approximately $0.7 million and $1.2 million in 2006 and 2005, respectively, which reflected the sales of Fast Freedom in 2007 and
MAPP and Conversant in 2006. There was a slight gain from discontinued operations in 2007 of less than $0.1 million.

Other Comprehensive Income

The change in the fair value of the effective portion of our open gas contracts designated as cashflow hedges 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. 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, or interest expense, in the periods in
which the hedged transaction is actually realized or no longer qualifies for hedge accounting.

The
following table sets forth the pre-tax gains/(losses) of our natural gas contracts and interest rate contracts for our electric segment that have settled and been
reclassified, the pre-tax change in the fair

42

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market
value (FMV) of our open contracts and the tax effect in Other Comprehensive Income (OCI) for the presented periods ended December 31:

|(in millions)                                      |                                       | 2007 |      | 2006 |   | 2005  |      
|-------------------------------------------------- | ------------------------------------- | ---- | ---- | ---- | - | ----- | -----
|Natural gas contracts settled(1)                   |                                       | $    | (1.6 | )    | $ | (1.3  | )    
|Interest rate contracts settled                    |                                       |      |     |      |   |      |      
|                                                   |                                       |      |      |      |   |       |      
|                                                   | Total contracts settled               |      | $    | (1.6 | ) | $     | (1.3 
|Change in FMV of open contracts for natural gas    |                                       | $    | 5.2  |      | $ | (13.6 | )    
|Change in FMV of open contracts for interest rates |                                       |      |     |      |   |      |      
|                                                   |                                       |      |      |      |   |       |      
|                                                   | Total change in FMV of open contracts |      | $    | 5.2  |   | $     | (13.6
|                                                   |                                       |      |      |      |   |       |      
|Taxes  natural gas                                |                                       | $    | (1.4 | )    | $ | 5.7   |      
|                                                   |                                       |      |      |      |   |       |      
|Total taxes                                        |                                       | $    | (1.4 | )    | $ | 5.7   |      
|                                                   |                                       |      |      |      |   |       |      
|Total change in OCI  net of tax                   |                                       | $    | 2.2  |      | $ | (9.2  | )    
|                                                   |                                       |      |      |      |   |       |      

---

Our
average cost for our open financial natural gas hedges was $5.460/Dth at December 31, 2007, $4.805/Dth at December 31, 2006 and $4.744/Dth at December 31, 2005
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.

We
had entered into an interest rate derivative contract in May 2005 to hedge against the risk of a rise in interest rates impacting our 5.8% Senior Notes due 2035 prior to their
issuance on June 27, 2005. Costs associated with the interest rate derivative (primarily due to interest rate fluctuations) amounted to approximately $1.4 million and were recorded as a
regulatory asset and are being amortized over the life of the 2035 Notes. The $1.2 million redemption premium paid in connection with the redemption of the $30 million aggregate
principal amount of our First Mortgage Bonds, 7.75% Series due 2025 redeemed in June 2005, together with $2.4 million of remaining unamortized loss on reacquired debt and $0.3 million of
unamortized debt expense, were recorded as a regulatory asset and are being amortized as interest expense over the life of the 2035 Notes. See Note 7 of "Notes to Consolidated Financial
Statements" under Item 8. We had no interest rate derivative contracts in 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 gain of approximately $1.3 million after taxes, which will be recorded in the Statement of Income in the first
quarter of 2008.

43

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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, 2005:

|Jurisdiction        |  | Date
Requested   |  | Annual
Increase
Granted |            | Percent
Increase
Granted |       | Date
Effective
|------------------- |  | ---------------- |  | ----------------------- | ---------- | ------------------------ | ----- | --------------
|Missouri  Electric |  | February 1, 2006 |  | $                       | 29,369,397 |                          | 9.96  | %             
|Missouri  Water    |  | June 24, 2005    |  |                         | 469,000    |                          | 35.90 | %             
|Kansas  Electric   |  | April 29, 2005   |  |                         | 2,150,000  |                          | 12.67 | %             
|Arkansas  Electric |  | July 14, 2004    |  |                         | 595,000    |                          | 7.66  | %             
|Missouri  Electric |  | April 30, 2004   |  |                         | 25,705,500 |                          | 9.96  | %             

Missouri

On April 30, 2004, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294,
or 14.82%. On December 22, 2004, we, the MPSC Staff, the Office of the Public Counsel (OPC) and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC
settling several issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above or below the amount
included in this rate case as a regulatory asset or
liability. The amount of pension cost allowed in this rate case was approximately $3.0 million. This stipulation became effective on March 27, 2005 as part of the final Missouri order
described below. Therefore, the deferral of these costs began in the second quarter of 2005.

The
MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25,705,500, or 9.96%, effective March 27, 2005. The order
granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates included a cost of removal
component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual Interim Energy Charge (IEC) of approximately $8.2 million effective
March 27, 2005 and expiring three years later. The IEC was $0.002131 per kilowatt hour of customer usage. The MPSC allowed us to use forecasted fuel costs rather than the traditional historical
costs in determining the fuel portion of the rate increase. At the end of two years, an assessment would be made of the money collected from customers compared to the greater of the actual and
prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts was greater than $10 million, the
excess over $10 million would be refunded to the customers. The entire excess amount of IEC, not previously refunded, would be refunded at the end of three years, unless the IEC was terminated
earlier. Each refund was to include interest at the current prime rate at the time of the refund. The IEC revenues recorded since the inception of the IEC did not recover all the Missouri related fuel
and purchased power costs incurred during that period. From inception of the IEC through December 31, 2006, the costs of fuel and purchased power were approximately $22.3 million higher
than the total of the costs in our base rates and the IEC recorded during the period, therefore, no provision for refund was recorded.

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 $29,513,713, or 9.63%. We also
requested transition from the IEC from an earlier case to Missouri's new fuel adjustment mechanism. The MPSC issued an order May 2, 2006, however, ruling that we may have the option of
requesting that the IEC be terminated, but we may

44

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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
$29,369,397 (including regulatory amortization), or 9.96%, with an effective date of January 1, 2007 and eliminating the IEC. Pursuant to this order, the collected IEC 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. Of the increase, approximately $19 million was granted in
the form of base rates, with the remainder of approximately $10.4 million granted as regulatory amortization 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. 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 March 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 cost of our Energy Center 2 construction project. The Missouri jurisdictional portion of this agreement resulted in a pre
tax write off of $0.8 million in the fourth quarter of 2006.

On
December 29, 2006, the Office of Public Counsel (OPC) and intervenors Praxair, Inc. and Explorer Pipeline Company, filed an application with the MPSC requesting the MPSC
grant a rehearing on most of the issues addressed in the December 2006 Missouri rate case order and many of the procedural issues. On December 29, 2006, we also filed an application with the
MPSC requesting a rehearing on return on equity, capital structure and energy cost recovery. A decision by the MPSC is pending.

Praxair
and Explorer Pipeline filed a Petition for Writ of Review with the Cole County Circuit Court on January 31, 2007. The Circuit Court issued a Writ, but the MPSC moved to
have the Writ set aside on the basis that it was issued prematurely. On March 20, 2007, Praxair and Explorer filed a motion in the Circuit Court writ proceeding requesting an immediate stay of
the effectiveness of our December 2006 Missouri rate case order and the tariffs filed pursuant thereto. Without an order being issued on the stay motion, pursuant to an agreement of the parties, the
Circuit Court set aside the Writ and dismissed the case.

On
January 4, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Court of Appeals, Western District, seeking to have the order approving tariffs issued by the
MPSC on December 29, 2006, set aside. On March 12, 2007, the Court of Appeals issued an order denying the OPC's petition.

On
March 19, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Supreme Court seeking an order requiring the MPSC to vacate and rescind its December 29,
2006 order approving tariffs and directing the MPSC to provide an effective date for any subsequent tariff approval order that allows at least ten days to prepare and file an application for
rehearing. On May 1, 2007, the Missouri Supreme Court issued a preliminary writ directing the MPSC to respond to the OPC's petition. Following briefs and oral argument, on October 30,
2007, the Supreme Court made its preliminary writ peremptory and issued an opinion directing the MPSC to vacate its December 29 order approving tariffs and allow the Public Counsel a reasonable
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 December 29, 2006 order approving tariffs, and
considered only the timing of the issuance of the order. The Court also did not consider the underlying tariffed rates which continue in force and in effect. Acting upon this opinion, 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 an application with the MPSC requesting the MPSC grant a rehearing on the December 4, 2007 order. All
applications for rehearing remain pending before the MPSC.

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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%.
This request is to allow us to recover 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 2007 ice storms
and other changes in our underlying costs. We are also requesting implementation of a fuel adjustment clause in Missouri which would permit the distribution to Missouri customers of changes in fuel
and purchased power costs.

On
June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. The MPSC issued a final
order on January 31, 2006 approving an annual increase in base rates of approximately $469,000, or 35.9%, effective February 4, 2006.

Arkansas

On July 14, 2004, we filed a request with the APSC for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or
22.1%. On May 13, 2005, the APSC granted an annual increase in electric rates for our Arkansas customers of approximately $595,000, or 7.66%, effective May 14, 2005.

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 $4,181,078, 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 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 will be 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 with an effective date of January 4, 2006. Pursuant to the Agreement, we were to
seek KCC approval of an explicit hedging program in a separate docket by March 1, 2006. However, we requested and received an extension until April 1, 2006. We made this filing on
March 30, 2006. On February 4, 2008, the KCC issued an order denying the request for the approval of our existing natural gas hedging program. All gains or losses related to the
financial instruments used to fix the future price of natural gas will be excluded from recovery through the ECA and future base electric rates in Kansas.

We
have filed applications for Accounting Authority Orders in Oklahoma and Kansas respecting costs incurred due to the 2007 ice storms.

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 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 Missouri Rate Case effective March 27, 2005.

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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. Our last ACA filing was completed on October 24, 2007.

COMPETITION

Electric Segment

SPP-RTO

On February 1, 2007, the 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. Although our experience to date in the EIS market is limited, we believe we have received benefits through our participation. Our active participation and assessment of EIS market
benefits continues.

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
February 16, 2007, the FERC issued a Final Order No. 890, which instituted numerous reforms to its Order 888 open access transmission pro forma tariff (OATT) which was
issued in April 1996. The purpose of the Order was (i) to strengthen the OATT to ensure that it better achieves its original purpose of remedying undue discrimination for the provision of
transmission service, (ii) to provide greater specificity in the OATT to reduce opportunities for the exercise of undue discrimination, make undue discrimination easier to detect, and
facilitate the FERC's enforcement, and (iii) to increase transparency in the rules applicable to planning and use of the transmission system. The FERC's actions required modifications to the
SPP and our OATTs as well as regional and local transmission planning processes. We and SPP submitted our respective Order 890 compliance filings of our OATTs on October 11, 2007. Compliance
modifications to our OATT filing were not material and we anticipate them being accepted. The SPP proposed modifications to its regional and local area transmission planning processes, pursuant to
Order 890, in its December 7, 2007 FERC filing. An issuance from the FERC on our and SPP's filings is pending. In December 2007, the FERC issued Order 890A, reconfirming its February Order 890.

FERC Market Power Order

In April and July 2004, the FERC issued orders regarding new testing standards for assessing market power by entities that have wholesale market-based rate
tariffs filed with the FERC. The parameters included in the tests are such that most investor owned electric utilities fail the test within their own control area and are subject to a rebuttable
presumption of market power. Entities with wholesale market based rates tariffs are subject to a triennial filing to test for market power and are required to apply the new testing criteria. FERC
determination of market power would result in the inability for a utility to continue

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to
charge such market-based rates. In September 2004, we submitted amended and updated market power analyses filings.

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 could amount to approximately $0.6 million (excluding interest) covering over a thousand hourly energy
sales from the period of May 2005 through August 2006 to numerous counterparties external to our system. In response to the order, we filed a Motion For Extension of time and expedited treatment
regarding the refund and 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 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. The FERC's decision on the refund is still pending.

On
June 21, 2007, the FERC issued a Final Rule related to Market-Based Rates for Wholesales of Electric Energy, Capacity, and Ancillary Services by Public Utilities which directly
affects our market power assessment within our service area and Request For Rehearing related to the aforementioned pending potential refund. In reaction to the Final Rule, we were required to modify
our Market Based Rate Tariff in the form of a compliance filing to the FERC, which was made on September 17, 2007. The FERC's ruling on our compliance filing is also pending. We have
implemented revisions to our wholesale power sales business practices in accordance with the Final Rule.

Other FERC Rulemaking

Also 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. The FERC is seeking comment in the following areas: (i) the role of demand response in the organized markets, (ii) increasing
opportunities for long-term power contracts, (iii) strengthening market monitoring and (iv) the responsiveness of RTOs and ISOs to customers and stakeholders.

On
January 28, 2008, we made a filing at the FERC related to 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 Order No. 614. The FERC's acceptance of the proposed updates to our OATT is pending.

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.

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LIQUIDITY AND CAPITAL RESOURCES

We used approximately $178.5 million of cash for regulated capital expenditures during 2007. Our primary sources of cash flow for these expenditures during
2007 were $103.5 million in internally generated funds from continuing operations, $79.8 million in gross proceeds from first mortgage bonds and $71.7 million in gross proceeds
from the sale of common stock. We also used cash sources to reduce short-term debt by $44.0 million and pay dividends of $39.0 million.

A
detailed discussion on cash flow activity follows.

Cash Provided by Operating Activities

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. 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 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.

Our
net cash flows provided by operating activities decreased $4.8 million during 2006 as compared to 2005. Cash flows were positively impacted mainly by a $15.5 million
increase in net income and a $8.6 million cash flow change in accounts receivable and accrued unbilled revenues. There was also no
pension contribution in 2006 as compared to an $11.5 million pension contribution in 2005. These positive impacts were offset mainly by a $28.8 million cash flow change in accounts
payable and accrued liabilities and a $6.3 million cash flow change in fuel, materials and supplies. Changes in adjustments to net income for non-cash items were $2.9 million
less in 2006 compared to 2005 mainly due to decreases in deferred income taxes.

Capital Requirements and Investing Activities

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 expenditures for Plum Point Unit 1 and Iatan 2, capital
expenditures related to the January and December 2007 ice storms and capital expenditures related to the new SCR at the Asbury Plant. Proceeds from the sale of the unit train added
$1.2 million.

Our
net cash flows used in investing activities increased $146.7 million during 2006 as compared to 2005, primarily reflecting our acquisition of Missouri Gas, additions to our
transmission and distribution systems and construction expenditures for Plum Point Unit 1, Iatan 2 and the new combustion turbine at our Riverton Plant.

Our
capital expenditures incurred for continuing operations total approximately $195.5 million, $120.2 million, and $73.2 million in 2007, 2006 and 2005,
respectively (excluding the acquisition of Missouri

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Gas
in 2006). These capital expenditures include AFUDC, capital expenditures to retire assets and benefits from salvage.

A
breakdown of these capital expenditures (including AFUDC) for 2007, 2006 and 2005 is as follows:

|                                                             |                          | Capital Expenditures
|------------------------------------------------------------ | ------------------------ | --------------------
|
|Distribution and transmission system additions               |                          | $                   
|New generation  Riverton combustion turbine                 |                          |                     
|New generation  Plum Point Energy Station                   |                          |                     
|New generation  Iatan 2                                     |                          |                     
|Storms(1)                                                    |                          |                     
|Additions and replacements  Asbury                          |                          |                     
|Additions and replacements  Iatan 1                         |                          |                     
|Additions and replacements  Energy Center                   |                          |                     
|Additions and replacements  State Line Combined Cycle Unit, |                          |                     
|                                                             | Riverton and Ozark Beach |                     
|Additions and replacements  State Line Unit 1               |                          |                     
|Gas segment additions and replacements                       |                          |                     
|Transportation                                               |                          |                     
|Other (including retirements and salvage  net)              |                          |                     
|                                                             |                          |                     
|Subtotal                                                     |                          | $                   
|Non-regulated capital expenditures (primarily fiber optics)  |                          |                     
|                                                             |                          |                     
|Subtotal capital expenditures incurred(2)                    |                          | $                   
|                                                             |                          |                     
|Less capital expenditures payable(3)                         |                          |                     
|                                                             |                          |                     
|Total cash outlay                                            |                          | $                   
|                                                             |                          |                     

---

Approximately
36%, 30% and 56% of our cash requirements for capital expenditures for 2007, 2006 (excluding the acquisition of Missouri Gas) and 2005, 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.

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We
estimate that our capital expenditures will total approximately $189.3 million in 2008, $121.2 million in 2009 and $121.0 million in 2010 (excluding AFUDC). Of
these budgeted amounts, we anticipate that we will spend the following amounts over the next three years for the following projects:

|Project                                    |  | 2008 |      | 2009 |   | 2010
|------------------------------------------ |  | ---- | ---- | ---- | - | ----
|Iatan 2                                    |  | $    | 72.4 |      | $ | 43.8
|Plum Point Energy Station                  |  |      | 26.3 |      |   | 9.1 
|Combustion turbine for 2011                |  |      | 0.2  |      |   | 4.8 
|Electric distribution system additions     |  |      | 34.9 |      |   | 42.0
|Electric transmission facilities additions |  |      | 11.9 |      |   | 6.5 
|Environmental upgrades  Iatan 1           |  |      | 26.7 |      |   | 1.4 

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 convert the 50 megawatts covered by the purchased power agreement into an ownership interest in 2015. We are planning a new combustion turbine at a
still-to-be-determined site in 2011. See Note 12 of "Notes to Consolidated Financial Statements" under Item 8 for additional information regarding
commitments.

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

We
are installing pollution control equipment on Iatan 1 by 2008 which will include a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a
baghouse, with our share of the capital cost estimated at $46 million (excluding AFUDC). We incurred approximately $12.1 million of this cost in 2007 and $3.9 million in 2006. For
additional information, see Item 1, "Business  Environmental Matters."

We
estimate that internally generated funds will provide approximately 22% of the funds required in 2008 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.

Financing Activities

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.

Our
net cash flows from continuing operations provided by financing activities increased $142.3 million to $143.1 million during 2006 as compared to $0.9 million in
2005, primarily due to increased proceeds from the issuance of common stock and EDG first mortgage bonds in 2006.

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.

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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
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
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.

We
have an effective shelf registration statement with the SEC under which approximately $174.2 million of our common stock, unsecured debt securities, preference stock and first
mortgage bonds remain available for issuance. Of this amount, $120 million remains available of the original $200 million approved by the MPSC as 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 $40.5 million as of February 1, 2008. 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 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, 2007, 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 no outstanding borrowings under this agreement at December 31, 2007, however, $33.0 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

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for
the twelve months ended December 31, 2007 would permit us to issue approximately $247.7 million of new first mortgage bonds based on this test with an assumed interest rate of 6.5%.
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, 2007, we had retired bonds and net property additions which would enable the issuance of at least $565.5 million principal amount of bonds if the annual interest
requirements are met. As of December 31, 2007, we believe we are in compliance with all restrictive covenants of the EDE Mortgage.

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. At
December 31, 2007, we had property additions of $2.5 million. 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, 2007, this test would not allow us to issue any new first mortgage bonds. However, our current financing plan does not contemplate the need for
additional EDG first mortgage bonds.

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     |  | BB+              
|Trust Preferred Securities                      |  | BBB-     |  | Baa3     |  | BB               
|Commercial Paper                                |  | F2       |  | P-2      |  | A-3              
|Outlook                                         |  | Negative |  | Negative |  | Stable           

On September 22, 2005, Standard & Poor's (S&P), reflecting our announcement of our proposed acquisition of Aquila, Inc.'s Missouri natural
gas properties, placed our corporate credit rating on credit watch with negative implications. S&P stated that the acquisition comes in addition to our embarking on a capital spending program that is
significantly higher than historical levels and will be partially debt
financed. On February 13, 2006, S&P removed our corporate credit rating from credit watch, but placed us on negative outlook. S&P also reduced the rating on our commercial paper from
A-2 to A-3 on February 21, 2006. This reduction made it more difficult for us to issue commercial paper and, as a result, our short-term debt during the
period from February 21, 2006 to June 30, 2006, was in the form of borrowings under our revolving credit facility. However, beginning on June 30, 2006, we were able to again issue
commercial paper at the current rating under a new agreement with Wells Fargo Bank. 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 with a stable outlook.

Moody's
affirmed our ratings on May 13, 2005 and revised their rating outlook on us from negative to stable. On January 24, 2007, Moody's again affirmed our ratings but
changed their rating outlook on us back 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

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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 will 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. The review will also consider the potential for elevated costs related to our capital spending plan in 2008. This action, as well as any
actual downgrade of our commercial paper rating from Moody's, 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 higher-cost revolving credit facility.

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. The change to a negative rating outlook reflects uncertainty surrounding the outcome of
our current rate filing and weakness in our projected financial measures relative to Fitch guidelines for the rating category. Recent events leading to the revision were storm damage in December 2007
and the extended outage of the Asbury baseload coal plant following a failed generator inspection.

CONTRACTUAL OBLIGATIONS

Set forth below is information summarizing our contractual obligations as of December 31, 2007. 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 20072011 as noted below. Future pension funding commitments are not
expected to be material over the next 5 years and have not been estimated for later years.

|                                          |  | Payments Due By Period
(in millions)
|----------------------------------------- |  | ------------------------------------
|
|Long-term debt (w/o discount)             |  | $                                   
|Note payable to securitization trust      |  |                                     
|Interest on long-term debt                |  |                                     
|Short-term debt                           |  |                                     
|Capital lease obligations                 |  |                                     
|Operating lease obligations(2)            |  |                                     
|Electric purchase obligations(3)          |  |                                     
|Gas purchase obligations(4)               |  |                                     
|Open purchase orders                      |  |                                     
|Plum Point                                |  |                                     
|SPP transmission system upgrades          |  |                                     
|Postretirement benefit obligation funding |  |                                     
|Other long-term liabilities(5)            |  |                                     
|                                          |  |                                     
|Total Contractual Obligations(6)          |  | $                                   
|                                          |  |                                     

---

54

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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, 2007, our retained earnings balance was
$17.2 million, compared to $22.9 million as of December 31, 2006, after paying out $39.0 million in dividends during 2007. A reduction of our dividend per share, partially
or in whole, could have an adverse effect on our common stock price.

Our
diluted earnings per share were $1.09 for the twelve months ended December 31, 2007 and were $1.39 and $0.92 for the years ended December 31, 2006 and 2005,
respectively. Dividends paid per share were $1.28 for the twelve months ended December 31, 2007 and for each of the years ended December 31, 2006 and 2005.

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 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. As of December 31, 2007, our level of earned surplus did not prevent us from issuing dividends. Absent an amendment to the EDE Mortgage, we may not
have sufficient earned surplus to pay our next quarterly dividend at the rate of $0.32 per share. As a result, we have commenced a consent solicitation to amend the EDE Mortgage to increase the earned
surplus basket under the EDE Mortgage by $10.75 million. We believe that the consent solicitation, which is scheduled to expire on March 11, 2008, will be successful. However, we can
give no assurance that this will be the case.

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

55

---



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, 2007, 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.

In
our 2005 electric Missouri Rate Case (effective March 27, 2005), 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 calculate 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)). This is a change from the policy approved in the 2002 order, which allowed us to recover pension costs on an
ERISA minimum funding (or cash) basis. Prior to the 2002 order, the MPSC allowed us to recover pension costs consistent with our GAAP policy. We had determined that the difference between the ERISA
recovery allowed by the MPSC and our accounting for pension costs under GAPP did not meet the FAS 71 requirements for treatment as a regulatory asset or liability. As a result, we continue to
account for pension expense or benefits in accordance with FAS 87, using the previously mentioned amortization formula for recognizing net gains or losses.

The
MPSC ruled the 2005 change in the recognition of pension costs would allow 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 most recently approved Kansas Rate Case (effective January 1, 2006), 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.

56

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Thus
the fair value adjustment acquisition entries have been recorded as regulatory assets, as these amounts will be recovered 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. We now expect future pension expense or benefits will be fully recovered or recognized in rates charged to our Missouri and Kansas customers, thus lowering our sensitivity to risks
and uncertainties.

Our
2006 Missouri rate case order allows us to defer any OPEB 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
September 29, 2006, the FASB issued 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 is intended to improve financial reporting by requiring 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 or changes in unrestricted net assets of a not-for-profit organization. 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.

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
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 include: future rate of return on plan assets, interest rates used in valuing benefit obligations
(i.e. discount rates), healthcare cost trend rates, Medicare prescription drug costs and demographic assumptions (i.e. mortality and retirement rates).

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), while gains and losses from ineffective (overhedged) instruments are recognized as the
fair value of the derivative instrument changes.

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.

57

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As
of February 15, 2008, approximately 88% of our anticipated volume of natural gas usage for our electric operations for the remainder of the year 2008 is hedged, either through
physical or financial
contracts, at an average price of $6.811 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
five years are hedged at the following average prices per Dth:

Year

% Hedged

Dth Hedged

Average Price2009

55
%
4,696,000

$
6.0602010

34
%
3,200,000

$
5.5612011

34
%
3,200,000

$
5.5612012

13
%
1,200,000

$
7.2952013

13
%
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 15, 2008, we have 93% of our
expected remaining winter heating season usage (through March 2008) hedged with physical storage, physical forward contracts and financial derivative contracts. The average price of these hedges is
$5.488 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 16, 2008, we had 0.4 million Dths in storage on the three pipelines that serve our customers. This represents 21% of our storage capacity. Our
long-term hedge positions for gas purchased for resale are still in the development process. A PGA clause is included in our rates for our gas segment operations, therefore, we mark to
market any unrealized gains or losses
and 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 four states).

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 if the conditions of paragraphs 9a
and b of FAS 71 have been met. 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, and we believe that the regulatory assets and liabilities we have recorded will be afforded similar treatment. If these items are not afforded similar treatment they will be required to be
recognized in our statement of income.

As
of December 31, 2007, we have recorded $91.5 million in regulatory assets and $56.8 million in income taxes, gain on interest rate derivatives, pensions and other
postretirement benefits and costs of removal as regulatory liabilities. See Note 4 of "Notes to Consolidated Financial Statements" under Item 8 for detailed information regarding our
regulatory assets and liabilities.

We
continually assess the recoverability of our regulatory assets. Under current accounting standards, regulatory assets and liabilities are eliminated through a charge or credit,
respectively, to earnings if and when it is no longer probable that such amounts will be recovered through future revenues.

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 and the ability to recover costs.

58

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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 2007, 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, 2007 and 2006 was $2.0 million and $1.6 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.

Goodwill.We recorded goodwill upon the completion of the 2006 Missouri Gas acquisition of
$39.5 million. 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," goodwill is required to be tested for impairment on an annual basis or whenever events or circumstances indicate possible
impairment. Circumstances under which impairment could occur include not realizing anticipated synergies, adverse regulatory treatment or the loss of gas customers. In performing impairment tests,
valuation techniques require the use of estimates with regard to discounted future cash flows of operations, involving judgments based on a broad range of information and historical results. If the
test indicates impairment has occurred, goodwill would be reduced, adversely impacting earnings. We performed our annual goodwill impairment test as of November 30, 2007 and concluded our
goodwill was not impaired.

Risks
and uncertainties affecting these assumptions include: management's identification of impairment indicators, changes in business, industry, laws, technology or economic and market
conditions, and valuation assumptions and conclusion.

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.

59

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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 2008 than in 2007, our interest expense would increase, and income before taxes would decrease by less than $0.4 million. This amount
has been determined by considering the impact of the hypothetical interest rates on our highest month-end commercial paper balance for 2007. 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 58.6% of our 2007 generation fuel supply need through coal. Approximately 86% of our 2007 coal supply was Western coal. We have contracts to supply fuel for our coal plants
through 2010. These contracts and current inventory satisfy approximately 93% of our anticipated fuel requirements for 2008, 61% for 2009 and 48% for our 2010 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 minimize our risk
from 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 expense and improve predictability. We expect that increases in gas
prices will be partially offset by realized gains under financial derivative transactions. As of January 25, 2008, 88%, or 6.8 million Dths's, of our anticipated volume of natural gas
usage for our electric operations for the remainder of 2008 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 2008, if average natural gas prices should increase 10% more in 2008 than the price at December 31,
2007, our natural gas expense would increase, and income before taxes would decrease by approximately $0.9 million based on our December 31, 2007 total hedged positions for the next
twelve months.

60

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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 15, 2008, we have 93% of our expected remaining winter heating season usage (through March 2008) hedged with physical storage, physical forward contracts and financial derivative
contracts. The average price of these hedges is $5.488 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 16, 2008, we have 0.4 million Dths in storage on the three pipelines that serve our customers. This
represents 21% of our storage capacity. Our long-term hedge strategy for our gas segment is still in the development process. 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. 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)

2007

2006Margin deposit assets

$
6.3

$
2.0Margin deposit liabilities

$


$
3.9


In addition, we are holding a letter of credit from a counterparty in our favor for $6.5 million as of December 31, 2007.

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.

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 January 25, 2008, gross credit exposure related to these transactions totaled $22.9 million, reflecting the
unrealized gains for contracts carried at fair value.

Subprime Market Risk.We have evaluated our exposure to the current housing subprime risk environment and do not feel it has
a significant effect on our business, financial position and results of operations. However, if the credit market continues to deteriorate, we will re-evaluate any effects.

61

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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 accompanying index present fairly, in all material respects, the financial position of The Empire District Electric
Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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 accompanying index 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, 2007, based on criteria established inInternal Control 
Integrated Frameworkissued 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 2007 and 2006). 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.

As
discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for share-based compensation and pension and other
post-retirement benefits in fiscal 2006.

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 29, 2008

62

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

|                                          |                                                                                 | December 31,
|----------------------------------------- | ------------------------------------------------------------------------------- | ------------
|
|
|Assets                                    |                                                                                 |             
|Plant and property, at original cost:     |                                                                                 |             
|                                          | Electric                                                                        |             
|                                          | Natural gas                                                                     |             
|                                          | Water                                                                           |             
|                                          | Non-regulated                                                                   |             
|                                          | Construction work in progress                                                   |             
|                                          |                                                                                 |             
|                                          |                                                                                 |             
|Accumulated depreciation and amortization |                                                                                 |             
|                                          |                                                                                 |             
|                                          |                                                                                 |             
|                                          |                                                                                 |             
|Current assets:                           |                                                                                 |             
|                                          | Cash and cash equivalents                                                       |             
|                                          | Accounts receivable  trade, net of allowance of $1,140 and $1,179 respectively |             
|                                          | Accrued unbilled revenues                                                       |             
|                                          | Accounts receivable  other                                                     |             
|                                          | Fuel, material and supplies                                                     |             
|                                          | Unrealized gain in fair value of derivative contracts                           |             
|                                          | Prepaid expenses and other                                                      |             
|                                          | Discontinued operations                                                         |             
|                                          |                                                                                 |             
|                                          |                                                                                 |             
|                                          |                                                                                 |             
|Noncurrent assets and deferred charges:   |                                                                                 |             
|                                          | Regulatory assets                                                               |             
|                                          | Goodwill                                                                        |             
|                                          | Unamortized debt issuance costs                                                 |             
|                                          | Unrealized gain in fair value of derivative contracts                           |             
|                                          | Other                                                                           |             
|                                          | Discontinued operations                                                         |             
|                                          |                                                                                 |             
|                                          |                                                                                 |             
|                                          |                                                                                 |             
|Total assets                              |                                                                                 | $           
|                                          |                                                                                 |             

(Continued)

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

63

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

|                                                                                                                                 |                                                       | December 31,                                        
|-------------------------------------------------------------------------------------------------------------------------------- | ----------------------------------------------------- | ----------------------------------------------------
|
|
|Capitalization and liabilities                                                                                                   |                                                       |                                                     
|Common stock, $1 par value, 100,000,000 shares authorized, 33,605,871 and 30,250,566 shares issued and outstanding, respectively |                                                       | $                                                   
|Capital in excess of par value                                                                                                   |                                                       |                                                     
|Retained earnings                                                                                                                |                                                       |                                                     
|Accumulated other comprehensive income, net of income tax                                                                        |                                                       |                                                     
|                                                                                                                                 |                                                       |                                                     
|                                                                                                                                 |                                                       | Total common stockholders' equity                   
|Long-term debt, (net of current portion)                                                                                         |                                                       |                                                     
|                                                                                                                                 | Note payable to securitization trust                  |                                                     
|                                                                                                                                 | Obligations under capital lease                       |                                                     
|                                                                                                                                 | First mortgage bonds and secured debt                 |                                                     
|                                                                                                                                 | Unsecured debt                                        |                                                     
|                                                                                                                                 |                                                       |                                                     
|                                                                                                                                 |                                                       | Total long-term debt                                
|                                                                                                                                 |                                                       |                                                     
|                                                                                                                                 |                                                       | Total long-term debt and common stockholders' equity
|                                                                                                                                 |                                                       |                                                     
|Current liabilities:                                                                                                             |                                                       |                                                     
|                                                                                                                                 | Accounts payable and accrued liabilities              |                                                     
|                                                                                                                                 | Current maturities of long-term debt                  |                                                     
|                                                                                                                                 | Short-term debt                                       |                                                     
|                                                                                                                                 | Customer deposits                                     |                                                     
|                                                                                                                                 | Interest accrued                                      |                                                     
|                                                                                                                                 | Unrealized loss in fair value of derivative contracts |                                                     
|                                                                                                                                 | Taxes accrued                                         |                                                     
|                                                                                                                                 | Other current liabilities                             |                                                     
|                                                                                                                                 | Discontinued operations                               |                                                     
|                                                                                                                                 |                                                       |                                                     
|                                                                                                                                 |                                                       |                                                     
|                                                                                                                                 |                                                       |                                                     
|Commitments and contingencies (Note 12)                                                                                          |                                                       |                                                     
|Noncurrent liabilities and deferred credits:                                                                                     |                                                       |                                                     
|                                                                                                                                 | Regulatory liabilities                                |                                                     
|                                                                                                                                 | Deferred income taxes                                 |                                                     
|                                                                                                                                 | Unamortized investment tax credits                    |                                                     
|                                                                                                                                 | Pension and other postretirement benefit obligations  |                                                     
|                                                                                                                                 | Unrealized loss in fair value of derivative contracts |                                                     
|                                                                                                                                 | Other                                                 |                                                     
|                                                                                                                                 | Discontinued operations                               |                                                     
|                                                                                                                                 |                                                       |                                                     
|                                                                                                                                 |                                                       |                                                     
|                                                                                                                                 |                                                       |                                                     
|                                                                                                                                 |                                                       | Total capitalization and liabilities                
|                                                                                                                                 |                                                       |                                                     

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

64

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED STATEMENTS OF INCOME

|                                                                                                   |                                                        | Year Ended December 31, |        
|-------------------------------------------------------------------------------------------------- | ------------------------------------------------------ | ----------------------- | -------
|
|
|Operating revenues:                                                                                |                                                        |                         |        
|                                                                                                   | Electric                                               |                         | $      
|                                                                                                   | Gas                                                    |                         |        
|                                                                                                   | Water                                                  |                         |        
|                                                                                                   | Non-regulated                                          |                         |        
|                                                                                                   |                                                        |                         |        
|                                                                                                   |                                                        |                         | 490,160
|                                                                                                   |                                                        |                         |        
|Operating revenue deductions:                                                                      |                                                        |                         |        
|                                                                                                   | Fuel  Electric                                        |                         |        
|                                                                                                   | Purchased power                                        |                         |        
|                                                                                                   | Cost of natural gas sold and transported               |                         |        
|                                                                                                   | Non-regulated  other                                  |                         |        
|                                                                                                   | Regulated  other                                      |                         |        
|                                                                                                   | Maintenance and repairs                                |                         |        
|                                                                                                   | Loss on plant disallowance                             |                         |        
|                                                                                                   | Gain on sale of assets                                 |                         |        
|                                                                                                   | Depreciation and amortization                          |                         |        
|                                                                                                   | Provision for income taxes                             |                         |        
|                                                                                                   | Other taxes                                            |                         |        
|                                                                                                   |                                                        |                         |        
|                                                                                                   |                                                        |                         | 424,594
|                                                                                                   |                                                        |                         |        
|Operating income                                                                                   |                                                        |                         | 65,566 
|Other income and (deductions):                                                                     |                                                        |                         |        
|                                                                                                   | Allowance for equity funds used during construction    |                         |        
|                                                                                                   | Interest income                                        |                         |        
|                                                                                                   | Benefit/(provision) for other income taxes             |                         |        
|                                                                                                   | Other  non-operating income                           |                         |        
|                                                                                                   | Other  non-operating expense                          |                         |        
|                                                                                                   |                                                        |                         |        
|                                                                                                   |                                                        |                         | 2,252  
|                                                                                                   |                                                        |                         |        
|Interest charges:                                                                                  |                                                        |                         |        
|                                                                                                   | Long-term debt                                         |                         |        
|                                                                                                   | Note payable to securitization trust                   |                         |        
|                                                                                                   | Allowance for borrowed funds used during construction  |                         |        
|                                                                                                   | Short-term debt                                        |                         |        
|                                                                                                   | Other                                                  |                         |        
|                                                                                                   |                                                        |                         |        
|                                                                                                   |                                                        |                         | 34,637 
|                                                                                                   |                                                        |                         |        
|Income from continuing operations                                                                  |                                                        |                         | 33,181 
|                                                                                                   | Income (loss) from discontinued operations, net of tax |                         |        
|                                                                                                   |                                                        |                         |        
|Net income                                                                                         |                                                        | $                       | 33,244 
|                                                                                                   |                                                        |                         |        
|Weighted average number of common shares outstanding  basic                                       |                                                        |                         | 30,587 
|                                                                                                   |                                                        |                         |        
|Weighted average number of common shares outstanding  diluted                                     |                                                        |                         | 30,610 
|                                                                                                   |                                                        |                         |        
|Earnings from continuing operations per weighted average share of common stock  basic and diluted |                                                        | $                       | 1.09   
|                                                                                                   |                                                        |                         |        
|Loss from discontinued operations per weighted average share of common stock  basic and diluted   |                                                        |                         | 0.00   
|                                                                                                   |                                                        |                         |        
|Total earnings per weighted average share of common stock  basic and diluted                      |                                                        | $                       | 1.09   
|                                                                                                   |                                                        |                         |        
|Dividends declared per share of common stock                                                       |                                                        | $                       | 1.28   
|                                                                                                   |                                                        |                         |        

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

65

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME

|                                                                                                               |  | Year Ended December 31, |       
|-------------------------------------------------------------------------------------------------------------- |  | ----------------------- | ------
|
|
|Net income                                                                                                     |  | $                       | 33,244
|                                                                                                               |  |                         |       
|Reclassification adjustments for gains included in net income or reclassified to regulatory asset or liability |  |                         | (1,610
|Net change in fair value of open derivative contracts for period                                               |  |                         | 5,229 
|Income taxes                                                                                                   |  |                         | (1,379
|                                                                                                               |  |                         |       
|Net change in unrealized gain/(loss) on derivative contracts                                                   |  |                         | 2,240 
|                                                                                                               |  |                         |       
|Comprehensive income                                                                                           |  | $                       | 35,484
|                                                                                                               |  |                         |       

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

66

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

|                                        |                                                              | December 31,                          |                     
|--------------------------------------- | ------------------------------------------------------------ | ------------------------------------- | --------------------
|
|
|Common stock, $1 par value:             |                                                              |                                       |                     
|                                        | Balance, beginning of year                                   |                                       | $                   
|                                        | Stock/stock units issued through:                            |                                       |                     
|                                        |                                                              | Public offering                       |                     
|                                        |                                                              | Stock purchase and reinvestment plans |                     
|                                        |                                                              |                                       |                     
|                                        |                                                              |                                       | Balance, end of year
|                                        |                                                              |                                       |                     
|Capital in excess of par value:         |                                                              |                                       |                     
|                                        | Balance, beginning of year                                   |                                       | $                   
|                                        | Excess of net proceeds over par value of stock issued:       |                                       |                     
|                                        |                                                              | Public offering                       |                     
|                                        |                                                              | Stock purchase and reinvestment plans |                     
|                                        |                                                              |                                       |                     
|                                        |                                                              |                                       | Balance, end of year
|                                        |                                                              |                                       |                     
|Retained earnings:                      |                                                              |                                       |                     
|                                        | Balance, beginning of year                                   |                                       | $                   
|                                        | Cumulative effect of adopting a change in accounting         |                                       |                     
|                                        | Net income                                                   |                                       |                     
|                                        |                                                              |                                       |                     
|                                        |                                                              |                                       | 56,106              
|                                        | Less common stock dividends declared                         |                                       |                     
|                                        |                                                              |                                       |                     
|                                        |                                                              |                                       | Balance, end of year
|                                        |                                                              |                                       |                     
|Accumulated other comprehensive income: |                                                              |                                       |                     
|                                        | Balance, beginning of year                                   |                                       | $                   
|                                        | Reclassification adjustment for gains included in net income |                                       |                     
|                                        | Change in fair value of open derivative contracts for period |                                       |                     
|                                        | Income taxes                                                 |                                       |                     
|                                        |                                                              |                                       |                     
|                                        |                                                              |                                       | Balance, end of year
|                                        |                                                              |                                       |                     

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

67

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THE EMPIRE DISTRICT ELECTRIC COMPANY        CONSOLIDATED STATEMENTS OF CASH FLOWS

|                                                                     |                                                                  | Year Ended December 31, |        
|-------------------------------------------------------------------- | ---------------------------------------------------------------- | ----------------------- | -------
|
|
|Operating activities:                                                |                                                                  |                         |        
|                                                                     | Net income                                                       |                         | $      
|Adjustments to reconcile net income to cash flows:                   |                                                                  |                         |        
|                                                                     | Depreciation and amortization                                    |                         |        
|                                                                     | Pension and other postretirement benefit costs                   |                         |        
|                                                                     | Deferred income taxes and unamortized investment tax credit, net |                         |        
|                                                                     | Allowance for equity funds used during construction              |                         |        
|                                                                     | Stock compensation expense                                       |                         |        
|                                                                     | Loss on plant disallowance                                       |                         |        
|                                                                     | Non cash gain on derivatives                                     |                         |        
|                                                                     | Gain on the sale of assets                                       |                         |        
|                                                                     | Gain on the sale of non-regulated businesses                     |                         |        
|Cash flows impacted by changes in:                                   |                                                                  |                         |        
|                                                                     | Accounts receivable and accrued unbilled revenues                |                         |        
|                                                                     | Fuel, materials and supplies                                     |                         |        
|                                                                     | Prepaid expenses, other current assets and deferred charges      |                         |        
|                                                                     | Accounts payable and accrued liabilities                         |                         |        
|                                                                     | Pension contribution                                             |                         |        
|                                                                     | Interest, taxes accrued and customer deposits                    |                         |        
|                                                                     | Other liabilities and other deferred credits                     |                         |        
|                                                                     |                                                                  |                         |        
|Net cash provided by operating activities of continuing operations   |                                                                  |                         | 103,457
|Net cash provided by operating activities of discontinued operations |                                                                  |                         | 208    
|                                                                     |                                                                  |                         |        
|Total net cash provided by operating activities                      |                                                                  |                         | 103,665
|                                                                     |                                                                  |                         |        

(Continued)

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

68

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THE EMPIRE DISTRICT ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

|                                                                   |                                                                       | Year Ended December 31, |         
|------------------------------------------------------------------ | --------------------------------------------------------------------- | ----------------------- | --------
|
|
|Investing activities:                                              |                                                                       |                         |         
|                                                                   | Capital expenditures  regulated                                      |                         | $       
|                                                                   | Acquisition of gas operations, net of cash acquired                   |                         |         
|                                                                   | Capital expenditures and other investments  non-regulated            |                         |         
|                                                                   | Proceeds from the sale of property, plant and equipment               |                         |         
|                                                                   | Proceeds from the sale of non-regulated businesses                    |                         |         
|                                                                   |                                                                       |                         |         
|Net cash used in investing activities of continuing operations     |                                                                       |                         | (178,903
|Net cash used in investing activities of discontinued operations   |                                                                       |                         | (12     
|                                                                   |                                                                       |                         |         
|Total net cash used in investing activities                        |                                                                       |                         | (178,915
|                                                                   |                                                                       |                         |         
|Financing activities:                                              |                                                                       |                         |         
|                                                                   | Proceeds from first mortgage bonds  electric                         |                         |         
|                                                                   | Proceeds from first mortgage bonds  gas                              |                         |         
|                                                                   | Payment of interest rate derivatives                                  |                         |         
|                                                                   | Proceeds from issuance of senior notes                                |                         |         
|                                                                   | Proceeds from issuance of common stock, net of issuance costs         |                         |         
|                                                                   | Long-term debt issuance costs                                         |                         |         
|                                                                   | Redemption of first mortgage bonds                                    |                         |         
|                                                                   | Premium paid on extinguished debt                                     |                         |         
|                                                                   | Dividends                                                             |                         |         
|                                                                   | Net short-term (repayments) borrowings                                |                         |         
|                                                                   | Other                                                                 |                         |         
|                                                                   |                                                                       |                         |         
|Net cash provided by financing activities of continuing operations |                                                                       |                         | 67,059  
|Net cash used in financing activities of discontinued operations   |                                                                       |                         | (69     
|                                                                   |                                                                       |                         |         
|Net cash provided by financing activities                          |                                                                       |                         | 66,990  
|                                                                   |                                                                       |                         |         
|Net (decrease)/increase in cash and cash equivalents               |                                                                       |                         | (8,260  
|Cash and cash equivalents, beginning of year                       |                                                                       |                         | 12,303  
|                                                                   |                                                                       |                         |         
|Cash and cash equivalents, end of year                             |                                                                       | $                       | 4,043   
|                                                                   |                                                                       |                         |         
|
|Supplemental cash flow information:                                |                                                                       |                         |         
|                                                                   | Interest paid                                                         |                         | $       
|                                                                   | Income taxes (received) paid, net of refund                           |                         |         
|                                                                   | Capital lease obligations for purchase of new equipment               |                         |         
|Supplementary non-cash financing activities:                       |                                                                       |                         |         
|                                                                   | Accrued additions to property, plant and equipment not reported above |                         | $       

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

69

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THE EMPIRE DISTRICT ELECTRIC COMPANY        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     Summary of Significant Accounting Policies

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. It provides natural gas distribution to 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. These businesses are held by our other operating
segment. See Note 13. In 2007, 87.1% of our gross operating revenues were provided from sales from our electric segment (including 0.4% from the sale of water), 12.2% from sales from our gas
segment and 0.7% from our other segment.

The
utility portions of our business are subject to regulation by the Missouri Public Service Commission (MPSC), the State Corporation Commission of the State of Kansas (KCC), the
Corporation Commission of Oklahoma (OCC), the Arkansas Public Service Commission (APSC) and the Federal Energy Regulatory Commission (FERC). Our accounting policies are in accordance with the
ratemaking practices of the regulatory authorities and conform to generally accepted accounting principles as applied to regulated public utilities.

Our
electric revenues in 2007 were derived as follows: residential 41.1%, commercial 30.4%, industrial 15.9%, wholesale on-system 4.3%, wholesale off-system 4.6%
and other 3.7%. Our retail electric revenues for 2007 by jurisdiction were as follows: Missouri 89.0%, Kansas 5.5%, Arkansas 2.7%, and Oklahoma 2.8%.

Our
gas operations serve approximately 46,000 customers and the 2007 gas operating revenues were derived as follows: residential 65.5%, commercial 27.7%, industrial 1.2%, and other 5.6%.

Following
is a description of the Company's significant accounting policies:

Basis of Presentation

The consolidated financial statements include the accounts of EDE, EDG, and EDE Holdings and its subsidiaries. The consolidated entity is referred to throughout
as "we" or the "Company". Significant intercompany balances and transactions have been eliminated in consolidation. See Note 13 for additional information regarding our three segments. Certain
reclassifications have been made to prior year information to conform to the current year presentation.

Discontinued Operations

In August and December 2006, we sold two of our non-regulated businesses, our controlling 52% interest in Mid-America Precision Products
(MAPP) and our 100% interest in Conversant, respectively. MAPP specialized in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries, and was
sold to other current owners. We owned 100% of Conversant, a software company that marketed Customer Watch, an
internet-based customer information system software. In September 2007, we also sold our 100% interest in Fast Freedom, Inc., an Internet service provider. For financial reporting purposes,
these businesses have been classified as discontinued operations and are not included in our segment information.

70

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accounting for the Effects of Regulation

In accordance with Statement of Financial Accounting Standards 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 our regulated generation and other utility operations (the MPSC, the KCC, the
OCC, the APSC and the FERC).

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 if the conditions of paragraphs 9a
and b of FAS 71 have been met. 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. (See Note 4 for further discussion of regulatory assets and liabilities).

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. Estimates also affect the reported amounts of
revenues and expenses during the period. Areas in the financial statements significantly affected by estimates and assumptions include 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.

Revenue Recognition

For our utility operations, we use cycle billing and accrue estimated, but unbilled, revenue for services provided between the last bill date and the period end
date. Unbilled revenues represent the estimate of receivables for energy and natural gas services delivered, but not yet billed to customers. The unbilled estimates are determined based on various
assumptions, such as current month load requirements, billing rates by customer classification and loss factors. Changes in those assumptions can significantly affect the estimates of unbilled
revenues. During 2006, the Company recorded a $5.9 million increase in electric unbilled revenues as a result of certain changes to the assumptions used in determining estimated unbilled
revenues.

Through
December 31, 2006 we collected an Interim Energy Charge (IEC) of $0.002131 per kilowatt hour of customer usage authorized by the MPSC. The IEC was designed to recover
variable fuel and

71

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

purchased
power costs we incurred subject to a ceiling and floor on the amount recoverable (including realized gains or losses associated with our natural gas hedging program) which are higher than
such costs included in the base rates allowed in the 2005 Missouri rate case. This revenue was recorded when service was provided to the customer and subject to refund to the extent collected amounts
exceeded variable fuel and purchased power costs. At each balance sheet date, we evaluated the probability that we would be required to refund either a portion or all of the amounts collected under
the IEC to ratepayers. No provision for refund was recorded. Effective January 1, 2007 the IEC was terminated as a result of an order issued by the MPSC on December 22, 2006.

Property, Plant & Equipment

The costs of additions to utility property and replacements for retired property units are capitalized. Costs include labor, material and an allocation of general
and administrative costs, plus an allowance for funds used during construction (AFUDC). The original cost of units retired or disposed of and the costs of removal are charged to accumulated
depreciation, unless the removed property constitutes an operating unit. In this case a gain or loss is recognized upon the disposal of the asset. We recognized a $1.2 million gain from the
sale of our unit train in the fourth quarter. Maintenance expenditures and the removal of items not considered units of property are charged to income as incurred.

Until
2002, the depreciation/cost of service methodology utilized by our rate-regulated operations included an estimated cost of dismantling and removing plant from service
upon retirement. From January 2002 through March 2005, we suspended accruing the cost of removing plant from service upon retirement through depreciation rates pursuant to the October 2001 Missouri
rate case. Pursuant to our Missouri rate case, effective March 27, 2005, we began accruing cost of removal in depreciation rates reclassified for mass property (including transmission,
distribution and general plant assets) on April 1, 2005. We reclassified the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an asset
retirement obligation under SFAS 143, "Accounting for Obligations Associated with the Retirement of Long-Lived Assets" (FAS 143), from accumulated depreciation to a
regulatory liability. At December 31, 2007, and 2006, the amount of accrued cost of removal was $32.0 million and $27.4 million, respectively, for our electric operating segment.
We have a similar cost of removal regulatory liability for our gas operating segment. This amount was $3.7 at December 31, 2007 and $4.0 million at December 31, 2006. These
amounts are net of our actual cost of removal expenditures.

Depreciation

Provisions for depreciation are computed at straight-line rates in accordance with GAAP consistent with rates approved by regulatory authorities.
These rates are applied to the various classes of utility assets on a composite basis. Provisions for depreciation for our other businesses are computed at straight-line rates over the
estimated useful life of the properties. (See Note 3 for additional details regarding depreciation rates).

In
accordance with our December 21, 2006 order from the MPSC, we recorded approximately $10.4 million of regulatory amortization during 2007. This amortization included in
our rates was granted in the Experimental Regulatory Plan approved by the MPSC on August 2, 2005. It provides additional cash flow to enhance the financial support for our current generation
expansion plan. It is related to our investment in Iatan 2 and also includes our Riverton V84.3A2 combustion turbine (Riverton 12) and environmental improvement and upgrades at Asbury and Iatan
1. This amortization is included as depreciation and amortization expense and in accumulated depreciation and amortization on the consolidated balance sheet.

72

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accounts Receivable

Accounts receivable are recorded at the tariffed rates for customer usage, including applicable taxes and fees and do not bear interest. We review the outstanding
accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the
allowance when management determines it is probable the receivable will not be recovered.

Allowance for Funds Used During Construction

As provided in the regulatory Uniform System of Accounts, utility plant is recorded at original cost, including an allowance for funds used during construction
when first placed in service. The AFUDC is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds applicable to our construction program are capitalized
as a cost of construction. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction
charges for labor and materials.

AFUDC
does not represent current cash income. Recognition of this item as a cost of utility plant is in accordance with regulatory rate practice under which such plant costs are
permitted as a component of rate base and the provision for depreciation.

In
accordance with the methodology prescribed by the FERC, we utilized aggregate rates (on a before-tax basis) of 7.6% for 2007, 7.2% for 2006 and 7.6% for 2005, compounded
semiannually, in determining AFUDC for all of our projects except Iatan 2. The specific Iatan 2 AFUDC rate is a result of our Experimental Regulatory Plan approved by the MPSC on August 2,
2005. In this agreement we were allowed to receive the regulatory amortization discussed above, in rates prior to the completion of Iatan 2. As a result the equity portion of our AFUDC rate for the
Iatan 2 project was reduced by 2.5 percentage points. (See Note 4 for additional discussion of our regulatory plan.)

Asset Impairments

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be
recoverable. To the extent that certain assets may be impaired, analysis is performed based on several criteria, including but not limited to revenue trends, undiscounted forecasted cash flows and
other operating factors, to determine the impairment amount. None of our assets were impaired as of December 31, 2007. In December 2006 we reduced the capitalized value of our Energy Center
Units 3 and 4 by recording a charge to expense for $0.8 million. In our Missouri rate case (ER-2006-0315) Stipulation and Agreement as to Certain Issues, approved
December 21, 2006, we agreed to this disallowance for regulatory purposes and recorded the charge to expense, once it was determined it would not be afforded rate recovery in Missouri rates.
Until this stipulation was finalized on December 21, 2006, we considered these capitalized costs to be probable of recovery in rates. No other impairments existed at December 31, 2006.

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," goodwill is required to be tested for impairment on an annual basis or whenever events or circumstances indicate possible impairment. Circumstances under which impairment could occur include
not realizing anticipated synergies, adverse regulatory treatment or the loss of gas customers. In performing impairment tests, valuation techniques require the use of estimates

73

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

with
regard to discounted future cash flows of operations, involving judgments based on a broad range of information and historical results. If the test indicates impairment has occurred, goodwill
would be reduced, adversely impacting earnings. We performed our annual goodwill impairment test as of November 30, 2007 and concluded our goodwill was not impaired.

Fuel and Purchased Power

Electric Segment

Fuel and purchased power expenses are recorded at the time the fuel is used or the power purchased for our Missouri electric jurisdictions. In our Kansas
jurisdiction, the costs of fuel are recovered from customers through a fuel adjustment clause, based upon estimated fuel costs and purchased power. The adjustments are subject to audit and final
determination by regulators. Similar fuel recovery mechanisms are in place for our Oklahoma, Arkansas and the FERC jurisdictions. In our Kansas jurisdiction, the difference between the costs of fuel
used and the cost of fuel recovered from our customers is recorded as a regulatory asset or a regulatory liability if the actual costs are higher or lower than the costs billed to customers, in
accordance with FAS 71. We buy and sell power through the SPP RTO energy imbalance services market (EIS). We net settle these market transactions on an hourly basis.

Gas Segment

Fuel expense for our gas segment is recognized when the natural gas is delivered to our customers, based on the current cost recovery allowed in rates. A
Purchased Gas Adjustment (PGA) clause allows EDG to recover from our customers, subject to routine regulatory review, the cost of purchased gas supplies. 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.

We
calculate the PGA factor based on our best estimate of our annual gas costs and volumes purchased for resale. The calculated factor is reviewed by the MPSC staff and approved by the
MPSC. PGA factor elements considered include cost of gas supply, storage costs, hedging contracts, revenue and refunds, prior period adjustments and transportation costs.

Pursuant
to the provisions of the PGA clause, the difference between actual costs incurred and costs recovered through the application of the PGA (including costs, cost reductions and
carrying costs associated with the use of financial instruments), are reflected as a regulatory asset or liability. The balance is amortized as amounts are reflected in customer billings.

Derivatives

We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business or
sold in our natural gas business, on the volatile spot market and to manage certain interest rate exposure.

Electric Segment

Pursuant to SFAS 133, "Accounting for Derivative Instruments and Hedging Activities (FAS 133)", derivatives are required to be recognized on the
balance sheet at their fair value. On the date a derivative contract is entered into, the derivative is designated as (1) a hedge of a forecasted transaction or of the variability of cash flows
to be received or paid related to a recognized asset or liability ("cash-flow" hedge); or (2) an instrument that is held for non-hedging purposes (a
"non-hedging" instrument). Changes in the fair value of a derivative that is highly effective and designated and qualifies as a cash-flow hedge are

74

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

recorded
in other comprehensive income until earnings are affected by the variability of cash flows (e.g., when periodic settlements on a variable-rate asset or liability are
recorded in earnings). Changes in the fair value of non-hedged derivative instruments and any ineffective portion of a qualified hedge are reported in current-period earnings in fuel
expense.

We
discontinue hedge accounting prospectively when (1) it is determined that the derivative is no longer highly effective in offsetting changes in cash flows of a hedged item
(including forecasted transactions); (2) the derivative expires or is sold, terminated, or exercised; (3) the derivative is de-designated as a non-hedging
instrument, because it is less than probable that a forecasted transaction will occur; or (4) management determines that designation of the derivative as a hedge instrument is no longer
appropriate. (See note 15).

We
also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts, if they meet the definition of a derivative, are not
subject to derivative accounting because they are considered to be normal purchase normal sales (NPNS) transactions. If these transactions don't qualify for NPNS treatment, they would be marked to
market for each reporting period through income.

Gas Segment

Financial hedges for our natural gas business are recorded at fair value on our balance sheet. Because we have a commission approved natural gas cost recovery
mechanism (PGA), we record the mark-to-market gain/loss on natural gas financial hedges each reporting period to a regulatory asset/liability account. The regulatory
asset/liability account tracks the difference between revenues billed to customers for natural gas costs and actual natural gas expense and then is trued up at the end of August each year and included
in the Actual Cost Adjustment (ACA) factor to
be billed to customers during the next year. This is consistent with FAS 71, in that we will be recovering our costs after the annual true up period (subject to a prudency review by the MPSC).

Cash
flows from hedges for both electric and gas segments are classified within cash flows from operations.

Pension and Other Postretirement Benefits

We recognize expense related to pension and other 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 expense calculation 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.

Pensions

In our 2005 electric Missouri Rate Case (effective March 27, 2005), the MPSC ruled the Company 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 FAS 87). This was a
change from the policy approved in our 2002 order, effective December 1, 2002, which allowed us to recover pension costs on an ERISA minimum funding (or cash) basis. Prior to the 2002 order,
the MPSC allowed the Company to recover pension costs consistent with our GAAP policy. We had determined that the difference between the ERISA recovery allowed by the MPSC

75

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

and
our accounting for pension costs under GAAP did not meet the FAS 71 requirements for treatment as a regulatory asset or liability. As a result, the Company continued to account for pension
expense or benefits in accordance with FAS 87, using the previously mentioned amortization formula for recognizing net gains or losses.

The
MPSC ruled the 2005 change in the recognition of pension costs would allow the Company to record the Missouri portion of any costs above the amount included in the 2005 rate case as
a regulatory asset or recognize a regulatory liability for costs incurred that are less than those allowed in rates. Therefore, the deferral of these costs began in the second quarter of 2005. In the
most recently
approved Kansas Rate Case (effective January 1, 2006), the KCC also ruled that the Company would be allowed to change the recognition of pension costs, deferring the Kansas portion of any costs
above or below the amount included in the rate case as a regulatory asset or liability.

In
the order approved April 18, 2006 by the MPSC regarding the purchase of Missouri Gas by EDG, the Company was 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 postretirement benefits would be recoverable in future rate proceedings. Thus the fair value
adjustment acquisition entries related to the acquisition of Missouri Gas have been recorded as regulatory assets, as these amounts will be recovered 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 five years.

Other Postretirement Benefits (OPEB)

In our most recent Missouri rate case, effective January 1, 2007, the MPSC approved regulatory treatment for our OPEB costs similar to the treatment
described above for pension costs. This includes the use of a market-related value of assets, the amortization of unrecognized gains or losses into actuarial expense over ten years and the recognition
of regulatory assets and liabilities as described above.

In
the third quarter of 2004, we adopted FASB staff position No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement
and Modernization Act of 2003". Beginning December 31, 2004, the accumulated postretirement benefit obligation (APBO) and net cost recognized for OPEB reflects the effects of the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act provides for a federal subsidy, beginning in 2006, of 28% of prescription drug costs between $250 and $5,000 for each
Medicare-eligible retiree who does not join Medicare Part D, to companies whose plans provide prescription drug benefits to their retirees that are "actuarially equivalent" to the prescription
drug benefits provided under Medicare. Equivalency must be certified annually by the Federal Government. Our plan provides prescription drug benefits that are "actuarially equivalent" to the
prescription drug benefits provided under Medicare and have been certified as such.

On
December 31, 2006, we adopted SFAS 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 is intended to improve financial reporting by requiring 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. FAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of
financial position, with limited exceptions. Based on the regulatory treatment of pension and OPEB recovery afforded in the Company's jurisdictions, the Company has concluded that the amount of

76

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

unfunded
defined benefit pension and postretirement plan obligations are probable of future rate recovery and are recorded as regulatory assets on the balance sheet rather than as reductions of equity
through comprehensive income. (See Note 9).

Unamortized Debt Discount, Premium and Expense

Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. Costs, including gains and losses,
related to refunded long-term debt are amortized over the lives of the related new debt issues, in accordance with regulatory rate practices.

Liability Insurance

We carry excess liability insurance for workers' compensation and public liability claims for our electric segment. In order to provide for the cost of losses not
covered by insurance, an allowance for injuries and damages is maintained based on our loss experience. Our gas segment is covered by excess liability insurance for public liability claims, and
workers' compensation claims are covered by a guaranteed cost policy. (See Note 12).

Franchise Taxes

Franchise taxes are collected for and remitted to their respective entities and are included in operating revenues and other taxes in the Consolidated Statements
of Income. Franchise taxes of $10.0 million, $7.3 million and $6.4 million were recorded for each of the years ended December 31, 2007, 2006 and 2005, respectively.

Cash & Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an initial maturity of three months or less. It also includes checks and
electronic funds transfers that have been issued but have not cleared the bank, which are also reflected in current accrued liabilities. At December 31, 2007 and 2006, these amounts were
$13.2 million and $12.7 million, respectively.

Fuel, Material and Supplies

Fuel, material and supplies consist primarily of coal, natural gas in storage and materials and supplies, which are reported at average cost. These balances are
as follows (in thousands):

2007

2006Electric fuel inventory

$
16,643

$
12,213Natural gas inventory


5,639


9,184Materials and supplies


27,200


25,216Total

$
49,482

$
46,613


Income Taxes

Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax
return purposes, measured using statutory tax rates. (See Note 10).

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Investment
tax credits utilized in prior years were deferred and are being amortized over the useful lives of the properties to which they relate. Remaining unamortized investment tax
credits are being amortized over remaining lives of approximately 24 years.

Computations of Earnings Per Share

Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per share are computed
by dividing net income by the weighted average number of common shares outstanding plus the incremental shares that would have been outstanding under the assumed exercise of dilutive restricted shares
and options.

Weighted Average Number Of Shares

2007

2006

2005Basic

30,586,780

28,276,568

25,898,428Dilutive shares

23,571

19,827

42,680Total Dilutive Shares

30,610,351

28,296,395

25,941,108Antidilutive Shares

48,903

48,903

41,115


Potentially dilutive shares are not expected to have a material impact unless significant appreciation of the Company's stock price occurs.

Stock-Based Compensation

At December 31, 2007, we had several stock-based compensation plans, which are described in more detail in Note 5. During 2002, we adopted SFAS
No. 148, "Accounting for Stock-Based Compensation  Transition and Disclosure  an Amendment of SFAS 123" (FAS 148), and elected to adopt the
accounting provision of FAS 123 "Accounting for Stock-Based Compensation" (FAS 123). Under FAS 123, we recognized compensation expense over the vesting period of all stock-based
compensation awards issued subsequent to January 1, 2002 based upon the fair-value of the award as of the date of issuance. We adopted FAS 123(R) "Share Based Payment" on
January 1, 2006 using the modified prospective approach. (See Note 5  "Common Stock"). The adoption of FAS 123(R) did not have a material impact on our stock
compensation expense.

Asset Retirement Obligation

We account and report for legal obligations associated with the retirement or anticipated retirement of tangible long-lived assets in accordance with
SFAS No. 143 "Accounting for Obligations Associated with the Retirement of Long-Lived Assets" (FAS 143) and FASB Interpretation No. 47, "Accounting for Conditional
Asset Retirement Obligations" (FIN 47). We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which
the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset
retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the
probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value.

We
have identified future asset retirement obligations associated with the removal of certain river water intake structures and equipment at the Iatan Power Plant, in which we have a 12%
ownership. We also have a liability for future containment of an ash landfill at the Riverton Power Plant along with a liability for future asset retirement obligations associated with the removal of
asbestos located at the Riverton and Asbury Plants. In addition, we have a liability for the removal and disposal of Polychlorinated

78

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Biphenyls
(PCB) contaminants associated with our transformers and substation equipment. These liabilities have been estimated based upon either third party costs or historical review of expenditures
for the removal of similar past liabilities. The potential costs of these future liabilities are based on engineering estimates of third party costs to remove the assets in satisfaction of the
associated obligations. This liability will be accreted over the period up to the estimated settlement date.

All
of our recorded asset retirement obligations have been estimated as of the expected retirement date, or settlement date, and have been discounted using a credit adjusted
risk-free rate ranging from 5.0% to 5.52% depending on the settlement date. Revisions to these liabilities could occur due to changes in the cost estimates, anticipated timing of
settlement or federal or state regulatory requirements.

The
balances at the end of 2006 and 2007 are shown below.

|(000's)                     |  | Liability
Balance
12/31/06 |       | Liabilities
Recognized |   | Liabilities
Settled |  | Accretion |   | Cash Flow
Revisions |   | Liability
Balance at
12/31/07
|--------------------------- |  | -------------------------- | ----- | ---------------------- | - | ------------------- |  | --------- | - | ------------------- | - | -----------------------------
|Asset Retirement Obligation |  | $                          | 3,448 |                        | $ |                    |  | $         |  |                     | $ | 104                          

Upon adoption of these standards, we recorded a non-recurring discounted liability and a regulatory asset because we expect to recover these costs of
removal in electric and gas rates either through depreciation accruals or direct expenses. We also defer the liability accretion and depreciation expense as a regulatory asset. At December 31,
2007, and 2006, our regulatory assets relating to AROs totaled $2.9 million and $3.0 million, respectively.

Also
as noted previously under property, plant and equipment, we reclassify the accrued cost of dismantling and removing plant from service upon retirement, which is not considered an
asset retirement obligation under FAS 143, from accumulated depreciation to a regulatory liability. This balance sheet reclassification has no impact on results of operations.

Accounting for Uncertainty in Income Taxes

On July 13, 2006, the FASB issued Interpretation No. 48 (FIN 48), which clarifies the accounting for uncertainty in income taxes recognized
in an enterprise's financial statements in accordance with FASB Statement No. 109, "Accounting for Income Taxes." We file consolidated income tax returns in the U.S. federal and state
jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2003. We adopted the
provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, we recognized approximately $54,000 of additional liability for unrecognized tax benefits,
which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. At January 1, 2007 and December 31, 2007, our balance sheet included approximately
$219,000 and $328,000, respectively, of unrecognized tax benefits which would affect our effective tax rate if recognized. We do not expect any material changes to unrecognized tax benefits within the
next twelve months. We recognize interest accrued and penalties related to unrecognized tax benefits in other expenses.

Recently Issued and Proposed Accounting Standards

On September 15, 2006, the FASB issued FASB No. 157, "Fair Value Measurements" (FAS 157), which provides guidance for using fair value to
measure assets and liabilities. FAS 157 also responds to investors' requests for more information about (1) the extent to which companies measure assets and liabilities at fair value,
(2) the information used to measure fair value and (3) the effect that fair-value measurements have on earnings. FAS 157 will apply whenever another standard requires
(or permits) assets or liabilities to be measured at fair value. This standard does not expand the use of fair value to any

79

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

new
circumstances. FAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. On
February 12, 2008 the FASB delayed the effective date of FAS 157 for certain nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair
value in the financial statements on a recurring basis (at least annually). The delay is intended to allow the Board and constituents additional time to consider the effect of various implementation
issues that have arisen, or that may arise, from the application of FAS 157. We do not expect the pronouncement or the delay to have a material effect on our financial statements.

On
February 15, 2007, the FASB issued FASB No. 159, "The Fair-Value Option for Financial Assets and Financial Liabilities  including an
amendment of FAS 115" (FAS 159). Under FAS 159, a company may elect to measure eligible financial assets and financial liabilities at fair value. Unrealized gains and losses on
items for which the fair value option has been elected are reported in earnings at each subsequent reporting date. FAS 159 is effective for financial statements issued for fiscal years
beginning after November 15, 2007. We have not yet completed our review regarding the impact of the adoption of this standard; however, we do not expect the adoption of this standard to have a
material impact on our financial statements.

On
April 30, 2007, the FASB issued FASB Staff Position No. 39-1 (FIN 39), an "Amendment of FASB Interpretation No. 39".
FIN 39-1 is effective for fiscal years ending after November 15, 2007. It amends paragraph 3 of Interpretation 39 to replace the terms "conditional contracts and
exchange contracts" with the term "derivative instruments as defined in FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities". It also amends paragraph 10
of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a
payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with that
paragraph. We currently do not apply this offsetting alternative. We are still evaluating this staff position, but do not believe it will have an impact on our financial statements.

On
December 1, 2007, the FASB issued SFAS 141(R) "Business Combinations" (FAS 141(R)) and SFAS No. 160, "Noncontrolling Interests in Consolidated Financial
Statements, an amendment of ARB
No. 51" (FAS 160). FAS 141(R) and FAS 160 are effective for business combinations entered into in fiscal years beginning on or after December 15, 2008.
FAS 141 (R) changes the definitions of a business and a business combination, and will result in more transactions recorded as business combinations. Certain acquired contingencies will
be recorded initially at fair value on the acquisition date, transactions and restructuring costs generally will be expensed as incurred and in partial acquisitions, companies generally will record
100 percent of the assets and liabilities at fair value, including goodwill. We do not expect these pronouncements to have an effect on our financial statements unless we enter into future
business combinations.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2.     Acquisition of Missouri Natural Gas Distribution Operations

On September 21, 2005, we announced that we had entered into an Asset Purchase Agreement pursuant to which we agreed to acquire the Missouri natural gas
distribution operations of Aquila, Inc. This acquisition was completed by EDG on June 1, 2006. This transaction was subject to the approval of the MPSC, which was obtained, effective
May 1, 2006. The total purchase price, including working capital and net plant adjustments but excluding acquisition costs, was $102.5 million. We recorded $39.5 million of
goodwill as a result of the acquisition. All of this is expected to be tax deductible.

The
components of the purchase price allocation for the Missouri Gas acquisition are shown below. (See Note 7  "Long-Term Debt", for the
information on the purchase price financing). Assets and liabilities are valued at fair value. In the case of property, plant and equipment, fair value is calculated in a manner consistent with the
amount recoverable for regulatory treatment.

(in thousands)

Missouri GasPurchase Price:Cash paid

$
102,502Acquisition costs


2,447Total

$
104,949Allocation:Property, plant and equipment

$
52,226Current assets


15,292Goodwill


39,492Other assets


11,082Other liabilities


(13,143
)Total

$
104,949


2007 changes to the goodwill reflect minor true-up items primarily relating to accounts receivable and pension adjustments in the first quarter.

The
following presents certain consolidated proforma financial information for the years ended December 31, 2006 and 2005, as if our acquisition of Missouri Gas had been completed
as of the beginning of 2005. These estimates are based on historical results of the Missouri Gas operations, provided to us by Aquila, Inc., and are unaudited. In addition, they do not include
the effects of any financing costs (in thousands).

2006

2005Proforma revenues

$
441,815

$
421,899Proforma net income from continuing operations

$
41,586

$
26,052Proforma earnings per share from continuing operations  basic and diluted

$
1.38

$
0.88


81

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3.     Property, Plant and Equipment

Our total property, plant and equipment are summarized below (in thousands).

|                                               |                                                     | December 31,
|---------------------------------------------- | --------------------------------------------------- | ------------
|
|Electric plant                                 |                                                     |             
|Production                                     |                                                     | $           
|                                               | Transmission                                        |             
|                                               | Distribution                                        |             
|                                               | General(1)                                          |             
|                                               |                                                     |             
|                                               | Electric plant                                      |             
|Less accumulated depreciation and amortization |                                                     |             
|                                               |                                                     |             
|                                               | Electric plant net of depreciation and amortization |             
|Construction work in progress                  |                                                     |             
|                                               |                                                     |             
|                                               | Net electric plant                                  |             
|                                               |                                                     |             
|Gas plant                                      |                                                     |             
|Less accumulated depreciation and amortization |                                                     |             
|                                               |                                                     |             
|                                               | Gas plant net of accumulated depreciation           |             
|Construction work in progress                  |                                                     |             
|                                               |                                                     |             
|                                               | Net gas plant                                       |             
|                                               |                                                     |             
|Water plant                                    |                                                     |             
|Less accumulated depreciation and amortization |                                                     |             
|                                               |                                                     |             
|                                               | Water plant net of depreciation and amortization    |             
|Construction work in progress                  |                                                     |             
|                                               |                                                     |             
|                                               | Net water plant                                     |             
|                                               |                                                     |             
|Other                                          |                                                     |             
|                                               | Fiber                                               |             
|                                               | Other non-regulated property                        |             
|Less accumulated depreciation and amortization |                                                     |             
|                                               |                                                     |             
|                                               | Non-regulated net of depreciation and amortization  |             
|Construction work in progress                  |                                                     |             
|                                               |                                                     |             
|                                               | Net non-regulated property                          |             
|                                               |                                                     |             
|Net plant and property                         |                                                     | $           
|                                               |                                                     |             

---

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The
table below summarizes the total provision for depreciation and the depreciation rates for continuing operations, both capitalized and expensed, for the years ended
December 31 (in thousands):

2007

2006

2005Provision for depreciationRegulated  Electric and Water

$
39,577

$
37,174

$
34,637Regulated  Gas


1,967


1,104


Non-Regulated


1,077


877


807Total


42,621


39,155


35,444Amortization(1)


11,310


777


776Total

$
53,931

$
39,932

$
36,220




Annual depreciation ratesElectric

3.0
%
3.0
%
2.8
%Gas

3.7
%
2.1
%
Other

4.5
%
4.4
%
4.5
%Total company

3.0
%
2.9
%
2.9
%


The table below sets forth the average depreciation rate for each class of assets for each period presented:

2007

2006

2005Annual Weighted Average Depreciation RateElectric fixed assets:Production plant

2.2
%
2.2
%
2.2
%Transmission plant

2.3
%
2.3
%
2.2
%Distribution plant

3.6
%
3.5
%
3.3
%General plant

6.1
%
6.1
%
6.5
%Water

2.7
%
2.8
%
2.6
%Gas(1)

3.7
%
2.1
%
Other

4.5
%
4.4
%
4.5
%




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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4.     Regulatory Matters

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, 2005:

|Jurisdiction        |  | Date
Requested   |  | Annual
Increase
Granted |            | Percent
Increase
Granted |       | Date
Effective
|------------------- |  | ---------------- |  | ----------------------- | ---------- | ------------------------ | ----- | --------------
|Missouri  Electric |  | February 1, 2006 |  | $                       | 29,369,397 |                          | 9.96  | %             
|Missouri  Water    |  | June 24, 2005    |  |                         | 469,000    |                          | 35.90 | %             
|Kansas  Electric   |  | April 29, 2005   |  |                         | 2,150,000  |                          | 12.67 | %             
|Arkansas  Electric |  | July 14, 2004    |  |                         | 595,000    |                          | 7.66  | %             
|Missouri  Electric |  | April 30, 2004   |  |                         | 25,705,500 |                          | 9.96  | %             

Missouri

On April 30, 2004, we filed a request with the MPSC for an annual increase in base rates for our Missouri electric customers in the amount of $38,282,294,
or 14.82%. On December 22, 2004, we, the MPSC Staff, the Office of the Public Counsel (OPC) and two intervenors filed a unanimous Stipulation and Agreement as to Certain Issues with the MPSC
settling several issues. One of the issues we were able to agree on was a change in the recognition of pension costs allowing us to defer the Missouri portion of any costs above or below the amount
included in this rate case as a regulatory asset or liability. The amount of pension cost allowed in this rate case was approximately $3.0 million. This stipulation became effective on
March 27, 2005 as part of the final Missouri order described below. Therefore, the deferral of these costs began in the second quarter of 2005.

The
MPSC issued a final order on March 10, 2005 approving an annual increase in base rates of approximately $25,705,500, or 9.96%, effective March 27, 2005. The order
granted us a return on equity of 11%, an increase in base rates for fuel and purchased power at $24.68/MWH and an increase in depreciation rates. The new depreciation rates included a cost of removal
component of mass property (transmission, distribution and general plant costs). In addition, the order approved an annual Interim Energy Charge (IEC) of approximately $8.2 million effective
March 27, 2005 and expiring three years later. The IEC was $0.002131 per kilowatt hour of customer usage. The MPSC allowed us to use forecasted fuel costs rather than the traditional historical
costs in determining the fuel portion of the rate increase. At the end of two years, an assessment would be made of the money collected from customers compared to the greater of the actual and
prudently incurred costs or the base cost of fuel and purchased power set in rates. If the excess of the amount collected over the greater of these two amounts was greater than $10 million, the
excess over $10 million would be refunded to the customers. The entire excess amount of IEC, not previously refunded, would be refunded at the end of three years, unless the IEC was terminated
earlier. Each refund was to include interest at the current prime rate at the time of the refund. The IEC revenues recorded since the inception of the IEC did not recover all the Missouri related fuel
and purchased power costs incurred during that period. From inception of the IEC through December 31, 2006, the costs of fuel and purchased power were approximately $22.3 million higher
than the total of the costs in our base rates and the IEC recorded during the period, therefore, no provision for refund was recorded.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 $29,513,713, or 9.63%. We also
requested transition from
the IEC from an earlier case to Missouri's new fuel adjustment mechanism. The MPSC issued an order May 2, 2006, however, ruling that we may have the option of requesting that the IEC be
terminated, but 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 $29,369,397 (including regulatory amortization), or 9.96%, with an effective date of January 1, 2007 and eliminating the IEC. Pursuant to this order, the collected IEC 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. Of the increase, approximately
$19 million was granted in the form of base rates, with the remainder of approximately $10.4 million granted as regulatory amortization 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. 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 March 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 cost of our Energy Center 2 construction project. The Missouri jurisdictional portion of this agreement resulted in a
pre tax write off of $0.8 million in the fourth quarter of 2006.

On
December 29, 2006, the Office of Public Counsel (OPC) and intervenors Praxair, Inc. and Explorer Pipeline Company, filed an application with the MPSC requesting the MPSC
grant a rehearing on most of the issues addressed in the December 2006 Missouri rate case order and many of the procedural issues. On December 29, 2006, we also filed an application with the
MPSC requesting a rehearing on return on equity, capital structure and energy cost recovery. A decision by the MPSC is pending.

Praxair
and Explorer Pipeline filed a Petition for Writ of Review with the Cole County Circuit Court on January 31, 2007. The Circuit Court issued a Writ, but the MPSC moved to
have the Writ set aside on the basis that it was issued prematurely. On March 20, 2007, Praxair and Explorer filed a motion in the Circuit Court writ proceeding requesting an immediate stay of
the effectiveness of our December 2006 Missouri rate case order and the tariffs filed pursuant thereto. Without an order being issued on the stay motion, pursuant to an agreement of the parties, the
Circuit Court set aside the Writ and dismissed the case.

On
January 4, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Court of Appeals, Western District, seeking to have the order approving tariffs issued by the
MPSC on December 29, 2006, set aside. On March 12, 2007, the Court of Appeals issued an order denying the OPC's petition.

On
March 19, 2007, the OPC filed a Petition for Writ of Mandamus with the Missouri Supreme Court seeking an order requiring the MPSC to vacate and rescind its December 29,
2006 order approving tariffs and directing the MPSC to provide an effective date for any subsequent tariff approval order that allows at least ten days to prepare and file an application for
rehearing. On May 1, 2007, the Missouri Supreme Court issued a preliminary writ directing the MPSC to respond to the OPC's petition. Following briefs and oral argument, on October 30,
2007, the Supreme Court made its preliminary writ peremptory and issued an opinion directing the MPSC to vacate its December 29 order approving tariffs and allow the Public Counsel a reasonable
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 December 29, 2006 order approving tariffs,

85

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

and
considered only the timing of the issuance of the order. The Court also did not consider the underlying tariffed rates which continue in force and in effect. Acting upon this opinion, 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 an application with the MPSC requesting the MPSC grant a rehearing on the December 4, 2007 order. All
applications for rehearing remain pending before the MPSC.

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%.
This request is to allow us to recover 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 2007 ice storms and other changes in our underlying costs. We are also requesting
implementation of a fuel adjustment clause in Missouri which would permit the distribution to Missouri customers of changes in fuel and purchased power costs.

On
June 24, 2005, we filed a request with the MPSC for an annual increase in base rates for our Missouri water customers in the amount of $523,000, or 38%. The MPSC issued a final
order on January 31, 2006 approving an annual increase in base rates of approximately $469,000, or 35.9%, effective February 4, 2006.

Arkansas

On July 14, 2004, we filed a request with the APSC for an annual increase in base rates for our Arkansas electric customers in the amount of $1,428,225, or
22.1%. On May 13, 2005, the APSC granted an annual increase in electric rates for our Arkansas customers of approximately $595,000, or 7.66%, effective May 14, 2005.

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 $4,181,078, 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 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 will be 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 with an effective date of January 4, 2006. Pursuant to the Agreement, we were to
seek KCC approval of an explicit hedging program in a separate docket by March 1, 2006. However, we requested and received an extension until April 1, 2006. We made this filing on
March 30, 2006. On February 4, 2008, the KCC issued an order denying the request for the approval of our existing natural gas hedging program. All gains or losses related to the
financial instruments used to fix the future price of natural gas will be excluded from recovery through the ECA and future base electric rates in Kansas.

We
have filed applications for Accounting Authority Orders in Oklahoma and Kansas respecting costs incurred due to the 2007 ice storms.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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 Missouri Rate Case effective March 27, 2005.

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. Our last ACA filing was completed on October 24, 2007.

Competition

Electric Segment

SPP-RTO

On February 1, 2007, the 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. Although our experience to date in the EIS market is limited, we believe we have received benefits through our participation. Our active participation and assessment of EIS market
benefits continues.

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
February 16, 2007, the FERC issued a Final Order No. 890, which instituted numerous reforms to its Order 888 open access transmission pro forma tariff (OATT) which was
issued in April 1996. The purpose of the Order was (i) to strengthen the OATT to ensure that it better achieves its original purpose of remedying undue discrimination for the provision of
transmission service, (ii) to provide greater specificity in the OATT to reduce opportunities for the exercise of undue discrimination, make undue discrimination easier to detect, and
facilitate the FERC's enforcement, and (iii) to increase transparency in the rules applicable to planning and use of the transmission system. The FERC's actions required modifications to the
SPP and our OATTs as well as regional and local transmission planning processes. We and SPP submitted our respective Order 890 compliance filings of our OATTs on October 11, 2007.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Compliance
modifications to our OATT filing were not material and we anticipate them being accepted. The SPP proposed modifications to its regional and local area transmission planning processes,
pursuant to Order 890, in its December 7, 2007 FERC filing. An issuance from the FERC on our and SPP's filings is pending. In December 2007, the FERC issued Order 890A, reconfirming its
February Order 890.

The FERC Market Power Order

In April and July 2004, the FERC issued orders regarding new testing standards for assessing market power by entities that have wholesale market-based rate
tariffs filed with the FERC. The parameters included in the tests are such that most investor owned electric utilities fail the test within their own control area and are subject to a rebuttable
presumption of market power. Entities with wholesale market based rates tariffs are subject to a triennial filing to test for market power and are required to apply the new testing criteria. The FERC
determination of market power would result in the inability for a utility to continue to charge such market-based rates. In September 2004, we submitted amended and updated market power analyses
filings.

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 could amount to approximately $0.6 million (excluding interest) covering over a thousand hourly energy
sales from the period of May 2005 through August 2006 to numerous counterparties external to our system. In response to the order, we filed a Motion For Extension of time and expedited treatment
regarding the refund and 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 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. The FERC's decision on the refund is still pending.

On
June 21, 2007, the FERC issued a Final Rule related to Market-Based Rates for Wholesales of Electric Energy, Capacity, and Ancillary Services by Public Utilities which directly
affects our market power assessment within our service area and Request For Rehearing related to the aforementioned pending potential refund. In reaction to the Final Rule, we were required to modify
our Market Based Rate Tariff in the form of a compliance filing to the FERC, which was made on September 17, 2007. The FERC's ruling on our compliance filing is also pending. We have
implemented revisions to our wholesale power sales business practices in accordance with the Final Rule.

Other FERC Rulemaking

Also 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. The FERC is seeking comment in the following areas: (i) the role of demand response in the organized markets, (ii) increasing
opportunities for long-term power contracts, (iii) strengthening market monitoring and (iv) the responsiveness of RTOs and ISOs to customers and stakeholders.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On
January 28, 2008, we made a filing at the FERC related to 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 Order No. 614. The FERC's acceptance of the proposed updates to our OATT is pending.

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.

Other  Rate Matters

In accordance with FAS No. 71, we currently have deferred approximately $1.0 million of expense related to rate cases under other
non-current assets and deferred charges of which $0.3 million is related to the Missouri rate case filed in October 2007, $0.1 million is directly related to the Missouri
rate case that was completed in the first quarter of 2005 and $0.3 million for the Missouri rate case completed in 2006. We amortize this amount over varying periods upon the completion of the
specific case. As of December 31, 2007, $0.1 million in expense related to the 2006 Kansas rate case completed is unamortized. Based on past history, we expect all these expenses to be
recovered in rates.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Regulatory Assets and Liabilities and Other Deferred Credits

We have recorded the following regulatory assets and regulatory liabilities (in thousands).

|                                                        |  | December 31,
|------------------------------------------------------- |  | ------------
|
|Regulatory Assets                                       |  |             
|Income taxes                                            |  | $           
|Unamortized loss on reacquired debt                     |  |             
|Unamortized loss on interest rate derivative            |  |             
|Asbury five-year maintenance                            |  |             
|Pension and other postretirement benefits(1)            |  |             
|Ice storm costs                                         |  |             
|Asset retirement obligations                            |  |             
|Unrecovered purchase gas costs and Kansas fuel costs(2) |  |             
|Other                                                   |  |             
|                                                        |  |             
|Total regulatory assets                                 |  | $           
|                                                        |  |             
|Regulatory Liabilities                                  |  |             
|Income taxes                                            |  |             
|Unamortized gain on interest rate derivative            |  |             
|Gain on disposition of emission allowances              |  |             
|Costs of removal                                        |  |             
|Pension and other postretirement benefits(1)            |  |             
|                                                        |  |             
|Total regulatory liabilities                            |  | $           
|                                                        |  |             

---

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



5.     Common Stock

Recent Issues

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 used to pay down short-term debt incurred, in part, as a
result of our ongoing construction program.

Stock Based Compensation

We have several stock-based awards and programs, which are described below. Effective January 1, 2006, we adopted FAS 123(R) "Share-Based Payment"
and applied it to our stock-based awards and programs using the modified prospective approach. We had previously recognized compensation expense over the vesting period of all stock-based compensation
awards issued subsequent to January 1, 2002 based upon the fair value of the award as of the date of issuance. The adoption of FAS 123(R) did not have a material impact on our financial
results, as compared to prior periods.

We
recognized the following amounts in compensation expense and tax benefits for all of our stock-based awards and programs for the applicable years ended December 31 (in
thousands):

2007

2006

2005Compensation expense

$
2,122

$
1,670

$
1,584Tax benefit recognized


772


599


566


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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Stock Incentive Plans

Our 1996 Incentive Plan (the 1996 Stock Incentive Plan) provided for the grant of up to 650,000 shares of common stock through January 2006. The 1996 Stock
Incentive Plan permitted grants of stock options and restricted stock to qualified employees and permitted Directors to receive common stock in lieu of cash compensation for service as a Director. Our
2006 Stock Incentive Plan (the 2006 Incentive Plan) was adopted by shareholders at the annual meeting on April 28, 2005 and provides for grants of up to 650,000 shares of common stock
through January 2016. The 2006 Stock Incentive Plan permits grants of stock options and restricted stock to qualified employees and permits Directors to receive common stock in lieu of cash
compensation for service as a Director. The terms of the 2006 Incentive Plan are substantially the same as the 1996 Stock Incentive Plan. Awards made prior to 2006 were made under the 1996 Stock
Incentive Plan. Awards made on or after January 1, 2006 are made under the 2006 Incentive Plan. The terms and conditions of any option or stock grant are determined by the Board of Directors
Compensation Committee, within the provisions of these Stock Incentive Plans.

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards are granted to qualified individuals consisting of the right to receive a number of shares of common stock at the end of
the restricted period assuming performance criteria are met. The performance measure for the award is the total return to our shareholders over a three-year period compared with an
investor-owned utility peer group. The threshold level of performance under the 2005, 2006 and 2007 grants was set at the 20th percentile level of the peer group, target at the
50th percentile level, and the maximum at the 80th percentile level. Shares would be earned at the end of the three-year performance period as follows: 100% of
the target number of shares if the target level of performance is reached, 50% if the threshold is reached, and 200% if the percentile ranking is at or above the maximum, with the number of shares
interpolated between these levels. However, no shares would be payable if the threshold level is not reached.

For
the 2005 grants related to stock incentive plans and performance based restricted stock awards described above, the fair value of these stock awards was determined based on the
number of shares granted and the quoted price of our stock on the date of grant of $22.77. Upon adoption of FAS 123(R), the fair value of the estimated shares awarded under the 2006 and 2007
grants were estimated on the date of grant using a lattice-based option valuation model with the assumptions noted in the following table:

2007

2006Risk-free interest rate

5.09% to 4.88%

4.60% to 4.54%Expected volatility of Empire stock

16.6%

15.2%Expected volatility of peer group stock

18.9%

19.8%Expected dividend yield on Empire stock

5.55%

5.80%Expected forfeiture rates

3%

3%Plan cycle

3 years

3 yearsEDE percentile performance

25th

33rdFair value percentage

107.73%

108.13%Grant date

1/31/2007

2/01/2006Grant date fair value per share

$25.65

$24.04


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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Non-vested restricted stock awards (based on target number) as of December 31, 2007, 2006 and 2005 and changes during the year ended
December 31, 2007, 2006 and 2005 were as follows:

|                          |  | 2007   |   | 2006 |       | 2005
|------------------------- |  | ------ | - | ---- | ----- | ----
|
|Nonvested at January 1,   |  | 38,800 |   | $    | 22.25 |     
|Granted                   |  | 17,700 |   | $    | 23.81 |     
|Awarded                   |  | (7,598 | ) | $    | 21.79 |     
|Not awarded               |  | (5,502 | ) | $    |      |     
|                          |  |        |   |      |       |     
|Nonvested at December 31, |  | 43,400 |   | $    | 23.02 |     

At December 31, 2007, unamortized compensation expense related to estimated outstanding awards was $0.4 million.

Stock Options

Stock options are issued with an exercise price equal to the fair market value of the shares on the date of grant, become exercisable after three years and expire
ten years after the date granted. Participants' options that are not vested become forfeited when participants leave Empire except for terminations of employment under certain specified circumstances.
Dividend equivalent awards are also issued to the recipients of the stock options under which dividend equivalents will be accumulated for the three-year period until the option becomes
exercisable.

The
dividend equivalents are accumulated for the three-year period and are converted to shares of our common stock based on the fair market value of the shares on the date
converted. To be in compliance with Section 409A of the Internal Revenue Code added by the American Jobs Creation Act of 2004, the dividend equivalent awards were changed to vest and be payable
in fully vested shares of our common stock on the third anniversary of the grant date (conversion date) or at a change in control and not dependent upon the exercise of the related option. This
modification did not have a material impact on our financial statements.

A
summary of option activity under the plan during the year ended December 31, 2007, 2006 and 2005 is presented below:

|                            |  | 2007    |   | 2006 |       | 2005
|--------------------------- |  | ------- | - | ---- | ----- | ----
|
|Outstanding at January 1,   |  | 135,000 |   | $    | 22.21 |     
|Granted                     |  | 64,200  |   | $    | 23.81 |     
|Exercised                   |  | (50,000 | ) | $    | 21.79 |     
|                            |  |         |   |      |       |     
|Outstanding at December 31, |  | 149,200 |   | $    | 23.04 |     
|                            |  |         |   |      |       |     
|Exercisable, end of year    |  | 4,200   |   | $    | 21.79 |     
|                            |  |         |   |      |       |     

The aggregate intrinsic value at December 31, 2007, 2006 and 2005 was approximately $0.0 million, $0.3 million and $0.1 million,
respectively. The intrinsic value of the unexercised options is the difference between the Company's closing stock price on the last day of the period and the exercise price multiplied

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

by
the number of in-the-money options had all option holders exercised their options on the last day of the period.

The
weighted-average remaining contractual life of outstanding options at December 31, 2007, 2006 and 2005 was 7.6, 8.1 and 8.1 years, respectively. As of
December 31, 2007, this includes 4,200 shares at the weighted average price of $21.79, which are vested and exercisable. All others are non-vested. As of December 31,
2007, there was $0.3 million of unrecognized compensation expense. The range of exercise prices as of December 31, 2007 was $21.79  $23.81.

The
fair value of the options granted, which is amortized to expense over the option vesting period, has been determined on the date of grant using the methods and assumptions outlined
in the table below.

2007

2006

2005Stock Options
Valuation Methodology

Black-Scholes

Black-Scholes

Expanded
Black-ScholesWeighted average fair value of grants

$
2.38

$
1.65

$
4.38Risk-free interest rate


4.68
%

3.27
%

3.63
%Dividend yield(1)


5.33
%

6.16
%

0
%Expected volatility(2)


16.13
%

18.14
%

15.51
%Expected life in months


60


60


60Grant Date


1/31/07


2/1/06


2/3/05




Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (ESPP) permits the grant to eligible employees of options to purchase common stock at 90% of the lower of market value at date of
grant or at date of exercise. The lookback feature of this plan is valued at 90% of the Black-Scholes methodology plus 10% of the maximum subscription price. As of December 31, 2007, there were
480,812 shares available for issuance in this plan. The adoption of FAS 123(R) did not change the valuation of the options granted under this plan.

2007

2006

2005Subscriptions outstanding at December 31,


40,672


38,707


39,391Maximum subscription price

$
21.23
(1)
$
20.05

$
21.03Shares of stock issued


37,686


39,322


43,133Stock issuance price

$
20.05

$
19.62

$
18.00




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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Assumptions
for valuation of these shares are shown in the table below.

2007

2006

2005Weighted average fair value of grants

$
3.40

$
3.19

$
3.24Risk-free interest rate


4.98
%

5.02
%

3.25
%Dividend yield


5.43
%

5.75
%

5.5
%Expected volatility(1)


18.01
%

18.3
%

15.38
%Expected life in months


12


12


12Grant date


6/1/07


6/1/06


6/1/05




Stock Unit Plan for Directors

Our Stock Unit Plan for directors (Stock Unit Plan) provides a stock-based compensation program for directors. This plan enhances our ability to attract and
retain competent and experienced directors and allows the directors the opportunity to accumulate compensation in the form of common stock units. The Stock Unit Plan also provided directors the
opportunity to convert previously earned cash retirement benefits to common stock units. All eligible directors who had benefits under the prior cash retirement plan converted their cash retirement
benefits to common stock units.

A
total of 400,000 shares are authorized under this plan. Each common stock unit earns dividends in the form of common stock units and can be redeemed for shares of common stock.
The number of units granted annually is computed by dividing an annual credit (determined by the Compensation Committee) by the fair market value of our common stock on January 1 of the year
the units are granted. Common stock unit dividends are computed based on the fair market value of our stock on the dividend's record date. We record the related compensation expense at the time we
make the accrual for the directors' benefits as the directors provide services. At December 31, 2007, there were 97,231 shares accrued to directors' accounts and 356,206 shares
available for issuance under this plan.

2007

2006

2005Units granted for service

12,702

11,018

9,528Units granted for dividends

5,147

4,523

3,842Units redeemed for common stock

3,299

3,119

1,642


401(k) Plan and ESOP

Our Employee 401(k) Plan and ESOP (the 401(k) Plan) allows participating employees to defer up to 25% of their annual compensation up to an Internal Revenue
Service specified limit. We match 50% of each employee's deferrals by contributing shares of our common stock, with such matching contributions not to exceed 3% of the employee's eligible
compensation. We record the compensation expense at the time the quarterly matching contributions are made to the plan. At December 31, 2007, there were 52,092 shares available to be
issued.

2007

2006

2005Shares contributed

47,563

46,123

40,313


Dividends

Holders of our common stock are entitled to dividends, if, as and when declared by our Board of Directors out of funds legally available therefore subject to the
prior rights of holders of our outstanding

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

cumulative
preferred 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). Also, the EDE Mortgage and our Restated Articles contain certain dividend restrictions. The most restrictive 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 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. As of December 31, 2007, our level of earned surplus did not prevent us from issuing dividends. Absent an
amendment to the EDE Mortgage, we may not have sufficient earned surplus to pay our next quarterly dividend at the rate of $0.32 per share. As a result, we have commenced a consent solicitation to
amend the EDE Mortgage to increase the earned surplus basket under the EDE Mortgage by $10.75 million. We believe that the consent solicitation, which is scheduled to expire on March 11,
2008, will be successful. However, we can give no assurance that this will be the case.

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, 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, 2007, there were no such
restrictions on our ability to pay dividends.

6.     Preferred and Preference Stock

We have 2.5 million shares of preference stock authorized, including 0.5 million shares of Series A Participating Preference Stock, none of
which have been issued. We have 5 million shares of $10.00 par value cumulative preferred stock authorized. There was no preferred stock issued and outstanding at December 31, 2007 or
2006.

Preference Stock Purchase Rights

Our shareholder rights plan provides each of the common stockholders one Preference Stock Purchase Right (Right) for each share of common stock owned. Each 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
one-hundredth share, subject to adjustment. The Rights (other than those held by an acquiring person or group (Acquiring Person)), which expire July 25, 2010, will be exercisable
only if an Acquiring Person acquires 10% or more of our common stock or if certain other events occur. The Rights may be redeemed by us in whole, but not in part, for $0.01 per Right, prior to
10 days after the first public announcement of the acquisition of 10% or more of our common stock by an Acquiring Person. We had 33.5 million and 30.2 million Rights outstanding
at December 31, 2007 and 2006, respectively.

96

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In addition, upon the occurrence of a merger or other business combination, or an event of the type referred to in the preceding paragraph, holders of the Rights,
other than an Acquiring Person, will be entitled, upon exercise of a Right, to receive either our common stock or common stock of the Acquiring Person having a value equal to two times the exercise
price of the Right. Any time after an Acquiring Person acquires 10% or more (but less than 50%) of our outstanding common stock, our Board of Directors may, at their option, exchange part or all of
the Rights (other than Rights held by the Acquiring Person) for our common stock on a one-for-one basis.

7.     Long-Term Debt

At December 31, 2007 and 2006, the balance of long-term debt outstanding was as follows (in thousands):

|                                          |                                              | 2007                 |         | 2006 |        
|----------------------------------------- | -------------------------------------------- | -------------------- | ------- | ---- | -------
|Note payable to securitization trust(1)   |                                              | $                    | 50,000  |      | $      
|First mortgage bonds (EDE):               |                                              |                      |         |      |        
|81/8% Series due 2009                     |                                              |                      | 20,000  |      |        
|61/2% Series due 2010                     |                                              |                      | 50,000  |      |        
|7.20% Series due 2016                     |                                              |                      | 25,000  |      |        
|5.3% Pollution Control Series due 2013(2) |                                              |                      | 8,000   |      |        
|5.2% Pollution Control Series due 2013(2) |                                              |                      | 5,200   |      |        
|5.875% Series due 2037(3)                 |                                              |                      | 80,000  |      |        
|First mortgage bonds (EDG):               |                                              |                      |         |      |        
|6.82% Series due 2036(3)                  |                                              |                      | 55,000  |      |        
|                                          |                                              |                      |         |      |        
|                                          |                                              |                      | 243,200 |      |        
|Senior Notes, 7.05% Series due 2022(2)    |                                              |                      | 49,289  |      |        
|Senior Notes, 41/2% Series due 2013(3)    |                                              |                      | 98,000  |      |        
|Senior Notes, 6.70% Series due 2033(3)    |                                              |                      | 62,000  |      |        
|Senior Notes, 5.80% Series due 2035(3)    |                                              |                      | 40,000  |      |        
|Other                                     |                                              |                      | 499     |      |        
|                                          | Less unamortized net discount                |                      |         | (958 | )      
|                                          |                                              |                      |         |      |        
|                                          |                                              |                      | 542,030 |      |        
|                                          | Less current obligations of long-term debt   |                      |         |     |        
|                                          | Less current obligations under capital lease |                      |         | (150 | )      
|                                          |                                              |                      |         |      |        
|                                          |                                              | Total long-term debt |         | $    | 541,880
|                                          |                                              |                      |         |      |        

---

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Financing Activities

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.

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.

We
have an effective shelf registration statement with the SEC under which approximately $174.2 million of our common stock, unsecured debt securities, preference stock and first
mortgage bonds remain available for issuance. Of this amount, $120 million remains available of the original $200 million approved by the MPSC as 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.

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) are 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, 2007 would permit us to issue approximately $247.7 million of new first mortgage bonds based on
this test with an assumed interest rate of 6.5%. 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, 2007, we had retired bonds and net property additions which would enable the issuance of at least $565.5 million principal amount of bonds
if the annual interest requirements are met. As of December 31, 2007, we believe we are in compliance with all restrictive covenants of the EDE Mortgage.

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. At
December 31, 2007, we had property additions of $2.5 million. 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, 2007,
this test would not allow us to issue any new first mortgage bonds. However, our current financing plan does not contemplate the need for additional EDG first mortgage bonds.

The
carrying amount of our total debt exclusive of capital leases at December 31, 2007 was $541.5 million compared to a fair market value of approximately
$524.0 million. The 2006 carrying amount for total debt exclusive of capital leases approximated its fair market value. These estimates were based on the quoted market prices for the same or
similar issues or on the current rates offered to us for debt of the

98

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

same
remaining maturities. The estimated fair market value may not represent the actual value that could have been realized as of year-end or that will be realizable in the future.

|                                                  |                                  | Payments Due By Period
|------------------------------------------------- | -------------------------------- | ----------------------
|
|2008                                              |                                  | $                     
|2009                                              |                                  |                       
|2010                                              |                                  |                       
|2011                                              |                                  |                       
|2012                                              |                                  |                       
|Thereafter                                        |                                  |                       
|                                                  |                                  |                       
|                                                  | Total long-term debt obligations |                       
|                                                  |                                  |                       
|Less current obligations and unamortized discount |                                  |                       
|                                                  |                                  |                       
|                                                  | Total long-term debt             |                       
|                                                  |                                  |                       

8.     Short-Term Borrowings

At December 31, 2007, commercial paper comprised $33.0 million of short-term debt. Short-term commercial paper outstanding
and notes payable averaged $51.0 million and $39.6 million daily during 2007 and 2006, respectively, with the highest month-end balances being $81.0 million and
$77.1 million, respectively. The weighted average interest rates during 2007 and 2006 were 5.76% and 5.74% in each period. The weighted average interest rate of borrowings outstanding at
December 31, 2007 was 5.76%,

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 $40.5 million as of February 1, 2008.
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 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, 2007, 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 no outstanding borrowings under this agreement at
December 31, 2007, however, $33.0 million of the availability thereunder was used at such date to back up our outstanding commercial paper.

99

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9.     Retirement Benefits

We record retirement benefits in accordance with FAS 158 and have recorded the appropriate liabilities to reflect the unfunded status of our benefit plans,
with offsetting entries to a regulatory asset, because we believe it is probable that the unfunded amount of these plans will be afforded rate recovery. The tax effects of these entries, including the
tax benefit of the Medicare Part D subsidy, are reflected as deferred tax assets and liabilities and regulatory liabilities. All of the benefit plans have been measured as of
December 31, 2007, consistent with previous years. (See Note 1).

Pensions

Our noncontributory defined benefit pension plan includes all employees meeting minimum age and service requirements. The benefits are based on years of service
and the employee's average annual basic earnings. Annual contributions to the plan are at least equal to the minimum funding
requirements of ERISA. We also have a supplemental retirement program ("SERP") for designated officers of the Company, which we fund from Company funds as the benefits are paid.

We
expect there to be no contribution required under ERISA to the trust in order to maintain minimum funding levels in 2008. This could change in future years, however, based on actual
investment performance, changes in interest rates, any future pension plan funding, reform legislation and finalization of actuarial assumptions.

Expected
benefit payments are as follows (in millions):

Year

Payments from Trust2008

$
7.02009


7.52010


7.92011


8.42012


8.92013  2017


52.4


Other Postretirement Benefits (OPEB)

We provide certain healthcare and life insurance benefits to eligible retired employees, their dependents and survivors through trusts we have established.
Participants generally become eligible for retiree healthcare benefits after reaching age 55 with 5 years of service.

Our
funding policy is to contribute annually an amount at least equal to the revenues collected for the amount of postretirement benefit costs allowed in rates. Based on the performance
of the trust assets through December 31, 2007, we expect to be required to fund approximately $1.1 million in 2008.

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Estimated
benefit payments are as follows (in millions):

Year

Payments from Trust

Expected
Federal Subsidy2008

$
2.4

$
0.32009


2.7


0.32010


2.9


0.32011


3.2


0.42012


3.4


0.42013  2017


21.3


2.6


The following tables reflect the effect of the acquisition of the Missouri Gas assets from Aquila, Inc., on June 1, 2006, and set forth the
Company's benefit plans' projected benefit obligation, the fair value of the plans' assets and the funded status (in thousands).

Reconciliation of Projected Benefit Obligations:

|                                        |  | Pension |         | SERP |   | OPEB    |  
|--------------------------------------- |  | ------- | ------- | ---- | - | ------- | -
|
|Benefit obligation at beginning of year |  | $       | 136,260 |      | $ | 123,088 |  
|Service cost                            |  |         | 3,492   |      |   | 3,354   |  
|Interest cost                           |  |         | 8,238   |      |   | 7,368   |  
|Amendments                              |  |         | 3,832   |      |   |        |  
|Net actuarial (gain)/loss               |  |         | (5,191  | )    |   | (3,403  | )
|Plan participant's contribution         |  |         |        |      |   |        |  
|Benefits and expenses paid              |  |         | (6,278  | )    |   | (6,055  | )
|Federal subsidy                         |  |         |        |      |   |        |  
|Acquisition of Missouri gas             |  |         |        |      |   | 11,908  |  
|                                        |  |         |         |      |   |         |  
|Benefit obligation at end of year       |  | $       | 140,353 |      | $ | 136,260 |  
|                                        |  |         |         |      |   |         |  

Reconciliation of Fair Value of Plan Assets:

|                                               |  | Pension |         | SERP |   | OPEB    |  
|---------------------------------------------- |  | ------- | ------- | ---- | - | ------- | -
|
|Fair value of plan assets at beginning of year |  | $       | 126,812 |      | $ | 109,276 |  
|Actual return on plan assets  gain            |  |         | 11,405  |      |   | 11,137  |  
|Employer contribution                          |  |         |        |      |   |        |  
|Benefits paid                                  |  |         | (6,278  | )    |   | (6,055  | )
|Plan participant's contribution                |  |         |        |      |   |        |  
|Federal subsidy                                |  |         |        |      |   |        |  
|Acquisition of Missouri gas                    |  |         |        |      |   | 12,454  |  
|                                               |  |         |         |      |   |         |  
|Fair value of plan assets at end of year       |  | $       | 131,939 |      | $ | 126,812 |  
|                                               |  |         |         |      |   |         |  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Reconciliation of Funded Status:

|                              |  | Pension |          | SERP |   | OPEB     |  
|----------------------------- |  | ------- | -------- | ---- | - | -------- | -
|
|Fair value of plan assets     |  | $       | 131,939  |      | $ | 126,812  |  
|Projected benefit obligations |  |         | (140,353 | )    |   | (136,260 | )
|                              |  |         |          |      |   |          |  
|Funded status                 |  | $       | (8,414   | )    | $ | (9,448   | )
|                              |  |         |          |      |   |          |  

The employee pension plan accumulated benefit obligation at December 31, 2007, and 2006, is presented in the following table (in thousands):

Pension Benefits

SERP2007

2006

2007

2006Accumulated benefit obligation

$
123,310

$
118,633

$
1,304

$
1,158


Amounts recognized in the balance sheet consist of (in thousands):

|                                                    |  | Pension |       | SERP |   | OPEB 
|--------------------------------------------------- |  | ------- | ----- | ---- | - | -----
|
|Other current liabilities                           |  | $       |      |      | $ |     
|Pension and other postretirement benefit obligation |  | $       | 8,414 |      | $ | 9,448

Net periodic benefit pension cost for 2007, 2006 and 2005, some of which is capitalized as a component of labor cost and some of which is deferred as a regulatory
asset, is comprised of the following components (in thousands):

Net Periodic Pension Benefit Cost:

|                               |                                    | Pension |         | OPEB  |  
|------------------------------ | ---------------------------------- | ------- | ------- | ----- | -
|
|Service cost                   |                                    | $       | 3,492   |       | $
|Interest cost                  |                                    |         | 8,238   |       |  
|Expected return on plan assets |                                    |         | (10,300 | )     |  
|Amortization of:               |                                    |         |         |       |  
|                               | Unrecognized transition obligation |         |         |      |  
|                               | Prior service cost                 |         |         | 588   |  
|                               | Actuarial loss                     |         |         | 2,601 |  
|                               |                                    |         |         |       |  
|Net periodic benefit cost      |                                    | $       | 4,619   |       | $
|                               |                                    |         |         |       |  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Net Periodic Pension Benefit Cost:

|                               |                                    | SERP
|------------------------------ | ---------------------------------- | ----
|
|Service cost                   |                                    | $   
|Interest cost                  |                                    |     
|Expected return on plan assets |                                    |     
|Amortization of:               |                                    |     
|                               | Unrecognized transition obligation |     
|                               | Prior service cost                 |     
|                               | Actuarial loss                     |     
|                               |                                    |     
|Net periodic benefit cost      |                                    | $   
|                               |                                    |     

Our net periodic pension benefit cost, exclusive of capitalized and deferred amounts, net of tax, as a percentage of net income for 2007, 2006 and 2005 was 6.9%,
6.0% and 10.7%, respectively.

Upon
adoption of FAS 158 on December 31, 2006, we recorded the appropriate liabilities to reflect the unfunded status of our benefit plans, with offsetting entries to a
regulatory asset, because we believe it is probable that the unfunded amount of these plans will be afforded rate recovery. The tax effect of these entries, including the tax benefit of the Medicare
Part D subsidy, are reflected as deferred tax assets and liabilities and regulatory liabilities.

The
initial adoption had the following increase or (decrease) effect on our balance sheet accounts at December 31, 2006 (in millions):

Pension and other post-retirement liabilities

$
15.1Prepaid pension assets

$
(14.9
)Regulatory assets

$
30.0Deferred tax assets

$
17.9Deferred tax liabilities

$
11.5Regulatory liabilities

$
6.4


The tables below present the activity in the regulatory asset accounts for the year (in thousands).

|        |  |   |        | Amount Recognized |   |        |  
|------- |  | - | ------ | ----------------- | - | ------ | -
|
|Pension |  | $ | 24,330 |                   | $ | (6,296 | )
|SERP    |  | $ | 1,270  |                   | $ | 95     |  
|OPEB    |  | $ | 4,400  |                   | $ | (4,028 | )

The following table presents the amount of net actuarial gains/losses, transition obligations/assets and prior period service costs in regulatory assets not yet
recognized as a component of net periodic benefit cost. It also shows the amounts expected to be recognized in the subsequent year. The following table

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

presents
those items for the employee pension plan and other benefits plan at December 31, 2007, and the subsequent twelve-month period (in thousands):

|                              |       | Pension Benefits |        | SERP   |   | OPEB  |      
|----------------------------- | ----- | ---------------- | ------ | ------ | - | ----- | -----
|
|Net actuarial loss            |       | $                | 13,754 |        | $ | 1,615 |      
|Transition obligation/(asset) |       | $                |       |        | $ |      |      
|Prior service cost (benefit)  |       | $                | 4,923  |        | $ | 744   |      
|                              |       |                  |        |        |   |       |      
|                              | Total |                  | $      | 18,677 |   | $     | 2,359
|                              |       |                  |        |        |   |       |      

The measurement date used to determine the pension and other postretirement benefits is December 31. The assumptions used to determine the benefit
obligation and the periodic costs are as follows:

Weighted-average assumptions used to determine the benefit obligation as of December 31:

|                              |  | Pension Benefits |   | OPEB |  
|----------------------------- |  | ---------------- | - | ---- | -
|
|Discount rate                 |  | 6.40             | % | 5.90 | %
|Rate of compensation increase |  | 4.50             | % | 4.25 | %

Weighted-average assumptions used to determine the net benefit cost (income) as of January 1:

|                               |  | Pension Benefits |   | OPEB |  
|------------------------------ |  | ---------------- | - | ---- | -
|
|Discount rate                  |  | 5.90             | % | 5.65 | %
|Expected return on plan assets |  | 8.50             | % | 8.50 | %
|Rate of compensation increase  |  | 4.25             | % | 4.00 | %

To determine the discount rate assumption used in our December 31, 2007 and December 31, 2006 plan obligation estimates, we used an interest rate
yield curve that enables companies to make judgments pursuant to Emerging Issues Task Force EITF Topic No. D-36, "Selection of Discount Rates Used for Measuring Defined Benefit
Pension Obligations and Obligations of Post Retirement Benefit Plans Other Than Pensions." The yield curve is constructed based on the yields on over 500 high-quality,
non-callable corporate bonds with maturities between zero and thirty years. A theoretical spot rate curve constructed from this yield curve is then used to discount
the annual benefit cash flows of our pension plan and develop a single-point discount rate matching the plan's payout structure.

The
expected long-term rate of return assumption was based on historical return and adjusted to estimate the potential range of returns for the current asset allocation.

The
assumed 2007 cost trend rate used to measure the expected cost of healthcare benefits and benefit obligation is 8.50%. Each trend rate decreases 0.50% through 2014 to an ultimate
rate of 5.0% in 2014 and subsequent years.

The
effect of a 1% increase in each future year's assumed healthcare cost trend rate on the current service and interest cost components of the net periodic benefit cost is
$0.5 million, increasing the service and interest cost from $5.1 million to $5.6 million. The effect on the accumulated postretirement benefit obligation is $7.8 million,
increasing the obligation from $56.5 million to $64.3 million. The effect of a 1%

104

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

decrease
in each future year's assumed healthcare cost trend rate for these components is $0.4 million which would decrease the current service and interest cost from $5.1 million to
$4.7 million. The effect on the accumulated benefit obligation is $6.8 million, decreasing the obligation from $56.5 million to $49.7 million.

Allocation of Plan Assets

|                  |       | % of Fair Value as of December 31,
|----------------- | ----- | ----------------------------------
|
|
|
|Equity securities |       | 71.8                              
|Debt securities   |       | 28.2                              
|Other             |       | 0                                 
|                  |       |                                   
|                  | Total |                                   

We utilize fair value in determining the market-related values for the different classes of our pension plan assets. The market-related value is determined based
on smoothing actual asset returns in excess of (or less than) expected return on assets over a 5-year period.

The
Company's primary investment goals for pension fund assets are based around four basic elements:



The
Company believes that it is appropriate for the pension fund to assume a moderate degree of investment risk with diversification of fund assets among different classes (or types) of
investments, as appropriate, as a means of reducing risk. Although the pension fund can and will tolerate some variability in market value and rates of return in order to achieve a greater
long-term rate of return, primary emphasis is placed on preserving the pension fund's principal. Full discretion is delegated to the investment managers to carry out investment policy
within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee.

105

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Permissible Investments

Listed below are the investment vehicles specifically permitted:

Permissible Investments

Equity Oriented

Fixed Income Oriented and Real Estate
Common Stocks


Bonds
Preferred Stocks


GICs, BICs
Convertible Preferred Stocks


Corporate Bonds (minimum quality rating
Convertible Bonds


of Baa or BBB)
Covered Options


Cash-Equivalent Securities (e.g., U.S.
Hedged Equity Funds of Funds


T-Bills, Commercial Paper, etc.)
Certificates of Deposit in institutions withFDIC/FSLIC protection
Money Market Funds/Bank STIF Funds
Real Estate  Publicly Traded


The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

Those
investments prohibited by the Investment Committee without prior approval are:

Prohibited Investments Requiring Pre-approval


Privately Placed Securities


Warrants
Commodities Futures


Short Sales
Securities of Empire District


Index Options
Derivatives


Allocation of Plan Assets

|                |       | % of Fair Value as of December 31,
|--------------- | ----- | ----------------------------------
|
|
|
|Cash equivalent |       | 3.2                               
|Fixed income    |       | 40.3                              
|Equities        |       | 56.5                              
|                |       |                                   
|                | Total |                                   

We utilize fair value in determining the market-related values for the different classes of our postretirement plan assets. The market-related value is determined
based on smoothing actual asset returns in excess of (or less than) expected return on assets over a 5-year period.

The
Company's primary investment goals for the component of the fund used to pay current benefits are liquidity and safety. The primary investment goals for the component of the fund
used to accumulate funds to provide for payment of benefits after the retirement of plan participants are preservation of the fund with a reasonable rate of return.

The
Company's guideline in the management of this fund is to endorse a long-term approach, but not expose the fund to levels of volatility that might adversely affect the
value of the assets. Full discretion is

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

delegated
to the investment managers to carry out investment policy within stated guidelines. The guidelines and performance of the managers are monitored by the Company's Investment Committee.

Listed
below are the investment vehicles specifically permitted:

Permissible Investments

Equity

Fixed Income
Common Stocks


Cash-Equivalent Securities with a maturity
Preferred Stocks


of one-year or less
Bonds
Money Market Funds / Bank STIF Funds
Certificates of Deposit in institutions with FDIC protection
Corporate Bonds (minimum quality rating of A)


The above assets can be held in commingled (mutual) funds as well as privately managed separate accounts.

Listed
below are those investments prohibited by the Investment Committee:

Prohibited Investments


Privately Placed Securities


Margin Transactions
Commodities Futures


Short Sales
Securities of Empire District


Index Options
Derivatives


Real Estate and Real Property
Instrumentalities in violation of the Prohibited Transactions Standards of ERISA


Restricted Stock


107

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10.   Income Taxes

Income tax expense components for the years ended December 31 are as follows (in thousands):

2007

2006

2005Current income taxes:Federal

$
(3,788
)
$
18,410

$
5,113State


(540
)

2,630


923Total


(4,328
)

21,040


6,036Deferred income taxes:Federal


16,895


1,091


6,280State


2,407


330


847Total


19,302


1,421


7,127Investment tax credit amortization


(530
)

(530
)

(540
)Income tax from continuing operations


14,444


21,931


12,623Income tax from discontinued operations


39


(461
)

(723
)Total income tax expense

$
14,483

$
21,470

$
11,900


Deferred Income Taxes

Deferred tax assets and liabilities are reflected on our consolidated balance sheet as follows (in thousands):

December 31,Deferred Income Taxes2007

2006Current deferred tax liability (included in other current liabilities)

$
381

$
911Non-current deferred tax liabilities, net


165,989


140,838Net deferred tax liabilities

$
166,370

$
141,749


108

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Temporary differences related to deferred tax assets and deferred tax liabilities are summarized as follows (in thousands):

December 31,Temporary Differences2007

2006Deferred tax assets:Disallowed plant costs

$
1,218

$
1,318Gains on hedging transactions


1,673


1,738Plant related basis differences


11,881


10,531Regulated liabilities related to income taxes


4,793


5,730Pensions and other post-retirement benefits


20,036


24,924Other


695


702Total deferred tax assets

$
40,296

$
44,943Deferred tax liabilities:Depreciation, amortization and other plant related differences

$
145,340

$
127,817Regulated assets related to income


30,947


27,893Loss on reacquired debt


5,504


6,008Accumulated other comprehensive income


6,790


5,411Losses on hedging transactions


1,036


1,157Pensions and other post-retirement benefits


8,048


16,167Deferred ice storm expenses


5,912


Amortization of intangibles


1,613


533Other


1,476


1706Total deferred tax liabilities


206,666


186,692Net deferred tax liabilities

$
166,370

$
141,749


Effective Income Tax Rates

The difference between income taxes and amounts calculated by applying the federal legal rate to income tax expense for continuing operations were as follows:

Effective Income Tax Rates

2007

2006

2005Federal statutory income tax rate

35.0
%
35.0
%
35.0
%Increase in income tax rate resulting from:State income tax (net of federal benefit)

3.1

3.1

3.1Investment tax credit amortization

(1.1
)
(0.9
)
(1.5
)Effect of ratemaking on property related differences

(4.1
)
(1.3
)
(1.0
)Other

(2.6
)
(0.6
)
(2.2
)Effective income tax rate

30.3
%
35.3
%
33.4
%


109

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Unrecognized Tax Benefits

AmountUnrecognized tax benefits  01/01/07

$
219,000The gross amounts of increases and decreases in unrecognized tax benefits as a result of tax positions taken during the current period


109,000Unrecognized tax benefits  12/31/07

$
328,000


If unrecognized tax benefits are recognized, the effective tax rate would change from 30.3% to 29.7%. The Company did not recognize any interest or penalties
during 2007 related to unrecognized tax benefits in other expenses or on the balance sheet. The Company does not expect any significant changes to our unrecognized tax benefits over the next twelve
months.

11.   Commonly Owned Facilities

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. At December 31, 2007 and 2006, our property, plant and equipment accounts
included the cost of our ownership interest in the plant of $49.4 million and $50.5 million, respectively, and accumulated depreciation of $34.0 million and $36.3 million,
respectively. Expenditures recorded for our portion of ownership were $8.4 million and $7.5 million for 2007 and 2006, respectively, excluding depreciation expenses. 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 completed, currently estimated to be
late in the fourth quarter of 2008. 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 and Aquila own 70%
and 18% respectively, of the Unit. KCP&L operates the unit for the joint owners. On June 13, 2006, we entered into an agreement with KCP&L to purchase a 12% undivided ownership interest in the
new coal-fired Iatan 2.

110

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We and Westar Generating, Inc ("WGI"), a subsidiary of Westar Energy, Inc., share joint ownership of a 500-megawatt combined cycle unit at the
State Line Power Plant (the "State Line Combined Cycle Unit"). We are responsible for the operation and maintenance of the State Line Combined Cycle Unit, and are entitled to 60% of the available
capacity and are responsible for approximately 60% of its costs. At December 31, 2007 and 2006, our property, plant and equipment accounts include the cost of our ownership interest in the unit
of $154.4 million and $154.2 million, respectively, and accumulated depreciation of $31.5 million and $27.0 million, respectively. Expenditures recorded (as operating and
maintenance expenses) for our portion of ownership were $68.5 million and $49.3 million for 2007 and 2006, respectively, excluding depreciation.

All
of the dollar amounts listed above represent our ownership share of costs. Each participant must provide their own financing.

12.   Commitments and Contingencies

We are a party to various claims and legal proceedings arising out of the normal course of our business. Management regularly analyzes this information, and has
provided accruals for any liabilities, in accordance with the guidelines of Statement of Financial Accounting Standards SFAS 5, "Accounting for Contingencies" (FAS 5). In the opinion of
management, it is not probable, given the company's defenses, that the ultimate outcome of these claims and lawsuits will have a material adverse affect upon our financial condition, or results of
operations or cash flows.

Coal, Natural Gas and Transportation Contracts

We have entered into long and short-term agreements to purchase coal and natural gas for our energy supply and natural gas operations. Under these
contracts, the natural gas supplies are divided into firm physical commitments and derivatives that are used to hedge future purchases. The firm physical gas and transportation commitments total
$47.5 million for 2008, $47.8 million for 2009 through 2010, $46.2 million for 2011 through 2012 and $72.4 million for 2013 and beyond. In the event that this gas cannot be
used at our plants, the gas would be liquidated at market price.

We
have coal supply agreements and transportation contracts in place to provide for the delivery of coal to the plants. These contracts are written with Force Majeure clauses that enable
us to reduce tonnages or cease shipments under certain circumstances or events. These include mechanical or electrical maintenance items, acts of God, war or insurrection, strikes, weather and other
disrupting events. This reduces the risk we have for not taking the minimum requirements of fuel under the contracts. Due to the extended Asbury maintenance outage, we have issued force majeure
notices to our Western coal suppliers and to the railroads suspending Western coal shipments during the outage. This relieves us of our contractual obligations to receive shipments of coal to the
extent caused by the Asbury outage. The minimum requirements are $20.9 million for 2008 and $29.3 million for 2009 through 2010.

Purchased Power

We currently supplement our on-system generating capacity with purchases of capacity and energy from other utilities in order to meet the demands of
our customers and the capacity margins applicable to us under current pooling agreements and National Electric Reliability Council (NERC) rules.

We
have contracted with Westar Energy for the purchase of capacity and energy through May 31, 2010. Commitments under this contract total approximately $39.1 million
through May 31, 2010.

111

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We
also have a long term (30 year) agreement for the purchase of capacity from the Plum Point Energy Station, 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 2010. We have the option to convert the 50 megawatts covered by the
purchased power agreement into an ownership interest in 2015. Commitments under this contract total approximately $48.0 million through June 30, 2015.

We
have entered into 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 to be located in Cloud County, Kansas and a 20-year contract with Elk River Windfarm, LLC, owned
by PPM Energy, to purchase the energy generated at the 150-megawatt Elk River Windfarm located in Butler County, Kansas. Although these agreements are considered operating leases under
GAAP, payments for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations
discussed below.

New Construction

On March 14, 2006, we 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. The estimated cost is approximately $86.5 million, excluding AFUDC. In
addition, we entered into an agreement with Kansas City Power & Light (KCP&L) on June 13, 2006 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. Construction began in the spring of 2006 with completion scheduled for 2010. We expect our
share of the Iatan 2 construction costs will range from approximately $183.6 million to $200.5 million, excluding AFUDC.

Leases

On June 25, 2007, we entered into a 20-year purchased power agreement with Cloud County Windfarm, LLC, owned by Horizon Wind Energy,
Houston, Texas. The agreement provides for a 20-year term commencing with the commercial operation date, which is expected to be about January 1, 2009. We will begin taking delivery
of the energy at that time. Pursuant to the terms of
the agreement, we will purchase all of the output from the approximately 105-megawatt Phase 1 Meridian Way Wind Farm to be located in Cloud County, Kansas. We do not own any portion
of the windfarm. Annual payments are contingent upon output of the facility and can range from zero to a maximum of approximately $14.6 million based on a 20-year average cost.

On
December 10, 2004, we entered into a 20-year contract with Elk River Windfarm, LLC to purchase the energy generated at the 150-megawatt Elk River
Windfarm located in Butler County, Kansas. We have contracted to purchase approximately 550,000 megawatt-hours of energy per year, or approximately 10% of our annual supply under the contract, which
was declared commercial on December 15, 2005. We do not own any portion of the windfarm. Payments for wind energy from the Elk River Windfarm are contingent upon output of the facility. Annual
payments can run from zero to a maximum of approximately $16.9 million based on a 20-year average cost.

Payments
for these wind agreements are recorded as purchased power expenses, and, because of the contingent nature of these payments, are not included in the operating lease obligations
shown below.

We
also currently have short-term operating leases for two unit trains to meet coal delivery demands and garage and office facilities for our electric segment and six service
center properties for our gas segment. In addition we have a five-year capital lease for telephone equipment.

112

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The
gross amount of assets recorded under capital leases total $1.3 million.

Our
lease obligations over the next five years are as follows (in thousands):

Capital Leases2008

$
2882009


2882010


2412011


3Thereafter


Total minimum payments

$
820Less amount representing maintenance


274Net minimum lease payments


546Less amount representing interest


47Present value of net minimum lease payments

$
499Operating Leases2008

$
1,5032009


7122010


3722011


3192012


224Thereafter


674Total minimum payments

$
3,804


Expenses incurred related to operating leases were $1.4 million, $0.9 million and $0.7 million for 2007, 2006, and 2005, respectively. The
accumulated amount of amortization for our capital leases was $0.2 million at December 31, 2007.

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 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). The Asbury Plant became an affected unit under the 1990 Amendments for SO2 on January 1, 1995 and for NOx as a Group 2 cyclone-fired
boiler on January 1, 2000. The Iatan Plant became an affected unit for both SO2 and NOx on January 1, 2000. The Riverton Plant became an affected unit for NOx in November 1996 and for
SO2 on January 1, 2000. The State Line Plant became an affected unit for SO2 and NOx on January 1, 2000.

113

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Units
3 and 4 at the Empire Energy Center became affected units for both SO2 and NOx in April 2003. The new Riverton Unit 12 became an affected unit in January 2007.

SO2 Emissions.Under the 1990 Amendments, the amount of SO2 an affected unit can emit is
regulated. Each existing affected unit has been awarded a specific number of emission allowances, each of which allows the holder to emit one ton of SO2. Utilities covered by the 1990 Amendments must
have emission allowances equal to the number of tons of SO2 emitted during a given year by each of their affected units. 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 awarded to each affected unit and sells those emission allowances
through a direct auction. We receive compensation from the EPA for the sale of these withheld allowances.

Our
Asbury, Riverton (other than the gas-fired combustion turbines) and Iatan Plants 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 do not receive 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 2007, the combined actual SO2 allowance need for all affected plant facilities
exceeded the number of allowances awarded to us by the EPA. Although the actual reconciliation of SO2 allowances does not occur until March 1 of each year, we had approximately 24,000 banked
SO2 allowances at December 31, 2007 as compared to 31,000 at December 31, 2006. We project that our 2008 emissions will again exceed the number of allowances awarded by the EPA. Based on
current SO2 allowance usage projections, we expect to exhaust our banked allowances by the end of 2010.

Once
our SO2 allowance bank is exhausted, we will need to purchase additional SO2 allowances or build a scrubber at our Asbury Plant. Based on current and projected SO2 allowance prices
and high-level estimated 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. In addition, projected engineering and construction timeframes for a new scrubber make it
unfeasible at this time to construct a scrubber by the end of 2010.

On
July 14, 2004, we filed an application with the MPSC seeking an order authorizing us to implement a plan for the management, sale, exchange, transfer or other disposition of
our SO2 emission allowances issued by the EPA. On 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 swap banked allowances for future vintage allowances and/or monetary value and, in extreme market conditions, to sell SO2 allowances
outright for monetary value. The Stipulation and Agreement became effective March 11, 2005, although we have not yet swapped or sold any allowances. Our banked allowances are not assigned a
cost value. The allowances are removed from inventory on a FIFO basis.

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.

114

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THE EMPIRE DISTRICT ELECTRIC COMPANY

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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 2007, approximately 2,651
tons of TDF were burned. This is equivalent to 265,100 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. However, 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 and additional NOx controls are not required.

NOx
is further regulated as described in the Clean Air Interstate Rule below.

Clean Air Interstate Rule (CAIR)

The EPA issued its final CAIR on March 10, 2005. CAIR governs NOx and SO2 emissions from fossil fueled units greater than 25 megawatts and will affect 28
states, including Missouri, where our Asbury, Energy Center, State Line and Iatan Plants are located and Arkansas where the future Plum Point Energy Station will be located. Kansas is not included in
CAIR and our Riverton Plant will not be affected.

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 for approval. The Missouri SIP was approved
and became effective on December 14, 2007. We will receive our full allotment of allowances as published in the Missouri CAIR Rule. The Arkansas CAIR SIP has been approved but not finalized.
Until the Arkansas SIP is finalized by the EPA, we cannot definitively determine the allowed emissions of ozone season NOx for the Plum Point Energy Station in Arkansas. However, based on the SIP for
Missouri and the approved SIP for Arkansas, it appears 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 compared to
our non-CAIR Kansas units beginning in 2010. 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 help meet anticipated CAIR requirements and to meet air permit requirements for Iatan Unit 2, pollution control equipment is being installed on Iatan Unit 1 which will be
completed around the end of 2008. This equipment includes a Selective Catalytic Reduction (SCR) system, a Flue Gas Desulphurization (FGD) system and a baghouse, with our share of the capital cost
estimated at $46 million, excluding AFUDC. Of this amount, approximately $3.9 million was incurred in 2006 and $12.1 million in 2007. Approximately $26.7 million in 2008,
$1.4 million in 2009 and $0.3 million in 2010 are included in our current capital expenditures budget. This project was also included as part of our Experimental Regulatory Plan approved
by the MPSC.

Also
to help meet anticipated CAIR requirements, we constructed an SCR at Asbury during the fall of 2007 and placed it in service in early 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 also included as part of our
Experimental Regulatory Plan approved by the MPSC.

Additional
pollution control equipment to comply with CAIR may become economically justified at the Asbury Plant sometime prior to 2015 and may include an FGD scrubber to control SO2 and
a baghouse at an estimated capital cost of $100 million.

115

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 for Phase 1 were scheduled to go into effect January 1, 2010 and remain in effect until January 1, 2018. Beginning January 1, 2018,
more restrictive mercury emission limits were scheduled to go into effect for Phase 2 of CAMR. These regulations were challenged in the U.S. Court of Appeals for the District of Columbia
Circuit by a group of states led by New Jersey. On February 8, 2008, the Court of Appeals issued its opinion and vacated the EPA's CAMR regulations. The EPA is required to reconsider the
regulation of mercury under Section 112 of the CAA. At this point it is too early to determine the effects of this ruling.

The
CAMR was not directed to specific generation units, but instead, required the states (including Missouri, Kansas and Arkansas) to develop SIPs to comply with specific mercury
state-wide annual budgets. Missouri, Kansas and Arkansas have finalized their respective regulations and submitted their SIPs to the EPA. The proposed SIPs for all states include allowance
trading programs for mercury that could allow compliance without additional capital expenditures.

Based
on CAMR, we installed a mercury analyzer at Asbury during late 2007 and scheduled the installation of two mercury analyzers at Riverton during 2008 in order to verify our mercury
emissions and to meet the compliance date of January 1, 2009 for mercury analyzers and the Phase 1 mercury emission compliance date of January 1, 2010.

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. Several bills addressing climate change have been
introduced in the U.S. Congress and, 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. Various proposals in the U.S. Congress
could require us to purchase offsets or allowances for some or all of our CO2 emissions, or otherwise affect us based on the amount of CO2 we generate. 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.

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 State Line permit was renewed in May 2007. The Energy Center permit was renewed in September 2005 and the Asbury Plant permit was renewed in December 2005.

The
Riverton Plant is affected by final regulations for Cooling Water Intake Structures issued under the Clean Water Act Section 316(b) Phase II. The regulations became
final on February 16, 2004 and require the submission of a Comprehensive Demonstration Study with the permit renewal in 2008. A Proposal for Information Collection (PIC) has been approved by
the Kansas Department of Health and Environment (KDHE). Aquatic sampling commenced in April 2006 in accordance with the PIC and was completed in August 2007. Analysis of the sampling and a summary
report will be completed during the first half of 2008. On January 25, 2007, the United States Court of Appeals for the Second Circuit

116

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

remanded
key sections of the EPA's February 16, 2004 regulations. On July 9, 2007, the EPA suspended the regulation and is expected to revise and re-propose the regulation by
December 2008. If this occurs, we will monitor the EPA revision process and comment appropriately. Data collection and analysis will continue under the PIC and will be completed as needed to limit
increased costs, if any, due to the EPA's suspension and revision of the regulation. The permit renewal application will be prepared and submitted as scheduled following KDHE guidance. Under the
initial 316(b) regulations, we did not expect costs associated with compliance to be material. We will assess costs under revised rules when they are complete.

Other.Under Title V of the 1990 Amendments, we must obtain site operating permits for each of our plants from the
authorities in the state in which the plant is located. These permits, which are valid for five years, regulate the plant site's total 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 MDNR issues the renewed permits. A Compliance
Assurance Monitoring (CAM) plan is required by the renewed permit for Asbury. We estimate that the capital costs associated with the CAM plan will not exceed $2 million.

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 completed, currently estimated to be late in the fourth quarter of 2008.

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 is listed in the MDNR Registry of Confirmed Abandoned or Uncontrolled Hazardous Waste Disposal Sites in Missouri. Site #2 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. This estimated liability 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 Statement of
Financial Accounting Standards No. 71  "Accounting for the Effects of Certain Types of Regulation" (FAS 71).

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THE EMPIRE DISTRICT ELECTRIC COMPANY

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13.   Segment Information

We operate our business as three segments: electric, gas and other. As part of our electric segment, we also provide water service to three towns in Missouri. The
Empire District Gas Company is our wholly owned subsidiary formed to hold the Missouri Gas assets acquired from Aquila, Inc. on June 1, 2006. The other segment consists of our
non-regulated businesses, primarily a subsidiary for our fiber optics business.

As
discussed in "Note 18  Discontinued Operations", we sold our controlling 52% interest in MAAP to other current owners on August 31, 2006. MAPP is a
company that specialized in close-tolerance custom manufacturing for the aerospace, electronics, telecommunications and machinery industries. We also sold our 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. For financial reporting purposes, all of these businesses have been classified as a discontinued operation and are not included in our segment information as shown below (in
thousands).

|                                         |  | For the year ended December 31,
|---------------------------------------- |  | -------------------------------
|
|
|Statement of Income Information:         |  |                                
|Revenues                                 |  | $                              
|Depreciation and amortization            |  |                                
|Federal and state income taxes           |  |                                
|Operating income                         |  |                                
|Interest income                          |  |                                
|Interest expense                         |  |                                
|Income from AFUDC, (debt and equity)     |  |                                
|Income (loss) from continuing operations |  |                                
|Capital Expenditures                     |  | $                              
|
|
|Statement of Income Information:         |  |                                
|Revenues                                 |  | $                              
|Depreciation and amortization            |  |                                
|Federal and state income taxes           |  |                                
|Operating income                         |  |                                
|Interest income                          |  |                                
|Interest expense                         |  |                                
|Income from AFUDC, (debt and equity)     |  |                                
|Income (loss) from continuing operations |  |                                
|Capital Expenditures(1)                  |  | $                              

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|                                         |  | 2005
|---------------------------------------- |  | ----
|
|Statement of Income Information:         |  |     
|Revenues                                 |  | $   
|Depreciation and amortization            |  |     
|Federal and state income taxes           |  |     
|Operating income                         |  |     
|Interest income                          |  |     
|Interest expense                         |  |     
|Income from AFUDC, (debt and equity)     |  |     
|Income (loss) from continuing operations |  |     
|Capital Expenditures                     |  | $   

---

|                           |  | December 31,
|-------------------------- |  | ------------
|
|
|Balance Sheet Information: |  |             
|Total assets               |  | $           
|
|
|
|Balance Sheet Information: |  |             
|Total assets               |  | $           

---

119

---



THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14.   Selected Quarterly Information (Unaudited)

The following is a summary of quarterly results for 2007 and 2006 (dollars in thousands except per share amounts):

|                                                     |  | Quarters |        
|---------------------------------------------------- |  | -------- | -------
|
|
|Operating revenues                                   |  | $        | 125,650
|Operating income                                     |  |          | 11,913 
|Income from continuing operations                    |  | $        | 4,531  
|Income from discontinued operations                  |  |          | (31    
|                                                     |  |          |        
|Net Income                                           |  | $        | 4,500  
|Basic earnings per share  continuing operations     |  | $        | 0.15   
|Basic earnings per share  discontinued operations   |  |          |       
|                                                     |  |          |        
|Basic Earning Per Share                              |  | $        | 0.15   
|Diluted earnings per share  continuing operations   |  | $        | 0.15   
|Diluted earnings per share  discontinued operations |  |          |       
|                                                     |  |          |        
|Diluted Earnings Per Share                           |  | $        | 0.15   
|                                                     |  |          |        
|
|
|
|Operating revenues                                   |  | $        | 83,658 
|Operating income                                     |  |          | 9,323  
|Income from continuing operations                    |  | $        | 2,114  
|Income from discontinued operations                  |  |          | (502   
|                                                     |  |          |        
|Net Income                                           |  | $        | 1,612  
|Basic earnings per share  continuing operations     |  | $        | 0.08   
|Basic earnings per share  discontinued operations   |  |          | (0.02  
|                                                     |  |          |        
|Basic Earning Per Share                              |  | $        | 0.06   
|Diluted earnings per share  continuing operations   |  | $        | 0.08   
|Diluted earnings per share  discontinued operations |  |          | (0.02  
|                                                     |  |          |        
|Diluted Earnings Per Share                           |  | $        | 0.06   

The sum of the quarterly earnings per share of common stock may not equal the earnings per share of common stock as computed on an annual basis due to rounding.

In
the fourth quarter of 2007, we experienced a net loss of $0.4 million, or ($0.01) per share compared to fourth quarter 2006 earnings of $8.2 million, or $0.27 per share.
Total revenues increased approximately $8.5 million (8.0%) for the fourth quarter of 2007 as compared to the fourth quarter of 2006 primarily due to the Missouri rate increase. However, this
was offset by increased operating expenses, including fuel and purchased power (approximately $17.5 million) primarily relating to an extended outage at our Asbury plant. Depreciation expense
increased (approximately $3.4 million), along with other operating and maintenance costs which increased approximately $3.0 million, of which $1.5 million was December ice storm
expense.

120

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15.   Risk Management and Derivative Financial Instruments

We utilize derivatives to help manage our natural gas commodity market risk resulting from purchasing natural gas, to be used as fuel in our electric business and
for sale in our natural gas business, on the volatile spot market and to manage certain interest rate exposure.

As
of December 31, 2007 and 2006, we have recorded the following assets and liabilities representing the fair value of derivative financial instruments held as of
December 31, (in thousands):

ASSET DERIVATIVES

Derivatives designated as hedging instruments under statement 133

|                                                    |  |                                         |  | 2007 |        | 2006
|--------------------------------------------------- |  | --------------------------------------- |  | ---- | ------ | ----
|
|Natural gas contracts, current electric segment     |  | Current assets                          |  | $    | 2,435  |     
|Natural gas contracts, non-current electric segment |  | Non-current assets and deferred charges |  |      | 17,520 |     

Derivatives not designated as hedging instruments under statement 133

|Natural gas contracts, current gas segment     |                          | Current assets                          |   |        | 64 |   |        | 
|---------------------------------------------- | ------------------------ | --------------------------------------- | - | ------ | -- | - | ------ | -
|Natural gas contracts, non-current gas segment |                          | Non-current assets and deferred charges |   |        |   |   |        | 
|                                               |                          |                                         |   |        |    |  
|                                               | Total derivatives assets |                                         | $ | 20,019 |    | $ | 15,631
|                                               |                          |                                         |   |        |    |  

LIABILITY DERIVATIVES

Derivatives designated as hedging instruments under statement 133

|                                                    |  |                                              |  | 2007 |       | 2006
|--------------------------------------------------- |  | -------------------------------------------- |  | ---- | ----- | ----
|
|Natural gas contracts, current electric segment     |  | Current liabilities                          |  | $    | 1,154 |     
|Natural gas contracts, non-current electric segment |  | Non-current liabilities and deferred charges |  |      | 698   |     

Derivatives not designated as hedging instruments under statement 133

|Natural gas contracts, current gas segment     |                               | Current liabilities                          |   | $     | 457 |   | $     | 562
|---------------------------------------------- | ----------------------------- | -------------------------------------------- | - | ----- | --- | - | ----- | ---
|Natural gas contracts, non-current gas segment |                               | Non-current liabilities and deferred credits |   |       |    |   |       |   
|                                               |                               |                                              |   |       |     |  
|                                               | Total derivatives liabilities |                                              | $ | 2,309 |     | $ | 1,372
|                                               |                               |                                              |   |       |     |  

121

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

OTHER COMPREHENSIVE INCOME

|                                                                        |  |                                              |        | 2007 |        | 2006   |  
|----------------------------------------------------------------------- |  | -------------------------------------------- | ------ | ---- | ------ | ------ | -
|
|Current assets  electric segment                                       |  | Current assets                               |        | $    | 2,435  |        | $
|Ineffective non-hedged unrealized gain included in current assets above |  | Current assets                               |        |      | (281   | )      |  
|Unamortized option premiums included in current assets above            |  | Current assets                               |        |      |       |        |  
|Non current assets-electric segment                                     |  | Non-current assets and deferred charges      |        |      | 17,520 |        |  
|Current liabilities  electric segment                                  |  | Current liabilities                          |        |      | (1,154 | )      |  
|Non current liabilities  electric segment                              |  | Non-current liabilities and deferred charges |        |      | (698   | )      |  
|                                                                        |  |                                              |        |      |        |        |  
|Net fair value of derivatives (before
tax)  electric segment           |  |                                              | 17,822 |      |        | 14,203 |  
|Tax effect                                                              |  | Deferred taxes                               |        |      | (6,790 | )      |  
|                                                                        |  |                                              |        |      |        |        |  
|Other comprehensive income                                              |  | Capitalization                               |        | $    | 11,032 |        | $
|                                                                        |  |                                              |        |      |        |        |  

Electric

An $11.0 million net of tax, unrealized gain representing the fair market value of our electric segment derivative contracts treated as cash flow hedges is
recognized as Accumulated Other Comprehensive Income in the capitalization section of the balance sheet as of December 31, 2007. The tax effect of $6.8 million on this gain is included
in deferred taxes. These amounts will be adjusted cumulatively on a monthly basis during the determination periods, beginning January 1, 2008 and ending on September 30, 2011. At the end
of each determination period, or if cash flow hedge treatment is discontinued, any gain or loss for that period related to the instrument will be reclassified to fuel expense. As of
December 31, 2007, approximately $1.0 million of unrealized gains are applicable to financial instruments which will settle within the next twelve months.

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 approximate $6 million increase 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.

122

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The
following table sets forth the actual pre-tax gains/(losses) from the qualified portion of our hedging activities for settled contracts for the electric segment for each
of the years ended December 31, (in thousands):

Derivatives in Statement 133 Cash Flow Hedging Relationships

|                                       |                                    |              |   | Amount of Gain/(Loss) Reclassed from OCI into Income (Effective Portion) |       | Amount of Gain/(Loss) Recognized in OCI on Derivative (Effective Portion)
|-------------------------------------- | ---------------------------------- | ------------ | - | ------------------------------------------------------------------------ | ----- | -------------------------------------------------------------------------
|
|
|Commodity contracts  electric segment |                                    | Fuel Expense |   | $                                                                        | 1,610 |                                                                          
|                                       |                                    |              |   |                                                                          |       |                                                                          
|                                       | Total Effective  Electric Segment |              | $ | 1,610                                                                    |       | $                                                                        
|                                       |                                    |              |   |                                                                          |       |                                                                          

We record unrealized gains/(losses) on the ineffective portion of our gas hedging activities in "Fuel" under the Operating Revenue Deductions section of our
statement of operations since all of our gas hedging activities are related to stabilizing fuel costs as part of our fuel procurement program and are not speculative activities.

The
following table sets forth "mark-to-market" pre-tax gains/ (losses) from the ineffective portion of our hedging activities for the electric
segment for each of the years ended December 31, (in thousands):

Derivatives in Statement 133 Cash Flow Hedging Relationships

|                                       |                                      |              |   | Amount of Gain/(Loss) Recognized in Income on Derivative-(Ineffective) |  
|-------------------------------------- | ------------------------------------ | ------------ | - | ---------------------------------------------------------------------- | -
|
|
|Commodity contracts  electric segment |                                      | Fuel Expense |   | $                                                                      | 
|                                       |                                      |              |   |                                                                        |  
|                                       | Total Ineffective  Electric Segment |              | $ |                                                                       |  
|                                       |                                      |              |   |                                                                        |  

The following table sets forth "mark-to-market" pre-tax gains/(losses) from derivatives not designated as hedging instruments
under Statement 133 for the electric segment for each of the years ended December 31, (in thousands):

Derivatives Not Designated as Hedging Instruments Under Statement 133(1)

|                                       |                          |              |   | Amount of Gain/(Loss) Recognized in Income on Derivative
|-------------------------------------- | ------------------------ | ------------ | - | --------------------------------------------------------
|
|
|Commodity contracts  electric segment |                          | Fuel Expense |   | $                                                       
|                                       |                          |              |   |                                                         
|                                       | Total  Electric Segment |              | $ | 281                                                     
|                                       |                          |              |   |                                                         

---

123

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We
also enter into fixed-price forward physical contracts for the purchase of natural gas, coal and purchased power. These contracts are not subject to the fair value accounting of
FAS 133 because they are considered to be normal purchases. We have instituted a process to determine if any future executed contracts that otherwise qualify for the normal purchases exception
contain a price adjustment feature and will account for these contracts accordingly.

As
of February 15, 2008, 88% of our anticipated volume of natural gas usage for our electric operations for the remainder of year 2008 is hedged, either through physical or
financial contracts, at an average price of $6.811 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 six years are hedged at the following average prices per Dth:

Year

% Hedged

Dth Hedged

Average Price2009

55
%
4,696,000

$
6.0602010

34
%
3,200,000

$
5.5612011

34
%
3,200,000

$
5.5612012

13
%
1,200,000

$
7.2952013

13
%
1,200,000

$
7.295


On February 15, 2008, the Company unwound 992,000 Dth of physical gas contracts originally scheduled for delivery in July and August of 2010 and 2011. This
transaction resulted in a gain of approximately $1.3 after tax which will be recorded in the Statement of Income in the first quarter of 2008.

Gas

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 15, 2008, we have 93% of our
expected remaining winter heating season usage (through March 2008) hedged with physical storage, physical forward contracts and financial derivative contracts. The average price of these hedges is
$5.488 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 16, 2008, we had 0.4 million Dths in storage on the three pipelines that serve our customers. This represents 21% of our storage capacity. Our
long-term hedge
positions for gas purchased for resale are still in the development process. A Purchased Gas Adjustment (PGA) clause is included in our rates for our gas segment operations, therefore, we mark to
market any unrealized gains or losses and any realized gains or losses relating to financial derivative contracts to a regulatory asset or regulatory liability account on our balance sheet.

The
following table sets forth "mark-to-market" pre-tax gains/(losses) from derivatives not designated as hedging instruments under
Statement 133 for the gas segment for the years ended December 31, (in thousands):

Derivatives not designated as hedging instruments under Statement 133

|                                  |                     |                   |        | Amount of Gain/(Loss) Recognized on Balance Sheet |       
|--------------------------------- | ------------------- | ----------------- | ------ | ------------------------------------------------- | ------
|
|
|Commodity contracts  gas segment |                     | Regulatory assets |        | (1,534                                            | )     
|                                  |                     |                   |        |                                                   |       
|                                  | Total  Gas Segment |                   | (1,534 | )                                                 | (1,563
|                                  |                     |                   |        |                                                   |       

124

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16.   Accounts Receivable  Other

The following table sets forth the major components comprising "accounts receivable  other" on our consolidated balance sheet (in thousands):

|                                                                                          |                                   | December 31,
|----------------------------------------------------------------------------------------- | --------------------------------- | ------------
|
|Accounts receivable for meter loops, meter bases, line extensions, highway projects, etc. |                                   | $           
|Accounts receivable for gas segment(1)                                                    |                                   |             
|Accounts receivable for non-regulated subsidiary companies                                |                                   |             
|Accounts receivable from Westar Generating, Inc., for commonly-owned facility             |                                   |             
|Taxes receivable  overpayment of estimated income taxes                                  |                                   |             
|Accounts receivable for energy trading margin deposit(2)                                  |                                   |             
|Accounts receivable for true-up on maintenance contracts(3)                               |                                   |             
|Other                                                                                     |                                   |             
|                                                                                          |                                   |             
|                                                                                          | Total accounts receivable  other |             
|                                                                                          |                                   |             

---

125

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17.   Regulated  Other Operating Expense

The following table sets forth the major components comprising "regulated  other" under "Operating Revenue Deductions" on our consolidated
statements of income the years ended (in thousands):

|                                                  |       | December 31,
|------------------------------------------------- | ----- | ------------
|
|Electric transmission and distribution expense    |       | $           
|Natural gas transmission and distribution expense |       |             
|Power operation expense (other than fuel)         |       |             
|Customer accounts & assistance expense            |       |             
|Employee pension expense(1)                       |       |             
|Employee healthcare plan(1)                       |       |             
|General office supplies and expense               |       |             
|Administrative and general expense                |       |             
|Allowance for uncollectible accounts              |       |             
|Miscellaneous expense                             |       |             
|                                                  |       |             
|                                                  | Total |             
|                                                  |       |             

---

18.   Discontinued Operations

In August 2006, we sold our controlling 52% interest in MAPP to other current owners. MAPP is 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. We have reported MAPP,
Conversant and Fast Freedom's results as discontinued operations. A summary of the components of losses from discontinued operations for the years ended December 31, 2007, 2006 and 2005 follows
(in thousands):

|2007                                                    |                                   |   |       |    |   | Fast Freedom |    | Total | 
|------------------------------------------------------- | --------------------------------- | - | ----- | -- | - | ------------ | -- | ----- | 
|Revenues                                                |                                   | $ | 905   |    | $ | 905          |   
|Expenses                                                |                                   |   | 1,063 |    |   | 1,063        |   
|                                                        |                                   |   |       |    |   |              |    |       | 
|Losses from discontinued operations before income taxes |                                   |   | (158  | )  |   | (158         | ) 
|Gain on disposal                                        |                                   |   | 161   |    |   | 161          |   
|Income tax                                              |                                   |   | 60    |    |   | 60           |   
|Minority interest                                       |                                   |   |      |    |   |             |   
|Income tax  minority interest                          |                                   |   |      |    |   |             |   
|                                                        |                                   |   |       |    |   |              |    |       | 
|                                                        | Gain from discontinued operations |   | $     | 63 |   | $            | 63 |      
|                                                        |                                   |   |       |    |   |              |    |       | 

126

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THE EMPIRE DISTRICT ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

|2006                                                               |                                          | MAPP |        | Conversant |   | Fast Freedom |        | Total |      
|------------------------------------------------------------------ | ---------------------------------------- | ---- | ------ | ---------- | - | ------------ | ------ | ----- | -----
|Revenues                                                           |                                          | $    | 8,927  |            | $ | 1,822        |        | $     | 1,363
|Expenses                                                           |                                          |      | 9,295  |            |   | 3,908        |        |       | 1,632
|                                                                   |                                          |      |        |            |   |              |        |       |      
|Losses from discontinued operations before income taxes            |                                          |      | (368   | )          |   | (2,086       | )      |       | (269 
|Gain on disposal                                                   |                                          |      | 271    |            |   | 555          |        |       |     
|Income tax                                                         |                                          |      | 140    |            |   | 795          |        |       | 102  
|Minority interest                                                  |                                          |      | 177    |            |   |             |        |       |     
|Income tax  minority interest                                     |                                          |      | (67    | )          |   |             |        |       |     
|                                                                   |                                          |      |        |            |   |              |        |       |      
|                                                                   | Gain (loss) from discontinued operations |      | $      | 153        |   | $            | (736   | )     | $    
|                                                                   |                                          |      |        |            |   |              |        |       |      
|
|Revenues                                                           |                                          | $    | 20,494 |            | $ | 1,914        |        | $     | 1,466
|Expenses                                                           |                                          |      | 19,779 |            |   | 3,981        |        |       | 1,671
|                                                                   |                                          |      |        |            |   |              |        |       |      
|Earnings (losses) from discontinued operations before income taxes |                                          |      | 715    |            |   | (2,067       | )      |       | (205 
|Income tax                                                         |                                          |      | (272   | )          |   | 788          |        |       | 78   
|Minority interest                                                  |                                          |      | (344   | )          |   |             |        |       |     
|Income tax  minority interest                                     |                                          |      | 131    |            |   |             |        |       |     
|                                                                   |                                          |      |        |            |   |              |        |       |      
|                                                                   | Gain (loss) from discontinued operations |      | $      | 230        |   | $            | (1,279 | )     | $    
|                                                                   |                                          |      |        |            |   |              |        |       |      

127

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of our management, including
our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as such term is defined in
Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls
and procedures were effective as of December 31, 2007.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act
Rule 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and
Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of
December 31, 2007.

Audit of Internal Control Over Financial Reporting

The effectiveness of our internal control over financial reporting as of December 31, 2007, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the fourth quarter of 2007 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

None.

128

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Except as set forth below, the information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held
April 24, 2008, which is incorporated herein by reference.

Pursuant
to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, the information required by this Item with respect to executive officers
is set forth in Item 1 of Part I of this Form 10-K under "Executive Officers and Other Officers of Empire."

We
have adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers. A copy of the code is available on our website at www.empiredistrict.com. Any future
amendments or waivers to the code will be posted on our website at www.empiredistrict.com.

Because
our common stock is listed on the NYSE, our Chief Executive Officer is required to make a CEO's Annual Certification to the NYSE in accordance with Section 303A.12 of the
NYSE Listed Company Manual stating that he is not aware of any violations by us of the NYSE corporate governance listing standards. Our Chief Executive Officer has provided, and intends to continue to
timely provide, the NYSE with the CEO's Annual Certificate.

ITEM 11.    EXECUTIVE COMPENSATION

Information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 24, 2008, which is
incorporated herein by reference.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Except as set forth below, information required by this item may be found in our proxy statement for our Annual Meeting of Stockholders to be held
April 24, 2008, which is incorporated herein by reference.

There
are no arrangements the operation of which may at a subsequent date result in a change in control of Empire.

Securities Authorized For Issuance Under Equity Compensation Plans

We have four equity compensation plans, all of which have been approved by shareholders, the 1996 Stock Incentive Plan, the 2006 Stock Incentive Plan, the
Employee Stock Purchase Plan (ESPP) and the Stock Unit Plan for Directors.

129

---



The
following table summarizes information about our equity compensation plans as of December 31, 2007:

|Plan Category                                              |       | (a) Number of securities
to be issued upon exercise
of outstanding options, warrants and rights. |         | (b) Weighted-average
exercise price
of outstanding options,
warrants and rights(1) |       | (c) Number of securities
remaining available
for future issuance
under equity compensation
plans (excluding securities reflected in column (a))
|---------------------------------------------------------- | ----- | ------------------------------------------------------------------------------------------------ | ------- | ---------------------------------------------------------------------------------- | ----- | -----------------------------------------------------------------------------------------------------------------------------------------------
|Equity compensation plans approved by security holders     |       | 373,902                                                                                          |         | $                                                                                  | 22.65 |                                                                                                                                                
|Equity compensation plans not approved by security holders |       |                                                                                                 |         |                                                                                    |      |                                                                                                                                                
|                                                           |       |                                                                                                  |         |                                                                                    |       |                                                                                                                                                
|                                                           | Total |                                                                                                  | 373,902 |                                                                                    | $     | 22.65                                                                                                                                          
|                                                           |       |                                                                                                  |         |                                                                                    |       |                                                                                                                                                

---

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 24, 2008, which is
incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item may be found in our proxy statement for our Annual Meeting of Stockholders to be held April 24, 2008, which is
incorporated herein by reference.

130

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Index to Financial Statements and Financial Statement Schedule Covered by Report of  Independent Registered Public Accounting Firm

|Consolidated balance sheets at December 31, 2007 and 2006                                                         |                                                                                                                          | 63
|----------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------ | --
|Consolidated statements of income for each of the three years in the period ended December 31, 2007               |                                                                                                                          | 65
|Consolidated statements of comprehensive income for each of the three years in the period ended December 31, 2007 |                                                                                                                          | 66
|                                                                                                                  | Consolidated statements of common stockholders' equity for each of the three years in the period ended December 31, 2007 |   
|Consolidated statements of cash flows for each of the three years in the period ended December 31, 2007           |                                                                                                                          | 68
|Notes to consolidated financial statements                                                                        |                                                                                                                          | 70
|Schedule for the years ended December 31, 2007, 2006 and 2005:                                                    |                                                                                                                          |   
|                                                                                                                  | Schedule II  Valuation and qualifying accounts                                                                          |   

All other schedules are omitted as the required information is either not present, is not present in sufficient amounts, or the information required therein is
included in the financial statements or notes thereto.

List of Exhibits

|(3)(a) |  | The Restated Articles of Incorporation of Empire (Incorporated by reference to Exhibit 4(a) to Registration Statement No. 33-54539 on Form S-3).                                                                                                        
|------ |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(b)    |  | By-laws of Empire as amended October 31, 2002 (Incorporated by reference to Exhibit 4(b) to Annual Report on Form 10-K for year ended December 31, 2002, File No. 1-3368).                                                                              
|(4)(a) |  | Indenture of Mortgage and Deed of Trust dated as of September 1, 1944 and First Supplemental Indenture thereto among Empire, The Bank of New York and UMB Bank, N.A., (Incorporated by reference to Exhibits B(1) and B(2) to Form 10, File
No. 1-3368).
|(b)    |  | Third Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).                                                                                                      
|(c)    |  | Sixth through Eighth Supplemental Indentures to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 2(c) to Form S-7, File No. 2-59924).                                                                                      
|(d)    |  | Fourteenth Supplemental Indenture to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(f) to Form S-3, File No. 33-56635).                                                                                                
|(e)    |  | Twenty-Second Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(k) to Annual Report on Form 10-K for year ended December 31, 1993, File
No. 1-3368).               
|(f)    |  | Twenty-Third Supplemental Indenture dated as of November 1, 1993 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(l) to Annual Report on Form 10-K for year ended December 31, 1994, File
No. 1-3368).                
|(g)    |  | Twenty-Fourth Supplemental Indenture dated as of March 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(m) to Annual Report on Form 10-K for year ended December 31, 1993, File
No. 1-3368).                  

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|(h) |  | Twenty-Fifth Supplemental Indenture dated as of November 1, 1994 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4(p) to Registration Statement No. 33-56635 on Form S-3).                                                                                                                                                               
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(i) |  | Twenty-Eighth Supplemental Indenture dated as of December 1, 1996 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Annual Report on Form 10-K for year ended December 31, 1996, File
No. 1-3368).                                                                                                                                    
|(j) |  | Twenty-Ninth Supplemental Indenture dated as of April 1, 1998 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4 to Form 10-Q for quarter ended March 31, 1998, File No. 1-3368).                                                                                                                                                         
|(k) |  | Thirty-First Supplemental Indenture dated as of March 26, 2007 to Indenture of Mortgage and Deed of Trust (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated March 26, 2007 and filed March 28, 2007,
File No. 1-3368).                                                                                                                        
|(l) |  | Indenture for Unsecured Debt Securities, dated as of September 10, 1999 between Empire and Wells Fargo Bank Minnesota, National Association (Incorporated by reference to Exhibit 4(v) to Registration Statement No. 333-87015 on
Form S-3).                                                                                                                              
|(m) |  | Securities Resolution No. 2, dated as of February 22, 2001, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4(s) to Annual Report on Form 10-K for the year ended December 31,
2002, File No. 1-3368).                                                                                                                  
|(n) |  | Securities Resolution No. 3, dated as of December 18, 2002, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4(s) to Annual Report on Form 10-K for year ended December 31, 2002,
 File No. 1-3368).                                                                                                                     
|(o) |  | Securities Resolution No. 4, dated as of June 10, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Current Report on Form 8-K dated June 10, 2003 and filed
June 29, 2003, File No. 1-3368).                                                                                                                  
|(p) |  | Securities Resolution No. 5, dated as of October 29, 2003, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Quarterly Report on Form 10-Q for quarter ended September 30,
2003).                                                                                                                                    
|(q) |  | Securities Resolution No. 6, dated as of June 27, 2005, of Empire under the Indenture for Unsecured Debt Securities (Incorporated by reference to Exhibit 4 to Current Report on Form 8-K dated June 27, 2005 and filed
June 28, 2005, File No. 1-3368).                                                                                                                  
|(r) |  | Rights Agreement dated as of April 27, 2000 between Empire and Wells Fargo Bank, N.A. (as successor to Mellon Investor Services LLC) (Incorporated by reference to Exhibit 4 to Form 10-Q for the quarter ended March 31, 2000,
File No. 1-3368).                                                                                                                         
|(s) |  | First Amended and Restated Unsecured Credit Agreement, dated as of March 14, 2006, among Empire, UMB Bank, N.A., as arranger and administrative agent, Bank of America, N.A., as syndication agent, and the lenders named therein (Incorporated by
reference to Exhibit 4.1 to Current Report on Form 8-K dated March 14, 2006 and filed March 16, 2006, File No. 1-3368).
|(t) |  | Bond Purchase Agreement dated June 1, 2006 among The Empire District Gas Company and the purchasers party thereto (Incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K dated June 1, 2006 and filed June 6,
2006, File No. 1-3368).                                                                                                                    

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|(u)     |  | Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The Bank of New York Trust Company, N.A., Bond Trustee, as
Grantee (Incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K dated June 1, 2006 and filed June 6, 2006, File No. 1-3368).                   
|------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(v)     |  | First Supplemental Indenture of Mortgage and Deed of Trust dated as of June 1, 2006 by The Empire District Gas Company, as Grantor, to Spencer R. Thomson, Deed of Trust Trustee for the Benefit of The Bank of New York Trust Company, N.A.,
Bond Trustee, as Grantee (Incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K dated June 1, 2006 and filed June 6, 2006, File No. 1-3368).
|(10)(a) |  | 1996 Stock Incentive Plan (Incorporated by reference to Exhibit 4.1 to Form S-8, File No. 33-64639).                                                                                                                                                                                                                                                                                                      
|(b)     |  | First Amendment to 1996 Stock Incentive Plan. *                                                                                                                                                                                                                                                                                                                                                           
|(c)     |  | 2006 Stock Incentive Plan (Incorporated by reference to Exhibit 4(u) to Form S-8, File No. 333-130075).                                                                                                                                                                                                                                                                                                   
|(d)     |  | First Amendment to 2006 Stock Incentive Plan. *                                                                                                                                                                                                                                                                                                                                                           
|(e)     |  | Deferred Compensation Plan for Directors as amended and restated effective January 1, 2008.*                                                                                                                                                                                                                                                                                                              
|(f)     |  | The Empire District Electric Company Change in Control Severance Pay Plan as amended and restated effective January 1, 2008.*                                                                                                                                                                                                                                                                             
|(g)     |  | Form of Severance Pay Agreement under The Empire District Electric Company Change in Control Severance Pay Plan.*                                                                                                                                                                                                                                                                                         
|(h)     |  | The Empire District Electric Company Supplemental Executive Retirement Plan as amended and restated effective January 1, 2008.*                                                                                                                                                                                                                                                                           
|(i)     |  | Retirement Plan for Directors as amended August 1, 1998 (Incorporated by reference to Exhibit 10(a) to Form 10-Q for quarter ended September 30, 1998, File No. 1-3368).                                                                                                                                                                                                                                  
|(j)     |  | Stock Unit Plan for Directors of The Empire District Electric Company (Incorporated by reference to Exhibit 10(i) to Annual Report on Form 10-K for year ended December 31, 2005, File No. 1-3368).                                                                                                                                                                                                       
|(k)     |  | First Amendment to Stock Unit Plan for Directors.*                                                                                                                                                                                                                                                                                                                                                        
|(l)     |  | Summary of Annual Incentive Plan.*                                                                                                                                                                                                                                                                                                                                                                        
|(m)     |  | Form of Notice of Award of Dividend Equivalents.*                                                                                                                                                                                                                                                                                                                                                         
|(n)     |  | Form of Notice of Award of Non-Qualified Stock Options.*                                                                                                                                                                                                                                                                                                                                                  
|(o)     |  | Form of Notice of Award of Performance-Based Restricted Stock.*                                                                                                                                                                                                                                                                                                                                           
|(p)     |  | Summary of Compensation of Non-Employee Directors.*                                                                                                                                                                                                                                                                                                                                                       
|(12)    |  | Computation of Ratios of Earnings to Fixed Charges.*                                                                                                                                                                                                                                                                                                                                                       
|(21)    |  | Subsidiaries of Empire.*                                                                                                                                                                                                                                                                                                                                                                                   
|(23)    |  | Consent of PricewaterhouseCoopers LLP.*                                                                                                                                                                                                                                                                                                                                                                    
|(24)    |  | Powers of Attorney.*                                                                                                                                                                                                                                                                                                                                                                                       

133

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|(31)(a) |  | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*                                                
|------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------
|(31)(b) |  | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*                                                
|(32)(a) |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~
|(32)(b) |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*~

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SCHEDULE II

Valuation and Qualifying AccountsYears ended December 31, 2007, 2006 and 2005:

|                                                                                         |  |   |           | Additions |   | Deductions From Reserve |  |                                           
|---------------------------------------------------------------------------------------- |  | - | --------- | --------- | - | ----------------------- |  | ------------------------------------------
|
|
|Year endedDecember 31, 2007:                                                             |  |   |           |           |   |                         |  |                                           
|*Reserve deducted from assets: accumulated provision for uncollectible accounts.         |  | $ | 1,180,577 |           | $ | 4,661,439               |  | Recovery of amounts previously written off
|Reserve not shown separately in balance sheet: Injuries and damages reserve (Note A)     |  | $ | 1,592,670 |           | $ | 1,484,529               |  | Property, plant & equipment               
|Year endedDecember 31, 2006:                                                             |  |   |           |           |   |                         |  |                                           
|Electric reserve deducted from assets: accumulated provision for uncollectible accounts. |  | $ | 561,808   |           | $ | 1,624,200               |  | Recovery of amounts previously written off
|EDG acquisition amount recorded to reserve  Balance as of June 1:                       |  | $ | 506,505   |           | $ | 351,530                 |  |                                           
|Reserve not shown separately in balance sheet: Injuries and damages reserve (Note A)     |  | $ | 1,496,670 |           | $ | 984,462                 |  | Property, plant & equipment               
|Year endedDecember 31, 2005:                                                             |  |   |           |           |   |                         |  |                                           
|Reserve deducted from assets: Accumulated provision for uncollectible accounts           |  | $ | 284,109   |           | $ | 1,821,444               |  | Recovery of amounts previously written off
|Reserve not shown separately in balance sheet: Injuries and damages reserve (Note A)     |  | $ | 1,546,670 |           | $ | 939,399                 |  | Property, plant & equipment               

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Note A: This reserve is provided for workers' compensation, certain postemployment benefits and public liability damages. At December 31, 2007, we
carried insurance for workers' compensation claims in excess of $500,000 and for public liability claims in excess of $500,000. The injuries and damages reserve is included on the Balance Sheet in the
section "Noncurrent liabilities and deferred credits" in the category "Other".

135

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

|                    | THE EMPIRE DISTRICT ELECTRIC COMPANY
|------------------- | ------------------------------------
|Date: March 3, 2008 | By                                  

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in
the capacities and on the date indicated.

|                                                                                                                            |  | Date         
|--------------------------------------------------------------------------------------------------------------------------- |  | -------------
|/s/WILLIAM L. GIPSONWilliam L. Gipson, President,
Chief Executive Officer, Director
(Principal Executive Officer)           |  |              
|/s/GREGORY A. KNAPPGregory A. Knapp, Vice President-Finance
(Principal Financial Officer)                                   |  |              
|/s/LAURIE A. DELANOLaurie A. Delano, Controller, Assistant
Secretary and Assistant Treasurer
(Principal Accounting Officer) |  |              
|/s/DR. JULIO S. LEON*Dr. Julio S. Leon, Director                                                                            |  |              
|/s/KENNETH R. ALLEN*Kenneth R. Allen, Director                                                                              |  |              
|/s/MYRON W. MCKINNEY*Myron W. McKinney, Director                                                                            |  |              
|/s/ROSS C. HARTLEY*Ross C. Hartley, Director                                                                                |  | March 3, 2008
|/s/D. RANDY LANEY*D. Randy Laney, Director                                                                                  |  |              
|/s/BILL D. HELTON*Bill D. Helton, Director                                                                                  |  |              
|/s/B. THOMAS MUELLER*B. Thomas Mueller, Director                                                                            |  |              
|/s/ALLAN T. THOMS*Allan T. Thoms, Director                                                                                  |  |              
|/s/MARY MCCLEARY POSNER*Mary McCleary Posner, Director                                                                      |  |              
|/s/GREGORY A. KNAPP*By (Gregory A. Knapp, As attorney in fact for
each of the persons indicated)                            |  |              

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